SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F/A
(Mark One)
| ¨ | Annual report pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934 (Fee required) |
or
| x | Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended March 31, 2004 (No Fee required) |
or
| ¨ | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from N/A to N/A (No Fee required) |
Commission file number 1-14990
BRITISH ENERGY LIMITED
(Exact Name of Registrant as Specified in Its Charter)
(Formerly British Energy plc)
Scotland
(Jurisdiction of Incorporation or Organization)
Systems House, Alba Campus, Livingston, EH54 7EG
(Address of Principal Executive Offices)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
| Title of each class | Name of each exchange on which registered | |
| Ordinary shares of 44 28/43p each (“ordinary |
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
| Ordinary shares of 44 28/43p each |
620,362,444 shares | |
| “A” shares of 60p each |
80,908,247 shares | |
| Non voting deferred shares of 60p each |
74,752,351 shares | |
| Non-voting special rights redeemable |
1 share |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
(1) x (2) x
Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 ¨ Item 18 x
| * | Not for trading but only in connection with the registration of ADSs pursuant to the requirements of the Securities and Exchange Commission. |
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| Key Information |
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| Information On The Company |
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| Operating And Financial Review And Prospects |
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| Directors, Senior Managers And Employees |
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| Major Shareholders And Related Party Transactions |
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| Financial Information |
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| The Offer And Listing |
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| Additional Information |
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| Quantitative And Qualitative Disclosures About Market Risk |
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| Dividend Arrearages And Delinquencies |
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| Material Modifications To The Rights Of Security Holders And Use Of Proceeds |
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| Controls And Procedures |
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| Reserved |
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| Audit Committee Financial Expert |
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| Code Of Ethics |
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| Principal Accountant Fees And Services |
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| Financial Statements |
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| Financial Statements |
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| Exhibits |
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In this annual report, except as otherwise specified, “British Energy”, the “British Energy Group”, the “Company”, the “Group”, “we”, “us” or “our” refer to British Energy plc and its subsidiaries and any of their respective predecessors in business, as the context may require. We were incorporated under the Companies Act 1985, as amended (the “Companies Act”) on December 13, 1995.
Our registered office is located at 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 annual report.
Amendments
The Company’s annual report on Form 20-F for the year ended March 31, 2004 was filed with the SEC on September 30, 2004. At the time of the filing of the Form 20-F with the SEC, Mike Alexander was the Chief Executive Officer of the Company and Martin Gatto was Chief Financial Officer. Accordingly, Messrs. Alexander and Gatto signed the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002.
Stephen Billingham took over the full responsibilities of Chief Financial Officer on January 1, 2005, upon the departure of Martin Gatto. On March 3, 2005, the Company received a comment letter from the SEC Staff requesting that certain amendments be made to the Form 20-F. On March 20, 2005, Mike Alexander resigned as Chief Executive Officer of the Company and William Coley was subsequently appointed Chief Executive Officer. Messrs. Coley and Billingham were not the Company’s Chief Executive Officer and Chief Financial Officer, respectively, at the time that the Form 20-F was prepared and filed. Accordingly, Messrs. Coley and Billingham were not responsible for establishing or maintaining the Company’s disclosure controls and procedures for the period of this report. They became responsible for establishing and maintaining the Company’s disclosure controls and procedures following their respective appointments as Chief Executive Officer and Chief Financial Officer and have continued to exercise that responsibility since the date of their appointment. They have signed this amended 20-F on that basis.
We publish our financial statements in pounds sterling. In this annual report, references to “pounds sterling”, “£”, “pence” or “p” are to UK currency, references to “US dollars”, “US$” or “$” are to US currency and references to “Canadian dollars”, or “C$” are to Canadian currency. Amounts in this annual report stated in US dollars, unless otherwise indicated, have been translated from pounds sterling solely for convenience and should not be construed as representations that the pound sterling actually represent such US dollar amounts or could be converted into US dollars at the rate indicated or any other rate. The Noon Buying Rate for pounds sterling on September 24, 2004 was £1.00 = $1.8031. For certain information about exchange rates between pounds sterling and US dollars, see “Item 3. Key Information—Exchange Rates”.
This annual report refers to certain technical terms used to measure output of electricity and the production of electricity over time. The basic unit for the measurement of electricity output is a kilowatt (“kW”). The basic unit for the measurement of electricity production is a kilowatt-hour (“kWh”); that is, one hour of electricity production at a constant output of one kilowatt. One thousand kilowatts are a megawatt (“MW”) or, in terms of production, a megawatt-hour (“MWh”). One thousand megawatts are a gigawatt (“GW”) or, in terms of production, a gigawatt-hour (“GWh”). One thousand gigawatts are a terawatt (“TW”) or, in terms of production, a terawatt-hour (“TWh”).
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Information Regarding Forward-looking Statements
This annual report contains certain “forward-looking” statements as defined in Section 21E of the US Securities Exchange Act of 1934. Such forward-looking statements include, among others:
| • | statements concerning our proposed restructuring and the effect of our proposed restructuring on our business and financial condition or results of operations, |
| • | the anticipated development of the UK electricity industry, the future development of regulation of the UK electricity industry, the effect of these developments on our business, financial condition or results of operations, and |
| • | other matters that are not historical facts concerning our business operations, financial condition and results of operations. |
These forward-looking statements involve known and unknown risks, uncertainties and other factors which are in some cases beyond our control and may cause our actual results or performance to differ materially from those expressed or implied by such forward-looking statements. For a discussion of some of the risks associated with these forward-looking statements, see “Item 3. Key Information—Risk Factors”. Due to the uncertainties and risks associated with these forward-looking statements, which speak only as of the date hereof, we are claiming the benefit of the safe harbor provision referred to above.
EBITDA and EBITDA from Continuing Activities
EBITDA means earnings before interest, taxes, depreciation, amortization and related exceptional items. EBITDA and EBITDA from continuing activities are supplemental measures of our performance and liquidity that are not required by, or presented in accordance with, UK GAAP or US GAAP. EBITDA and EBITDA from continuing activities are not measurements of our financial performance or liquidity under UK GAAP or US GAAP and should not be considered as an alternative to net income, operating income or any other performance measures derived in accordance with UK GAAP or US GAAP or as an alternative to cash flow from operating activities as a measure of our liquidity.
We present EBITDA and EBITDA from continuing activities because we believe that they are frequently used by certain of our investors and other interested parties in evaluating our financial performance. EBITDA and EBITDA from continuing activities can facilitate comparisons of operating performance from period to period and company to company by eliminating potential differences caused by variations in capital structures (affecting interest expense), tax positions (such as the impact on periods or companies of changes in effective tax rates or net operating losses), the age and booked depreciation and amortization of assets (affecting relative depreciation and amortization of expense), extraordinary items and minority interests.
Nevertheless, EBITDA and EBITDA from continuing activities have limitations as analytical tools, and you should not consider them in isolation from, or as a substitute for analysis of, our financial condition or results of operations, as reported under UK GAAP. Some of these limitations are:
| • | EBITDA and EBITDA from continuing activities measures do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments; |
| • | EBITDA and EBITDA from continuing activities measures do not reflect changes in, or cash requirements for, our working capital needs; |
| • | EBITDA and EBITDA from continuing activities measures do not reflect the interest expense, or the cash requirements necessary to service interest or principal payments, on our debt; |
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| • | 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 and EBITDA from continuing activities measures do not reflect any cash requirements for such replacements; |
| • | EBITDA and EBITDA from continuing activities measures do not reflect exceptional income/expense or any other non-cash items; |
| • | other companies in our industry may calculate these measures differently than we do, limiting their usefulness as a comparative measure. |
Because of these limitations, EBITDA and EBITDA from continuing activities 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 relying primarily on our UK GAAP results and using EBITDA only as supplemental measures.
Realized Price
We calculate our realized price for electricity by dividing UK turnover (net of energy supply costs and miscellaneous and exceptional income) by total output. Realized price is not derived in accordance with UK GAAP or 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 (i.e., the cost of transmitting electricity to our customers) and other exceptional items from total turnover. We make these adjustments to turnover because we believe that they allow our management team and our investors to better understand the net price that consumers are paying for our electricity.
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RISK FACTORS
OPERATING RISKS
If we do not find alternative sources of income as our power stations start to close we may not be able to recover our costs from our sales revenue.
Five of our Advanced Gas Cooled Reactor (“AGR”) power stations (“AGR power stations”) are, based on current scheduled accounting closure dates, due to close by 2014. This will reduce our generating capacity by 61.5% of our current generating capacity. There can be no assurance that station lifetime extensions will be achievable at any of our AGR power stations or at our Pressurized Water Reactor (“PWR”) power station (“PWR power station”). Our ability to find alternative sources of income is restricted by the compensatory measures we have agreed to undertake in connection with the European Commission’s approval of the State Aid elements of the Restructuring (as defined in Item 4) and certain other agreements to be entered into pursuant to the Restructuring. If our remaining assets do not generate income in line with our expectations (for example as a result of earlier than anticipated closure of a nuclear power station) our costs (including the costs of maturing pension schemes) may exceed our revenue and this may adversely affect our financial results and our ability to pay dividends in the future.
Our future profitability is dependent upon several factors, some of which are outside our control.
Costs structure and variable electricity prices
The operation of our nuclear power stations is characterized by high fixed costs. Additionally, some of our costs are not borne by our non-nuclear competitors because they are unique to the nuclear power generation industry.
Our ability to generate sufficient turnover at sufficient margin to cover our fixed costs is dependent, in part, on favorable electricity prices and our sales and trading strategy. Electricity prices depend on a number of market factors. Because our costs are primarily fixed in nature, they cannot be reduced in periods of low electricity prices. Therefore, in these circumstances it is possible that we may not produce sufficient revenue from our electricity sales and/or trading to cover our generation costs.
In addition, increasing vertical integration in the electricity sector is likely to affect the liquidity of the markets in which we trade and the volatility of those markets. This in turn may affect the revenue from our electricity sales or trading and may adversely impact our proposed trading going-forward.
Unplanned outages
Unplanned outages of our nuclear reactors result in lost generation and, due to our contractual obligations to deliver electricity at pre-established prices and quantities, we may, therefore, be required to purchase replacement electricity volume in the open market which may be at unfavorable prices. Given the complexity of operating nuclear power stations, we do not believe that we will be able to completely eliminate the risk of unplanned outages and we cannot predict the timing or impact of these outages with any certainty.
Therefore, there is no assurance that we will be profitable or generate sufficient cash to fund our operations or to meet our financial obligations as they fall due. For further risks relating to unplanned outages see “Item 3. Risk Factors—Unplanned outages at our nuclear power stations could adversely affect our revenues and profitability”.
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Unplanned outages at our nuclear power stations could adversely affect our revenues and profitability.
Historically, our nuclear output has been adversely affected by unplanned outages and unplanned reductions in output. We believe that the loss of output is indicative of a deterioration of the materiel condition of plant over time in part caused by inadequate investment over the last few years which has resulted in an increase in our maintenance backlog and failure to carry out required maintenance on a timely basis.
Further, some of our unplanned outages flow from human errors in the operation and maintenance of our plant.
Plant unreliability can result in significant imbalance costs being incurred. In the medium term we have contracted to supply most of our electricity to customers at pre-agreed prices and volumes. If our stations fail to produce the amount of electricity that we have contracted to supply or have otherwise already balanced in the wholesale market, we may have to enter into the short-term market or accept the prices prevailing in the balancing mechanism to meet any such shortfall in output. Prices in the short-term market and imbalance mechanism may be very high, particularly in periods of tight capacity margins for generating plant in the UK, and the unplanned outages of our stations may raise demand and therefore raise prices in these markets.
The Performance Improvement Program (“PIP”) may be constrained by our cash resources and there is no certainty that the hoped for benefits of PIP will materalize. This may adversely affect our prospects in the long term.
Although we are attempting to improve our plant reliability through increased investment and the implementation of the PIP, there is no guarantee that we will be able to identify and/or remedy the causes of plant unreliability. Even if we can identify the causes, there is no certainty that we will be able to implement cost effective solutions or PIP in such a way as to maximize the potential benefits that PIP may afford due to the requirements to maximize the output of our plants. The amount we are able to spend on PIP will be affected by the availability of our cash resources and, in the future in certain circumstances, may be restricted or prohibited by our arrangements with the Nuclear Liabilities Fund (“NLF”). Furthermore, our ability to undertake the proposed capital expenditure may be affected by requirements to undertake urgent remedial work at one (or more) of our nuclear power stations.
In addition, our insurances contain standard exclusions and restrictions and the material damage and business interruption cover does not therefore provide cover for damage caused by, for example, losses due to erosion, corrosion, stress corrosion or cracking. Consequently we may not be able to claim under our material damage and business interruption cover in such circumstances.
Our nuclear stations utilize sea water for condensing the steam from the turbines and for cooling the reactor pressure vessel and turbine-generator auxiliaries. These systems are essential to support generation and a failure of them could result in lost generation, adversely affecting our revenues and profitability.
In 2003, the failure of a cast iron pipe carrying sea water at Heysham 1 resulted in unplanned losses of some 3.2 TWh. Hunterston B, Hartlepool and Hinkley Point B stations also use cast iron pipe work for carrying sea water.
To address the problem, we have developed a strategy to systematically replace the existing cast iron pipe work with steel pipe work coated with a corrosion resistant barrier at all these stations. The corrosive nature of sea water may affect other parts of our pipe work systems, although inspection and maintenance strategies are in place to mitigate this risk. This program of work is planned to take place
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in 2004/5, 2005/6 and 2006/7 and we have made allowances for additional outages to enable this work to take place. We cannot assure you that there will not be further unplanned losses if any failure occurs before the planned program of work is completed.
Problems of damaged pre-stressing tendons at certain of our AGR power stations could negatively affect our profitability or revenues.
At our AGR stations, steel wires (tendons) are used to maintain the integrity of the concrete pressure vessel. We have recently identified limited corrosion in a small number of these pressure vessel pre-stressing tendons at one of our AGR power stations. The access for repair to these tendons is straightforward, and hence repairs are considered to be undemanding.
However, similar steel pre-stressing wires are used to assure the integrity of the boiler closure units (which are housed within the concrete pressure vessels) at two of our AGR stations. As a result of the discovery of corrosion on the tendons (as described above), the Nuclear Installations Inspectorate (“NII”) has concluded boiler closure unit steel wires could also suffer from corrosion. These boiler unit wires are more difficult to inspect.
At three of our reactors (at two of our nuclear power stations) we are presently inspecting the boiler closure unit tendon top anchorages and testing to show that the tendons are intact and, as far as can be determined, free from corrosion. We expect to return these three reactors to service on completion of this work in September and October 2004.
We may wish, or be required by the NII to make, further more detailed inspections at these three reactors. Such inspections may be complex and invasive and may result in a substantial loss of output, which could adversely affect our financial condition. Until these inspections are completed we cannot give assurances as to the length of outages or the cost of work that may be required to complete the inspections or repairs.
A significant engineering fault or a design flaw at one of our power stations, or one which is generic to a class of nuclear plants, could decrease our revenues and increase our costs.
A major engineering fault at one of our nuclear power stations could result in the closure of that station ahead of its expected closure date. Furthermore, engineering faults or safety risks arising from a design problem that is generic to a particular type of nuclear plant could result in the closure of all our nuclear power stations of the same nuclear plant design ahead of their expected closure dates. The early closure of one nuclear power station or any one type of nuclear power station would result in a loss of planned future output and result in costs associated with the closure of the affected nuclear power station or stations.
To deal with the potential of a major engineering fault, we have extensive inspection and testing programs in place in order to evaluate the physical condition of our nuclear power stations. These programs periodically identify certain technical issues for resolution. However, there is no assurance that our inspection process will identify all significant problems and the identification of technical issues with respect to our nuclear power stations may require us to incur significant expenditure for repairs or replacement of parts or equipment. This may result in lost output due to the outages necessary to complete such repairs or replacements.
Problems of graphite core brick cracking and reduced boiler life could negatively affect our profitability and the lifetime of our AGR power stations.
Graphite core brick cracking and reduced boiler life could lead to prolonged outages for testing and, potentially, early station closures at certain of our AGR power stations. These risks are explained in greater detail below.
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Graphite core brick cracking
The graphite cores in the AGRs are made up of a number of graphite bricks arranged in layers. Over the course of the nuclear generation process, the graphite bricks suffer from degradation. Analysis has shown that this degradation can result in a significant number of the graphite bricks developing single or multiple cracks. We are not aware of any technique for eliminating the cracks. Such cracking can lead to the distortion of the core structure and the reduction of the AGRs’ operational capacity.
While our understanding of this issue continues to develop, there is uncertainty as to the level of tolerance of graphite bricks to multiple cracks that can be demonstrated and which may be acceptable to the NII. As such, the development of a safety case, and therefore the continued operation of the reactor, may not be possible. The potential impact of this risk is that currently assumed station lifetime may not be achieved, particularly at Hinkley Point B, Hunterston B, Heysham 2 and Torness, and extensions to station lifetime at these stations may not be possible.
We carry out periodic inspections on the AGR cores and continue to develop safety cases to attempt to demonstrate the tolerance of graphite core brick cracking. However, until we fully understand whether it is possible to devise ways to control or minimize further graphite core brick cracking (if at all), our plants may require more frequent inspection to support our safety cases, which could result in prolonged statutory or unplanned outages or a refusal by the NII to permit us to operate a particular reactor.
Boiler life
The boilers at our AGR power stations consist of multiple steel tubes over which the hot reactor gas flows in order to boil the water that flows through the tubes. Failure of any of the boiler tubes could result in prolonged outages in order to complete repairs or lead to station closure.
If a boiler tube fails, action is taken to permanently seal-off the leaking tube from the incoming water supply. This may result in a permanent reduction in boiler performance and, consequently, our ability to generate electricity if a material number of tubes are sealed. If, ultimately, we are not able to repair the boiler tubes, it may not be possible for us to maintain a safety case for the continued operation of that reactor and the currently assumed station lifetimes may not be achieved.
In addition to the general problem of boiler tube leaks at each of our AGR power stations, specific design issues at some of our stations could lead to further significant threats to boiler life. The design adopted for these stations is unique in that a central cylindrical segment called a spine supports the boiler. The spine construction incorporates the main water inlet and steam outlet, each fabricated from different materials selected to suit the specific operating conditions. The various elements that make up the spine are welded together to form one fabricated section. A small number of these welds are susceptible to high temperature re-heat cracking. Failure of these welds could result in collapse of the boiler with consequential damage to the reactor pressure vessel and other reactor internal components. The boiler spine design and layout makes physical inspection or repair of the vulnerable welds difficult. The safety case for boiler operations is therefore extremely complex and has required us to develop novel methods of analysis to establish the safety justification. If further material analysis and remote inspection fails to strengthen the current safety case, this could shorten station life at some of our power stations.
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Our Hartlepool and Heysham 1 stations may suffer additional outages as a result of flooding threats.
The potential for turbine hall flooding events at our Hartlepool and Heysham 1 stations resulting in consequential flooding of the reactor buildings was highlighted by the cast iron pipework failure at Heysham 1 in 2003.
It is possible that other unplanned incidents (in particular the possibility of turbine-alternator disintegration) could result in turbine hall flooding. At Hartlepool and Heysham 1 this could also result in flooding of the reactor buildings and may interfere with the electrical equipment that supports the gas circulators causing the gas circulators to become inoperable. Our current safety case requires that the gas circulators are operable when a reactor is shutdown, depressurized and with an air atmosphere.
On the occasions that we are required to shutdown and introduce an air atmosphere to a Hartlepool or Heysham 1 reactor our current safety case requires the threat from turbine hall flooding to be minimized and this is best achieved by shutting down the other reactor/turbine at that station to remove the threat from turbine-alternator disintegration.
We are currently amending our safety cases to avoid this requirement but until we have the necessary safety case in place there is the risk of increased outages which would adversely affect our profits.
Obsolescence of some of our equipment, component parts and computer systems that are required to operate our power stations and monitor plant stability could result in higher operating costs, unplanned losses or the closure of our power stations.
The first of our nuclear power stations became operational in 1976. As a result, it is becoming increasingly difficult to source replacement parts for some older equipment and to find engineers qualified to service certain equipment, in particular our aging computer and other information technology systems that were installed at or about the time the plants were constructed. We may not be able to maintain our older equipment on a cost effective basis or at all. We believe the increasing obsolescence of some of our parts and systems may result in an increase in unplanned losses, longer planned outages, significantly higher repair costs and/or the closure of our stations.
The condition of some of the plant, equipment and components at our power stations is subject to gradual deterioration over time.
The impact on the condition of some of the plant, equipment and components at our power stations of station operations and natural processes such as erosion and corrosion tends to increase as such plant, equipment and components grow older. While we attempt to implement inspection and maintenance practices such that we repair or replace such plant, equipment and components before they fail there is no guarantee that we will be successful and consequently we may experience unplanned losses which will adversely impact on our profitability.
The failure of our AGR fuel could result in decreases in our output and revenues.
Our AGR fuel is contained inside a stainless steel fuel can which acts as the primary barrier for any fission products produced by the fuel during operation. If the steel fuel can cracks, then the fission products will leak into the carbon dioxide gas that is used to cool the reactor. As many of these fission products are radioactive, any major leakage into the carbon dioxide gas will potentially contaminate large parts of the reactor which in turn will lead to major operational difficulties. It is therefore important to minimize fuel failures of this type.
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We have experienced on average one fuel failure per year across our fleet of AGR stations in the period 1975 to 2000. In 2001 and 2002, we experienced ten and nine failures respectively. In 2003 we experienced one fuel failure and we have not experienced any failures in the fiscal year ended March 31, 2004. The increase in fuel failure rates was attributable to fuel failures at our Dungeness B, Hunterston B, Torness, Heysham 1 and Hartlepool stations. We have determined the cause of the failures at Heysham 1 and Hartlepool and we have taken corrective action. We have received initial results on the cause of the fuel failures at Dungeness B which indicates that the cause is different from those at Heysham 1 and Hartlepool but is one that is known to us. Detailed examinations of the fuel failures at Hunterston B and Torness have yet to take place and the reasons for the failures cannot yet be confirmed. Dependent upon the cause of these failures, we may be required to remove fuel from the reactor earlier than anticipated or to operate our reactors at lower power levels to protect the fuel against further failures.
Based on the cause of fuel failures we may have to shut down one or more of our nuclear reactors until we have determined the cause of such failures. In order to do so, we are, in certain cases, reliant upon services provided to us by British Nuclear Fuels plc (“BNFL”) a company wholly owned by the UK Government (the “Government”). If they were unable or unwilling to provide such services, we may be unable to determine the cause of such failures. Any nuclear power station closure or prolonged outage could adversely affect our business and profitability.
Our business depends on equipment and service suppliers of a specialized nature, who may fail to provide necessary equipment and services on a timely basis, discontinue their products or services and/or seek to charge us prices that are not competitive. Any of these events could adversely affect our business and/or profitability.
We depend upon a small number of specialized suppliers for essential products and services which are unique or highly specialized to our industry. Consequently, if our suppliers are unable or unwilling to deliver products and services on a timely basis and at reasonable prices or if their products are found to be faulty, this may impact negatively on our ability to continue to operate our power stations economically (or at all), and would have an adverse effect on our financial condition and results of operations. In addition, as our plants age, the costs associated with the sourcing of spare parts are likely to increase.
Our AGR fuel is fabricated by BNFL, the only supplier of AGR fuel in the world. To protect against any short term disruptions in supply we maintain a stock of fuel elements at each of our sites. This, along with the fuel in our reactors, is sufficient to maintain normal operations for between three to six months. However, we cannot rule out a more extended disruption in fuel supply which could result in reductions in our output.
Our spent AGR fuel is delivered to BNFL which provides spent fuel management services. We are able to store approximately nine months arisings of spent fuel at each nuclear power station and, of that, have approximately three months additional capacity in the event of any short term interruptions in the movement of spent fuel to BNFL’s Sellafield Site. If a station’s spent fuel storage facilities became full, the station could theoretically continue to generate electricity but the volume of electricity produced would gradually reduce as the fuel in the reactor was consumed. It would not be possible to load additional fuel into the reactor until at least the equivalent quantity of stored spent fuel was despatched to Sellafield.
In the case of certain of our contracts for the provision of services, the liability of the service provider is capped and consequential losses that may be suffered by us are excluded. While these are not unusual contractual provisions, the consequences to us of a breach or non-performance by a service provider may be severe (for example certain agreements are required to be in place to meet nuclear site license requirements and may be difficult to replace) and we would almost certainly not be able to recover the loss it may suffer as a result of breach or non-performance by these counterparties.
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Our turbines, generators and certain other plant components are designed, manufactured and maintained by a small number of key suppliers. We are reliant upon certain of these suppliers for the supply of parts and for servicing and maintenance. If they fail to provide parts and/or perform servicing or maintenance, this could result in the shutdown of one or more of our turbines, generators or other plant components.
The unavailability of component parts could adversely affect our revenues and profitability.
The failure of certain components in use at our power stations could result in unplanned outages to affect repairs. The duration of the outages is influenced by, among other things, the lead-time required to manufacture and procure replacement components. Certain components (e.g. turbine rotors and transformers) are complex and may take several months to manufacture. To reduce the impact of the failure of such items we hold spare components at our power stations and in a central storage facility. We also participate in “spares clubs” where the cost of holding expensive replacement components is shared with other parties. Although we aim to optimize our spares holdings we cannot guarantee that we will always have ready access to the required component in the event of a failure and we may incur extended unplanned outages while we obtain the required component.
We continue to face liquidity risks associated with the seasonality of our business and the provision of collateral to our counterparties.
The UK electricity market is characterized by lower demand in the summer months and therefore comparatively lower market prices, which leads us, where possible, to plan statutory outages in this period. Accordingly, positive cash flow is reduced through the combined effect of lower prices and output. In addition, the historic high volatility of market prices increases the liquidity risk as a result of collateral calls due to increases in market prices. While we closely monitor these risks and continue to adopt mitigation strategies through trading and procurement operations, it is possible that these strategies will not be as effective in minimizing these risks as planned.
Lack of liquidity in the wholesale market may adversely affect or require us to alter our trading strategy.
Liquidity in the wholesale electricity market is dependent on there being a sufficient number of counterparties willing to trade actively in the market. Changes to the market structure, and in particular further consolidation of the existing generation and supply businesses, could result in a reduction in the number of active participants in the market. This could reduce the level of liquidity in the wholesale market to such an extent that we are no longer able to rely on wholesale market trading as a means of hedging our short to medium term exposure to wholesale electricity market prices and balancing our portfolio. We also rely on reported prices from a liquid wholesale market to deliver reliable reference prices which are used within a number of our indexed price contracts. Thus a lack of liquidity could result in us incurring higher hedging or balancing costs to achieve our trading objectives.
While our understanding of potential contaminated land liabilities at our power stations continues to grow, we have yet to fully implement risk management systems at all sites that will allow us to monitor liabilities at those sites and develop more informed assessments of any such liabilities. Consequently, we are currently unable to predict the likely cost of all our contaminated land liabilities.
With the exception of Dungeness B, where an extensive remedial operation in response to historic spillages of diesel to ground has now been completed, we currently have only limited data from physical site investigations to support our assessments of contaminated land liability at our power stations. However, an independent expert review was recently carried out to review the potential for any significant contaminated land at our nuclear power stations. This expert review, completed in
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January 2002, suggested that there were no obviously significant problems but it did highlight areas of vulnerability to contamination at a number of our sites and the need to establish groundwater monitoring networks and allied procedures at each.
A ground contamination risk assessment carried out at the Eggborough power station has concluded that the site has significant potential to affect local groundwater quality and is vulnerable to contamination migrating from neighboring landfill sites. Although no significant contamination problems have been observed at the Eggborough power station to date, we cannot be certain that none will occur in the future and therefore cannot exclude the risk of significant unforeseen clean-up costs.
Certain types of nuclear liabilities arising at our power stations will not be covered by the scope of the Nuclear Liabilities Funding Agreement (“NLFA”) or the HLFA under the NLFA and/or the HLFA.
These nuclear liabilities include those which are not connected with nuclear decommissioning and those which are adjudged to have arisen as a result of our safety and environmental compliance standards falling below those of the minimum performance standard or minimum contracting standard agreed under the NLFA or HLFA respectively or by the implementation of operational changes made by us other than to meet current or reasonably anticipated legal or regulatory requirements or to comply with practices and procedures both considered by, and acceptable to, the relevant regulators will not be covered by the NLFA and HLFA and will thus remain for our account. While the definitions of minimum performance standard or minimum Contracting Standard may be known it is not currently certain how such minimum performance standards would be interpreted or applied. It may also be difficult to be certain whether the implementation of operational changes would be considered to meet reasonably anticipated legal or regulatory requirements or to comply with practices and procedures both considered by, and acceptable to, the relevant regulators. Consequently, the nature or amount of these liabilities is uncertain.
The potential hazards of nuclear operations (including nuclear operations carried out by other operators in the UK and elsewhere in the world) could expose us to the risk of material liabilities, lost revenues, increased expenses or reputational damage.
Our operations use and generate radioactive and hazardous substances that have the potential to seriously impact human health and the environment. There are particular risks associated with the operation of nuclear power stations. These include accidents, the breakdown or failure of equipment or processes or human performance, including our safety controls, and other catastrophic events that could result in the dispersal of radioactive material over large areas, thereby causing injury or loss of life and extensive property or environmental damage. Certain of these events, including those arising as a result of third party acts, such as acts of terrorism or war, are not within our control. Liabilities we may incur, and interruptions in the operation of a power station caused by these events or associated with any of the radioactive or hazardous materials involved, could significantly reduce our revenues and increase our expenses and result in negative publicity and significant reputational damage. Insurance proceeds may not be adequate to cover all liabilities incurred, lost revenue or increased expenses. Analogous incidents occurring at other nuclear power stations elsewhere in the world may result in negative publicity and reputational damage regardless of our having no control or influence over such incidents.
The continued operation of the Eggborough power station is subject to a number of factors which could increase our costs and decrease our revenues. In particular, the introduction of the EU Emissions Trading Scheme (“ETS”) and Large Combustion Plant Directive (“LCPD”) are major environmental initiatives which will have an important impact on the Eggborough power station as they seek to reduce carbon dioxide and other emissions.
The Eggborough power station was constructed in the 1960’s and is approaching the end of its originally anticipated operating life. The Eggborough power station has been, and will continue to be,
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subject to routine and other maintenance and repair. In order to continue its economic operation, and to comply with environmental and other regulations, it has also been, and may in future be, necessary to make modifications to the Eggborough power station. We believe that we are likely to be required to make further repairs and/or modifications to the Eggborough power station as its age increases and, insofar as such requirements are currently understood, such requirements are already in our plans.
We cannot guarantee that we will be able to make any required repairs or modifications to the Eggborough power station either economically or at all (including pursuant to our legal obligations under the documentation entered into in connection with our Restructuring). Similarly, we cannot be certain that any such repairs or modifications will successfully rectify any problems and/or allow the continued operation of the Eggborough power station without interruption or at all. This may result in lost output and could adversely affect our revenues and profitability.
The ETS is due to be implemented in January 2005 and will limit pollution by the Eggborough power station. The LCPD is due to become effective on January 1, 2008 and, in replacing the previous Large Combustion Plants Directive (1988/609/EEC), will further restrict the limits of permitted pollution by the Eggborough power station. The full extent of the possible implications of this legislation are not yet known and therefore we cannot be certain of: (i) the impact on output; (ii) the likely costs associated with any required engineering or structural changes to the Eggborough power station which may be required to ensure compliance; or (iii) how the legislation will affect the electricity generation market and, in particular, the price of electricity in the medium to long-term.
We have entered into a trading strategy that seeks to reduce the price risk associated with the cost of our electricity generation. However, this has reduced our ability to benefit from increasing market prices in the medium-term and may also result in an increase in collateral requirements as market prices rise. In addition, should various other unforeseen events occur which place demands on cash flow, our financial resources may prove to be insufficient.
We have entered into short-term and medium-term trading contracts with market counter parties and short-term and medium-term sales contracts with other industrial and commercial customers to hedge a significant proportion of our output against downward movements in market price. However, as a result of this, our cash flow benefits from market price increases are reduced while the level of collateral calls made by trading counter parties increases to cover their mark to market exposure.
We are reviewing our trading strategy to attempt to maintain an appropriate balance between the importance to us of maintaining a high degree of certainty of our revenues and collateral requirements, as well as continuing to take steps to identify and manage cash flow risks and manage cash resources. However, we cannot be certain that the level of funding available to us will be sufficient to meet our future needs.
Our business is subject to extensive and unique regulations.
As an owner and operator of nuclear and coal-fired power stations, we are subject to extensive governmental regulations. We are subject to, among others, nuclear safety, electricity market and environmental regulations of the UK, the EU and other governmental authorities. Unexpected or adverse changes in these regulatory regimes could adversely impact our business and profitability. Changes in regulations or personnel governing nuclear safety in the UK may result in the modification, suspension or revocation of our licenses to operate nuclear power stations, or require us to incur substantial additional cost for capital expenditure and/or services and labor.
A feature of the nuclear licensing regime is that we must conduct Periodic Safety Reviews at each of our nuclear power stations which may affect how we operate our stations and may result in significant additional costs. We must also obtain the approval of the NII to restart a nuclear power station after a statutory outage. In granting permission to re-start, the NII take comfort from the level of
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British Energy’s knowledge and understanding of reactor performance. Consequently, wherever outage inspections indicate potential issues outside of the predicted norm, there is a heightened risk that delays to re-start may occur as a result of the regulator’s intervention. The refusal of the NII to approve, or any delay in gaining approval from the NII, to continue or restart the operation of any of our nuclear power stations, would adversely affect future revenues and reduce our ability to trade profitably.
We are revising certain aspects of the safety cases at our AGR power stations in the light of developing regulatory standards. Whilst we are dedicating significant resources to resolving these outstanding safety case points, there can be no assurance that one of these issues may not lead the NII to refuse consent to restart one of our reactors following a statutory or unplanned outage or cause it to communicate to us that it would oppose our restarting a reactor on its return from a refueling outage. If the NII takes such action, this, too, would affect future revenues and reduce our ability to trade profitability.
We have agreed, in some cases informally, with certain of our suppliers to defer payments due to them.
We have reached, in some cases informal, agreements with certain of our suppliers to defer payments due to them from the summer months until later in the financial year. Cash balances are therefore likely to be higher for the remainder of the financial year as a result. The amount of our trade creditors will however continue to reflect the amount owed to these creditors and will accrue late payment interest in accordance with the terms of the underlying agreements with creditors. In cases where this has not been formalized, we can give no assurance that our creditors will not seek to enforce their respective contractual rights to have the amount due to them paid strictly in accordance with the payment terms of their respective agreements with us. Demands for payments to be made in advance of an agreed deferral schedule by a supplier may reduce the cash available to other parts of our business and may affect our investment, trading or operational decisions which may in turn affect our financial condition or profitability adversely. Since we have already sought deferrals from a number of our creditors this may reduce the likelihood of our being able to achieve further deferrals at other times in the financial year when our cash resources may benefit from some flexibility from our suppliers with regard to payment terms.
A failure to comply with, or the incurrence of liabilities under, environmental, health and safety laws and regulations to which we are subject, or a failure to obtain or maintain required environmental, health and safety regulatory approvals, could adversely affect our business or our ability to trade profitably.
We are subject to various environmental and health and safety laws and regulations governing, amongst other things: (i) the generation, storage, handling, release, use, disposal and transportation of hazardous and radioactive materials; (ii) the emission and discharge of hazardous materials into the ground, air or water; and (iii) decommissioning and decontamination of our facilities and the health and safety of the public and our employees. Regulators in the UK, including the NII, Environment Agency (the “EA”) and the Scottish Environment Protection Agency (“SEPA”), administer these laws and regulations.
We are also required to obtain environmental and safety permits from various governmental authorities for our operations. Certain permits require periodic renewal or review of their conditions and we cannot predict whether we will be able to renew such permits or whether material changes in permit conditions will be imposed. Therefore, we may not have been, or may not at all times in the future be, in complete compliance with such laws, regulations and permits. Violations of these laws, regulations or permits could result in plant shutdowns, fines and/or litigation being commenced against us or other sanctions. Other liabilities under environmental laws, including clean-up of radioactive or hazardous substances, can be costly to discharge. Environmental liabilities or failure to comply with environmental laws could also lead to negative publicity and significant damage to our reputation.
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While we cannot predict with any certainty the nature of developments in environmental regulation and control, we anticipate that the direction of future changes will be toward stricter controls. In view of the age and history of many sites we own or operate, we may incur liability in respect of sites that are found to be contaminated, together with increased costs of managing or cleaning up such sites. Site values could be affected and potential liabilities and clean-up costs may make disposal of potentially contaminated sites more difficult. It is possible that any clean-up costs would have an adverse effect on our business or our financial condition or results of operations.
Environmental and health and safety laws are complex, change frequently and have tended to become more stringent over time. Whilst we have budgeted for future capital and operating expenditures to comply with current environmental and health and safety laws, it is possible that any of these laws will change or become more stringent in the future. Therefore, our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, radioactive or hazardous substances, could adversely affect our business or our operating or financial performance.
The proximity of certain of our nuclear power stations to Magnox stations could result in potentially harmful materials in the ground migrating across the boundary onto our own sites. UK law currently provides that, unless we can provide adequate evidence to the contrary, any liability associated with such material under our sites would belong to us even though its initial occurrence there is beyond our control. Radiological contamination from neighboring Magnox plant may render one of our sites radioactive and would prevent its operation.
Each of Hunterston B, Dungeness B, Hinkley Point B and Sizewell B is located close to Magnox nuclear power stations operated by the British Nuclear Group and its subsidiary companies. Groundwater monitoring networks are now in place at Hunterston B, Dungeness B and Sizewell B that should allow the migration of potentially contaminating material from the neighboring sites to be identified. Although the need has been identified, an equivalent network has yet to be established at Hinkley Point B.
The statutory regime governing contaminated land in the UK provides, broadly, that if the person who is alleged to have caused a contaminated land liability cannot be identified, the land owner/occupier will be held liable for the costs of remedying the problem. Therefore, we cannot be certain that the costs of complying with this regime will not adversely affect our business or our operating or financial performance as it may not always be possible to identify another operator as a responsible party.
Further changes to the regulatory environment in the UK market and introduction of the British Electricity Transmission and Trading Arrangements (“BETTA”) may adversely affect our cash reserves.
BETTA is due to be implemented in April 2005 and will introduce a single Great Britain-wide set of arrangements for trading energy and for access to and use of a single Great Britain transmission system. The current CUSC Framework Agreement, BSC Framework Agreement and the Grid Code will continue to take effect but amendments will be made to them in line with the new regime and the extension of the BSC, CUSC and Grid Code to Scotland. Thus British Energy Generation Limited (“BEG”) as an existing signatory to these agreements will not need to sign any additional documents but British Energy Generation (UK) Limited (“BEG UK”) will need to accede to the framework agreements and the Grid Code by following the steps specified in the respective codes.
The introduction of BETTA is expected to result in changes to the terms and conditions that existing parties have in place for connection to or use of the transmission system and for trading electricity. In the main, the arrangements under BETTA will be based on those currently prevailing in England and Wales. As a consequence, the changes are likely to be particularly significant for those connected to/using the transmission system in Scotland. It is also anticipated that The Office of Gas
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and Electricity Markets (“Ofgem”)/The Department of Trade and Industry (“DTI”) will modify all electricity generation, supply and distribution licenses to oblige the holders to comply with the Grid Code. The introduction of BETTA may also require, among other things, an increase in the amount of cash collateral necessary to support our generation, supply and trading operations. Consequently, it is possible that our cash reserves may also be adversely affected.
Our current sales contract for generation from our two Scottish nuclear stations will expire in April 2006 or earlier upon the implementation of BETTA which may adversely affect our cash reserves.
We currently sell all the output from our Scottish nuclear power stations to Scottish Power and Scottish and Southern Energy under the terms of the Nuclear Energy Agreement (“NEA”). The NEA will continue in operation until the introduction of BETTA or, if earlier, April 1, 2006. BETTA is due to be introduced on April 1, 2005 but it is possible that its introduction will be delayed. Upon the expiry of the NEA, we will need to make alternative sales arrangements for this output and/or constrain output. Alternative sales arrangements may not be available at that time on similar financial terms to the current sales contract. This may also require an increase in the amount of cash collateral necessary to support our generation supply and trading operations. Consequently it is possible that our cash reserves may be adversely affected.
Proposed arrangements governing the cost of electricity transmission in the UK could reduce our ability to trade profitably in the future.
In May 2001, the Gas and Electricity Markets Authority, or GEMA, proposed a number of possible reforms to the market arrangements governing electricity transmission system access and transmission losses in England and Wales. Transmission losses occur from the electricity that is lost to the network in the form of heat as it is transmitted. If GEMA were to implement its proposals in the form which it originally proposed, this would result in a significant redistribution of transmission costs between electricity market participants. Under the proposals, some generators would pay for a proportion of transmission losses for which they were not previously responsible. The proposal would be unfavorable to generating plants located in the North of England and Scotland, which make up a significant portion of our generating capacity.
On January 17, 2003, GEMA directed that a modification should be implemented to the Balancing and Settlement Code, to introduce zonal marginal transmission losses, with effect from April 2004 in England and Wales. On January 30, 2003, the Government issued a consultation paper on whether these changes were appropriate for Great Britain as a whole, and concluded, on June 27, 2003, that they were not. However, there is a risk that a new proposal to introduce zonal charging for losses will be made if the arrangements under BETTA are introduced in April 2005. These charging arrangements for access to and use of the transmission network are not yet finalized and therefore there is a risk that we might be adversely affected by them given the geographical distribution of our power stations.
We are involved in several disputes that if resolved or determined against our interests could adversely affect our profitability and our available cash.
Bruce Power
On February 12, 2004, the consortium that purchased our 82.4% interest in Bruce Power served a notice on us alleging a breach of certain warranties and representations relating to tax and to the condition of plant at the Bruce power station.
The tax claim relates to the treatment of expenditures at the Bruce plant during the period of our ownership which is currently under review by the Canadian tax authorities. While we have proposed a treatment that could result in a material tax rebate, the consortium claims that the allowance of the expenditures for that period would cause it to lose future deductions.
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The claim relating to the condition of the plant is based upon alleged erosion of certain parts of the steam generators including support plates through which boiler tubes pass. It is alleged that this erosion resulted in an extended outage at one unit at the plant in order 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 or result in expenditures for further repairs. We have rejected the foregoing claims and intend to defend them if they are pursued further and thus further losses. In accordance with accounting standards, no provision has been made in the financial statements at June 30, 2004 for either claim.
AmerGen
We are involved in a dispute with Exelon arising in connection with the sale of our 50 per cent. interest in AmerGen to Exelon. Under the terms of the AmerGen sale agreement, we gave certain indemnities and guarantees in connection with the sale of our interest. As a result of an accounting adjustment made by Exelon to the value of nuclear fuel contained in AmerGen’s balance sheet dated December 21 2003, we may be required to make a payment to Exelon of up to US$13.7 million. British Energy disputes such claim. We served a dispute notice on Exelon on June 4 2004 to preserve our rights and the parties are endeavoring to resolve the matter amicably. The agreement with Exelon for the sale of AmerGen requires that, prior to instituting any litigation or other dispute resolution procedure, the companies will in good faith seek to resolve any dispute. Furthermore, we are reviewing with Exelon the effect on the working capital adjustment resulting from a change to the estimated tax recoverable for the prior periods made after the consummation of the sale, and this, if agreed may result in a reduction in the purchase price payable by Exelon. The reduction in the purchase price is currently estimated to be in the range of up to US$6.3 million.
If either of the Bruce claims or the AmerGen dispute is resolved against us, it could have a adverse effect on our results of operation and our available cash.
We do not currently own the rights of support for the land under the Eggborough Station.
The Eggborough Station does not enjoy a protected right of support. As a result, there is presently no restriction on coal mining taking place in circumstances whereby the stability of the Eggborough Station could be affected. We have tried, without success, to negotiate with UK Coal Mining Limited (“UKC”) (the holders of a license from the Coal Authority to mine coal) a pillar of support agreement.
If UKC were to mine under or in proximity to the Eggborough station in circumstances affecting its stability, then extensive liabilities would fall on UKC pursuant to the Coal Mining Subsidence Act 1991. Under this Act, the coal operator is required to carry out remedial works and/or make payments for the consequences of the mining damage.
We have submitted an application to the Secretary of State pursuant to the Mines (Working Facilities and Support) Act 1966 for restrictions to be imposed on the working of minerals under part of the Eggborough Station, and land adjacent to it as may be necessary to secure sufficient support for that area. If the Secretary of State is satisfied that a case has been established, the application will be referred to court. The court can only grant the application if it is considered to be in the national interest that restrictions on mining should be imposed. In order to limit our potential liability to pay compensation, we have only applied for the restriction of mine working of the area covered by a previous notice served earlier in 2004.
There can be no guarantee that our application to the Secretary of State to refer this matter to the court will be successful, or that if it is, that the court will find in our favor. We believe that if the court were to find in our favor, compensation is unlikely to be payable to UKC. If our application is not successful, or the court does not find in our favor, UKC would be permitted to mine in the area beneath the power station and the stability of the Eggborough Station might be adversely affected. If this were to occur, it may not be possible to continue the operation of the Eggborough Station, or substantial repairs could be required, and the compensation that UKC would be required to pay under the Coal Mining Subsidence Act might adversely affect our financial condition.
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Our right to title to certain ash and water pipelines which benefit Gale Common and the Eggborough power station is not registered with the Land Registry and is based solely on statutory declarations. In the event that we cannot establish title by long use of these pipelines, we would be unable to continue to benefit from them and the operation of Gale Common and the Eggborough power station would be adversely affected.
Title to the use of much of the ash pipeline at the Eggborough power station, the water pipeline from Gale Common to the River Aire and sections of the Eggborough cooling water pipes is not granted by deed nor referred to on the relevant registers at the Land Registry and is based solely on statutory declarations for a period from 1974 (in relation to the water pipelines) and from 1983 (in relation to the ash pipelines and cooling water pipes). The evidence contained in the statutory declarations will only be an effective step towards establishing title by long use provided that no contrary evidence comes to light which cannot be satisfactorily explained and no arguments are upheld based on lack of relevant knowledge of the existence of the pipelines by landowners. We cannot guarantee that we will be able to establish title by long use and therefore that if the pipelines were disconnected, that the work required to relocate them would not be detrimental to the operation of Eggborough power station.
In addition, title to the use of the remainder of the ash pipeline is based on the grant of licenses, many of which are terminable on notice of various lengths but frequently of six months or less.
The cost of providing pensions benefits to employees is subject to changes in pension fund values and changing demographics, and might have a material adverse effect on our financial results.
We operate two pension schemes that provide defined benefits to eligible recipients. Our actuaries are undertaking actuarial valuations of the two pension schemes as at March 31, 2004 and these are expected to be completed in October 2004. The combined funding deficiencies (on the actuarial bases used for the valuations) in the two pension schemes is expected to be £385 million. The investment performance of our pension fund assets may have an adverse effect on our business. The cost of providing pension benefits could increase as a result of changes in pension fund values and changing demographics, including longer life expectancy of the schemes’ beneficiaries. We may be required to recognize a charge to our profit and loss account to the extent that the pension fund values are less than the total anticipated liability under the plan. In addition, we may be required to contribute additional amounts to our pension funds to address any difference between pension fund values and accrued liabilities. We cannot assure you that such charges or payments will not have an adverse effect on our financial condition.
Our inability to attract and retain senior management and employees who are highly qualified nuclear specialists could adversely affect our business.
The success of our operations depends largely on our ability to attract and retain senior management and employees who are highly skilled in nuclear sciences or have exceptional experience operating nuclear power plants and suitably qualified finance staff. There is a limited pool of candidates with these credentials and, because competition among employers for these candidates is intense, we may not always be successful in hiring or retaining them.
Our trading contracts and certain of our other contracts may be subject to credit support obligations, such as the posting of collateral. Trading without the constraints of available collateral may increase our exposure to both fluctuations in wholesale electricity prices and potential disruptions to our generation business. We may have to post additional amounts of cash as collateral to support our trading activities, which could reduce the amount of cash available for other purposes or exceed our available cash resources. Certain counterparties require other types of collateral which would increase our requirements for third party finance or, if not provided, may affect their willingness to trade with us.
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As our credit rating is below investment grade, we have needed to establish alternative credit support to a parent company guarantee in respect of our obligations under certain trading contracts by posting collateral to support our obligations under these agreements. In the case of a significant proportion of our contracts, the financial obligations to be covered by the alternative credit support are generally related to the prevailing wholesale price of electricity. During a period of rising market prices, the amount of collateral that we are required to post will generally increase. In periods of rising market prices, the increase in the level of collateral that we could be required to post may result in us having to reduce expenditures in other areas, including capital expenditures and could exceed our available cash resources. Since notification of the EC State Aid decision on September 22, 2004 no incremental collateral can be posted under the Government Facility and therefore incremental collateral requirements are being provided by a charge over cash deposits in certain of our accounts. Although we are satisfied that generally deposits in such accounts will represent reasonably acceptable alternative credit support, in certain cases other types of collateral may be required and no assurance can be given that the provision of such charge arrangements for such collateral requirements will not affect the willingness of certain counterparties to trade with us. This may increase our requirements for third party finance and may adversely affect our financial results. For further details on the Government Facility see “Item 4—Information on the Company—the Government Facility”.
Given our circumstances and the Restructuring, certain of our contracts may be capable of being terminated.
Given our circumstances certain contracts including GTMAs may be capable of being terminated. Although we have faced financial difficulties for some two years, we continue to have trading relationships with a high proportion of our contracted counterparties from 2002 and our circumstances and the Restructuring have been widely known for many months. We would likely vigorously resist attempts by counterparties to terminate contracts on these grounds. However, no assurance can be given that counterparties will not successfully exercise termination or other default rights on these grounds even after completion of the Restructuring, in which case we may be liable for termination payments or payments may be withheld from us or supplies of goods or services to our business may be interrupted, any of which could have an adverse affect on our cash flows or our operations.
The amount of insurance cover we are mandatorily required to maintain in relation to nuclear liabilities by virtue of the Nuclear Installations Act will increase significantly, and there is no assurance that cover for nuclear liability for acts of terrorism will be available from the nuclear pool in future.
In early 2004 the Government signed an international treaty amending the existing international Conventions dealing with third party liability in the field of nuclear energy with the effect that, amongst other things, the liability of nuclear operators for events involving nuclear material or ionising radiation which cause damage or personal injury is likely to be increased to €700 million. Furthermore, the definition of nuclear damage is likely to be expanded to include, amongst other things, economic loss. It is likely that the NIA will be amended to increase the level of insurance cover we are required to maintain from the existing £140 million to €700 million. While the directors believe the insurance market will have sufficient capacity to offer cover for these increased limits, there is no assurance that such cover will be available when required nor that the cost of the insurance will increase in line with the increases in liability limit on a straight-line basis. Our insurers may also seek exclusions and/or higher levels of retention which may affect the ability to make a claim if required to do so.
Cover for nuclear liability sustained by acts of terrorism has been obtained for the year ending March 30, 2005 from the nuclear pool. The limit for this cover and the right of recovery by insurers mirrors that under the NIA in respect of nuclear liability. The Nuclear Pool indicated following the terrorist attacks in the World Trade Center in New York that it would not provide cover for nuclear liability without agreement from the Government that the Government would provide reinsurance cover. This arrangement is subject to annual review and has been forthcoming for the last three years. There is no assurance that the Government will be able to do so in the future.
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RISKS RELATING TO COMPLETION OF THE RESTRUCTURING
The Restructuring remains subject to a large number of significant uncertainties and important conditions, and if we do not complete the Restructuring, we may have to initiate insolvency proceedings.
The Restructuring remains subject to a number of significant uncertainties and important conditions. These include settling certain documents with creditors, approval of the relevant UK court and listing of the new shares and new bonds. The Restructuring is also conditional on there being no material adverse change affecting us as a whole or Eggborough Power Limited (“EPL”) and no material adverse effect on the value of the creditors’ entitlements under the Restructuring. Furthermore, the Secretary of State is entitled not to proceed with the Restructuring if, in her opinion, we will not be viable in all reasonably foreseeable conditions without access to additional financing beyond that which is committed and will continue to be available when required. Also, for listing purposes, the restructured British Energy will need to have sufficient working capital for its present requirements from listing of the new shares and new bonds. The Restructuring is conditional on the restructuring and standstill arrangements not being terminated in accordance with their terms. Furthermore, to the extent the Members’ Scheme of Arrangement lapses and the disposal of our assets for the purposes of the Restructuring is not approved by shareholders, the Restructuring is also conditional on the delisting of the Company from the Official List of the UK Listing Authority (“UKLA”). For additional information regarding the contracts governing the Restructuring and the delisting, see “Item 10. Material Contacts” and “Item 4. Information on the Company—Impact of the Restructuring on Existing Shareholders and Recent Developments—Requisitioned Extraordinary General Meeting and Delisting”. Some uncertainties which may affect the cash flow position, performance or outlook are described in Item 5. Operating and Financial Review and Prospects.
If the conditions to the Restructuring are not fulfilled, or if our cash generating initiatives are not achieved in each case within the time scales envisaged or required, or if there is a material deterioration in our cash flow position, performance or outlook or if the restructuring and standstill arrangements which we have entered into with certain of our creditors are terminated, we may be unable to meet our financial obligations as they fall due and consequently we may have to take appropriate insolvency proceedings, in which case the distributions, if any, to unsecured creditors may represent only a small fraction of their unsecured liabilities and it is highly unlikely there will be any return to shareholders. Further details on the Restructuring are contained in note 1 to our audited consolidated financial statements.
The decision of the European Commission (the “Commission”) that, insofar as the Restructuring involves the grant of State aid by the Government, such State aid is compatible with the common market (the “Decision”), may be appealed against by interested third parties in the EC Court resulting in the annulment in whole or in part of the Decision, or the possible imposition of further conditions on the Company; third parties may also seek an order from the EC Court suspending the grant of State aid by the Government. Interested third parties may also complain to the Commission or bring actions in the Courts in the UK alleging that the Company or the Government are not complying with any of the conditions in the Decision. Any of these events could adversely affect our business or profitability.
On September 22, 2004, we announced the receipt by the Secretary of State of the Decision. The Decision may be appealed to the Court of First Instance of the European Communities (the “CFI”) by any interested third parties provided that they can show that they are directly and individually concerned by the Decision. A party will be individually concerned by a State aid decision if it can show, for example that its competitive position in the market was or may be adversely affected by the
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Decision. The Decision may also be appealed to the Court of Justice of the European Communities (the “ECJ”) by the government of any other EC Member State. In each case the application for the appeal must be filed within two months and ten days from either (a) the date when the Government or any interested third party receives a full copy of the Decision from the Commission or (b) from the date of the publication of the Decision in the Official Journal of the European Communities, where the interested third party has not already received a copy of the Decision from the Commission.
An appeal to either the CFI or the ECJ may result in the Decision being annulled in whole or in part. In addition, upon application and upon satisfaction of the legal requirements, the CFI or the ECJ may suspend the Decision, or apply other interim measures, pending a final ruling on the appeal.
In the event of the Decision being annulled, the Commission would be required to issue a new decision taking into account the judgement of the ECJ or CFI. This further decision could either impose additional conditions on us depending on the reasons for the annulment of the Decision, or conceivably not approve the State Aid at all or approve only parts of it. Any judgment of the CFI can be appealed to the ECJ, but only on points of law.
Furthermore, any interested third party may also complain at any time to the Commission alleging that either we or the Government are in breach of any of the conditions imposed by the Decision. There can be no assurance that the Commission may not, as a result of any investigation it makes into the complaint, order the recovery of any aid which has been unlawfully given as a result of a breach and/or modify the conditions of the Decision or impose additional ones.
Any interested third party which can show sufficient interest (under English law) or both title and interest to sue (under Scottish law) can also bring an action in a Court in the appropriate jurisdiction alleging that either we or the Government are in breach of any of the conditions imposed by the Decision. The Court could decide to consult with the Commission or to refer questions to the ECJ in so far as it considers them to be necessary to interpret or apply the provisions of the Decision that may be in dispute. There can be no assurance that the Court would not order that the arrangements whereby the Government provides aid to the Company be suspended pending compliance with the Decision. Furthermore, the Court could order any aid given in breach of the Decision to be recovered from the Company by the Government. Any such appeals or procedures may have an adverse effect on the Company and our shareholders.
The proposed Creditors’ Scheme of Arrangement with the holders of our bonds (the “Bondholders”) due in 2003, 2006 and 2016 respectively and the Royal Bank of Scotland plc “RBS”) requires the approval of the relevant UK court; without such approval, our Restructuring will not be able to proceed.
To become effective, the Creditors’ Scheme of Arrangement requires the approval of the relevant UK court that supervises the scheme. Before the court gives its approval, the court must satisfy itself that the proposed arrangements are fair. We cannot assure you that the court will determine that the restructuring arrangements contemplated by the Creditors’ Scheme of Arrangement are fair, or that the court will not conclude that there are other reasons why it should not approve the Creditors’ Scheme of Arrangement. If the relevant UK court does not approve the Creditors’ Scheme of Arrangement, we may not be able to complete our Restructuring as envisaged. It is possible for a person with an interest in the Creditors’ Scheme of Arrangement (whether a scheme creditor, a bondholder or another person) to raise objections or, after receipt of the court order, to appeal against the granting of the court order approving the Creditors’ Scheme of Arrangement. There can be no assurance that such objections or appeals will not delay or possibly prevent the Restructuring.
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If certain timing deadlines are not satisfied, the Restructuring may not be implemented.
In order for the Creditors’ Scheme of Arrangement to be effective, the outstanding conditions and uncertainties must be satisfied or resolved and the Creditors’ Scheme of Arrangement must receive the sanction of the court. The timing of the court process is in the discretion of the court and accordingly there can be no assurance that the court process to effect the Creditors’ Scheme will be completed by the earlier of 120 days after the satisfaction of the initial conditions and January 31, 2005 (or such later date as the Company and parties to the Restructuring may agree) as required by the documentation entered into in connection with the Restructuring. In the event that the Creditors’ Scheme is not effective by such date, the Creditor Restructuring Agreement will automatically terminate and the standstill period under the standstill arrangements will expire.
If the Nuclear Liabilities Fund (the “NLF”) does not become effective, we may be required to make substantial payments to meet the long-term post-closure costs of decommissioning our existing nuclear power stations in the UK.
In the UK we established the Decommissioning Fund to accumulate funds to meet certain long-term post-closure costs of decommissioning our UK nuclear assets. We made, and until the NLF is operational, will continue to make, quarterly contributions to the Decommissioning Fund that are subject to adjustment for inflation. However, there is no certainty that the Decommissioning Fund will be sufficient to cover all the liabilities to which it relates. Furthermore, other substantial decommissioning liabilities are currently unfunded and the value of the Decommissioning Fund is subject to the volatility and fluctuations of the equity markets. As part of the Restructuring, the Decommissioning Fund will be enlarged and renamed NLF to which we will make fixed contributions as well as an initial contribution of £275 million aggregate principal amount by way of new bonds. Additionally we will contribute £150,000 (indexed to the retail price index) for every ton of uranium loaded into Sizewell B our Pressurised Water Reactor nuclear power station, or PWR, after completion of the Restructuring, and payments amounting (initially and subject to adjustment) up to 65% of our consolidated annual cash flow net of tax, financing costs, cash reserves and a forecast expenditure reserve. However, we expect that as part of the establishment of the NLF, the Government will fund contracted liabilities associated with our historic spent fuel as well as certain uncontracted nuclear liabilities and decommissioning costs of our nuclear power stations to the extent that the assets of the NLF are insufficient to meet those liabilities as they fall due. Furthermore, as a condition of the NLF, we will be required to continue to operate our nuclear power stations in compliance with applicable law and the practices and the procedures acceptable to the safety and environmental regulatory authorities. If we fail to do so, we may in certain circumstances incur additional liabilities over and above those which we currently expect to bear under the NLF.
If the NLF does not become effective, we will be required to continue to make contributions to the Decommissioning Fund pursuant to our obligations under our nuclear site licenses, and will be required to meet other historic unfunded liabilities and certain decommissioning liabilities, which may in turn significantly reduce our ability to trade profitably.
Our revised contracts with BNFL are contingent upon completion of the Restructuring, and our reliance on BNFL as our single supplier for AGR fuel and spent fuel management services could lead to increased costs and decreased profitability upon termination of the revised contracts if the Restructuring is not completed.
We currently rely on BNFL to supply fuel fabrication and spent fuel management services for our Advanced Gas Cooled Reactor, or AGR, stations. BNFL is currently the sole supplier of AGR fuel worldwide. On May 16, 2003, we announced that we had entered into a series of contracts with BNFL, replacing our then current contracts covering the fabrication of fuel for our AGR power stations, known
21
as front-end fuel cycle services, and the disposal of AGR fuel used by our AGR power stations, known as back-end fuel cycle services. The front-end fuel cycle contracts became effective as of April 1, 2003, but, with the exception of the new arrangements for the supply of uranics, may be terminated if, among other things, the Restructuring is not completed. The back-end fuel cycle contracts are conditional upon completion of the Restructuring, although, in accordance with the terms of the standstill agreement, our payments to BNFL for back-end fuel cycle services are made as if the back-end contracts had become effective on April 1, 2003.
Under these contracts, prices for a certain proportion of front-end and back-end fuel cycle services are linked to the prevailing market price for electricity, thereby reducing our exposure to downward fluctuations in market price, conversely if market prices rise above certain levels, a proportion of our costs under the revised BNFL contracts will increase.
If we do not complete the Restructuring, and our revised contracts with BNFL are terminated (or do not take effect), we would be required to rely upon our prior front-end and back-end fuel cycle contracts with BNFL. Consequently, we would be unable to realize the operating cost benefits associated with our revised contracts with BNFL. Furthermore, our current contract with BNFL for the supply of front-end fuel cycle services for the majority of our AGR stations expires in 2006. If the revised contracts with BNFL are terminated (or do not take effect) and if BNFL is unable or unwilling to continue to supply fuel to our AGR stations, we would need to seek a new source of supply for AGR fuel. A new supplier of fuel for our AGR stations would need to retool its production systems in order to be able to produce AGR fuel. The costs of such a retooling would probably be passed on to us, resulting in significantly increased operating costs and reduced profitability.
If we complete the Restructuring, our shareholders will suffer a very significant dilution of their interests in British Energy plc.
Under the Restructuring, we will undertake a court sanctioned scheme of arrangement, referred to as the Creditors’ Scheme of Arrangement, to restructure our obligations with respect to the Bondholders and RBS, as provider of a letter of credit to the bank syndicate that provided financing for our Eggborough coal-fired power station (referred to collectively as the “Eggborough Banks”). As part of the Restructuring, we will also undertake a court sanctioned scheme of arrangement, referred to as the Members’ Scheme, for our shareholders to effect the cancellation of our ordinary shares and the issuance of ordinary shares in British Energy Group plc, the proposed holding company of the restructured group. The Restructuring also includes arrangements to restructure our obligations to the Eggborough Banks and our significant trade creditors; Teesside Power Limited, Total Gas & Power Limited and Enron Capital & Trade Europe Finance LLC (Teesside Power Limited, Total Gas & Power Limited and Enron Capital & Trade Europe Finance LLC are referred to collectively as the “Significant Creditors”). The Significant Creditors have since transferred their interests to Deutsche Bank. As a result of these arrangements, the new shares issued to the Bondholders, RBS, the Eggborough Banks and the Significant Creditors will represent substantially all of the share capital of the restructured British Energy. In the event that the Members’ Scheme is implemented we expect that our current shareholders will receive 2.5% of the issued share capital of the restructured British Energy and warrants exercisable for up to a further 5% of the thereby diluted issued share capital of the restructured British Energy immediately following completion of the Restructuring. If the Members’ Scheme is not approved, but instead our shareholders approve the disposal by us of all of our subsidiaries and other assets to British Energy Holdings plc (a wholly-owned subsidiary of British Energy Group plc) in consideration for it agreeing to discharge our liabilities (the “Disposal”) the shareholders will receive the warrants exercisable for ordinary shares of British Energy Group plc but no shares. If shareholders do not vote in favor of either proposal they would receive no shares or warrants. Consequently, if the Restructuring is completed, our current shareholders will suffer a significant dilution of their interests.
22
Certain shareholders have threatened action to prevent the Restructuring occurring.
On September 3, 2004 Polygon Investment Partners LLP (“Polygon”) and Brandes Investment Partners LLC (“Brandes”) and their respective associates as owners of 10.22% of our ordinary shares requisitioned an extraordinary general meeting of shareholders (the “Requisitioned EGM”) to consider five resolutions. The resolutions were in brief summary: (1) to prevent the Company delisting from the Official List of the UKLA; (2) to prevent the Company from amending or extending the Creditors Restructuring Agreement; (3) to prevent the Company from disposing of its business or issuing shares in itself or any of its subsidiaries; (4) advising the board to seek to negotiate better terms for shareholders than those set out in the Restructuring; and (5) advising the board not to delist from the Official List of the UKLA. In response to the requisition, we have summoned an extraordinary general meeting of shareholders to be held on October 22, 2004. We are taking steps, described in a circular issued by us to shareholders on September 24, 2004, to enable us to implement the Restructuring even if some or all of the resolutions are passed. However no assurances can be given that such steps will be successfully implemented. On September 30, 2004, Polygon announced that in light of the recent circulars that we sent to shareholders, it had agreed to vote the ordinary shares of the Company owned by it against the proposed resolutions at the Requisitioned EGM and not to further oppose the Restructuring. While Polygon also announced on September 30, 2004 that it believes there is no commercial logic in proceeding with the Requisitioned EGM or supporting the proposed resolutions, the Requisitioned EGM will still take place on October 22, 2004 as described in the notice contained in the relevant circular mailed to our shareholders, and no assurance can be given that Brandes or other shareholders (acting individually or as a group) will be unable, through any shareholder action, exercise of voting rights, lobbying or court action, to prevent the Restructuring being implemented. If shareholders are able to prevent the Restructuring from being implemented as currently structured, we may be subject to significant liability under the Creditor Restructuring Agreement and may be unable to meet our financial obligations as they fall due. As such, we may have to take appropriate insolvency proceedings, in which case the distributions, if any, to unsecured creditors may represent only a small fraction of their unsecured liabilities and there is highly unlikely to be any return to shareholders. For further details on the Restructuring, see “Item 4—Restructuring” and note 1 to our audited consolidated financial statements starting on page F-1.
Our financial statements have been prepared on the basis that British Energy is a going concern. If we cease to be a going concern, we may be required to adjust the monetary value of assets, reassess our provisions for future liabilities and reclassify fixed assets and long-term liabilities as current assets and liabilities.
Our financial statements have been prepared on the basis that British Energy is a going concern. The going concern basis assumes that we will continue in operational existence for the foreseeable future. The validity of this assumption depends upon a number of factors that are beyond our control, including those discussed above. If for any reason we are unable to complete the Restructuring and cease to be a going concern, we may be required to adjust the monetary value of assets, reassess our provisions for future liabilities and reclassify fixed assets and long-term liabilities as current assets and liabilities. Such adjustments, reassessments and reclassifications may result in a material adverse change to the statement of our financial condition from that currently set forth in our financial statements. For additional information, see note 1 to our audited consolidated financial statements.
The following summary consolidated financial information for British Energy, insofar as it relates to profit and loss and cash flow for the fiscal years ended March 31, 2004, 2003, and 2002, and balance sheets as of March 31, 2004 and 2003 is derived from the audited financial statements appearing elsewhere in this annual report.
23
Our consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United Kingdom, or UK GAAP, which differs in certain significant respects from generally accepted accounting principles in the United States, or US GAAP. A full description of the significant differences between UK GAAP and US GAAP as they apply to us and a reconciliation of profit/(loss) after tax (or net income/(loss)) and equity shareholders’ funds (or deficit on equity shareholders funds) under UK GAAP to those under US GAAP are set out in note 36, (as restated), to our consolidated financial statements and in “Item 5. Operating and Financial Review and Prospects—Critical Accounting Policies.”
Our financial statements have been prepared on the basis that we are a going concern. The going concern basis assumes that we will continue in operational existence for the foreseeable future. The validity of this assumption depends upon a number of factors that are beyond our control, including those discussed above. If for any reason we are unable to complete our proposed Restructuring and cease to be a going concern, we may be required to adjust the monetary value of assets, reassess our provisions for future liabilities and reclassify fixed assets and long-term liabilities as current assets and liabilities. Such adjustments, reassessments and reclassifications may result in a material adverse change to the statement of our financial condition from that currently set forth in our financial statements. You should read the following summary consolidated financial information in conjunction with our audited consolidated financial statements and the notes thereto appearing elsewhere in this annual report as well as “Item 4. Information on the Company—Restructuring” and “Item 5. Operating and Financial Review and Prospects.”
24
| Year ended March 31, |
|||||||||||||||||||||||
| 2004(5) |
2004 |
2003 |
2002 |
2001 |
2000 |
||||||||||||||||||
| (restated)(1) | |||||||||||||||||||||||
| (in millions, except earnings and dividends per share and per ADS and weighted average shares) |
|||||||||||||||||||||||
| Profit and Loss Account Information: |
|||||||||||||||||||||||
| UK GAAP |
|||||||||||||||||||||||
| Turnover |
$ | 2,774 | £ | 1,516 | £ | 1,903 | £ | 2,049 | £ | 2,124 | £ | 2,058 | |||||||||||
| Turnover—continuing operations |
2,774 | 1,516 | 1,528 | 1,701 | 2,124 | 2,058 | |||||||||||||||||
| Turnover—discontinued operations(4) |
— | — | 375 | 348 | — | — | |||||||||||||||||
| Operating profit/(loss) |
622 | 340 | (3,802 | ) | (281 | ) | 280 | 412 | |||||||||||||||
| Operating profit/(loss)—continuing operations |
622 | 340 | (3,899 | ) | (333 | ) | 280 | 412 | |||||||||||||||
| Operating profit/(loss)—discontinued operations(4) |
— | — | 97 | 52 | — | — | |||||||||||||||||
| Profit/(loss) before taxation |
425 | 232 | (4,292 | ) | (493 | ) | 57 | 225 | |||||||||||||||
| Taxation |
4 | 2 | 368 | (25 | ) | (48 | ) | (118 | ) | ||||||||||||||
| Profit/(loss) after taxation |
429 | 234 | (3,924 | ) | (518 | ) | 9 | 107 | |||||||||||||||
| Dividends(2) |
— | — | — | (48 | ) | (48 | ) | (48 | ) | ||||||||||||||
| Basic earnings/(loss) per ordinary share(s) |
71.2 | 38.9 | p | (654.7 | )p | (88.5 | )p | 1.2 | p | 16.4 | p | ||||||||||||
| Basic earnings/(loss) per ordinary share(s)—continuing operations |
71.2 | 38.9 | p | (670.8 | )p | (97.2 | )p | 1.2 | p | 16.4 | p | ||||||||||||
| Basic earnings/(loss) per ordinary share(s)—discontinued operations(4) |
— | — | 16.1 | p | 8.7 | p | — | — | |||||||||||||||
| Basic earnings/(loss) per ADS(3) |
5,339 | 2,918 | p | (49,103 | )p | (6,638 | )p | 90 | p | 1,230 | p | ||||||||||||
| Basic earnings/(loss) per ADS(3)—continuing operations |
5,339 | 2,918 | p | (50,310 | )p | (7,290 | )p | 90 | p | 1,230 | p | ||||||||||||
| Basic earnings/(loss) per ADS(3)—discontinued operations(4) |
— | — | 1,208 | p | 652.5 | p | — | — | |||||||||||||||
| Diluted earnings/(loss) per ordinary share(s) |
71.2 | 38.9 | p | (654.7 | )p | (88.5 | )p | 1.2 | p | 16.1 | p | ||||||||||||
| Diluted earnings/(loss) per ordinary share(s)—continuing operations |
71.2 | 38.9 | p | (670.8 | )p | (97.2 | )p | 1.2 | p | 16.1 | p | ||||||||||||
| Diluted earnings/(loss) per ordinary share(s)—discontinued operations(4) |
— | — | 16.1 | p | 8.7 | p | — | — | |||||||||||||||
| Diluted earnings/(loss) per ADS(3) |
5,339 | 2,918 | p | (49,103 | )p | (6,638 | )p | 90 | p | 1,208 | p | ||||||||||||
| Diluted earnings/(loss) per ADS(3)—continuing operations |
5,339 | 2,918 | p | (50,310 | )p | (7,290 | )p | 90 | p | 1,208 | p | ||||||||||||
| Diluted earnings/(loss) per ADS(3)—discontinued operations(4) |
— | — | 1,208 | p | 652.5 | p | — | — | |||||||||||||||
| Dividends per ordinary share, net(2) |
— | — | — | 8.0 | p | 8.0 | p | 8.0 | p | ||||||||||||||
| Dividends per ADS, net(2)(3) |
— | — | — | 600.0 | p | 600.0 | p | 600.0 | p | ||||||||||||||
25
| Year ended March 31, |
||||||||||||||||||||||||
| 2004(5) |
2004 |
2003 |
2002 |
2001 |
2000 |
|||||||||||||||||||
| (restated)(7) | (restated)(7) | (restated)(6) | (restated)(1)(6) | |||||||||||||||||||||
| (in millions, except earnings and dividends per share and per ADS and weighted average shares) |
||||||||||||||||||||||||
| US GAAP |
||||||||||||||||||||||||
| Turnover |
$ | 2,774 | £ | 1,516 | £ | 1,903 | £ | 2,049 | £ | 2,124 | £ | 2,058 | ||||||||||||
| Turnover—continuing operations |
2,774 | 1,516 | 1,528 | 1,701 | 2,124 | 2,058 | ||||||||||||||||||
| Turnover—discontinued operations(4) |
— | — | 375 | 348 | — | — | ||||||||||||||||||
| Profit/(loss) after taxation |
13,839 | 7,562 | (7,800 | ) | (343 | ) | (124 | ) | 40 | |||||||||||||||
| Pro forma net (loss)/income as if FAS 143 has been applied effective April 1, 2001(8) |
— | — | (4,660 | ) | 112 | — | — | |||||||||||||||||
| Basic and diluted earnings/(loss) per ordinary share(s) |
2,298 | 1,256 | p | (1,296 | )p | (57.4 | )p | (21.0 | )p | 6.3 | p | |||||||||||||
| Basic and diluted earnings/(loss) per ordinary share(s)—continuing operations |
(24 | ) | (13 | )p | (1,305 | )p | (45.8 | )p | (21.0 | )p | 6.3 | p | ||||||||||||
| Basic and diluted earnings/(loss) per ordinary share(s)—discontinued operations(4) |
— | — | 9 | p | 2.8 | p | — | — | ||||||||||||||||
| Basic and diluted earnings/(loss) per ordinary share(s) arising from cumulative effect of change in accounting |
2,322 | 1,269 | p | — | (14.4 | )p | — | — | ||||||||||||||||
| Basic and diluted earnings/(loss) per ADS(3) |
172,386 | 94,200 | p | (97,176 | )p | (4,302 | )p | (1,575 | )p | 472.5 | p | |||||||||||||
| Basic and diluted earnings/(loss) per ADS(3)—continuing operations |
(1,784 | ) | (975 | )p | (97,836 | )p | (3,432 | )p | (1,575 | )p | 472.5 | p | ||||||||||||
| Basic and diluted earnings/(loss) per ADS(3)—discontinued operations(4) |
— | — | 660 | p | 210 | p | — | — | ||||||||||||||||
| Basic and diluted earning/(loss) per ADS(3) arising from cumulative effect of change in accounting |
174,170 | 95,175 | p | — | (1,080 | )p | — | — | ||||||||||||||||
| Weighted average number of ordinary shares(millions) |
602 | 602 | 602 | 598 | 597 | 651 | ||||||||||||||||||
| As at March 31, |
||||||||||||||||||||||||
| 2004(5) |
2004 |
2003 |
2002 |
2001 |
2000 |
|||||||||||||||||||
| (restated)(1) | ||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||
| Balance sheet information: |
||||||||||||||||||||||||
| UK GAAP |
||||||||||||||||||||||||
| Fixed assets |
$ | 1,715 | £ | 937 | £ | 763 | £ | 4,909 | £ | 5,245 | £ | 5,620 | ||||||||||||
| Total assets |
4,893 | 2,674 | 2,177 | 6,775 | 6,784 | 7,051 | ||||||||||||||||||
| Provisions and long term liabilities |
(8,036 | ) | (4,391 | ) | (4,375 | ) | (5,173 | ) | (4,931 | ) | (4,490 | ) | ||||||||||||
| Equity shareholders’ (deficit)/funds |
(5,960 | ) | (3,257 | ) | (3,476 | ) | 490 | 1,075 | 1,110 | |||||||||||||||
26
| As at March 31, |
||||||||||||||||||||||||
| 2004(5) |
2004 |
2003 |
2002 |
2001 |
2000 |
|||||||||||||||||||
| (restated)(6) | (restated)(1)(6) | |||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||
| US GAAP |
||||||||||||||||||||||||
| Fixed assets |
$ | 2,134 | £ | 1,166 | £ | 997 | £ | 8,259 | £ | 8,082 | £ | 8,517 | ||||||||||||
| Total assets |
4,672 | 2,553 | 2,175 | 10,250 | 9,766 | 11,823 | ||||||||||||||||||
| Provisions and long term liabilities |
(4,570 | ) | (2,497 | ) | (10,122 | ) | (10,367 | ) | (9,756 | ) | (11,024 | ) | ||||||||||||
| Equity shareholders’ (deficit)/funds |
(2,858 | ) | (1,562 | ) | (9,230 | ) | (1,145 | ) | (736 | ) | (545 | ) | ||||||||||||
| Year ended March 31, |
||||||||||||||||||||||||
| 2004(5) |
2004 |
2003 |
2002 |
2001 |
2000 |
|||||||||||||||||||
| (restated)(1) | ||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||
| Cash Flow Information: |
||||||||||||||||||||||||
| UK GAAP |
||||||||||||||||||||||||
| Operating profit/(loss) including exceptional items |
$ | 622 | £ | 340 | £ | (3,802 | ) | £ | (281 | ) | £ | 280 | £ | 412 | ||||||||||
| Exceptional items |
(518 | ) | (283 | ) | 3,906 | 512 | (54 | ) | 16 | |||||||||||||||
| Operating profit excluding exceptional items |
104 | 57 | 104 | 231 | 226 | 428 | ||||||||||||||||||
| Depreciation charges |
92 | 50 | 287 | 285 | 277 | 260 | ||||||||||||||||||
| Nuclear liabilities charged to operating costs |
238 | 130 | 105 | 156 | 132 | 141 | ||||||||||||||||||
| Nuclear liabilities discharged |
(108 | ) | (59 | ) | (115 | ) | (332 | ) | (319 | ) | (310 | ) | ||||||||||||
| Other provisions discharged |
(5 | ) | (3 | ) | (45 | ) | (43 | ) | (39 | ) | (34 | ) | ||||||||||||
| Regular contributions to UK decommissioning fund |
(35 | ) | (19 | ) | (18 | ) | (18 | ) | (17 | ) | (17 | ) | ||||||||||||
| Working capital: |
||||||||||||||||||||||||
| Decrease in stocks |
18 | 10 | 60 | 66 | 27 | 4 | ||||||||||||||||||
| Decrease/(increase) in debtors |
7 | 4 | (18 | ) | (117 | ) | 97 | (54 | ) | |||||||||||||||
| Increase/(decrease) in creditors |
(26 | ) | (14 | ) | (24 | ) | 152 | (107 | ) | 32 | ||||||||||||||
| Net cash inflow from operating activities |
285 | 156 | 336 | 380 | 277 | 450 | ||||||||||||||||||
| Payments to acquire tangible fixed assets |
(282 | ) | (225 | ) | (133 | ) | (137 | ) | ||||||||||||||||
| Net cash inflow from operating activities net of capital expenditure |
285 | 156 | 54 | 155 | 144 | 313 | ||||||||||||||||||
| (1) | Our consolidated financial statements were restated in 2002 to reflect the retroactive application of the UK Accounting Standards Board’s Financial Reporting Standard No. 19—Deferred Tax, FRS 19. FRS 19 came into effect with respect to all accounting periods ending after January 23, 2002 and requires that, when calculating the amount of taxation, full provisions be made for all timing differences for deferred taxes. |
| (2) | Dividends per share exclude any associated UK tax credit available to certain holders of ordinary shares. |
| (3) | Calculated based on a ratio of 75 ordinary shares for one ADS. On March 18, 2003, we increased the ratio of four ordinary shares for one ADS to the current ratio of 75 ordinary shares for one ADS. |
| (4) | The turnover for discontinued operations which related to Bruce Power (our interest in which was sold on February 14, 2003) are set out on a 100% holding basis. Our share in Bruce Power was 82.4% prior to the disposal. |
| (5) | Translated solely for the convenience of the reader, at $1.83 to £1.00, the closing exchange rate at March 31, 2004. |
| (6) | Our US GAAP financial statements for the years ended March 31, 2003 and March 31, 2002 were restated for certain items in connection with Statement of Financial Accounting Standard No. 133, Accounting for Derivatives and Hedging Activities. For further information, see “Item 5. Operating and Financial Review and Prospects—US Generally Accepted Accounting Principles—Restatement of Results.” |
| (7) | We have restated our 2004 consolidated financial statements in accordance with US GAAP to reflect the correct allocation of income tax expense/benefit between income from continuing operations and the cumulative effect of a change in accounting as of April 1, 2004. For further information, see “Item 5. Operating and Financial Review and Prospects—US Generally Accepted Accounting Principles—Restatement of Results.” |
| (8) | We have calculated the proforma net (loss)/income as if FAS 143 had been applied from April 1, 2001. We have not calculated the pro forma impact for any price periods. |
27
| Year ended March 31, |
||||||||||||
| 2004 |
2003 |
2002 |
||||||||||
| (in millions) | ||||||||||||
| Other Financial Information: |
||||||||||||
| Profit/(loss) after tax and exceptional items—UK GAAP |
£ | 234 | £ | (3,924 | ) | £ | (518 | ) | ||||
| Interest (including exceptional items) |
59 | 134 | 66 | |||||||||
| Revalorization (including exceptional items) |
117 | 364 | 187 | |||||||||
| Tax (including exceptional items) |
(2 | ) | (368 | ) | 25 | |||||||
| Depreciation charges |
50 | 273 | 280 | |||||||||
| Exceptional depreciation (credits)/charges due to impairment review |
(295 | ) | 3,738 | 300 | ||||||||
| EBITDA(1) |
163 | 217 | 340 | |||||||||
| (Gain)/loss on sale of business |
(47 | ) | 35 | (4 | ) | |||||||
| AmerGen profits |
(21 | ) | (43 | ) | (37 | ) | ||||||
| Bruce Power contributions |
— | (97 | ) | (52 | ) | |||||||
| Net exceptional charges other than depreciation, interest, tax and revalorization |
12 | 168 | 212 | |||||||||
| EBITDA—continuing activities(1) |
107 | 280 | 459 | |||||||||
| (1) | EBITDA represents earnings before interest, taxes, depreciation, amortization and related exceptional items. EBITDA and EBITDA from continuing activities are not GAAP measures in either the UK or in the United States and should not be considered in isolation or as a substitute for, or as an alternative to, net income, operating income, cash flow from operations, other cash flow data or any other performance measures prepared in accordance with UK GAAP or US GAAP. For additional information regarding the use of EBITDA, see “Presentation of Financial and Other Data—Non-GAAP Financial Measures—EBITDA.” |
Dividends
Our Board of Directors did not declare any dividends for the years ended March 31, 2003 and 2004. In prior fiscal years, we have paid interim and final dividends in January and July respectively. It is our intention to pay dividends when the requirements of the business permit, subject to the availability of distributable reserves and other factors. However, we do not anticipate declaring dividends in respect of the two financial years ending March 31, 2005 and 2006, as we believe that any available funds should be reinvested in our business to achieve a successful turnaround. (See “Item 4. Information about the Company—Restructuring” and “Item 13. Dividend Arrearages and Delinquencies”). The following table sets out the dividends paid on ordinary shares and ADSs in respect of the past five fiscal years, excluding any associated UK tax credit in respect of such dividends.
| Year ended March 31, | ||||||||||
| 2004 |
2003 |
2002 |
2001 |
2000 | ||||||
| (in pence) | ||||||||||
| Pence per ordinary share(1) |
||||||||||
| Interim |
— | — | 2.7 | 2.7 | 5.7 | |||||
| Final |
— | — | 5.3 | 5.3 | 2.3 | |||||
| Total |
— | — | 8.0 | 8.0 | 8.0 | |||||
| Year ended March 31, | ||||||||||
| 2004 |
2003 |
2002 |
2001 |
2000 | ||||||
| (in dollars) | ||||||||||
| US dollar per ADS:(1)(2)(3) |
||||||||||
| Interim |
— | — | 3.00 | 3.00 | 6.75 | |||||
| Final |
— | — | 5.63 | 5.63 | 2.81 | |||||
| Total |
— | — | 8.63 | 8.63 | 9.56 | |||||
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| (1) | Dividends per share and per ADS exclude any associated UK tax credit available to certain holders of ordinary shares and ADSs. Dividends paid by the Depositary in respect of ADSs are paid in US dollars based on a market rate of exchange that differs from the Noon Buying Rate. |
| (2) | Calculated on a ratio of 75 ordinary shares for one ADS. |
| (3) | Dividends have been translated from pounds sterling into US dollars, solely for the convenience of the reader at the Noon Buying Rate in effect at the date of payment. As our dividends are paid in pounds sterling, exchange rate fluctuations will affect the US dollar amounts received by holders of ADSs on conversion by the Depositary of such cash dividends. |
Exchange Rates
Dividends have been paid in pounds sterling. Exchange rate fluctuations have affected the US dollar amounts received by owners of the ADSs on conversion by the Depositary of such cash dividends. In addition, fluctuations in the exchange rate between pounds sterling and US dollars have affected the US equivalent of the quoted pounds sterling price of ordinary shares on the Daily Official List of the London Stock Exchange, and as a result, will likely affect the market price of ADSs in the United States.
The following table sets forth, for the periods and dates indicated, the noon buying rate in The City of New York as certified for customs purposes by the Federal Reserve Bank of New York, which we refer to as the Noon Buying Rate, for cable transfers in British pounds sterling, expressed in US dollars per British pound sterling. We provide these rates for your convenience only, and they are not the rates of exchange we used to prepare our consolidated financial statements included elsewhere in this annual report. We are not representing that British pounds sterling amounts have been or could be converted into US dollars at any of the exchange rates indicated.
| Year ended December 31, |
High |
Low |
Average(1) |
Period | ||||||||
| 1999 |
$ | 1.68 | $ | 1.55 | $ | 1.62 | $ | 1.60 | ||||
| 2000 |
$ | 1.65 | $ | 1.40 | $ | 1.50 | $ | 1.50 | ||||
| 2001 |
$ | 1.50 | $ | 1.37 | $ | 1.44 | $ | 1.45 | ||||
| 2002 |
$ | 1.61 | $ | 1.41 | $ | 1.45 | $ | 1.61 | ||||
| 2003 |
$ | 1.68 | $ | 1.55 | $ | 1.61 | $ | 1.59 | ||||
| 2004 (through September 24, 2004) |
$ | 1.90 | $ | 1.75 | — | — | ||||||
| (1) | The average of the Noon Buying Rates on the last business day of each month during the relevant period. |
The following table sets forth, for the six full months prior to the date of this annual report, the high and low Noon Buying Rates.
| Month 2004 |
High |
Low | ||
| March |
1.8680 | 1.7943 | ||
| April |
1.8564 | 1.7674 | ||
| May |
1.8369 | 1.7544 | ||
| June |
1.8386 | 1.8090 | ||
| July |
1.8708 | 1.8160 | ||
| August |
1.8459 | 1.7921 | ||
| September (through September 24, 2004) |
1.8031 | 1.7733 |
Except as we specify otherwise, we converted exchange rate translations in this annual report at the rates in effect on March 31, 2004, which correspond to the rates we used to prepare our consolidated financial statements.
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ITEM 4. INFORMATION ON THE COMPANY
Overview
Our principal activities are the generation, sale and trading of electricity. We are the UK’s largest generator of electricity, producing over one fifth of the UK’s electricity and employing approximately 5,150 staff. We own and operate eight nuclear power stations and one coal-fired power station in the UK. Of our nuclear power stations, seven are AGR power stations (Dungeness B, Hartlepool, Heysham 1, Heysham 2, Hunterston B, Hinkley Point and Torness) and the eighth (Sizewell B) is our sole PWR power station. Our nuclear power stations have a combined capacity of approximately 9,600 MW. Eggborough, our coal-fired power station in Yorkshire has capacity of 1,970 MW. During the year ended March 31, 2004, our power stations produced total output of 72.6 TWh, which was comprised of output of 65.0 TWh from our nuclear power stations and 7.6 TWh from Eggborough, our coal-fired power station. British Energy Power and Energy Trading Limited, one of our subsidiaries arranges the balancing of our electricity generation and supply.
During the periods under review, we made two significant divestitures: in February 2003 we disposed of our majority interest in Bruce Power, which operates the Bruce nuclear power station in Canada and in December 2003 we sold our 50% interest in AmerGen, a joint venture which operates three nuclear power stations in the United States.
We generated turnover of £1,516 million during the year ended March 31, 2004 resulting in operating profits of £57 million before exceptional operating credits of £283 million. During the year ended March 31, 2003, we generated turnover of £1,903 million, of which £1,528 million was from continuing activities, resulting in operating profits from continuing activities of £7 million before exceptional operating items of £3,906 million. Operating profits from continuing activities after exceptional operating credits were £340 million during the year ended March 31, 2004 as compared with an operating loss from continuing activities after exceptional operating costs of £3,802 million during the year ended March 31, 2003.
We use a variety of routes to market in the UK, including sales to the wholesale market, direct sales to large industrial and commercial customers and sales via long-term contracts. For a description of our sales activities see the paragraph below headed “Electricity Sales”. Our business is subject to a high degree of regulation in a number of areas, including nuclear and industrial safety, electricity generation, trading and supply, and the environment. For a description of our regulatory environment, see the paragraph below headed “Regulation”.
Restructuring
Work to implement our financial restructuring (the “Restructuring”) continued throughout the year and we achieved a number of significant milestones. In particular, on October 1, 2003 we announced that we had reached formal agreement on the terms of the Restructuring with the Government and certain of our creditors. During the financial year ended March 31, 2004 we also completed the sale of our 50% interest in AmerGen. The key terms of the Restructuring are set out in various agreements described below:
The Restructuring Agreements
| (a) | the Creditor Restructuring Agreement dated as of September 30, 2003 (as amended by a side letter entered into on October 31, 2003) among British Energy, certain other British Energy Group companies, the bank syndicate that provided financing for Eggborough (the “Eggborough Banks”), The Royal Bank of Scotland plc (“RBS”), Teesside Power Limited (“TPL”), Total Gas & Power Limited (“Total”) and Enron Capital & Trade Europe Finance LLC (“Enron”) |
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| (TPL, Total and Enron (which have subsequently transferred their respective interests to Deutsche Bank) collectively referred to as the “Significant Creditors”), the members of the ad hoc committee of British Energy’s bondholders (“Bondholders”) and British Nuclear Fuels plc (“BNFL”) (the “Creditor Restructuring Agreement”). By October 31, 2003, the Creditor Restructuring Agreement had been acceded to by all the Eggborough Banks and by Bondholders representing in aggregate with RBS, 88.8% of the combined amount owing to Bondholders; and |
| (b) | the Government Restructuring Agreement, dated October 1, 2003 among British Energy and certain of our subsidiaries, the Secretary of State, the Nuclear Generation Decommissioning Fund Limited (the “Decommissioning Fund”) and the trustees of the Nuclear Trust (the “Government Restructuring Agreement”. |
The principal elements of the Restructuring are as follows:
| • | the Bondholders, RBS, the Significant Creditors and the Eggborough Banks have agreed (subject to certain conditions) to compromise their existing unsecured claims in exchange for £275 million of new bonds (the “New Bonds”) to be issued by the restructured British Energy Group and at least 97.5% of the new ordinary shares (the “New Shares”) of the restructured British Energy Group. RBS and Bondholders will compromise their claims under a Court-approved scheme of arrangement (the “Creditors’ Scheme”) which must also be approved by a majority in number of those creditors representing three-fourths in value of their claims against us. The other Creditors have agreed to compromise their claims under the provisions of the Creditor Restructuring Agreement itself; |
| • | the Decommissioning Fund will be enlarged and renamed the Nuclear Liabilities Fund (the “NLF”). The NLF will fund certain of our uncontracted nuclear liabilities and costs of decommissioning our nuclear power stations and the Government will fund these decommissioning costs and uncontracted nuclear liabilities to the extent they exceed the assets of the NLF, as well as contracted liabilities for historic spent fuel, subject to certain exceptions; |
| • | in consideration for the assumption of the liability referred to above, the restructured British Energy Group will issue £275 million in New Bonds to the NLF. In addition, the restructured British Energy Group will make the following payments to the NLF: (i) fixed decommissioning contributions of £20 million per annum (indexed to the Retail Price Index, and subject to reduction as stations are closed); (ii) £150,000 (indexed to the Retail Price Index) for every tonne of fuel loaded into the Sizewell B reactor after completion of the Restructuring; and (iii) an annual contribution of up to 65% of our adjusted cash flow (after payment of debt service requirements) (the “NLF Cash Sweep”). The NLF Cash Sweep is subject to adjustment but will not exceed 65% of our adjusted cash flow; |
| • | the NLF may convert the NLF Cash Sweep into convertible shares of the restructured British Energy equal to the same percentage of the thereby enlarged issued share capital. The terms of the convertible ordinary shares into which such entitlement will convert will limit the general voting rights attaching to such shares to a maximum 29.9%; |
| • | the Eggborough Banks as lenders with security over the Eggborough coal-fired station and the shares of Eggborough Power Limited (“EPL”), have agreed (subject to certain conditions) to exchange their secured claims for a right to receive payments under an Amended and Restated Credit Agreement (the “Amended Credit Agreement”) equivalent to £150 million of New Bonds (the “CTA Bonds”). In addition, the Eggborough Banks will have an option to acquire the Eggborough power station in 2010 upon payment of a £104 million break fee and the extinguishment of the then outstanding CTA Bonds. This option may be accelerated in the event of a default under the Amended Credit Agreement; |
| • | the BNFL contracts for front-end and back-end related fuel services to our AGR Stations have been amended; and |
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| • | the standstill arrangements entered into by us and certain of our creditors on February 14, 2003 have been extended and will continue while the Restructuring is being completed (subject to the occurrence of certain termination events). |
The Government Facility
The Government Facility provided to us by the Secretary of State was granted on September 9, 2002 for up to £410 million to provide working capital for our immediate requirements and to allow us to stabilize our trading position in the UK and North America. It was subsequently extended and increased to £650 million before being reduced to a £200 million facility in March 2003. As at September 28, 2004 there was no outstanding balance on the Government Facility. Under its terms the Government Facility matures on the earlier of (i) January 31, 2005, (ii) the date on which the Restructuring becomes effective and (iii) any date notified by the Secretary of State to us on which repayment of amounts outstanding under the Government Facility are required as a result of a European Commission (the “Commission”) decision or an obligation under EU law. Following the receipt by the Secretary of State of notification from the Commission that as far as Restructuring involves the grant of State Aid by the Government, such aid is compatible with the Common Market, no further drawings can be made under the Government Facility. On September 29, 2004 the final maturity date of the Government Facility was amended from September 30, 2004 to January 31, 2005.
Receivables Facility
On August 25, 2004 British Energy Generation Limited ("BEG") entered into a three year trade receivables financing facility ("Receivables Facility") with a financial institution under which, on utilization, BEG will sell to the financial institution on a full recourse basis receivables arising from its direct supply business. The amount of funding available to BEG under the Receivables Facility is limited to £60 million and is dependent on the amount of eligible receivables available at utilization, which, in turn, is subject, inter alia, to seasonal changes in the demand and price for electricity and to limits on customer concentrations within the receivables portfolio. On completion of the Proposed Restructuring the Receivables Facility will be guaranteed by the other principal companies within the Group (excluding EPL). The Receivables Facility is subject to customary representations, warranties and covenants appropriate to the financial situation of BEG and the prospective guarantors. Events of default include, inter alia, non-payment, cross-default, occurrence of insolvency related events, revocation of the electricity supply license and the exercise by the Secretary of State of her right not to proceed with the Proposed Restructuring if, in her opinion, the Group will not be viable without access to additional financing. As at September 28, 2004, the Receivables Facility remains unutilized.
Impact of the Restructuring on Existing Shareholders
As part of the Restructuring, we propose to cancel our existing ordinary shares of 44 28/43 pence each and A shares of 60 pence each (the “Shares”) under a scheme of arrangement with our shareholders (the “Members’ Scheme”), and issue to shareholders: (i) new shares (the “New Shares”) in British Energy Group plc equal to 2.5% of the issued share capital of a newly incorporated ultimate parent company of the British Energy Group (“British Energy Group plc”) immediately following implementation of the Restructuring, and (ii) warrants to subscribe for a maximum of 5% of the thereby diluted ordinary issued share capital of British Energy Group plc (excluding, amongst others, the impact of conversion of the NLF Cash Sweep described above) immediately following implementation of the Restructuring (“Warrants”).
If the shareholders do not approve the Members’ Scheme or for any other reason the Members’ Scheme is not implemented, but shareholders instead vote in favor of the Company selling all its business and assets to British Energy Holdings plc, a directly wholly-owned subsidiary of British Energy Group plc (the “Disposal”), they will receive only the Warrants. The Creditor Restructuring Agreement requires that, absent shareholder approval, the Restructuring will be completed by delisting our shares from the Official List thus avoiding the requirement for shareholder approval under the existing Listing Rules. The UKLA has published a consultation paper proposing that a rule change should be made which would require shareholder consent for delisting. Our directors are confident that
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the introduction of any new rule would only apply to companies which have not announced or given notice of firm and agreed delisting proposals for the first time prior to the rules becoming effective. Our directors further consider that such notice, on the basis of the several statements already made as to the intention to de-list, has already been given by us, or if necessary, could be given in good time. If the shareholders do not vote in favor of either proposal, they will not receive any New Shares or Warrants.
The subscription price for the warrants which shareholders would receive in the circumstances detailed above is £28.95 million in aggregate, equivalent to an equity market capitalization of the restructured British Energy of £550 million following implementation of the Restructuring.
Bruce Power
We completed the sale of our 82.4% interest in Bruce Power and our 50% interest in Huron Wind on February 14, 2003.
On April 28, 2003, we announced that we had received C$20 million which had been retained on completion of the sale of Bruce Power for the possible price adjustment relating to pensions following confirmation that no such adjustment was required.
In addition to the consideration received at the time of the disposal of its interest in Bruce Power, we were entitled to receive up to C$100 million, contingent on the restart of two of the Bruce A Units (Units 3 and 4). On March 22, 2004 we received the sum of C$20 million in respect of the restart of Unit 4 and on May 25, 2004 we received a further C$10 million in respect of the Unit 3 restart. Discussions are ongoing with the Ontario Provincial Government regarding the release of further sums (if any). The total amount that will be released in respect of the restarts will be significantly less than C$100 million.
On February 12, 2004 we received a notice of warranty claims from the consortium which purchased the Group’s interest in Bruce Power alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce power station. 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. Further details of these claims can be found in “Item 5. Operating and Financial Review and Prospects—Contingent Liabilities”.
New Contracts with BNFL
On May 16, 2003, we announced that we had exchanged the suite of contracts covering front end and back end fuel services, required to give effect to non-binding heads of terms which it entered into with BNFL on November 28, 2002. The revised front end and back end fuel contracts that have been agreed with BNFL provide an important partial hedge against market price movement on approximately 50% of our total nuclear output.
The front end contracts became effective on April 1, 2003 but may be terminated if the Restructuring is not completed. The back end contracts are conditional on completion of the restructuring but, under the terms of the standstill agreement, pending formal implementation of the revised back end contracts, payment from us to BNFL will be made as if the revised back end contracts had become effective on April 1, 2003.
At the same time, we announced that new contracts had also been entered into for the sale of all of our natural and enriched uranium stocks to BNFL and their ongoing supply and procurement by BNFL. BNFL purchased the majority of our existing uranics stocks for some £50m and now provides us with a full uranics supply service (including an obligation to use all reasonable endeavors to achieve
33
the lowest possible price for uranium to be supplied to us). The remaining stocks were subsequently purchased by BNFL later in the year. Under the new lifetime arrangements (which are terminable however after an initial period of seven years) BNFL will supply the uranics required for our AGR stations in England, and will also supply enriched uranium for PWR fuel fabrication. BNFL will continue to supply uranics for our AGR stations in England, and will also supply enriched uranium for PWR fuel fabrication. BNFL will continue to supply uranics for our AGR stations in Scotland under existing arrangements until 2006, when similar arrangements to those applicable in England will take effect.
In addition, we have entered into an agreement whereby we will provide computer implementation support services to the BNFL for a fee of £10 million per annum plus certain incremental costs. This project is expected to be completed by March 31, 2005.
BNFL deferrals
Certain of our contractual arrangements with BNFL provide for BNFL to use its reasonable endeavors to meet our requirements for deferring payments or for us to use our reasonable endeavors to meet BNFL’s requirements for receiving advance payments under those agreements respectively, so long as neither party is adversely affected.
In exercise of this provision, we agreed with BNFL in June 2004 that the payment of certain charges due and invoiced by BNFL in July, August and September under our existing and post 2006 fuel supply agreements covering fuel supplied to BEG, up to a maximum of £20 million, may be deferred in each of the financial years of 2004/05, 2005/06 and 2006/07 providing we are in compliance with our other payment obligations under the agreements. These deferrals will allow us to better align the payments due in any one of these three years for fuel more closely with the receipts from the sales of our electricity in the same year.
We have deferred the agreed sum of £20 million in this financial year under this agreement and have stated to BNFL that it is our intention to pay the amounts in respect of the July invoiced payments on February 1, 2005 and to pay the amounts in respect of the August and September invoiced payments on March 1, 2005. The interest payable on such deferred amounts for the period of the deferral is at the contractual late payment interest rate of LIBOR plus 2%. Interest is calculated every three months, upon which BEG has an option to pay this interest or add it to the deferred payment amount.
Disposal of Interest in AmerGen
In September 2002, British Energy and Exelon, equal joint venture partners in AmerGen announced their intention jointly to sell their investment. The disposal process did not attract suitable offers and on March 7, 2003 we announced that we had decided, jointly with Exelon, to terminate the sale process as both parties together concluded that none of the proposals received adequately reflected AmerGen’s intrinsic value. At that time we stated that we were continuing to take steps to realize our 50% interest in AmerGen.
On September 11, 2003, we announced that we and certain of our subsidiaries had entered into a conditional agreement to dispose of our interest in AmerGen to the FPL Group Inc. (“FPL”) for approximately US$277 million, subject to various potential adjustments. FPL had been selected by us to purchase our interest following a competitive bidding process.
This announcement highlighted the fact that Exelon had a right of first refusal to purchase our interest on the same terms and conditions and at the same price as those offered by FPL. Subsequently, on October 3, 2003, Exelon exercised its right of first refusal. The terms and conditions of the disposal were formally agreed on October 10, 2003.
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As a result of Exelon’s exercise of its right of first refusal, the original agreement with FPL terminated on October 13, 2003 following the service of formal notice to that effect by us. As a consequence, a break fee of US$8.3 million became payable by us to FPL.
On December 23, 2003 we announced the completion of the disposal of our interest in AmerGen and received initial consideration of approximately US$277 million prior to adjustments relating to working capital levels, unspent nuclear fuel, inventory, capital expenditures and low-level waste disposal costs which were to be determined as at the time of closing. Finalization of these adjustments is still outstanding and is subject to dispute. For further information, see “Item 3. Risk Factors—We are involved in several disputes that if resolved or determined against our interests could adversely affect our profitability and our cash flow.”
Approximately £94 million of the consideration was used to pay down outstanding amounts under the Government Facility and the balance was retained for corporate purposes.
Further steps
We are continuing to work hard with our advisers to complete the Restructuring. This requires, among others:
| • | preparation and publication of Creditors’ Scheme and Members’ Scheme documentation and a prospectus in relation to the New Shares, New Bonds and Warrants to be issued under the Restructuring; |
| • | settling certain documents with creditors; |
| • | the holding of creditors’ and members’ meetings; |
| • | approval of the relevant UK Court in relation to the Creditors’ Scheme; and |
| • | implementation and listing of the New Shares, Warrants and New Bonds. |
Our ordinary shares are currently listed on the New York Stock Exchange (“NYSE”) in the form of American Depositary Receipts (“ADRs”) and we have agreed to make efforts to obtain a new listing of the New Shares upon completion of the Restructuring in the form of ADRs on the NYSE. We have also agreed to report our quarterly and annual financial results in compliance with US Generally Accepted Accounting Principles, generally to comply with the requirements of the Sarbanes Oxley Act, and to file reports as if we were a US domestic reporting company. The NYSE suspended trading in our ADRs prior to the opening of trading on September 28, 2004. At that time, the NYSE also instituted delisting proceedings. For further information concerning the background to the suspension of our ADRs see “Recent Developments” below.
Unless otherwise agreed by the relevant parties, the Creditor Restructuring Agreement and the Government Restructuring Agreement will automatically terminate (and consequently the Restructuring will not be implemented) if the Creditors’ Scheme has not become effective by 12:00 p.m. on the earlier of: (i) 120 days after the last of the key conditions to the Restructuring have been satisfied and (ii) January 31, 2005 (the “Restructuring Long Stop Date”).
The Restructuring remains subject to a large number of important conditions, including:
| • | the Secretary of State’s entitlement not to proceed with the Restructuring if, in her opinion, we will not be viable in all reasonably foreseeable conditions without access to additional financing beyond that which is committed and will continue to be available when required; |
| • | the restructured British Energy Group having sufficient working capital for its present requirements from the listing of the New Shares and New Bonds; |
| • | there being no material adverse change on our (or on EPL’s) current or future business or operations, financial or trading position, profits or prospects or which is likely to have a material |
35
| adverse effect on the value of the New Bonds, the New Shares, the CTA Bonds or the new Eggborough arrangements; |
| • | the Creditors’ Scheme becoming effective; |
| • | continuation of the standstill arrangements; and |
| • | agreement on presently unsettled documents with creditors, Scottish court approval and listing of the New Shares and New Bonds referred to above and the delisting of the Company’s ordinary shares and A shares. |
There are also a large number of significant uncertainties which may affect the Group’s cash flow position, performance or outlook.
If for any reason we are unable to implement the Restructuring, we may be unable to meet our financial obligations as they fall due, in which case we may have to take appropriate insolvency proceedings. If we were to commence insolvency proceedings, distributions, if any, to unsecured creditors may represent only a small fraction of their unsecured liabilities, and it is highly unlikely that there would be any return to shareholders. Even if the Restructuring is completed, the return, if any, for shareholders will represent a very significant dilution of their existing interests.
RECENT DEVELOPMENTS
Requisitioned Extraordinary General Meeting and Delisting
On September 3, 2004 two groups of shareholders, together holding 10.22% of our ordinary shares, requisitioned the Requisitioned EGM. Those groups of shareholders were Polygon and Brandes and their respective associates. We are, as a result, obliged under the Companies Act to call the Requisitioned EGM. One of the resolutions proposed by Polygon and Brandes would have the effect, if passed, of requiring the Company to seek shareholder approval prior to applying for the cancellation of its listings in London and New York. If we were required, under the terms of the Creditor Restructuring Agreement, to take steps to cancel the London listings of our shares, but could not do so as a result of a failure to achieve such shareholder approval, the Company believes, having taken legal advice, that it would be likely to be in breach of the Creditor Restructuring Agreement.
We announced on September 23, 2004 that the Requisitioned EGM will be held on October 22, 2004 and that as a result of this attempt to frustrate the Restructuring agreed by the Company in October 2003, we would be applying to the UKLA to cancel the listings of our ordinary and A Shares As a consequence, and as announced on September 23, 2004, the NYSE suspended trading in our ADRs prior to the opening of trading on September 28, 2004. At that time, the NYSE also instituted delisting proceedings. The suspension and possible delisting from the NYSE does not affect our status as a SEC registrant under the US Securities Exchange Act 1934, or our periodic reporting obligations.
On September 24, 2004 the Company announced (i) the unanimous recommendation of the Board to shareholders to vote against the resolutions proposed by Polygon and Brandes at the Requisitioned EGM, (ii) that it intended to seek an extension to the Creditor Restructuring Agreement long stop date of January 31, 2005 for the Restructuring and (iii) that, in accordance with the Creditor Restructuring Agreement, it would execute a business transfer agreement whereby the Company’s assets would, conditional on the Restructuring becoming effective, be transferred to a new intermediate holding company of the restructured British Energy group.
On September 30, 2004 Polygon announced that it would withdraw its support for the Requisitioned EGM. Polygon stated that, having considered the Company’s recent circulars, they now believe there is no commercial logic for it supporting the resolutions to be considered at the Requisitioned EGM and consequently have confirmed that they will vote against the resolutions and not further oppose the Restructuring. The Requisitioned EGM will take place on October 22, 2004 as described in the notice mailed to our shareholders. Our Board continues to reiterate its unanimous recommendation to all shareholders to vote against the resolutions proposed for the Requisitioned EGM.
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State Aid Approval
On September 22, 2004 we announced the receipt by the Secretary of State of notification from the Commission that as far as Restructuring involves the grant of State Aid by the Government, such aid is compatible with the Common Market. The Commission’s decision is subject to the following conditions:
| • | the Company’s nuclear generation business will be ring-fenced from its fossil fuel, supply and trading businesses to ensure the aid to the nuclear business is not used to cross subsidize any other of the company’s businesses. This measure will last indefinitely; |
| • | there is to be no nuclear or fossil-fuelled capacity expansion (above our current capacity) by the Company in the European Economic Area for six years, and no hydro-electric capacity expansion in the UK for the same period; and |
| • | a restriction on the Company selling to its industrial and commercial customers at prices below the prevailing wholesale market price for six years unless there are exceptional market circumstances as determined by an independent expert. |
The European Commission has set down an additional requirement that a threshold of £1.629 billion be set for the aid, above which the Commission can request enhanced reporting to satisfy themselves that the aid is being kept to a minimum and is only being used for authorized purposes.
Indicative Ratings for New Bonds
We have been in discussions with Fitch Ratings, Moody’s Investor Services and Standard & Poor’s Rating Services (“the Rating Agencies”) with regard to obtaining credit ratings for the £550 million of new bonds that are to be issued to certain of our creditors and to the NLF upon completion of the Restructuring pursuant to the terms announced on October 1, 2003.
Preliminary discussions were held with the Rating Agencies last year in advance of agreement on the terms of the Restructuring and it was stated in our announcement made on October 1, 2003 that one rating agency had provided an indicative rating for the new bonds of investment grade and two rating agencies had provided indicative ratings at non-investment grade.
On September 23, 2004, we announced that the Rating Agencies had updated their analysis and that all three agencies had now provided indicative non-investment grade ratings for the Company.
These ratings remain prospective and indicative and are subject to the Restructuring being completed in its proposed form in accordance with the assumptions that have been provided to the Rating Agencies for the purpose of the indicative prospective rating assessment. These ratings will only be finalized when the new bonds are issued upon completion of the Restructuring.
These ratings do not apply to the additional £150 million of bond-equivalent payments that will be issued to certain lenders to EPL through the Amended Credit Agreement, which will not be rated.
Classification of British Energy in the Public Sector
On September 24, 2004 the United Kingdom Office for National Statistics (‘‘ONS’’) announced that, with effect from September 9, 2002, the date on which the Government Facility was granted, the Company will be classified in the public sector. This classification was stated by the ONS to reflect the degree of control that can be exercised by the Government over us, first through the Credit Facility, and then as a result of our Restructuring. Prior to this announcement the ONS classified British Energy as part of the private sector.
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The ONS’s decision was made for UK National Accounts purposes and was dependent upon a judgment about the degree of control exercised by Government. The ONS has acknowledged that, following completion of the Restructuring, no one factor constitutes the degree of control necessary for a classification in the public sector. The decision is based on the view that, taken together, a number of factors represent a high degree of Government control. For further information on the background to and terms of the Restructuring, see “Item 4. Information on the Company—Restructuring’’ and note 1 to our financial statements beginning on page F-1.
The ONS have noted that as the Restructuring process has not been finalized, some of the details of their decision may change, and as a result this classification (as it will apply to the Company following the completion of the Restructuring) is provisional.
The UK National Accounts are produced by the ONS and provide an internationally compatible accounting framework that describes the activities in a national economy, including the transactions that take place between sectors of that economy.
We are currently assessing the implications of this decision for our business. In particular, we are giving thought to those relationships that will exist post-Restructuring that may require to be disclosed as ‘‘Related Parties’’ in our financial statements for the year ending March 31, 2005. We have not, as yet, finalized our conclusions on this. For further information see ‘‘Item 5. Operating and Financial Review and Prospects—Post Balance Sheet Events’’.
OUR BUSINESS
Our nuclear power stations
We own and operate two types of nuclear reactor namely, the advanced gas cooled reactor (“AGR”) and the pressurized water reactor (“PWR”). They differ in many respects including, amongst other things, in the types of fuels used and in the design of the reactor. Each of our seven AGR nuclear power stations, Dungeness B, Hartlepool, Heysham 1, Heysham 2, Hinkley Point B, Hunterston B and Torness, are powered by two AGRs. Sizewell B is powered by a single PWR. Whereas the AGR design is unique to the UK, the PWR design is the most common reactor type in the world.
As well as being unique to the UK, our AGR stations were constructed to varying specifications by different engineering consortia which we consider makes demonstrating safety cases for different reactors less straightforward and can mean that implementation of remedial action to make good a defect at one station cannot be replicated with ease at other differently designed stations. For further information on safety cases see the paragraph below headed “Station lifetimes”.
An AGR has a graphite moderator (which helps to control the reaction) which is comprised of large graphite bricks with channels for the fuel rods, control rods and pressurized carbon dioxide coolant. The reactor is encased in a steel-lined pre-stressed concrete pressure vessel several meters thick which also acts as a biological shield. The boilers in which the water is heated are situated inside the pressure vessel. The AGR uses enriched uranium for its fuel.
A PWR is contained inside a steel pressure vessel filled with pressurized water which acts as the coolant and moderator. Pressurized water is pumped around the reactor and through the boilers. The pressure vessel, boilers and connecting pipework are contained within a steel-lined pre-stressed concrete containment building, which acts as one of the multiple designed-in barriers to the release of radioactivity in the event of an accident. The fuel used is enriched uranium dioxide and is contained in zirconium alloy tubes.
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Operating regime
Capacity and output
The electrical output of a station depends on a combination of its overall generating capacity, the output level at which the station actually operates and its availability. The capacity of each station is reviewed and amended from time to time to reflect the long-term capability of the plant. The table below sets out the current capacity values for each of our nuclear stations, the output of each of our nuclear stations for each of the last five fiscal years and the percentage of the fleet’s load capacity that was achieved in each year (Annual Load Factor).
| Station |
Current Capacity (MW)(1) |
Output(3) (TWh)/Year ended March 31, |
|||||||||||||||
| 2004 |
2003 |
2002 |
2001 |
2000 |
|||||||||||||
| Dungeness B |
1,110 | 6.66 | 5.18 | 5.25 | 3.66 | 2.23 | |||||||||||
| Hartlepool |
1,210 | 8.28 | 9.34 | 8.83 | 9.09 | 9.32 | |||||||||||
| Heysham 1 |
1,150 | 6.28 | 7.85 | 8.11 | 8.92 | 8.45 | |||||||||||
| Heysham 2 |
1,250 | 9.81 | 9.30 | 9.03 | 10.05 | 6.41 | |||||||||||
| Hinkley Point B |
1,220 | 8.11 | 8.26 | 8.98 | 8.23 | 7.68 | |||||||||||
| Hunterston B |
1,190 | 8.77 | 8.93 | 9.85 | 6.43 | 8.88 | |||||||||||
| Sizewell B |
1,188 | 8.90 | 9.20 | 9.22 | 8.43 | 9.06 | |||||||||||
| Torness |
1,250 | 8.15 | 5.70 | 8.30 | 7.71 | 10.17 | |||||||||||
| Total |
9,568 | 64.96 | 63.76 | 67.57 | 62.53 | 62.20 | |||||||||||
| Annual Load Factor(2) |
77 | % | 76 | % | 81 | % | 75 | % | 74 | % | |||||||
| (1) | Capacities are stated net of all power consumed for the stations’ own use, including power imported from the National Grid. |
| (2) | Annual load factors are obtained by dividing the actual output by the output that would have been achieved had each station operated at its stated full load capacity in that year for the entire period. |
| (3) | Output in each year reflects any statutory, refueling and unplanned outages as discussed below. |
The output levels which stations can achieve relative to their stated capacities are affected by a number of factors, including plant operating conditions and operating strategies, which can result in a station being operated at below its maximum capacity level. Station availability is principally affected by the number and duration of planned and unplanned outages and load reductions, such as those required to carry out refueling (as described below). Taking into consideration the impact of statutory outages and refueling (but excluding planned repair outages), the maximum annual load factor which could be achieved across our portfolio of stations is approximately 90%. This is less than the annual load factor which could be achieved at a PWR power station.
Statutory outages
Periodically, our reactors need to be shut down to allow for regulatory inspection and routine maintenance. We refer to these as statutory outages. The interval between the statutory outages is determined by the plant safety case which includes the requirements for inspection, maintenance and testing, and the arrangements in place to control this interval are approved by the Nuclear Installations Inspectorate (“NII”). Currently, each of our AGRs must initiate a statutory outage once every three years and our PWR once every 18 months.
After a statutory outage, the NII’s consent is required for a reactor’s return to service and this consent is dependent upon us demonstrating an adequate safety case in respect of that reactor. For more information on safety cases see the paragraph below headed “Station lifetimes”. We seek to reduce the impact of statutory outages on revenue by timing such outages to occur during periods of lower demand for electricity when prices are lower (generally between March and October). We also seek to reduce the duration of any statutory outages by improving the efficiency with which we conduct the required program of work. AGR statutory outages completed during the year ended March 31, 2004 had an average duration of 53 days, compared to 56 days in 2003 and 46 days in 2002. Statutory outages are limited to one reactor within each AGR station at any one time.
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Refueling operations
Reactor output is also affected by planned outages including load reductions required to carry out refueling. We conduct on-load refueling (i.e., refueling while the reactor’s power is reduced to between 20% and 40% of full power) at Hinkley Point B, Heysham 2, Hunterston B and Torness to help reduce the amount of output lost due to refueling. We refuel these reactors one at a time at each station. On-load refueling operations typically take a few days to complete and are repeated approximately every six weeks for each reactor.
At Heysham 1, Hartlepool and Dungeness B we refuel the reactors whilst they are off-load, which typically takes approximately one week. We also refuel these reactors one at a time at each station. This process typically occurs every five months for each reactor.
Improvements in fuel utilization have reduced the amount of refueling required at each reactor. In particular, we have developed more efficient fuel management techniques, such as increasing fuel enrichment and radial shuffling (the movement of partially burnt fuel assemblies from the edge of the reactor to the center so that more of the energy can be extracted from the fuel over a longer period) to increase the output extracted per tonne of fuel loaded. Radial shuffling is carried out routinely at Hinkley Point B and Hunterston B and radial shuffling safety cases have been developed for Hartlepool and Heysham 1, where the process is expected to start in 2004, and approximately one year later at Dungeness B. Radial shuffling is not carried out at Torness or Heysham 2 because we believe that to do so would disproportionately increase the time taken to complete refueling and therefore would be uneconomical.
We are presently in discussions with BNFL regarding possible further increases in fuel enrichment and changes to the fuel design that will further improve its utilization and also make it less susceptible to failure. For further details, see Item 3. Risk Factors.
PWRs are not designed to refuel on-load and must be shut down for refueling. Accordingly, we seek to time statutory outages at Sizewell B to coincide with refueling outages. Although Sizewell B has only one reactor, that reactor has a performance capacity comparable to the combined reactor capacity of both reactors at an AGR station and the impact of an outage is for the same period therefore substantially greater than that associated with a single AGR reactor. Sizewell B currently operates for a period of up to 18 months between statutory/refueling outages, the average length of which is 47 days. During refueling, approximately one third of the fuel is replaced.
Unplanned losses
Our level of unplanned losses in recent years has significantly affected the results of our operations. To date these unplanned losses have been caused by a variety of factors, amongst the most significant of which are problems with our refueling equipment and processes, turbine-generators, tendons, boilers, gas circulators (which are used to pump carbon dioxide coolant gas around the reactor core) and pipe work (which is used to carry sea water for cooling). We believe that these losses are indicative of a deterioration in the materiel condition of our plant over time caused by: (i) inadequate investment when compared with international benchmarks for spending at nuclear power stations (of the order of approximately £45m per annum across the fleet over five years); (ii) by a failure to perform required maintenance on a timely basis; and (iii) human errors in the operation and maintenance of plant including conducting our operations and maintenance functions on a station by station basis rather than a fleet wide basis. This conclusion is consistent with the findings of the World Association of Nuclear Operators (WANO) corporate review carried out in 2001 (details of which are set out in the paragraph below headed “Key findings from the WANO 2001 corporate review”). The table below sets forth the total unplanned losses (expressed in terawatt hours) for the periods under review.
| Total unplanned losses (TWh)/Year to March 31, | ||||||||
| 2004 |
2003 |
2002 |
2001 |
2000 | ||||
| 10.7TWh | 10.6TWh | 9.1TWh | 12.8TWh | 12.4TWh | ||||
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Performance Improvement Program
To address the issues described above and with a view to reducing the level of unplanned outages, in August 2003 we brought together a team within British Energy and engaged a consortium of experienced external consultants, led by Ove Arup and Partners International Limited, in conjunction with significant support from WANO, to design and implement a far-reaching Performance Improvement Program (PIP). Our PIP implementation team and power station management teams, supplemented with additional experienced nuclear professionals seconded from WANO, have targeted six focus areas namely: (i) foundation; (ii) training; (iii) human performance; (iv) equipment reliability; (v) management of work; and (vi) operational focus:
| (i) | Foundation provides the infrastructure to mobilize many of the changes planned across the fundamentals of human performance, equipment reliability, management of work and operational focus. Its focus is on creating a defined, aligned, effective and properly resourced organization with improved organizational effectiveness to help achieve excellence in nuclear plant operation. In addition, it aims systematically to develop management and leadership skills to meet station and corporate needs. We expect this aspect of the program will lead to our employing more engineering and technician staff to work at our nuclear power stations; |
| (ii) | Training supports foundation and seeks to develop and maintain a knowledgeable, skilled nuclear staff by creating the appropriate training to enable staff effectively to do their job and ensure there is continual training to refresh and enhance skills. |
| (iii) | Human performance involves promoting cultural change with a focus on accountability and striving for excellence, improving the skill sets of our operational support team and setting clear performance targets. We have sought to capture the essence of this objective by defining our corporate ethos (communicated to the vast majority of our employees) as “Safe, profitable and proud”. Examples of progress to date include a number of operationally experienced people being appointed to senior positions in our central support functions, improvements in our technical training function and the re-organization of operational staff that we have undertaken at station level; |
| (iv) | Equipment reliability will involve significant investment to improve the materiel condition of our plant and to recover or attain higher levels of plant reliability and hence improve output levels. The asset survey review we recently concluded will be instrumental in seeking to identify and prioritize necessary expenditure over the next 5 years and to assist in ensuring that this expenditure is well targeted; |
| (v) | Management of work follows on from the work management program initiated in 2001 and aims to improve the effectiveness and efficiency of maintenance work activities; to standardize processes for resolving issues across sites where commonality can provide benefits; and to redirect planning and work management processes to reduce maintenance backlogs by, for example, undertaking more maintenance at the same time as works undertaken in relation to planned and unplanned outages. Other key focuses are on keeping work scopes stable, improving adherence to work schedules and improving outage management across the fleet; and |
| (vi) | Operational focus seeks to strengthen the management focus on excellence in nuclear operating performance. It includes the introduction of an effective corrective action program, redirecting our engineering teams to focus more closely on the health and performance of our systems (targeting the root cause of problems), ensuring operational challenges are identified and resolved prior to them impacting the operation of the stations, and promoting increased use of operating experience information to improve plant safety and reliability. |
We envisage that PIP will evolve over time, as it is implemented, to reflect changes to our business and operations though its overriding objective – to reduce unplanned outages – would remain unchanged.
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Following an initial mobilisation phase which ended in July 2004 and which included an asset condition survey and the development of a plan of action, the next phase of PIP implementation, which will focus on staff organization, prioritization of work activities and human performance initiatives is targeted to complete, subject to availability of sufficient working capital headroom around April 2005. The final phase, which focuses on investing in the materiel condition of our plant, is targeted to complete, subject again to sufficient working capital headroom being available, by March 31, 2007. Certain aspects of remedial capital investment will, however, likely run beyond that into the financial year ending March 31, 2008.
The investment in the materiel condition of our plant will focus initially on those items which we believe from our asset survey condition, represent high priority issues. There can be no assurance that the items of plant which we have identified as lower priority issues, on the basis of information to date, will not be a cause of an unplanned outage in the future or that the order in which we deal with higher priority items of plant will prevent unplanned outages. Furthermore, we recognize that to successfully improve our overall business performance we will need to perform better across a number of different areas of our business such as trading.
By putting in place and implementing PIP, which in essence involves investing in our people, processes and plant, we are aiming to increase the reliability of our nuclear generating assets. PIP should also lead to a reduction in our maintenance backlog. We believe that as a result of PIP, if properly implemented, we will be better placed to play a role in any future review by Government of UK energy policy.
However, because of PIP’s wide ranging nature and the time and costs involved in implementing it, we do not expect to see the benefits of the hoped for improvement in operational reliability in the current or next financial year. The degree of improvement in operational reliability and the quantification of its impact on our financial results will depend on how the implementation of PIP progresses in the next 12 months but the directors believe, on the basis of other improvement programs implemented elsewhere in the world, that enhancements in output reliability should be capable of being achieved.
However, AGR power stations are unique to the UK and were built in the 1970s and 1980s by different design consortia to different design specifications. Accordingly, there can be no assurance that the improvement in reliability achieved in other nuclear power station improvement programs, upon which PIP is based and which have been undertaken on newer fleets of nuclear power stations based on non-AGR technology, will be capable of being achieved in respect of our AGR power stations.
Station lifetimes
The primary factor in determining the operating life of a nuclear power station is the technical and economic practicability of supporting an agreed safety case for that station. A safety case is the underlying written report that describes the steps taken to secure the safe operation of a power station as well as certain supporting documents built up over the years of the station’s operation that demonstrate the arrangements made for managing the safety of that station. The adequacy of the safety case for each power station is confirmed at each statutory outage by us undertaking a review of operating performance and by an inspection of the plant and passing the findings of such review and inspection to the NII. The NII must then give its consent to a reactor being restarted. As such a reactor may only be operated for the interval determined by the safety case which, in the majority of our AGR power stations, is currently three years. The NII’s consent to a restart is a matter determined by the NII in its sole discretion. Its decisions are made by reference to its satisfaction with the safety case at the reactor in question. From time to time such consent to restart is not received from the NII.
In addition, every ten years we have to undertake a Periodic Safety Review (“PSR”) for each nuclear power station. This, too, requires NII approval in order to secure continued operation. Following the first PSRs at our AGR stations, the NII gave its approval for a further ten years of
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operation for each station based on an agreed program of work for modifying the plant to ensure adequate safety cases. For further information on PSRs, see the heading below entitled “Periodic Safety Reviews”.
A key element in support of an AGR safety case is the ability to demonstrate the continuing integrity of the reactor’s graphite moderator core (as they may be uneconomic to replace) and is dependent on the NII’s perception of, among other things, the key technical issues such as the onset of graphite core brick cracking and reduced boiler life (which are discussed in greater detail in Item 3. Risk Factors). By contrast, the key element in support of a PWR’s safety case is the ability to show the continuing viability of the lifetime of the reactor pressure vessel (as this is unlikely to be economic to replace).
The assessment of the potential lifetimes of our stations used in our financial statements (and as set out below) is known as the “accounting life”. This is consistent with our technical assessment of the ability to make a secure safety case at each statutory outage and at the relevant PSR. The current potential lifetimes are set out in the following table.
| Station |
Lifetime |
Estimated Closure Date |
Date next PSR is submitted to NII |
Date of expected response from NII | ||||
| Dungeness B |
25 | 2008 | December 2006 | January 2008 | ||||
| Hinkley Point B |
35 | 2011 | December 2005 | January 2007 | ||||
| Hunterston B |
35 | 2011 | December 2005 | January 2007 | ||||
| Heysham 1 |
30 | 2014 | December 2007 | January 2009 | ||||
| Hartlepool |
30 | 2014 | December 2007 | January 2009 | ||||
| Torness |
35 | 2023 | December 2008 | January 2010 | ||||
| Heysham 2 |
35 | 2023 | December 2008 | January 2010 | ||||
| Sizewell B |
40 | 2035 | December 2013 | January 2015 |
The exact closure date of our AGR stations will depend on the timing of the reactors’ statutory outages. We will aim to close one of a pair of AGRs ahead of the other in order to allow the de-fuelling which forms part of the decommissioning process to take place efficiently.
Extension of accounting lifetimes
We recognize that extending the lifetimes of our stations will enhance the value of our asset base, and we plan to carry out the evaluations to see if station lives can be extended. A decision to extend the accounting life of an AGR station is based, in large measure, on the engineering judgments made in relation to that station’s safety case bearing in mind the technical issues referred to above. The current assessment of station lifetimes set out above for all our AGR stations, other than Dungeness, is at least five years greater than their initial design lives. These extensions were made on the basis of our judgment of our ability to make a secure safety case for the extended lifetime of the station (taking into consideration the related technical issues).
There can be no assurance that lifetime extensions will be attainable at any of our AGR power stations nor that the existing operating lifetimes used in our financial statements will be capable of being achieved. For further information see “Item 3—Risk Factors—Problems of graphite core brick cracking and reduced boiler life could negatively affect our profitability and the lifetime of our AGR power stations.” If our AGR power stations are to operate until the end of the current operating life used in our financial statements, we will also need continue to be able to source AGR fuel from BNFL, the sole supplier of AGR fuel. See Item 3. Risk Factors Our business depends on equipment and service suppliers of a specialized nature.
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Nuclear fuel cycle
There are several clearly identifiable stages in the life of nuclear fuel, known as the fuel cycle. The stages of fuel preparation before it enters the reactor, namely, uranium supply, conversion, enrichment and fabrication, are known as the front end fuel cycle. The handling, storage, reprocessing and ultimate disposal of spent fuel and associated waste products are known as the back end fuel cycle. The various stages of the fuel cycle and the relevant fuel cycle contracts are described in more detail below.
The front end fuel cycle
Uranium supply, conversion and enrichment
New uranium production is supplied from mines in the form of uranium ore concentrate, and is available on the competitive world market. It is first converted into uranium hexafluoride (natural UF6). There are five major suppliers of conversion services and there is a competitive world market, although one of the suppliers (BNFL) has announced that its conversion plant will be shut down in 2006.
Once the uranium has been converted to natural UF6, it is enriched by increasing the proportion of UraniumU235 to make it suitable for use in certain types of commercial nuclear reactor (enriched UF6). There are four major suppliers in a competitive world market for enrichment services. Uranium in the forms of ore concentrate, UF6 and enriched UF6 are collectively termed uranics. Over the last 15 years a substantial proportion of the world’s uranics needs have been met from ex-military and civil stockpiles.
Fabrication
Up to the fabrication stage, fuel cycle processes are identical for both AGRs and PWRs. At the fabrication stage, enriched UF6 is converted into either AGR or PWR ceramic fuel pellets and assembled to produce fuel elements and fuel rods which are subsequently loaded into the reactors.
The sole supplier of AGR fuel fabrication services is BNFL. A competitive world market exists for PWR fuel fabrication services.
Front end fuel cycle contracts
Uranium procurement, conversion and enrichment
Under arrangements agreed as part of the Restructuring, BNFL is now responsible for purchasing all the uranics we require to be manufactured into fuel for our AGR power stations. Previously BNFL purchased uranics on behalf of the British Energy Generation (UK) Limited (“BEG (UK)”) stations only. BNFL is also responsible for purchasing enriched uranium for on-supply to our PWR fuel fabricator. These arrangements are set out in the AGR fuel fabrication and supply agreements between our companies and BNFL.
Existing contracts for the supply of uranics, along with the transfer by us to BNFL of British Energy BEG’s existing stocks of uranics both transferred to BNFL as part of the revised purchasing arrangements, are sufficient to fully meet our requirements for our AGRs and PWR until at least the end of 2006.
AGR fuel fabrication
We are dependent on BNFL as the sole supplier of AGR fuel fabrication services for the operating life of our AGRs. The AGR Fuel Supply Agreements agreed as part of Restructuring will expire when no further AGR fuel is required to be loaded into our AGR stations.
We maintain stocks of fuel at our AGR power stations which, together with the capability of the AGRs to continue to generate power without the need for new fuel to be loaded, would be sufficient for approximately three to four months’ continuous generation in the event of supply disruption.
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PWR fuel fabrication
Fuel fabrication services for Sizewell B are currently provided by Framatome ANP (Framatome) utilizing enriched uranium supplied to us by BNFL under the AGR Fuel Supply Agreements referred to above. The agreement with Framatome provides for a mix of fixed commitments for PWR fuel and options for us to call for additional PWR fuel, and is capable of meeting Sizewell B’s requirements until around 2015.
As PWR fuel is readily available in a competitive world market, we believe that it would be possible to secure replacement supplies in the event of supply disruption from Framatome, subject to fuel compatibility and licensing requirements.
The back end fuel cycle
Spent fuel
Spent fuel is fuel which is removed from a reactor because it can no longer support the required level of power generation. Following a three to six month period of storage and cooling in water-filled ponds at the AGR station sites, the spent AGR fuel is loaded into specially designed flasks and transported to BNFL’s plant at Sellafield, England for reprocessing or long-term storage. Our spent PWR fuel is stored on-site in cooling ponds pending construction of a longer term storage facility. Spent AGR and PWR fuel is stored for long periods prior to final disposal, or, after a period of at least three years for AGR spent fuel or five years for PWR spent fuel, it can be reprocessed.
Spent Fuel Reprocessing
Reprocessing of spent AGR fuel separates uranium and plutonium from highly radioactive nuclear waste products and is followed by storage of the resulting materials. We use BNFL’s reprocessing facilities at Sellafield, England. Reprocessed uranium can be recycled once it has been converted, enriched and fabricated into new AGR or PWR fuel. Reprocessed uranium is not currently used in the UK and a safety case has not been developed for its use.
Nuclear waste
Nuclear waste products are categorized by their radioactivity levels into low level radioactive waste, intermediate level radioactive waste and high level radioactive waste.
Low level waste (“LLW”) comprises potentially contaminated and slightly radioactive materials, such as used protective clothing and tools. In the UK, LLW represents approximately 86% by conditioned volume of radioactive waste. Most LLW can be handled by workers wearing simple protective clothing and gloves and without any requirement for radiation shielding.
Intermediate level waste (“ILW”) is more radioactive than LLW and includes the sludges and resins from the cleaning of cooling pond water and certain wastes arising from the reprocessing of spent fuel. In the UK, approximately 14% by conditioned volume of radioactive waste is classified as ILW.
High level waste (“HLW”) comprises spent fuel which is not reprocessed and certain nuclear waste products separated out from uranium and plutonium during the reprocessing of spent fuel. These categories of waste are characterized by the fact that their temperature may rise significantly as a result of its radioactivity and as such this factor has to be taken into account in the design of storage or disposal facilities. In the UK, HLW represents approximately 0.1% by conditioned volume of radioactive waste although this contains approximately 95% of the total radioactivity in all nuclear waste (excluding uranium and plutonium recovered from reprocessing).
The Government policy on HLW from reprocessing is that it should be stored for at least 50 years to allow the radioactivity to decay and heat generation to reduce. Once the waste has been allowed to cool the favored option is for underground disposal. Spent fuel which is not reprocessed should similarly be allowed to cool. Once the HLW has cooled, it will continue to be stored pending a decision
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on final disposal. There is currently no disposal route available in the UK for either ILW or HLW, however the Government has asked the newly formed Committee on Radioactive Waste Management to report to it on this issue in 2006.
Management and disposal of nuclear waste
We are responsible for the management and disposal of all operational nuclear waste arising from our operations in conformity with relevant law and regulations and having regard to Government policy.
LLW is often incinerated on site and the resulting ash and other LLW that has not been incinerated is, if appropriate, compacted and sent to BNFL for disposal at their facility at Drigg, England. We have contracts with BNFL until March 31, 2005 for the disposal of LLW. We intend to enter into further contracts with BNFL for the disposal of LLW at Drigg beyond March 31, 2005.
At present our ILW is stored on-site in purpose-built facilities and, in most cases, these facilities are designed to accommodate all of the ILW that we expect to be created during the current station lifetime. In anticipation of the fact that the capacity of our untreated ILW Resin storage tanks at Sizewell B will be exhausted ahead of plan, we are presently engaged in modifying the station’s on-site encapsulation plant to enable it to encapsulate ILW. Once the ILW has been cement encapsulated in metal drums, the waste can be stored in Sizewell B’s conditioned waste storage building. We intend to complete the encapsulation plant modifications before ILW resin storage tank exhaustion.
Back end fuel cycle contracts
Reprocessing and long-term management of spent fuel
AGR fuel
Each individual AGR power station’s storage capacity varies but overall capacity is approximately equivalent to nine months’ of spent fuel storage and with the storage facilities usually holding approximately six months’ spent fuel, this leaves approximately three months’ additional capacity in case of any short term interruptions in the movement of spent fuel to BNFL’s Sellafield site. If a station’s spent fuel storage facilities became full, the station could theoretically continue to generate, but the volume of electricity produced would gradually reduce as the fuel in the reactor was consumed. It would not be possible to load additional fuel into the reactor until the stored spent fuel was dispatched to Sellafield or otherwise suitably stored.
We have contracts with BNFL (the only available supplier of reprocessing and long term storage services in respect of spent AGR fuel) for the long term management of spent fuel covering the entire operating lives of the AGR power stations (the “Historic Fuel Agreements”) and for the fuel recovered from reactors at the end of their operating lives (the “New Fuel Agreements”).
Upon implementation of the Restructuring, under the Historic Fuel Agreements, BNFL will provide spent fuel management services for a certain period for all spent fuel arising from fuel which has been loaded into our AGR power stations prior to completion of the Restructuring (historic spent fuel). We retain ultimate responsibility for these materials after the date on which BNFL is no longer obliged to perform the services. The Government has agreed, subject to the implementation of the Restructuring, to meet our liabilities to BNFL (subject to certain exceptions) under the Historic Fuel Agreements (pursuant to the provisions of the Historic Liabilities Funding Agreement (the “HLFA”)). Under the HLFA, the Government will also have an option to acquire title to any of our historic spent fuel and materials deriving from spent fuel management at Sellafield.
Under the Nuclear Liabilities Funding Agreement (“NLFA”) the Government will (subject to certain exceptions and to the implementation of Restructuring) fund the uncontracted liabilities for management and disposal of the materials arising from the spent fuel management services (and for which we retain responsibility) to the extent that these and other defined liabilities cannot be met from the NLF. Under the Historic Fuel Agreements, BNFL will be responsible for the storage of the uranium, plutonium and, pending disposal, HLW and ILW arising from historic spent fuel reprocessing and for the storage of historic spent fuel which is not reprocessed until an agreed date.
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BNFL will be obliged to treat, package and store ILW resulting from fuel contracted for reprocessing under the Historic Fuel Agreements. If we require it, BNFL will store our ILW waste until an agreed date. BNFL will also take title to and all liabilities for certain pond equipment (LLW and/or ILW) which is used to store fuel on behalf of BEGL. The contracts with BNFL also provide for the possibility of extending these periods of storage, subject to obtaining necessary regulatory and planning consents, and taking into account the need for storage beyond this date.
Under the New Fuel Agreements BNFL will take title to, and all liability for, the management and ultimate disposal of all AGR spent fuel arising from fuel loaded into the reactors on or after implementation of the Restructuring.
PWR fuel
We intend that spent PWR fuel from Sizewell B will be stored on the Sizewell B site pending final disposal of the fuel. PWR fuel is not currently expected to be reprocessed though this has not been discounted.
The spent fuel storage pond at Sizewell B was designed to accommodate 18 years’ of spent fuel arisings and will be reconfigured to accommodate approximately 30 years’ spent fuel arisings, subject to obtaining appropriate consents including from the NDA. The reconfiguration work requires completion by 2009/10 to allow the continued operation of Sizewell B. At this time, it is our judgement that these works will be completed before or during 2009/10. We will consider, in due course, arrangements for the remainder of lifetime arisings for spent PWR fuel in the light of the prevailing commercial and regulatory environment.
The qualifying costs of waste management and the disposal of spent Sizewell B fuel will be met by the NLF (described in greater detail below in paragraph below headed: Liability for decommissioning).
Nuclear decommissioning
The decommissioning process
Decommissioning of a nuclear power station is the process whereby it is shut down at the end of its economic life and eventually dismantled. Throughout the world, over 90 nuclear reactors have been shut down and a large number of decommissioning projects are in progress. Decommissioning usually takes place over several decades and the majority of these projects are at an early stage. However, there is a growing volume of experience of the early decommissioning activities and pre-closure planning and preparation requirements of large scale nuclear power station decommissioning.
Our objectives for decommissioning are to: ensure the continued safety of the public, the workforce and the environment; minimize the environmental impact of the decommissioning of our stations as far as reasonably practicable; release sites for other use as appropriate; and, consistent with all of the foregoing, minimize the expenditure of resources on decommissioning.
We have adopted the Early Safestore Decommissioning Strategy (“ESS”) for decommissioning our AGR and PWR stations. The principal activities of the ESS are:
| • | Stage 1: pre-closure preparatory work; defueling; decommissioning engineering preparatory work; and management of potentially mobile operational wastes; |
| • | Stage 2: dismantling redundant ancillary buildings; safestore development; site surveillance, care and maintenance; and |
| • | Stage 3: preparation for reactor building dismantling and clearance; retrieval and management of stored radioactive waste; reactor dismantling and reactor building dismantling and clearance; and site clearance and release for re-use. |
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Liability for decommissioning
We have an obligation under our nuclear site licenses to decommission our stations at the end of their useful life. The estimated undiscounted costs of decommissioning our AGR and PWR stations are £5.1 billion. For further details, see Note 21 of our audited consolidated financial statements. Currently, certain of the decommissioning liabilities are covered by the existing arrangements with the Nuclear Decommissioning Fund (“NDF”) to which we have made contributions pursuant to the terms of the Nuclear Decommissioning Agreement (“NDA”) which was entered into on March 29, 1996.
If the Restructuring becomes effective, the NDA will terminate, the Nuclear Liabilities Funding Agreement and Contribution Agreement will become fully effective and the existing NDF will be enlarged into and renamed the NLF.
Under the terms of the Restructuring, the NLF will, subject to certain exceptions, fund certain of our qualifying uncontracted nuclear liabilities (i.e. all those nuclear liabilities for which there is currently no contract in place) and the costs of decommissioning our nuclear power stations and certain contracted liabilities for historic spent fuel. The NLF will be funded by contributions from us and the Government has agreed to fund the qualifying decommissioning costs and qualifying uncontracted liabilities to the extent that they exceed the assets of the NLF. To the extent that there is any surplus funds in the NLF, this amount will be paid to the Government. We will make the following contributions to the NLF:
| • | £275 million of New Bonds; |
| • | fixed decommissioning contributions of £20 million per annum (indexed to the UK Retail Price Index (“RPI”) but tapering off as our nuclear power stations are scheduled to close); |
| • | £150,000 (indexed to the RPI) for every tonne of fuel loaded into Sizewell B from the Effective Date of the Restructuring; and |
| • | The NLF Cash Sweep. |
The trustees of the NLF will have the right from time to time to convert all or part of the NLF Cash Sweep into our convertible ordinary shares. On a full conversion the NLF would hold up to 65% of the thereby enlarged share capital of the Company. These shares will be subject to certain voting restrictions, so that, for so long as the shares are held by NLF, they will be non voting to the extent they would otherwise carry more than 29.9% of our voting rights. The convertible ordinary shares will convert into New Shares automatically on transfer by the NLF to a third party but will not otherwise be convertible at the option of the NLF. There are certain restrictions on the manner which the NLF may convert its NLF Cash Sweep Payment or dispose of any of its shares.
COAL FIRED GENERATION
Eggborough Station’s operating regime
We acquired EPL, the owner of the Eggborough Station, from National Power (now RWE Innogy) in March 2000. This purchase was re-financed by a project finance loan of £550 million entered into on July 13, 2000 pursuant to which the lending banks (the Eggborough Banks) were granted security. As part of the Restructuring, the Eggborough Banks shall continue to have security over, among other things, the shares in EPL and the Eggborough Station and will have an option to acquire the Eggborough Station either through a share or asset purchase in 2010.
The Eggborough Station continues to be operated by our subsidiary EPL. Output from the Eggborough Station was 7.6 TWh during the year ended March 31, 2004, compared with 5.7TWh and 7.1TWh for the years ended March 31, 2003 and March 31, 2002, respectively. The Eggborough Station’s output level is influenced by market prices, our contracted trading position and the extent to which its operation is required to cover for unplanned outages at our nuclear stations, and by relevant environmental legislation (the influence of relevant environmental legislation will significantly increase over time).
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As a result of it being coal-fired, the Eggborough Station produces emissions of carbon dioxide (CO2), sulphur dioxide (SO2) and nitrogen oxides (NOx), and therefore its future output will be affected by the impact of two important environmental initiatives which seek to limit these emissions namely, the EU Emissions Trading Scheme and the Large Combustion Plant Directive, which are discussed in the paragraph below headed “Legislation affecting the Eggborough Station’s output”.
The Eggborough Station consists of four generating units with a nominal capacity of 500 MW and is operated at various levels, rather than at constant levels in the manner of our nuclear stations. Specifically, the Eggborough Station fulfils the following functions:
| • | Reserve capacity: by maintaining a level of reserve capacity it assists in managing the trading risks associated with unpredictable reductions in the availability of our nuclear stations. Calling on the Eggborough Station as an alternative source of supply reduces our reliance on the spot markets or the balancing mechanism; |
| • | Profiling or Shaping: unless a customer has a purely base load power requirement (i.e. a requirement for unvarying amounts of energy) we are unable to meet this requirement based solely on our nuclear generation capacity. As a result, we need to combine our base load generation with flexible output to meet the requirements of our customers who require varying levels of output over the term of their contract. The Eggborough Station provides us with a source of electricity supply for this purpose, thereby reducing our reliance on purchases from competitors; and |
| • | Flexibility: changes in customer demand over the short term and the nature of the overall customer profile mean that we need to have access to generation that is able to change output rapidly in response to changing requirements. Like other fossil-fuel power stations, the Eggborough Station is able to provide this flexibility and is an alternative to the use of the short term markets and power exchanges. |
We own an ash disposal site at Gale Common, close to the Eggborough Station, which is used for the disposal of ash produced by the Eggborough Station and the nearby Ferrybridge power station, which is owned by a subsidiary of Scottish and Southern Energy plc.
Investment in the Eggborough Station
In response to recent developments in relation to the regulation of emissions, details of which are set out in paragraph below headed “Legislation affecting the Eggborough Station’s output”, we are in the process of fitting two of the four generating units with flue gas desulphurisation (“FGD”) equipment. Once operational this equipment is designed to reduce emissions of SO2 to the atmosphere from the units which have been fitted with FGD by approximately 90%. The construction of the FGD equipment has been completed and commissioning tests are in progress.
As part of the Restructuring, we are also contractually committed to other investments to improve the Eggborough Station’s performance and reliability, including modification work to reduce CO2 emissions and improve plant monitoring and control systems and the acquisition of strategic spares for critical components.
Legislation affecting the Eggborough Station’s output
The EU Emissions Trading Scheme (“ETS”) and Large Combustion Plant Directive (“LCPD”) are major environmental initiatives which will have an important impact on the Eggborough Station as they seek to reduce CO2, and SO2, NOx and particulates. The ETS is due to be implemented in January 2005. The main provisions of the LCPD which limit emissions are due to become effective on January 1, 2008 and, in replacing the previous LCPD, will restrict further the limits of permitted emissions.
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ETS
Combustion installations with a rated thermal output in excess of 20 megawatts (excluding hazardous or municipal waste installations) require a Greenhouse Gas Emissions Permit (an Emissions Permit). Under an Emissions Permit, a combustion installation is allocated CO2 emissions allowances (ETS Allowances). From January 1, 2005 onwards, each combustion installation must surrender ETS Allowances equal in amount to its actual annual reportable emissions of CO2 by the date falling four months from the end of the year in which such emissions arose. In any year, a combustion installation’s emissions of CO2 may not exceed its ETS Allowances for such year unless it has purchased additional ETS Allowances to cover such excess emissions (in principle, ETS Allowances should be tradable across all EU member states, enabling those operators with a surplus of allowances to sell to those with a shortfall).
Eggborough power station has an Emissions Permit, however, the Government is still in the process of determining the allocation of ETS Allowances for combustion installations. Implementation of the ETS in the UK involves a draft National Allocation Plan (NAP) under which each combustion installation, including the Eggborough power station, is given a CO2 allocation for the period 2005/2007 (the First Phase). The Government is seeking an overall reduction in emissions of a package of greenhouse gases of 12.5% (based on 1990 levels) by 2010. In the draft NAP submitted to the Commission in April 2004, the Government stated that the First Phase would reduce emissions of CO2 by 5.5 million tonnes and that this would be achieved by cutting the projected emissions of the power station sector by a corresponding amount.
In the draft NAP published by the Government in January 2004, the Eggborough power station was allocated ETS Allowances equating to 4.9 million tonnes of CO2 emissions in each of the calendar years 2005, 2006 and 2007. This is equivalent to the level of emissions associated with electrical output of approximately 5.4TWh in each such year. This allocation is scheduled to be finalized in autumn 2004 but may change. Depending on the final allocations, additional allowances may need to be acquired if the Eggborough power station is to continue to generate electricity at 2003/2004 levels. We, along with other industry participants, are lobbying the Government for an increase in ETS Allowances. (The Government has indicated that they intend to retain some ETS Allowances for new market entrants and to auction any unallocated ETS Allowances from this reserve on an annual basis in the years up to 2007).
The basis for the allocation of ETS Allowances in the second phase of the ETS (this relates to the period from 2008 to 2012) has yet to be determined by the Government.
LCPD
The revised LCPD seeks to reduce the emissions of pollutants (namely NOx, SO2 and particulates) into the air from large combustion plants. By January 1, 2008, EU member states must achieve significant emissions reductions in one of two ways:
| • | ensuring that all permits for the operation of existing plants contain conditions securing compliance with the Emission Limit Values (“ELVs”) established for new plants; or |
| • | ensuring that existing plants are subject to a National Emission Reduction Plan (“NERP”). |
The ELV approach involves setting emission rate limits for individual plants, for sulphur dioxide, oxides of nitrogen and particulates for a given period which cannot be exceeded without breaching its permit. In comparison NERP involves the reduction of total emissions for the EU member state concerned, referenced to the levels that would have been achieved by applying the same rate limits as under ELVs to existing plants in operation in the year 2000, on the basis of each plant’s actual annual operating time, fuel used and thermal input averaged over the last five years of operation up to and
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including 2000. Provided that the total amount allocated to an EU member state is not breached, a member state has some flexibility in how it introduces NERP, for example, while each plant may be subject to limits under NERP, it may allow its plants to trade their allocation amongst other plants in that same member state. However, a member state’s flexibility under NERP will always be limited by the limits set under the pollution, prevention and control regime and the fact that the LCPD provides that the closure of plants included in the NERP shall not result in an increase in the total annual emissions from the remaining plants covered by the plan.
The Government has been in discussions with the electricity, steel, oil refining and other industries in recent months concerning the implementation of the LCPD. Discussion has focussed on whether to limit future emission rates for plants or to limit total emissions based on historic generation; and whether a plant will be treated as being a whole station, or an individual generating unit, in which case the Eggborough power station’s four units would be treated as separate plants. In the case of the former, the Government has highlighted that it is in discussions with the Commission about implementing a hybrid solution where large power stations, such as Eggborough, would be subject to rate limits for future emissions.
Plant owners have the option to “opt-out” of the LCPD in which case they will be permitted to run plants for a total of 20,000 hours between January 1, 2008 and January 31, 2015, subject to additional regulations imposed by the Environment Agency. Given the uncertainty on the key issues, the Government has provided further instruction that plant that is opted out by June 30, 2004 can be opted back in prior to June 30, 2005. British Energy has therefore chosen to conditionally opt-out its two non-FGD units, the conditionality relating to i) the choice to opt back in prior to the June 30, 2005 deadline and ii) whether a plant is treated as being a whole station, or an individual generating unit (if the former is the case the two-unit opt-out would be deemed invalid and those two units would be opted back-in again (subject to the consent of the Eggborough Banks holding 66 2/3% of the debt under the Amended Credit Agreement (such consent not to be unreasonably withheld or delayed)).
The final details of the implementation of the LCPD may affect the level of generation from the Eggborough power station and other fossil fuel plants in the future. The Government is expected to make a decision on how the LCPD will be implemented in the next few months.
Other legislation
Limits on the emissions of pollutants may also be imposed in permits issued by the Environment Agency (“EA”) and it is possible that stricter limits could be imposed than under the LCPD and NAP. This is because the EA are required to implement the LCPD and ensure that in doing so the National Emissions Ceiling Directive is not compromised. In addition, the EA has to take into account the requirements of the Integrated Pollution, Prevention Control Directive in 2006 and also the National Emissions Ceiling Directive (2001/81/EC), the Habitats Directive (1992/43/EEC) and the Water Framework Directive (2000/60/EC) requirements in setting permit conditions going forward.
ELECTRICITY SALES
We use a variety of routes to market to sell our generation output. These include bespoke longer term contracts, over-the-counter transactions in the wholesale traded market, electronic power exchange trading, direct supply to industrial and commercial customers, and sales of balancing and ancillary services to the National Grid. We also sell forward in order to manage the risks of short to medium price volatility in wholesale market prices and because there is insufficient liquidity in the short term markets alone for us to be sure that we would be able to sell our generation at an acceptable price.
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Role of trading
Our approach to trading utilizes these different routes to market with a view to seek to reduce overall exposure to volatility in short and medium term wholesale electricity market prices whilst seeking to reduce the amount of credit support required. We aim to build a portfolio of wholesale trades and direct supply contracts (often at fixed prices) to approximately match our planned generation output and to further mitigate the exposure to the wholesale market and, in particular, the risk of wholesale electricity market prices falling. This approach does however reduce in the medium term the benefit we receive from wholesale electricity prices rising. As of mid September 2004 we had in place contracts for volume equivalent to virtually all of our planned generation in 2004/05, of which a large majority are at fixed prices. For 2005/06, contracts are in place for over half of planned generation, with a significant proportion of these being at fixed prices. The average price under fixed contract price contracts for 2004/05 was £20.8 per MWh as of mid September 2004. This is substantially higher than the average realized price of £16.9/MWh for the year ended March 31, 2004.
Trades in the wholesale market
Longer term structured trades, on fixed or indexed price terms, are used in particular to hedge against exposure to falling market prices or to secure a longer term route to market for planned generation.
All of our over-the-counter trades, and a number of our longer-term bespoke trades are executed under the terms of Grid Trade Master Agreements (“GTMA”) agreed with the counter-party in question. The GTMA contract details responsibilities for contract notification and other obligations in respect of the Balancing and Settlement Code (“BSC”), payment terms, default and termination provisions, credit arrangements and other terms. Over-the-counter GTMA transactions, including both futures and options on electricity, are used to balance generation against the portfolio of contracts and as a hedge against adverse market price movements in the short to medium term.
Our ability to utilize the wholesale market as a route to market is affected by the strength and depth of the market, see risk Item 3—Risk Factors: “Lack of liquidity in the wholesale market may adversely affect or require us to alter our trading strategy”.
Short term trading is carried out via the Amsterdam Power Exchange (UK) Limited (APX), and is regulated by the Financial Services Authority. APX provides an anonymous electronic trading platform and clearing and notification service for electricity futures and spot trades for individual half-hour periods. We primarily use APX as a means of balancing our within-day physical position by either buying or selling to compensate for differences between our notified contractual position and planned generation and forecast supply up to gate closure, i.e. one hour before the start of the relevant delivery period. We typically trade 2-hour or 4-hour blocks, or individual half-hour periods.
Trading in products which may be regarded as regulated investments is carried out by our trading subsidiary, British Energy Trading Services Limited (“BETS”) as agent and arranger for BEPET. BETS is regulated by the Financial Services Authority in respect of these activities.
Direct supply business
One of our important routes to market is direct supply sales of electricity to industrial and commercial customers. Our target customer base is predominantly among industrial users with electricity demands of over 1,000 MWh per annum. As of March 31, 2004, we had contracts in place to supply some 1,350 customers at 7,500 sites. Our direct sales business has increased by almost 30% in volume terms in the period March 31, 2003 to March 31, 2004, to 29TWh, which is equal to approximately 40% of our total electricity generation. This follows an increase of 20% in volume terms in the period March 31, 2002 to March 31, 2003.
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We are progressively increasing the range of customers and are targeting customers such as retail groups with a large number of sites although we are not licensed to supply domestic customers. We have continued to maintain an overall number one ranking in terms of satisfaction of industrial and commercial customers for the last 20 successive quarters, based on data compiled by the independent Energy Information Centre via a quarterly survey of their customer base. The survey is designed to measure how customers rate the service they are receiving from their suppliers in 18 separate service areas. These service areas include, among others, contract price, responsiveness to enquiries, bill accuracy, clarity and promptness.
Ancillary and balancing services
We provide National Grid with ancillary services which include reactive power and frequency response. Because of its flexible response capability, the Eggborough Station is also able to provide balancing services to National Grid which are paid for at the bid or offer price if accepted.
Arrangements in Scotland
As there is currently no wholesale market in Scotland, we currently sell all the output from our Scottish nuclear power stations to Scottish Power and Scottish and Southern Energy under the terms of the Nuclear Energy Agreement (“NEA”), which was originally entered into in 1990 and subsequently amended, most recently, on July 15, 2002.
Under the revised terms of the NEA, Scottish Power and Scottish and Southern Energy purchase the electricity generated by our Scottish power stations from us under arrangements more closely linked to market prices and terms for the supply of base load energy in England and Wales than previously. The revised NEA will continue in operation until the introduction of BETTA (which is currently scheduled for April 1, 2005) or, if earlier, April 1, 2006. A further extension of the amended NEA beyond its original date of April 1, 2005 will be subject to regulatory approval. Beyond that date, Scottish Power and Scottish and Southern Energy have an option for follow-on contracts on GTMA terms up to 2011, at reduced volumes.
Collateral
Our electricity contracts give rise to the need for us to provide credit support in the form of cash collateral. In respect of trades in the wholesale market, this is requested by counter parties to ensure that, should the contracts terminate early for whatever reason, there are sufficient funds available to reimburse the costs they may incur in replacing the terminated transactions in the open market. In respect of most routes to market, and in respect of generation by our power stations, credit support is also required to ensure that there are sufficient funds available to cover balancing, transmission, distribution and other similar costs and charges.
Until September 2002, credit support was generally provided by way of parent company guarantee from British Energy plc. Following the loss of our credit rating in September 2002 this was replaced by collateral arrangements, which have substantially reduced the levels of liquid cash resources available to us. The level of collateral that we are required to post at any time is a function of three factors: (i) our contracting strategy; (ii) contract price; and (iii) prevailing electricity market prices.
Under certain of our GTMA wholesale contracts or as otherwise agreed, we are required to post collateral equal to the net sum of (i) billed or billable amounts which have not yet been paid for; (ii) the mark-to-market difference between the contract price and the prevailing market price at that time; and (iii) an additional sum that reflects the potential for market price volatility and future trades. Generally we have agreed to undertake this calculation on a weekly basis and any collateral sums that need to be posted are credited to a deposit account over which the relevant counter party holds a first fixed charge. In some limited cases the level of collateral that we are required to post is capped.
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Our direct supply sales to industrial and commercial customers do not require us to post any collateral to the purchasers of power. However, collateral is posted to distribution network operators in order to cover fees that BEG has to pay them.
In 2002 and 2003, we entered into contracts at the then prevailing wholesale market price equivalent to a large proportion of our forecast 2004 generation output. Since then, electricity prices have increased substantially, which has resulted in us being required to post a significant amount of collateral in support of these contracts.
Our direct supply sales to industrial and commercial customers generally do not require us to post any collateral to the purchasers of the power. However, collateral is required by distribution network operators in order to cover charges that BEG has to pay them.
Since notification of the EC State Aid decision on September 22, 2004, incremental collateral requirements are being provided by a charge over cash deposits in accounts in the name of Group Companies. Although the Group is satisfied that generally deposits in Group Company accounts will represent reasonable alternative credit support, in certain cases other types of collateral may be required and it may be the case that the provision of such charge arrangements for such collateral arrangements may affect the willingness of certain counterparties to trade with the New British Energy Group.
REGULATION
Introduction
Our participation in the electricity industry in two markets, England and Wales and Scotland, through a variety of routes, and the nature of the bulk of our electricity generation by nuclear power reactors means that we are a highly regulated business. In addition to the safety, competition, health and environment legislation which typically applies to a conventional power generation business, we are also subject to extensive safety, health and environmental constraints which apply solely to the operators of nuclear power plant, for example, the Nuclear Installations Act 1965 and the Radioactive Substances Act 1993. These regulatory regimes are described below in the paragraph below headed “Regulation of the UK nuclear generation industry”.
Regulation of the electricity industry
Key legislation
The framework for the economic regulation of the electricity industry in Great Britain is set out in the Electricity Act 1989 (Electricity Act) which was amended by the Utilities Act 2000 (Utilities Act) and the Energy Act 2004 (Energy Act).
GEMA was established by the Utilities Act. GEMA’s functions under the Electricity Act include granting licenses to generate, transmit, distribute or supply electricity; enforcing compliance with license conditions; administering funds generated by the English and Scottish Renewables Obligation Certificates (described in the paragraph below headed “Renewables Obligations”); and setting standards of performance for electricity licensees. The Electricity Act requires GEMA and the Government to exercise their functions under the Act in the manner which it considers is best calculated to protect the interests of consumers present and future, wherever appropriate by promoting effective competition.
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Regulatory developments
On July 22, 2004, the Energy Act received Royal Assent. The act provides the framework for the establishment of the NDA to manage the decommissioning of the UK’s nuclear legacy as well as the development of offshore wind and other marine renewable energy sources outside territorial waters. The act further provides for the implementation of BETTA thereby extending NETA to Scotland and creating a single wholesale electricity market for Great Britain. These new arrangements will create a much larger market for our Scottish generation once the NEA, under which all of our existing Scottish generation is currently sold to Scottish Power and Scottish and Southern Energy, ends in April 2006 or on the introduction of BETTA, whichever is the earlier. However, the termination of the NEA will also mean a loss of the guaranteed market for the output of our Scottish stations and other routes to market will need to be developed.
Licenses
Electricity generation licenses
Unless covered by exemption, all electricity generators operating a power station in the UK are required by the Electricity Act to have a generation license. In England and Wales, the conditions attached to a generation license require the license holder, amongst other things, to comply with the BSC (described above), the Grid Code and the Connection and Use of System Code (CUSC). For operators of power stations in Scotland, the conditions attached to generation licenses require the holder, amongst other things, to comply with the relevant grid code and the settlement agreement for Scotland. Failure to comply with any of the generation license conditions may subject the licensee to a variety of sanctions, including enforcement orders by GEMA, the imposition of monetary penalties or license revocation if an enforcement order or payment of a monetary penalty is not complied with.
Electricity supply licenses
Subject to minor exceptions, all electricity consumers in the UK must be supplied by a licensed supplier as provided for by the Electricity Act. Licensed suppliers purchase electricity and make use of the transmission and distribution networks to achieve delivery to customers’ premises. Following the enactment of the Utilities Act, there are now supply licenses covering all of Great Britain that contain standard license conditions for most suppliers.
The standard supply license is split into four distinct parts with not all parts of the license applicable to all supply license holders. The license deals with general obligations and requires the holder, amongst other things, to comply with the BSC, CUSC, Grid Code and Master Registration Agreement (the agreement to which all Ofgem licensed suppliers and distribution businesses are parties and which is concerned with retail customers changing their suppliers).
We currently hold one supply license through which we supply our large industrial and commercial customers in connection with our direct supply business. We are not licensed to supply to domestic customers.
Approval of State Aid
On September 22, 2004, the Commission advised the Government that, insofar as the restructuring plan notified by the Government on March 7, 2003 under Article 87(3) of the EU Treaty involved the grant of State Aid, such State Aid was compatible with the common market. The Commission’s decision is subject to certain conditions. These conditions include, amongst others, a requirement that we separate our direct supply business from other generation and trading businesses
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by April 2003. When we do so it is our intention to transfer our existing supply license for our direct supply sales business from BEG to British Energy Direct Limited, our direct sales subsidiary.
Renewables obligations
One of the ways in which the Government is seeking to increase the proportion of electricity generated from renewable sources is by the introduction of the Renewables Obligation (the “Obligation”). The Obligation on licensed electricity suppliers to source a proportion of their total electricity requirements from eligible renewable sources or to contribute through a buy-out payment came into force in April 2002. The amount of the Obligation increases from 3% in March 2003 to 10.4% in March 2011. As we are a licensed electricity supplier, we are subject to the Obligation in respect of our direct supply sales business.
Each MWh of electricity produced by an accredited renewable generator earns a Renewables Obligation Certificate (“ROC”) or, in Scotland, a Scottish Renewables Obligation Certificate (“SROC”). These certificates can be sold or purchased independently from the electricity to which they relate and a supplier can meet its renewables obligations by submitting equivalent ROCs/SROCs for the prescribed percentage of electricity supply or by making a buy-out payment to GEMA (currently set at £31.39/MWh and adjusted annually to reflect changes in the RPI) or a combination of both.
The Obligation is designed to incentivize electricity suppliers to acquire a sufficient number of certificates to meet their total electricity requirements, rather than making buy-out payments which are then distributed by GEMA (with interest accrued) to suppliers who have submitted ROC/SROCs in compliance with the Obligation.
In 2002/2003, the obligation in respect of our direct supply sales business was 564,622 MWh. This was met through a combination of ROCs, SROCs, and contributing to the buy-out fund. The cost of meeting the obligation is recovered from customers through their bills. For 2003/4 the amount of the obligation was 4.3% and the buy-out payment was £30.51/MWh.
Climate change levy
The Climate Change Levy (“CCL”), introduced in April 2001, aims to encourage the efficient use of energy and to reduce carbon emissions by around 5 million tonnes a year from 2001 levels by 2010. The CCL benefits qualifying renewables generators because energy acquired from renewable sources is exempted from the levy. Current Government thinking is that the CCL will continue in spite of the ETS. The levy is currently set at £0.43/KWh.
Our nuclear stations and the Eggborough power station do not qualify as renewable or CHP generators for the purposes of CCL. All suppliers are required to collect the CCL from their business customers and to pass this to HM Customs and Excise every quarter.
Regulation of the Eggborough Station and Gale Common
Key legislation
We are subject to numerous environmental regulations with respect to our ownership and operation of the Eggborough Station and the Gale Common ash disposal facility located next to the Eggborough power station.
A system of Integrated Pollution Control (“IPC”) for power stations was introduced under the Environmental Protection Act 1990 for which the Environment Agency has responsibility for
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enforcement. The EA’s IPC authorizations require power stations to use ‘Best Available Techniques Not Entailing Excessive Cost’ to minimize their emission of certain pollutants.
The Pollution Prevention and Control Directive 1996/61/EC was implemented in the UK on May 1, 2004 by the Pollution Prevention and Control Regulations and will modify the IPC regime, in relation to noise, waste minimization and energy efficiency, amongst other areas. Applications for authorization under the new Pollution Prevention and Control Regulations must be submitted to the EA by March 31, 2006.
Disposal of ash to the Gale Common facility is governed by the Landfill (England and Wales) Regulations 2002 and we currently hold two waste management licenses which are regulated by the EA.
More generally, we are also subject to the Water Resources Act 1991 which governs water pollution and requires persons who have knowingly permitted water pollution to carry out remediable works. The EU Environmental Liability Directive is aimed at the prevention and remedy of environmental damage to water, land and bio-diversity and is based on the principle that the polluter should bear the cost of damages caused to the environment or of measures to prevent imminent threat of damage.
Environmental management
We have seven key environmental policies for the Eggborough Station:
| • | To integrate environmental factors into business decisions. |
| • | To comply with all statutory and company requirements. |
| • | To continuously improve our environmental performance. |
| • | To minimize and control pollution from the process of electricity generation by implementing corrective action and/or control measures, as appropriate. |
| • | To regularly review and publicly report our environmental performance and objectives in our annual Environmental Performance Report. |
| • | To ensure our people are fully aware of their environmental responsibilities and seek participation in environmental activities. |
| • | To enhance our reputation for effective environmental management through certification to recognized standards. |
In addition, we have a comprehensive environmental management system in place which is accredited by Lloyds Register Quality Assurance to international standard ISO 14001, a standard which demonstrates our continued commitment to the prevention of pollution and recognizes our environmental performance.
We are also members of the Joint Environmental Program, a research initiative funded by eight of the major fossil fuel power station operators in the UK, including EPL, whose objective is to increase our knowledge of the impact that the production of electricity from fossil fuels has on the environment.
In 1994, we carried out a comprehensive Environmental Effects Evaluation covering emissions to air, land and water. Since this time, we have periodically updated the evaluation as part of our efforts to develop an effective environmental management system.
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Regulation of the UK nuclear generation industry
Key legislation
The principal areas of nuclear safety and security regulation in the UK (except for Northern Ireland) cover the construction, operation and decommissioning of nuclear installations and the protection of workers and the public against ionizing radiation. The principle regulating provisions are the Nuclear Installations Act 1965 (“NIA”), the Ionizing Radiations Regulations 1999 (“IRRs”) and the Anti-Terrorism Crime and Security Act 2001 (“ATCSA”).
Environmental regulation of the nuclear industry covers the disposal of radioactive waste including discharges to the environment under the Radioactive Substances Act 1993 (“RSA”). Regulation of the transport of radioactive material is the subject of the Radioactive Material (Road Transport) Act 1991 (“RMRTA”).
The nuclear generation industry is also subject to the same regulations as other generators as regards non-nuclear aspects of health and safety and environmental protection, in particular under the Health and Safety at Work Act 1974 (“HSWA”), the Environmental Protection Act 1990 (“EPA”), the Water Resources Act 1991 and the Pollution Prevention and Control Act 1999.
Nuclear site licenses
Under UK law, and in particular the HSWA, employers are responsible for ensuring the safety of their workers and the public. This responsibility is reinforced for nuclear installations by the NIA which establishes a nuclear licensing regime controlled by the HSE. The licensing function is administered on HSE’s behalf by the NII. Operation of a nuclear plant is governed by the nuclear site license and the license conditions which are attached to it and apply to the whole plant through its life cycle, up to and including the early stages of decommissioning.
Before a nuclear site license is granted, the NII must be satisfied as to the safety of the operation and eventual decommissioning of an installation, and the ability of the applicant to understand and meet its obligations. Prospective licensees will be assessed under three broad areas: organization of applicant and measures to discharge license obligations; location and security of site; safety of the site’s design, its manufacture, installation, commercial operation and maintenance. NII consent is also needed before key stages, such as decommissioning, commence. The safety of the installation is demonstrated through a written safety case and the applicant also documents the arrangements for the management of safety which the NII assesses prior to granting a license. Modifications to the original safety case are managed through arrangements which ensure that significant changes cannot be made if the NII objects.
The NII’s regulatory approach to safety involves defining levels of tolerable risk. Activities above the level of tolerability are not normally permitted. Tolerable risks must be reduced to a level which is as low as reasonably practicable.
Nuclear site licenses require adequate arrangements to be made for the decommissioning of any plant. To ensure that a licensee’s decommissioning strategies remain sound as circumstances change, they are reviewed every five years by the NII, which also consults the relevant environmental regulatory bodies. Applicants justify their chosen decommissioning strategy to the NII and demonstrate that there will be adequate funds to carry out the work.
The NII scrutinizes the activities of the licensee directly on site, and of the licensee’s central support organization, through the assessment of the licensee’s written submissions. An NII inspector is allocated to each nuclear power station and is typically present on site one week per month to hold meetings with the station staff and to check for compliance with the license conditions and safety case requirements. An inspection team may also visit the station to assess a particular part of the plant, or aspect of the safety case, and may also visit the licensee’s central support organization to assess its part in ensuring safety on the licensed sites. As discussed in greater detail in the paragraph below headed “Safety management”, each license also requires the establishment of a Nuclear Safety
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Committee (“NSC”) for each licensed site, to provide independent advice to the licensee on significant nuclear safety issues.
There are nuclear site license conditions requiring the licensee periodically to shut down the reactor to carry out inspections and maintenance (statutory outages), particularly in respect of the reactor core and other plant that cannot be accessed whilst operating, and to review and reassess the safety case for the plant. Statutory outages take place at intervals of up to three years for an AGR and up to 18 months for a PWR. Before consenting to the reactor restarting, the NII has to be satisfied that, based on the previous operating experience and the condition of the plant, there is an adequate safety case for the operation of the plant for the next period. This may require enhancement of the safety case to justify continued operation.
The NII’s powers under HSWA extend to industrial safety and to enforcing the conditions of the nuclear site license by the service of Improvement Notices, Prohibition Notices or, in the event of non compliance with license conditions or other offences, by prosecution. The NII may also direct a licensee to shut down a nuclear reactor. A nuclear power station remains a licensed site throughout the decommissioning process and is subject to the same system of regulation as when it was operational.
Under our nuclear site licenses, we are required to carry out a PSR to review the safety case for each of our stations once every ten years, taking into account current safety standards, the operational history and the effects of plant aging. Further details of the PSR are set out below in the paragraph below headed “Periodic Safety Reviews”.
Nuclear site licenses for our nuclear power stations are currently held in England by BEG and in Scotland by BEG UK. In December 2002, BEG applied for nuclear site licenses in respect of the two nuclear stations in Scotland currently licensed to BEG UK. The re-licensing of these two stations is expected to be completed in 2005 and will result in all of our UK nuclear stations being operated by a single licensed company.
Safety management
In accordance with its site license, each nuclear power station has established an NSC to provide independent advice to the licensee on significant nuclear safety issues. The NSC consists of senior company personnel with knowledge of, and responsibility for, nuclear safety and the relevant station director and external appointees who have significant experience in the nuclear industry. The NII approves the terms of reference of each NSC, which determines the matters to be referred to it, and has a power of veto on any appointment to an NSC.
License condition on organizational change
In March 2000, the NII added a new condition to the standard nuclear site license, thereby bringing changes to organizational structure and resource directly within the licensing regime. We have site license compliance arrangements in place to address the new license condition and to manage organizational changes which may affect nuclear safety, such as the creation of new station posts, reductions in manpower or outsourcing of functions. A program director and change plan were put in place in connection with the closure of the current headquarters at Peel Park, East Kilbride, Scotland to manage the impact on the business and enable the licensees to satisfy themselves and the NII that the closure will not adversely affect the overall capability of suitably qualified and experienced persons employed within the central functions who support nuclear operations.
Nuclear liability under the Nuclear Installations Act
The NIA provides that the licensee of a nuclear site has a duty to ensure that no occurrence involving either nuclear material or ionizing radiation causes personal injury or damage to property other than property of the licensee, or other property which is on the site and is used in connection with the operation of the nuclear installation. The licensee is exclusively liable for a breach of this duty irrespective of fault and we currently maintain insurance in relation to this risk.
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Under the NIA, our liability to pay compensation for a breach of this duty is currently limited to £140 million per occurrence (excluding interest or costs). The NIA requires the licensee to make provision, by insurance or such other means as the Government may approve, for sufficient funds to be available at all times to ensure that duly established claims are satisfied up to £140 million per site in respect of each of the periods of the licensee’s responsibility specified in the NIA. The NIA also requires that the Government will make available such sums (in addition to insurance or other funds which may be available from the licensee) as may be required to ensure that all duly established claims (excluding interest or costs) in respect of any occurrence are satisfied, up to 300 million special drawing rights (equivalent to approximately £240 million). A claim for compensation which is not satisfied out of this sum may, under the NIA, be satisfied by the Government to such extent as it may determine. The Secretary of State may direct the licensee to begin a new period of responsibility in the light of previous occurrences or claims.
It is likely that these thresholds will increase in the near future. On February 12, 2004, the Government signed a Protocol to amend the Paris Convention on Third Party Liability in the Field of Nuclear Energy, 1960 and the Supplementary Brussels Convention, 1963 which together increase the limit of liability of nuclear operators to a minimum of 700 million euros; the liability of the Government to 500 million euros; and the liability of the pool of funds contributed to by contracting parties to the Brussels Convention to 300 million euros. Total compensation available under the revised regime will be a minimum of 1.5 billion euros, a four-fold increase. In addition, the definition of nuclear damage will be expanded to allow a broader range of damage to be compensated, including economic loss and the costs of preventive measures. Following ratification of the Protocol, the NIA will be amended. The Directors believe that the insurance market will have sufficient capacity to offer cover for these liabilities (and are aware that the costs of insurance will increase in line with the increases in liability resulting from the intended amendments to the NIA described above) arising to a nuclear operator and intend to maintain such insurance following implementation of the Restructuring.
Health and safety
Operators of nuclear power stations must comply with the strict limits set out in the IRRs which lay down basic safety standards for the protection of the health of workers and the general public against the dangers arising from ionizing radiation.
Periodic Safety Reviews
The adequacy of the safety case for each power station is confirmed at each statutory outage, at which point the NII reviews the operating performance of the station and the inspection that we have carried out on the plant. Prior to consenting to the nuclear reactor restarting, the NII must be satisfied that there is an adequate safety case for the operation of the plant.
In addition, pursuant to a condition of our nuclear site licenses, a PSR is required at each nuclear power station, at intervals of not more than ten years, to review the safety case taking into account operational history, plant aging and current safety standards. The scope and timing of the PSR is agreed between the NII and the licensee. The nuclear power station’s commercial viability may be significantly eroded if we fail to convince the NII of the adequacy of the safety case.
Once the timing of the PSR is agreed the licensee carries out the review and submits it to the NII. The NII’s expectation from a PSR is that it will receive confirmation that safety structures, systems and components remain fit for purpose insofar as they are able to perform according to original design intent and that modern standards are achieved as far as reasonably practicable. The NII may require additional work to be carried out to demonstrate the adequacy of the safety case for continued operation and the progress of any such work will usually be monitored by the NII on an ongoing basis.
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The first PSR has been completed for each of our AGRs. Sizewell B, the last station to complete a PSR, provided its submission to the NII in December 2003. The NII is expected to complete its assessment of that submission in September 2005 (although generally the NII takes approximately thirteen months to assess our PSRs). For details of the PSR dates for all our stations see the paragraph above headed “Station lifetimes”.
The next PSRs of Hunterston B and Hinkley Point B are planned to be submitted to the NII in December 2005 at which time we will be required to confirm that all the recommendations arising from the previous PSRs of Hunterston B and Hinkley Point B have been implemented. The NII’s decision whether to agree continued operation of each nuclear power station is expected a year or so after these submission dates.
Public safety
Transport
The transport of all radioactive material, both waste and fuel, off site must comply with the Department of Transport requirements under RMRTA and the HSE’s requirements under HSWA and ATCSA. The RMRTA regulates the transport by road of radioactive material. Under these Acts, the Government may regulate the packaging, labeling, consignment, handling, transport, storage and delivery of radioactive packages. The current regulations require certain consignments to be specifically approved by the Secretary of State for Transport.
Security
We operate in a world where we must be vigilant to security threats of all sorts in particular as a result of increased levels of terrorist activity internationally. Our operations are regulated and subject to audit by the Office for Civil Nuclear Security (“OCNS”) which published its initial report after the terrorist attacks on the World Trade Center in New York on September 11, 2001, and must comply with the Nuclear Industries Security Regulations 2003 (the NIS Regulations) which are made under ATCSA and all directions made under that legislation. The OCNS published its latest annual report (“The State of Security in the Civil Nuclear Industry and Effectiveness of Security Regulation April 2003-March 2004”) in July 2004. This report contains recommendations and changes, some of which we will be developing with the OCNS over the coming months, along with other nuclear operating companies to consider the impact of the revised strategy on our security arrangements but it is likely to result in increased security costs.
Our security arrangements are independently reviewed, and we remain confident that our security regime and processes are of a high standard. We have and are further enhancing our security arrangements to meet the increasing UK regulatory requirements and conform with Government guidelines. The reviews cover protective security-related compliance issues as well as compliance with legal requirements. Our security policy and our security risk management audit process are documented and subject to regular internal review and we consider we have effective systems in place to address security issues across a range of areas including personnel recruitment, information technology, physical security and health and safety. We make every effort to ensure that robust security management is achieved.
Emergency arrangements
Emergency arrangements have been established and demonstrated to the satisfaction of the relevant regulators. Each power station has an emergency plan which is approved by the NII and lodged with local emergency services, public libraries and others. Information on emergency arrangements is discussed at local consultative meetings and information is provided to local residents. Each power station has an emergency control center on-site, as well as off-site arrangements for co-ordination with the police, the local authorities, other emergency services and other government agencies. No nuclear emergencies have occurred at any of our sites which have resulted in a release of radioactivity above the authorized level.
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Safety performance
Under the terms of our nuclear site license, all incidents are required to be recorded and investigated and those of significance must be notified to the NII within defined time scales.
To aid public understanding of the safety significance of events at nuclear installations and their consequences, the International Atomic Energy Agency and the Nuclear Energy Agency of the Organization for Economic Co-operation and Development have developed the International Nuclear Event Scale which sets out various levels of incident increasing in seriousness from “0” (i.e. an anomaly with no safety significance) to “7” (i.e. major accident with widespread health and environmental effects) and the criteria relating to each level.
Only events at level 4 and above involve a significant release of radioactivity off-site. There has never been an event at any of our power stations resulting in an exposure to radiation of a person on or off the site above the statutory exposure limits, or the need to consider countermeasures to protect the public off-site. No event has been rated higher than level 2 at our power stations (i.e. an incident with a significant failure in safety provisions but with sufficient defense in depth remaining to cope with additional failures or an event resulting in a radiation dose to a worker in excess of the statutory annual dose limit and/or an event which leads to the presence of significant quantities of radioactivity in the installation in areas not expected by design and which require corrective action).
There has been a reduction in the collective radiation exposure to our workers from 0.12 man Sv/reactor in 2002/2003 to 0.09 man Sv/reactor in 2003/2004. This figure represents approximately one tenth of the worldwide median of the operators contributing to information collated by the World Association of Nuclear Operators (WANO) and places us in the top 10% of performers in this respect.
We maintain an open culture that promotes the reporting of all accidents, including those where no injury actually resulted. The industrial safety accident rate is used to indicate the average number of accidents involving time off work which an individual would be likely to experience in their working lifetime (based on an expected working life of 100,000 hours). In the year to March 31, 2004, our accident frequency rate was 0.53 lost-time accidents per 200,000 man-hours of operation, an increase from 0.46 in the prior year. This ranks unfavorably in comparison to other nuclear operators contributing data in respect of their industrial safety accident rates to WANO.
The Royal Society for the Prevention of Accidents (ROSPA) has recognized our safety performance by awarding all of our eight nuclear stations with Gold Awards for achieving very high standards of safety in 2003/04. Gold Medal Awards were presented to two of our power stations for achieving continued safety performance over the last five years and five of our power stations were awarded the President’s Award for achieving Gold Awards for the last ten consecutive years.
NII safety management audit
In 1998, the Board announced its decision to reorganize the Group and, in particular, our two licensed subsidiaries, BEG and BEG UK, to bring all eight UK nuclear power stations under one licensee, namely BEG. Following this decision, in April and May 1999, the NII carried out a major audit of the safety management arrangements in the central functions that support safety at the licensed sites. The report from this audit was published by the NII in January 2000, and included 103 recommendations to be addressed by both licensees. The NII expressed concern about the ability of BEG and BEG UK to maintain adequate levels of technical support in the future, the extended working time of technical staff, the levels of contractor support being used and the adequacy of the management of change arrangements. The NII confirmed that it was not concerned about the immediate safety of the power stations, but wished to ensure that BEG and BEG UK remained adequate nuclear licensees in the future.
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Since publication of the NII audit report in January 2000, we have worked to develop processes to address the NII’s concerns. Of the 103 recommendations, 80 have been fully cleared and require no further action, one has yet to be cleared (although the way to resolve the issue has been agreed), and 22 are being monitored to confirm that the agreed resolution has been fully carried out. The NII has confirmed that it will review the BEG and BEG UK management of the proposed relocation of technical staff from Peel Park to Barnwood over the next year or so as a test of whether the processes put in place to address the audit findings are working, and will not finally clear the majority of the remaining 22 recommendations until they are satisfied.
WANO
We are a member of WANO which unites operators from more than 420 nuclear power plants in over 30 countries. WANO aims to maximize the safety and reliability of its members’ nuclear power plants. WANO undertakes a program of site evaluations with the intent of reviewing operations at each of our nuclear power stations every two years.
WANO also carries out corporate evaluations where ‘corporate’ means any part of the power plant organization which does not report directly to the station director. These evaluations provide an opportunity for members to learn and share the best worldwide insights into the performance of the corporate organization. WANO has developed over the years a series of Performance Objectives & Criteria (POs&Cs) for operational nuclear power plant, which set the expectations of how the best performing utilities should perform. A subset of the POs&Cs has been developed as the basis for corporate reviews. At our request, WANO carried out a corporate review of BEG and BEG UK in July 2001, which was the first such review outside of North America.
Key findings from the WANO 2001 corporate review
In September 2001 WANO presented the findings of the corporate review and identified five areas for improvement:
| • | the materiel condition and equipment performance of our nuclear stations needed significant improvement as it is adversely impacting the reliability of the stations; |
| • | we need to develop a strong operational focus to ensure sufficient attention to the problems and priorities that affect safe and reliable performance of our nuclear stations; |
| • | the corporate organization needed to be aligned around an integrated strategy with the clear lines of authority and accountability to improve overall performance; |
| • | operating experience information needed to be used effectively by the line organization to prevent the recurrence of operational events; and |
| • | an unambiguous message regarding the overriding importance of nuclear safety needed to be provided throughout the organization. |
June 2003 WANO revisit
In June 2003, a WANO corporate review team returned to BEG and BEG UK to review progress in addressing the five main areas for improvement described above. Since then, we have reformulated our strategic business objectives to address WANO’s concerns and improve our performance. We now focus on what we call the four fundamentals of human performance, equipment reliability, management of work and operational focus together with what we call the foundation areas of training organization and structure, people and leadership and culture change. Our efforts to regain world standards of safety and reliability are being supported by our recently launched performance improvement program described above in the paragraph above headed “Performance Improvement Program”.
Compliance with nuclear regulations
We place great emphasis on the importance of maintaining and continuing to develop a “safety first” culture in addition to complying with regulatory requirements. Our overall organizational structures
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and policies and our safety management arrangements are designed to ensure that legislative requirements and developments are recognized, implemented and monitored through appropriate procedures and practices and that continuous improvements in safety culture and performance are promoted.
Other regulation
Our operations are subject to numerous international, environmental and health and safety laws and regulations governing, amongst other things, the construction, operation and decommissioning of nuclear and coal-fired power stations; discharges to the air, water and land; the use, handling, transport and disposal of radioactive and hazardous substances and wastes; soil and groundwater contamination, and public and employee health and safety.
Waste, emissions and discharges
The Radioactive Substances Act 1993 (“RSA”) governs the disposal of radioactive waste including radioactive discharges. Radioactive gaseous, liquid or solid waste may only be disposed of or moved off the site in accordance with authorizations granted under the RSA. To enable the re-licensing to BEG of the two nuclear stations in Scotland currently licensed to BEG UK under the NIA, it is also necessary for BEG to be granted the RSA authorizations in respect of the two Scottish stations. Applications for these authorizations have been submitted to the Scottish Environment Protection Agency (“SEPA”) and are expected to be granted on a similar timescale to the nuclear site licenses to permit relicensing in 2005.
In England and Wales, the EA regulates nuclear power stations and grants discharge authorizations under the RSA. In Scotland, SEPA regulates under the RSA. We have obtained all necessary consents and authorizations from the EA and SEPA for the disposal of radioactive waste and for non-radioactive discharges from our stations.
Authorizations for disposal of radioactive waste require the operator to use best practicable means to reduce discharges or radioactivity. The operator must in any event comply with the authorized discharge limits set by the EA or SEPA. In England, the EA also sets quarterly notification levels for discharges which are lower than these limits and which, if exceeded, require a formal notification and justification to the EA that best practicable means have been employed. The Energy Act requires EA and SEPA to carry out periodic reviews to the limitations and conditions attached to the authorizations.
The EPA provides for a waste management licensing regime and imposes certain obligations and duties on companies that produce, handle and dispose of non-radioactive waste. Separately, the Integrated Pollution Control (“IPC”) environmental authorization regime introduced in 1991 under the EPA provides an authorization regime for emissions which requires that a power station use the best available techniques (not entailing excessive cost) to minimize the emission of certain pollutants. The IPC is under a staggered process of repeal, to be replaced by a new Integrated Pollution Prevention and Control (IPPC) regime. The IPPC regime will combine the waste management and emission regimes and will impose progressively stricter requirements on power stations. It is expected to be fully implemented by 2007. The regulatory bodies under the new IPPC regime will remain the EA and SEPA.
Consumer information
The EU has recently issued a liberalization directive relating to electricity markets. It includes a requirement for electricity suppliers to provide information on the types of fuel that have been used to produce the electricity, to assist consumers in making informed choices about the environmental
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impact of the electricity they buy. This requirement is imposed by way of a new license condition which will be introduced this autumn, although we have been disclosing fuel mix and other environmental information to customers since 2003.
Environmental performance
Our AGR and PWR Stations
The Centre for Environment, Fisheries and Agriculture Science produces a “Radioactivity in Food and the Environment” report on behalf of the EA, SEPA and the Food Standards Agency which contains radiological monitoring data. The report shows that in 2002 radiation doses to the public resulting from our radioactive discharges to the environment were well below the national and international limits in all parts of the UK.
Both in England and Wales and in Scotland, compliance with radioactive discharge authorizations is assessed through returns made to the relevant regulator and a regular program of site inspections by the regulator.
None of our stations has ever been prosecuted for exceeding any of its authorized discharge limits for the disposal of radioactive waste. However, in January 2003 BEG UK was prosecuted at Haddington Sheriff Court, Scotland relating to the unauthorized discharge of an Active Effluent Discharge Tank in October 2001 at Torness and was fined £15,000 reflecting the fact that: (i) this was the first ever prosecution against BEG UK; (ii) the action it took in reporting and remedying the breach; and (iii) the absence of detriment to the environment.
We have been served with a number of Enforcement Notices from the environmental regulatory authorities requiring improvements to plant and/or processes associated with environmental performance, all of which we have dealt with to the satisfaction of those authorities. In October 2003, the EA wrote to us highlighting a series of incidents and non-compliance that, in its view, indicated a serious shortfall in our compliance with, and understanding of, our environmental permits and environmental legislation. In December 2003, we responded to the EA setting out the actions that we intended to take to resolve the issues raised in their October 2003 letter. We continue to meet with the EA to review our environmental performance.
Eggborough Station and Gale Common
Every year we set environmental objectives and targets for the Eggborough Station and the Gale Common facility. For 2003/04, we set twenty targets related to the key environmental policies set out above in paragraph: “Regulation of the Eggborough Station and Gale Common”, seventeen of which were fully achieved by the end of the period in March 2004. Three of our targets were partially achieved in this period and therefore we will continue to work towards achieving them in the year 2004/05.
The levels of carbon dioxide, oxides of nitrogen, hydrogen chloride and sulphur dioxide emissions recorded in 2003/04 were lower than for each of the last three years. In addition, the level of emission of particulates was lower in 2003/04 compared with 2002/03. We hope to be able to carry out modifications to each unit at the Eggborough Station to help maintain or, even, reduce the rates of NOx emission, in particular, with work anticipated to start next year.
Along with other power station operators in the Aire Valley (the area in which the Eggborough Station is located), we monitor ambient air quality as part of a process agreed with the Environment Agency in order to meet the requirements of our IPC authorization. Results from this monitoring have
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all compared very favorably with the National Air Quality Standards and UK Objective for the protection of human health, both of which are due to come into force in 2005, as well as all the air quality standards currently in place.
We continue to play our part in creating and maintaining bio-diversity at the Eggborough Station and Gale Common through integrated Land Management Plans which we have developed with ADAS (a consultancy and research organization to land-based industries in the UK and abroad and formerly part of the Ministry of Agriculture, Fisheries and Food). The purpose of these plans is to protect and enhance the wildlife in, and conserve the local landscape and historical heritage of, the area in which we conduct our business.
PROPERTY, PLANT AND EQUIPMENT
Our properties consist of power stations and associated land and administrative offices, and various other properties (a small number of which are held pending disposal). We own the freehold (in England and Wales)/feuhold (in Scotland) to each of our eight UK nuclear power stations and one coal fired power station as well as the administrative centers, our corporate headquarters at Peel Park near East Kilbride in Scotland and at Barnwood near Gloucester in England. In connection with the closure of Peel Park we have agreed to take on other office premises in Scotland at Renfrew and Livingston. On September 15, 2004 we announced the proposed sale and partial lease-back of our corporate headquarters building at Peel Park. In addition, we currently lease an office in London. The nuclear power stations are operated under license and subject to regulation. Details of our power stations and offices are set out below:
| Type |
Capacity (MW) |
Location | ||||
| Nuclear Power Stations: |
||||||
| Dungeness B |
AGR | 1,110 | England | |||
| Hartlepool |
AGR | 1,210 | England | |||
| Heysham 1 |
AGR | 1,150 | England | |||
| Heysham 2 |
AGR | 1,250 | England | |||
| Hinkley Point B |
AGR | 1,220 | England | |||
| Hunterston B |
AGR | 1,190 | Scotland | |||
| Sizewell B |
PWR | 1,188 | England | |||
| Torness |
AGR | 1,250 | Scotland | |||
| Coal Fired Power Station: |
||||||
| Eggborough |
— | 2000 | England | |||
| Principal Offices: |
||||||
| Peel Park, East Kilbride |
— | — | Scotland | |||
| Barnwood, Gloucester |
— | — | England | |||
| Sheldon Square, London |
— | — | England | |||
In connection with our privatization in July 1996, we entered into a Property Clawback Deed with the then Secretary of State for Trade and Industry. The Property Clawback Deed provides that in the event of the disposal (or a deemed disposal) of any property in which we had an interest as at March 31, 1996 (other than our power stations), the Government is entitled to 50% of any capital gain realized on the disposal in excess of £400,000 increased in accordance with RPI since April 1, 1996. The Property Clawback Deed will cease to have effect from March 31, 2006.
Under the terms of the Government Facility, we granted a first ranking security to the Government over each of our UK nuclear stations. This security will be released on termination of the Government Facility, implementation of the Restructuring, or EU approval of State Aid. In addition, certain of our
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subsidiaries have granted security over their assets in order to secure the decommissioning default payments and related costs and expenses under the Contribution Agreement pursuant to the DDP Debenture.
On July 2, 2003, we announced proposals to close our current corporate headquarters at Peel Park in East Kilbride. On September 15, 2004 we announced the proposed sale of the Peel Park building to Kenmore Capital East Kilbride Limited in consideration of a cash payment of £6.625 million and a potential additional cash payment of up to £0.25 million if certain letting arrangements come to fruition. We have also entered into a ten year lease for part of the building. It is expected that the sale will be completed in January 2005. As a consequence certain operational posts will be relocated to our Barnwood office, and our headquarters will be transferred to a new location at Alba Campus, Livingston in Scotland. A small number of staff will remain at Peel Park as part of the proposed sale and partial leaseback arrangement. We are currently in the process of consulting with those employees directly affected by these proposals. Our remaining staff who choose not to be re-located to Barnwood will be temporarily relocated to new offices at Renfrew in Scotland and will leave the company once their successors are in place at Barnwood.
As a result of the sale of Peel Park, we have taken a 15 year lease of two floors of an office in Livingston with a ten year break option. We have also agreed to take a 12-24 month lease of one wing of an office in Renfrew and a long lease of a second wing until 2013 with a terminal break option in 2009.
Competition
We compete in the market for electricity supply with the other power stations, including other nuclear power stations, and a number of coal-, oil- and gas-fired power stations. Our major competitors are E.ON UK, RWE Innogy, EDF Energy, Drax Power, Scottish Power, Scottish and Southern Energy and BNFL. In addition, there are a large number of companies that own single power plants. As compared to nuclear power stations, coal-, oil- and gas-fired power stations are able to more easily adjust their output to take advantage of changes in market price, which in some situations may put us at a competitive disadvantage.
There has been some consolidation of supply businesses in recent years. Excluding British Energy, there are only six major suppliers in Great Britain: E.ON (Powergen), RWE Innogy (previously National Power), EDF Energy, Scottish Power, Scottish and Southern Energy and Centrica (British Gas). While we operate exclusively in the industrial and commercial sector, the other major suppliers also compete in the domestic retail sector. Gaz de France has recently entered the supply market and competes in the industrial and commercial sectors.
Legal Proceedings
On February 12, 2004 we received a notice of warranty claims from the consortium which purchased our 82.4% interest in Bruce Power alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce power station.
The claim relating to the condition of the plant is based upon alleged erosion of some of the steam generator 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 net revenues and costs of approximately C$64.5million. 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.
The principal tax claim relates to the treatment of expenditures at the Bruce plant during the period of our ownership that is currently being considered by the Canadian tax authorities. The treatment proposed by us could result in a material tax rebate that has not been recognized in our 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 do not believe that the
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amount of the tax claim should materially exceed the amount of the rebate, and therefore the tax claim should not have a material impact on our cash flow. See Item 3. Risk Factors—“We are involved in several disputes that if resolved or determined against our interests could adversely affect our financial condition.”
Under the Bruce Power sale agreement with the consortium, C$20million was retained in trust to meet any representation and warranty claims. This amount may be retained pending resolution of the claims.
As a result of an accounting adjustment made by Exelon to the value of nuclear fuel contained in AmerGen’s balance sheet dated December 21, 2003 we may be required to make a payment to Exelon of up to US$13.7 million. We dispute such claim and served a dispute notice on Exelon on June 4, 2004 to preserve our rights under the sale agreement. The agreement with Exelon for the sale of AmerGen requires that, prior to instituting any litigation or other dispute resolution procedure, the companies will in good faith seek to resolve any dispute. Furthermore, we are reviewing with Exelon the effect on the working capital adjustment resulting from a change to the estimated tax recoverable for prior periods made after the consummation of the sale, and this, if agreed, may result in a reduction in the purchase price payable by Exelon, with the reduction currently estimated to be in the range of up to US$6.3 million.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
You should read the following information together with our audited consolidated financial statements and the related notes included herein beginning on page F-1. Further information on the basis of preparation are included in note 1 to our audited consolidated financial statements. The following discussion and analysis is based on our audited consolidated financial statements, which have been prepared in accordance with UK GAAP. UK GAAP differs in a number of significant respects from US GAAP. You can find a description of the differences between UK GAAP and US GAAP relevant to our audited consolidated financial statements and reconciliations of profit/(loss) after tax (or net income/(loss)) and deficit on equity shareholders’ funds in note 36 (as restated) to our audited consolidated financial statements.
Our financial statements have been prepared on the basis that we are a going concern. The going concern basis assumes that we will continue in operational existence for the foreseeable future. The validity of this assumption depends upon a number of factors that are beyond our control, including those discussed above. If for any reason we are unable to complete our proposed restructuring and cease to be a going concern, we may be required to adjust the monetary value of assets, reassess our provisions for future liabilities and reclassify fixed assets and long-term liabilities as current assets and liabilities. Such adjustments, reassessments and reclassifications may result in a material adverse change to the statement of our financial condition from that currently set forth in our financial statements. For further information, see note 1 to our audited consolidated financial statements.
Overview of the Group
Our principal activity is the generation, sale and trading of electricity. We are the UK’s (which comprises Great Britain and Northern Ireland) largest generator of electricity, producing over one fifth of the UK’s electricity and employing approximately 5,100 staff. We own and operate eight nuclear power stations and one coal-fired power station in the UK. Of our nuclear power stations, seven are AGRs (Dungeness B, Hartlepool, Heysham 1, Heysham 2, Hunterston B, Hinkley Point B and Torness) and the eighth (Sizewell B) is our sole PWR. Our nuclear power stations have a combined capacity of approximately 9,600 MW. Eggborough power station has output capacity of 1,970 MW. During the year ended March 31, 2004, our power stations produced total output of 72.6 TWh, which was comprised of output of 65.0 TWh from our nuclear power stations and 7.6 TWh from the Eggborough power station.
During the periods under review, we made two significant divestitures: in February 2003, we disposed of our majority interest in Bruce Power, which operates the Bruce nuclear power station in Canada and in December 2003, we sold our 50 per cent. interest in AmerGen, a joint venture which operates three nuclear power stations in the United States.
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We generated turnover of £1,516 million during the year ended March 31, 2004 resulting in operating profits of £57 million before exceptional operating credits of £283 million. During the year ended March 31, 2003, we generated turnover of £1,903 million of which £1,528 million was from continuing activities and resulted in operating profits from continuing activities of £7 million before exceptional operating costs of £3,906 million. Operating profits from continuing activities after exceptional operating credits were £340 million during the year ended March 31, 2004 as compared with an operating loss from continuing activities after exceptional operating costs of £3,802 million during the year ended March 31, 2003.
The Restructuring
We are currently in the process of a major financial restructuring. In October 2003, we announced that we had agreed to the terms of the Restructuring. Completion of the Restructuring remains subject to the satisfaction of a number of important conditions. If the Restructuring is completed, our Creditors will have agreed to compromise at least £1,199 million in debt and other obligations. The Restructuring involves the Bondholders the Eggborough Banks, RBS and the significant Creditors compromising their claims against the British Energy Group pursuant to the Creditors’ Scheme and other arrangements under the Creditor Restructuring Agreement in exchange for, among other things, £275 million of New Bonds to be issued by British Energy Holdings plc as well as at least 97.5 per cent. of the new shares of the New British Energy.
In addition the Significant Creditors will extinguish all and the Eggborough Banks will extinguish part of, their existing claims against the Group pursuant to the various arrangements under the Creditor Restructuring Agreement.
Furthermore, the Eggborough Banks will compromise their secured claims in exchange for a right to payments having a payment profile equivalent to £150 million of New Bonds and option to acquire the Eggborough power station in 2010 for a one-time payment of £104 million and the extinguishment of the then £83 million of outstanding payments due at that time.
Under the Government Restructuring Agreement entered into in connection with the Restructuring and which sets out new arrangements with the Secretary of State, the existing NDF will be enlarged and renamed the NLF which will fund qualifying uncontracted nuclear liabilities and the qualifying costs of decommissioning our nuclear power stations. The Secretary of State will fund: (i) qualifying uncontracted nuclear liabilities and qualifying costs of decommissioning of the Group’s nuclear power stations to the extent they exceed the assets of the NLF; and (ii) subject to certain exceptions, contracted liabilities for historic fuel. The New British Energy Group will be responsible for funding certain excluded or disqualified liabilities and will be, in certain circumstances, required to compensate or indemnify the NLF and the Government in relation to such liabilities. The excluded liabilities include, among others, employment and redundancy costs, certain environmental expenses, liabilities other than nuclear liabilities and liabilities. These excluded and disqualified liabilities include, amongst others, costs incurred as a result of our failure to operate in accordance with a minimum performance standard or introduction of certain operational changes at our nuclear power stations. In consideration for assuming these liabilities, Holdings plc will issue £275 million in New Bonds to the NLF and the New British Energy Group will make various payments to the NLF including an annual contribution equal to (initially and subject to adjustment but no to exceed) 65 per cent. of New British Energy’s adjusted net cash flow (the NLF Cash Sweep Payment). The NLF may, at its option, convert the NLF Cash Sweep Payment into Convertible Shares. The terms of the Convertible Shares will limit the general voting rights attaching to such shares, whilst held by the NLF, to the maximum amount which can be held by the NLF (and its concert parties) without triggering a mandatory offer under the Takeover Code, being currently 29.9 per cent.
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For further information about the Restructuring, the NLF and the related agreements see “Item 4. Information on the Company—Restructuring.” However, there can be no assurance that we will complete the Restructuring. For further information about the risks related to the Restructuring, the NLF and related agreements, see “Item 3. Risk Factors—Risks relating to completion of the Restructuring.”
Critical Accounting Policies
UK GAAP requires our Directors to adopt those accounting policies which are most appropriate for the purpose of the preparation of the accounts. In preparing the accounts in conformity with UK GAAP, the Directors are required to make estimates and assumptions which impact on the reported amounts of revenues, expenses, assets and liabilities. Actual results may differ from these estimates. Certain of our accounting policies have been identified as the most critical accounting policies by considering which policies involve particularly complex or subjective decisions or assessments and these are discussed below.
Going concern
Our audited consolidated financial statements have been prepared on a going concern basis because our Directors are currently seeking an alternative to liquidation or ceasing trading operations. The going concern basis assumes that we will continue in operational existence for the foreseeable future. The validity of this assumption is dependent on completion of the Restructuring.
If the remaining conditions and approvals to the Restructuring are not satisfied, we may no longer be considered to be operating as a going concern. Some of the conditions required to implement the Restructuring are beyond our control, such as Court approval of the Schemes. If for any reason we are unable to complete the Restructuring and cease to be a going concern, adjustments may have to be made to reduce the monetary values of our assets to their recoverable amounts, to provide for further liabilities that might arise and to reclassify our fixed assets and long-term liabilities as current assets and liabilities.
Nuclear liabilities and decommissioning
Our nuclear liabilities principally relate to the cost of reprocessing and storage of nuclear fuel and storage and disposal of nuclear waste, collectively known as back-end fuel costs and the cost of defuelling our reactors and decommissioning our nuclear power stations.
In accordance with UK GAAP, back-end fuel costs are recognized in each year’s financial statements in proportion to the amount of fuel consumed. However, because these costs will not be incurred for many years the estimated costs (expressed in current prices) are discounted at 3 per cent. per annum from their estimated payment dates. The discounted back-end fuel cost is recognized when the related fuel is consumed. The 3 per cent. discount rate reflects average assumed long-term investment returns. More than 80 per cent. of AGR back-end fuel costs (on a discounted basis) are covered by contractual arrangements with BNFL, all of which include fixed price terms subject to indexation. Liabilities for PWR back-end fuel costs are based on cost estimates derived from the latest technical estimates.
In accordance with UK GAAP, the estimated costs of decommissioning our nuclear power stations are provided for when the nuclear power stations begin operating commercially, and are capitalized as part of the cost of construction and depreciated over the same lives as the stations. The estimated costs of decommissioning are discounted to reflect the timescale before and during which the work will take place (following closure of the power station). We anticipate that after defueling the reactors, dismantling the reactors will not be possible for at least 50, and up to 135 years, after the closure of the relevant nuclear power station.
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As at March 31, 2004, our total undiscounted expected future payments in respect of nuclear liabilities, stated at current values, were £15.0 billion. This amount takes into account all costs associated with fuel consumed in the past, estimated fuel to be consumed in the future and decommissioning. Discounted at 3% per annum from the estimated eventual payment dates, this amount was £5.7 billion as at March 31, 2004, of which £4.2 billion had been accrued. The difference between the total discounted nuclear liabilities and the amount accrued as at March 31, 2004, represents the estimated discounted back-end fuel cycle costs associated with fuel to be consumed in the future.
The actual liability for decommissioning may vary significantly from our estimate, and as a result, the liabilities we report in our results may vary significantly if our assessment of these costs changes. Many of the factors that are integral to the determination of our estimate, such as governmental regulations and inflation, are beyond our control.
Fixed assets and depreciation
Fixed assets (other than assets in the course of construction) are stated in the balance sheet at cost less accumulated depreciation. Accumulated depreciation includes additional charges made where necessary to reflect impairment in value. Assets in the course of construction are stated at cost and are not depreciated until brought into commission.
The charge for depreciation of fixed assets is based on the straight line method so as to write off the costs of assets, after taking into account provisions for diminution in value, over their estimated useful lives.
The carrying values of fixed assets are reviewed for impairment where there has been a trigger event by assessing the preset value of estimated future cash flows and net realizable value compared with net book value. The calculation of estimated future cash flows is based on the Directors’ best estimates of future prices, output and costs and is therefore subjective.
Impairment of fixed assets
We undertook a review of the carrying value of our fixed assets compared with the economic value and net realizable value of those assets. In carrying out the economic valuations, significant estimates are made of the future cash flows being generated by the assets, taking into account current and expected future market conditions and the expected lives of our power stations. The assessment of future market conditions includes, for example, a view of likely overcapacity in the market over a number of years and the likely timing of the market returning to new entrant prices. The actual outcome can vary significantly from our forecasts, thereby affecting our assessment of expected future cash flows. The expected future cash flows are discounted at a rate approximating to our weighted average cost of capital as this is the rate most representative of those assets. The impairment review has resulted in the value of our power stations being written up by £295 million for UK GAAP during the year ended March 31, 2004.
Station accounting lives
Accounting lifetimes of our nuclear power stations reflect our current assessment of potential life limiting technical factors and independent engineering assessments. The operating lifetime of a nuclear power station is limited principally by the lifetime of items which are uneconomical to replace such as the graphite core, the boiler (in AGRs) and other components inside the reactor pressure vessel. The methodologies and technology used to evaluate the expected lifetimes of nuclear stations are dynamic, resulting in progressively improved measurement capabilities that allow us to determine whether the safety case for an extended accounting life of a nuclear power station can be supported. The estimates of station accounting lives are therefore subjective. The extension of a station’s life may improve our results, in light of the incremental income and the largely fixed cost base. We have not considered it appropriate to extend the accounting lives of any of our power stations in the financial year ended March 31, 2004.
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The Decommissioning Fund
We make contributions into an independently administered fund to cover all costs of decommissioning our nuclear power stations, except de-fuelling costs. Our annual contributions to the fund are determined by qualified actuaries, taking into account the amount and timing and expected decommissioning costs and the periods until station closures. The value of the asset in the balance sheet represents our contributions to the Nuclear Decommissioning Fund (the “Decommissioning Fund”), together with an estimated actuarially determined long-term rate of return on the Decommissioning Fund. The change in value arising from applying the estimated long-term rate of return is taken to the profit and loss account and disclosed as part of revalorization.
The revalorization of the Decommissioning Fund, which has been taken through the profit and loss account, is not a realized profit for the purposes of the Companies Act 1985 because the income is unrealized until we receive the related cash from the Decommissioning Fund to reimburse decommissioning expenditures. The inclusion of this profit in the profit and loss account is a departure from the requirements of the Companies Act 1985. Revalorization of the accrued decommissioning provision is charged to the profit and loss account each year and accordingly, we believe it is necessary to include the estimated annual long-term rate of return of the Decommissioning Fund in our profit and loss account in order for the financial statements to give a true and fair view. In the event that the net realizable value as indicated by the market value of the Decommissioning Fund is lower than the value determined under the accounting policy set out above, we have included the lower value in our accounts.
Onerous contracts
Following the introduction of NETA and the renegotiation of certain contracts, a number of our electricity trading contracts no longer hedge our physical output. As the status of these contracts changed under UK GAAP, a provision was made for the “out of market” element of the contracts under FRS 12. In arriving at the provision, the terms of the contract are considered along with our estimate of the expected future electricity prices over the period of the contracts. The financial statements for the year ended March 31, 2004 reflect the claim amounts for these contracts which have been agreed in principle for the purpose of the Restructuring.
Deferred Taxation
Following the implementation of FRS 19, Deferred Taxation, we discount our full deferred tax liability. FRS 19 allows a company the choice as to whether or not to discount its deferred tax liability. We implemented FRS 19 on a discounted basis in the financial year ended March 31, 2002 as we consider that this is necessary in order to present all our long term liabilities on a consistent basis. The implementation of FRS 19 resulted in an adverse adjustment to reserves and net assets of £130 million in our consolidated financial statements for the year ended March 31, 2002.
As at March 31, 2004, we had an unrecognized deferred taxation asset of £375m (£291m discounted) which was not recognized due to uncertainty over the level of future taxable profits. It is our policy to recognize deferred taxation assets when we consider that it is more likely than not that there will be suitable taxable profits from which the future reversal of the underlying timing differences can be deducted.
Factors Affecting our Results of Operations
Our results of operations during the periods under review were affected by operational and other factors. Operational factors include changes in plant output, achieved electricity prices, operating costs and capital expenditures. Other factors that affected our results of operations include the impact of accounting for discontinued operations and revalorization charges. Our results of operations during the year ended March 31, 2004 have been affected by the implementation of the new BNFL contracts and the standstill arrangements with BNFL. Furthermore, results of operations during the periods under
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review were also affected by a change in the manner in which we accounted for turnover and certain operating costs to reflect the new trading arrangements in England and Wales as a result of NETA. Each of these factors is discussed below.
Operational factors affecting our results of operations
Nuclear output. The electrical output that our nuclear stations can achieve is affected by a number of factors, including plant operating conditions and strategy, and the frequency and duration of outages. The principal factor affecting our nuclear output for any given period is the number and duration of outages. The table set forth below shows our nuclear output from continuing operations for the periods under review:
| Output | Year ended March 31, |
Variance |
||||||||||
| 2004 |
2003 |
2002 |
2003-2004 |
2003-2002 |
||||||||
| (in TWh) | ||||||||||||
| Nuclear output |
65.0 | 63.8 | 67.6 | 1.9 | % | (5.6 | )% | |||||
The nuclear regulatory regime in the UK requires each nuclear power station to be shut down periodically for maintenance and inspection as a condition of that power station’s nuclear site licence. We refer to such a shut down as a “statutory outage”. Certain of our nuclear power stations must also be shut down to allow for refueling, which we refer to as a “refueling outage”. Nuclear power stations must also be shut down for maintenance and testing or to address an unplanned technical malfunction or engineering failure, which we refer to as “unplanned outages”.
Our level of unplanned outages in recent years has significantly affected our operating and financial performance. Nuclear output for both the years ended March 31, 2003 and 2004 was adversely affected by a number of unplanned outages. In particular, we experienced unplanned outages at both reactors at Heysham 1 in 2004. We estimate that this loss of output at Heysham 1 equated to approximately £71 million in lost profits after considering imbalance costs and associated fuel savings. Since 2002, the proportion of unplanned outages arising from incidents other than major plant failures has gradually increased during the periods under review. To date these unplanned outages have been caused by a variety of technical issues, the most significant of which are: problems with our refueling equipment and processes; turbine-generators; tendons; boilers; boiler feed pumps; gas circulators (which are used to pump carbon dioxide coolant gas around the reactor core); and the seawater coolant system. We believe that the loss of output arising from these outages is indicative of a deterioration in the materiel condition of our plant over time, caused by: (i) inadequate investment when compared with international benchmarks for spending at nuclear power stations (of the order of approximately £45 million per annum across the fleet over each of the last 5 years); (ii) by a failure to perform required maintenance on a timely basis; and (iii) human errors in the operation and maintenance of our plant including conducting our operations and maintenance functions on a station by station rather than fleet wide basis. This conclusion is consistent with the findings of the World Association of Nuclear Operators (WANO) corporate review carried out in 2001.
The table set forth below shows the aggregate loss of output, in terawatt-hours, associated with our statutory, refueling and other outages during the periods indicated.
| Outages | Year ended March 31, |
Variance |
||||||||||
| 2004 |
2003 |
2002 |
2003-2004 |
2003-2002 |
||||||||
| (in TWh) | ||||||||||||
| Statutory |
4.9 | 5.9 | 2.8 | (16.9 | )% | 110.7 | % | |||||
| Refueling |
2.9 | 3.0 | 3.9 | (3.3 | )% | (23.1 | )% | |||||
| Others |
10.7 | 10.6 | 9.1 | 0.9 | % | 16.5 | % | |||||
| TOTAL |
18.5 | 19.5 | 15.8 | (5.1 | )% | 23.4 | % | |||||
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In recent years, we have sought to reduce the impact of refueling outages through the introduction of low power on-load refueling (that is, refueling while the reactor is still on) at four of our seven AGR stations as well as scheduling refueling outages to coincide with statutory outages. (PWRs are not designed to refuel on-load and must be shut down for refueling.) We have reached an agreement with the NII which has allowed us to extend the period between statutory outages at all of our AGR stations to three years and to extend the period between statutory outages to 18 months in the case of our PWR power station. We seek to reduce the impact of statutory outages on revenue by timing such outages to occur during periods of lower demand for electricity when prices are lower (generally between March and October.) We also seek to reduce the duration of any statutory outages by improving the efficiency with which we conduct the required program of work.
Coal output. Output from the Eggborough Station for the periods under review was as follows:
| Coal Output | Year ended March 31, |
Variance |
||||||||||
| 2004 |
2003 |
2002 |
2003-2004 |
2003-2002 |
||||||||
| (in TWh) | ||||||||||||
| Total output |
7.6 | 5.7 | 7.1 | 33.3 | % | (19.7 | )% | |||||
The Eggborough power station is operated at various output levels rather than at constant levels in the manner of our nuclear stations. We operate the Eggborough power station principally to take advantage of favorable electricity prices, to generate additional power during unplanned outages at our nuclear power stations and to change output in response to changing requirements. As such, prevailing electricity prices, our contracted trading position and unplanned outages at our nuclear plants are the primary factors driving our total output for each of the periods under review.
Electricity Prices
Our realized price for electricity is critical to our profitability. During the year ended March 31, 2004, our realized price, which is calculated by dividing total UK turnover (net of energy supply costs and miscellaneous and exceptional income) by total output during the period, was £16.9/MWh. The average forward price for baseload power which we consider to represent a “market price” for wholesale electricity sales for 2003/2004 delivery was £16.7/MWh. During the year ended March 31, 2003, our realized price was £18.3/MWh as compared with a market price of £18.6/MWh. The difference between our realized price and the market price primarily reflects the impact of fixed price contracts on turnover during a period when wholesale electricity prices were rising. However, while these contracts reduce our exposure to potential falls in market prices, it also means that we are not able to fully benefit from rising electricity prices and vice versa should prices fall. We currently have forward contracts in place for volume equivalent to virtually all our planned output for the year ended March 31, 2005. The large majority of these forward sales contracts are fixed price contracts and in mid September 2004 were at an average price of £20.8/MWh for 2004/2005 delivery. As at March 31, 2004, the forward price for baseload power for 2004/2005 delivery was approximately £20.3/MWh. As a result of these contracts, our realized price for electricity may differ from the average market price for the year.
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Our realized price for the years ended March 31, 2002 and 2003 also reflects the effect of several changes to the manner in which we account for turnover and certain operating costs as a result of the introduction of new trading arrangements brought about by the commencement of NETA. On a comparable basis, adjusted to reflect the trading arrangements in place prior to the commencement of NETA, our realized price for the periods under review were as follows:
| Year ended March 31, |
||||||||||
| 2004 |
2003 |
2002 |
||||||||
| Realized Price |
£ | 16.9/MWh | £ | 18.3/MWh | £ | 20.4/MWh | ||||
| Market Price(1) |
£ | 16.7/MWh | £ | 18.6/MWh | (2 | ) | ||||
| (1) | The Market Price quoted is the average of the mid-point of the closing prices for annual baseload contracts during the year prior to delivery as reported on European Daily Electricity Markets, published by Heren Energy. |
| (2) | An equivalent market price for contracts traded in 2001/02 is not available because of limited liquidity immediately before the introduction of NETA on March 27, 2001. |
Operating costs
In general, the operation of nuclear power stations is characterized by high fixed costs. Fixed costs include costs of decommissioning our power stations and other costs that are unique to the nuclear power generation industry. Fuel costs represent our most significant operating cost and reflect not only the amount of fuel burnt during the period (based on total output) and the efficiency of our fuel utilization (the percentage of nuclear fuel used before it is removed from the reactor) but also including the cost of reprocessing and storage of spent fuel and storage and disposal of nuclear waste, collectively referred to as back-end fuel costs.
New BNFL Contracts
On March 31, 2003 and May 16, 2003 respectively, we exchanged contracts covering front-end and back-end fuel services, which give effect to the non-binding heads of terms which we entered into with BNFL on November 28, 2002. The revised and amended front-end and back-end fuel contracts that have been agreed with BNFL provide that amounts paid to BNFL will reflect changes to wholesale electricity prices within certain agreed parameters, thereby partially hedging our fuel costs against market price movements. The revised front-end contracts became effective on April 1, 2003 but (except in relation to the supply of uranics by BNFL to BEG until March 31, 2006) may be terminated if the Restructuring is not completed. The new front-end post-2006 contracts are conditional on completion of the Restructuring. The amendments to existing back-end contracts and the new contracts are conditional on completion of the Restructuring but, under the terms of the standstill agreement, pending formal implementation of the new back-end contracts, our payments to BNFL for back-end fuel services are being made as if the new back-end contracts had become effective on April 1, 2003.
The profit and loss account for the year ended March 31, 2004 was prepared on the basis of the existing BNFL contracts in respect of back-end fuel costs, pending satisfaction of the BNFL Conditions. The accounting treatment has taken this approach, as this element of the Restructuring will have a retrospective impact. Consequently, our results of operations for the year ended March 31, 2004 do not reflect the profit and loss account savings that will arise under the New BNFL Contracts, which we estimate would have amounted to £58 million for the year ended March 31, 2004. This amount will be recognised on the completion of the Restructuring, together with other restructuring adjustments. The saving has been calculated using an average electricity price, as defined in the New BNFL Contracts, of £17.6/MWh.
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As noted above and as part of the standstill arrangements, we have made payments during the year ended March 31, 2004 to BNFL as if the revised BNFL contracts were in place. The difference in the cash payments, taken together with the profit and loss account savings under the revised contracts means that included within current liabilities are amounts due to BNFL which will never be paid by us, provided the Restructuring is completed. These amounts totalled £306 million as at March 31, 2004 and £113 million as at March 31, 2003.
Capital Expenditures
Following the substantial write down of our fixed asset carrying values of our nuclear power stations as at March 31, 2003, it has not been possible to demonstrate that expenditure of a capital nature has enhanced the value of our fixed assets. Accordingly, the cost of non-recurring expenditures as well as expenditures on strategic spares during the year ended March 31, 2004 has been recognized as an operating cost in our profit and loss account. We estimate that, of the total investment on power stations of £92 million during the year ended March 31, 2004, £70 million would have been capitalized as a capital expenditure but for the impairment review. The principal determining factor in the recommencement in capital expenditures will be a demonstrable and sustainable improvement in reliability of output. There is no certainty as to when this will occur and the accounting treatment for the future expenditure will be assessed when it is incurred.
Non-operational factors affecting our results of operations
Revalorization
In each fiscal year during the periods under review, we recompute our back-end fuel costs and decommissioning costs to reflect the impact of inflation during the year and to remove the effect of one year’s discount to the estimated costs of decommissioning (which is capitalized at the commencement of commercial operation of a nuclear power station and depreciated over the life of the station as the estimated payment date moves a year closer). These two effects combined, known as “revalorization,” are accounted for as part of the financing charge in our profit and loss account. The charge in respect of the revalorization of decommissioning liabilities is partially offset by a credit in respect of the actuarially determined value of the NDF on an assumed long-term real rate of return of 3 per cent. on investments. The amount of the revalorization charge in any given year will be affected, principally, by the rate of inflation in the UK. For the periods under review, the rate of inflation has fluctuated from 1.7 per cent. in 2002 to 2.6 per cent. in 2004.
The benefit under the revised BNFL back end contracts to the date of Restructuring will be recognized in the balance sheet upon implementation of the Restructuring together with other Restructuring related adjustments. The ultimate benefit recognized will depend on a number of factors including the date of Restructuring, the market price of electricity between April 1, 2004 and the date of Restructuring as defined in the contract and the amount of fuel used.
Discontinued Operations
During the periods under review, we disposed of our interests in Bruce Power, our Canadian operations, and of our interest in AmerGen, a joint venture in the United States. The results of operations of Bruce Power and the share of joint venture turnover from AmerGen during the periods under review are recognized as discontinued operations.
Disposal of Bruce Power
In May 2001, our 82.4% owned Canadian subsidiary, Bruce Power Limited Partnership (“Bruce Power”), leased the two nuclear power stations at the Bruce nuclear site in Canada from the Ontario Provincial Government (OPG). In the period of April 1, 2002 to February 14, 2003, Bruce Power generated 19.2 TWh and made an operating profit contribution before minority interest of £97 million.
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On February 14, 2003 we sold our entire interest in Bruce Power to a consortium consisting of Cameco Corporation (an existing partner in Bruce Power), BPC Generation Infrastructure and TransCanada Pipelines Limited. At completion of the disposal, we received initial consideration of C$627 million after minor closing adjustments, and a payment of C$51 million in recognition of our earlier capital contributions paid to Bruce Power. On April 28, 2003, we announced that we had received a further C$20 million that had been retained upon completion of the sale for a possible price adjustment relating to pensions following confirmation that no such adjustment was required within specified time periods.
In addition to the consideration received at the time of the disposal of our interest in Bruce Power, we are entitled to receive up to C$100 million, contingent on the restart of Units 3 and 4 at the Bruce plant within specified time periods. On March 22, 2004 we received C$20 million for the restart of Unit 4 and on May 25, 2004 we received a further C$10 million in respect of the restart of Unit 3. While discussions are continuing with OPG regarding the release of further amounts, if any, the total amount that may be released will be substantially less than C$100 million.
Pursuant to the terms of the sale of Bruce Power, a further C$20 million was retained as security against any representation and warranty claims. On February 12, 2004 we received a notice of warranty claims from the purchasers alleging breach of certain warranties and representations related to tax matters and the condition of the Bruce Power station. We expect that the C$20 million will remain in trust pending resolution of the dispute. For additional information regarding these claims, see “Item 4. Information on the Company—Legal Proceedings.”
Disposal of AmerGen
On December 23, 2003 we announced the completion of the disposal of our 50% interest in AmerGen to Exelon, our equal joint venture partner in AmerGen. AmerGen operates three nuclear power stations in the United States. AmerGen contributed an operating profit of £43 million during the year ended March 31, 2003 and £21 million during the year ended March 31, 2004.
At closing, consideration of approximately US$277 million was received prior to adjustments relating to working capital levels, unspent nuclear fuel, inventory, capital expenditures and low-level waste disposal costs which were to be determined as at the time of closing. Finalisation of these adjustments is still outstanding. Approximately £94 million of the consideration was used to pay down outstanding amounts under the Government Facility and the balance was used to fund ongoing working capital requirements.
Prior to the disposal of our interest in AmerGen to Exelon, we entered into a conditional agreement to dispose of our interest in AmerGen to the FPL Group Inc. (“FPL”) subject to Exelon’s right of first refusal to purchase our interest on the same terms and conditions as those offered by FPL. Exelon exercised its right of first refusal and, as a result the original agreement with FPL terminated on October 13, 2003. As a consequence on December 24, 2003 we paid a break fee of US$8.3 million to FPL.
In connection with the disposal of our interest in AmerGen, we gave certain indemnities and guarantees. As a result of an accounting adjustment made by Exelon to the value of nuclear fuel contained in AmerGen’s balance sheet dated December 21, 2003, we may be required to pay Exelon up to US$13.7 million. We dispute the claim and served a dispute notice on Exelon on June 4, 2004 to preserve our rights. Furthermore, we are reviewing with Exelon the effect on the working capital adjustment resulting from a change to the estimated tax recoverable for prior periods made after the consummation of the sale, and this, if agreed, may result in a reduction in the purchase price payable by Exelon, with the reduction currently estimated to be in the range of up to US$6.3 million.
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For additional information, see Item 3. Risk Factors.
Exceptional operating and financing items
During the three years ended March 31, 2004, our financial results have been significantly impacted by a number of exceptional operating and financing items. The table below summarizes the impact of exceptional operating and financing items (before tax) for each of the three prior fiscal years.
| Year ended March 31, |
|||||||||
| 2004 |
2003 |
2002 |
|||||||
| (pounds in millions) | |||||||||
| Reversal of write-down/(write-down) of fixed asset carrying values |
295 | (3,738 | ) | (300 | ) | ||||
| UK decommissioning fund credit/(charge) |
13 | (13 | ) | — | |||||
| Write-down of own shares held |
— | (102 | ) | — | |||||
| Provision for slow moving stocks |
— | (57 | ) | — | |||||
| Restructuring costs |
(43 | ) | (35 | ) | — | ||||
| Onerous trading contracts |
— | (2 | ) | (209 | ) | ||||
| Siemens settlement |
18 | — | — | ||||||
| Nuclear Energy Agreement |
— | 41 | — | ||||||
| Exceptional costs in respect of shares issued to the British Energy Qualifying Share Trust to meet options granted to employees under the Sharesave Scheme |
— | — | (3 | ) | |||||
| Exceptional items included within operating results |
283 | (3,906 | ) | (512 | ) | ||||
| UK/AmerGen decommissioning fund credit/(charge) |
68 | (159 | ) | (27 | ) | ||||
| Credit/(charge) for interest rate swap provision |
5 | (56 | ) | — | |||||
| Write-off of capitalized borrowing costs |
— | (6 | ) | — | |||||
| Exceptional items included within financing costs |
73 | (221 | ) | (27 | ) | ||||
| Exceptional gain/(loss) on sale of joint venture and businesses |
47 | (35 | ) | 4 | |||||
| Total net exceptional credits/(charges) |
403 | (4,162 | ) | (535 | ) | ||||
We recognized net exceptional operating and financial credits of £403 million for the year ended March 31, 2004, and net exceptional operating and financial charges of £4,162 million for the year ended March 31, 2003 and £535 million for the year ended March 31, 2002. These exceptional items were comprised of:
For the Year ended March 31, 2004
| • | An exceptional credit of £295 million following the review of the carrying value of our fixed assets to reflect the partial reversal of previous impairment losses. At March 31, 2004, we reassessed the fixed asset carrying values of our nuclear power stations, determined that revisions to the impairment of their fixed asset carrying values were appropriate principally due to an expectation of higher electricity prices. The carrying value of our nuclear stations was calculated by discounting the expected future cash flows from the continued use of the assets. |
| • | An exceptional charge of £43 million relating to advisory fees and other costs associated with the Restructuring. |
| • | An exceptional credit of £18 million from the settlement of a dispute with Siemens Power Generation Limited in connection with work carried out relating to the design and manufacture of turbines at Heysham 2. |
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| • | The total Decommissioning Fund and AmerGen decommissioning fund exceptional credits of £81 million (Decommissioning Fund: £13 million; AmerGen: 68 million) as explained below: |
| • | At March 31, 2004 the market value of the Decommissioning Fund had increased to £440 million compared with £334 million for the year ended March 31, 2003 thereby necessitating an exceptional credit of £59 million for the year ended March 31, 2004. The £59 million included a £13 million exceptional credit to reverse the write-down on non-operational assets made in the year ended March 31, 2003. The remaining balance of the restatement to market value of £46 million has been dealt with as an exceptional financing credit to reverse previously written-down revalorization amounts. The total of the Decommissioning Fund exceptional revaluation charge amounted to £159 million. |
| • | The market value of the AmerGen decommissioning fund had also increased and our share of the exceptional credit was £22 million in the year ended March 31, 2004. |
| • | An exceptional credit of £47 million related to the gain on the sale of our investments in Bruce Power, AmerGen and Offshore Wind. |
| • | At March 31, 2004 the value of interest rate swaps were marked to market and the resultant valuation was lower than the book value. The exceptional credit is £5 million for the year ended March 31, 2004. |
For the Year ended March 31, 2003
| • | An exceptional charge of £3,738 million (which has now been reversed in part) resulted from the write-down of our fixed assets. This is explained below: |
| • | The carrying value of the nuclear stations was calculated by discounting the expected future cash flows from continued use of the assets, having made appropriate assumptions regarding future operating performance, including in relation to electricity price assumptions. The valuation of the Eggborough power station was based on an assessment of net realizable value. |
| • | The electricity price assumptions were a significant component of the asset value calculation. We considered the market’s views on future prices of wholesale electricity and also specifically commissioned, and commercially available forecasts. We considered the potential for rationalization of generation capacity in the UK and the potential effect on the market of changes in Government policy on renewables generation and of any potential changes to that policy. In determining the price assumptions, we also took account of the effect on the market as a result of the dramatic fall in prices over the two years ended March 31, 2003 and took a cautious view on there being a significant recovery in prices. |
| • | At March 31, 2003 the market value of the Decommissioning Fund at £334 million was lower than the value of £458 million that would have been derived from revalorizing the amounts contributed. As a result an exceptional charge of £124 million was recognized to record the fund at market value of which £111 million relates to the write-off of previous revalorization and £13 million has been classified as a write-off of non-operational assets. |
| • | The market value of the AmerGen decommissioning fund was also lower than the value that would have been derived from revalorizing the amounts contributed. Our share of the adjustment required to restate the value of the fund to market value is £48 million, all of which relates to previous revalorization. |
| • | The total of the Decommissioning Fund exceptional revalorization charges amounted to £159 million. |
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| • | An exceptional charge of £102 million related to the write-down in value of our shares held in trust to satisfy employee share options. The shares were written down to £2 million to reflect market value compared to a book value of £104 million, based on market prices of 3.75p and 3.0p for our Ordinary Shares and “A” Shares respectively. |
| • | An exceptional charge of £57 million related to a provision for slow-moving and obsolete stocks. |
| • | An exceptional charge of £56 million related to interest swap provisions in respect of interest rate swap contracts which are no longer effective as hedges. |
| • | An exceptional charge of £35 million related to advisory and other costs associated with the Restructuring. |
| • | An exceptional charge of £35 million related to a loss on our disposal of Bruce Power and Huron Wind. The calculation of the loss on disposal incorporates receipt of the C$20 million retention relating to pensions. |
| • | An exceptional charge of £6 million related to borrowings that are now part of the Restructuring. These costs had been capitalized and were being amortized over the duration of the borrowings. |
| • | A £2 million charge when two trading contracts were terminated, thus giving rise to claims for certain amounts which became payable. The amounts reflect the claimed amounts that have been agreed in principle with the three relevant counterparties for the purposes of the Restructuring. |
| • | An exceptional credit of £41 million related to the revised terms for the electricity supply agreement with ScottishPower and Scottish and Southern Energy. Under the terms of the agreement we released a balance of £41 million in respect of cash previously received. |
For the Year ended March 31, 2002
| • | An exceptional charge of £300 million resulting from the write-down of our investment in the Eggborough Station. This write-down arose as a result of lower than anticipated electricity selling prices in England and Wales and our assessment as to the effect of continued over-capacity in the UK electricity market on the value of similar coal-fired power stations. |
| • | An exceptional charge of £27 million related to the market value of the Decommissioning Fund. |
| • | An exceptional charge of £209 million arising as a result of a provision for three significant out-of-the-money trading contracts due to lower than anticipated electricity prices in the UK. These contracts had previously been accounted for as a hedge against our electricity output in the UK. However, since the introduction of NETA, these contracts were no longer accounted for as hedge contracts and, because they were out-of-the-money, they were provided for as onerous contracts under UK GAAP. |
| • | An exceptional operating cost of £3 million resulting from the issuance of shares to the British Energy Qualifying Employee Share Trust (QUEST) to satisfy the exercise of options granted to employees under the Sharesave Scheme between 2002-2003. The charge arises as a result of the difference between QUEST’s subscription price (the then prevailing market price per share) and the option exercise prices. The costs were charged over a five-year period ended March 31, 2002. |
| • | An exceptional credit of £4 million related to the gain on the sale of our investment in Humber Power Limited. We acquired a 12.5% interest in Humber Power Limited, the operator of a 1,260 MW combined cycle gas fired power plant in 1997. |
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Results of operations for the year ended March 31, 2004 compared with the year ended March 31, 2003
Turnover
Turnover and our share in turnover from the AmerGen joint venture for the year ended March 31, 2004 was £1,660 million. Turnover from continuing activities for the year ended March 31, 2004 was £1,516 million, a decrease of £12 million compared with turnover from continuing activities of £1,528 million for the year ended March 31, 2003. Turnover from discontinued activities for the year ended March 31, 2003 was £375 million and represented sales by Bruce Power prior to its disposal on February 14, 2003. The principal factors resulting in the decrease in turnover from continuing activities are set forth in the table below.
| Changes in Turnover from 2003 |
|||
| £ (in millions) |
|||
| Increased/(Decreased) Turnover |
|||
| Due to increased output |
57 | ||
| Due to lower achieved electricity prices |
(103 | ) | |
| Due to increased energy supply costs recharged to customers |
76 | ||
| Decrease in miscellaneous sales |
(1 | ) | |
| Decrease in exceptional turnover |
(41 | ) | |
| Total decrease in turnover |
(12 | ) | |
The decrease in turnover was primarily due to lower realized prices for our electricity. Our realized price1 for the year ended March 31, 2004 was £16.9 MW/h compared with £18.3 MW/h for the year ended March 31, 2003, a 7.7% decrease.
The decrease in realized prices for electricity was partially off-set by the growth in our direct supply business and increases in output. Our direct supply business has become one of our more important routes to market. Our target customer base is predominantly amongst the energy intensive industrial and commercial users, with electricity demands of over 1,000 MWh per annum. In the year ended March 31, 2004 we had contracts in place to supply some 1,350 direct supply customers at 7,500 sites. Our direct supply business has increased by almost 30% in volume terms in the year to March 31, 2004, to 29TWh. The volume of power sold directly to customers through the direct supply business is now equivalent to 40% of total output. This follows an increase of 20% in volume terms in the year to March 31, 2003. The table below sets forth the turnover generated by each of our wholesale and direct supply routes to market.
| Year ended March 31, |
||||||
| 2004 |
2003 |
|||||
| (pounds in millions) | ||||||
| Turnover analysis |
||||||
| Wholesale generation |
703 | 852 | ||||
| Direct supply (including energy supply costs) |
782 | 603 | ||||
| Total turnover |
1,485 | 1,455 | ||||
| Less: energy supply costs |
(260 | ) | (184 | ) | ||
| Total turnover excluding energy supply costs |
1,225 | 1,271 | ||||
| Per cent. split—excluding energy supply costs |
||||||
| Wholesale generation |
57 | % | 67 | % | ||
| Direct supply |
43 | % | 33 | % | ||
| (1) | Realized price is calculated by dividing UK turnover, net of energy supply cost and miscellaneous and exceptional income, by total output during the same period. |
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Total output from our plants in the UK for the year ended March 31, 2004 was 72.6 TWh, representing an increase of 3.1 TWh as compared with total output of 69.5 TWh for the year ended March 31, 2003. This increase was the result of output increases of 1.2 TWh from our nuclear plants and 1.9 TWh from the Eggborough power station. Our nuclear output was nevertheless affected by a number of unplanned outages. In particular, the major outage in both reactors at Heysham 1 resulted in the loss of 3.2 TWh due to cast iron pipe-work failure. The outages at Heysham 1 were equivalent to some £71 million of lost profit contribution inclusive of imbalance costs and associated fuel savings. Output at the Eggborough power station increased in 2004 compared to prior years in order to take advantage of higher electricity prices and to provide cover for the unplanned outages at our nuclear plants during the year.
Operating costs
Total operating costs (including exceptional items) for continuing activities for the year ended March 31, 2004 were £1,176 million compared to £5,427 million in the year ended March 31, 2003. Operating costs from continuing activities (excluding exceptional items) were £1,459 million for the year ended March 31, 2004, a reduction of £21 million compared to £1,480 million for the year ended March 31, 2003. The following table sets forth the various components of our operating costs for the years ended March 31, 2004 and 2003.
| Year ended March 31, | |||||
| 2004 |
2003 | ||||
| (pounds in millions) | |||||
| Continuing activities excluding exceptional items: |
|||||
| Fuel |
413 | 371 | |||
| Materials and services |
512 | 425 | |||
| Staff costs |
224 | 227 | |||
| Depreciation charges |
50 | 273 | |||
| Energy supply costs |
260 | 184 | |||
| 1,459 | 1,480 | ||||
| Continuing activities—exceptional items: |
|||||
| Materials and services |
25 | 94 | |||
| Depreciation (credits)/charges due to impairment review |
(295 | ) | 3,738 | ||
| Amounts (credited)/charged to non-operational assets |
(13 | ) | 115 | ||
| (283 | ) | 3,947 | |||
| Continuing activities—total costs: |
|||||
| Fuel |
413 | 371 | |||
| Materials and services |
537 | 519 | |||
| Staff costs |
224 | 227 | |||
| Depreciation (credits)/charges |
(245 | ) | 4,011 | ||
| Energy supply costs |
260 | 184 | |||
| Amounts (credited)/charged to non-operational assets |
(13 | ) | 115 | ||
| Total operating costs—continuing activities |
1,176 | 5,427 | |||
Fuel Costs
Total fuel costs for the year ended March 31, 2004 amounted to £413 million, an increase of £42 million compared with £371 million for the year ended March 31, 2003. Nuclear fuel costs were £318 million for the year ended March 31, 2004, representing an increase of £20 million as compared with £298 million for the year ended March 31, 2003. Coal costs were £95 million for the year ended March 31, 2004, representing an increase of £22 million as compared with £73 million for the year ended March 31, 2003.
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Of the £20 million increase in the cost of nuclear fuel, £7 million was attributable to increased output from our plants, offset by savings and efficiencies of £1 million. The main increase, however, was due to costs being £14 million lower following a one-off review of contract cost schedules with BNFL in 2003. The £22 million increase in coal costs relates primarily to the increase in output from the Eggborough power station over the year ended March 31, 2004.
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 of material and services for the year ended March 31, 2004, excluding exceptional items, were £512 million compared with £425 million for the year ended March 31, 2003, an increase of £87 million. The increase in material and services costs was largely the result of capital investment expenses of £92 million that were expensed as operating costs for the year ended March 31, 2004. This arose because it was not possible to demonstrate that this expenditure enhanced the value of our fixed assets after taking account of the impairment review. We have reviewed the capital investment expenditure of £92 million incurred, primarily on our power stations, and concluded that of this amount, £70 million may have been capitalized in the absence of the impairment review. The balance of capital investment expenditure of £22 million has been classified as refurbishment costs within materials and services.
Staff costs
Staff costs decreased by £3 million from £227 million for the year ended March 31, 2003 to £224 million for the year ended March 31, 2004 mainly due to reduced severance costs of £11 million but this was partly offset by salary inflation and an increased head count.
Depreciation
Depreciation charges (excluding exceptional charges) were £50 million for the year ended March 31, 2004 compared to £273 million for the year ended March 31, 2003. The charges for depreciation for the year ended March 31, 2004 were significantly affected by the fixed assets write down of £3,738 million at March 31, 2003. For additional information regarding the writedown of these assets, see Note 13 of our audited consolidated financial statements.
Energy supply costs
Energy supply costs mainly comprise the costs incurred by our direct supply business for the use of the distribution and transmission systems. These costs, however, are passed on to our customers and are fully recovered through turnover. For the year ended March 31, 2004 energy supply costs also included costs of £36 million related to meeting the cost of compliance with the Obligation. We are required to comply with the Obligation as part of the regulations introduced by the UK Government which are intended to address climate change. The costs for the year ended March 31, 2004 were £260 million compared with £184 million for the year ended March 31, 2003, an increase of £76 million. This increase reflects the inclusion of costs associated with the Obligation and growth in the direct supply business since March 31, 2003 as discussed above.
Discontinued activities
Operating costs from discontinued activities for the year ended March 31, 2003 were £278 million and represented the costs of Bruce Power prior to its disposal on February 14, 2003.
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Operating Profit/(Loss)
The following table sets forth certain summary operating information and the variance from period to period as indicated.
Operating profit/(loss):
| Year ended March 31, |
Variance |
|||||||
| 2004 |
2003 |
2003-2004 |
||||||
| (pounds in millions) | ||||||||
| Operating profit before exceptional items—continuing activities |
57 | 7 | 50 | |||||
| Exceptional items |
283 | (3,906 | ) | 4,189 | ||||
| Total operating profit/(loss)—continuing activities |
340 | (3,899 | ) | 4,239 | ||||
| Operating profit—discontinued activities |
— | 97 | (97 | ) | ||||
| Group operating profit/(loss) |
340 | (3,802 | ) | 4,142 | ||||
The increase of £50 million over the results for the year ended March 31, 2003 is explained as follows:
| (pounds in millions) |
|||
| Increased/(Decreased) Operating Profit due to: |
|||
| Output increases—turnover |
57 | ||
| Output increases—operating cost impact |
(31 | ) | |
| Price movements |
(103 | ) | |
| Capital investment expenditure now expensed |
(92 | ) | |
| Depreciation decrease |
223 | ||
| Other |
(4 | ) | |
| Variance |
50 | ||
Share of operating profit of discontinued joint venture
On 22 December 2003, we sold our 50% share in AmerGen to Exelon for US$277 million. Our share of the operating profit of AmerGen prior to the date of disposal was £21 million. Our share of operating profit was £43 million for the year ended March 31, 2003. This reduction of £22 million was due to an extended outage at the Three Mile Island nuclear power station and the contribution of only a part-year result within the period.
Financing charges, net interest and revalorization
The total financing charges were £176 million, consisting of revalorization and net interest of £249 million, exceptional financing credits of £5 million and exceptional revalorization credits of £68 million. This compares with total financing charges of £498 million for the year ended March 31, 2003 made up of revalorization and net interest of £277 million, exceptional financing charges of £62 million and exceptional revalorization of £159 million.
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The total financing charges are analyzed below:
| Year ended March 31, |
||||||
| 2004 |
2003 |
|||||
| (pounds in millions) | ||||||
| Revalorization of nuclear liabilities |
215 | 228 | ||||
| Revalorization of decommissioning fund |
(28 | ) | (29 | ) | ||
| Revalorization of other provisions |
— | 10 | ||||
| Share of revalorization of joint venture |
(2 | ) | (4 | ) | ||
| Total revalorization |
185 | 205 | ||||
| Net interest expense |
64 | 72 | ||||
| Financing charges before exceptional items |
249 | 277 | ||||
| Exceptional interest (credit)/charge |
(5 | ) | 62 | |||
| Exceptional revalorization (credit)/charge |
(68 | ) | 159 | |||
| Total financing charges |
176 | 498 | ||||
The net revalorization charge excluding exceptional items was £185 million, a decrease of £20 million from the year ended March 31, 2003 principally due to a reduction in inflation and discontinuation of revalorization of onerous contract provisions. The weighted average of RPI and RPIX used to revalorize our nuclear liabilities was 2.4% compared with 3.0% for the year ended March 31, 2003.
The net interest expense charge of £64 million for the year ended March 31, 2004 was £8 million lower than the charge for the year ended March 31, 2003. The principal reasons for this decrease were due to lower charges in relation to the interest rate swaps and additional interest earned on deposits. These increases were offset by an increase in standstill interest due to a full year charge in the year ended March 31, 2004.
In the year ended March 31, 2003 there were exceptional interest charges of £62 million resulting from the provision for the out of the money element of interest rate swaps which were no longer considered to be effective as hedges and the write-off of borrowing costs. The borrowing costs had been previously capitalized and were being amortized over the expected duration of loan financing in respect of the acquisition of the Eggborough Station. For the year ended March 31, 2004 there were exceptional interest credits of £5 million reflecting a partial reversal of the provision for interest rate swaps.
Profit/(loss) before tax
The profit before taxation was £232 million compared with a loss before tax of £4,292 million in the year ended March 31, 2003. The main reason for the movement of £4,524 million is the large exceptional costs in the prior year, some of which were partially reversed in the period.
Taxation
There was a £2 million taxation credit on ordinary activities for the period relating to the release of an over provision for foreign tax in prior years. The share of taxation for the discontinued joint venture was nil, comprising a tax charge on trading results to the date of the AmerGen disposal of £9 million, offset by credits for overprovisions of £9 million in earlier years.
In the year ended March 31, 2003 there was a net tax credit of £368 million, comprising tax charges of £18 million on North American activities, £10 million share of taxation for joint venture and a
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£396 million credit for release of UK deferred tax provisions. The deferred tax credit in the year ended March 31, 2003 arose as a result of the large exceptional charges.
The deferred tax assets of £291 million and £150 million at March 31, 2004 and at March 31, 2003 respectively were not recognized because there is insufficient certainty of recovery within the foreseeable future.
Earnings per share
The earnings per share in the period was 38.9p compared to a deficit of 654.7p for the year ended March 31, 2003, being an improvement of 693.6p.
Results of operations for the year ended March 31, 2003 compared with the year ended March 31, 2002
Turnover
Turnover in the year ended March 31, 2003 was £1,903 million, a decrease of £146 million compared with turnover of £2,049 million for the year ended March 31, 2002. The principal factors resulting in this decrease are set forth below.
| Changes in turnover from 2002 |
|||
| (pounds in millions) | |||
| Decreased UK turnover |
|||
| Due to decreased output |
(118 | ) | |
| Due to lower achieved electricity prices |
(111 | ) | |
| Due to exceptional NEA income |
41 | ||
| Increase in miscellaneous income |
15 | ||
| Decrease in turnover from continuing activities |
(173 | ) | |
| Increase in Bruce Power turnover |
27 | ||
| Total decrease in turnover |
(146 | ) | |
Our output in the UK was 69.5 TWh in the year ended March 31, 2003 as compared with 74.7 TWh in the year ended March 31, 2002. Nuclear generation output was 63.8 TWh in the year ended March 31, 2003 compared with 67.6 TWh in the year ended March 31, 2002. Eggborough power station output fell from 7.1 TWh to 5.7 TWh in the year ended March 31, 2003. Decreased output from our UK power stations resulted in reduced turnover of £118 million.
Our realized price during the year ended March 31, 2003 was £18.30/MWh, a decrease of 10% as compared with the prior year, resulting in a decrease in our UK turnover of £111 million. UK turnover increased by £41 million in respect of the exceptional credit relating to the release of the balance that had been held awaiting settlement of our dispute with Scottish Power and Scottish and Southern Energy for the Nuclear Energy Agreement. Miscellaneous income increased by £15 million, mainly due to insurance receipts relating to outages at Torness. The increase in turnover at Bruce Power was mainly due to increased electricity prices, offset to some extent by a reduction in output.
Operating costs
Operating costs were £5,705 million in the year ended March 31, 2003, an increase of £3,375 million compared with £2,330 million in the year ended March 31, 2002. Excluding exceptional items,
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operating costs decreased by £60 million to £1,758 million in the year ended March 31, 2003 from £1,818 million in the year ended March 31, 2002. The following table sets forth the various components of our operating costs for the years ended March 31, 2003 and March 31, 2002.
| Year ended March 31, | ||||
| 2003 |
2002 | |||
| (pounds in millions) | ||||
| Continuing activities excluding exceptional items: |
||||
| Fuel |
371 | 467 | ||
| Materials and services |
425 | 395 | ||
| Staff costs |
227 | 209 | ||
| Depreciation charges |
273 | 280 | ||
| Energy supply costs |
184 | 171 | ||
| 1,480 | 1,522 | |||
| Continuing activities—exceptional items: |
||||
| Staff Costs |
— | 3 | ||
| Materials and services |
94 | 209 | ||
| Depreciation (credits)/charges due to impairment review |
3,738 | 300 | ||
| Amounts (credited)/charged to non-operational assets |
115 | — | ||
| 3,947 | 512 | |||
| Continuing activities—total costs: |
||||
| Fuel |
371 | 467 | ||
| Materials and services |
519 | 604 | ||
| Staff costs |
227 | 212 | ||
| Depreciation (credits)/charges |
4,011 | 580 | ||
| Energy supply costs |
184 | 171 | ||
| Amounts (credited)/charged to non-operational assets |
115 | — | ||
| Total operating costs—continuing activities |
5,427 | 2,034 | ||
| Discontinued activities |
||||
| Fuel |
17 | 23 | ||
| Material and services |
143 | 149 | ||
| Staff costs |
111 | 119 | ||
| Depreciation |
7 | 5 | ||
| 278 | 296 | |||
| Total operating costs |
5,705 | 2,330 | ||
Fuel costs for our continuing UK activities were £371 million in the year ended March 31, 2003 compared with £467 million in the year ended March 31, 2002. The reduction reflects decreased output by our UK power stations, fuel efficiencies and price variances.
Materials and service costs are comprised of operating expenses for our power stations and support functions (such as administrative, engineering and maintenance costs) excluding fuel costs, staff costs and depreciation. Materials and services costs for our continuing UK activities in the year ended March 31, 2003 were £519 million, a decrease of £85 million compared with the year ended March 31, 2002. These figures include exceptional charges in the year ended March 31, 2003 of £57 million in respect of a write down of slow moving stocks, £35 million in respect of Restructuring costs and £2 million in respect of additional provisions for onerous trading contracts. They include exceptional charges of £209 million in the year ended March 31, 2002 in respect of provisions for onerous trading contracts. Excluding these exceptional items, materials and services costs for our
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continuing UK activities increased by £30 million to £425 million in the year ended March 31, 2003 compared with £395 million in the year ended March 31, 2002. This increase was primarily due to the costs associated with a higher number of outages in the year ended March 31, 2003.
Staff costs
Staff costs for our continuing UK activities in the year ended March 31, 2003 were £227 million, an increase of £15 million compared with the year ended March 31, 2002. The main reason for the increase was additional severance costs of £8 million.
Depreciation
Depreciation charges for our continuing UK activities were £4,011 million in the year ended March 31, 2003 compared with £580 million in the year ended March 31, 2002. These figures include exceptional charges associated with the write down of our fixed assets amounting to £3,738 million in the year ended March 31, 2003 and £300 million in the year ended March 31, 2002. Excluding these exceptional charges, the depreciation charges for our continuing UK activities decreased by £7 million to £273 million in the year ended March 31, 2003 compared with £280 million in the year ended March 31, 2002.
Amounts written off as non-operational assets in our continuing activities amounted to £115 million in the year ended March 31, 2003 compared to zero in the year ended March 31, 2002. These amounts consisted of exceptional items relating to the write down of our own shares held and an element of a write down of the UK decommissioning fund receivable, both of which were treated as exceptional items.
Energy supply costs
Energy supply costs in the UK were £184 million in the year ended March 31, 2003 compared with £171 million in the year ended March 31, 2002. The increase primarily reflects the increase of sales through our direct supply business.
Discontinued activities
Operating costs in our discontinued Canadian activities were £278 million in the year ended March 31, 2003 compared with £296 million in the year ended March 31, 2002. The decrease was partly attributable to reduced fuel costs arising from the reduction in output and partly attributable to operational efficiencies.
Our share of the operating profit of AmerGen increased by £6 million to £43 million in the year ended March 31, 2003. The output from the three AmerGen power stations totaled 20.2 TWh in the year ended March 31, 2003, an increase of 1.5 TWh compared with 18.7 TWh in the year ended March 31, 2002.
Operating loss
The operating loss in the year ended March 31, 2003 was £3,802 million compared with an operating loss of £281 million in the year ended March 31, 2002. The operating loss of our continuing activities was £3,899 million in the year ended March 31, 2003 compared with an operating loss of £333 million in the year ended March 31, 2002. The operating profit of our discontinued activities was £97 million in the year ended March 31, 2003 compared with an operating profit of £52 million in the year ended March 31, 2002.
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Excluding exceptional items, operating profit in the year ended March 31, 2003 was £104 million, compared with an operating profit of £231 million in the year ended March 31, 2002. The operating profit of our continuing activities was £7 million in the year ended March 31, 2003 compared with an operating profit of £179 million in the year ended March 31, 2002. The operating profit of our discontinued activities was £97 million in the year ended March 2003 compared with an operating profit of £52 million in the year ended March 31, 2002.
(Loss)/profit on sale of business
The results for the year ended March 31, 2003 include a loss of £35 million in respect of the disposal of our interests in Bruce Power and Huron Wind. The results for the year ended March 31, 2002 include a profit of £4 million on the disposal of our interests in Humber Power.
Financing charges
Financing charges, which comprise revalorization charges and net interest expense, were £498 million in the year ended March 31, 2003, an increase of £245 million compared with £253 million in the year ended March 31, 2002. The financing charges for the year ended March 31, 2003 include exceptional items amounting to £159 million in respect of a write down of our decommissioning fund receivable, £56 million in respect of a provision for interest rate swaps and £6 million in respect of a write off of capitalized borrowing costs. Financing charges for the year ended March 31, 2002 consist of a write down of £27 million in respect of the decommissioning fund receivable. Excluding these exceptional items, financing charges increased by £51 million to £277 million in the year ended March 31, 2003 compared with £226 million in the prior year. The increase primarily reflects higher revalorization as a result of higher UK inflation. Excluding the exceptional items, the revalorization charge was £205 million in the year ended March 31, 2003 compared with £160 million in the prior year. The increase in revalorization reflects the weighted average UK inflation rate of 3.0% in the year ended March 31, 2003 compared with 1.7% in the year ended March 31, 2002.
Taxation
In the year ended March 31, 2002 we adopted FRS19, the UK deferred tax accounting standard, on a discounted basis. The tax credit for the year ended March 31, 2003 was £368 million. Excluding tax relating to exceptional items, the tax charge for the year ended March 31, 2003 was £2 million. The effective tax rate is higher than the standard rate of 30% as a result of overseas profits being taxed at rates in excess of 30%, the impact of items that are non-deductible for tax purposes, such as the write-down of our investment in Eggborough, and the impact of unwinding one year’s discount from our opening deferred tax liability. The tax charge for the year ended March 31, 2003 comprises a deferred tax credit of £396 million, an overseas tax charge of £18 million and £10 million charge in respect of AmerGen. The tax charge for the year ended March 31, 2002 comprised a prior year UK corporation tax credit of £11 million, a deferred tax credit of £8 million, an overseas tax charge of £15 million and £29 million charge in respect of AmerGen.
As of March 31, 2003 there were deferred tax assets of £382 million and deferred tax liabilities of £20 million on an undiscounted basis. Of the deferred tax asset, £262 million relates to tax relief from operating losses carried forward. A further £64 million relates to the expected tax relief associated with accrued decommissioning costs which are expected to be deductible against future taxable income and £56 million relates to accelerated depreciation in excess of capital allowances. The deferred tax liability relates to other short-term timing differences.
The net discounted deferred tax asset under UK GAAP at March 31, 2003 of £150 million has not been recognized as it is not likely to be realized unless the Restructuring is completed. Under US
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GAAP a full valuation allowance has been made against the net deferred tax asset of £2,101 million at March 31, 2003.
Loss per share
There was a loss per share of 654.7p per share for the year ended March 31, 2003 compared with a loss per share of 88.5p per share in the year ended March 31, 2002.
Loss on ordinary activities
As a result of the factors discussed above, there was a loss on ordinary activities after taxation for the year ended March 31, 2003 of £3,924 million compared with a loss of £518 million in the year ended March 31, 2002. Excluding exceptional items there was a loss of £132 million in the year ended March 31, 2003 compared with a loss of £39 million in the year ended March 31, 2002.
Minority interests
There was a minority interest in respect of the 17.6% minority shares of the profits of Bruce Power of £17 million in the year ended March 31, 2003 compared with £9 million in the year ended March 31, 2002.
Review of our balance sheet items as at March 31, 2004
Current assets
Total current assets increased in the year ended March 31, 2004 by £323 million to £1,737 million, from £1,414 million in the year ended March 31, 2003. The largest component of this rise was the £240 million increase in cash and liquid funds from £333 million in the year ended March 31, 2003 to £573 million in the year ended March 31, 2004.
Total stocks were reduced by £10 million. Nuclear fuel stocks were reduced by £18 million following a supply chain review. This reduction was partly offset by an increase in stores of £7 million mainly due to the acquisition of certain key strategic spares at Eggborough power station following a risk review and an increase in coal stock of £1 million.
The level of total debtors reduced by £13 million to £374 million. This is due to a decrease in the taxation and social security balance recorded in debtors of £65 million, which was reallocated to current liabilities. This decrease is offset by an increase in the pension prepayment of £29 million and there is also an increase of £23 million in trade debtors and other prepayments.
The Decommissioning Fund will be used to fund post-defueling decommissioning costs. The balance sheet carrying value of the decommissioning fund receivable has been restated to a market value of £440 million compared to £334 million for the ended March 31, 2003. The increase in market value reflects the upturn in equity market values that occurred in the year ended March 31, 2004 and the fact that we contributed an additional £19 million to the fund.
Current liabilities
The level of creditors due within one year (excluding borrowings) has increased from £1,033 million to £1,250 million. The main movement is an increase in the level of nuclear liabilities classed as due within one year from £355 million to £554 million. The difference arises because the liability continues to be recorded under the historic BNFL contracts while payments are based on the revised BNFL contracts.
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The other movements within creditors comprise a net increase in the other taxes and social security balances of £40 million relating to the reallocation from debtors of £65 million, reallocation of VAT from the tax creditors of £86 million and an increase in the amount of £19 million during the year ended March 31, 2004. Trade creditors decreased by £18 million due to a reallocation of £86 million, as mentioned, to the other taxes and social security balance and an increase in trade creditors of £68 million. There were other decreases of £4 million in retentions, accruals and other creditors.
Provisions
Included in provisions at March 31, 2004 were accrued nuclear liabilities of £1,776 million, an increase of £103 million over the year ended March 31, 2003. The liabilities increased due to additional fuel consumed in our nuclear power stations, revalorization (inflation and removal of one year’s discount to restate the provision at balance sheet money values) and reduced by cash payments made during the year ended March 31, 2004.
Pensions
Note 25 to the Financial Statements provides the disclosures required under the transitional requirements of FRS17, the UK accounting standard dealing with retirement benefits. The FRS17 valuation is based on a valuation of assets and liabilities at a particular point in time and does not necessarily take account of the long-term nature of pension schemes. Movements in equity markets and bond yields can create considerable volatility in the FRS17 valuation at different points in time.
Under FRS17, the net pension deficit was £325 million for the UK schemes as at March 31, 2004, a decrease of £27 million from March 31, 2003. The value of the scheme assets has increased with the rise of the equity markets, but this was offset by increased liabilities due to future higher inflation rate assumptions and improved actuarial information.
The Trustees of the Schemes follow an investment policy whereby a high proportion of the Scheme’s assets is invested in equities. One consequence of this investment policy, and the methodology and assumptions used for determining the schemes’ liabilities under FRS17, is that the difference between the market value of the schemes’ assets and its FRS17 liabilities (i.e. its FRS17 “surplus” or “deficit”) is expected to be volatile. Indeed, the amount of any surplus or deficit could change significantly over periods as short as a day (in the event of significant market movements). The results reported should not, therefore, be taken as an indication of the Scheme’s financial position in accordance with FRS17 on any date other than March 31, of the relevant year.
The funding of the pension schemes is based on the results of three yearly valuations by independent actuaries rather than on the results of the FRS17 valuation. A valuation is being carried out by our actuaries as at March 31, 2004, however, the result of the valuation will not be concluded until October 2004. The combined funding deficiencies (on the actuarial bases used for the valuations) in the two pension schemes is expected to be £385 million, within the range of £330 million to £440 million previously disclosed. When the valuation is completed the potential level of increase in future employer contributions will be agreed with the Trustees of the Scheme.
During the year ended March 31, 2003, the actuary of the British Energy Generation Group scheme (our main UK pension scheme) carried out an interim review of scheme assets and liabilities in order to assess the appropriateness of continued use of the surplus that arose at the March 31, 2001 valuation. As a result of that review, the employer’s contributions to that scheme were increased from 10% to 17.1% from November 1, 2002. The employer’s contributions to the British Energy Combined Group scheme (our smaller UK pension scheme) were increased from 12% to 15.3% from April 1,
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2002. In total, cash contributions were £34 million for the year ended March 31, 2004 and £31 million for the year ended March 31, 2003.
There were no changes to the contribution rates in the year ended March 31, 2004.
Our balance sheet reported at March 31, 2004 and March 31, 2003 does not include the FRS17 deficit.
Total recognized gains and losses
In addition to the profit after tax of £234 million, exchange translation losses on foreign currency net investments arose amounting to £15 million. These were all in relation to the investment in the AmerGen joint venture and its subsequent disposal.
Disclosure of Contractual Obligations
We have made various financial commitments in the ordinary course of our business. Such commitments include entering into contracts for the supply of fuel for our power stations and capital expenditure commitments. In addition, we have made certain contingent financial commitments which may become payable under certain circumstances, for example in the event that a guarantee becomes payable.
The following table provides a summary of our general financial obligations as of March 31, 2004.
| Payment due by period |
|||||||||||||||||||
| Total |
2003(3) |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
Thereafter |
|||||||||||
| (in millions of pounds) | |||||||||||||||||||
| Bonds(2) |
408 | 110 | — | — | 163 | — | — | — | 135 | (1) | |||||||||
| Project finance loan(2) |
475 | — | 42 | 45 | 48 | 52 | 56 | 60 | 172 | ||||||||||
| UK nuclear fuel purchases |
1,465 | — | — | 200 | 183 | 93 | 67 | 63 | 859 | ||||||||||
| UK coal purchases |
82 | — | — | 49 | 29 | 4 | — | — | — | ||||||||||
| Capital commitments |
17 | — | — | 17 | — | — | — | — | — | ||||||||||
| Long-term electricity purchase contracts(2) |
316 | 46 | 62 | 62 | 47 | 36 | 37 | 8 | 18 | ||||||||||
| 2,763 | 156 | 104 | 373 | 470 | 185 | 160 | 131 | 1,184 | |||||||||||
| (1) | Final maturity in 2016. |
| (2) | The analysis of maturity of Bonds, Project Finance Loan and long term electricity trading contracts has been prepared based on the dates when they mature under the existing contractual arrangements. However, the standstill arrangements which have been put in place have the effect of deferring the payments of certain amounts due until the Bonds, Eggborough Project Finance Loan and long term electricity trading contracts are replaced as part of the Restructuring or earlier termination of the standstill. The maturity profile is likely to change upon completion of the Restructuring. |
| (3) | Amounts are included to illustrate obligations that were due in 2003, but are currently under the standstill arrangements. |
In addition to the above, there are also amounts payable relating to our back-end fuel costs and decommissioning liabilities. These amounts are based on our expected future output and costs. For more information as to how we calculate the amounts set forth below, see “—Critical Accounting Policies—Nuclear Liabilities and Decommissioning”.
| Payment due by period | ||||||||||||||
| Total |
2005 |
2006 |
2007 |
2008 |
2009 |
Thereafter | ||||||||
| (in millions of pounds) | ||||||||||||||
| Nuclear liabilities |
10,663 | 571 | 249 | 209 | 240 | 240 | 9,154 | |||||||
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Liquidity and capital resources
Government facility
Following the sale of AmerGen, the Government Facility was repaid in full and the amount of credit available under the Government Facility reverted back to £200 million on December 24, 2003 all of which was undrawn and available as at March 31, 2004.
Investment expenditure
There have been no additions to fixed assets recorded in the year ended March 31, 2004 following the fixed asset write down carried out in the year ended March 31, 2003. It has not been possible to demonstrate that the capital investment expenditure enhanced the value of our fixed assets after taking account of the impairment review. Included within material and services, an element of operating costs, for the year ended March 31, 2004 were £92 million of capital investment expenditures. Of this amount, £70 million may have been capitalized in the absence of an impairment review, with the balance of £22 million being classified as refurbishment costs which were expensed compared to £112 million of capital investment expenditures that were capitalized within fixed assets in the year ended March 31, 2003.
In relation to the financial year ending March 31, 2005, we expect that the investment in plant projects, major repairs and strategic spares across the whole company, including incremental costs associated with the Performance Improvement Program of approximately £20 million, will be in the range of £150 million to £180 million, compared to £128 million in the year ended March 31, 2004. Whether or not any of this expenditure will be capitalized or expensed depends on the future carrying value of fixed assets as a result of impairment, fair value reviews and whether the expenditure will enhance the value of the assets.
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Cash flow
A reconciliation of profit after tax and exceptional items to EBITDA(1) is shown in the table below. The EBITDA calculations are shown for the total results and also excluding the disposals during the year ended March 31, 2004 and exceptional items for the continuing business. The EBITDA calculation for the continuing activities is further expanded to show the operating cash flow and the increase in total cash. The total cash is however subject to restricted use prior to the completion of the Restructuring and thereafter to the terms of the NLF Cash Sweep Payment.
| Year ended March 31, |
|||||||||
| 2004 |
2003 |
2002 |
|||||||
| (pounds in millions) | |||||||||
| Profit/(loss) after tax and exceptional items |
234 | (3,924 | ) | (518 | ) | ||||
| Interest (including exceptional items) |
59 | 134 | 66 | ||||||
| Revalorization (including exceptional items) |
117 | 364 | 187 | ||||||
| Tax (including exceptional items) |
(2 | ) | (368 | ) | 25 | ||||
| Depreciation charges |
50 | 273 | 280 | ||||||
| Exceptional depreciation (credits)/charges due to impairment review |
(295 | ) | 3,738 | 300 | |||||
| EBITDA(1) |
163 | 217 | 340 | ||||||
| (Gain)/loss on sale of business |
(47 | ) | 35 | (4 | ) | ||||
| AmerGen profits |
(21 | ) | (43 | ) | (37 | ) | |||
| Bruce Power contributions |
— | (97 | ) | (52 | ) | ||||
| Net exceptional charges other than depreciation, interest, tax and revalorization |
12 | 168 | 212 | ||||||
| EBITDA—continuing activities |
107 | 280 | 459 | ||||||
| Nuclear liabilities charged to operating costs |
130 | 105 | 156 | ||||||
| Nuclear liabilities discharged |
(59 | ) | (115 | ) | (332 | ) | |||
| Regular contributions to decommissioning fund |
(19 | ) | (18 | ) | (18 | ) | |||
| Other provisions discharged |
(3 | ) | (45 | ) | (43 | ) | |||
| Exceptional operating cash costs |
(25 | ) | (154 | ) | — | ||||
| Working capital movements |
25 | 191 | 101 | ||||||
| Operating cash flow from continuing activities |
156 | 244 | 323 | ||||||
| Capital expenditure |
— | (112 | ) | (187 | ) | ||||
| Taxation (paid)/received |
(12 | ) | 3 | 4 | |||||
| Disposal/(purchase) of investments |
171 | 262 | (129 | ) | |||||
| Net interest paid |
(75 | ) | (84 | ) | (53 | ) | |||
| Net cash outflow of discontinued activities |
— | (78 | ) | 57 | |||||
| Increase in cash (before equity dividends) |
240 | 235 | 15 | ||||||
| Equity dividends |
— | (31 | ) | (46 | ) | ||||
| Increase in total cash (after equity dividends) |
240 | 204 | (31 | ) | |||||
| (1) | EBITDA represents earnings before interest, taxes, depreciation and amortization, extraordinary and other non-cash items and minority interests. EBITDA and EBITDA from continuing activities are not GAAP measures in either the UK or in the United States and should not be considered in isolation or as a substitute for, or as an alternative to, net income, operating income, cash flow from operations, other cash flow data or any other performance measures prepared in accordance with UK GAAP or US GAAP. For additional information regarding the use of EBITDA, see “Presentation of Financial and Other Data—Non-GAAP Financial Measures.” |
Operating cash flow from continuing activities
The operating cash flow from continuing activities for the year ended March 31, 2004 was £156 million, £88 million lower than the prior year after excluding the cash received from the disposal of Bruce Power. The cash flows for the year ended March 31, 2004 include capital investment
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expenditures totaling £92 million that are now expensed as part of materials and services costs. Of this amount, £70 million may have been capitalized on the absence of the impairment review with the balance of £22 million being classified as refurbishment costs. During the year ended March 31, 2003, £112 million was not deducted in calculating net cash inflow from operating activities.
When adjusted for the capital expenditure, the taxation paid or received, the receipts from sale of investments, the net interest paid and discontinued activities the free cash flow position is £240 million for the year ended March 31, 2004 compared to £235 million (before equity dividends paid of £31 million) in the year ended March 31, 2003.
Net cash outflows for interest payments reduced by £9 million. Net receipts from disposals of £171 million mainly represented the proceeds from the sale of AmerGen. In the prior year there were net receipts of £262 million from the sale of Bruce Power.
Capital resources
At March 31, 2004, total debt of £883 million comprised:
| • | A project finance loan of £475 million secured on the assets of Eggborough Power Limited (EPL), a subsidiary company that operates the Eggborough Station. At March 31, 2004, the effect of our interest rate contracts is to classify the borrowings as fixed rate. We do not guarantee amounts owed by EPL but we do guarantee the payment of amounts by British Energy Power and Energy Trading Limited (BEPET) to EPL under the Capacity and Tolling Agreement (CTA) between BEPET and EPL. The contractual amounts payable by BEPET under the CTA are calculated so as to cover EPL’s borrowing requirements and operating costs. We also provide a subordinated loan facility to EPL. The final installment of loan principal is due to be repaid in 2011. The loan currently bears interest at LIBOR plus 1.3% It is proposed that these arrangements will be restructured as part of our Restructuring. For further details of the Restructuring, see “Item 4. Information about the Company—the Restructuring”. |
| • | An aggregate principal amount of £408 million sterling denominated bonds due between 2003 and 2016. The bonds bear interest at a rate of between 5.9% and 6.2% An aggregate principal amount of £110 million matured in March 2003 but payment has been stoodstill as part of the arrangements in the Restructuring. It is proposed that these arrangements will be restructured as part of our Restructuring. |
| Cash at Bank |
Term balances |
Debt due in less than one year |
Debt due after more than one year |
Net debt |
|||||||||
| (pounds in millions) | |||||||||||||
| Net debt at April 1, 2003 |
87 | 246 | (152 | ) | (731 | ) | (550 | ) | |||||
| Cash flows |
175 | 65 | (45 | ) | 45 | 240 | |||||||
| Net debt at March 31, 2004 |
262 | 311 | (197 | ) | (686 | ) | (310 | ) | |||||
As at March 31, 2004, our net debt was £310 million, a decrease of £240 million compared to our net debt as at April 1, 2003. The main reasons for the reduction in our net debt were the proceeds from the sale of AmerGen and improved cash management procedures.
Future liquidity
Our main source of liquidity is our operating businesses. Cash generated by our operating businesses is dependent upon the reliability of our power stations in producing electricity, the realized price for electricity, operational risk and capital investment expenditure (expensed in the profit and loss
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account since April 1, 2003), maintenance requirements as well as collateral requirements relating to our trading activities. However, we believe that our current available working capital is not sufficient to meet our present requirements. We are taking steps with a view to improving this situation. The receipt of the proceeds from the disposal of AmerGen significantly increased our financial flexibility. We are continuing to explore initiatives to reduce the demand for trading collateral and to achieve sufficient liquid resources to implement the Restructuring.
The Restructuring and, therefore, the working capital available to us remain subject to a large number of significant uncertainties and important conditions. These include settling certain documents with creditors, approval of the Scottish court and listing of the new shares and new bonds. The Restructuring is also conditional on there being no material adverse change affecting us as a whole or Eggborough Power Limited and no material adverse effect on the value of the creditors’ entitlements under the Restructuring. Furthermore, the Secretary of State is entitled not to proceed with the Restructuring if, in her opinion, we will not be viable in all reasonably foreseeable conditions without access to additional financing beyond that which is committed and will continue to be available when required. Also, for listing purposes, the restructured British Energy will need to have sufficient working capital for its present requirements from listing of the new shares and new bonds. For additional uncertainties which may affect our cash flow position, performance or outlook, see “Item 3. Risk Factors.”
During the third quarter of the year ended March 31, 2004 we faced short term pressures on liquidity resulting from the combined effect of seasonality, the major unplanned outage at Heysham 1 and the increased levels of collateral brought about increased volatility in electricity prices. As at March 31, 2004 we had £276 million in unrestricted cash which was not the subject of restrictions. In addition, we had £297 million deposited as collateral in support of trading activities. In the event that outages, collateral requirements or other events impact our ability to generate sufficient cash or liquidity for our operations, we have £200 million in available credit under the Government Facility. We have granted, amongst others things, a lien on certain receivables and a pledge and mortgage on the shares of certain of our subsidiaries as security for any future drawings under the Government Facility. On August 25, 2004 we entered into the Receivables Facility, details of which are contained in “Item 4. Restructuring—Receivables Facility”.
Post Balance Sheet Events
In connection with our agreement for the sale of Bruce Power we received the sum of C$10 million in respect of the restart of Unit 3 of the Bruce Power station on May 25, 2004, which brings the total sale proceeds relating to the sale of Bruce Power to C$728 million. See note 32 to our audited consolidated financial statements.
For further information on post balance sheet events see note 35 to our consolidated financial statements.
Contingent liabilities
On February 12, 2004, we received a notice of warranty claims from the consortium that purchased our 82.4% interest in Bruce Power alleging breach of certain representations and warranties relating to taxation and the condition of certain plants at the Bruce power station.
The principal tax claim relates to the treatment of expenditures at the Bruce plant during the period of our ownership that is currently being considered by the Canadian tax authorities. The treatment that we have proposed could result in a rebate of a material amount of tax that has not been recognised in our financial statements for the year ended March 31, 2004. The consortium claims that allowance of the expenditure for that period would cause it to lose future deductions. We have rejected the tax claim
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and expect to defend it if it is pursued further. On the basis of advice received, 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 impact on our cash flow.
The claim relating to the condition of the plant is based upon alleged erosion of some of the steam generator 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. In accordance with UK GAAP, no provision has been made in the financial statements at March 31, 2004 for either element of the claim.
Under the Bruce Power sale agreement, C$20 million has been placed in trust to satisfy any representation and warranty claim. The C$20 million may be retained by the trustee pending agreement or final resolution of the claims.
Following an accounting adjustment made by Exelon to the value of nuclear fuel contained in AmerGen’s balance sheet dated December 21, 2003 (as a result of which we may be required to make a payment to Exelon of up to US$13.7 million) we served a Dispute Notice on Exelon on June 4, 2004 to preserve our rights. The agreement with Exelon for the sale of AmerGen requires that, prior to instituting any litigation or other dispute resolution procedure, the companies will in good faith seek to resolve any dispute.
Furthermore, we are reviewing with Exelon the effect on the working capital adjustment resulting from a change to the estimated tax recoverable for prior periods made after the consummation of the sale, and this, if agreed, may result in a reduction in the purchase price payable by Exelon, with the reduction currently estimated to be in the range of up to US$6.3 million.
For additional information regarding further contingent liabilities, see note 33 to our audited consolidated financial statements.
Financial Instruments and Risk Management
Overview
The main financial risks faced are output risk across the fleet and trading risks in England and Wales and in Scotland following the introduction of BETTA in respect of movements in the wholesale market price for electricity. There is also an exposure to risks associated with fluctuations in the equity markets through the Decommissioning Fund and Pension Schemes. Policies have been instituted for managing each of these risks, which have been approved by the Board. Each of these risks is discussed in more detail below.
Our Power and Energy Trading Division manage electricity trading risks. The Power and Energy Trading Division operate within policies and procedures that are approved by the Board and monitored by a sub-committee of the Executive Committee.
Non-trading risks (i.e. cash resources, debt finance and financial risks) are managed by the central treasury function (the Treasury Department). The Treasury Department operates within policies and procedures approved by the Board of Directors. The Treasury Department uses appropriate and available instruments, within specified limits, to manage financial risk but is not permitted to take speculative, open positions. Both the Treasury Department and the Power and Energy Trading Division are subject to regular scrutiny from the Internal Audit Department (as are our other Departments and business units).
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Interest Rate Risk Management
The market value of debt varies with fluctuations in prevailing interest rates in the UK.
Eggborough related derivative agreements (nominal amount of £377 million as at March 31, 2004 and £398 million as at March 31, 2003) have been amended in the period as part of the Restructuring. The effect has been to fix future interest payments under the swaps from October 2004 onwards.
At March 31, 2004 the total of investments in liquid funds and cash amounted to £573 million, and had maturity dates due within one year. Cash not immediately required for business purposes is invested in fixed-rate term deposits and money market funds. At March 31, 2004, the term deposits and money market funds not used to fund our collateral agreements were due to mature or were available within one day and earned interest at an average rate of 3.9%. Term deposits, such as money market funds and bank balances, at March 31, 2004 include £297 million of cash that has been deposited in collateral bank accounts and earned interest at an average rate of 3.1%. However, this cash is restricted over the periods of our collateralized positions.
As the deposit terms are short term, the carrying value of our investment in liquid funds and cash at March 31, 2004 approximates to the fair market value.
Foreign Exchange Risk Management
At March 31, 2004 we did not hedge foreign currency risk. However, we will continue to evaluate currency hedging opportunities based on our exposure to foreign currency risk.
At March 31, 2003, there were deferred losses of £2 million accounted for as part of stock that arose on the rollover of maturing forward contracts used for hedging the future purchase of nuclear fuel prior to and including the year ended March 31, 2003. See note 20 to our audited consolidated financial statements.
Electricity Trading Risk Management
Our trading activities relate principally to supporting our power generation business and our direct supply business. The trading operations, therefore, act principally as wholesale marketers rather than as pure financial traders. The principal objective of our trading activities is to increase the return on our assets while hedging the market risk associated with plant output and market price.
Under NETA in England and Wales, any mismatch between actual metered generation (or demand) and the notified contract position is settled through the balancing mechanism at generally unfavorable prices. We generally sell all planned nuclear output forward and to minimize our exposure to unfavorable prices pursuant to the balancing mechanism. The risks in the wholesale market are managed through a contracting strategy that builds a portfolio of forward contracts of different lengths.
Eggborough power station provides a flexible generation capability that fulfils three purposes designed to enhance profitability. Firstly, it provides a means for compensating for unplanned lost output from our nuclear units at short notice; secondly it provides the capability to profile the output to meet the requirements of both wholesale and direct supply business customers; and thirdly, it provides a flexible capability.
Our policy is to manage credit exposure to trading and financial counterparties within clearly defined limits. A sub-committee of the Executive Committee strictly monitors electricity trading activities and places controls through delegated authorities and procedures, which include specific criteria for the management of counterparty credit exposures.
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Output from the two stations in Scotland will continue to be sold under the terms of the Nuclear Energy Agreement to Scottish Power and Scottish and Southern Energy until April 1, 2006, or the introduction of BETTA (currently scheduled for April 1, 2005), whichever is earlier.
Equity Risk Management
The Decommissioning Fund was established to provide for the eventual decommissioning of our nuclear power stations. Cash contributions are made on a quarterly basis to a payment profile set out in a contract between us and the Decommissioning Fund and are invested by it in UK marketable fixed income debt, equity securities and property in accordance with its investment policy. We are ultimately responsible for contributions to the Decommissioning Fund. Therefore, the level of future contributions, which are reviewed every five years in conjunction with the review of ultimate decommissioning costs, depend partly on the estimated long-term investment performance of the equity and debt instruments in which the contributions are invested and returns on investments in property. Income from dividends and other returns on the underlying investments are retained by the Decommissioning Fund and then reinvested in debt and equity securities.
The balance held by the Decommissioning Fund was recorded in the balance sheet at £440 million at March 31, 2004, which approximates to its market value. The Decommissioning Fund included property and debt and equity securities with market values of £44 million and £396 million respectively at March 31, 2004. Under the terms of the Restructuring, the Decommissioning Fund will be enlarged into and renamed the NLF and we will have no liability for shortfalls in the NLF resulting from changes in the market value of its debt and equity securities.
We reported a deficit of £325 million on our employee pension schemes, on an FRS17 basis, in our financial statements at March 31, 2004. As at March 31, 2004, the pension schemes’ assets were valued at £1,822 million compared to £1,525 million as at March 31, 2003, of which £1,571 million was held in equities and bonds compared to £1,316 as at March 31, 2003. The level of employer contribution to the schemes will be re-assessed following the triennial actuarial valuation that will be carried out as at March 31, 2004. The level of re-assessed contribution will depend partly on the estimated long-term investment performance of the equity and debt instruments in which the contributions are invested.
US Generally Accepted Accounting Principles
In addition to preparing our accounts in accordance with UK GAAP, the Directors are also required to prepare a reconciliation of our profit and loss and shareholders’ funds from UK GAAP to United States Generally Accepted Accounting Principles, or US GAAP. The adjustments required to reconcile our profit and loss and shareholders’ funds from UK GAAP to US GAAP are explained in Note 36 (as restated) to the accounts. Certain of our US GAAP accounting policies have been identified as the most critical US GAAP accounting policies and these are discussed below. The discussion below should be read in conjunction with the full explanation of US GAAP accounting policies set out in note 36 (as restated) of our audited consolidated financial statements.
Nuclear Liabilities and Decommissioning
As discussed in the preceding section under UK GAAP, we record liabilities for back end fuel costs and decommissioning costs. On April 1, 2003 we adopted FAS 143 “Accounting for Asset Retirement Obligations” which address the accounting for legal obligations associated with the retirement of long-lived assets that result from the construction, development or normal operation of a long-lived asset.
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Under FAS 143, a liability for an asset retirement obligation is recognized when a legal obligation arises and should be initially measured at fair value. The liability should also be capitalized as part of the carrying amount of the related long-lived asset. Changes in the liability due to the passage of time is recorded as an operating expense in the statement of profit and loss. The determination of the fair value of our asset retirement obligations requires management to make certain judgements about the estimated useful lives of our long-lived assets, changes in technology, economic and market conditions, and actions or assessments by our regulators. A change in these judgements can affect the amount of asset retirement obligations recognized in our financial statements.
As a result of adopting FAS 143, we recorded a cumulative adjustment of £7,640 million (net of tax charge of £273 million) (as restated) in the year ended March 31, 2004. The cumulative adjustment is primarily due to the difference in accounting for the liability using a higher rate of discounting under FAS 143 than in previous periods. For additional information regarding the impact of FAS 143, see note 36 (as restated) of our audited consolidated financial statements.
Impairment of Fixed Assets
As discussed in the preceding section under UK GAAP, we have performed an impairment review of our fixed assets for UK GAAP. As a result of that review, the value of our power stations was written up by £295 million. In addition, we have also performed an impairment review of our fixed assets under US GAAP, using consistent assumptions and estimates as those used for purposes of our review under UK GAAP. Under US GAAP, fixed assets are written down to their fair value only when their carrying value exceeds their undiscounted future cash flows. In the current year the US GAAP impairment test indicated that the carrying value of our power stations did not exceed their undiscounted future cash flows. However, reversing previous year impairment charges is not permitted under US GAAP. As a result, we were required to record a US GAAP adjustment charge of £225 million for purposes of US GAAP in the year ended March 31, 2004. The charge reflects the £295 million difference arising from reversing previous impairment charges under UK GAAP, net of £70 million capital expenditures expensed under UK GAAP but capitalized under US GAAP. The adjustments are described more fully in note 36 (as restated) of our audited consolidated financial statements.
Derivatives
Under US GAAP certain contracts that have been entered into by us in the ordinary course of business are considered to be derivative instruments. Accordingly we are required to arrive at the fair value of these contracts at each period and include these fair values in our US GAAP balance sheet. The movement in fair value from one reporting period to the next is recognized in our income statement or within other comprehensive income, as appropriate.
In arriving at the fair values of the derivatives, estimates are made of future commodity prices, including the selling price for electricity and for coal. Certain of these prices can be ascertained externally in the short term, however, in the longer term we are required to use internal valuation techniques and models which take account of forecast sales volumes, prices and the correlation between various factors in the market place. The actual outcome can vary significantly from our future forecasts and, as a result, the amounts we report in our results can vary significantly as a result of changes in factors, many of which are beyond our control.
UK Decommissioning Fund
As discussed in the preceding section under UK GAAP, we rely on an actuarially determined assumed annual rate of return on the assets of the Decommissioning Fund that is recorded in our profit
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and loss account as a revalorization credit for UK GAAP. Under US GAAP, the assets of the Decommissioning Fund are classified as “available-for-sale” securities and are recorded at market value. Unrealized gains and losses resulting from changes in the market value of the securities in the Decommissioning Fund that are deemed to be temporary are excluded from the profit and loss account until realized and instead are reported within other comprehensive income as a separate component of equity shareholders’ funds. However, if the assets of the Decommissioning Fund continue to perform poorly, we are required to review the decline in the Decommissioning Fund’s value for an impairment that could potentially be considered to be “other-than-temporary” and would result in a charge to our profit and loss account rather than to shareholders’ equity. In arriving at a conclusion as to whether or not an impairment is considered to be temporary or “other-than-temporary”, we consider the following factors:
| • | Current market conditions |
| • | Earnings and dividends of the assets and investments comprising the Decommissioning Fund |
| • | Security ratings on the investments |
| • | Financial condition of the underlying investments |
We are required to make significant judgments and estimates in reviewing the assets of the Decommissioning Fund for an “other-than-temporary” impairment. The actual returns on the assets of the Decommissioning Fund can vary significantly from our estimate and market assumptions, and may therefore result in an inappropriate adjustment to our earnings.
In arriving at the market value of our investments in the Decommissioning Fund at March 31, 2003, we reviewed the decline in value of the Decommissioning Fund’s assets for impairment. Based on our review, we recognized a £94 million charge to our US GAAP net loss as we deemed a portion of the decline in value in the Decommissioning Fund to be “other-than-temporary”. As at March 31, 2004 the market value of the Decommissioning Fund had increased to £440 million, thereby necessitating an exceptional credit of £59 million for the year ended March 31, 2004 to reverse previously written-down amounts. As a result of the Decommissioning Fund receivable being restated at market value, a £13 million exceptional credit has been recorded in operating costs to reverse a prior write-down of non-operational assets, and exceptional credits of £46 million have been recorded in finance charges for the year ended March 31, 2004 to reverse the prior write-down of previous revalorization.
Pensions
As discussed in the preceding section under UK GAAP, we expense the cost of providing pension benefits over the average expected service life of eligible employees applying SSAP24. Additionally, we have provided the transitional disclosure requirements as prescribed by FRS 17.
Under US GAAP, we follow the accounting principles of FAS 87 and FAS 132R, which set out the accounting and disclosure requirements for pensions. We use an actuarial method for determining the pension costs and net pension liability or asset. Periodic pension costs are comprised of service and interest costs together with amortization of deferred actuarial gains and losses and offset by the expected return on plan assets. In computing our pension expense and obligation, significant assumptions and estimates are applied including:
| • | future rate of returns on pension assets |
| • | interest rates used in the valuation of benefit obligations |
| • | timing of employee retirements. |
Changes in these assumptions may result in a different pension expense and obligation than that presented in our financial statements.
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UK GAAP to US GAAP Reconciliation
Restatement of Results
Year ended March 31, 2004
We adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“FAS 143”) as of April 1, 2003.
We determined that application of Statement of Financial Accounting Standards No. 109 Accounting for Income Taxes (“FAS 109”) as a result of our adoption of FAS 143 did not appropriately record the tax impact for the year ended March 31, 2004. Consequently, we have restated our 2004 consolidated financial statements in accordance with U.S. GAAP to reflect the correct allocation of income tax expense/benefit between income from continuing operations and the cumulative effect of a change in accounting as of April 1, 2004.
The impact of the restatement on the US GAAP financial statements is as follows:
| March 31, 2004 |
||||||||||||||||||
| As previously reported |
Impact of Restatement |
As restated |
||||||||||||||||
| £m |
Earnings per share |
£m |
Earnings per share |
£m |
Earnings per share |
|||||||||||||
| Profit/(loss) under US GAAP before cumulative adjustment for FAS 143 |
2,023 | 336 | p | (2,101 | ) | (349 | )p | (78 | ) | (13 | )p | |||||||
| Cumulative adjustment for FAS 143 (net of tax) |
5,539 | 920 | p | 2,101 | 349 | p | 7,640 | 1,269 | p | |||||||||
| Profit/(loss) under US GAAP for the year |
7,562 | 1,256 | p | — | — | 7,562 | 1,256 | p | ||||||||||
| Deficit on equity shareholders’ funds under US GAAP |
(1,562 | ) | — | — | — | (1,562 | ) | — | ||||||||||
We adopted Statement of Financial Accounting Standards (“FAS”) 133—“Accounting for Derivative and Hedging Activities”, as amended—(‘FAS 133’), as of April 1, 2001.
Years ended March 31, 2002 and 2003
Upon adoption of FAS 133, we identified certain electricity purchase and sale contracts as being derivatives in accordance with FAS 133. For the years ended March 31, 2002 and 2003 certain of these contracts were not included in the annual mark to market calculations on the basis that they qualified for the Normal Purchase Normal Sale (“NPNS”) scope exemption.
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During the year ended March 31, 2004 we adopted FAS 149—“Accounting for Derivative and Hedging Activities”. As part of the process of implementing FAS 149 we conducted a broader review of our compliance with derivative accounting regulation. During this exercise, the Group determined that the analysis supporting NPNS, and the documentation of compliance with the requirements of FAS 133 was not sufficient to support the accounting method previously applied. As a result of the review we determined that it was necessary to restate the results for 2002 and 2003. The impact of the restatement on the US GAAP financial statements is as follows:
| March 31, 2003 |
March 31, 2002 |
||||||||||||||||||||||||||||||||||
| As previously reported |
Impact of Restatement |
As restated |
As previously reported |
Impact of Restatement |
As restated |
||||||||||||||||||||||||||||||
| £m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
||||||||||||||||||||||||
| US GAAP net loss (net of tax) before cumulative adjustment for FAS 133 |
(7,732 | ) | (1,284 | )p | (68 | ) | (12 | )p | (7,800 | ) | (1,296 | )p | (337 | ) | (56 | )p | 80 | 13p | (257 | ) | (43 | )p | |||||||||||||
| Cumulative adjustment for FAS 133 (net of tax) |
— | — | — | — | — | — | (89 | ) | (15 | )p | 3 | 1p | (86 | ) | (14 | )p | |||||||||||||||||||
| Loss for the year under US GAAP |
(7,732 | ) | (1,284 | )p | (68 | ) | (12 | )p | (7,800 | ) | (1,296 | )p | (426 | ) | (71 | )p | 83 | 14p | (343 | ) | (57 | )p | |||||||||||||
| Tax Effect of US GAAP adjustments |
959 | — | 31 | — | 990 | — | 65 | — | (35 | ) | — | 30 | — | ||||||||||||||||||||||
| Deficit on equity shareholders’ funds under US GAAP |
(9,245 | ) | — | 15 | — | (9,230 | ) | — | (1,228 | ) | — | 83 | — | (1,145 | ) | — | |||||||||||||||||||
Reconciling items
Under US GAAP a charge of £225 million was recorded in the financial year ended March 31 2004. The difference was the result of the reversal of £295 million of impairment charges incurred in the prior year for UK GAAP. Under US GAAP, reversal of previously incurred impairment charges are not permitted. This was partially offset by £70 million of expenses incurred under UK GAAP were permitted to be capitalized under US GAAP.
We adopted FAS 143 at April 1, 2003, resulting in a change in our methodology of recording asset retirement obligations related to decommissioning costs and back end fuel costs. Under FAS 143, asset retirement obligations are recorded at fair value, determined by discounting the expected future cash flows at the credit adjusted risk free rate.
As a result of adopting FAS 143 and using a higher discount rate than under UK GAAP, we recorded a benefit for decommissioning costs and back end fuel costs of £13 million and £37 million, respectively. Additionally, the cumulative adjustment of adopting FAS 143 was a benefit of £7,640 million (net of tax of £273 million) (as restated). Corresponding adjustments to shareholders deficit for decommissioning costs and back end fuel costs was £663 million and £1,624 million, respectively. The adjustments are described more fully in note 36, as restated, of our audited consolidated financial statements.
As at March 31, 2004, our total undiscounted estimated costs in respect of back-end fuel costs and decommissioning, stated at current prices, were £9.9 billion for back-end fuel costs and £5.1 billion for decommissioning. See note 22 to our audited consolidated financial statements.
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During the year we disposed of our 50% interest in AmerGen. Due to the cumulative effect of differences between UK GAAP and US GAAP, AmerGen had a higher carrying value under US GAAP and therefore the sale resulted in a US GAAP loss on disposal. Under US GAAP, the profit after tax for the year ended March 31, 2004 was £7,562 million and the loss for the year ended March 31, 2003 was £7,800 million (as restated), compared with a profit of £234 million for the year ended March 31, 2004 and a loss of £3,941 million for the year ended March 31, 2003 under UK GAAP.
The deficit on equity shareholders’ funds under US GAAP at March 31, 2004 and March 31, 2003 were £(1,562) million and £(9,230) million (as restated) compared with equity shareholders’ funds of £(3,257) million and £(3,476) million respectively under UK GAAP. Differences primarily result from the adoption of FAS 143 (including decommissioning costs and back-end fuel costs and the deferred tax implications of these adjustments). See note 36 (as restated) to our audited consolidated financial statements.
New Accounting Standards
UK Accounting Standards
There is one new accounting standard that could have a potentially significant impact on our reported results that we have not yet implemented. FRS 17 sets out the requirements for disclosure and measurement of retirement benefits, including pensions. FRS 17 replaces SSAP 24 and discloses deferred benefit pension scheme surpluses or deficits on the balance sheet and accounts for all annual movements in pension scheme valuations through the profit and loss account and statement of total recognized gains and losses. The date for full adoption of FRS 17 is June 2005. However, we have complied with the applicable disclosure provisions by meeting the disclosures set out in Note 25 to our consolidated financial statements regarding the potential impact of FRS 17 on our balance sheet at March 31, 2004.
US Accounting Standards
In January 2003, the Financial Accounting Standards Board issued FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51.” FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have no contractual relationship or other business relationship with a variable interest entity and, therefore, we do not expect that the adoption of FIN 46 will have a material effect on our consolidated financial position, results of operations or cash flows.
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ITEM 6. DIRECTORS, SENIOR MANAGERS AND EMPLOYEES
Directors and Senior Management
We operate under the overall direction of our Board of Directors. Our Articles of Association provide that the number of Directors shall not, unless or until otherwise determined by an ordinary resolution, be less than four or more than 15. This provision of the Articles of Association may not be amended without the consent of the Special Shareholder (the Government). The Articles of Association also provide that at every annual general meeting of shareholders one third (or the number nearest to but not less than one third) of the Directors shall retire from office. The Directors to retire in each year are the Directors who have been longest in office since their appointment or re-appointment. Directors who retire by rotation in this manner are eligible to stand for re-election. The Directors may, at any time, appoint any person to be a director. Any person so appointed will hold office until the next annual general meeting of shareholders and shall then be eligible for election. The Directors may appoint one or more of their number to the office of Managing Director or to any other executive office for such period and on such terms as the Directors think fit. With the exception of Mr. Gatto all executive Directors have one-year rolling employment contracts with us. Mr. Gatto has a fixed term contract which terminates on December 31, 2004. The executive officers have contracts that are terminable by us on one year’s notice. It is our policy that Non-Executive Directors are appointed for a three-year term, renewable for a further three-year term on the basis of satisfactory performance, except where they are required to stand for re-election under the Articles of Association.
The name, title, age and date appointed of each of our Non-Executive Directors, our Executive Directors and our executive officers as at March 31, 2004Q were as follows:
| Name |
Title |
Age |
Date appointed | |||
| Adrian Montague•¨ |
Chairman | 56 | November 28, 2002 | |||
| Mike Alexander †§¨ |
Chief Executive | 56 | March 1, 2003 | |||
| David Gilchrist †#§¨à |
Managing Director, Generation | 51 | September 1, 2001 | |||
| Martin Gatto§¨O |
Interim Finance Director | 53 | December 8, 2003 | |||
| Ian Harley +*•¨ |
Independent Director | 53 | June 1, 2002 | |||
| William Coley +•†*¨ |
Independent Director | 60 | June 1, 2003 | |||
| Pascal Colombani†¨ |
Independent Director | 58 | June 1, 2003 | |||
| Sir Robert Walmsley*•#+†¨ |
Independent Director | 63 | August 1, 2003 | |||
| John Delucca+¨ |
Independent Director | 60 | February 9, 2004 | |||
| Clare Spottiswoode +*•¨ |
Deputy Chairman and Senior Independent Director | 51 | December 1, 2001 | |||
| Robert Armour § |
Company Secretary and General Counsel | 44 | December 13, 1995 | |||
| Sally Smedley § |
Director, Human Resources | 54 | February 8, 1999 | |||
| Terry Brookshaw §< |
Director, Power and Energy Trading | 58 | September 25, 2000 |
| + | Denotes member of the Audit Committee. |
| * | Denotes member of the Remuneration Committee. |
| • | Denotes member of the Nominations Committee. |
| # | Denotes member of the Safety, Health and Environment Committee. |
| † | Denotes member of the Nuclear Performance Review Committee. |
| § | Denotes member of the Executive Committee. |
| ¨ | Denotes member of the British Energy plc Board. |
| < | Terry Brookshaw ceased to be Director of Power and Energy Trading on May 4, 2004. He was succeeded as Director of Power and Energy Trading by Neil O’Hara (aged 37). |
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| Q | Roy Anderson (aged 54) joined British Energy as Chief Nuclear Officer and was appointed a member of the Executive Committee with effect from July 5, 2004. He was appointed as a Director of British Energy plc on September 16, 2004. The appointment of Roy Anderson as Chief Nuclear Officer is to be approved by the NII pursuant to our site license. We expect this approval to be forthcoming. For the purpose of this document we refer to Roy Anderson as Chief Nuclear Officer on this basis. Stephen Billingham (aged 46) joined British Energy as Finance Director Designate on August 25, 2004. He was appointed as Finance Director on September 16, 2004. David Pryde (aged 54) was appointed as an Independent Director on September 1, 2004. |
| à | David Gilchrist resigned from the British Energy plc Board on August 5, 2004. |
| O | Martin Gatto resigned from the British Energy plc Board on September 16, 2004 and was appointed Chief Financial Officer on the same date as part of ongoing hand over arrangements following Stephen Billingham’s appointment as Finance Director. |
The written consent of the Special Shareholder is required for the appointment of the Chairman of the Board. As part of the agreements related to the Restructuring entered into with certain creditors, we have agreed to appoint two Directors to be proposed by the ad hoc committee representing the bondholders provided that the nominees met certain conditions relating to skills, suitability and independence. John Delucca and David Pryde were nominated by the ad hoc committee and appointed as Directors in furtherance of this agreement. There are no other arrangements or understandings between any Director or executive officer and any other person pursuant to which such director or executive officer was selected to serve. There are no family relationships between any of our Directors or executive officers.
Adrian Montague joined British Energy as Chairman in November 2002 and also held an executive role until the appointment of Mike Alexander as Chief Executive in March 2003. He is currently also Chairman of Michael Page plc, Deputy Chairman of Network Rail, Chairman of Infrastructure Investors Limited and a senior international adviser to Société Generale and a non-executive director of Cellmark AB. A law graduate of Cambridge University, he was a partner with Linklaters & Paines, before joining Kleinwort Benson as Head of the Project and Export Finance Department in 1993, and subsequently became Global Head of Project Finance of Dresdner Kleinwort Benson in 1997. Then he undertook a number of senior roles in the implementation of the Government’s private finance policies, serving as the Chief Executive of the Treasury Taskforce from 1997-2000, and as Deputy Chairman of Partnerships UK plc, and a Private Finance Advisor to the Department of the Environment, Transport and The Regions between 2000 and 2001. In September 2002 he was appointed to head the review team monitoring London’s Crossrail project. He was awarded a CBE in 2001. He is Chairman of the Nominations Committee.
Mike Alexander was appointed as Chief Executive in March 2003. Prior to joining British Energy he was Chief Operating Officer and Executive Board Member of Centrica plc, and before that Managing Director of British Gas Trading. After graduating from Manchester University with a BSc in Chemical Engineering and an MSc in Control Engineering he joined BP, undertaking a number of operational plant improvement, engineering, corporate planning and business development projects throughout the world. He joined British Gas in 1991 as Commercial Director of BG Exploration & Production Limited and was a Director of several overseas exploration and production subsidiaries, becoming Managing Director of British Gas Supply Limited. Whilst at British Gas he directed their move into the deregulated electricity market and oversaw the launch of the Goldfish credit card. He is a Chartered Engineer and Chartered Scientist and a Fellow of the Institute of Chemical Engineers, the Institute of Electrical Engineers and the Institute of Gas Engineers. He is a Non-Executive Director of Associated British Foods plc and was previously Chairman of AG Solutions Limited, Hydrocarbons Resources Limited, Goldfish Bank Limited and a Non-Executive Director of The Energy Saving Trust.
David Gilchrist was appointed Managing Director of British Energy Generation in 2002 . Formerly Executive Vice President, Finance of Bruce Power LP between 1999 and 2001, having previously been
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Financial & Commercial Director, British Energy North America. He was Executive Director, Finance of Nuclear Electric Limited from 1996 to 1998. After graduating from Cambridge University with a degree in engineering he worked in the UK and US at Caterpillar and Ford of Europe as well as a period with PA Management Consultants. A Chartered Engineer and member of the Institution of Mechanical Engineers, he was Business Development Director, Automotive at GKN plc from 1988 before joining Nuclear Electric in 1991. He was elected as the UK Representative on the Governing Board of the WANO Paris Centre in 2003. Mr Gilchrist resigned from the Board of Directors on August 5, 2004.
Martin Gatto was appointed Interim Finance Director in December 2003. He is a Fellow of the Chartered Institute of Management Accountants. Prior to joining British Energy he was Interim Chief Financial Officer at Midlands Electricity plc and was Group Finance Director at Somerfield plc between 1993 and 2002. He holds a degree in Polymer Technology from Brunel University and started as a graduate trainee with 3M UK. Subsequently he was Deputy Group Controller of Lex Service plc, and Financial Controller, Brewing, and Pubs and Leisure for Grand Metropolitan plc. He joined Hilton International in 1983, becoming Chief Financial Officer and Development and Property Director before becoming Chief Financial Officer of Sun International in 1991. In January 2004 he joined the board of Luminar plc as a Non-Executive Director and he is also a Non-Executive Director of Cox & Kings Travel Limited. Martin Gatto resigned from the Board of Directors on September 16, 2004 and was appointed Chief Financial Officer on the same date.
Ian Harley was appointed as an independent Non-Executive Director in 2002 and Chairman of the Audit Committee. He joined Abbey National in 1977 where he held a variety of posts in the Finance, Retail Banking and Wholesale Banking Divisions before joining the Board in 1993. He spent nine years on the Board as first Finance Director, then Chief Executive, before retiring in 2002. An Economics graduate of Edinburgh University, he is a Fellow of the Institute of Chartered Accountants and a Fellow and Past President of the Institute of Bankers. He is currently a Non-Executive Director of Rentokil Initial plc and Remploy, a Governor of the Whitgift Foundation and a Vice-President of the National Deaf Children’s Society. Previously Chairman of the Association for Payment Clearing Services, a member of the Deposit Protection Board, appointed by the Bank of England, and a member of the Financial Services Authority’s Practitioner Panel. He is Chairman of the Audit Committee.
William Coley was appointed as an independent Non-Executive Director in 2003. He joined Duke Power, a major US utility company as an engineer in 1966, becoming Group President in 1997 and retiring from this position in 2003 after a 37 year career with the company. During his time at Duke Power he held a variety of management and executive roles including Vice-President, Central Division and Senior Vice-President, Power Delivery. He was elected to Duke Power’s Board of Directors in 1990, becoming Senior Vice-President, Customer Group and was President of the Associated Enterprises Group between 1994 and 1997. A Non-Executive Director of CT Communications Inc., SouthTrust Corporation and Peabody Energy (all publicly traded companies), and a director of ER Jahna Enterprises (a privately owned company) he holds a BSc in Electrical Engineering from the Georgia Institute of Technology. He is a registered Professional Engineer in North and South Carolina. He is Chairman of the Nuclear Performance Review Committee and a member of the Nominations and Audit Committees.
Pascal Colombani was appointed as an independent Non-Executive Director in 2003. He holds a doctorate in nuclear physics and is a former Chairman and CEO of the French Atomic Energy Commission. He was also formerly the Chairman (non-executive) of Areva, the nuclear engineering conglomerate, and a board member of Electricité de France and France Télécom. He is a member of the French Academy of Technology, an Associate Director at ATKearney and a board member of Alstom SA and of the French Institute of Petroleum.
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Sir Robert Walmsley was appointed as an independent Non-Executive Director in 2003. Previously he served in the Royal Navy where his final appointment was as Vice Admiral Controller of the Navy and member of the Navy Board as a Vice Admiral, starting in 1994. He was knighted in 1995. During his earlier naval career he held a number of nuclear related posts including service as the Chief Engineer of a nuclear submarine, Project Manager of a Nuclear Submarine Refit and Refuel, and Chairman of the Naval Nuclear Technical Safety Panel; he was Director General, Submarines between 1993 and 1994. He held roles in Procurement at the Ministry of Defense and was Executive Aide to the Chief of Defense Procurement between 1986 and 1987. After retiring from the Navy, he was appointed as Chief of Defense Procurement (a Permanent Secretary grade post in the Civil Service), occupying that position from 1996 until 2003. Holding an MA from Cambridge University and a postgraduate diploma in control engineering he also was awarded an MSc in Nuclear Science and Technology from the Royal Naval College. Earlier this year he was appointed as a Senior Adviser at bankers Morgan Stanley and was elected as an independent director of General Dynamics in the United States. He is Chairman of the Safety Health and Environment Committee and a Non-Executive Director of the Group’s licensed nuclear generator subsidiaries.
John Delucca was appointed as an independent Non-Executive Director in February 2004. He holds an MBA in Finance from Fairleigh-Dickinson University School of graduate study and a BA from Bloomfield College and has held a variety of senior roles in US business. Most recently, from 2003 until March of this year he was Executive Vice-President and Chief Financial Officer of the REL Consultancy Group. Prior to that from 1998 to 2002 he was Executive Vice-President, Finance and Administration and Chief Financial Officer of Coty Inc and a member of their Executive Committee. Between 1993 and 1998 he was Senior Vice-President and Treasurer of RJR Nabisco Inc., having previously held executive positions with Hasco Associates, a private investment group, the Lexington Group, providing financial consulting to distressed companies, the Trump Group and the International Controls Corporation, where he was Executive Vice-President and CFO as well as Chairman and CEO of a subsidiary, Transway Finance Company. He is a Non-Executive Director, and chairs the audit committees of, ITC Deltacom, Enzo Biochem and Elliott Company. He has been a lecturer at Forham University’s Graduate School of Business Administration and Adjunct Assistant Professor at Seton Hall University School of Business Administration. He is deputy chairman of the Audit Committee.
Clare Spottiswoode was appointed as an independent Non-Executive Director in 2001. Chair of the Remuneration Committee. Her career started as an economist with the Treasury before establishing her own software company. Between 1993 and 1998 she was Director General of Ofgas and has also served as a member of the Government’s Deregulation Task Force (1993) and the Public Services Productivity Panel (1998). Mrs Spottiswoode currently chairs Busy Bees Group Limited and Economatters Limited and was previously a Non-Executive Director of Booker plc. She is also currently a Non-Executive Director of Advanced Technology (UK) plc, Tullow Oil plc and Petroleum Geo-Services ASA. Awarded a CBE for services to industry in 1999, she holds degrees from Cambridge and Yale Universities. She is the Deputy Chairman, Chairman of the Audit Committee and a senior Independent Non-Executive Director.
Robert Armour was appointed Company Secretary in 1995 and General Counsel in 2003. A solicitor, he was a partner in Wright Johnston & Mackenzie, solicitors, between 1986 and 1990 before joining Scottish Nuclear as Company Secretary in 1990. He was Director of Performance Development for Scottish Nuclear between 1993 and 1995. From 1997 to 2003 he was Director of Corporate Affairs. He holds a law degree and MBA from Edinburgh University and has also attended INSEAD’s Advanced Management Program.
Sally Smedley was previously Human Resources and Corporate Relations Director at East Midlands Electricity plc, and Employee Relations Director, the BOC Group plc. She has a BSc (Tech) in Occupational Psychology.
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Terry Brookshaw was previously Energy Trading Manager for British Gas where he was responsible for helping to develop their electricity market entry strategy. He has a BSc in Physics and an MSc in Operational Research. He stepped down as Director, Power and Energy Trading on May 4, 2004.
Neil O’Hara was appointed as Director of Power and Energy Trading on May 4, 2004. He was previously employed by RWE Innogy and before that was Managing Director for strategy and business development at American Electric Power.
Roy Anderson was appointed Chief Nuclear Officer of British Energy on September 16, 2004. He was previously President of PSEG Nuclear in the US, and Chief Nuclear Officer of Nuclear Management Company and of Florida Power Corporation. His early career involved working for Caroline Power and Light Company, Boston Edison Company and General Electric Company, all in the US. He has a degree in marine and nuclear engineering and an MBA in operation research.
Robert Hill retired as an Independent Non-Executive Director on July 31, 2003. Keith Lough resigned as Finance Director on December 8, 2003 and Duncan Hawthorne resigned as Non-Executive Director on March 12, 2004.
Stephen Billingham joined as Finance Director Designate on August, 25 2004. As part of ongoing handover arrangements, he was appointed as Finance Director on September 16, 2004. On the same date Martin Gatto, formerly our Interim Finance Director, resigned as a Director and assumed the role of Chief Financial Officer. Steven Billingham was formerly Group Finance Director at WS Atkins plc. Prior to his role at WS Atkins plc, he led the finance team that concluded the Metronet London Underground Public Private Partnership.
David Pryde was appointed as an Independent Director on September 1, 2004. He has extensive trading and risk management experience. Having formerly headed precious metals trading in Asia for NM Rothschild and Sons Ltd and Philipp Brothers Inc. He joined JPMorgan & Co. Inc. in 1984 and has subsequently held various senior management positions in trading businesses, including Global Head of Precious Metals Trading, Global Head of Commodity Derivatives Trading and Marketing and Global Head of Futures and Options Brokerage. He sat on the Boards of the Commodity Exchange, the Chicago Mercantile Exchange and the Future Industry Association.
Other Directorships
Details of other directorships and outside interests of our directors and executive officers are as follows:
| Other Directorships/Outside Interests | ||
| Adrian Montague |
Crossrail; Network Rail; Michael Page International plc, Société | |
| Mike Alexander |
Associated British Foods plc | |
| David Gilchrist |
WANO Paris Centre | |
| William Coley |
CT Communications Inc; South Trust Corporation; Peabody Energy | |
| Pascal Colombani |
AT Kearney; Alstom | |
| Ian Harley |
Rentokil Initial plc; Remploy; Whitgift Foundation; National Deaf Children’s Society | |
| Clare Spottiswoode |
Advanced Technology (UK) plc; Busy Bees Limited; Economatters Ltd; Tullow Oil plc; Petroleum Geo-Services ASA | |
| Sally Smedley |
Remploy | |
| Robert Armour |
The Electricity Association; Scottish Council Development and Industry; Northmere Limited; British Nuclear Industry Forum Limited | |
| Martin Gatto |
Luminar plc; Cox & Kings Travel Limited | |
| John Delucca |
ITC Deltacom; Enzo Biochem; Elliott Company | |
| Sir Robert Walmsley |
General Dynamics; Morgan Stanley |
None of the other directors or executive officers had other business interests outside of British Energy.
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Compensation of Directors and Officers
During the year ended March 31, 2004, the aggregate amount of compensation we paid to all Executive and Non-Executive Directors and Executive officers was £2,662,253 (excluding pension contributions). During the year ended March 31, 2004, the aggregate amounts set aside or accrued to provide pension, retirement or similar benefits for Executive and Non-Executive Directors and executive officers, pursuant to any existing plan, was £2,460,000. Note 7 to the consolidated financial statements sets forth specific information regarding the emoluments and interests of individual Executive and Non-Executive Directors but does not address executive officers.
All of our Executive Directors are entitled to bonus payments under the Annual Incentive Plan. Bonus payments are determined by performance against a range of challenging targets underpinned by the safety and environmental priorities necessitated by the nature of our business.
In the year ended March 31, 2004, Executive Directors could be awarded cash payments of up to 60% of salary, depending on achievement of financial and other targets. In the year ended March 31, 2004, the plan included costs, output and operating cash flow targets, and was subject to an override reflecting the safety and environmental priorities necessitated by the nature of our activities.
During the year the Remuneration Committee determined that in the absence of any long-term incentive plan the bonuses earned by the Executive Directors and Executive Committee members in the year ended March 31, 2004 should be increased by a factor of 1.67. The Committee believes that this is reasonable both in the light of the absence of a long-term incentive plan and the stretch nature of the bonus target.
Service Contracts
We aim to set notice or contract periods for Executive Directors at one year or less. Where it is necessary to offer longer notice or contract periods to new Executive Directors recruited from outside the company, it is our policy to reduce the duration of these contracts as soon as possible after the initial period has expired. All of our Executive Directors currently have 12-month rolling contracts with the exception of Martin Gatto who has a fixed-term contract that will expire on December 31, 2004.
Independent and Non-Executive Directors
The remuneration of Non-Executive Directors is determined by the Board. Appointed for three-year terms, our independent and Non-Executive Directors do not have service contracts, are not eligible for any of our share schemes and do not receive any pension provision from us.
The expiry dates of the current Non-Executive Directors’ appointments are:
| Name |
Expiry Date | |
| W Coley |
31/05/2006 | |
| P Colombani |
31/05/2006 | |
| J Delucca |
31/01/2007 | |
| I Harley |
01/06/2005 | |
| A Montague |
01/12/2005 | |
| C Spottiswoode |
01/12/2004 | |
| R Walmsley |
31/07/2006 |
Board Practices
Remuneration Committee
The Remuneration Committee is concerned primarily with the pay, benefits and other employment conditions of Executive Directors. The Committee is made up entirely of Independent Directors. In
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addition, it retains an interest in the pay and benefits to other senior staff, to ensure reasonable consistency. The Terms of Reference for the Committee empower it to:
| • | establish the remuneration policies and practices for Executive Directors and certain other Directors and senior employees; |
| • | design and implement long-term incentive schemes; |
| • | determine and review the individual remuneration packages of the Executive Directors and other selected senior employees, including pension provision; |
| • | authorize the annual performance incentive plan for Executive Directors; and |
| • | obtain external professional advice and expertise necessary for the performance of its duties. |
Audit Committee
The Audit Committee is comprised entirely of Independent Non-Executive Directors. The Committee is responsible for reviewing the adequacy and effectiveness of our internal control and compliance procedures and ensuring that we comply with all statutory requirements in relation to the principles, policies and practices adopted in the preparation of the Financial Statements, including those arising as a result of the application of the Sarbanes-Oxley Act. The Committee reviews our risk management including actions to mitigate or control key risks. The Committee seeks the advice of both external and internal auditors in relation to matters arising from their work and is also responsible for encouraging and monitoring the adoption of Best Practice in Corporate Governance. The Committee also reviews the nature and extent of our external auditor’s non-audit services to ensure that a balance of objectivity, independence and value for money is maintained.
Nominations Committee
The Nominations Committee advises the Board in relation to our senior appointments. Board appointments recommended by the Committee are made after an appropriate search and selection process has been undertaken. The Committee is made up entirely of Non-Executive Directors.
Share Ownership
As of March 31, 2004, the total amount of voting securities owned by the Directors and executive officers, as a group was 18,891 ordinary shares, representing 0.003% of our issued and outstanding ordinary shares.
In addition, as of March 31, 2004, our Directors and executive officers as a group, held options to purchase 489,489 ordinary shares, all of which options were issued pursuant to our Executive Share Option Schemes or our Sharesave Scheme. This figure includes share options granted to Keith Lough which lapsed on that date when he ceased to be an employee. For further details see the section entitled “Executive share options” below.
Options to Purchase Securities from Registrant or Subsidiaries
We have established several share option schemes. The No. 1 Scheme has been designed for approval by the UK Inland Revenue under Schedule 9 of the UK Income and Corporation Taxes Act of 1988 and, consequently confers certain tax benefits on its participants. The No. 2 Scheme is an unapproved share option scheme and does not, therefore, confer any particular tax benefits on its participants. Collectively, the No. 1 Scheme and No. 2 Scheme are referred to as the “Executive Share Option Schemes”. In order to be eligible to participate in the Executive Share Option Schemes an individual must be a full time director or employee of British Energy. The No. 3 Scheme (the
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“All-Employee Share Option Scheme”) has been approved by the UK Inland Revenue and is available to all of our employees other than those who may participate in the Executive Share Option Schemes. There is also a Sharesave Scheme that is open to all our UK employees and full time Directors who have been continuously employed for such period as the Board may prescribe (not exceeding five years before the date the options are to be granted).
As at March 31, 2004 there were 3,620,248 options outstanding under the Executive Share Option Schemes, 14,537,004 options outstanding under the All-Employee Share Option Scheme, and 8,518,496 options outstanding under the Sharesave Scheme.
Detailed below are the No. 1 Scheme options held by Directors and executive officers as at March 31, 2004. These options become exercisable three years after the date of grant, subject to achievement of a performance condition.
At our Annual General Meeting in July 2001, our shareholders approved the All Employee Share Option Plan 2001, which revised the terms of the previous No. 3 Share Option Scheme. No options have been granted under this scheme.
The Shareholders also approved the Share Incentive Plan (SIP) 2001. The SIP is based on UK legislation, which permits favorable tax treatment under certain circumstances for employees who invest in their employing company. This plan has not been activated.
At our Annual General Meeting in July 2002 shareholders approved a new Executive Share Option Plan 2002 to replace the No. 1 and No. 2 Share Option Schemes. No options have been granted under the plan.
Directors’ Emoluments
During the year the Board reviewed the fees paid to non-executive Directors. On the basis of external advice, fees were reviewed effective from January 1, 2004 as follows:
| Independent/Non-Executive Director |
£ | 27,000 | |
| Additional fee for Deputy Chairman/Senior Independent Director |
£ | 25,000 | |
| Additional fee for Chairing Committees (per Committee) |
£ | 10,000 |
In addition, with effect from April 1, 2004, those Non-Executive Directors who travel from the USA receive £1,000 per Board meeting subject to a maximum of £10,000 per annum. Those who reside elsewhere outside the UK are paid £500 per meeting to a maximum of £5,000 per annum.
Adrian Montague’s base fee is £150,000 per annum but, because of the additional time commitment, his fees will be £300,000 per annum until the Restructuring is effective and binding on all interested parties, or until negotiations for a solvent restructuring are terminated. His service agreement also provides for additional lump sum fees to be paid when certain milestones related to the Restructuring are achieved.
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| Basic Salary and Fees(£) |
Bonus (£) |
Contingent Fees (£) |
Compensation for Loss of Office (£) | |||||||||||||
| Name |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 | ||||||||
| A Montague |
300,000 | 100,000 | — | — | — | 300,000 | — | — | ||||||||
| M Alexander |
400,000 | 33,333 | 190,004 | — | — | — | — | — | ||||||||
| W Coley(1) |
25,000 | — | — | — | — | — | — | — | ||||||||
| P Colombani(2) |
22,500 | — | — | — | — | — | — | — | ||||||||
| J Delucca(3) |
4,500 | — | — | — | — | — | — | — | ||||||||
| M Gatto(4) |
130,000 | — | 36,013 | — | — | — | — | — | ||||||||
| D Gilchrist |
199,013 | 183,563 | 106,105 | — | — | — | — | — | ||||||||
| I Harley |
36,500 | 25,833 | — | — | — | — | — | — | ||||||||
| C Spottiswoode |
59,000 | 53,333 | — | — | — | — | — | — | ||||||||
| R Walmsley(5) |
24,667 | — | — | — | — | — | — | — | ||||||||
| Total Emoluments for serving Directors at March 31, 2004 |
1,201,180 | 396,062 | 332,122 | — | — | 300,000 | — | — | ||||||||
| R Biggam |
— | 11,167 | — | — | — | — | — | — | ||||||||
| D Hawthorne(6) |
25,228 | 152,978 | — | — | — | — | — | — | ||||||||
| R Hill(7) |
19,167 | 57,500 | — | — | — | — | — | — | ||||||||
| R Jeffrey |
— | 309,188 | — | — | — | — | — | 98,000 | ||||||||
| M Kirwan |
— | 45,042 | — | — | — | — | — | — | ||||||||
| K Lough(8) |
151,975 | 211,250 | 73,679 | — | — | — | 145,625 | — | ||||||||
| P Stevenson |
— | 25,893 | — | — | — | — | — | — | ||||||||
| J Walsh |
— | 7,325 | — | — | — | — | — | — | ||||||||
| Total Emoluments (all Directors) |
1,397,550 | 1,216,405 | 405,801 | — | — | 300,000 | 145,625 | 98,000 | ||||||||
| Other Benefits (£) |
Total Emoluments Excluding Pension (£) |
Pension Contributions (£) | ||||||||||
| Name |
2004 |
2003 |
2004 |
2003 |
2004 |
2003 | ||||||
| A Montague |
— | 209 | 300,000 | 400,209 | — | — | ||||||
| M Alexander |
32,864 | 2,202 | 622,868 | 35,535 | 16,929 | 1,385 | ||||||
| W Coley(1) |
— | — | 25,000 | — | — | — | ||||||
| P Colombani(2) |
— | — | 22,500 | — | — | — | ||||||
| J Delucca(3) |
— | — | 4,500 | — | — | — | ||||||
| M Gatto(4) |
— | — | 166,013 | — | — | — | ||||||
| D Gilchrist |
15,247 | 20,067 | 320,365 | 203,630 | 16,929 | 12,020 | ||||||
| I Harley |
— | — | 36,500 | 25,833 | — | — | ||||||
| C Spottiswoode |
— | — | 59,000 | 53,333 | — | — | ||||||
| R Walmsley(5) |
— | — | 24,667 | — | — | — | ||||||
| Total Emoluments for serving Directors at March 31, 2004 |
48,111 | 22,478 | 1,581,413 | 718,540 | 33,858 | 13,405 | ||||||
| R Biggam |
— | — | — | 11,167 | — | — | ||||||
| D Hawthorne(6) |
— | 8,046 | 25,228 | 161,024 | — | 21,749 | ||||||
| R Hill(7) |
— | — | 19,167 | 57,500 | — | — | ||||||
| R Jeffrey |
— | 17,349 | — | 424,537 | — | — | ||||||
| M Kirwan |
— | 4,007 | — | 49,049 | — | 4,453 | ||||||
| K Lough(8) |
11,309 | 12,886 | 382,588 | 224,136 | 11,657 | 12,020 | ||||||
| P Stevenson |
— | — | — | 25,893 | — | — | ||||||
| J Walsh |
— | — | — | 7,325 | — | — | ||||||
| Total Emoluments (all Directors) |
59,420 | 64,766 | 2,008,396 | 1,679,171 | 45,515 | 51,627 | ||||||
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| Notes: |
| (1) | Appointed as Non-Executive Director on June 1, 2003 |
| (2) | Appointed as Non-Executive Director on June 1, 2003 |
| (3) | Appointed as Non-Executive Director on February 1, 2004 |
| (4) | Appointed as Executive Director on December 8, 2003 |
| (5) | Appointed as Non-Executive Director on August 1, 2003 |
| (6) | Retired as Executive Director on February 14, 2003. Appointed as Non-Executive Director on February 15, 2003 and resigned on March 12, 2004 |
| (7) | Retired as Non-Executive Director on July 31, 2003 |
| (8) | Resigned as Executive Director on December 8, 2003 |
Shares and Share Options
| Ordinary shares |
March 31, 2004 |
March 31, 2003 | ||
| A Montague |
2,188 | 2,188 | ||
| M Alexander |
0 | 0 | ||
| W Coley |
0 | 0 | ||
| P Colombani |
0 | 0 | ||
| J Delucca |
0 | 0 | ||
| M Gatto |
0 | 0 | ||
| D Gilchrist |
6,024 | 6,024 | ||
| I Harley |
2,000 | 2,000 | ||
| C Spottiswoode |
0 | 0 | ||
| R Walmsley |
0 | 0 |
There has been no change in Directors’ Shareholdings since March 31, 2004 and no Director has a non-beneficial interest in any of our shares.
Any ordinary shares required to fulfill entitlements under current option schemes may be provided by the British Energy Employee Share Trust (BEEST) an the Qualifying Employee Share Trust (QUEST). As beneficiaries under the BEEST and the QUEST, the Directors are deemed to be interested in the shares held by both Trusts, which, at March 31, 2004, amounted to 27,026,922 ordinary shares and 19,165,471 ‘A’ shares.
Executive share options
As at March 31, 2004 Directors’ interests in Executive and SAYE share options over ordinary shares were as follows:
| Name |
Options held at April 1, 2003 |
Options Granted during the year |
Options Exercised during the year |
Options Lapsed during the year |
Options held at March 31, 2004 |
Option (£) |
Date from which exercisable |
Expiry date | ||||||||
| D Gilchrist |
57,692 | — | — | — | 57,692 | 2.60 | 15/07/2000 | 14/07/2004 | ||||||||
| 11,538 | — | — | — | 11,538 | 2.60 | 15/07/2000 | 14/07/2007 | |||||||||
| 19,862 | — | — | — | 19,862 | 5.08 | 29/06/2001 | 28/06/2005 | |||||||||
| 21,379 | — | — | — | 21,379 | 5.295 | 25/06/2002 | 24/06/2006 | |||||||||
| 40,659 | — | — | — | 40,659 | 2.4125 | 14/07/2003 | 13/07/2007 | |||||||||
| 151,130 | — | — | — | 151,130 | ||||||||||||
| K Lough |
9,433 | — | — | — | 9,433 | 3.18 | 14/09/2004 | 13/09/2011 | ||||||||
| 116,353 | — | — | — | 116,353 | 3.18 | 14/09/2004 | 13/09/2008 | |||||||||
| 125,786 | — | — | — | 125,786 | ||||||||||||
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No. 1 Scheme Options
| Date of Grant |
Date when option expires |
Option price |
Number of Ordinary Option | ||||||
| D Gilchrist |
July 15, 1997 | July 14, 2007 | £ | 2.60 | 11,538 | ||||
| K Lough |
September 14, 2001 | September 13, 2011 | £ | 3.18 | 9,433 | ||||
| R Armour |
August 12, 1997 | August 11, 2007 | £ | 2.60 | 11,538 | ||||
| S Smedley |
February 8, 1999 | February 7, 2009 | £ | 6.67 | 4,497 | ||||
No. 2 Scheme Options
| Date of Grant |
Date when option expires |
Option price |
Number of Ordinary Option | ||||||
| D. Gilchrist |
July 15, 1997 | July 14, 2004 | £ | 2.60 | 57,692 | ||||
| June 29, 1998 | June 28, 2005 | £ | 5.08 | 19,862 | |||||
| June 25, 1999 | June 24, 2006 | £ | 5.29 | 21,379 | |||||
| July 14, 2000 | July 13, 2007 | £ | 2.41 | 40,659 | |||||
| K. Lough |
September 14, 2001 | September 13, 2008 | £ | 3.18 | 116,353 | ||||
| R. Armour |
August 12, 1997 | August 11, 2004 | £ | 2.60 | 19,243 | ||||
| June 29, 1998 | June 28, 2005 | £ | 5.08 | 11,392 | |||||
| June 25, 1999 | June 24, 2006 | £ | 5.29 | 25,436 | |||||
| July 14, 2000 | July 13, 2007 | £ | 2.41 | 43,523 | |||||
| S. Smedley |
February 8, 1999 | February 7, 2006 | £ | 6.67 | 15,368 | ||||
| June 25, 1999 | June 24, 2006 | £ | 5.29 | 25,023 | |||||
| July 14, 2000 | July 13, 2007 | £ | 2.41 | 56,373 | |||||
Robin Jeffrey and Duncan Hawthorne ceased to be Executive Directors during the fiscal year ended March 31, 2003. All share options granted to them lapsed on the dates when, respectively, Mr. Hawthorne ceased to be an Executive Director and when Dr. Jeffrey tendered his resignation. Keith Lough’s share options lapsed on March 31, 2004 when he ceased to be an employee.
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
Major Shareholders
Control of Registrant
We are not directly or indirectly owned or controlled by another corporation or by any government (except to the extent permitted by the Special Share, discussed below). The rights of the Government and certain creditors under the Restructuring are described in “Item 4. Information on the Company—Restructuring.” As at September 24, 2004 we had been notified of the following interests of 3% or more of the issued ordinary share capital of British Energy.
| Shareholder |
Percentage | |
| Brian J Stark |
10.66 | |
| Brandes Investment Partners |
6.92 | |
| UBS Investment Bank |
6.53 | |
| Polygon Investment Partners LLP |
5.69 | |
| Deutsche Bank AG |
4.97 | |
| The Goldman Sachs Group, Inc. |
4.26 | |
| British Energy Employee Share Trust |
3.50 |
The voting rights of holders of 3% or more of our ordinary shares do not differ from those of other shareholders.
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The shareholding held by British Energy Employee Share Trust at the year end in each of the previous three years was as follows:
| March 31, 2004 |
3.50 | % | |
| March 31, 2003 |
3.50 | % | |
| March 31, 2002 |
3.47 | % |
On March 31, 2004, there were 184 registered holders of 305,853 ordinary shares with addresses in the US. The combined holdings of these shareholders constituted less than 1% of the total number of ordinary shares outstanding. As certain of the ordinary shares are held by brokers and other nominees, these numbers may not be representative of the actual number of beneficial owners in the US or the number of ordinary shares beneficially held by US persons.
On March 31, 2004, there were 36 registered holders of 1,318,645 ADRs. The combined holdings of these shareholders constituted over 10% of the total number of ordinary shares outstanding. One ADR is equivalent to 75 ordinary shares.
We do not know of any current arrangements the operation of which may result in our change of control. However, if the Restructuring is completed, the NLF may, at its option, convert certain cash amounts due under the NLF cash sweep into ordinary shares of British Energy. Such option if effective and if exercised may result in a change of control. For additional information, see Note 1 to our consolidated financial statements.
Our share capital includes one special rights redeemable preference share, the Special Share, with a nominal value of £1.00. The Special Share may only be held by the Special Shareholder, which includes any of one or more of Her Majesty’s Secretaries of State, another minister in the UK Government, the Treasury Solicitor or any person acting on behalf of the UK Government. The Special Shareholder may require us to redeem the Special Share at any time after September 30, 2006 at its nominal value by giving us notice and delivering the relevant share certificate. The registered holder of the Special Share may attend and speak at any general or other meeting of holders of any class of our shares but has no right to vote at any such meeting.
Until such time as the Special Share is redeemed, our Articles of Association prohibit any person (other than certain permitted persons) from holding more than 15% of the voting rights of our issued share capital. We call this restriction the Limitation. Permitted persons are deemed to include any custodian or depositary who holds shares for the benefit of holders of our ADRs. However, permitted persons would not include a holder of ADRs which represent, in aggregate, a beneficial interest in more than 15% of the voting rights of our issued share capital. As long as the Limitation is in effect, we are required by our articles to enforce the Limitation (including, without limitation, withdrawal of voting rights of such shares and the forced sale of such shares).
The written consent of the Special Shareholder is required for each of the following:
| • | The amendment, removal or alteration of the effect of (including the ratification of any breach of) certain provisions of our Articles of Association, including the provisions with respect to the Special Share and the Limitation and the number of Directors who may be appointed to the Board of Directors. |
| • | The creation or issue of any of our shares carrying voting rights other than (a) shares carrying voting rights in all circumstances at general meetings of our shareholders and (b) shares which do not constitute equity share capital (as defined in the Companies Act) and which, when aggregated with all other such shares, carry the right to cast less than 15% of the votes capable of being cast at any general meeting of our shareholders. |
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| • | Variation of any voting rights attached to any class of shares. |
| • | The appointment of the Chairman of the Board. |
| • | The passing of a resolution for our voluntary winding up. |
| • | Any changes to the Articles of Association of our operating subsidiaries that would allow them to issue shares to any person other than us and the disposal by us of any such shares. |
As a consequence of the Restructuring it is likely that British Energy plc will become a wholly-owned subsidiary of a new parent company of the British Energy group following the Restructuring. As a result, the interests of existing shareholders are likely to be very substantially diluted. British Energy plc may subsequently be liquidated or dissolved, with all of its assets distributed to its creditors over time in accordance with the proposed scheme of arrangements. (see “Item 4. Information On The Company—Restructuring”)
Related Party Transactions
Interest of Management in Certain Transactions
There have been no material transactions during our most recent three fiscal years, nor are there presently proposed to be any material transactions to which we or any of our subsidiaries are or were a party and in which any Executive or Non-Executive Director, or 10% shareholder, or any relative or spouse thereof or any relative of such spouse, who had the same home as such person or who is a director or executive officer of any parent or subsidiary of British Energy had or is to have a direct or indirect material interest. Furthermore, during our most recent three fiscal years there has been no, and at present there is no, outstanding indebtedness to us or any of our subsidiaries owed or owing by any of our Executive or Non-Executive Directors or any associate thereof.
Duncan Hawthorne, who was an Executive Director of the company until February 15, 2003 was also Chief Executive Officer of Bruce Power. Following the sale of our interest in Bruce Power which was completed on that date, Mr. Hawthorne remained as Chief Executive of, and as an employee of, Bruce Power. After that date he ceased to be an Executive Director, and became a Non-Executive Director of British Energy. Mr. Hawthorne resigned as a Non-Executive Director on March 12, 2004.
See “Item 18. Financial Statements”.
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Nature of Trading Market
The principal trading market for our ordinary shares is the London Stock Exchange. In addition, American Depositary Shares, or ADSs, (each of which represents 75 ordinary shares) are issued by Morgan Guaranty Trust Company of New York, as depositary for our ADRs, or the Depositary. Prior to October 31, 1999, neither ordinary shares nor American Depositary Receipts were listed or quoted on any recognized stock exchange in the United States. The table below sets forth, for the calendar quarters of each year indicated, the highest and lowest middle-market quotations (the closing price quoted for a security on any given day on the London Stock Exchange as published in the Daily Official List of the London Stock Exchange) for the ordinary shares.
| Ordinary Shares(1) |
ADSs(2) | |||||||
| High |
Low |
High |
Low | |||||
| (in pence) | (in dollars) | |||||||
| QUARTERLY |
||||||||
| 1999 |
||||||||
| Third |
591.00 | 405.00 | — | — | ||||
| Fourth |
444.50 | 345.00 | 24.38 | 23.00 | ||||
| 2000 |
||||||||
| First |
399.75 | 175.25 | 25.88 | 11.06 | ||||
| Second |
205.00 | 119.50 | 12.50 | 7.25 | ||||
| Third |
262.00 | 165.00 | 16.19 | 10.38 | ||||
| Fourth |
258.00 | 162.25 | 14.81 | 9.50 | ||||
| 2001 |
||||||||
| First |
295.50 | 193.00 | 17.35 | 11.75 | ||||
| Second |
324.00 | 228.50 | 19.10 | 13.20 | ||||
| Third |
337.00 | 256.75 | 19.40 | 14.45 | ||||
| Fourth |
293.00 | 219.00 | 16.60 | 12.90 | ||||
| 2002 |
||||||||
| First |
259.75 | 175.00 | 14.96 | 10.20 | ||||
| Second |
190.00 | 161.00 | 10.94 | 9.42 | ||||
| Third |
171.50 | 5.00 | 9.15 | 0.50 | ||||
| Fourth |
16.88 | 5.15 | 1.07 | 0.36 | ||||
| 2003 |
||||||||
| First |
7.50 | 3.20 | 4.93 | 0.22 | ||||
| Second |
7.17 | 3.50 | 8.72 | 4.05 | ||||
| Third |
6.75 | 3.50 | 7.96 | 4.25 | ||||
| Fourth |
5.50 | 4.03 | 6.90 | 5.53 | ||||
| 2004 |
||||||||
| First |
10.25 | 4.21 | 13.70 | 5.94 | ||||
| Second |
14.30 | 7.00 | 19.29 | 9.79 | ||||
| MONTHLY |
||||||||
| January |
5.85 | 4.21 | 8.40 | 5.94 | ||||
| February |
10.25 | 6.25 | 13.70 | 8.87 | ||||
| March |
8.00 | 6.50 | 11.08 | 9.09 | ||||
| April |
12.30 | 7.00 | 16.27 | 9.79 | ||||
| May |
14.30 | 9.81 | 19.29 | 13.27 | ||||
| June |
14.00 | 11.60 | 18.90 | 16.07 | ||||
| July |
22.25 | 14.50 | 30.60 | 20.09 | ||||
| August |
21.50 | 19.00 | 30.20 | 26.00 | ||||
| September(3) |
24.75 | 15.25 | 32.50 | 18.51 | ||||
| (1) | The past performance of the ordinary shares is not necessarily indicative of future performance. |
| (2) | In order to meet the minimum price criteria set by and following discussions with the New York Stock Exchange (NYSE), on |
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| March 7, 2003 we announced that we would change the ratio of our shares traded on the NYSE. The effect of the change would be to alter this ratio from one ADR to four ordinary shares, to a new ratio of one ADR to 75 ordinary shares. This change became effective on March 18, 2003. |
| (3) | Through September 23, 2004. |
On September 5, 2002, our Board of Directors announced that it had initiated discussions with the UK Government with a view to seeking immediate financial support to implement a longer-term financial restructuring. The Board of Directors decided to initiate discussions with the UK Government based on several factors including: (i) its review of our revised forecast for UK nuclear generation for the fiscal year ending March 31, 2003 (which indicated output of approximately 63 TWh as compared with the original target output of 67.5 TWh, due to unplanned outages particularly those at our Torness and Dungeness B nuclear power stations), (ii) the failure of our negotiations with BNFL to reach agreement on the terms of our fuel contracts, and (iii) the review of our long-term prospects. At close of business on September 5, 2002, certain of our securities including our ordinary shares listed in London and our ADRs traded on the New York Stock Exchange were subjected to temporary trading suspensions on the London Stock Exchange and the New York Stock Exchange respectively. Our ordinary shares and our ADRs resumed trading on the London Stock Exchange and the New York Stock Exchange on September 9, 2002. We announced on September 23, 2004 that we would be applying to the UKLA to cancel the listing of our ordinary and A shares. As a consequence the NYSE suspended trading in our ADRs prior to the opening of trading on September 28, 2004. At that time, the NYSE also instituted delisting proceedings.
ITEM 10. ADDITIONAL INFORMATION
Material Contracts
Disposals
| (a) | Master purchase agreement, dated October 10, 2003, by and between British Energy Investment Limited (“BEIL”) and Exelon Generation Company, LLC (“Exelon”) relating to the disposal of British Energy plc’s entire 50% interest in AmerGen Energy Company LLC (“AmerGen”) (the “New AmerGen Agreement”). |
In consideration of the disposal of its entire 50% interest in AmerGen, British Energy plc received initial consideration of US$277 million upon financial closing on December 22, 2003 prior to adjustments for working capital levels, unspent nuclear fuel, inventory, capital expenditure and low level waste disposal costs.
BEIL gave standard representations and warranties to Exelon, in relation to, inter alia, the business and affairs of AmerGen. The obligations of British Energy plc to indemnify Exelon in respect of losses suffered by it in respect of such representations and warranties are broadly subject to a minimum aggregate loss threshold of $5,000,000. Only aggregate claims in excess of the threshold are to be indemnified. There is a maximum claims limit of 75% of the purchase price following adjustment. In addition, British Energy plc has agreed to indemnify Exelon in respect of losses suffered by it in relation to the allegations of environmental violations resulting from specified recent events at one of AmerGen’s plants which resulted in the death of numerous fish near the plant. This indemnity is not subject to the above-mentioned thresholds, but is not likely to be material.
The New AmerGen Agreement is governed by and construed in accordance with the domestic laws of the State of New York.
| (b) | Master purchase agreement dated September 11, 2003 and made between BEIL and FPL Nuclear Mid-Atlantic, LLC (FPL) (the Original AmerGen Agreement). |
The principal terms of the Original AmerGen Agreement are substantially identical to those of the New AmerGen Agreement save that references in the description of the New AmerGen Agreement to Exelon as the buyer should be construed instead as references to FPL Nuclear Mid-Atlantic, LLC and
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the break fee arrangements are slightly different. As a result of the exercise by Exelon of its right of first refusal to purchase British Energy plc’s interest in AmerGen on the same terms as those offered to FPL (arising under a limited liability company agreement relating to AmerGen dated August 1, 2000 and amended on December 21, 2001 and May 1, 2002), the Original AmerGen Agreement terminated on October 13, 2003 following the service by British Energy plc of a formal notice to that effect on FPL.
| (c) | A Master Purchase Agreement dated January 17, 2003 for the disposal of British Energy’s interest in Bruce Power Limited Partnership (“Bruce Power”) (“the Disposal”) was entered into between, among others, British Energy and (i) Cameco Corporation (“Cameo”), (ii) BPC Generation Infrastructure Trust (“BPC”) and (iii) TransCanada Pipelines Limited (“TransCanada”) (together, the “Consortium”). |
The Disposal was effected by the sale of the entire issued share capital of British Energy (Canada) Limited (“BECL”) to a newly incorporated Ontario Corporation funded by the Consortium. The total consideration payable by the Consortium was C$950 million subject to certain adjustments. The Consortium paid C$100 million of the total consideration directly to the Provincial Government of Ontario, Canada as a one-off allowance and restructuring fee. C$100 million of the consideration was contingent upon the restart of two Bruce A units, and, to date, we have received C$30 million of such sum following the restart of unit 4 in the third quarter and unit 3 in the fourth quarter of 2003/04. A further C$80 million was held in escrow to cover the estimated outstanding tax liabilities of the Bruce Group following an interim refund of some C$3 million and the balance has been remitted to the tax authorities in Ontario. An additional C$20 million is held in escrow to cover successful claims in respect of representations and warranties for such period until all claims made against British Energy and British Energy International Holdings Limited (“BEIHL”) within two years from the completion of the Disposal are resolved. Finally, we received C$20 million in April 2003 which had been retained in escrow following completion in respect of a possible price adjustment relating to pensions following confirmation that no such adjustment was required.
Pursuant to binding heads of agreements entered into in November and December 2002 between British Energy and certain of its subsidiaries, the Power Workers’ Union Trust No.1 and The Society of Energy Professionals Trust (together “the Unions”) consented to the transaction under the Limited Partnership Agreement in consideration of Bruce Power Investments Inc (“BPII”) forgiving loans of approximately C$16.2 million made to the Unions to allow them to acquire their initial 2.6% interest in Bruce Power and fund subsequent capital calls, and the transfer by BPII to the Unions of an additional 2.6% interest in Bruce Power in aggregate immediately prior to the completion of the Disposal.
British Energy and BEIHL have jointly and severally given extensive representations and warranties to the Consortium in relation to, inter alia, the business and affairs of the Bruce Group. The obligations of British Energy and BEIHL to indemnify the Consortium in respect of any breach of such representations and warranties are mostly subject to a minimum claims limit of C$20 million, a maximum claims limit of C$1,175 million and customary time limits.
The Consortium have, upon completion of the Disposal, assumed responsibility for all of British Energy’s obligations as credit support provider and/or guarantor under Bruce Power’s existing Trading Contracts. The Consortium also took over British Energy’s financial assurance obligations to Bruce Power in respect of the CNSC License upon completion of the Disposal. In addition, pursuant to the OPG Heads, the Consortium assumed responsibility for the C$175 million guarantee granted by British Energy to OPG under the Lease and the Lease Guarantee and British Energy was released from these obligations and the Consortium put Bruce Power in funds to pay the C$225 million of deferred rent payment due by Bruce Power to OPG at the date of completion of the Disposal which was further condition to the OPG Heads. British Energy has no further obligation to OPG in respect of rent payments.
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British Energy will provide support services as requested from time to time by Bruce Power to support plant operations for a period of four years on terms to be agreed between British Energy and Bruce Power, acting reasonably.
Neither British Energy nor any of its affiliates will for a period of two years from the disposal (i) solicit any of BPII or Bruce Power’s existing employees; or (ii) become involved in nuclear power generation operations in Canada.
Cameco already holds a 15% interest in Bruce Power and BPII through its subsidiary Cameco Bruce Holdings Inc. (“CBHI”) and the Unions together hold a 2.6% interest in Bruce Power. Each of the Consortium members will own a 31.6% interest in Bruce Power and a 16.7% interest in Huron Wind as a result of the disposal. The Bruce Workers’ Union Trust No. 1 will have a 4.0% interest in Bruce Power and The Society of Energy Professionals Trust will have a 1.2% interest in Bruce Power. BPII will be entirely owned by the Consortium.
The Master Purchase Agreement is governed by the laws of the province of Ontario.
Standstill and Restructuring
| (d) | Creditor Restructuring Agreement dated October 1, 2003 (as amended by a side letter entered into on October 31, 2003) and entered into by British Energy plc, certain other Group companies, Enron Capital & Trade Europe Finance Limited (“ECTEF”) Teesside Power Limited, (“TPL”), Total Gas & Power Limited (“Total”) (ECTEF, TPL and Total collectively, the “Significant Creditors”), the Royal Bank of Scotland plc (“RBS”), the members of the ad hoc committee of British Energy plc’s Bondholders and British Nuclear Fuels plc (“BNFL”) (the “Creditor Restructuring Agreement”). |
On October 1, 2003, Bondholders representing in aggregate with RBS 88.8% of the combined amount owing to Bondholders and RBS signed up to the Creditor Restructuring Agreement, and all of the lenders and swap providers in the Eggborough Bank syndicate, (each, an “Eggborough Bank”) also entered into the Creditor Restructuring Agreement, they (and RBS) having obtained credit committee approvals by such date. A summary of the key terms and conditons of the Creditor Restructuring Agreement is set forth in “Item 4. Information on the Company—Restructuring.”
| (e) | Standstill Agreement entered into on February 14, 2003 between RBS, Barclays Bank PLC, the Eggborough Banks, Significant Creditors and BNFL (the “Creditors”) and British Energy plc and certain of its subsidiaries (the “Old Standstill Agreement”) as replaced by a new standstill agreement entered into by the parties (and their successors in title) to the Old Standstill Agreement on February 13, 2004 (the “New Standstill Agreement”)). |
During the period of the standstill, the Creditors agreed that they would not take any steps to initiate insolvency proceedings or demand or accelerate any amounts due and payable by us. The original standstill period would have terminated on the earliest of: (i) September 30, 2004; (ii) the occurrence of a termination event, and (iii) the completion of the Restructuring (the “Standstill Period”). Under the terms of the New Standstill Agreement, the Standstill Period was extended until the earliest of: (i) the Restructuring Long Stop Date (as defined in the Creditor Restructuring Agreement); (ii) the date British Energy receives a termination notice; and (iii) the date on which the Restructuring becomes effective. Under the terms of the New Standstill Agreement certain Significant Creditors will be paid interest but not principal in respect of their claims against us. Interest will continue to be paid to the Eggborough Banks in accordance with existing arrangements. In respect of TPL, Deutsche Bank, AG London, ECTEF and RBS, interest was to be paid first on March 25, 2003 and then on the last business day of every six-month period thereafter based on the agreed amounts which such creditors
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were claiming against us (except in the case of RBS where interest payments were to be based on the then present value of its claim amount).
Any of the Creditors has the right to terminate the New Standstill Agreement following the occurrence of a termination event. Termination events include certain insolvency events affecting British Energy plc, BEG, BEG UK, BEPET or EPL, acceleration of the Government Facility, and any of British Energy plc, BEG UK, BEG, BEPET or EPL failing to discharge certain continuing obligations.
The termination events are set out in full in the new Standstill Agreement which is set forth as an exhibit to this Form 20-F. See “Item 19. Exhibits”.
| (f) | Government Restructuring Agreement entered into between British Energy plc and certain of its subsidiaries, the Nuclear Generation Decommissioning Fund Limited (to be renamed the NLF) and the trustees of the Nuclear Trust on October 1, 2003. |
This agreement sets out the circumstances in which the Secretary of State will support the Restructuring, including entering into the agreements with us, and in certain cases the NLF, which effect the proposals regarding the manner in which the decommissioning and other uncontracted liabilities of the Group are to be funded and the agreements relating to the funding of certain of the contracted nuclear liabilities of the Group (the “Nuclear Liabilities Agreements”). It also effects some further amendments to the Government Facility described in paragraph (g) below.
Under the Government Restructuring Agreement, the obligations of the Secretary of State to support the Restructuring (including as the holder of a number of special shares) and of the parties to the Nuclear Liabilities Agreements to enter into them are conditional on, inter alia:
| • | the Creditor Restructuring Agreement becoming effective (save for the extension of the standstill arrangements which is immediately effective) by October 31, 2003 or such later date as the Secretary of State may agree; |
| • | the Creditor Restructuring Agreement becoming unconditional in all respects by the earlier of 120 days following the date that the initial conditions to implementation of the Restructuring (as set out in the Creditor Restructuring Agreement) are satisfied and January 31, 2005 (“Restructuring Longstop Date”); |
| • | the Secretary of State not having determined and notified British Energy plc in writing that, in her opinion, the Group (including British Energy Group plc and British Energy Holdings plc, the public companies incorporated pursuant to the Restructuring) will not be viable in all reasonably foreseeable conditions without access to additional financing (other than financing which the Secretary of State is satisfied has been committed and will continue to be available when required); |
| • | there being no continuing event of default under the Government Facility; |
| • | receipt by the Secretary of State of copies of letters from the Group’s auditors and financial advisers giving the confirmations referred to in the terms of Rule 2.18 of the UKLA Listing Rules without qualification (whether or not British Energy Group plc is to be listed on the Official List of the UKLA) (without imposition of any duties, or increase in the liabilities of these advisers beyond those which would otherwise apply). (The confirmations referred to relate to the requirement for the provision by British Energy Group plc of an unqualified working capital statement which would be required to be produced by it in its listing particulars were it to be listed pursuant to the Restructuring); |
| • | the representations and warranties given by British Energy plc parties in the Government Restructuring Agreement being true, accurate and not misleading when given and if repeated at the effective date of the Restructuring; and |
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| • | there being no breach of any undertaking given by any British Energy plc party under the Government Restructuring Agreement which, in the opinion of the Secretary of State, is or is likely to be material in the context of the Restructuring. |
If any of the above conditions are not fulfilled or waived by the Secretary of State by the time specified in the requisite condition or if no such date is specified, by the Restructuring Longstop Date, the Government Restructuring Agreement will terminate and if a material adverse change (as defined) occurs at any time before the order sanctioning the Restructuring Scheme is filed with the registrar of companies in Scotland, the Secretary of State may give written notice to British Energy plc to terminate the Government Restructuring Agreement.
Financings
| (g) | Credit facility agreement (the “Government Facility”) dated September 26, 2002 (as amended) between, among others, the (i) Secretary of State and (ii) British Energy plc, BEG UK, BEG and BEPET as borrowers and (iii) British Energy plc, BEG UK, BEG, BEPET, BEIL, District Energy Limited and BEIHL as Guarantors (the borrowers and guarantors (including Peel Park Funding Limited) are together referred to as the Obligors). |
All obligors have given some security for obligations under the Government Facility.
The original facility amount was £650 million; the total facility amount now is £200 million. The Government Facility consists of a £175 million collateral facility and a £25 million working capital facility. The facilities have an availability period ending on September 30, 2004 (subject to extension at the discretion of the Secretary of State), although the Secretary of State can require earlier repayment if, inter alia, that is required by the Commission or under European law or if she is of the opinion that the Restructuring cannot be implemented in the manner or time envisaged in the Creditor Restructuring Agreement (the Final Maturity Date). Each loan made pursuant to the Government Facility is repayable no later than the Final Maturity Date.
Mandatory prepayment events under the agreement include if (1) the initial conditions set out in the Creditor Restructuring Agreement are not satisfied on or before November 30, 2004; or such later date as the Secretary of State may in writing agree; (2) the restructuring date, (as defined in the Creditor Restructuring Agreement) does not occur by the Restructuring Longstop Date; and (3) Any restructuring Agreement (as defined in the Government Facility, to include the Creditor Restructuring Agreement and the Government Restructuring Agreement) is terminated before the date on which the documentation required to give effect to the Restructuring is filed.
The obligors make and repeat customary representations and warranties. The obligors have given covenants appropriate to their financial situation and the nature of their business. A cash sweep mechanism is included by which on the first business day in each week, all cash not forecast to be required to meet payments of members of the Group incorporated or otherwise carrying on business in the UK in the following seven day period shall, to the extent that it exceeds £10 million, be deposited in a cash reserve account (the Cash Reserve Account) which is secured in favor of the Secretary of State. Events of default include, inter alia, non-payment, breach of obligations, misrepresentation, cross-default, material judgments or orders being made, distress, sequestration or other process being levied/enforced, occurrence of insolvency related events, material litigation, seizure, change in control and breach of law. The Government Facility is governed by English law.
| (h) | Bondholder Restructuring Agreement |
A Bondholder Restructuring (Standstill) Agreement dated February 14, 2003 was entered into between British Energy plc, BEG and BEG (UK) and (i) certain Bondholders owning 58% of the £109,861,000 5.949% Guaranteed Bonds due 2003 (the “2003 Bonds”), (ii) certain Bondholders owning 55% of the £163,444,000 6.077% Guaranteed Bonds due 2006 (the “2006 Series Bonds”) and (iii) certain Bondholders owning 75% of the £134,586,000
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6.202% Guaranteed Bonds due 2016 (the “2016 Series Bonds”) (collectively known as the “Bondholders” and the 2003 Bonds, the 2006 Series Bonds and 2016 Series Bonds, together (the “Bonds”).
The Bonds were issued by British Energy on March 25, 1999. The principal amount outstanding of the 2003 Bonds is £109,861,000. The scheduled maturity date was March 25, 2003. Interest at 5.949% per annum is payable on March 25, in each year. The principal amount outstanding of the 2006 Bonds is £163,444,000. The scheduled maturity date is March 25, 2006. Interest at 6.077% per annum is payable on March 25, in each year. The principal amount outstanding of the 2016 Bonds is £134,586,000. The scheduled maturity date is March 25, 2016. Interest at 6.202% per annum is payable on March 25, in each year. The trustee of the Bonds is the Law Debenture Trust Corporation (the “Trustee”).
Pursuant to the Bondholder Restructuring (Standstill) Agreement, during the Standstill Period (the period commencing on February 14, 2003 and ending on September 30, 2004, or the earliest of a termination event or the completion of the Restructuring), British Energy plc will continue to pay interest on the Bonds (at the current rate(s) on the full principal amounts outstanding on the Bonds), but on a semi-annual basis after the annual payment to be made on March 25, 2003. The scheduled redemption of the 2003 Bonds will be deferred until the end of the Standstill Period or, if later, in circumstances where there is no event of default subsisting, the date on which such Bonds would otherwise become due and payable. The holders of each series of Bonds and the other affected Significant Creditors will not be able to accelerate their claims or commence insolvency or other proceedings against British Energy plc and certain of its subsidiaries.
The Supplemental Trust Deeds (constituting the standstill arrangements in respect of the relevant series of Bonds) entered into by the Trustee can be terminated upon, amongst other things, the receipt by British Energy of a lawful notice of termination by the Trustee. The Trustee would serve such a notice of termination if it is requested in writing to do so by the holders of at least 50% in aggregate principal amount outstanding of the relevant series of Bonds (and provided it has been indemnified to its satisfaction) following the occurrence of a Termination Event (as defined in the Bondholder Restructuring (Standstill) Agreement), which includes failure to pay interest on the Bonds when due and such failure continues for 20 business days. Each and every Supplemental Trust Deed also contains undertakings by British Energy plc, BEG and BEG (UK) concerning the way in which their business is carried on during this Standstill Period. If any of these undertakings is breached, the Supplemental Trust Deed can be terminated if such breach is not remedied within seven days of the date on which the Trustee serves a notice on British Energy plc (and copied to the UK Secretary of State) requiring remedy and either (i) the Trustee certifies to the Issuer that such breach is, in the opinion of the Trustee, materially prejudicial to the interests of the Bondholders or (ii) the Trustee is requested to do so by the holders of at least 50% in principal amount outstanding of the relevant series of Bonds and has been indemnified to its satisfaction.
| (i) | Supplemental Trust Deed (which constitutes the standstill arrangements in respect of the Bonds) entered into by British Energy plc, BEG, BEG UK and the Trustee (the “First Supplemental Trust Deed”). |
Pursuant to a resolution of the Bondholders passed on March 24, 2003, the First Supplemental Trust Deed was entered into on March 31, 2003. The First Supplemental Trust Deed implements certain standstill arrangements with respect to the Bonds and can be terminated upon, among other things, the receipt by British Energy plc of a lawful notice of termination by the Trustee. The Trustee would serve such a notice of termination if it is requested in writing to do so by the holders of at least 50% in aggregate principal amount of the Bonds then outstanding (and provided it has been indemnified to its satisfaction) following the occurrence of a termination event, which includes failure to pay interest on the Bonds when due and such failure continues for 20 business days.
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The First Supplemental Trust Deed also contains undertakings by British Energy plc, BEG and BEG UK concerning the way in which their businesses are carried on during this Standstill Period. If any of these undertakings is breached, the First Supplemental Trust Deed can be terminated if such breach is not remedied within seven days of the date on which the Trustee serves a notice on British Energy plc (and copied to the Secretary of State) requiring remedy and either (i) the Trustee certifies to the Issuer that such breach is, in the opinion of the Trustee, materially prejudicial to the interests of the Bondholders or (ii) the Trustee is requested to do so by the holders of at least 50% in principal amount
outstanding of the relevant series of Bonds and has been indemnified to its satisfaction.
The BNFL Contracts
| (a) | The Deed of Amendment and Guarantee between British Energy Generation Limited (“BEG”), British Nuclear Fuels plc (“BNFL”) and British Energy plc dated March 31, 2003 (as amended on July 22, 2003 and October 30, 2003) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors between Nuclear Electric Limited and BNFL dated June 3, 1997, as amended. |
This amendment gives effect to certain changes to the fuel supply arrangements and inserts new arrangements in relation to the supply of uranics used in the AGR fuel fabrication process and enriched uranium for on-supply by BEG to its PWR fuel fabricator. The amendments contained in the deed became effective on April 1, 2003 however, (except in relation to the amendments relating to the new uranics arrangements which are not subject to conditionality), the amendments are subject to a number of termination conditions relating to the Restructuring of the British Energy Group. In the event that the conditions are not satisfied (or waived) by January 31, 2005, the existing agreement will continue in force as if the deed had never been entered into (except in relation to the new uranics arrangements as noted above).
The main amendments effected by the deed relate to:
| • | the reduction of the fixed annual payment by an agreed sum and a discount (which is calculated across both the BEG and the British Energy Generation (UK) Limited (“BEG (UK)”) AGR fuel supply agreement in accordance with wholesale baseload electricity prices. |
| • | the insertion of additional exceptions to the general prohibition on assignment of rights under the agreement without the consent of the other party (not to be unreasonably withheld) permitting both BNFL and BEG to assign rights under the fuel supply agreement without consent and or on certain conditions. |
| • | an additional obligation on the parties to provide assistance to HMG in relation to the State Aid notification and to notify the agreements to the competition authorities. |
| • | the insertion of a parent company guarantee by British Energy plc under which British Energy plc guarantees the performance of BEG under BEG’s existing AGR fuel supply agreement as amended by the deed. British Energy plc’s liability under the guarantee is expressed to be no greater than the liability of BEG under the agreement. Where British Energy plc ceases to be the ultimate holding company of BEG, it must notify BNFL and assign certain contracts which it has entered into with BNFL. |
| • | the insertion of a new provision whereby British Energy plc and BEG acknowledge and agree that no member of the Group will bring any claim against BNFL that the terms of the existing agreement/deed or the heads of terms dated November 28, 2002 between BNFL and British Energy plc infringe competition law or that the “hardship” provisions of the existing agreement may be invoked. |
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| • | new uranics arrangements under which BNFL will supply uranics to BEG for an initial firm period of seven years which either BEG or BNFL may terminate on 12 month’s notice (but not before the end of the sixth year) or earlier for non-performance by BNFL. This initial term is divided across BEG’s existing fuel supply agreement and its new post 2006 fuel supply agreement (described in paragraph (b) below). BNFL is to supply BEG with uranics for the purposes of fabrication into AGR fuel in accordance with a procurement policy and a procurement strategy, and is required to provide certain information to BEG on a regular basis. BEG is required to pay variable charges to BNFL relating to the uranics contained in the fabricated fuel supplied to BEG, incidental services (such as transport, insurance, cylinder washing, cylinder hire or uranic analysis), administration based on the quantity of stocks held by BNFL for the purposes of supplying fuel to BEG under BEG’s fuel supply agreement and procurement and management services. |
Stock is to be repurchased by BEG in the event that the value of BEG’s forecast of stock cover at the end of the first month of BEG’s 12 months forecast exceeds certain levels under the existing fuel supply agreement), and BNFL is to buy back and use any stock repurchased by BEG prior to purchasing any new uranium material. BEG has rights to step into the uranics supply arrangements and procure uranics required under the existing fuel supply agreement (at the sole cost of BNFL) in the event that the level of uranium material available for BEG for the purposes of fabricating into fuel under the fuel supply agreement falls below a percentage of forward months’ fuel requirements for a period of three months (subject to a grace period).
Upon the expiry or early termination of the uranics supply arrangements, BEG must repurchase all stock maintained by BNFL for the purposes of supplying fuel under BEG’s fuel supply agreement and take back all contracts novated to BNFL as well as all new contracts entered into by BNFL for the supply of uranics and/or for conversion or enrichment services in order to supply BEG with fabricated fuel (subject to consent of the counterparties). The stock repurchase will be immediate upon the expiry or elective termination of BEG or BNFL, and will take place over a period of five years in accordance with an agreed schedule where BEG terminated for breach by BNFL.
| (b) | An Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation Limited (“BEG”), British Nuclear Fuels plc (“BNFL”) and British Energy plc, dated March 31, 2003, (as amended on July 22, 2003 and October 30, 2003). |
This agreement is based on BEG’s existing AGR fuel supply agreement and incorporates the new provisions inserted into BEG’s existing AGR fuel supply agreement by way of the deeds of amendment (entered into in 2003 as described above in paragraph (a)). Subject to satisfaction of the conditions described above, the agreement will take effect on April 1, 2006 and continue until the end of the fuel supply period (defined as the date following which no further AGR fuel is loaded into any AGR reactor of either BEG or British Energy Generation (UK) Limited (“BEG (UK)”).
The main differences between the new post 2006 agreement and BEG’s existing AGR fuel supply agreement as amended by the deeds of amendment (entered into in 2003 as described above in paragraph (a)) are:
| • | the annual fixed charge is £25.5 million. This charge is adjusted in the same way as described above in relation to the deeds of amendment (entered into in 2003 as described above in paragraph (a)); |
| • | BNFL agrees to provide certain services relating to AGR fuel required as a result of the closure of a station (for example, the decommissioning or refurbishment of surplus fuel stocks and the return of or storage of surplus fuel) (on terms and conditions to be agreed); and |
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| • | the prices for the supply of ancillary components will be derived by adding an engineering, procurement and warranty charge to the buying-in price of externally sourced components. The prices charged to BEG will be reviewed annually. |
| (c) | A Deed of Amendment and Guarantee between British Energy Generation (UK) Limited (“BEG (UK)”), British Nuclear Fuels plc (“BNFL”) and British Energy plc, dated March 31, 2003 (as amended on July 22, 2003 and October 30, 2003) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors between Scottish Nuclear Limited and BNFL dated March 30, 1995 as amended. |
The amendments contained in this deed are as set out above in paragraph (a) respect of the deed of amendment to British Energy Generation Limited’s existing fuel supply agreement, except in relation to the uranics arrangements which will essentially continue as set out in BEG (UK)’s existing fuel supply agreement. All amendments contained in this deed are subject to the same conditionality as described in relation to the deed of amendment to BEG’s existing fuel supply agreement described above in paragraph (a).
| (d) | An Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation (UK) Limited (“BEG (UK)”), British Nuclear Fuels plc (“BNFL”) and British Energy, dated March 31, 2003 (as amended on July 22, 2003 and October 30, 2003). |
This agreement is based on BEG (UK)’s existing fuel supply agreement as amended by the deeds of amendment entered into in 2003 as described above, and is subject to the same conditionality as the deeds of amendment to the BEG and BEG (UK) existing fuel supply agreements and the BEG new post 2006 fuel supply agreement.
| (e) | A Deed of Sale and Purchase of Enriched and Natural Uranium Stocks between British Energy Generation Limited (“BEG”), British Nuclear Fuels plc (“BNFL”) and British Energy plc, dated March 31, 2003 as amended on October 13, 2003, November 26, 2003, February 20, 2004, April 5, 2004 and June 10, 2004. |
This deed provides for the purchase by BNFL of BEG’s existing stocks of uranium material with an approximate value of £60 million. The sale of the stocks was arranged to take place in several tranches: on March 31, 2003, July 1, 2003 and further interim sales on dates nominated by BEG (the last date being August 31, 2004) (comprising all remaining stocks which could not be transferred on the date of the second sale). A reconciliation to market prices of the stocks transferred in the second and further sales will be reconciled following audit certification.
The deed also provides for the transfer to BNFL of BEG’s third party contracts relating to the supply of uranium ore, uranium hexafluoride and/or the provision of conversion or enrichment services by August 31, 2004. An interim pass-through of the contracts applies between March 31, 2003 (the completion of the first sale) and the final completion date under which BEG will perform the contracts upon BNFL’s instructions, and an ongoing pass-through of all contracts applies in respect of those contracts which the parties have not been able to novate to BNFL (e.g. because of failure to obtain counter party consent) until the earlier of the date of expiry or early termination of the relevant contracts and the date on which the term of the uranics supply arrangement under the fuel supply agreements ends.
Reciprocal provisions apply under which the liability of BEG and BNFL is capped (except in relation to BNFL’s obligation to pay the purchase price of the stocks sold under the agreement) and indirect losses are excluded (except in relation to payments under the indemnities in connection with the pass-through arrangements described above).
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| (f) | An End of Life Program: Transmittal Letter from British Nuclear Fuels plc (“BNFL”) to British Energy dated February 14, 2003, acknowledged by British Energy on March 31, 2003. |
This side letter provides for the establishment of a joint team to study the end of life optimization program for AGR power stations with a view to lowering the full costs of production of AGR fuel and sharing the benefits. The prices for AGR fuel, when this is being loaded into three or fewer stations, will be set on the basis of the recommendations of this team (which is required to meet formally at least annually). The respective parties are to provide an update on progress towards station lifetime extension and/or station closure and progress against the Springfields Transformation Plan, and are required to submit a report to the parties containing their recommendations as to certain matters.
| (g) | An agreement dated March 31, 2003 between British Energy Generation Limited (“BEG”), Magnox Electric plc (“Magnox”), BNFL and British Energy plc for the implementation of the Passport 9 asset management software. |
Under an agreement signed in 1996, BEG currently provides Magnox with computer services to host the asset management software entitled “Passport”, and to provide fault and maintenance support for emergency services. BEG uses Passport to manage its own power stations and has recently upgraded to a new version of the software. Under a computer services agreement signed on March 31, 2003, BEG is to assist Magnox in its upgrade to a new version of Passport. The upgrade is expected to be completed by the end of March 2005. The 1996 agreement, which was due to expire on March 31, 2004, was extended on March 31, 2003 to last until end March 2005, at a cost to Magnox of £1.5 million.
Under the new computer services agreement BEG is to receive £10 million annually from Magnox paid in equal monthly installments, which are accelerated if the project is completed ahead of schedule. A one-off amount is payable at the start of the contract period in respect of project set-up costs. Two costs are payable by Magnox during the lifetime of the project: a fixed monthly amount in respect of mainframe costs; and a variable amount in respect of external consultants’ costs. The latter are to be borne equally by BEG and Magnox up to a cap of £1 million annually for BEG. Once BEG has borne £1 million of external consultants’ costs in a year, any further costs are to be paid for entirely by Magnox. Magnox’s payment obligations are guaranteed by BNFL, its parent company. British Energy plc is a party to the agreement for the purposes of guaranteeing the performance of BEG’s obligations should BEG transfer its rights and obligations under the agreement or subcontract it to another group company.
| (h) | An agreement for new spent fuel management services between British Nuclear Fuels plc, (“BNFL”) British Energy Generation Limited (“BEG”), British Energy Trading Services Limited and British Energy plc dated May 16, 2003 (as amended on October 30, 2003) (“BEG New Spent Fuel Agreement”). |
This agreement is based on the current Spent Fuel Management Agreement dated June 3, 1997. It, together with the BEG (UK) New Spent Fuel Agreement described in paragraph (i) below, (together the “New Spent Fuel Agreements”) provides for BNFL to manage irradiated AGR fuel arising from fuel which was loaded to the AGR reactors on or after the effective date, until the final delivery of irradiated fuel from the last AGR station to shut down including final cores. The effective date is the date following the date on which certain conditions relating to the Restructuring of the British Energy Group are satisfied or waived. These conditions apply to both the AGR Fuel Supply Agreements described in paragraphs (a) to (d) above and the other spent fuel management and ancillary services agreements and deeds of amendment described below. None of these spent fuel management related agreements and deeds of amendment become effective until these conditions precedent have either been satisfied or, in certain cases, waived by BNFL.
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The main features of the BEG New Spent Fuel Agreement are as follows:
| • | Under the BEG New Spent Fuel Agreement, BNFL will take title to all irradiated AGR fuel on collection by BNFL of such fuel from the power stations. Under the current spent fuel arrangements, although risk passes to BNFL on collection of the fuel, title to the fuel and most of the waste products deriving therefrom remains with BEG, who is therefore obliged to remove and be responsible for the ultimate disposal of these products and wastes at the end of the contracted storage period. Under the BEG New Spent Fuel Agreement, BNFL will be responsible for managing and ultimately disposing of the irradiated AGR fuel at its sole discretion. |
| • | The pricing provisions under the BEG New Spent Fuel Agreement differ substantially from the current arrangements. BEG will make one-off payments to BNFL in respect of the each tonne of uranium contained in the fuel, such payments being linked to the time of first loading of such fuel into a reactor rather than the date on which it is actually delivered to BNFL as irradiated fuel, which will in most cases be some 5-10 years later. The payment structure is also subject to a rebate/surcharge mechanism linked to wholesale electricity prices, giving BEG a two-way hedge against these prices. |
In relation to the main payment, BEG will pay BNFL a price of £150,000 (in 2002/03 money and thereafter escalated in accordance with RPI) per tonne of uranium. The surcharge/rebate is calculated according to a formula based on the amount of BEG/BEG(UK) output.
Invoicing will be on a monthly basis and will be based on agreed estimates of loading, coupled with an estimated rebate or surcharge. An annual reconciliation will be carried out. In the event that the annual reconciliation reveals that the payments that should have been made by BNFL to BEG exceed those from BEG to BNFL, then the reconciliation amount will be adjusted so that the total payments from BNFL to BEG equal those from BEG—i.e. there will never be a net payment from BNFL to BEG in a year.
In addition to the above, BEG must pay BNFL all those incremental costs incurred by BNFL in handling, storing and disposing of any non-standard fuel over and above those costs that BNFL would have incurred in respect of an equivalent quantity of fuel that meets the specification.
| • | British Energy plc is a signatory as guarantor in respect of its subsidiaries’ obligations (both financial and performance). |
| (i) | An agreement for new spent fuel management services between British Nuclear Fuels plc, British Energy Generation (UK) Limited (“BEG (UK)”), British Energy Trading Services Limited and British Energy dated May 16, 2003 (as amended on October 30, 2004) (“BEG (UK) New Spent Fuel Agreement”). |
The BEG (UK) New Spent Fuel Agreement is equivalent to the BEG New Spent Fuel Agreement and is based on the Agreement for the Long-Term Storage of Irradiated Fuel dated March 30, 1995. It is subject to the same conditionally as that agreement as described in paragraph (h) above.
| (j) | A deed of amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), dated May 16, 2003, and as amended in October 30, 2003, relating to the agreement for the storage and reprocessing of irradiated oxide fuel and related services between British Nuclear Fuels plc and Nuclear Electric plc dated March 31, 1995, as amended and novated (“BEG 1995 Historic Fuel Agreement”). |
This deed of amendment amends and restates the BEG 1995 Historic Fuel Agreement so that, together with the amended and restated agreements (described below in paragraphs (k), (l) and (m)), (together, the “Historic Fuel Agreements”) it covers the management of irradiated AGR fuel which has
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already been delivered to BNFL’s Sellafield facility, which is currently in the reactors, or in spent fuel storage at the stations or which is to be loaded into the reactors prior to the effective date. The effective date is the date following the day on which certain conditions in relation to the proposed Restructuring of the British Energy Group are satisfied or waived.
The services provided under this amended and restated agreement are the same as, and on the same terms as, those currently provided under the existing agreement. The primary difference between the existing agreement and this amended version are:
| • | consequential amendments that are necessary to reflect that while the existing BEG 1995 Historic Fuel Agreement (together with the existing versions of the other Historic Fuel Agreements) covered the lifetime arisings from the power stations, the amended and restated BEG 1995 Historic Fuel Agreement, together with the amended and restated versions of the other Historic Fuel Agreements, now only deal with fuel loaded into the reactors prior to the effective date, on which date the BEG (UK) New Spent Fuel Agreement and the BEG New Spent Fuel Agreement described above will come into play; and |
| • | the current payment provisions have been replaced by a fixed monthly payment schedule. Payments for services, beyond the standard services, such as extended storage or treatment of non-standard fuel are not covered by the scheduled monthly payments. |
| • | this agreement terminates immediately upon the occurrence of the appointment of a liquidator in respect of BEG or the making of a court order, or the passing of a resolution, for the winding-up or dissolution of BEG (other than for the purposes of a solvent amalgamation or reconstruction) and BNFL shall also be entitled to terminate the Historic Fuel Agreements to which BEG is a party on the occurrence of the appointment of a liquidator or the making of a court order, or the passing of a resolution, for the winding-up or dissolution (other than for the purposes of a solvent amalgamation or reconstruction) in respect of BEG (UK) or British Energy plc or (where British Energy plc is no longer BEG’s ultimate holding company) BEG’s ultimate holding company. |
| (k) | A Deed of Amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”) dated May 16, 2003 (as amended on October 30, 2003), relating to the Agreement for Spent Fuel Management Services between BNFL and Nuclear Electric Limited dated June 3, 1997, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG 1995 Historic Fuel Agreement.
The current payment provisions have been removed and payment for services provided under this agreement is covered by the monthly payments made by BEG pursuant to the amended and restated BEG 1995 Historic Fuel Agreement described in paragraph (j) above.
| (l) | A Deed of Amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”) dated May 16, 2003 (as amended on October 30, 2003), relating to the Agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995, as amended, and to the agreement for the Long Term Storage of Irradiated Oxide Fuel and Related Services dated March 30, 1995 between BNFL and Scottish Nuclear Limited, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG 1995 Historic Fuel Agreement in paragraph (j).
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As with the Historic Fuel Agreements, to which BEG is a counterparty, (as described above), the current payment provisions of the agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995 and the agreement for the Long Term Storage of Irradiated Oxide Fuel and Related Services dated March 30, 1995 between BNFL and Scottish Nuclear Limited have been replaced by a fixed monthly payment schedule which appears in the amended and restated agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995 and which will be determined on the effective date. These payments cover the provision of services by BNFL to BEG (UK) under the agreement for the Storage and Reprocessing of Irradiated Oxide Fuel and Related Services between BNFL and Scottish Nuclear Limited dated March 30, 1995 and the agreement for the Long Term Storage of Irradiated Oxide Fuel and Related Services dated March 30, 1995 between BNFL and Scottish Nuclear Limited as well as the provision of services to BEG (UK) under those agreements described in paragraphs (q), (r), (s) and (t). Payments for services, beyond the standard services, such as extended storage or treatment of non-standard fuel are not covered by the scheduled monthly payments.
| (m) | A Deed of Amendment between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”) dated May 16, 2003 (as amended on October 30, 2003), relating to the agreement for Oxide Flask Maintenance between BNFL and Nuclear Electric plc dated March 31, 1996, as amended and novated (“BEG Flask Maintenance Agreement”). |
The amendments to the BEG Flask Maintenance Agreement and the agreements described in paragraphs (n), (o), (p), (q), (r), (s) and (t) below (together the “Ancillary Agreements”) are essentially consequential amendments required to reflect the new structures of the New Spent Fuel Agreements and Historic Fuel Agreements described in paragraphs above.
Termination provisions, equivalent to those described in respect of the Historic Fuel Agreements above, appear in the amended and restated versions of this agreement and the other Ancillary Agreements. However, such termination rights are limited to the historic fuel component of such agreements—i.e. the provision of services in respect of fuel loaded into British Energy’s AGR reactors prior to the effective date. The reason for this is that these Ancillary Agreements support both the New Spent Fuel Agreements (described in paragraphs (h) and (i)) and the Historic Fuel Agreements (described in paragraphs (j), (k) and (l)). The New Spent Fuel Agreements do not contain such a termination provision and, accordingly, in the event that the Historic Fuel Agreements terminate, the services provided under the Ancillary Agreements would still be needed in respect of the New Spent Fuel Agreements.
An additional amendment has also been made in respect of this agreement and the BEG (UK) 1996 Flask Maintenance Agreement described in paragraph (q). Monthly payments were due under those agreements have been removed as they are now covered by the new payment schedules in the Historic Fuel Agreements described in paragraphs (j), (k) and (l).
| (n) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), relating to the new agreement for Oxide Flask Maintenance between BNFL and Nuclear Electric Limited dated June 3, 1997, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
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| (o) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), relating to the agreement for Rail Transport Services of Irradiated Nuclear Fuel in the United Kingdom between BNFL and Nuclear Electric Limited dated June 3, 1997, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
| (p) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation Limited (“BEG”), relating to the agreement for Oxide Miscellaneous Services between BNFL and Nuclear Electric plc dated March 31, 1996, as amended and novated. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
| (q) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the agreement for Oxide Flask Maintenance between BNFL and Scottish Nuclear Limited, dated March 29, 1996, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
| (r) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the new agreement for Oxide Flask Maintenance Services between BNFL and Scottish Nuclear Limited, dated June 3, 1997, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
| (s) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the agreement for Rail Transport Services of Irradiated Nuclear Fuel in the United Kingdom between BNFL and Scottish Nuclear Limited, dated June 3, 1997, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
| (t) | A Deed of Amendment dated May 16, 2003 (as amended on October 30, 2003) between British Nuclear Fuels plc (“BNFL”) and British Energy Generation (UK) Limited (“BEG (UK)”), relating to the agreement for Oxide Miscellaneous Services between BNFL and Scottish Nuclear Limited, dated March 29, 1996, as amended. |
This deed of amendment is equivalent to the one described above in respect of the BEG Flask Maintenance Agreement.
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Memorandum and Articles of Association
The following is a summary of the principal provisions of our Memorandum and Articles of Association a copy of which has been filed with the Registrar of Companies. We were incorporated in Scotland on December 13, 1995 as Company Number 162273 Memorandum and Articles of Association.
The following is a summary of the principal provisions of our Memorandum and Articles of Association a copy of which has been filed with the Registrar of Companies. We were incorporated in Scotland on December 13, 1995 as Company Number 162273.
Memorandum of Association
Clause 6 of our Memorandum of Association states that our principal objectives are, among other things, to carry on all or any of the businesses of generators, suppliers, distributors, transformers, converters, transmitters, producers, manufacturers, processors, developers, storers, carriers, importers and exporters of, and dealers in electricity, derived from whatever source.
Articles of Association
At an Extraordinary General Meeting held on November 4, 2002, an amendment to the Articles of Association was approved, authorizing the Directors to permit the aggregate principal amount outstanding in respect of moneys borrowed by the Group to be up to an amount of £1.6 billion.
(u) Voting Rights
In the following description of the rights attaching to our shares, a “holder of shares” and a “shareholder” is, in either case, the person registered in the company’s register of members as the holder of the relevant shares. Shareholders can choose whether their shares are to be evidenced by share certificates (i.e. in a certificated form) or held in uncertified electronic form in CREST (the electronic settlement system in the United Kingdom).
Except as provided by the restrictions described below, every shareholder present at any general meeting has one vote on a show of hands and, on a poll, every shareholder present in person or by proxy has one vote for each share which they hold or represent.
Voting at all meetings of shareholders is by a show of hands unless a poll is demanded by the chairman of the meeting or by at least five shareholders at the meeting who are entitled to vote on the resolution (or their proxies), or by one or more shareholders at the meeting entitled to vote (or their proxies) and who have, between them, not less than 10% of the total votes of all shareholders who have the right to vote at the meeting; or by one or more shareholders at the meeting entitled to vote (or their proxies) who have, between them, shares conferring the right to vote on a resolution on which an aggregate sum has been paid up equal to not less than one-tenth of the total sum paid up on all the shares conferring that right.
No person is, unless the board decides otherwise, entitled to attend or vote at any general meeting or to exercise any other right conferred by being a shareholder at or in relation to meetings of the company in respect of any shares held by them if they or any person appearing to be interested in those shares have been sent a notice under section 212 of the Companies Act 1985 (which confers upon public companies the power to require information with respect to interests in their voting shares) and they or any interested person has failed to supply to the company the information requested within 14 days after delivery of that notice; and, in the case of any person who is interested or appears to us to be interested in shares representing at least 0.25% in nominal value of the issued shares of the class they shall additionally not be entitled to receive any dividend or other distribution or amount payable in respect of the default share, or to transfer or agree to transfer any of those shares or any rights in them. These restrictions continue until the earlier of:
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| (i) | Seven days after the earlier of the date the shareholder complies with the request to the board’s satisfaction or the company receives notice that there has been a market transfer or the shares; or |
| (ii) | if the board decides to waive these restrictions, in whole or in part. |
At any general meeting, the necessary quorum is two persons present in person or by proxy and entitled to vote.
(v) A Shares
Our authorized share capital includes A shares, par value 60p. As of March 31, 2004, 80,908,247 A Shares were issued and outstanding. The A Shares do not carry any rights to receive notice of, attend, speak or vote at any general meeting, unless the meeting is due to consider a resolution for our winding up, or the non-cumulative preferential dividend remains unpaid six months or more after it fell due. Upon our winding up, the A Shares have preferential rights over the ordinary shares in respect of the distribution of capital. The A Shares confer no right to participate in our capital or profits beyond their nominal value. The A Shares are held in certificate and uncertificated (paperless) form.
(w) The Special Share
Our authorized share capital includes one Special Share, a special rights redeemable preference share of £1. The Special Share may only be issued to, held by and transferred to one or more of Her Majesty’s Secretaries of State, another Minister of the Crown, the solicitor for the affairs of her Majesty’s Treasury or other person acting on behalf of the crown. The approval of the holder of the special share is required for certain matters, including alterations to our Memorandum of Association, certain of our Articles of Association, and certain other rights including the appointment of the chairman of the board. The holder of the Special Share may require us to redeem the Special Share at par at any time after September 30, 2006.
| (x) | Limitation on Size of Shareholdings |
The term “interest” is widely defined for the purpose of these provisions. It generally follows but is more extensive than the definition used in deciding whether a notification to the company would be required under Part VI of the Companies Act, 1985 (which contains requirements for the notification of interest in shares in public limited companies). Any person who has an interest in 3% or more of the voting shares in the company is required to notify the company of that interest and is otherwise required to give notices in relation to interests in voting shares as currently provided in Part VI of the Companies Act.
If, to the knowledge of the board, any person has an interest in the company’s shares which carry 15% or more of the total votes attaching to relevant share capital (as that expression is defined in the Act), the board shall send a written notice to all persons (other than certain persons referred to below) who appear to it to have such interests, and if different, to the registered holder(s) of the shares concerned. That notice will set out the restrictions referred to below and will call for the interest concerned to be reduced to less than 15% by sale or other disposal of shares within 21 days of giving the notice to the registered holder(s) (or such longer period as the board considers reasonable). No transfer of the shares comprised in the interest may be made except for the purpose of reducing the interest to less than 15% or if the notice sent by the board is withdrawn.
If that notice is not complied with to the satisfaction of the board and has not been withdrawn, the board must, so far as it is able, effect the disposal on the terms as it decides, based upon advice obtained by it for the purpose and being reasonably practicable having regard to all the circumstances.
A registered holder on whom a valid notice referred to above has been served is not entitled in respect of the share or shares comprised in the interest, until that notice has been complied with to the satisfaction of the board or withdrawn, to attend or vote at any general meeting of the company or meeting of the holders of a class of shares and those rights will vest in the chairman of the meeting who may act entirely at his discretion.
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The board is not required to send a notice to any person if it does not know that person’s identity or address. Not delivering a notice in such case and any accidental error in or failure to give notice to a person to whom notice is required to be sent under this provision will not prevent the implementation of or invalidate any procedure under the relevant article. Any resolution or determination of, or decision or exercise of any discretion or power by, the board is final and conclusive.
Certain specified shareholders, including the ADR Depositary or a Clearing House, acting, in each case in that capacity are not subject to these restrictions.
| (y) | Variation of Rights |
Whenever our share capital is split into different classes of shares, the special rights attached to any of those classes can be varied or withdrawn either:
| (i) | in such manner as may be provided by those rights; or |
| (ii) | in the absence of such provision, either with the consent in writing of the holders of at least three-quarters in nominal value of the issued shares of that class or with the sanction of an extraordinary resolution passed at a separate general meeting of the holders of those shares validly held in accordance with the articles, but not otherwise. |
Unless otherwise expressly provided by the terms of their issue, the rights attached to any class of shares shall not be deemed to be varied by the creation or issue of further shares ranking equally with them or subsequent to them or by the purchase or redemption by us of our own shares or by any other reduction of capital.
(z) Changes in Capital
We may by ordinary resolution:
| (i) | increase our share capital by the creation of new shares of the amount prescribed by the resolution; |
| (ii) | cancel any shares which have not, at the date of the ordinary resolution, been taken or agreed to be taken by any person and which diminish the amount of our share capital by the amount of the shares so cancelled; |
| (iii) | consolidate and divide all or any of our share capital into shares of a larger amount than its existing shares; and |
| (iv) | sub-divide all or part of our share capital into shares of a smaller amount than is fixed by the memorandum or articles; |
We may also:
| (i) | by extraordinary resolution passed at a separate meeting, buy back our own shares; and |
| (ii) | by special resolution reduce our share capital, any capital redemption reserve and any share premium account. |
(aa) Dividends
We may declare dividends by passing an ordinary resolution. No dividend can exceed the amount recommended by the Directors. The board may declare and pay such dividends as appear to be justified by the profits available for distribution. If the Directors consider that our profits justify such payments, they can pay interim dividends on any class of shares of the amounts and on the dates and for the periods they decide. Fixed dividends will be paid on any class of share on the dates stated for the payments of those dividends.
The Directors can (with the authority of an ordinary resolution of shareholders) offer ordinary shareholders the right to choose to receive new ordinary shares, which are credited as fully paid, instead of some or all of their cash dividend. To date, we have not sought such approval.
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Any dividend which has not been claimed for 12 years after it was declared or became due for payment may be forfeited and will belong to us unless the Directors decide otherwise.
We can stop paying dividends to a shareholder if payments for two dividends in a row are sent back or not cashed or have not been able to be made, until the shareholder or a person entitled to the shares by transmission claims them.
In view of British Energy’s financial situation, no interim or final dividend was paid in the financial year 2003-2004. The Board does not expect to declare or propose any dividend on the ordinary or “A” shares prior to the completion of the proposed restructuring.
(bb) Distribution of Assets on Winding Up
If we are in voluntary liquidation the liquidator may, with the sanction of an extraordinary resolution passed by the shareholders, and any other sanction required by law, divide among shareholders all or any part of the assets of the company. This applies whether the assets consist of property of one kind or different kinds. For this purpose, the liquidator can place whatever value the liquidator considers fair on any property and decide how the division is carried out between shareholders or different groups of shareholders or; vest the whole or any part of the assets or class of assets in trustees upon such trusts for the benefit of shareholders as the liquidator shall determine.
(cc) Transfer of Shares
Our certificated shares may be transferred in writing either by an instrument of transfer in the usual standard form or another form approved by the board. The transfer form must be signed or made effective by or on behalf of the person making the transfer. The person making the transfer will be treated as continuing to be the holder of the shares transferred until the name of the person to whom the shares are being transferred is entered in the register of members of the company. The board may, in its absolute discretion and without giving any reason for its decision, refuse to register the transfer of a certified share not fully paid up, or a certified share on which we have a lien.
The board may refuse to register any transfer of any share held in certified form:
| • | which is in respect of more than one class of shares; |
| • | which is in favor of more than four joint holders; |
| • | unless it is left at the place decided by the board for registration; |
| • | unless the transfer form to be registered is properly stamped to show payment of any applicable stamp duty; and |
| • | unless the transfer has the share certificate for the shares to be transferred with it, together with any other evidence which the board asks for to prove that the person wanting to make the transfer is entitled to do this; and if the transfer form is executed by another person on behalf of the person making the transfer, evidence of the authority of that person to do so. |
Transfers of uncertified shares must be carried out using a relevant system (as defined in Uncertificated Securities Regulations 1995 (the “Regulations”)). The board can refuse to register a transfer of an uncertified share in the circumstances stated in the Regulations.
If the board decides not to register a transfer of a share, they must notify the person to whom the share was to be transferred within two months of either the transfer, or the instruction from the operator of the relevant system being lodged with us.
The board can decide to suspend the registration of transfer, for up to 30 days a year, by closing the register of shareholders. The register must not be closed without the consent of the operator of a relevant system in the case of any relevant register relating to a particular security.
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(dd) Untraced Shareholders
We may sell any shares after advertising our intention and waiting for three months if the shares have been in issue for at last 12 years, during that period at least three dividends have become payable on them and have not been claimed and we have not heard from the shareholder or any person entitled to the dividends by transmission. We shall account for the proceeds to the former shareholder or the person entitled to them by transmission if that shareholder, or that other person, asks for them.
(ee) General Meetings of Shareholders
Every year we must hold an annual general meeting. The board can call an extraordinary general meeting at any time, and, under general law, it must call one on a valid shareholder’s requisition.
(ff) Limitations on Rights of Non-residents or Foreign Shareholders
There are no limitations imposed by the Articles of Association on the rights of non-residents on foreign shareholders.
(gg) Directors
Directors’ Remuneration
The Directors (other than alternate Directors or those Directors who hold an executive office or employment with the Company (or one of its subsidiaries), shall be paid out of the funds of the Company by way of remuneration for their services as Directors such fees not exceeding in aggregate £500,000 a year (or such larger sum as British Energy may by ordinary resolution, determine) as the Directors may decide to be divided among them in such proportion and manner as the board decides (or else equally). The Directors shall also be paid their expenses properly incurred by them in connection with the discharge of their duties as our Directors.
The board may grant special remuneration to a director who performs any special or extra services to or at the request of the board.
The board may provide pensions or other benefits to, among others, any director or former director or persons connected with them.
Directors’ Votes
A director need not be a shareholder, but a director who is not a shareholder can still attend and speak at shareholders’ meetings.
Unless the Articles of Association say otherwise, a director cannot vote on a resolution about a contract in which the director has a material interest (this will also apply to interests of a person connected with the director). The director can vote if the interest is only an interest in British Energy shares, debentures or other securities. A director can, however, vote and be counted in a quorum in respect of certain matters in which he is interested as set out in the articles.
Subject to the legislation, the shareholders can by passing an ordinary resolution suspend or relax, among other things, the provisions relating to the declaration of the interest of a director in any contract or arrangement or relating to a director’s right to vote and be counted in a quorum on resolutions in which he is interested to any extent or ratify any particular contract or arrangement carried out in breach of those provisions.
Directors’ Interests
If the legislation allows and the director had disclosed the nature and extent of the interest to the board, the director can:
| (i) | have interest in a contract with or involving us (or in which we have an interest or with or involving another company in which we have an interest); |
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| (ii) | have any interest in a company in which we have an interest; |
| (iii) | hold a position (other than an auditor) in us or another company in which we have an interest or power of appointment; and |
| (iv) | along (or through some firm with which the director is associated) do paid professional work (other than as auditor) for us or another company in which we have an interest on terms and conditions decided by the board. |
A director does not have to hand over to us any benefit received or profit made as a result of anything permitted to be done under the articles.
When a director knows that they are interested in a contract with us they must tell the other Directors.
Retirement of Directors
Under the terms of the Articles of Association the appointment of a director or requirement for him to stop being a director is not restricted due to the fact that he has reached a particular age.
At every annual general meeting one third of the Directors (or if their number is not a multiple of three, the number nearest to but not less than one third) must retire by rotation as Directors. The Directors to retire are selected on the basis of time in office since their last election. Any director appointed by the Directors automatically retires at the next following annual general meeting, and is then eligible for election, but is not taken into account in determining which and how many Directors are to retire by rotation at such meeting. A retiring director is eligible for re-election.
Exchange Controls and other Limitations Affecting Security Holders
There are no UK laws or regulations, including foreign exchange contracts that restrict the import or export of capital to or from the United Kingdom. Except as discussed in “Taxation” below, there are no restrictions on our payment of dividends or other amounts to non-UK resident holders of our securities. Except with respect to the Limitation, neither UK law nor our articles impose any restrictions on the rights of non-UK resident or non-UK citizen holders of our ordinary shares and ADSs to hold or to vote such securities.
Taxation
The following discussion describes certain US federal income tax and UK tax consequences of the acquisition, ownership and disposition of our ordinary shares or ADSs (evidenced by ADRs) to absolute beneficial owners of our ordinary shares or ADSs (as such term is used for UK tax purposes):
| • | who are residents of the United States for purposes of the income tax convention between the United States and the United Kingdom; |
| • | whose ownership of our ordinary shares or ADSs are not, for the purposes of the income tax convention, attributable to a permanent establishment in the United Kingdom; |
| • | who otherwise qualify for the full benefits of the income tax convention; and |
| • | who are US holders (as defined below). |
The statements of US federal income tax and UK tax laws set out below:
| • | are based on the laws in force and as interpreted by the relevant taxation authorities as of the date hereof; and |
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| • | are subject to any changes in US federal income tax or UK tax law, in the interpretation thereof by the relevant taxation authorities, or in the income tax convention, occurring after the date hereof. |
No assurance can be given that taxing authorities or the courts will agree with this analysis. For purposes of this discussion, the terms “we”, “us” and “our” refers to British Energy plc.
This discussion is not a complete listing of all potential tax consequences to a US Holder of the acquisition, ownership or disposition of our ordinary shares or ADSs, and does not address all aspects of UK taxation that may be relevant to a US holder and is not intended to reflect the individual tax position of any US holder, including tax considerations that arise from rules of general application to all taxpayers or to certain classes of investors or that are generally assumed to be known by investors.
The portions of this summary relating to US federal taxation are based upon the US Internal Revenue Code of 1986, as amended (the “Code”), its legislative history, existing and proposed US Treasury regulations promulgated thereunder, published rulings by the US Internal Revenue Service (“IRS”), and court decisions, all in effect as of the date hereof, all of which authorities are subject to change or differing interpretations, which changes or differing interpretations could apply retroactively. The portions of this summary relating to US federal taxation are limited to US Holders who hold our ordinary shares or ADSs as capital assets within the meaning of Section 1221 of the Code, generally, property held for investment, and does not purport to deal with investors in special tax situations, such as expatriates, dealers in securities or currencies, persons whose functional currency is not the US dollar and certain persons, including but not limited to life insurance companies, tax exempt entities, banks, financial institutions, traders in securities that elect to use a “mark-to-market” method of accounting for their securities holdings, regulated investment companies, persons holding our ordinary shares or ADSs as part of a hedging, integrated, conversion or constructive sale transaction or straddle or persons subject to the alternative minimum tax, who may be subject to special rules not discussed below. In particular, the following summary does not address the tax treatment to a US holder if the US holder owns, directly or by attribution, 10% or more of our outstanding voting share capital for US federal tax income purposes.
As used herein, the term “US holder” means a beneficial owner of our ordinary shares or ADSs who or which is for US federal income tax purposes:
| • | a citizen or resident of the United States; |
| • | a corporation (or other entity treated as a corporation) created or organized in or under the laws of the United States or any political subdivision thereof; |
| • | an estate the income of which is subject to US federal income taxation regardless of its source; or |
| • | a trust (1) that is subject to the supervision of a court within the United States and the control of one or more US persons as described in section 7701(a)(30) of the Code or (2) that has a valid election in effect under applicable US Treasury regulations to be treated as a US person. |
If a partnership (or other entity treated as a partnership) holds our ordinary shares or ADSs, the US federal income tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. If a US holders is a partner of a partnership holding our ordinary shares or ADSs, the US holder should consult its own tax advisors regarding the US federal income tax consequences of the partnership acquiring, owning and disposing of the shares or ADSs.
The summary does not include any description of the tax laws of any state, local or foreign governments that may be applicable to the acquisition, ownership and disposition of our ordinary shares or ADSs. Shareholders are urged to consult their own tax advisor regarding the
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US federal, state, and local tax consequences to them of the acquisition, ownership and disposition of shares or ADSs, as well as the tax consequences to them in the United Kingdom and any other jurisdictions arising from the acquisition, ownership or disposition of our ordinary shares or ADSs.
For the purposes of the income tax convention and the Code, a US holder will be treated as the owner of our ordinary shares represented by the ADSs evidenced by the ADRs.
New Income Tax Convention
The new income tax convention between the United States and the United Kingdom (the “New Convention”) has recently been ratified by the competent authorities in the two countries and entered into force on March 31, 2003. The New Convention put in place new rules that modify the treatment of US holders under the previous income tax convention between the United States and the United Kingdom (the “Old Convention”) in several aspects. Specific references to the new rules under the New Convention have been included as appropriate throughout this summary. Each US holder should consult its own tax advisor regarding the effect of the New Convention on its investment in shares or ADSs.
Taxation of dividends
United Kingdom
No withholding tax is charged or due when a UK incorporated company pays dividends. An individual shareholder resident in the United Kingdom will generally be entitled to a tax credit in respect of any dividend received. The amount of the tax credit is equal to one-ninth of the cash dividend or 10% of the aggregate of the cash dividend and the associated tax credit. Under the New Convention, a US holder is not entitled to a payment from the UK Inland Revenue in respect to the tax credit.
United States
Subject to the PFIC discussion below, generally, distributions a US holder receives from us will constitute dividend income to the extent paid out of our current and accumulated earnings and profits, as determined under US federal income tax principles, and, subject to discussions below, taxed at ordinary income tax rates applicable to the US Holder. Distributions in excess of our current and accumulated earnings and profits will first be treated as a nontaxable return on capital to the extent of the US holder’s adjusted tax basis (generally equal to the US holder’s acquisition cost of the shares or ADSs) in the shares or ADSs and then as gain from the sale or exchange of a capital asset. Dividends paid by us will not be eligible for the dividends received deduction that is applicable to US corporations. For the purposes of computing the foreign tax credit, dividends paid on our ordinary shares or ADSs are treated as income from sources outside the United States, but generally will be grouped separately, together with other items of “passive” or “financial services” income. The rules governing the foreign tax credit are complex. US holders should consult their own tax advisors regarding the availability of the foreign tax credit in their particular circumstances.
The Jobs and Growth Tax Relief Reconciliation Act of 2003 (the “Act”) which became effective on May 28, 2003 modified various provisions of the Code relevant to the taxation of US Holders of our ordinary shares or ADSs. In particular, the Act reduces the maximum US federal income tax rate applicable to individual US Holders to a maximum 15% tax rate on certain types of dividends. The reduced rates of tax applies to the 2003 through the 2008 taxable years. Generally, dividends paid by a foreign corporation will be eligible for this reduced rate of tax if the foreign corporation (a) is not a
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“foreign personal holding company”, “foreign investment company” or “passive foreign investment company”, (b)(i) is eligible for benefits under a comprehensive income tax convention with the United States that satisfies certain requirements or (ii) the stock with respect to which the dividend is paid is readily tradable on an established securities market in the United States, and (c) certain other requirements are met. Individual US Holders should consult their own advisors as to the eligibility of the reduced rate of tax to dividends paid by us.
During the periods the Old Convention was in effect, if a US holder were eligible for benefits under, and elected the application of, the Old Convention, the US holder would include in gross income, as dividends, an amount equal to the sum of the actual dividend plus the tax credit amount (to the extent such amount is paid out of our earnings and profits), and the US holder would be treated for US foreign tax credit purposes, as having paid UK withholding tax equal to the amount of the tax credit. A US holder could elect the application of the Old Convention by filing a timely and duly completed Form 8833 with the US holder’s income tax return for the relevant year. Subject to certain conditions and limitations, the UK deemed withholding tax could be deducted from taxable income, or instead credited against the US holder’s US federal income tax liability.
Under the New Income Tax Convention, the amount of dividends to be included in a US holder’s gross income no longer includes the amount any UK tax credit amount described above. Therefore, the amount of dividends that a US holder is treated as receiving from us will be the amount of dividends the US holder actually receive from us. US holders should consult their own tax advisors regarding the effects of the Old Convention and the New Convention on their investment in our ordinary shares or ADSs, and their eligibility for benefits under the Old Convention and the New Convention with respect to distributions from us.
The amount of any dividend paid in pounds sterling will equal the US dollar value of the pounds sterling received calculated by reference to the exchange rate in effect on the date the dividend is received by a US holder, in the case of shares, or by the Depositary, in the case of ADSs, regardless of whether the pounds sterling are converted into US dollars. If a US holder does not convert the pounds sterling received as a dividend into US dollars on the date of receipt, the US holder will have a basis in the pounds sterling equal to their US dollar value on the date of receipt. Generally, any gain or loss realized on the US holder’s subsequent conversion or other disposition of the pounds sterling will be treated as ordinary income or loss from US sources.
Taxation of capital gains
United Kingdom
If a US holder is not resident or ordinarily resident in the United Kingdom for UK tax purposes, the US holder is not liable for UK tax on capital gains realized or accrued on the sale or other disposition of shares or ADSs unless the shares or ADSs are held in connection with the US holder’s trade or business (which for this purpose includes a profession or a vocation) carried on in the United Kingdom through a permanent establishment and the shares or ADSs are or have been used, held or acquired for the purposes of such trade or business or such permanent establishment.
A US holder who is an individual who has on or after March 17, 1998 ceased to be resident or ordinarily resident in the United Kingdom for a period of five years and who disposes of shares or ADSs during that period may also be liable for UK tax on capital gains on his return to the UK notwithstanding that the person may not be resident or ordinarily resident in the United Kingdom at the time of the disposal.
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United States
Subject to the PFIC discussion below, gain or loss realized by a US holder on the sale or other disposition of the shares or ADSs will be subject to US federal income tax as capital gain or loss in an amount equal to the difference between the US holder’s adjusted tax basis in the shares or ADSs and the amount realized on the disposition. The capital gain or loss will be long-term capital gain or loss if the US holder has held the shares or ADSs for more than one year at the time of the sale or exchange. In the case of individual US Holders, the Act reduces the maximum long-term capital gains tax rate to 15% for sales and exchanges occurring on or after May 6, 2003 through 2008. Gain or loss realized by a US holder generally will be treated as US source gain or loss for US foreign tax credit purposes.
Passive foreign investment company considerations
Generally, for US federal income tax purposes, we will be a “passive foreign investment company”, or a “PFIC”, for any taxable year if either (i) 75% or more of our gross income is “passive” income or (ii) 50% or more of the value of our assets, determined on the basis of a quarterly average, is attributable to assets that produce or are held for the production of passive income. Passive income generally includes dividends, interest, royalties and rents not arising from the active conduct of a trade or business, and gains from the sale of assets that produce such income. If we are a PFIC in any taxable year that a US holder owns our ordinary shares or ADSs, the US holder may be subject to tax at ordinary income rates on (a) a portion of any gain recognized on the sale of our ordinary shares or ADSs and (b) any “excess distribution” paid on our ordinary shares or ADSs (generally, a distribution in excess of 125% of the average annual distributions paid by us in the three preceding taxable years). In addition, any dividends paid by us that would otherwise be eligible for the reduced rate of tax as discussed above, will not be eligible for such reduced rate of tax if we are a PFIC.
Based on our current activities and assets, we do not believe that we are a “passive foreign investment company” or a “PFIC”, and we do not expect to become a PFIC in the foreseeable future for US federal income tax purposes. The determination of whether we are a PFIC is made annually. Accordingly, it may be possible that we will become a PFIC in the current or any future year due to changes in our asset or income composition.
UK stamp duty and stamp duty reserve tax
Subject to certain exemptions, stamp duty will be charged at the rate of 1.5% rounded up to the nearest £5, or there will be a charge to stamp duty reserve tax at the rate of 1.5% on the amount or value of the consideration paid, or in some circumstances the issue price or open market value, on a transfer or issue of shares (1) to, or to a nominee for, a person whose business is or includes the provision of clearance services, or (2) to, or to a nominee for, a person whose business is or includes the issuing of depositary receipts. It is assumed that the UK Inland Revenue Stamp Office considers the depositary to fall within one or the other of the above two categories. The stamp duty reserve tax on the deposit of Shares with the depositary will be payable, pursuant to the terms of the deposit agreement among British Energy plc, Morgan Guaranty Trust Company of New York, as depositary, and the holders of ADRs, dated as of June 26, 1996, by the holders of the ADRs. Where stamp duty reserve tax is charged on a transfer of shares and ad valorem stamp duty is chargeable on the instrument effecting the transfer, the amount of the stamp duty reserve tax charged is an amount equal to the excess, if any, of the stamp duty reserve tax charge due on the transfer after the deduction of the stamp duty paid.
For US federal income tax purposes, a US holder will not be entitled to a foreign tax credit with respect to any UK stamp duty or stamp duty reserve tax, but may be entitled to a deduction subject to applicable limitations under the Code. US holders are urged to consult their own tax advisors regarding the availability of a deduction under their particular circumstances.
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Transfers of ADRs
No UK stamp duty will be payable on an instrument transferring an ADR or on a written agreement to transfer an ADR provided that payment is made outside the UK and the instrument of transfer or the agreement to transfer is executed outside the United Kingdom. Where these conditions are not met, the transfer of, or agreement to transfer an ADR could, depending on the circumstances, attract a charge to ad valorem stamp duty at the rate of 0.5% of the value of the consideration (rounded up to the nearest £5) plus (i) interest if not stamped within 30 days of execution and (ii) penalties if not presented for stamping within 30 days after the earlier of the day on which it is executed in the UK and the day on which it is first received in the UK.
No stamp duty reserve tax will be payable in respect of an agreement to transfer an ADR, whether made in or outside the United Kingdom.
Where no sale is involved and no transfer of beneficial ownership has occurred, a transfer of shares by the depositary or its nominee to the holder of an ADR upon cancellation of the ADR is subject to UK stamp duty of £5 per instrument of transfer.
Issue and transfer of Shares in registered form
Except in relation to persons whose business is or includes the issue of depositary receipts or the provision of clearance services or their nominees, the allotment and issue of shares by us will not normally give rise to a charge to UK stamp duty or stamp duty reserve tax.
Transfers of shares, as opposed to ADRs, will attract ad valorem stamp duty normally at the rate of 0.5% of the value of the consideration (rounded up to the nearest £5). A charge to stamp duty reserve tax, normally at the rate of 0.5% of the consideration, arises, in the case of an unconditional agreement to transfers shares, on the date of the agreement, and in the case of a conditional agreement the date on which the agreement becomes unconditional. In the case of transfers effected through the CREST system, ordinarily the stamp duty reserve tax is collected through the system. In other cases, the stamp duty reserve tax is payable on the seventh day of the month following the month in which the charge arises. Where an instrument of transfer is executed and duly stamped before the expiry of a period of six years beginning with the date of that agreement, any stamp duty reserve tax that has not been paid ceases to be payable, and if any stamp duty reserve tax has been paid a claim may be made for its repayment (with interest) provided that the tax paid is not less than 25 pounds sterling.
Information reporting and backup withholding
Payments that relate to the shares or ADSs that are made in the United States or by a US related financial intermediary will be subject to information reporting. Information reporting generally will require each paying agent making payments, which relate to a share or ADS, to provide the US Internal Revenue Service, or the IRS, with information, including the beneficial owner’s name, address, taxpayer identification number, and the aggregate amount of dividends paid to such beneficial owner during the calendar year. These reporting requirements, however, do not apply to all beneficial owners. Specifically, corporations, securities broker-dealers, other financial institutions, tax-exempt organizations, qualified pension and profit sharing trusts and individual retirement accounts are all excluded from reporting requirements.
We may be required to withhold, as a backup against a US holder’s US federal income tax liability, a portion of each payment of dividends on our ordinary shares or ADS in the event that the US holder:
| • | fails to establish its exemption from the information reporting requirements; |
| • | is subject to the reporting requirements described above and fails to supply its correct taxpayer identification number in the manner required by applicable law; or |
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| • | underreports its tax liability; or |
| • | if we are otherwise notified by the IRS. |
This backup withholding tax is not an additional tax and may be credited against the beneficial owner’s US federal income tax liability if the required information is furnished to the IRS.
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following discussions about our risk management activities include “forward-looking” statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward-looking statements.
The following tables summarize the financial instruments, derivative instruments and derivative commodity instruments held by us at March 31, 2004, which are potentially sensitive to changes in interest rates, foreign exchange rates, commodity prices and equity markets. We use foreign exchange contracts and other derivative instruments to hedge the primary market exposures associated with our underlying assets, liabilities and committed transactions. None of the instruments we have entered into are leveraged or held for speculative purposes. We use fixed rate interest rate borrowings and deposits to reduce our exposure to fluctuations in interest rates.
Financial Instruments and Risk Management
Overview
The main financial risks faced are trading risk in England and Wales in respect of both price and output volume. There is also an exposure to risk associated with fluctuations in the equity markets through the Decommissioning Fund and Pension Schemes. Policies have been instituted for managing each of these risks, which have been approved by the Board of Directors. Each of these risks is discussed in more detail below.
Electricity trading risks are managed by the Power and Energy Trading Division. The Power and Energy Trading Division operate within policies and procedures approved by the Board and monitored by a sub-committee of the Executive Committee.
Non-trading risks (i.e. cash resources, debt finance and financial risks) are managed by the central treasury function (the “Treasury Department”). The Treasury Department operates within policies and procedures approved by the Board. The Treasury Department uses appropriate and available instruments, within specified limits, to manage financial risk but is not permitted to take speculative, open positions. Both the Treasury Department and the Power and Energy Trading Division are subject to regular scrutiny from our internal auditors.
Interest Rate Risk Management
Debt at March 31, 2004 comprised a project finance loan of £475 million, and bonds in an aggregate principal amount of £408 million no change from the previous year end March 31, 2003.
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The market value of our debt varies, with fluctuations in prevailing interest rates in the United Kingdom. The debt is analyzed as follows:
| Expected Maturity Date |
Fair Value at March 31, | |||||||||||||||||||||
| Liabilities |
2003 |
2004 |
2005 |
2006 |
2007 |
2008 |
2009 |
Thereafter |
Total |
2004 |
2003 | |||||||||||
| (in millions of pounds, except percentages) | ||||||||||||||||||||||
| Fixed rate bond due 2003 at 5.949%(1) |
110 | — | — | — | — | — | — | — | 110 | 138 | 46 | |||||||||||
| Fixed rate bond due 2006 at 6.077%(1) |
— | — | — | 163 | — | — | — | — | 163 | 204 | 69 | |||||||||||
| Fixed rate bond due 2016 at 6.202%(1) |
— | — | — | — | — | — | — | 135 | 135 | 168 | 56 | |||||||||||
| Long-term—project finance |
— | 42 | 45 | 48 | 52 | 56 | 60 | 172 | 475 | 150 | 150 | |||||||||||
| Weighted average interest rate, % |
6.04 | 5.34 | 5.34 | 5.98 | 5.34 | 5.34 | 5.34 | 5.76 | 5.72 | — | — | |||||||||||
| (1) | The analysis of maturity of Bonds, Project Finance loan and long term electricity trading contracts has been prepared based on the dates when they mature under the existing contractual arrangements. However, the standstill arrangements which have been put in place have the effect of deferring the payments of certain amounts due until the bonds, Eggborough project finance loan and long term electricity trading contracts are replaced as part of the restructuring of the Group or earlier termination of the standstill. The maturity profile is likely to change upon completion of the proposed restructuring. |
The following interest rate agreements were in effect as at March 31, 2004.
| Maturity Analysis of Interest Rate Contracts |
2005 |
2006 |
2007 |
2008 |
2009 |
Fair Value as
at |
||||||||||||
| (in millions of pounds, except percentages) | ||||||||||||||||||
| Eggborough Fixed: |
||||||||||||||||||
| Notional Amounts* |
356 | 332 | 291 | 235 | 174 | (28 | ) | |||||||||||
| Average Pay Rate |
6.6 | % | 6.6 | % | 6.6 | % | 6.6 | % | 6.6 | % | ||||||||
| Average Receive Rate |
4.7 | % | 4.7 | % | 4.7 | % | 4.7 | % | 4.7 | % | ||||||||
| British Energy plc |
||||||||||||||||||
| Variable to Fixed: |
||||||||||||||||||
| Notional Amounts** |
30 | (3 | ) | |||||||||||||||
| Average Pay Rate |
5.8 | % | ||||||||||||||||
| Average Receive Rate |
6M LIBOR | |||||||||||||||||
| Collars: |
||||||||||||||||||
| Notional Amounts*** |
70 | (2 | ) | |||||||||||||||
| Fair Value Collar Spread |
5.3%-6.8 | % | ||||||||||||||||
| * | The Eggborough related derivative agreements were amended post March 31, 2003 as part of the proposed Restructuring process. The effect has been to fix future interest payments under the swaps from October 2004. onwards. |
| ** | Bank has the right to cancel swap at zero cost on any cancellation date from April 2005 and every year thereafter. |
| *** | Banks have the right to enter into semi-annual swap receiving 5.25% and paying 6 month LIBOR for ten years at zero cost in April 2005. |
At March 31, 2004 the total of investments in liquid funds and cash at bank amounted to £573 million, and had maturity dates due within one year. Cash not immediately required for business purposes is invested in fixed-rate term deposits and money market funds. At March 31, 2004, these term deposits and money market funds earned interest at an average rate of 3.9%. Term deposits, money market funds and bank balances at March 31, 2004 include £297 million of cash which has been deposited in collateral bank accounts. Availability of this cash is therefore restricted over the period of the collateralized position.
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As the deposit terms are short term, the carrying value at March 31, 2004 approximates the fair market value.
Foreign Exchange Risk Management
There are potential future foreign currency receivables in respect of the retentions outstanding from the sales of Bruce Power and AmerGen. When these cash flows become more certain in the future, the Group will evaluate currency hedging opportunities, balancing the cost and availability of entering into such transactions against the underlying currency risk.
At March 31, 2004 there were no foreign exchange contracts in place.
At March 31, 2004, there were nil deferred losses accounted for as part of stock which arose on the rollover of maturing forward contracts used for hedging the future purchase of fuel prior to and including the year ended March 31, 2003. See note 19 to our consolidated financial statements. The equivalent deferred losses for the years ended March 31, 2003 and 2002 each accounted for as part of inventory approximated £2 million and £10 million respectively.
The underlying fuel purchase commitments as at March 31, 2004 are analyzed as follows:
| Expected Maturity Date |
Fair Value at March 31, | |||||||||||||
| Total fuel commitments per currency (millions) as at March 31, 2003 |
2005 |
2006 |
2007 |
2008 |
Thereafter |
2004 |
Total 2003 | |||||||
| US Dollars |
54.2 | 17.5 | 7.9 | 8.6 | — | 88.2 | 144.1 | |||||||
| Euros |
8.7 | — | 9.4 | 9.4 | — | 27.5 | 8.5 | |||||||
We do not have significant commodity price exposure in relation to our procurement of nuclear fuels.
Electricity Trading Risk Management
Our trading activities principally relate to supporting our generating business. Our trading operations, therefore, principally act as wholesale marketers rather than as pure financial traders, with the principal objective of increasing the return on our assets while hedging the market risk associated with the output of the plants.
Under NETA any mismatch between actual metered generation (or demand) and the notified contract position is exposed to the prices in the balancing mechanism run by the grid system operator. Based on experience to date prices in the balancing mechanism encourage forward contracting, as the price for spilling energy to the system tends to be lower than the forward market price, whereas the price for purchasing top-up supplies tends to be higher than the forward market price.
We manage the risks in the new wholesale market through a contracting strategy that builds a portfolio of forward contracts with a variety of terms. Contracts are sold through several routes to market including bespoke bilateral contracts, brokered over-the-counter trades in standard products, exchange trading and direct sales to industrial and commercial customers. The objective is to sell forward all of our planned nuclear generation in England and Wales ahead of delivery. Eggborough provides a flexible generation capability which fulfils three purposes designed to enhance our profitability. Firstly, it provides a means for compensating for unplanned lost output from nuclear units at short notice; secondly, it provides the capability to profile the generation shape to meet the requirements of both wholesale and directly-supplied customers; and thirdly, it provides a flexible capability that is offered to the system operator via the balancing mechanism. Output from our two stations in Scotland will continue to be sold under the terms of the NEA to ScottishPower and Scottish and Southern Energy, until April 2006, or the introduction of BETTA, whichever is earlier.
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Our policy is to manage our credit exposure to trading and financial counter parties within clearly defined limits. Electricity trading activities are strictly monitored and controlled through delegated authorities and procedures, which include specific criteria for the management of counter party credit exposures.
Equity Risk Management
The Decommissioning Fund was established to provide for the eventual decommissioning of our UK nuclear power stations. Cash contributions are made on a quarterly basis to a payment profile set out in a contract between us and the Decommissioning Fund and are invested by the trustees of the Decommissioning Fund in UK marketable fixed income debt, equity securities and property. We are solely responsible for contributions to the Decommissioning Fund. Therefore the level of future contributions, which are reviewed every five years in conjunction with our review of ultimate decommissioning costs, depend partly on the estimated long-term investment performance of the equity and debt instruments in which the contributions are invested and returns on investments in property. Income from dividends and other returns on the underlying investments are retained by the Decommissioning Fund and then invested in debt and equity securities.
At March 31, 2004 we reported a book value of £440 million in the Decommissioning Fund, which is the same as the market value as at March 31, 2004. The Decommissioning Fund included debt and equity securities with market values of £44 million and £396 million respectively.
ITEM 13. DIVIDEND ARREARAGES AND DELINQUENCIES
On June 3, 2003 we announced that we did not expect to pay any dividends prior to the completion of the Restructuring. No dividends were paid to holders of A Shares on the August 11, 2003 payment date. The Board intends to distribute to shareholders as much of the Company’s available cash flow as prudently possible, but not prior to the completion of the Restructuring, and 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 our ability to pay dividends, including:
| • | we are required to fund a cash reserve out of our net cash flow in order to support British Energy Group plc’s collateral and liquidity requirements following the Restructuring. The initial target amount for the cash reserve is £490 million plus the amount by which cash employed as collateral exceeds £200 million (the “Target Amount”). Prior to paying any dividend, our cash must equal or exceed the Target Amount and certain amounts specified in the Contribution Agreement. |
| • | the terms of the Contribution Agreement also require that once the cash reserve is funded to the Target Amount, we must make the NLF Cash Sweep Payment. Initially this is 65% of the increase in cash, cash equivalents and other liquid assets during the year after adjusting for certain matters (the “Payment Percentage”). The Payment Percentage may be adjusted for certain corporate actions but may never exceed 65%. The requirement to make the NLF Cash Sweep Payment will greatly reduce the amount of cash that would otherwise be available for distribution to shareholders. In addition, we may not pay any dividends without making an additional payment to the NLF if the result of paying such dividend would be that the aggregate amount of dividends paid to shareholders following the Proposed Restructuring would exceed the aggregate of our annual adjusted net cash flow in such period less the aggregate NLF Cash Sweep Payment payable in such period. |
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| • | the terms of the New Bonds contain certain covenants, including a restriction that allows us to pay a dividend only if no event of default has occurred; and |
| • | we are incorporated in the UK and must comply with all UK legislation affecting companies incorporated in the UK. One such requirement under UK legislation is that in order to declare dividends we must have distributable reserves as defined by the Companies Act. |
As a result of these restrictions and after making a prudent allowance for collateral requirements, we believe that the earliest possible period for which declaration of a dividend may be considered is the financial year 2006/7.
Subject to these restrictions, we intend to distribute to shareholders as much of our available cash flow as prudently possible. Any such decision to make such a distribution will be made in the circumstances of the time. In relation to any financial year in respect of which we might otherwise be permitted to pay a dividend, the directors might, for example, consider during the course of that year (or subsequent to it) whether it would be prudent to redeem or repurchase New Bonds and CTA Bonds (together with accelerated payments of fixed decommissioning payment to the NLF), make additional contributions to our pension schemes, allocate cash to the forecast expenditure reserve in accordance with the Contribution Agreement (for instance, to meet certain qualifying expenditure on PIP which is due in the following financial period, to acquire or finance a specific fixed asset or undertaking (expected to be with cash and not from borrowings)) or retain cash reserves in excess of the Target Amount.
Movements in our operational cash flow (prior to debt service and the adjustments referred to above) from one financial year to another are likely to be volatile, for example because of movements in the wholesale price of electricity and variability in our output.
Taking account of the constraints set out above, consideration of prudence and the likely volatility of operational cash flows, the Board believes that any dividends paid may vary in size and frequency.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
(None)
ITEM 15. CONTROLS AND PROCEDURES
As recommended by the U.S. Securities and Exchange Commission, or SEC, we have established a Disclosure & Controls Committee (the “Disclosure Committee”). The Disclosure Committee reports to our Chief Executive Officer, Chief Financial Officer and to the Audit Committee. It is chaired by the Group Financial Controller and the members consist of senior managers from operations, finance, legal, internal audit and investor relations. It has responsibility for considering the materiality of information, and on a timely basis, determination of the disclosure and treatment of material information. The Disclosure Committee also has responsibility for the timely filing of reports with the SEC and the formal review of the contents of our Annual Report on Form 20-F.
We determined that application of Statement of Financial Accounting Standards No. 109 Accounting for Income Taxes (“FAS 109”) as a result of our adoption of Statement of Financial Accounting Standards No.143, Accounting for Asset Retirement Obligations (“FAS 143”) on April 1, 2003 did not appropriately record the tax impact for the year ended March 31, 2004. Consequently, we have restated our 2004 consolidated financial statements in accordance with U.S. GAAP to reflect the correct allocation of income tax expense/benefit between income from continuing operations and the cumulative effect of a change in accounting as of April 1, 2004, as discussed in more detail in Note 36
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to our audited financial statements included elsewhere in this annual report. While the restatement did not impact our net income or shareholders’ equity it did impact income from continuing operations and cumulative effect from changes in accounting included in note 36 (ii) due to the allocation of income tax between income from continuing operations before cumulative effect and the cumulative effect of a change in accounting.
We adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative and Hedging Activities, as amended (“FAS 133”), for the accounting period commencing April 1, 2001. At the time of adoption, certain contracts were identified as being derivatives in accordance with FAS 133. It was also noted as part of the FAS 133 implementation project that several of these derivatives may qualify for the Normal Purchase Normal Sale (“NPNS”) exemption allowed under FAS 133, provided that appropriate contemporaneous documentational evidence existed as to both physical delivery and the election of NPNS itself.
As part of the process of implementing Statement of Financial Accounting Standards No. 149, Accounting for Derivative and Hedging Activities (“FAS 149”), for the year ended March 31, 2004 we conducted a broader review of our compliance with derivative accounting regulation and revised the application of the NPNS exemption rules against specific contracts. As a result of this revision we determined that it was necessary to restate the results for 2002 and 2003.
For the years ended March 31, 2002 and 2003, several contracts that met the requirements for derivative accounting under FAS 133 were not marked to market on the basis that we claimed they qualified for the NPNS exemption. The contracts for which the NPNS exemption was taken in these two fiscal years include (1) Grid Trade Master Agreement (“GTMA”) contracts and (2) certain structured sales contracts. GTMA contracts are bilateral contracts for the forward purchase and/or sale of electricity. GTMA contracts are industry standard contracts arising following the introduction of the New Electricity Trading Arrangements (“NETA”) market in England and Wales in March 2001. During the period from April 2001 to March 2004, the number of GTMA contracts that were entered into in the market place increased significantly, and hence the number of contracts for which we were claiming the NPNS exemption increased significantly.
For the year ended March 31, 2004 we adopted FAS 149. As part of that process, a broader review of our accounting for derivative contracts was undertaken. It was then concluded that all or a portion of the GTMA contracts on which we claimed the NPNS exemption do not go to physical delivery, but rather are “booked-out” as we enter into offsetting GTMA contracts as the increase in GTMA activity in the market place meant that the volumes of electricity traded using GTMA contracts was in excess of the market capacity for the physical flow of electricity. The documentation that we had in place was not sufficient to support the assertion of physical delivery that is required to claim NPNS as there was no distinction in our documentation between those contracts that physically delivered and those that booked-out.
At the same time, we performed a review of our other structured contracts for which we had previously claimed the NPNS exemption. As part of that review it was noted that the guidance within FAS 133 had been misapplied in certain limited instances, and that certain of those contracts did not in fact qualify for NPNS exemption.
Recognizing that the sales channels used by us were continuing to develop, certain procedural amendments were put in place in fiscal year 2005 to ensure that the FAS 133 treatment is continually monitored. The revised procedures that have been put in place involve reviews by legal, commercial, credit, accounting and risk personnel, together with more detailed ongoing reviews of unusual contracts. The procedures being followed are:
| • | Existing contracts are reviewed on an annual basis. |
149
| • | All new non-standard trading contracts now go through a two stage internal review process prior to placing firm commitment with external counter-parties. This internal review process includes a review by senior members of the Finance team with sufficient knowledge of the UK and US accounting rules who comment upon the accounting treatment of the contract under both UK and US GAAP. |
| • | Prior to a contract agreement being put in place, the broad details of the proposed transaction are set out to ensure that all relevant staff are aware of the proposal and that there are no major issues foreseen at that stage. |
| • | Once an agreement is in place, the proposal is set out in more detail, thus enabling the finance staff to formally recommend the correct accounting treatment under UK and US GAAP. |
Our Chief Executive Officer and our Chief Financial Officer, have evaluated the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as at March 31, 2004 (the “Evaluation Date”). They have concluded that as of the Evaluation Date, in light of the misapplication of FAS 109 and FAS 133 described above (which we have identified as a material weakness in relation to FAS 109 and FAS 133 and which have been corrected since the Evaluation Date), our disclosure controls and procedures at that time cannot be deemed to have been effective to ensure that material information relating to us and our consolidated subsidiaries was accumulated, recorded, processed, summarized, communicated to management, including our Chief Executive Officer and our Chief Financial Officer, and reported in a timely manner.
There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of such controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their controls objectives. Acknowledging this, we have designed our disclosure controls and procedures to provide such reasonable assurance.
In accordance with Section 404 of the Sarbanes-Oxley Act 2002, we are undertaking a comprehensive review of our internal control processes and controls for financial reporting purposes, and will report the findings in our Annual Report on Form 20-F for the year ending March 31, 2005.
Changes in Internal Controls
There were no changes in our internal controls over financial reporting during the period covered by the annual report that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT
Our Board of Directors has determined that Ian Harley and John Delucca are “audit committee financial experts.”
We have not adopted a code of ethics that meets the specific requirements of a “code of ethics” as defined in the rules promulgated under the Sarbanes-Oxley Act because we currently have, and distribute to all personnel, a code of conduct that governs the ethical and moral conduct of our officers, directors and employees. We are formulating a more all embracing code of ethics which will be published with our Corporate Social Responsibility Report later in the year.
150
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES
It is our policy to engage PricewaterhouseCoopers LLP on assignments where their expertise and experience with British Energy are important, or where they win work on a competitive basis. An analysis of auditor’s remuneration for the past two fiscal years ending March 31, 2003 and 2004 is as follows:
| 2004 |
2003 | |||||||
| £000’s |
% |
£000’s |
% | |||||
| Audit Related Fees |
768 | 13 | 695 | 23 | ||||
| Tax Fees |
510 | 9 | 331 | 11 | ||||
| All Other Fees |
||||||||
| — Creditors’ long form report |
2,017 | 35 | — | — | ||||
| — Reporting accountant—working capital report |
1,208 | 21 | 532 | 17 | ||||
| — Review of accounting for restructuring |
1,114 | 20 | 1,111 | 36 | ||||
| — Other non-audit services |
80 | 1 | 409 | 13 | ||||
| Total |
5,697 | 100 | 3,078 | 100 | ||||
ITEM 16D.
Not Applicable
ITEM 16E.
Not Applicable
See Item 18.
See our audited consolidated financial statements beginning at page F-1.
| 1.01 | Articles of Association of British Energy plc, as amended.(1) | |
| 1.02 | Memorandum of Association of British Energy plc.(2) | |
| 4.01 | Trust Deed, dated March 25, 1999 among British Energy plc, British Energy Generation Limited, British Energy Generation (UK) Limited and The Law Debenture Trust Corporation constituting £134,586,000 6.202% Guaranteed Bonds due 2016 and £163,444,000 6.077% Guaranteed Bonds due 2006 and £109,861,000 5.949% Guaranteed Bonds due 2003 guaranteed by British Energy Generation Limited and British Energy Generation (UK) Limited.(2) | |
| 4.02 | Master Purchase Agreement dated January 17, 2003 for the disposal of British Energy’s interest in Bruce Power Limited Partnership was entered into between, amongst others, British Energy and (i) Cameco Corporation, (ii) BPC Generation Infrastructure Trust and (iii) TransCanada Pipelines Limited.(1) | |
| 4.03 | Standstill Agreement dated February 14, 2003 between British Energy plc and (i) the steering committee of the Eggborough Bank Syndicate, (ii) The Royal Bank of Scotland plc as provider | |
151
| of a letter of credit to the Eggborough Banks, (iii) Teesside Power Limited, (iv) TotalFinaElf Gas and Power Limited, (v) Enron Capital & Trade Europe Finance LLC and (vi) British Nuclear Fuels plc.(4) | ||
| 4.04 | Bondholder Restructuring (Standstill) Agreement dated February 14, 2003 between British Energy plc, British Energy Generation Limited and British Energy Generation (UK) Limited and (i) certain Bondholders owning 58% of the £109,861,000 5.949% Guaranteed Bonds due 2003, (ii) certain Bondholders owning 55% of the £163,444,000 6.077% Guaranteed Bonds due 2006 and (iii) certain Bondholders owning 75% of the £134,586,000 6.202% Guaranteed Bonds due 2016.(4) | |
| 4.05 | The Deed of Amendment and Guarantee between British Energy Generation Limited, British Nuclear Fuels plc (“BNFL”) and British Energy plc dated March 31, 2003 (as amended on July 22, 2003) relating to the Agreement for the supply of Fuel for Use in Advanced Gas Cooled Reactors between Nuclear Electric Limited and BNFL dated June 3, 1997, as amended.(4)(5) | |
| 4.06 | Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003, (as amended).(4) | |
| 4.07 | Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Reactors from April 1, 2006 between British Energy Generation (UK) Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003 (as amended)(4) | |
| 4.08 | Deed of Amendment and Guarantee between British Energy Generation (UK) Limited, British Nuclear Fuels plc and British Energy plc, dated March 31, 2003 (as amended) relating to the Agreement for the Supply of Fuel for Use in Advanced Gas Cooled Nuclear Reactors between Scottish Nuclear and BNFL dated March 30, 1995 as amended.(4)(5) | |
| 4.09 | Nuclear Electric—Generation License.(2) | |
| 4.10 | Scottish Nuclear—Generation License.(2) | |
| 4.11 | Representative Nuclear Site License.(2) | |
| 4.12 | Credit Facility Agreement dated September 26, 2002 as amended and restated on March 7, 2003 and further amended by a side letter dated August 15, 2003 between the UK Secretary of State and (i) British Energy, British Energy General (UK) Limited, British Energy Generation Limited and British Energy Power and Energy Trading Limited as borrowers and (ii) British Energy, British Energy General (UK) Limited, British Energy Generation Limited, British Energy Power and Energy Trading Limited, British Energy Investment Limited, District Energy Limited, British Energy International Holdings Limited, British Energy US Holdings Inc., British Energy L.P. and Peel Park Funding Limited as guarantors.(4) | |
| 4.13 | Purchase and Sale Agreement dated as of September 11, 2003 between British Energy Investment Limited and FPL Energy Nuclear Mid-Atlantic, LLC relating to the sale and purchase of 100% of the shares of British Energy US Holdings Inc.(5) | |
| 4.14 | Purchase and Sale Agreement dated as of October 10, 2003 between British Energy Investment Limited and Exelon Generation Company, LLC relating to the sale and purchase at 100% of the shares of British Energy US Holdings Inc.(5) | |
| 4.15 | Government Restructuring Agreement dated October 1, 2003 between British Energy plc, British Energy Generation (UK) Limited, British Energy Generation Limited, certain other British Energy parties, the Nuclear Generation Decommissioning Fund Limited (to be renamed Nuclear Liabilities Fund Limited), the Trustees of the Nuclear Trust and the Secretary of State for Trade and Industry.(5) | |
152
| 4.16 | Creditor Restructuring Agreement dated as of September 30, 2003 between British Energy plc, British Energy Generation Limited, British Energy Generation (UK) Limited, British Energy Power and Energy Trading Limited, Eggborough Power Limited, Eggborough Power Holdings Limited, Teesside Power Limited, Total Gas & Power Limited, Enron Capital & Trade Europe Finance LLC, the Royal Bank at Scotland plc, British Nuclear Fuels plc, the consenting EPL Banks (as defined) and the consenting EPL Bondholders (as defined) (as amended on October 24, 2003).(5) | |
| 4.17 | New Standstill Agreement dated February 13, 2004 between British Energy plc and (i) the steering committee of the Eggborough Bank Syndicate, (ii) The Royal Bank of Scotland plc, (iii) Teesside Power Limited, (iv) Barclays Bank PLC, (v) Enron Capital & Trade Europe Finance LLC, (vi) Deutsche Bank AG and (vii) BNFL.(5) | |
| 8.01 | List of Subsidiaries of British Energy plc.(3) | |
| 12.1 | Certification of William Coley, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 12.2 | Certification of Stephen Billingham, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 13.1 | Certification by Chief Executive Officer of British Energy plc of periodic financial report pursuant to 18 U.S.C. Section 1350, as mandated by Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 13.2 | Certification by Chief Financial Officer of British Energy plc of periodic financial report pursuant to 18 U.S.C. Section 1350, as mandated by Section 906 of the Sarbanes-Oxley Act of 2002. | |
| (1) | As filed on the registrant’s Annual Report on Form 20-F on September 23, 2003 (File No. 1-14990). |
| (2) | As filed on the registrant’s Registration Statement submitted on Form 20-FR on December 6, 1999 (File No. 1-14990). |
| (3) | As filed on the registrant’s Annual Report submitted on Form 20-F on August 13, 2001 (File No. 1-14990). |
| (4) | As filed on the registrant’s Annual Report submitted on Form 20-F on September 23, 2003 (File No. 1-14990). |
| (5) | As filed on the registrant’s Annual Report submitted on Form 20-F on September 30, 2004. |
The registrant agrees to furnish to the Securities and Exchange Commission upon request a copy of any instrument which defines the rights of holders of long-term debt of British Energy and its consolidated subsidiaries.
153
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the Registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.
| BRITISH ENERGY plc | ||
| By: |
/s/ Stephen Billingham | |
| Name: | Stephen Billingham | |
| Title: | Chief Financial Officer | |
| June 24, 2005 | ||
US FORM 20-F
Financials
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members of British Energy plc:
We have audited the accompanying consolidated balance sheets of British Energy plc and its subsidiaries, together “the Group,” as of March 31, 2004 and 2003, and the related consolidated statements of profit and loss account, cash flows, and total recognized gains and losses for each of the three years in the period ended March 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and auditing standards generally accepted in the United Kingdom. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of British Energy plc and its subsidiaries as at March 31, 2004 and 2003, and the results of their operations and their cash-flows for each of the three years in the period ended March 31, 2004 in conformity with accounting principles generally accepted in the United Kingdom.
The accompanying financial statements have been prepared assuming that the Group will continue as a going concern. As discussed in Note 1 to the financial statements, the validity of this depends on the fulfilment of the conditions of the Proposed Restructuring and the achievement of the Group’s cash generating initiatives, in each case within the time scales envisaged or required and the continuation of the restructuring and standstill arrangements with certain creditors and financial assistance from the Secretary of State pursuant to the Government Facility and there being no material deterioration in the Group’s cash flow position, performance or outlook. In view of the significance of the uncertainties concerning these matters, together with the losses from operations and net capital employed deficiency, there is substantial doubt about the Group’s ability to continue as a going concern. The Board’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Accounting principles generally accepted in the United Kingdom vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences, as restated, is presented in note 36 to the Consolidated Financial Statements.
PricewaterhouseCoopers LLP
Chartered Accountants and Registered Auditors
Edinburgh, United Kingdom
June 17, 2004 except with respect to note 36 (ii) for which the date is July 25, 2005
F-2
GROUP PROFIT AND LOSS ACCOUNTS
For the years ended March 31, 2004, 2003 and 2002
| Notes | 2004 |
2003 |
2002 |
||||||||
| £m | £m | £m | |||||||||
| Turnover: Group and share of joint venture |
1,660 | 2,115 | 2,259 | ||||||||
| Less: Share of turnover in joint venture |
(144 | ) | (212 | ) | (210 | ) | |||||
| Turnover: |
|||||||||||
| —continuing activities |
1,516 | 1,528 | 1,701 | ||||||||
| —discontinued activities |
— | 375 | 348 | ||||||||
| Turnover |
3 | 1,516 | 1,903 | 2,049 | |||||||
| Operating costs before exceptional items |
4 | (1,459 | ) | (1,758 | ) | (1,818 | ) | ||||
| Exceptional items |
4 | 283 | (3,947 | ) | (512 | ) | |||||
| Operating costs after exceptional items |
4 | (1,176 | ) | (5,705 | ) | (2,330 | ) | ||||
| Group operating profit/(loss) |
|||||||||||
| —continuing activities |
340 | (3,899 | ) | (333 | ) | ||||||
| —discontinued activities |
— | 97 | 52 | ||||||||
| Group operating profit/(loss) |
340 | (3,802 | ) | (281 | ) | ||||||
| Share of operating profit of discontinued joint venture |
21 | 43 | 37 | ||||||||
| Operating profit/(loss): group and share of joint venture |
361 | (3,759 | ) | (244 | ) | ||||||
| Profit/(loss) on sale of investments |
5 | 47 | (35 | ) | 4 | ||||||
| Financing (charges)/credits |
|||||||||||
| —revalorization |
8 | (185 | ) | (205 | ) | (160 | ) | ||||
| —net interest payable |
8 | (64 | ) | (72 | ) | (66 | ) | ||||
| —exceptional items |
8 | 73 | (221 | ) | (27 | ) | |||||
| Profit/(loss) on ordinary activities before taxation |
232 | (4,292 | ) | (493 | ) | ||||||
| Taxation on profit/(loss) on ordinary activities |
9 | 2 | 378 | 4 | |||||||
| Share of taxation for joint venture |
9 | — | (10 | ) | (29 | ) | |||||
| Profit/(loss) on ordinary activities after taxation |
234 | (3,924 | ) | (518 | ) | ||||||
| Minority interest |
— | (17 | ) | (9 | ) | ||||||
| Profit/(loss) attributable to shareholders |
234 | (3,941 | ) | (527 | ) | ||||||
| Dividends |
|||||||||||
| —annual |
11 | — | — | (48 | ) | ||||||
| —non-equity |
11 | — | — | (2 | ) | ||||||
| Profit/(loss) for the year |
27 | 234 | (3,941 | ) | (577 | ) | |||||
| Earnings/(loss) per share (p) |
|||||||||||
| —basic |
12 | 38.9 | (654.7 | ) | (88.5 | ) | |||||
| —diluted |
12 | 38.9 | (654.7 | ) | (88.5 | ) | |||||
| Dividends per share (p) |
|||||||||||
| —annual |
11 | — | — | 8.0 | |||||||
| —non-equity |
11 | — | — | 2.3 | |||||||
Other gains and losses for the years are set out in the Statement of Total Recognized Gains and Losses on Page F5.
Notes 1 to 36 form part of these financial statements.
F-3
BALANCE SHEETS
As at March 31, 2004 and 2003
| Group |
Company |
|||||||||||||
| Notes | 2004 |
2003 |
2004 |
2003 |
||||||||||
| £m | £m | £m | £m | |||||||||||
| Fixed assets |
||||||||||||||
| Tangible assets |
13 | 931 | 686 | — | — | |||||||||
| Investment in joint venture: |
||||||||||||||
| —share of gross assets |
— | 477 | — | — | ||||||||||
| —share of gross liabilities |
— | (406 | ) | — | — | |||||||||
| 14 | — | 71 | — | — | ||||||||||
| Other investments |
14 | 6 | 6 | 10 | 14 | |||||||||
| 937 | 763 | 10 | 14 | |||||||||||
| Current assets |
||||||||||||||
| Decommissioning fund |
15 | 440 | 334 | — | — | |||||||||
| Stocks |
16 | 350 | 360 | — | — | |||||||||
| Debtors |
17 | 374 | 387 | 11 | 85 | |||||||||
| Investments—liquid funds |
31 | 311 | 246 | 249 | 210 | |||||||||
| Cash at bank |
31 | 262 | 87 | 256 | 83 | |||||||||
| 1,737 | 1,414 | 516 | 378 | |||||||||||
| Creditors: amounts falling due within one year |
||||||||||||||
| —borrowings |
19 | (197 | ) | (152 | ) | (110 | ) | (110 | ) | |||||
| —other |
18 | (1,250 | ) | (1,033 | ) | (4,496 | ) | (3,742 | ) | |||||
| (1,447 | ) | (1,185 | ) | (4,606 | ) | (3,852 | ) | |||||||
| Net current assets/(liabilities) |
290 | 229 | (4,090 | ) | (3,474 | ) | ||||||||
| Total assets less current assets/(liabilities) |
1,227 | 992 | (4,080 | ) | (3,460 | ) | ||||||||
| Creditors: amounts falling due after more than one year |
||||||||||||||
| —borrowings |
19 | (686 | ) | (731 | ) | (298 | ) | (298 | ) | |||||
| —other |
18 | (1,893 | ) | (1,909 | ) | — | — | |||||||
| Provisions for liabilities and charges |
21 | (1,812 | ) | (1,735 | ) | (5 | ) | (9 | ) | |||||
| Net liabilities |
(3,164 | ) | (3,383 | ) | (4,383 | ) | (3,767 | ) | ||||||
| Capital and reserves |
||||||||||||||
| Called up equity share capital |
26 | 277 | 277 | 277 | 277 | |||||||||
| Share premium |
76 | 76 | 76 | 76 | ||||||||||
| Capital redemption reserve |
350 | 350 | 350 | 350 | ||||||||||
| Profit and loss account |
27 | (3,960 | ) | (4,179 | ) | (5,179 | ) | (4,563 | ) | |||||
| Equity shareholders’ interests |
28 | (3,257 | ) | (3,476 | ) | (4,476 | ) | (3,860 | ) | |||||
| Non-equity shareholders’ interests |
26 | 93 | 93 | 93 | 93 | |||||||||
| Capital employed |
(3,164 | ) | (3,383 | ) | (4,383 | ) | (3,767 | ) | ||||||
Notes 1 to 36 form part of these financial statements.
F-4
GROUP CASH FLOW STATEMENTS
for the years ended March 31, 2004, 2003 and 2002
| Notes | 2004 |
2003 |
2002 |
||||||||
| £m | £m | £m | |||||||||
| Net cash inflow from operating activities |
29 | 156 | 336 | 380 | |||||||
| Interest paid |
(85 | ) | (91 | ) | (62 | ) | |||||
| Interest received |
10 | 9 | 13 | ||||||||
| Fees paid |
— | — | (2 | ) | |||||||
| Dividends paid on non-equity shares |
— | (2 | ) | (2 | ) | ||||||
| Returns on investments and servicing of finance |
(75 | ) | (84 | ) | (53 | ) | |||||
| Taxation (paid)/received |
(12 | ) | 3 | 4 | |||||||
| Payments to acquire tangible fixed assets |
— | (282 | ) | (225 | ) | ||||||
| Receipts from sales of financial investments |
— | — | 38 | ||||||||
| Capital expenditure and financial investment |
— | (282 | ) | (187 | ) | ||||||
| Receipts from sale of Canadian investment |
171 | 262 | — | ||||||||
| Investment in North America |
— | — | (129 | ) | |||||||
| Acquisitions and disposals |
171 | 262 | (129 | ) | |||||||
| Equity dividends paid |
— | (31 | ) | (46 | ) | ||||||
| (Increase)/decrease in term deposits |
(65 | ) | (37 | ) | 18 | ||||||
| Management of liquid resources |
31 | (65 | ) | (37 | ) | 18 | |||||
| Minority funding of Bruce Power |
— | 12 | 4 | ||||||||
| New loans, net of repayments of amounts borrowed |
— | (92 | ) | 9 | |||||||
| Financing |
— | (80 | ) | 13 | |||||||
| Movement in cash |
31 | 175 | 87 | — | |||||||
STATEMENT OF TOTAL RECOGNIZED GAINS AND LOSSES
for the years ended March 31, 2004, 2003 and 2002
| Notes | 2004 |
2003 |
2002 |
||||||||
| £m | £m | £m | |||||||||
| Profit/(loss) for the financial year |
234 | (3,941 | ) | (527 | ) | ||||||
| Translation differences on foreign currency net investments |
28 | (15 | ) | (25 | ) | (8 | ) | ||||
| Total recognized gains/(losses) for the year |
219 | (3,966 | ) | (535 | ) | ||||||
| Prior year adjustment in respect of accounting policy changes |
— | — | (130 | ) | |||||||
| Total recognized gains/(losses) since last annual report |
219 | (3,966 | ) | (665 | ) | ||||||
Notes 1 to 36 form part of these financial statements.
F-5
NOTES FOR FINANCIAL STATEMENTS
for the year ended March 31, 2004
1. BASIS OF PREPARATION
(i) Introduction
The Group accounts are a consolidation of the financial statements of the Company and all its subsidiary undertakings, and are drawn up on a non-restructured basis, i.e. on the basis of contracts and agreements in place at March 31, 2004. In the following discussion British Energy plc is referred to as ‘British Energy’ or ‘the Company’ and ‘the Group’ refers to the Company and its subsidiary undertakings.
On February 14, 2003, the Group disposed of its stake in Bruce Power Limited Partnership (‘Bruce Power’) and Huron Wind Limited Partnership (‘Huron Wind’), therefore, their results up to the point of disposal have been classified as discontinued activities within prior reporting periods. On December 22, 2003, the Group disposed of its 50% interest in AmerGen Energy Company LLC (‘AmerGen’), therefore, its results up to the point of disposal have been classified as discontinued joint venture operations during the year. All other activities of the Group have been shown as continuing activities
(ii) Background to Proposed Restructuring
Having reviewed the longer-term prospects of the business, on September 5, 2002 the Directors of British Energy announced that they had no alternative but to seek financial support from the UK Government. On September 9, 2002 the UK Government granted the Company a credit facility of up to £410m (the ‘Government Facility’) to provide working capital for the Group’s immediate requirements and to allow British Energy to stabilise its trading position in the UK and North America. On September 26, 2002 British Energy announced that the UK Government had agreed to extend a revised Government Facility for up to £650m until November 29, 2002 to give the Company sufficient opportunity to develop a restructuring plan. On November 28, 2002 British Energy announced that the Government Facility had been further extended until March 9, 2003. The Government Facility is cross-guaranteed by the principal Group subsidiaries (excluding Eggborough Power (Holdings) Limited and Eggborough Power Limited (‘EPL’)) and is secured by, among other things, fixed and floating charges and/or share pledges granted by those subsidiaries. The Government Facility also contains a requirement to provide further security as required by the Secretary of State for Trade and Industry (the ‘Secretary of State’) provided that the creation of such security would not cause a material default under any contract to which any member of the Group is a party or a breach of law.
On February 14, 2003 British Energy and certain of its subsidiaries announced that they had entered into binding standstill agreements, namely:
| (a) | the Standstill Agreement between British Energy and its subsidiaries and the bank syndicate that provided financing for the Eggborough coal-fired power station (the ‘Eggborough Banks’), The Royal Bank of Scotland plc (‘RBS’) as provider of a letter of credit to the Eggborough Banks, our significant trade creditors, Teesside Power Limited (‘TPL’), TotalFinaElf Gas and Power Limited (now Total Gas & Power Limited) (‘Total’) and Enron Capital & Trade Europe Finance LLC (‘Enron’) (TPL, Total (which has subsequently transferred its interest to Deutsche Bank) and Enron (which has also subsequently transferred its interest to Deutsche Bank) being collectively referred to as the ‘Significant Creditors’) and British Nuclear Fuels plc (‘BNFL’); and |
| (b) | the Bondholder Restructuring Agreement between British Energy, British Energy Generation Limited (‘BEG’), British Energy Generation (UK) Limited (‘BEGUK’) and certain holders of British Energy bonds due in 2003, 2006 and 2016 (the holders of those bonds being referred to collectively as the ‘Bondholders’). |
F-6
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
On March 7, 2003 British Energy announced that the UK Government had agreed to extend the Government Facility in the reduced amount of £200m, such that it would mature on the earliest of (1) September 30, 2004, (2) the date on which the proposed restructuring, outlined in (iii) below, (the ‘Proposed Restructuring’) becomes effective, and (3) any date notified by the Secretary of State to British Energy on which repayment of amounts outstanding under the Government Facility are required as a result of a European Commission (‘Commission’) decision or an obligation under EU law (the ‘Final Maturity Date’). In the meantime the Secretary of State may require repayment of the Government Facility if she concludes that the Proposed Restructuring cannot be completed in the manner or time scales envisaged.
On October 1, 2003, the Company announced that it had agreed the terms of the Proposed Restructuring of the Group with certain of the Group’s creditors and the Secretary of State and by October 31, 2003 had obtained the further approvals and agreements required.
The Company also agreed the proposed disposal of its 50% interest in AmerGen to Exelon Generation Company LLC (‘Exelon’) in October 2003 for US$277m, subject to various adjustments and conditions including a break fee of US$8.295m payable to FPL Group Inc. The disposal was completed on December 22, 2003.
The Government Facility was temporarily increased to £275m on November 27, 2003. The additional £75m ceased to be available on the Group’s receipt of the proceeds from the sale of AmerGen on December 23, 2003.
On December 19, 2003 Bondholders approved amendments to the trust deed constituting the bonds to facilitate the implementation of the Proposed Restructuring and to amend the standstill arrangements under the trust deed on terms consistent with the Creditor Restructuring Agreement (as defined in (iii) below). Following formal amendment of the trust deed, a new standstill agreement has been entered into with creditors in place of the Standstill Agreement dated February 14, 2003 in accordance with the terms of the Creditor Restructuring Agreement.
We have retained a trading relationship with a high proportion of our existing contracted counterparties during the period since our announcement of September 5, 2002, although in most cases we have been required to provide alternative credit support to a parent company guarantee. Given the financial circumstances of the Group, certain contracts may be capable of being terminated. Such termination may result in termination payments being payable as well as having an adverse effect on our cash flows.
The Company faced short-term pressures on liquidity during the year resulting from the combined effect of seasonality, the unplanned outage at Heysham 1 and the increased levels of collateral and costs of unplanned outages brought about by the increased level of volatility in electricity prices. The Board is exploring initiatives to achieve sufficient liquid resources to implement the Proposed Restructuring, including investigating the availability of third party financing.
The alternative credit support currently in place has been provided by the Group under banking arrangements involving the UK Government established in connection with the Government Facility. The Group is seeking to replace these with arrangements which do not involve the UK Government before the Final Maturity Date of the Government Facility and over the longer term to reduce the demand for trading collateral.
F-7
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(iii) Terms of the Proposed Restructuring
The terms of the Proposed Restructuring are set out in:
| (a) | the Creditor Restructuring Agreement dated as of September 30, 2003 and entered into by the Company, certain other Group companies, the Significant Creditors, RBS, the members of the ad hoc committee of British Energy’s Bondholders and BNFL (as amended by a side letter entered into on October 31, 2003) (the ‘Creditor Restructuring Agreement’); and |
| (b) | the Government Restructuring Agreement dated October 1, 2003 and entered into between the Company, BEGUK, BEG, British Energy Power and Energy Trading Limited (‘BEPET’), British Energy Investment Limited, District Energy Limited, British Energy International Holdings Limited, British Energy US Holdings Inc., British Energy L.P., Peel Park Funding Limited, the Secretary of State, the Nuclear Generation Decommissioning Fund Limited (to be renamed the Nuclear Liabilities Fund Limited (‘NLF’)) and the trustees of the Nuclear Trust (the ‘Government Restructuring Agreement’). |
The Creditor Restructuring Agreement required certain further creditor approvals and sign ups. By October 31, 2003 all these requirements had been satisfied as follows:
| (a) | bondholders representing in aggregate with RBS 88.8% of the combined amount owing to the Bondholders and RBS had signed up to the Creditor Restructuring Agreement; |
| (b) | the terms of the Proposed Restructuring had been approved by the credit committee of RBS; and |
| (c) | all of the lenders and swap providers comprising the Eggborough Banks had signed up to the Creditor Restructuring Agreement with full credit committee approvals. |
The principal features of the Proposed Restructuring include:
| • | compromising the existing claims of Bondholders, RBS, Significant Creditors and the Eggborough Banks in exchange for new bonds and new ordinary shares and settling new arrangements for Eggborough (the claims of the Bondholders and RBS will be exchanged pursuant to a scheme of arrangement to be proposed to these creditors by the Company (the Creditors’ Scheme). In the case of the Significant Creditors and the Eggborough Banks, claims will be exchanged pursuant to the terms of the Creditor Restructuring Agreement itself); |
| • | the amendment and extension of the BNFL contracts for front end and back end related fuel services for the Group’s AGR stations announced on May 16, 2003 and the implementation of a new trading strategy; |
| • | establishing the NLF which will assume financial responsibility for certain uncontracted nuclear liabilities and decommissioning costs in return for initial and ongoing contributions from British Energy; and |
| • | the Government funding liabilities relating to certain historic spent fuel and any shortfall in the NLF. |
F-8
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Creditor Restructuring Agreement
Conditions
Completion of the Proposed Restructuring is subject to a large number of conditions in the Creditor Restructuring Agreement including, amongst other things:
| • | the receipt by the Secretary of State of notification of a satisfactory decision by the Commission that insofar as the proposals involve the grant of State Aid by the UK Government, such aid is compatible with the common market. The Secretary of State expects to receive this notification this autumn; |
| • | there being no material adverse change (see below); |
| • | the Government Restructuring Agreement becoming unconditional; |
| • | agreement of presently unsettled documents with creditors; |
| • | the approval of the Scottish Court; and |
| • | the listing of the new shares and bonds and delisting of the ordinary and A shares. |
For the purposes of the Creditor Restructuring Agreement, a material adverse change is defined as a material adverse change in the current or future business or operations, the financial or trading position, profits or prospects of the Group as a whole or of EPL or a change in the current or future business or operations, the financial or trading position, profits or prospects of the Group as a whole which is likely to have a material adverse effect on the value of the new bonds, the new ordinary shares (to be issued as part of the Proposed Restructuring), the CTA global bond to be held by EPL to fund the £150m of new bond-equivalent payments under the new Eggborough arrangements (the ‘CTA Global Bond’) or the new Eggborough arrangements.
Creditor allocations
Under the terms of the Creditor Restructuring Agreement the creditors have agreed (subject to certain conditions) to extinguish their existing unsecured claims against the Group in exchange for £275m of new bonds and at least 97.5% of the issued ordinary shares of the new parent company of the Group (‘Newco 1’).
In addition, the Eggborough Banks, as creditors with security over the assets of and shares in EPL, have agreed (subject to certain conditions) to replace their existing secured claims with a right to payments under an Amended and Restated Credit Agreement (the ‘Amended Credit Agreement’) having a payment profile equivalent to £150m of new bonds secured over the assets of and shares in EPL. The Eggborough Banks will also have an option to acquire the Eggborough station either through a share or asset purchase in 2010 upon payment of an approximate £104m break fee and the extinguishment of the principal then outstanding under the Amended Credit Agreement. This option may be accelerated in the event of a default under the Amended Credit Agreement. The security over the assets of and shares in EPL under the Amended Credit Agreement will secure both the £150m bond-equivalent payments and, through an indemnity for non-performance, the option acceleration.
Standstill arrangements
The Creditor Restructuring Agreement and ancillary agreements restrict the Significant Creditors, the Eggborough Banks, RBS, each Bondholder who signs up to the Creditor Restructuring Agreement
F-9
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(the ‘Consenting Bondholders’) and BNFL (together the ‘Consenting Creditors’) from taking any steps to initiate insolvency proceedings or demand or accelerate any amounts due and payable by British Energy during the period of the standstill (the ‘Standstill Period’) until the earliest of:
| (a) | 12 noon on the earlier of January 31, 2005 and the date falling 120 days after the satisfaction of the initial conditions to the Proposed Restructuring (the ‘Restructuring Longstop Date’); |
| (b) | termination of the Creditor Restructuring Agreement or the standstill arrangements in accordance with their terms; or |
| (c) | the completion of the Proposed Restructuring. |
Any of the Consenting Creditors may terminate the standstill arrangements following the occurrence of a termination event. The termination events include, inter alia, certain insolvency events affecting the Company, BEG, BEGUK, BEPET or EPL; acceleration of the Government Facility; and any of the Company, BEG, BEGUK, BEPET or EPL failing to discharge certain continuing obligations. If the standstill arrangements terminate, the Creditor Restructuring Agreement will also terminate and vice versa.
Under the standstill arrangements, RBS, the Eggborough Banks, Significant Creditors and Bondholders are to be paid interest but not principal in respect of any claims against the Group. Interest will continue to be paid to Bondholders and the Eggborough Banks in accordance with existing arrangements. The terms of the bonds were amended in March 2003 for interest to be paid on a six monthly rather than an annual basis. In respect of the Significant Creditors and RBS, interest was paid first on March 25, 2003 and is subsequently payable on the last business day of every six month period thereafter based on the agreed claim amounts (except in the case of RBS where interest payments will be based on the present value of its claim amount as at February 14, 2003). Commission will also continue to be paid to RBS under the facility agreement for the letter of credit to the Eggborough Banks.
The Creditor Restructuring Agreement also contains certain covenants by British Energy for the benefit of the Consenting Creditors that have signed it, including certain limitations on acquisitions and disposals, a prohibition on the payment of dividends and on the issuing of equity as well as a negative pledge.
Mechanics for implementation and shareholder allocation
The Proposed Restructuring will involve establishing Newco 1 as the new parent company of the Group and a directly wholly owned subsidiary of Newco 1 as an intermediate holding company (‘Newco 2’).
The Company proposes to cancel its existing ordinary shares of 44 28/43 pence each and A shares of 60 pence each under a scheme of arrangement with its shareholders (the ‘Members’ Scheme’), and issue to shareholders: (i) new ordinary shares in Newco 1 equal to 2.5% of the issued share capital of Newco 1 immediately following implementation of the Proposed Restructuring, and (ii) warrants to subscribe for a maximum of 5% of the thereby diluted ordinary issued share capital of Newco 1 (excluding, amongst others, the impact of conversion of the NLF Cash Sweep Payment (see section entitled ‘Government Restructuring Agreement’ below)) immediately following implementation of the Proposed Restructuring. The subscription price under the warrants is £28.95m in aggregate, equivalent
F-10
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
to an equity market capitalization of the Group of £550m following implementation of the Proposed Restructuring. This will result in a very significant dilution of the holdings of the existing shareholders.
If the Members’ Scheme is not approved by the requisite majority of shareholders or for any other reason the Members’ Scheme is not implemented, the Company will dispose of all its business and assets to Newco 2. If the disposal is approved by the shareholders in general meeting, shareholders will receive only the warrants. If neither proposal is approved by shareholders, they will receive no shares or warrants.
Government Restructuring Agreement
The Government Restructuring Agreement provides for the circumstances in which the Secretary of State will support the Proposed Restructuring, including entering into the agreements with the Group and, in certain cases, the NLF, which affect the proposals regarding the manner in which the decommissioning and other uncontracted liabilities of the Group are to be funded and the agreements relating to the funding of certain of the contracted nuclear liabilities of the Group (the ‘Nuclear Liabilities Agreements’). It also affects some further amendments to the Government Facility. As noted above the Government Facility will terminate (unless previously extended) on the Final Maturity Date.
Conditions
Under the Government Restructuring Agreement, the obligations of the Secretary of State to support the Proposed Restructuring (including as the holder of a number of special shares) and of the parties to the Nuclear Liabilities Agreements to enter into them are conditional on, among other things:
| • | the Creditor Restructuring Agreement becoming unconditional in all respects by the Restructuring Longstop Date; |
| • | the Secretary of State not having determined and notified British Energy in writing that, in her opinion, the Group (including Newco 1 and Newco 2) will not be viable in all reasonably foreseeable conditions without access to additional financing (other than financing which the Secretary of State is satisfied has been committed and will continue to be available when required); |
| • | there being no continuing event of default under the Government Facility; |
| • | receipt by the Secretary of State of copies of letters giving the confirmations relating to working capital referred to in the terms of Rule 2.18 of the UKLA Listing Rules without qualification (whether or not Newco 1 is to be listed on the Official List of the UKLA); |
| • | the representations and warranties given by the members of the Group being true, accurate and not misleading when given and if repeated at the effective date of the Proposed Restructuring; and |
| • | there being no breach of any undertaking given by any member of the Group pursuant to the Government Restructuring Agreement which, in the opinion of the Secretary of State, is or is likely to be material in the context of the Proposed Restructuring. |
If any of the conditions are not fulfilled or waived by the Secretary of State by the time specified in the requisite conditions or if no such date is specified, by the Restructuring Longstop Date, the Government Restructuring Agreement will terminate. In addition if a material adverse change (as defined in the Creditor Restructuring Agreement) occurs at any time before the order sanctioning the
F-11
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Creditors’ Scheme is filed with the Registrar of Companies in Scotland, the Secretary of State may give written notice to British Energy to terminate the Government Restructuring Agreement.
Nuclear Liabilities Agreements
Under the Nuclear Liabilities Agreements to be entered into pursuant to the Government Restructuring Agreement, the NLF will assume financial responsibility for discharging certain of the Group’s uncontracted nuclear liabilities and the costs of decommissioning the Group’s nuclear power stations, and the Secretary of State will assume financial responsibility for certain of the Group’s contracted nuclear liabilities and any shortfall in the NLF. In consideration for this assumption of financial responsibility, Newco 2 will issue £275m in new bonds to the NLF. In addition, members of the Group will make the following payments to the NLF; (i) fixed decommissioning contributions of £20m per annum (indexed to RPI and tapering as stations are currently scheduled to close); (ii) £150,000 (indexed to RPI) for every tonne of fuel loaded into the Sizewell B reactor after completion of the Proposed Restructuring; and (iii) an annual contribution equal to (initially and subject to adjustment but not to exceed) 65% of the Group’s increase in cash, cash equivalents and other liquid assets, during the year after adjusting for the NLF Cash Sweep Payment and any dividends paid in the year the proceeds from issuers or sales of shares and notional transfers to cash reserves and the Forecast Expenditure Reserve. (the ‘NLF Cash Sweep Payment’).
The entitlement of the NLF to the NLF Cash Sweep Payment is convertible into an equity shareholding in British Energy Group plc. equal to the same percentage of the thereby enlarged issued share capital. Although the NLF will receive convertible ordinary shares equal to the then prevailing NLF Cash Sweep Payment percentage (again subject to a maximum of 65%) the terms of the convertible ordinary shares into which such entitlement will convert will limit the general voting rights attaching to such shares to a maximum of 29.9%.
In addition, under the Nuclear Liabilities Agreements, British Energy is required to establish and maintain cash reserves to provide collateral for trading and operations, cover lost revenue and costs resulting from plant outages and to meet other working capital requirements (the ‘Cash Reserve’). The initial target amount for the Cash Reserve is £490m plus the amount by which cash employed as collateral exceeds £200m.
(iv) Principles Underlying Going Concern Assumption
The financial statements have been prepared on a going concern basis in accordance with FRS18, because British Energy has not been liquidated nor is it ceasing to trade. The validity of this assumption depends on the fulfillment of the conditions of the Proposed Restructuring and achievement of the Group’s cash generation initiatives, in each case within the time scales envisaged or required and the continuation of the restructuring and standstill arrangements with certain creditors and financial assistance from the Secretary of State pursuant to the Government Facility and there being no material deterioration in the Group’s cash flow position, performance or outlook. This assumption is, therefore, subject to a large number of significant uncertainties and important conditions.
If for any reason British Energy is unable to meet its financial obligations as they fall due the Company may have to take appropriate insolvency proceedings and cease to be a going concern, in which case adjustments may have to be made to reduce the monetary values of assets to the recoverable amounts, to provide for further liabilities that might arise and to reclassify the fixed assets and long-term liabilities as current assets and liabilities.
F-12
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
2. ACCOUNTING POLICIES
(i) Basis of Accounting
The financial statements are prepared under the historical cost convention and in accordance with applicable accounting standards, except for the departures noted below.
Commodity trading contracts, where there is no associated physical delivery, are marked to market using externally derived market prices. This is a departure from the general provisions of Schedule 4 of the Companies Act 1985. An explanation of this departure is given in note 2 (xix).
The income recognized by the Group in respect of the long-term rate of return of the decommissioning fund is unrealized and its recognition is a departure from one of the accounting principles set out in Schedule 4 of the Companies Act 1985. An explanation of this departure is given in note 2 (xvii).
The preparation of accounts in conformity with UK and US Generally Accepted Accounting Principles 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 accounts and the reported amounts of revenues and expenses during the reporting period. Actual results can differ from those estimates.
In accordance with FRS18 the Directors have reviewed the Group’s accounting policies and confirm that they continue to be the most appropriate. A number of the policies require the Group to use a variety of estimation techniques. Significant factors considered when assessing the carrying value of assets include future electricity prices, expected annual output, expected station operating costs, remaining station lives and discount rates. Estimates of output, costs and timing of associated cash flows as well as the expected regulatory framework are key factors used to apply the stated policies for long-term nuclear liabilities and decommissioning as discussed further in note 2 (xvi) below.
The effect of the Proposed Restructuring of the Company, as noted above, will be significant and will result in, among other matters, the reassessment of estimates and assumptions which have been used to prepare these financial statements. In particular, the calculation of the carrying value of the nuclear stations will be reassessed on the basis of the new contracts with BNFL, the contribution of 65% of cash flow to the Nuclear Liabilities Fund and the likely review of the risk discount rate applied to the future cash flows.
In preparing these accounts changes in presentation have been made to the accounts previously presented in the Group’s published UK Annual Board Report and Accounts, with the exception of the consolidated cash flow statements, in order to comply with accounting presentation and disclosure requirements applicable in the United States. A reconciliation to US GAAP is set out in note 36.
(ii) Basis of Consolidation
The Group financial statements consolidate the financial statements of British Energy and all its subsidiary undertakings. Inter-company profits, transactions and balances are eliminated on consolidation.
F-13
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(iii) Turnover
Turnover represents sales of electricity, net of electricity purchases, and sales of other related goods. Turnover is shown net of value added tax and climate change levy.
Wholesale generation and direct supply sales are recognized on an accruals basis with reference to meter readings or where required based on management’s best estimate of electricity supplied.
Included within turnover is the mark to market of net unrealized gains and losses made from trades recorded within the proprietary trading book. Refer to note 2 (xix) for details of accounting treatment of proprietary trading.
(iv) Fuel Costs—Nuclear Front End
Advanced Gas Cooled Reactors (“AGR”)
Front end fuel costs consist of the costs of procurement of uranium, conversion and enrichment services and fuel element fabrication. Fabrication costs comprise fixed and variable elements. The fixed element is charged to the profit and loss account as incurred and the variable element, other than for unburnt fuel at shutdown, is charged to the profit and loss account in proportion to the amount of fuel burnt.
Pressurized Water Reactor (“PWR”)
All front-end fuel costs are variable and, other than for unburnt fuel at shutdown, are charged to the profit and loss account in proportion to the amount of fuel burnt.
Bruce Power
Front end fuel costs are recognized when fuel is loaded into the reactor. The reactors are continually reloaded and as such this method closely reflects fuel burnt. British Energy disposed of its interest in Bruce Power on February 14, 2003.
(v) Fuel Costs—Nuclear Back End
AGR
Spent fuel extracted from the reactors is sent for reprocessing and/or long-term storage and eventual disposal of resulting waste products. Back end fuel costs comprise the estimated cost of this process at current prices discounted back to current value in respect of both the amount of irradiated fuel burnt during the year and an appropriate proportion of unburnt fuel which will remain in the reactors at the end of their lives. All back end fuel costs, other than for unburnt fuel at shutdown, are charged to the profit and loss account in proportion to the amount of fuel burnt.
PWR
Back end fuel costs are based on wet storage in station ponds followed by dry storage and subsequent direct disposal of fuel. Back end fuel costs comprise the estimated cost of this process at current prices discounted back to current value. All back end fuel costs, other than for unburnt fuel at shutdown, are charged to the profit and loss account in proportion to the amount of fuel burnt.
F-14
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Bruce Power
Under the terms of the Bruce Power lease the responsibility for spent fuel, waste and decommissioning remains with Ontario Power Generation Inc. British Energy disposed of its interest in Bruce Power on February 14, 2003.
(vi) Unburnt Fuel at Shutdown
Due to the nature of the nuclear fuel process there will be some unburnt fuel in the reactors at station closure. The front end and back end costs of this fuel are charged to the profit and loss account over the estimated useful life of each nuclear station on a straight line basis.
(vii) Fuel Costs—Coal
Fuel costs for coal are determined on a weighted average cost basis.
(viii) Energy Supply Costs
Annual commitments payable under Renewable Obligation Certificates are reflected in the profit and loss account based on the volume of direct supply sales. Acquired certificates are recognized as assets on purchase and are offset against related obligation payments.
(ix) Research and Development
Research and development expenditure is charged to the profit and loss account as incurred.
(x) Pensions and Other Post-retirement Benefits
The Group continues to provide for UK pension costs in accordance with SSAP24. Contributions to the Group’s defined benefit pension schemes are assessed by qualified actuaries and are charged to the profit and loss account so as to spread the cost of pensions over employees’ working lives with the Group. The capital cost of ex-gratia and supplementary pensions is charged to the profit and loss account, to the extent that the arrangements are not covered by the surplus in schemes, in the accounting period in which they are granted. Differences between the amounts funded and the amounts charged to the profit and loss account are included in the balance sheet.
In Canada, the charges for pensions and other post retirement benefits are determined annually by actuaries on the basis of management estimates. These costs consisted of current service costs, interest and adjustments arising from plan amendments, changes in assumptions, and experience gains or losses, which were amortized on a straight line basis over the expected average remaining service life of the employees covered by the plan. Costs are recorded in the year in which employees render services. British Energy disposed of its interest in Canada on February 14, 2003.
(xi) Foreign Currencies
Transactions in foreign currencies are recorded at the rate of exchange at the date of the transaction or, if hedged forward, at the rate of exchange under the related forward currency contract. Assets and liabilities denominated in foreign currencies are retranslated into Sterling at the rate of exchange ruling at the date of the balance sheet or at the contracted rate if applicable. All differences are taken to the profit and loss account.
F-15
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
For consolidation purposes the assets and liabilities of overseas subsidiary undertakings and joint ventures are translated at closing exchange rates. Profit and loss accounts of such undertakings are consolidated at the average rates of exchange during the year up until the date of disposal. Differences on foreign exchange arising from the retranslation of the opening net investment in, and results of, subsidiary and associated undertakings and joint ventures are taken to reserves. Where appropriate, these are matched with differences arising on the translation of related foreign currency borrowings and are reported in the statement of total recognized gains and losses.
(xii) Tangible Fixed Assets and Depreciation, including Decommissioning Costs
Fixed assets comprise assets acquired or constructed by the Group. During the year ended March 31, 2004 all capital expenditure investment that would previously have been capitalized as fixed assets was expensed as operating costs following the fixed asset impairment review carried out in the year ended March 31, 2003. This arises because it is not possible to demonstrate that this expenditure enhanced the value of the Company’s fixed assets after taking account of the impairment review.
Fixed assets (other than assets in the course of construction) are stated in the balance sheet at cost less accumulated depreciation. Accumulated depreciation includes additional charges made where necessary to reflect impairment in value. Assets in the course of construction are stated at cost and not depreciated until brought into commission.
The carrying values of fixed assets are reviewed for impairment where there has been a trigger event by assessing the present value of estimated future cash flows and net realizable value compared with net book value. The calculation of estimated future cash flows is based on the Directors’ best estimates of future prices, output and costs and is therefore subjective.
The charge for depreciation of fixed assets is based on the straight line method so as to write-off the costs of assets, after taking into account provisions for diminution in value, over their estimated useful lives.
The asset lives adopted are subject to regular review and for the year ended March 31, 2004 were:
| AGR power stations |
25-35 years | |
| PWR power stations |
40 years | |
| Bruce power station assets |
18 years | |
| Coal power station |
12 years | |
| Other buildings |
40 years | |
| Other plant and equipment |
5 years |
The estimated costs for decommissioning the Group’s nuclear power stations are capitalized as part of the cost of construction and are depreciated over the same lives as the stations. These estimated costs are discounted having regard to the time scale whereby work will take place over many years after station closure. The estimated costs include the demolition and site clearance of the stations’ radioactive facilities and the management of waste.
(xiii) Fixed Asset Investments
Investments in subsidiaries are initially recorded at the nominal value of shares allotted. Fixed asset investments are stated at cost less amortization or provisions for diminution in value. The
F-16
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Group’s investment in its joint venture is stated at cost plus the Group’s share of retained earnings up until the date of disposal. The carrying value of all fixed asset investments is regularly assessed for permanent impairment and provision made, if appropriate.
Own shares purchased in respect of the Employee Share Option and ShareSave Option Schemes are held at cost less charges to write-down the shares to the option exercise prices over the minimum lives of the options. The carrying value of all own share investments is regularly assessed for permanent impairment and provision made if appropriate. The Group has taken advantage of the exemption relating to Inland Revenue approved schemes under UITF17 in respect of Save As You Earn Share Schemes.
(xiv) Stocks of Fuel, Stores and Spares
Stocks of fuel, stores and spares are valued at the lower of cost and net realizable value. The nuclear fuel stock is reduced by the provision for unburnt fuel at shutdown (note 2 (vi)). Strategic spares are amortized over the life of the asset to which they relate.
(xv) Deferred Taxation
Deferred tax is recognized in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or events that result in an obligation to pay more, or a right to pay less, tax in the future have occurred at the balance sheet date. The full amount of the provision is discounted using a discount rate similar to the current post tax rates of return on UK treasury gilts. Deferred tax assets are recognized only to the extent that the Directors consider that it is more likely than not that there will be suitable taxable profits from which the future reversal of the underlying timing differences can be deducted.
(xvi) Nuclear Liabilities
Nuclear liabilities represent provision for the Group’s liabilities in respect of the costs of waste management of spent fuel and nuclear decommissioning. The provisions represent the Directors’ best estimates of the costs expected to be incurred. They are calculated based on the latest technical evaluation of the processes and methods likely to be used, and reflect current engineering knowledge. The provisions are based on such commercial agreements as are currently in place, and reflect the Directors’ understanding of the current Government policy and regulatory framework. The Directors carry out an in-depth review of the adequacy of amounts provided on a five-yearly basis, and also review the amounts provided for significant change during the intervening years. Given that Government policy and the regulatory framework on which our assumptions have been based may be expected to develop and that the Directors’ plans will be influenced by improvements in technology and experience gained from decommissioning activities, liabilities and the resulting provisions are likely to be adjusted.
In matching the costs of generating electricity against the income from sales, accruals are made in respect of the following:
| (a) | Fuel costs—back end |
The treatment of back end fuel costs in the profit and loss account has been dealt with in notes 2(v)and 2(vi). These accruals cover reprocessing and storage of spent nuclear fuel and the long-term storage, treatment and eventual disposal of nuclear waste. They are based, as
F-17
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
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. The provision established at the commencement of a power station’s operating life is capitalized as part of the costs of the station and depreciated over the station life.
Accruals and provisions for back end fuel costs and decommissioning are stated in the balance sheet at current price levels, discounted at a long-term real rate of interest of 3% per annum to take account of the timing of payments. Each year the financing charges in the profit and loss account include the revalorization of liabilities required to discharge one year’s discount from provisions made in prior years and restate these provisions to current price levels.
(xvii) Decommissioning Funds
The Group makes contributions into an independently administered fund to cover all costs of decommissioning its nuclear power stations, except de-fuelling costs. The Group’s annual contributions to the fund are assessed by qualified actuaries, taking into account the amount and timing and expected decommissioning costs and the periods until station closures. The value of the asset in the balance sheet represents the contributions made by the Group, together with an estimated actuarially determined long-term rate of return on the fund. The change in value arising from applying the estimated long-term rate of return is taken to the profit and loss account and disclosed as part of revalorization.
The revalorization of the decommissioning fund, which has been taken through the profit and loss account, is not a realized profit for the purposes of the Companies Act 1985 because the income is unrealized until the Group receives the related cash from the fund to reimburse decommissioning expenditure. The inclusion of this profit in the profit and loss account is a departure from the requirements of the Companies Act 1985. Revalorization of the accrued decommissioning provision is charged to the profit and loss account each year and accordingly, in the opinion of the Directors, it is necessary to include the estimated annual long-term rate of return of the fund in the Group’s profit and loss account in order for the financial statements to give a true and fair view. In the event that the net realizable value as indicated by the market value of the fund is lower than the value determined under the accounting policy set out above, the lower value is included in the Group accounts.
UK GAAP comprises both the provisions of the Companies Act 1985 and Accounting Standards. Within UK GAAP, a company is allowed to depart from the provisions of Schedule 4 of the Companies Act 1985 if the departure is considered necessary to give a true and fair view of the Group’s financial position. Therefore to invoke the true and fair override is not a departure from UK GAAP, but the adoption of a specific set of rules within UK GAAP.
The recognition in the profit and loss account of the actuarial gain on the investment assets of the Decommissioning Fund, which is unrealized profit, is in contradiction to Schedule 4 of the Companies
F-18
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Act 1985 (Schedule 4 (12a)) but is allowable by the true and fair view override provision (Companies Act §226(4)). It is the opinion of the Directors of British Energy that this departure from Schedule 4 of the Companies Act 1985 is necessary to give a true and fair view.
Under UK GAAP, without invoking the true and fair override, the Group would carry a current asset at historic cost (cash contributions made) to represent the investment assets of the Decommissioning Fund. This is because, under the Companies Act 1985, a current asset must be stated at the lower of historical purchase cost or net realizable value. The mark-to-market approach is not permitted under UK GAAP for current assets. However, because the actuarial value is lower than the market value the Decommissioning Fund is included in the financial statements at market value. In order to give a true and fair view, the actuarial gains on the independent fund are included within the profit and loss account and disclosed according to UK GAAP (Companies Act §226(4), Schedule 4 and para. 15, UITF 7).
The effect of the departure for the UK fund is to increase the loss before tax by £74m (2003: increase the loss before tax by £82m; 2002: increase the loss before tax by £4m), and to reduce the reported loss before exceptional items for the year by £28m (2003: increase the loss by £29m; 2002: increase the loss by £23m). There is no impact on the net assets at March 31, 2004 as the fund has been restated at market value (2003 net assets were £nil; 2002: £82m higher due to this departure). There are no tax consequences of this departure.
A similar decommissioning fund existed in the United States for AmerGen that was accounted for on a consistent basis as outlined above for the UK fund. Up until the date of sale the effect of the departure for the AmerGen Fund was to increase the profit before tax by £36m (2003: increase the loss before tax by £28m) and to reduce the reported loss before exceptional items for the year ended March 31, 2004 by £14m (2003: £20m). There was no impact on net assets as the AmerGen fund had been restated at market value.
(xviii) Liquid Funds
Cash which is placed on term deposits which mature more than one day after the end of the financial year or invested in commercial paper, is classified under current asset investments in the balance sheet and the movement in liquid funds is disclosed under management of liquid resources in the cash flow statement.
(xix) Financial Instruments and Derivatives
Debt instruments
All borrowings are stated at cost with issue costs being charged to the profit and loss account on purchase. The interest payable on debt is charged to the profit and loss account over the life of the borrowing. Premiums and discounts arising on early repayment of borrowings are recognized in the profit and loss account as incurred and received.
Commodity contracts
Where there is physical delivery associated with power and coal commodity contracts they are accounted for on an accruals basis following delivery of the commodity. Amounts payable or receivable in respect of these contracts are recorded within trade creditors and debtors respectively and recognized as turnover.
F-19
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Where there is no physical delivery associated with these contracts, they are recorded at fair value on the balance sheet. Where the instrument is for proprietary trading purposes, the change in fair value is reflected through the profit and loss account as part of turnover—wholesale generation. This is not in accordance with the general provisions of Schedule 4 of the Companies Act 1985, which requires that these contracts are stated at the lower of cost and net realizable value or that, if revalued, any revaluation difference be taken to a revaluation reserve. However, the Directors consider that this departure is necessary in order that the financial statements give a true and fair view of the results of the Group’s trading activities, in accordance with Section 226(5) of the Companies Act 1985. The effect of the departure on the financial statements is to increase the profit for the year by £12m (2003: reduce the loss for the year by £9m) and reduce the net liabilities at March 31, 2004 by £21m (2003: £9m).
As noted above, UK GAAP comprises both the provisions of the Companies Act 1985 and Accounting Standards. Within UK GAAP a Company is allowed to depart from the provisions of Schedule 4 of the Companies Act 1985 if the departure is considered necessary to give a true and fair view of the Group’s financial position. Therefore, to invoke the true and fair override is not a departure from UK GAAP, but the adoption of a specific set of rules within UK GAAP.
For instruments used for proprietary trading purposes, reflecting the change in fair value through the profit and loss account is in contradiction to the general provisions of Schedule 4 of the Companies Act 1985 but is allowable by the true and fair view override provision (Companies Act §226(4)). It is the opinion of the Directors of British Energy that this departure from Schedule 4 of the Companies Act 1985 is necessary to give a true and fair view.
Under UK GAAP, without invoking the true and fair override, the Group would carry these contracts at the lower of cost and net realizable value and, if revalued, any difference would be taken to the profit and loss account. This is because, under the Companies Act 1985, a current asset must be stated at the lower of historical purchase cost or valuation. The mark-to-market approach is not permitted under UK GAAP for current assets. In order to give a true and fair view, these contracts are marked to market.
Futures and power options
Power futures and options are undertaken for hedging and proprietary trading purposes. Initial margins paid on entering power exchange contracts are recorded on the balance sheet within restricted cash in ‘Investments—liquid funds’ throughout the term of the contract. Where the instrument is a hedge, the daily margin calls are initially reflected on the balance sheet and subsequently reflected through the profit and loss account to match the recognition of the hedged item.
Interest rate swaps
Interest rate swaps are used to manage debt interest rate exposure. Amounts payable or receivable in respect of interest rate swaps are recognized as adjustments to the net interest charge over the term of the contracts. Where derivatives used to manage interest rate risk or to hedge other anticipated cash flows are terminated before the underlying debt matures, the resulting gain or loss is deferred on the balance sheet and amortized to the profit and loss account to match the timing and accounting treatment of the underlying debt. If the debt is subsequently terminated any unamortized deferred gain or loss is recognized immediately in the profit and loss account. Where interest rate swaps are no longer considered effective hedging instruments, any cumulative losses relating to the fair value of the derivatives are taken to the profit and loss account in accordance with FRS 12.
F-20
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Options
The Group used currency options to manage exposure on its disposal of overseas assets. Premiums received and paid on the contracts are included in the net sale proceeds in ‘Exceptional gain/(loss) on sale of joint venture and businesses’.
Premiums received and paid on wholesale generation contracts are amortized over the period of the contracts and are included within turnover.
(xx) Goodwill
Goodwill arising on acquisitions represents the excess of the fair value of the consideration at acquisition compared to the fair value of the identifiable net assets acquired. Goodwill is capitalized as an intangible asset on the balance sheet and amortized on a straight line basis over its estimated useful life.
(xxi) Joint Venture
The Group’s share of the results of the joint venture is included in the consolidated financial statements based on the latest audited accounts of the joint venture, except where the accounting reference date is not coterminous with the parent company, in which case management accounts are used and adjusted to comply with British Energy accounting policies.
On December 22, 2003 the Group disposed of its interest in AmerGen.
(xxii) Operating Leases
The Group entered into an operating lease with Ontario Power Generation (OPG) to lease the Bruce Power nuclear plant in Ontario, Canada until 2018. Under the terms of the agreement a significant initial payment was made. This consideration, plus related transaction costs attributed to the operating lease prepayment, was amortized on a straight line basis over the expected period of the lease. Other costs of the Bruce Power lease were charged to the profit and loss account in accordance with the rental schedule which is included in the lease agreement. The Group disposed of its investments in Bruce Power and Huron Wind on February 14, 2003. The results of Bruce Power are classified as a discontinued activity for the purpose of this report.
Rentals payable under operating leases are charged to the profit and loss account on a straight line basis over the lease term.
F-21
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
3. TURNOVER, PROFIT/(LOSS) ON ORDINARY ACTIVITIES BEFORE TAX AND NET
The Group considers that it has one geographical segment being the UK. In addition it separately discloses certain financial information in respect of Bruce (sold February 14, 2003) and AmerGen (sold December 22, 2003).
(a) Output and Turnover
| 2004 |
2003 |
2002 | ||||
| TWh | TWh | TWh | ||||
| Output |
||||||
| United Kingdom |
72.6 | 69.5 | 74.7 | |||
| Canada |
— | 19.2 | 20.5 | |||
| 72.6 | 88.7 | 95.2 | ||||
| £m | £m | £m | ||||
| Group Turnover |
||||||
| Continuing activities |
||||||
| United Kingdom |
||||||
| —wholesale generation |
703 | 852 | 1,162 | |||
| —direct supply |
782 | 603 | 522 | |||
| —Turnover from continuing activities excluding exceptional income and miscellaneous income |
1,485 | 1,455 | 1,684 | |||
| —miscellaneous income |
31 | 32 | 17 | |||
| —exceptional income |
— | 41 | — | |||
| 1,516 | 1,528 | 1,701 | ||||
| Discontinued activities |
— | 375 | 348 | |||
| Turnover |
1,516 | 1,903 | 2,049 | |||
In the year ended March 31, 2003 the Group agreed revised terms for the Nuclear Energy Agreement (‘NEA’) with Scottish Power and Scottish and Southern Energy which resulted in the release of £41m in respect of cash amounts previously received, and was reported as an exceptional item in the results for the year ended March 31, 2003.
Turnover from discontinued activities in Canada in 2002 and 2003 represent the sales by Bruce Power which was acquired on May 12, 2001 and sold on February 14, 2003.
The turnover, operating profits and net assets of the Group’s joint venture, AmerGen, relate entirely to activities in the United States of America. On December 22, 2003 the Group disposed of its interest in AmerGen.
(b) Profit/(Loss) on Ordinary Activities Before Taxation
A geographical analysis of operating profit/(loss) on ordinary activities before taxation is as follows:
| 2004 |
2003 |
2002 |
||||||
| £m | £m | £m | ||||||
| United Kingdom |
187 | (4,388 | ) | (586 | ) | |||
| Canada—discontinued |
— | 97 | 52 | |||||
| 187 | (4,291 | ) | (534 | ) | ||||
| Share of discontinued joint venture—United States |
45 | (1 | ) | 41 | ||||
| 232 | (4,292 | ) | (493 | ) | ||||
F-22
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(c) Net (Liabilities)/Assets
A geographical analysis of the Group’s net (liabilities)/assets is as follows:
| 2004 |
2003 |
2002 | ||||||
| £m | £m | £m | ||||||
| United Kingdom |
(3,164 | ) | (3,454 | ) | 388 | |||
| Canada |
— | — | 158 | |||||
| United States |
— | 71 | 81 | |||||
| (3,164 | ) | (3,383 | ) | 627 | ||||
(d) Additional Financial Information
Included within the profit and loss account of the Group (excluding AmerGen joint venture) are the following items by geographical location.
| 2004 |
2003 |
2002 |
||||||||||||||||||||||||
| UK |
Canada |
Group |
UK |
Canada |
Group |
UK |
Canada |
Group |
||||||||||||||||||
| £m | £m | £m | £m | £m | £m | £m | £m | £m | ||||||||||||||||||
| Depreciation |
50 | — | 50 | 273 | 7 | 280 | 280 | 5 | 285 | |||||||||||||||||
| Revalorization |
187 | — | 187 | 209 | — | 209 | 164 | — | 164 | |||||||||||||||||
| Interest receivable |
(11 | ) | — | (11 | ) | (9 | ) | — | (9 | ) | (13 | ) | (3 | ) | (16 | ) | ||||||||||
| Interest expense |
75 | — | 75 | 81 | — | 81 | 74 | 8 | 82 | |||||||||||||||||
| Taxation |
— | (2 | ) | (2 | ) | (396 | ) | 18 | (378 | ) | (19 | ) | 15 | (4 | ) | |||||||||||
| Exceptional items |
(381 | ) | — | (381 | ) | 4,162 | — | 4,162 | 535 | — | 535 | |||||||||||||||
F-23
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
4. OPERATING COSTS
| 2004 |
2003 |
2002 | |||||
| £m | £m | £m | |||||
| Total costs |
|||||||
| Continuing activities |
|||||||
| —fuel |
413 | 371 | 467 | ||||
| —materials and services |
537 | 519 | 604 | ||||
| —staff costs (note 6) |
224 | 227 | 212 | ||||
| —depreciation (credits)/charges |
(245 | ) | 4,011 | 580 | |||
| 929 | 5,128 | 1,863 | |||||
| Amounts written off non-operational assets |
(13 | ) | 115 | — | |||
| Electricity purchases for direct supply costs |
260 | 184 | 171 | ||||
| 1,176 | 5,427 | 2,034 | |||||
| Discontinued activities |
|||||||
| —fuel |
— | 17 | 23 | ||||
| —materials and services |
— | 143 | 149 | ||||
| —staff costs (note 6) |
— | 111 | 119 | ||||
| —depreciation charges |
— | 7 | 5 | ||||
| — | 278 | 296 | |||||
| Total operating costs |
1,176 | 5,705 | 2,330 | ||||
| Exceptional items |
|||||||
| Continuing activities |
|||||||
| —materials and services |
25 | 94 | 209 | ||||
| —staff costs (note 6) |
— | — | 3 | ||||
| —depreciation (credits)/charges |
(295 | ) | 3,738 | 300 | |||
| (270 | ) | 3,832 | 512 | ||||
| Amounts written off non-operational assets |
(13 | ) | 115 | — | |||
| (283 | ) | 3,947 | 512 | ||||
| Analysis of exceptional items |
|||||||
| —restructuring costs |
43 | 35 | — | ||||
| —settlement of claim |
(18 | ) | — | — | |||
| —stock obsolescence |
— | 57 | — | ||||
| —staff costs |
— | — | 3 | ||||
| —onerous trading contracts |
— | 2 | 209 | ||||
| —fixed asset (write up)/ down (note 13) |
(295 | ) | 3,738 | 300 | |||
| —investments in own shares write down (note 14) |
— | 102 | — | ||||
| —UK decommissioning fund (write up)/write down (note 15) |
(13 | ) | 13 | — | |||
| (283 | ) | 3,947 | 512 | ||||
There were exceptional materials and services costs of £43m in respect of costs incurred on advisory fees and other costs associated with restructuring the Group’s activities.
F-24
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The Group settled long standing disputes with Siemens Power Generation Limited (‘Siemens’) relating to work done since 1996 by the former Parsons business. Under the terms of the settlement Siemens paid the Company approximately £18m. The settlement included a commitment by the Company and Siemens to develop a mutually beneficial relationship under a long-term supply agreement.
At March 31, 2004 the Directors reassessed the fixed asset carrying values, in line with the requirements of FRS11, to determine whether any revisions to fixed asset carrying values were appropriate. In carrying out such a review the Directors concluded that, pending completion of the Proposed Restructuring, it was appropriate to carry out a full review of valuations.
The carrying value of the nuclear stations was calculated by discounting the expected future cash flows from continued use of the assets, having made appropriate assumptions regarding future operating performance. The valuation of Eggborough was based on an assessment of net realizable value. Following the review, the carrying value of fixed assets was increased by £295m at March 31, 2004 to reflect reversal of previous impairment losses. The calculation of fixed asset carrying values at March 31, 2004 includes cash flow estimates regarding the level of increase in pension fund contributions that may be required to repair the actuarial pension fund deficit at March 31, 2004. The potential payments included in the fixed asset calculation amount to approximately £207m after being discounted at 15%, and are equivalent to a pension fund deficit calculated on an actuarial basis in the range of £330m to £440m. Formal triennial valuations of the British Energy Generation Group (BEGG) and British Energy Combined Group (BECG) pension schemes at March 31, 2004 are currently being undertaken, but the results of these valuations will not be finalised until later in 2004.
The electricity price assumptions are a very significant component of the asset value calculation. The Directors have considered market views on future prices of wholesale electricity and also the commercially available forecasts. They have considered the impact on future prices of the increases in market electricity prices which occurred in the past year, the outlook for coal and gas fuel prices, potential for changes in generation capacity in the UK, and the potential effect on the market of changes in Government policy particularly in the area of environmental legislation. In determining the price assumptions the directors have taken a cautious view of there being a significant long-term recovery in market prices. This recovery of market prices during the year has led to forecasts of future electricity prices being greater than those underpinning the value in use calculated at March 31, 2003. Greater cash inflows are therefore anticipated over the lifetime of the nuclear plants, and so an element of the prior year impairment loss has been reversed. As market prices are outside the Directors’ control actual prices may differ from those forecast.
At March 31, 2004 the market value of the UK decommissioning fund had increased to £440m (March 31, 2003: £334m), thereby necessitating an exceptional credit of £59m in the twelve months ended March 31, 2004. The £59m included a £13m exceptional credit to reverse the write-down on non-operational assets made in the year ended March 31, 2003. The remaining balance of the restatement to market value of £46m has been dealt with as an exceptional financing credit to reverse previously written-down revalorization amounts. The remaining UK decommissioning fund movements relate to revalorization of £28m and regular cash contributions of £19m.
Exceptional operating costs amounting to £3,947m were reported for the year ended March 31, 2003. These amounts are further explained as follows:
| • | charges incurred on advisory fees and other costs associated with the restructuring of the Group’s activities of £35m in the year ended March 31, 2003; |
F-25
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
| • | a charge of £57m in the year ended March 31, 2003 to provide for obsolete stores and spares; |
| • | a charge of £2m for the year to March 31, 2003 to provide for the onerous pre-New Electricity Trading Arrangements (NETA) contracts with TPL, Total and Enron; |
| • | exceptional depreciation charge of £3,738m in the year ended March, 31 2003 in respect of a write down of an impairment loss in the carrying value of fixed assets following a review of economic values and net realizable values of fixed assets; |
| • | a write-down of £102m in the year ended March 31, 2003 to reflect permanent diminution in the value of own shares held in employee trusts; and |
| • | the investments held within the UK decommissioning fund were written-down to reflect a reduction in market value, resulting in a charge for the year to March 31, 2003 of £13m. |
Exceptional operating costs amounting to £512m were reported for the year ended March 31, 2002.
These amounts are further explained as follows:
| • | a £209m provision in respect of the onerous pre-NETA contracts with Enron, TPL and TFE; |
| • | a charge of £3m for share option costs charged to staff costs; and |
| • | an asset write-down of £300m in respect of the Eggborough Power Station. |
| 2004 |
2003 |
2002 | ||||
| £m | £m | £m | ||||
| Operating costs are stated after charging: |
||||||
| —research and development |
14 | 15 | 16 | |||
| —operating lease costs—Bruce Power |
— | 70 | 38 | |||
| —other |
1 | — | — |
It is the Group’s policy to engage PricewaterhouseCoopers LLP on assignments where their expertise and experience with the Group are important, or where they win work on a competitive basis. An analysis of auditors’ remuneration on a worldwide basis is provided below:
| 2004 |
2003 |
2002 | ||||||||||
| £000’s | % | £000’s | % | £000’s | % | |||||||
| Audit services |
||||||||||||
| —Statutory |
510 | 9 | 480 | 16 | 358 | 16 | ||||||
| —Audit related regulatory reporting |
258 | 5 | 215 | 7 | 101 | 5 | ||||||
| Further assurance services |
||||||||||||
| —Creditors’ long form report |
2,017 | 35 | — | — | — | — | ||||||
| —Reporting accountant—working capital report |
1,208 | 21 | 532 | 17 | — | — | ||||||
| —Review of accounting for restructuring |
1,114 | 20 | 1,111 | 36 | — | — | ||||||
| Taxation |
||||||||||||
| —Tax service |
510 | 9 | 331 | 11 | 1,249 | 57 | ||||||
| Other |
||||||||||||
| —Other non-audit services |
80 | 1 | 409 | 13 | 475 | 22 | ||||||
| Total |
5,697 | 100 | 3,078 | 100 | 2,183 | 100 | ||||||
Statutory audit fees for British Energy plc were £65,000 (2003: £60,000; 2002: £45,000).
F-26
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
5. SALE OF INVESTMENTS
On December 22, 2003 the Group completed the sale of its 50% interest in AmerGen to Exelon. The Group received initial consideration of US$277m upon financial close on December 22, 2003 prior to adjustments relating to working capital levels, stocks of unspent nuclear fuel inventory, capital expenditures and low-level waste disposal costs to be determined at the time of closing. The gain on sale calculated below is a provisional estimate pending receipt of financial statements drawn up as at the date of financial close.
On December 23, 2003 the Group sold its 50% equity interest in Offshore Wind Power Limited (‘Offshore Wind’) to GB Gas Holdings Limited, a wholly owned subsidiary of Centrica plc, for an up front cash consideration of £2m and deferred consideration of up to £750,000 which has not been recognized in these accounts (net book value £nil).
Total cash receipts in relation to the discontinued activities of Bruce Power amounted to £17m. The cash receipt of £9m received on April 28, 2003 in relation to Bruce Power was accounted for in the year ended March 31, 2003 as an adjusting post balance sheet event. The additional receipt of £8m received on March 22, 2004 was in relation to the re-start of the Bruce A reactor. These receipts relate to the discontinued activities of Bruce Power.
The exceptional profit arising from the disposal of joint venture and businesses and cash consideration which have been recognized in the current period are analyzed as follows:
| Bruce Power |
AmerGen |
Offshore Wind |
Total | |||||
| £m | £m | £m | £m | |||||
| Net assets sold |
— | 112 | — | 112 | ||||
| Accounted for by: |
||||||||
| Cash consideration net of transaction cost and break fee |
8 | 149 | 2 | 159 | ||||
| Exceptional gain on sale of joint venture and businesses |
8 | 37 | 2 | 47 | ||||
| Cash flows: |
||||||||
| Cash consideration net of transaction costs received in the year ended March 31, 2004 |
17 | 152 | 2 | 171 | ||||
On February 14, 2003 the Group completed the sale of its 82.4% interest in Bruce Power Limited Partnership (“Bruce Power”) and 50% share in Huron Wind Limited Partnership to a Canadian consortium led by Cameco Corporation, TransCanada and BPC Generation Infrastructure Trust.
The Group received initial consideration of C$678m upon financial close on February 14, 2003, together with a C$20m retention initially held in escrow pending confirmation of the pension deficit which was subsequently received in April 2003. In addition, there are certain amounts held in escrow which the Group may be entitled to receive pending satisfaction of various conditions related to the disposal. These amounts, which have not been recognized in the results for the year ended March 31, 2003, are:
| • | C$100m, contingent on the restart of two Bruce A units, with C$50m to be released provided the first unit restarts by June 15, 2003 and an additional C$50m if the second unit restarts by August 1, 2003. If the units do not restart on the specified dates then the contingent amounts |
F-27
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
| released for each unit will be reduced by C$5m and such payment is reduced by a further C$5m if that unit is not restarted on or before the first day of each successive calendar month following the scheduled restart date. |
| • | C$20m, which is held in escrow from closing to cover any successful claims in respect of representations and warranties until any claims made against British Energy and British Energy International Holdings which are made within two years from the date of closing are resolved. |
A further C$80m is held in an escrow account to cover the estimated outstanding tax liabilities of the Bruce Group. In the event that the sums held back to satisfy the tax liability are insufficient, then British Energy would be required to repay the amount of such excess to the Bruce Power consortium. Conversely, British Energy will be refunded any balance remaining after settlement of the tax liability.
The loss arising from the disposal and cash consideration which have been recognized in these accounts are analyzed as follows:
| £m | |||
| Net assets sold: |
|||
| Tangible fixed assets |
303 | ||
| Investment in joint venture and associates |
4 | ||
| Stocks |
37 | ||
| Debtors |
313 | ||
| Cash at bank |
4 | ||
| Borrowings |
(92 | ) | |
| Creditors and provisions |
(192 | ) | |
| Net assets disposed |
377 | ||
| Minority interests |
(68 | ) | |
| Net assets disposed less minorities |
309 | ||
| Accounted for by: |
|||
| Cash consideration net of transaction costs |
266 | ||
| Contingent consideration received post year end on determination of pension deficit |
8 | ||
| Loss on disposal—exceptional item |
(35 | ) | |
| Cash flows: |
|||
| Cash consideration net of transaction costs received in 2002/03 |
266 | ||
| Less: cash held by disposed subsidiary |
(4 | ) | |
| Net cash inflow |
262 | ||
The Group’s disposal of its interest in Humber Power Limited during 2001/02 resulted in an exceptional profit of £4m.
F-28
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
6. EMPLOYEE INFORMATION
(a) Staff Costs
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Salaries |
208 | 201 | 189 | ||||||
| Social security costs |
19 | 17 | 18 | ||||||
| Pension costs (note 25) |
— | 6 | 1 | ||||||
| Severance charges |
2 | 12 | — | ||||||
| Amortization of share option costs |
— | — | 9 | ||||||
| Amounts capitalized |
(5 | ) | (9 | ) | (8 | ) | |||
| Exceptional charge/(credit) |
— | — | 3 | ||||||
| Continuing activities |
224 | 227 | 212 | ||||||
| Discontinued activities |
— | 111 | 119 | ||||||
| Total staff costs |
224 | 338 | 331 | ||||||
Amounts capitalized within staff costs for the year ended March 31, 2004 are subsequently expensed as operating costs within materials and services costs following the fixed assets impairment review carried out.
(b) Employee Numbers
| 2004 |
2003 |
2002 | ||||
| Number | Number | Number | ||||
| Average number of employees during the year |
||||||
| Continuing operations |
5,165 | 5,103 | 4,969 | |||
| Discontinued operations |
— | 2,799 | 2,701 | |||
| 5,165 | 7,902 | 7,670 | ||||
Average number of full-time equivalent employees by category during the year were:
| 2004 |
2003 |
2002 | ||||
| Number | Number | Number | ||||
| United Kingdom |
||||||
| Power stations |
3,870 | 3,826 | 3,750 | |||
| Engineering, technical and corporate support |
1,257 | 1,228 | 1,170 | |||
| North America—continuing operations |
12 | 28 | 32 | |||
| 5,139 | 5,082 | 4,952 | ||||
| Canada—discontinued operations |
— | 2,798 | 2,701 | |||
| 5,139 | 7,880 | 7,653 | ||||
F-29
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
7. DIRECTORS’ EMOLUMENTS AND INTERESTS
(a) Summary of Directors’ Emoluments
| 2004 |
2003 |
2002 | ||||
| £’000 | £’000 | £’000 | ||||
| Total emoluments, including pension contributions |
||||||
| As Directors |
517 | 585 | 221 | |||
| For management services: |
||||||
| —salaries and other benefits |
940 | 996 | 1,041 | |||
| —performance related bonuses |
405 | — | 343 | |||
| —pension contributions |
46 | 52 | 48 | |||
| 1,908 | 1,633 | 1,653 | ||||
| —compensation for loss of office |
146 | 98 | 365 | |||
| 2,054 | 1,731 | 2,018 | ||||
(b) Individual Remuneration
| Salary and fees |
Bonus |
Compensation for loss of office |
Other benefits |
Total emoluments excluding pension | ||||||||
| Year ended March 31 |
2004 |
2004 |
2004 |
2004 |
2004 |
2003 | ||||||
| £ | £ | £ | £ | £ | £ | |||||||
| A Montague(1) |
300,000 | — | — | — | 300,000 | 400,209 | ||||||
| M Alexander(2) |
400,000 | 190,004 | — | 32,864 | 622,868 | 35,535 | ||||||
| W Coley(12) |
25,000 | — | — | — | 25,000 | — | ||||||
| P Colombani(12) |
22,500 | — | — | — | 22,500 | — | ||||||
| J Deluca(13) |
4,500 | — | — | — | 4,500 | — | ||||||
| M Gatto(14) |
130,000 | 36,013 | — | — | 166,013 | — | ||||||
| D Gilchrist(3) |
199,013 | 106,105 | — | 15,247 | 320,365 | 203,630 | ||||||
| I Harley(5) |
36,500 | — | — | — | 36,500 | 25,833 | ||||||
| C Spottiswoode(11) |
59,000 | — | — | — | 59,000 | 53,333 | ||||||
| R Walmsley(15) |
24,667 | — | — | — | 24,667 | — | ||||||
| Total emoluments for serving Directors as at March 31, 2004 |
1,201,180 | 332,122 | — | 48,111 | 1,581,413 | 718,540 | ||||||
| R Biggam(7) |
— | — | — | — | — | 11,167 | ||||||
| D Hawthorne(3),(4) |
25,228 | — | — | — | 25,228 | 161,024 | ||||||
| R Hill(16) |
19,167 | — | — | — | 19,167 | 57,500 | ||||||
| R Jeffrey(6) |
— | — | — | — | — | 424,537 | ||||||
| M Kirwan(9) |
— | — | — | — | — | 49,049 | ||||||
| K Lough(3),(17) |
151,975 | 73,679 | 145,625 | 11,309 | 382,588 | 224,136 | ||||||
| P Stevenson(8) |
— | — | — | — | — | 25,893 | ||||||
| J Walsh(10) |
— | — | — | — | — | 7,325 | ||||||
| Total emoluments (all Directors) |
1,397,550 | 405,801 | 145,625 | 59,420 | 2,008,396 | 1,679,171 | ||||||
| Compensation for loss of office: |
||||||||||||
| R Jeffrey(6) |
98,000 | |||||||||||
There were no accommodation and relocation expenses paid in the year to March 31, 2004.
F-30
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(c) Directors’ Pension Contributions
| 2004 |
2003 | |||
| £ | £ | |||
| A Montague(1) |
— | — | ||
| M Alexander(2) |
16,929 | 1,385 | ||
| W Coley(12) |
— | — | ||
| P Colombani(12) |
— | — | ||
| J Delucca(13) |
— | — | ||
| M Gatto(14) |
— | — | ||
| D Gilchrist(3) |
16,929 | 12,020 | ||
| I Harley(5) |
— | — | ||
| C Spottiswoode(11) |
— | — | ||
| R Walmsley(15) |
||||
| Total pension contributions serving Directors at March 31, 2004 |
33,858 | 13,405 | ||
| Sir R Biggam(7) |
— | — | ||
| D Hawthorne(3),(4) |
— | 21,749 | ||
| Sir R Hill(16) |
— | — | ||
| R Jeffrey(6) |
— | — | ||
| M Kirwan(9) |
— | 4,453 | ||
| K Lough(3),(17) |
11,657 | 12,020 | ||
| P Stevenson(8) |
— | — | ||
| J Walsh(10) |
— | — | ||
| Total Pension Contributions (all Directors) |
45,515 | 51,627 | ||
Notes referred to in above tables—
| (1) | Appointed on December 1, 2002. |
| (2) | Appointed on March 1, 2003. |
| (3) | Appointed as Executive Directors on September 1, 2001. |
| (4) | D Hawthorne’s pro rata salary to termination date of February 14, 2003 is C$357,107 and has been converted into Sterling at the average exchange rate for the year (£1 = C$2.40). Mr Hawthorne became a Non-Executive Director serving on the Board from February 15, 2003 and resigned on March 12, 2004. |
| (5) | Appointed on June 1, 2002. |
| (6) | R Jeffrey resigned as a Director on February 10, 2003. |
| (7) | Sir R Biggam resigned as a Director on June 7, 2002. |
| (8) | P Stevenson resigned as a Director on February 28, 2003. |
| (9) | M Kirwan resigned as a Director on May 31, 2002. The salary figure for 2003 includes accrued holiday pay of £13,458. |
| (10) | J Walsh resigned as a Director on July 16, 2002. |
| (11) | C Spottiswoode appointed as a Director on September 1, 2001. |
| (12) | Appointed as Non-Executive Directors on June 1, 2003. |
| (13) | Appointed as Non-Executive Director on February 1, 2004. |
| (14) | Appointed as Executive Director on December 8, 2003. |
| (15) | Appointed as Non-Executive Director on August 1, 2003. |
| (16) | Sir R Hill resigned as a Non-Executive Director on July 31, 2003. |
| (17) | K Lough resigned as an Executive Director on December 8, 2003. |
F-31
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(d) Executive Share Options
| Name |
Options held at 01/04/03 |
Options granted during the year |
Options Exercised during the year |
Options lapsed during the year |
Options held at 31/3/04 |
Option exercise Price (£) |
Date from which exercisable |
Expiry date | ||||||||
| D Gilchrist |
57,692 | — | — | — | 57,692 | 2.60 | 15/7/00 | 14/7/04 | ||||||||
| 11,538 | — | — | — | 11,538 | 2.60 | 15/7/00 | 14/7/07 | |||||||||
| 19,862 | — | — | — | 19,862 | 5.08 | 29/6/01 | 28/6/05 | |||||||||
| 21,379 | — | — | — | 21,379 | 5.295 | 25/6/02 | 24/6/06 | |||||||||
| 40,659 | — | — | — | 40,659 | 2.4125 | 14/7/03 | 13/7/07 | |||||||||
| 151,130 | — | — | — | 151,130 | ||||||||||||
| K Lough |
9,433 | — | — | — | 9,433 | 3.18 | 14/9/04 | 13/9/11 | ||||||||
| 116,353 | — | — | — | 116,353 | 3.18 | 14/9/04 | 13/9/08 | |||||||||
| 125,786 | — | — | — | 125,786 | ||||||||||||
8. FINANCING CHARGES/(CREDITS)
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Revalorization of nuclear liabilities |
215 | 228 | 175 | ||||||
| Revalorization of decommissioning fund |
(28 | ) | (29 | ) | (23 | ) | |||
| Revalorization of other provisions |
— | 10 | 12 | ||||||
| Share of revalorization of joint venture |
(2 | ) | (4 | ) | (4 | ) | |||
| Revalorization charge before exceptional items |
185 | 205 | 160 | ||||||
| Exceptional revalorization (credit)/charge (see below) |
(68 | ) | 159 | 27 | |||||
| Revalorization charge |
117 | 364 | 187 | ||||||
| Interest: |
|||||||||
| Interest on loans repayable within five years |
|||||||||
| —banks |
11 | 11 | 27 | ||||||
| —others |
33 | 24 | 27 | ||||||
| Interest on loans repayable in five years or more |
|||||||||
| —banks |
24 | 38 | 20 | ||||||
| —others |
7 | 8 | 8 | ||||||
| Interest receivable |
(11 | ) | (9 | ) | (16 | ) | |||
| Net interest before exceptional items |
64 | 72 | 66 | ||||||
| Exceptional (credit)/charge—interest rate swaps |
(5 | ) | 56 | — | |||||
| Exceptional charge—borrowing costs |
— | 6 | — | ||||||
| Exceptional financing (credit)/charges |
(5 | ) | 62 | — | |||||
| Net interest payable and similar charges |
59 | 134 | 66 | ||||||
At March 31, 2004 the market value of the UK decommissioning fund had increased to £440m (March 31, 2003: £334m), thereby necessitating an exceptional credit of £59m in the twelve months ended March 31, 2004 to reverse previously written-down amounts. As a result of the UK decommissioning fund receivable being restated at market value, a £13m exceptional credit has been recorded in operating costs to reverse a prior write-down of non-operational assets, and exceptional
F-32
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
credits of £46m have been recorded in finance charges for the twelve months ended March 31, 2004 to reverse the prior write-down of previous revalorization. The market value remains below the amount which would have been calculated by revalorizing on an actuarial basis the total amounts that have been invested in the fund.
The market value of the AmerGen decommissioning fund had also increased over the period of December 22, 2003, and the British Energy share of the exceptional credit was £22m in the year to the date of sale.
The total of the UK decommissioning fund and AmerGen decommissioning fund exceptional revalorization credits included within financing charges amounted to £68m.
At March 31, 2004 the value of the interest rate swaps were marked to market and the resultant valuation was lower than the book value. The exceptional credit is £5m for the year ended March 31, 2004.
At March 31, 2003 the market value of the UK decommissioning fund was lower than the value that would have been derived from revalorizing the cost of the investment. The difference was £124m of which £111m was recognized as an exceptional financing charge with the remainder classified as write-offs of non-operational assets. At March 31, 2003 the British Energy share of the adjustment required to reduce the AmerGen decommissioning fund to market value was a charge of £48m.
An exceptional charge of £56m was recognized for the year ended March 31, 2003 for interest rate swaps, which were no longer considered to be effective. In addition an exceptional charge of £6m was recorded for the write-off of borrowing costs which had been previously capitalized and were being amortized over the expected duration of the loan financing the acquisition of the Eggborough power station.
The UK Decommissioning Fund was also written down by £27m in the 2001/02 accounts, to reflect a lower market value at March 31, 2002.
9. TAXATION
| 2004 |
2003 |
2002 |
|||||||
| (restated) | |||||||||
| £m | £m | £m | |||||||
| Tax on profit on ordinary activities: |
|||||||||
| UK corporation tax—prior year |
— | — | (11 | ) | |||||
| Deferred taxation on (loss)/profit before tax and exceptionals |
— | (40 | ) | 34 | |||||
| Unwinding of discount |
— | 14 | 14 | ||||||
| (Charge)/credit on loss for the year |
— | (26 | ) | 48 | |||||
| Exceptional deferred tax credit |
— | (370 | ) | (56 | ) | ||||
| Deferred tax credit for the year |
— | (396 | ) | (8 | ) | ||||
| Foreign tax |
(2 | ) | 18 | 15 | |||||
| (2 | ) | (378 | ) | (4 | ) | ||||
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Share of taxation for discontinued joint venture: |
|||||||||
| Ordinary activities |
— | 10 | 29 | ||||||
F-33
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
There is no UK current tax charge for the year ended March 31, 2004 (2003: £nil). The tax credit of £2m for the year ended March 31, 2004 represents the release of an over provision of foreign tax in earlier years.
The exceptional tax credit for the year ended March 31, 2003 of £370m related to a deferred taxation credit on exceptional items of £520m offset by the de-recognition of the deferred taxation assets of £150m.
As set out in the Group’s Cash Flow Statement, the tax paid of £12m in the year relates to the Group’s liability for its share of AmerGen’s taxable profits. In the year ended March 31, 2003 the net tax refund of £3m comprised tax paid of £10m in respect of AmerGen and Bruce Power offset by a UK tax refund of £13m.
In 2001/02 the credit arose mainly as a result of the increased provision on the long-term onerous trading contracts.
A reconciliation of the effective tax rate for the current year tax charge, which solely comprises foreign tax is set out below.
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Tax charge/(credit) on Group profit/(loss) at standard rate of 30% |
70 | (1,288 | ) | (148 | ) | ||||
| Deferred tax: |
|||||||||
| Current year movement |
— | 396 | 8 | ||||||
| Impact of discounting |
(140 | ) | 619 | 55 | |||||
| Increase in deferred tax asset not recognized |
113 | 150 | — | ||||||
| Total deferred tax movement pre discounting |
(27 | ) | 1,165 | 63 | |||||
| (Credits)/expenses not (chargeable)/deductible for tax purposes |
(16 | ) | 140 | 108 | |||||
| (Gain)/loss on sale of investments not taxable |
(13 | ) | 11 | — | |||||
| Lower tax rates on overseas earnings |
— | (6 | ) | 3 | |||||
| Minority interests |
— | (4 | ) | (3 | ) | ||||
| Impact of joint venture |
(14 | ) | — | (8 | ) | ||||
| Over provision for foreign tax in earlier years |
(2 | ) | — | — | |||||
| Current tax (credit)/charge for year |
(2 | ) | 18 | 15 | |||||
The share of taxation for the joint venture represents the Group’s liability for its share of AmerGen’s taxable profits.
10. LOSS OF THE COMPANY
The Group’s results include a loss of £616m (2003: loss of £6,058m; 2002: loss of £310m) attributable to the Company, inclusive of a provision of £590m (2003: provision of £6,144m) made in the year for bad and doubtful inter-company debtors which is eliminated on consolidation. The Company did not have any distributable reserves at March 31, 2004 (2003: £nil). As permitted under Section 230 of the Companies Act 1985 the Company has not published a separate profit and loss account.
F-34
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
11. DIVIDENDS
| 2004 |
2003 |
2002 |
2004 |
2003 |
2002 | |||||||
| p/share | p/share | p/share | £m | £m | £m | |||||||
| Annual dividend per ordinary share |
||||||||||||
| Interim paid |
— | — | 2.7 | — | — | 16 | ||||||
| Final proposed |
— | — | 5.3 | — | — | 32 | ||||||
| Total annual |
— | — | 8.0 | — | — | 48 | ||||||
| — | — | |||||||||||
| Actual cash dividends paid per Ordinary Share |
— | — | 8.0 | — | — | 46 | ||||||
| Non-equity dividend |
— | — | 2.3 | — | — | 2 | ||||||
The British Energy Employee Share Trust and the QUEST elected to waive their entitlement to receive dividends for financial year ended March 31, 2002.
12. EARNINGS/(DEFICIT) PER SHARE
The basic earnings/(deficit) per share for the year has been calculated by dividing the profit/(loss) on ordinary activities after taxation, minority interests and non-equity dividends by the weighted average number of ordinary shares in issue during the year, based on the following information:
| 2004 |
2003 |
2002 |
||||||
| Profit/(loss) for the year (£million) |
234 | (3,941 | ) | (529 | ) | |||
| Basic weighted average share capital (number of shares, million) |
602 | 602 | 598 |
A calculation of diluted earnings per share has not been provided because the outstanding share options do not have any dilutive potential at March 31, 2004, 2003 or 2002.
13. TANGIBLE FIXED ASSETS
| Group |
Power stations |
Other land and buildings |
Other plant and equipment |
Total |
||||||||
| £m | £m | £m | £m | |||||||||
| Cost |
||||||||||||
| As at April 1, 2003 and March 31, 2004 |
10,747 | 47 | 434 | 11,228 | ||||||||
| Depreciation |
||||||||||||
| As at April 1, 2003 |
10,108 | 24 | 410 | 10,542 | ||||||||
| Exceptional asset write up |
(275 | ) | (1 | ) | (19 | ) | (295 | ) | ||||
| Charge for the year |
38 | 1 | 11 | 50 | ||||||||
| As at March 31, 2004 |
9,871 | 24 | 402 | 10,297 | ||||||||
| Net book value |
||||||||||||
| As at March 31, 2004 |
876 | 23 | 32 | 931 | ||||||||
| As at March 31, 2003 |
639 | 23 | 24 | 686 | ||||||||
F-35
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The net book value of tangible fixed assets includes the following amounts in respect of freehold land and buildings:
| 2004 |
2003 | |||
| £m | £m | |||
| Cost |
2,245 | 2,245 | ||
| Net book value |
157 | 107 | ||
The Directors have reviewed the economic values and net realizable values of the Group’s fixed assets and compared them to their book value. A discount rate of 15% (2003: 15%) was applied to the economic value review. As a result of this review the value of its fixed assets has been increased by £295m (2003: reduced by £3,738m). The background to the review is discussed more fully in note 4.
The value of fixed assets held by the Company is £nil (2003: £nil).
14. FIXED ASSET INVESTMENTS
| Group |
AmerGen joint |
Loans to Nirex |
Own shares |
Other investments |
Total |
|||||||
| £m | £m | £m | £m | £m | ||||||||
| Cost |
||||||||||||
| As at April 1, 2003 |
119 | 37 | 140 | 4 | 300 | |||||||
| Foreign exchange |
(11 | ) | — | — | — | (11 | ) | |||||
| Share of retained profits at date of disposal |
48 | — | — | — | 48 | |||||||
| Disposal of joint venture |
(156 | ) | — | — | — | (156 | ) | |||||
| As at March 31, 2004 |
— | 37 | 140 | 4 | 181 | |||||||
| Provision for diminution in value |
||||||||||||
| As at April 1, 2003 |
48 | 37 | 138 | — | 223 | |||||||
| Foreign exchange |
(4 | ) | — | — | — | (4 | ) | |||||
| Disposal of joint venture |
(44 | ) | — | — | — | (44 | ) | |||||
| As at March 31, 2004 |
— | 37 | 138 | — | 175 | |||||||
| Net book value |
||||||||||||
| As at March 31, 2004 |
— | — | 2 | 4 | 6 | |||||||
| As at March 31, 2003 |
71 | — | 2 | 4 | 77 | |||||||
Other investments relate wholly to the investment held by Lochside Insurance Limited.
F-36
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
On December 22, 2003 the Group disposed of its interest in AmerGen. An analysis of British Energy’s share of the aggregate net assets of the AmerGen joint venture as at March 31, 2003 is set out below.
| 2003 |
|||
| £m | |||
| Negative goodwill |
(7 | ) | |
| Tangible assets |
144 | ||
| Stocks |
10 | ||
| Cash |
6 | ||
| Decommissioning fund |
306 | ||
| Debtors |
18 | ||
| Creditors |
(51 | ) | |
| Decommissioning liabilities |
(321 | ) | |
| Loan notes |
(34 | ) | |
| Net assets |
71 | ||
Negative goodwill relates to AmerGen’s acquisition of Oyster Creek nuclear power station in August 2000.
Loans have been made to United Kingdom Nirex Limited to fund development expenditure for building an intermediate-level nuclear waste repository. These loans have been fully provided for in the Group’s financial statements.
At March 31, 2004 British Energy Employee Share Trust held 21,734,839 ordinary shares at an average cost of £4.68 for a total consideration of £101m. At 31 March 2004 the Qualifying Employee Shareholders Trust held 5,292,103 ordinary shares at a cost of £5.32 per share (£28m) and 19,165,471 ‘A’ shares at a cost of 60p per share (£11m).
The market value of the shares held by the employee trusts at March 31, 2004 was £3m, compared to a book value of £2m. The long-term prospect of the Company have deteriorated considerably and the Directors considered it inappropriate to recognize the increase in value of the shares held in employee trusts.
The Company held investments in Lochside Insurance Limited and British Energy Finance Limited at March 31, 2004. During the year, the investment in Lochside Insurance Limited was written down by £4m (2003: £nil), to a net book value of £4m at March, 31 2004 (2003: £8m).
| Company |
Subsidiary undertakings | |
| £m | ||
| Cost |
||
| As at April 1, 2003 and March 31, 2004 |
14 | |
| Provision for diminution in value |
||
| Charge for the year |
4 | |
| Net Book value |
||
| At March, 31 2004 |
10 | |
| At March 31, 2003 |
14 | |
F-37
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Details of British Energy’s principal subsidiary undertakings and other holdings of more than 10% are as follows:
| Country of registration and operation |
Class of Share |
Group share- holding |
Company share- holding |
Principal activity | ||||||
| % | % | |||||||||
| Subsidiary undertakings |
||||||||||
| British Energy Generation (UK) Limited |
Scotland | Ordinary | 100 | 100 | Generation and sale of electricity | |||||
| British Energy Generation Limited |
England and Wales |
Ordinary | 100 | — | Generation and sale of electricity | |||||
| British Energy Power & Energy Trading Limited |
Scotland | Ordinary | 100 | 100 | Energy trading | |||||
| Eggborough Power Limited |
England and Wales |
Ordinary | 100 | — | Generation and sale of electricity | |||||
| Other holdings of more than 10 per cent |
||||||||||
| United Kingdom Nirex Limited |
England and Wales |
Ordinary | 10.8 | — | Disposal of nuclear waste |
Included in the Group and Company accounts are the assets of British Energy Employee Share Trust and the assets of British Energy Qualifying Employee Share Trust, which are trusts set up to hold shares purchased on behalf of the Group’s employees under the Employee Share Scheme and the British Energy ShareSave Scheme respectively.
15. DECOMMISSIONING FUND
| Group | ||
| £m | ||
| As at April 1, 2003 |
334 | |
| Regular contributions |
19 | |
| Revalorization (note 8) |
28 | |
| 381 | ||
| Exceptional item to mark the fund to market value (note 8) |
59 | |
| As at March 31, 2004 |
440 | |
The decommissioning fund asset in the balance sheet normally represents the contributions made by the Group, together with an estimated actuarially determined long-term post-tax real rate of return on the fund of 3.5% per annum. The change in value arising from applying the estimated long-term rate of return is taken to the profit and loss account as a revalorization credit. The decommissioning fund asset is receivable after more than one year and is restricted in its use.
At March 31, 2004 the market value of the UK decommissioning fund had increased to £440m (March 31, 2003: £334m), thereby necessitating an exceptional credit of £59m to the profit and loss account in the twelve months ended March 31, 2004 to reverse previously written-down amounts. The market value remains below the amount which would have been calculated by revalorizing on an actuarial basis the total amounts which have been invested in the fund. As a result of the UK decommissioning fund receivable being restated at market value, a £13m exceptional credit has been
F-38
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
recorded in operating costs to reverse a prior write-down of non-operational assets, and exceptional credits of £46m have been recorded in finance charges for the twelve months ended March 31, 2004 to reverse the prior write-down of previous revalorization.
The Company has no decommissioning fund at March, 31 2004 (2003: £nil).
16. STOCKS
| Group |
||||||
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Unburnt nuclear fuel in reactors |
472 | 469 | ||||
| Provision for unburnt fuel at station closure |
(280 | ) | (272 | ) | ||
| Net unburnt nuclear fuel in reactors |
192 | 197 | ||||
| Other nuclear fuel |
61 | 74 | ||||
| Coal stocks |
15 | 14 | ||||
| Stores/strategic spares |
82 | 75 | ||||
| 350 | 360 | |||||
The Company has no stock at March 31, 2004 (2003: £nil).
17. DEBTORS
| Group |
Company | |||||||
| 2004 |
2003 |
2004 |
2003 | |||||
| £m | £m | £m | £m | |||||
| Trade debtors |
252 | 226 | 4 | 3 | ||||
| Other debtors |
16 | 89 | — | — | ||||
| Prepayments |
106 | 72 | 7 | 1 | ||||
| Amounts due from subsidiary undertakings |
— | — | — | 81 | ||||
| 374 | 387 | 11 | 85 | |||||
Included within the Company’s amount due from subsidiary undertakings is £6,734m relating to amounts due from UK subsidiaries all of which have been provided for (2003: £6,144m relating to amounts due from UK subsidiaries all of which have been provided for and £81m which was denominated in foreign currencies and translated at the year-end exchange rate).
Included within prepayments for the Group is £101m (2003: £72m) in respect of pension contribution payments made in advance of their recognition in the profit and loss account. These amounts fall due after more than one year.
F-39
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
18. CREDITORS
| Group |
Company | |||||||
| 2004 |
2003 |
2004 |
2003 | |||||
| £m | £m | £m | £m | |||||
| Amounts falling due within one year |
||||||||
| Nuclear liabilities (note 22) |
554 | 355 | — | — | ||||
| Trade creditors |
180 | 198 | — | — | ||||
| Retentions |
6 | 5 | — | — | ||||
| Other taxes and social security |
49 | 9 | — | — | ||||
| Other creditors |
317 | 326 | 3 | 1 | ||||
| Accruals |
144 | 140 | 18 | 20 | ||||
| Amounts due to subsidiary undertakings |
— | — | 4,475 | 3,721 | ||||
| 1,250 | 1,033 | 4,496 | 3,742 | |||||
| Other creditors: amounts falling due after more than one year Nuclear liabilities (note 22) |
1,893 | 1,909 | — | — | ||||
Other creditors include £316m (2003: £316m) in respect of claims relating to onerous trading contracts. These contracts are pre-NETA electricity trading contracts with Enron, TPL and Total. The Enron and Total contracts were terminated during the prior year, which gave rise to claims for certain amounts which have become payable. Interest is payable on standstill balances at a rate of 6%, other than the bonds and the amounts due to the Eggborough banks which continue under their original terms. These accounts reflect the claim amounts, which have been agreed in principle with Enron, TPL and Total for the purposes of the Proposed Restructuring of the Group. Total and Enron subsequently transferred their interest to Deutsche Bank.
19. BORROWINGS
Summary
The Group and Company’s borrowings at March 31, 2004 were as follows:
| Group |
Company | |||||||
| 2004 |
2003 |
2004 |
2003 | |||||
| £m | £m | £m | £m | |||||
| Long term project finance loan—Sterling |
475 | 475 | — | — | ||||
| Bonds—Sterling |
408 | 408 | 408 | 408 | ||||
| 883 | 883 | 408 | 408 | |||||
The borrowings mature as follows:
| Group |
Company | |||||||
| 2004 |
2003 |
2004 |
2003 | |||||
| £m | £m | £m | £m | |||||
| Amounts falling due within one year |
197 | 152 | 110 | 110 | ||||
| Amounts falling due after more than one year |
686 | 731 | 298 | 298 | ||||
| 883 | 883 | 408 | 408 | |||||
The maturities assume no debt has been accelerated and reflect the standstill agreements as part of the Proposed Restructuring.
F-40
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The long-term project finance loan is secured on the assets of EPL. Amounts owed by EPL to the lenders are not guaranteed by British Energy plc but British Energy guarantees the payment of amounts by BEPET to EPL. The contractual amounts payable by BEPET are calculated so as to cover EPL’s borrowing requirements and operating costs. British Energy also provides a subordinated loan facility to EPL. The final installment of loan principal is scheduled to be repaid in 2011. The loan currently bears interest at LIBOR plus 1.3%. It is proposed that these arrangements will be restructured as part of the Proposed Restructuring of the Group.
20. FINANCIAL INSTRUMENTS AND DERIVATIVES
Disclosures include short-term debtors and creditors and exclude commodity power contracts.
(i) Interest rate risk profile of financial liabilities
The interest rate profile of financial liabilities of the Group as at March 31, 2004 was:
| Currency |
Total |
Floating rate financial liabilities |
Fixed rate financial liabilities |
Mixed rate financial liabilities (see below) |
Financial liabilities on which no interest is paid | |||||
| £m | £m | £m | £m | £m | ||||||
| Sterling |
3,883 | 475 | 408 | 33 | 2,967 |
| Fixed rate financial liabilities |
Financial liabilities on which no interest is paid | |||||
| Currency |
Weighted average interest rate |
Weighted average period for which the rate is fixed |
Weighted average period until maturity | |||
| % | Years | Years | ||||
| Sterling |
6.08 | 4.8 | 13.1 | |||
At March 31, 2004, nil borrowings (2003: £475m) were reclassified to fixed rate financial liabilities due to the effect of the Group’s interest rate contracts. The 2003 balance has been reclassified to floating rate financial liabilities, as the directors believe the swaps used to cover this liability are no longer effective.
The interest rate profile of mixed rate financial liabilities of the Group as at March, 31 2004 was:
| Interest rate agreements |
2005 |
2006 |
2007 |
2008 |
2009 |
Net fair value |
|||||||
| Fixed |
|||||||||||||
| Notional amounts A (GBP million) |
356 | 332 | 291 | 235 | 174 | (28 | ) | ||||||
| Average pay rate |
6.6% | 6.6% | 6.6% | 6.6% | 6.6% | ||||||||
| Average receive rate |
4.7% | 4.7% | 4.7% | 4.7% | 4.7% | ||||||||
| Variable to fixed: |
|||||||||||||
| Notional amounts B (GBP million) |
30 | (3 | ) | ||||||||||
| Average pay rate |
5.8% | ||||||||||||
| Average receive rate |
6 month | ||||||||||||
| LIBOR | |||||||||||||
| Collars: |
|||||||||||||
| Notional amounts C (GBP million) |
70 | (2 | ) | ||||||||||
| Collar spread |
5.3% to 6.8% |
||||||||||||
| TOTAL |
(33 | ) | |||||||||||
F-41
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
| A. | The derivative agreements were amended post March 31, 2003 as part of the Proposed Restructuring. The effect has been to fix interest payments under the swaps from October 2004 onwards |
| B. | The bank has the right to cancel the swaps at zero cost on any cancellation date from April 2005 and every year thereafter. |
| C. | The banks have the right to enter into semi-annual swaps receiving 5.25% and pay 6 month LIBOR for ten years at zero cost in April 2005. |
The interest rate profile of financial liabilities of the Group as at March 31, 2003 was:
| Currency |
Total |
Floating rate financial liabilities |
Fixed rate financial liabilities |
Mixed rate financial liabilities (see below) |
Financial liabilities on which no interest is paid | |||||
| £m | £m | £m | £m | £m | ||||||
| Sterling |
3,729 | 475 | 408 | 56 | 2,790 |
| Fixed Rate financial liabilities |
Financial liabilities on which no interest is paid | |||||
| Currency |
Weighted average interest rate |
Weighted average period for which the rate is fixed |
Weighted average period until maturity | |||
| % | Years | Years | ||||
| Sterling |
6.08 | 5.5 | 14.6 | |||
The interest rate profile of mixed rate financial liabilities of the Group as at March 31, 2003 was:
| Interest rate agreements |
2004 |
2005 |
2006 |
2007 |
2008 |
Net fair value |
|||||||
| Variable to fixed: |
|||||||||||||
| Notional amounts (GBP million) |
377 | 356 | 332 | 291 | 235 | (47 | ) | ||||||
| Average pay rate |
6.6% | 6.6% | 6.6% | 6.6% | 6.6% | ||||||||
| Average receive rate |
6 month | 6 month | 6 month | 6 month | 6 month | ||||||||
| LIBOR | LIBOR | LIBOR | LIBOR | LIBOR | |||||||||
| Fixed variable: |
|||||||||||||
| Notional amounts (GBP million) |
30 | 30 | (3 | ) | |||||||||
| Average pay rate |
5.8% | 5.8% | |||||||||||
| Average receive rate |
6 month | 6 month | |||||||||||
| LIBOR | LIBOR | ||||||||||||
| Collars: |
|||||||||||||
| Notional amounts (GBP million) |
70 | 70 | (6 | ) | |||||||||
| Collar spread |
5.3% to 6.8% |
5.3% to 6.8% |
|||||||||||
| TOTAL |
(56 | ) | |||||||||||
F-42
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(ii) Interest rate risk profile of financial assets
The Group held the following financial assets as at March 31, 2004 and March 31, 2003:
| Group | ||||
| 2004 |
2003 | |||
| £m | £m | |||
| Assets held as part of the financing arrangements of the Group: |
||||
| Short-term financial assets |
||||
| Sterling |
840 | 647 | ||
| Non-Sterling |
1 | 1 | ||
| 841 | 648 | |||
| Long term financial assets |
||||
| Sterling |
446 | 340 | ||
| 1,287 | 988 | |||
Short-term financial assets comprise cash, investments in liquid funds and debtors (excluding prepayments) all of which have maturity dates within one year. Cash not immediately required for business purposes is invested in fixed-rate term deposits and money market funds. At March 31, 2004 the term deposits and money market funds not used to provide collateral were due to mature or were available within one month and earned interest at an average rate of 3.9%. The balance of £297m, which was deposited in support of collateral requirements, earned an average rate of 3.1%. Availability of the cash is restricted over the periods of the collateralized positions.
Long-term financial assets comprise the balance in the UK decommissioning fund and fixed asset investments.
(iii) Maturity profile of financial liabilities
| 2004 |
2003 | |||
| £m | £m | |||
| Less than one year |
1,304 | 1,089 | ||
| Between one and two years |
413 | 248 | ||
| Between two and five years |
679 | 834 | ||
| Over five years |
1,487 | 1,558 | ||
| 3,883 | 3,729 | |||
The analysis of maturity of borrowings has been prepared based on the dates when the borrowings mature under the existing contractual arrangements. However, the standstill arrangements which have been put in place have the effect of deferring the payments of certain amounts due until the bonds and Eggborough project finance loan are replaced as part of the restructuring of the Group or earlier termination of the standstill arrangements. The maturity profile of borrowing is likely to change upon completion of the restructuring.
F-43
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(iv) Borrowing facilities
At March 31, 2004 and March 31, 2003 the Group had the following undrawn committed borrowing facilities in place, in respect of which all conditions precedent had been met at that date:
| 2004 |
2003 | |||
| £m | £m | |||
| Expiring in one year or less—Government Facility |
200 | 200 | ||
(v) Fair values
Set out below is a comparison by category of book values and fair values of all the Group’s financial assets and financial liabilities as at March 31, 2004 and March 31, 2003.
| 2004 |
2003 |
|||||||||||
| Book value |
Fair value |
Book value |
Fair value |
|||||||||
| £m | £m | £m | £m | |||||||||
| Primary financial instruments held or issued to finance the Group’s operations: |
||||||||||||
| Short-term assets |
810 | 810 | 639 | 639 | ||||||||
| Short-term borrowings and current portion of long-term borrowings |
(1,261 | ) | (1,288 | ) | (1,033 | ) | (969 | ) | ||||
| Long-term assets |
446 | 446 | 340 | 340 | ||||||||
| Long-term borrowings and liabilities |
(2,579 | ) | (2,328 | ) | (2,640 | ) | (2,140 | ) | ||||
| (2,584 | ) | (2,360 | ) | (2,694 | ) | (2,130 | ) | |||||
| Financial instruments held or issued for proprietary trading purposes |
||||||||||||
| Speculative trading contracts |
21 | 21 | 9 | 9 | ||||||||
| Derivative financial instruments used to manage foreign currency, interest rate and commodity price risk |
||||||||||||
| Interest rate swaps |
(33 | ) | (33 | ) | (56 | ) | (56 | ) | ||||
| (2,596 | ) | (2,372 | ) | (2,741 | ) | (2,177 | ) | |||||
The fair value of the short-term assets approximates to book value due to their short-term maturities.
Short-term borrowings comprise trade creditors and retentions. The book value of these liabilities has been used to approximate fair value.
Long-term assets comprise the balance in the UK decommissioning fund and other fixed asset investments. The basis of valuation is referred to in notes 15 and 14 respectively.
Long-term borrowings and liabilities comprise the Group’s nuclear liabilities, bonds and the long-term project finance loan related to the investment in the Eggborough Power Station. There is no open market information available for the long-term project finance loan, the value of which has been severely affected by the financial restructuring of the Group. Therefore, the fair value that has been
F-44
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
attributed to the loan, £150m (2003: £150m), has been based on the Directors’ best estimate of the net realizable value of the Eggborough Station upon which this debt is secured. The nuclear liabilities book value has been used to approximate fair value and the quoted closing clean market price at the balance sheet date has been used to determine the fair valuation of the long-term bonds.
The fair value of onerous trading contracts represents the value established within the terms of the Proposed Restructuring.
The market trading price at balance sheet date was used to determine the fair valuation of the interest rate swaps.
(vi) Gains and losses on financial instruments held or issued for trading purposes
The net gain from trading in energy derivatives included in the profit and loss account for the period to March 31, 2004 is £14m (2003: £13m).
Interest rate swaps are also held, which do not qualify for hedge accounting. However, the interest rate swaps are not held for trading purposes, and so disclosures in the interest rate swaps are given in note 23.
As discussed in note 2(xix) where the financial investments are for proprietary trading purposes, the movement in the fair value is reflected through the profit and loss account.
F-45
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(vii) Hedges
Gains and losses on instruments used for hedging are not recognized until the exposure that is being hedged is itself recognized. Unrecognized gains and losses on instruments used for hedging, and the movements therein, are as follows:
| March 31, 2004 |
Unrecognized Gains |
Unrecognized Losses |
Total Unrecognized |
Deferred |
|||||||
| £m | £m | £m | £m | ||||||||
| Net losses on derivative instruments at April 1, 2003 |
— | — | — | (2 | ) | ||||||
| Note losses arising in previous period included in current period profit and loss account |
— | — | — | 2 | |||||||
| Net losses on derivative instruments at March 31, 2004 |
— | — | — | — | |||||||
| March 31, 2003 |
Unrecognized Gains |
Unrecognized Losses |
Total Unrecognized |
Deferred |
|||||||
| £m | £m | £m | £m | ||||||||
| Net losses on derivative instruments at April 1, 2002 |
— | (28 | ) | (28 | ) | (10 | ) | ||||
| Note losses arising in previous period included in current period profit and loss account |
— | 28 | 28 | 8 | |||||||
| Net losses arising before April 1, 2002 not included in current period profit and loss account |
— | — | — | (2 | ) | ||||||
| Net losses arising in current period not included in current period profit and loss account |
— | — | — | — | |||||||
| Net losses on derivative instruments at March 31, 2003 |
— | — | — | (2 | ) | ||||||
| Of which: |
|||||||||||
| Net losses expected to be included in the profit and loss account for the year end March 31, 2004 |
— | — | — | (2 | ) | ||||||
| Net losses expected to be included in the profit and loss accounts beyond the year ended March 31, 2004 |
— | — | — | — | |||||||
The above analysis excludes any gains and losses in respect of the net investment as gains and losses arising on these contracts are recorded in the statement of total recognized gains and losses.
(viii) Currency exposures
The Group used foreign currency borrowings to mitigate the currency exposures arising from its net investments overseas. Gains and losses arising on net investments overseas and currency borrowings used to hedge the currency exposure have been recognized in the statement of total recognized gains and losses. The Group did not hold material net monetary assets or liabilities in currencies other than functional currency of the operating unit involved at March 31, 2004 and March 31, 2003.
F-46
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
There are potential future foreign currency receivables in respect of amounts outstanding from the sale of Bruce Power and AmerGen. When these cash flows become more certain in the future the Group will evaluate currency hedging opportunities, balancing the cost and availability of entering into such transactions against the underlying currency risk.
21. PROVISIONS FOR LIABILITIES AND CHARGES
| Group |
Company | |||||||
| 2004 |
2003 |
2004 |
2003 | |||||
| £m | £m | £m | £m | |||||
| Nuclear liabilities (note 22) |
1,776 | 1,673 | — | — | ||||
| Other provisions (note 23) |
36 | 62 | 5 | 9 | ||||
| 1,812 | 1,735 | 5 | 9 | |||||
22. NUCLEAR LIABILITIES
| Back end fuel costs contracted |
Back end fuel costs uncontracted |
De- commissioning |
2004 Total |
2003 Total |
|||||||||
| £m | £m | £m | £m | £m | |||||||||
| As at April 1, 2003 |
2,263 | 678 | 996 | 3,937 | 3,719 | ||||||||
| Charged to profit and loss account: |
|||||||||||||
| —operating costs |
114 | 16 | — | 130 | 105 | ||||||||
| —revalorization (note 8) |
129 | 35 | 51 | 215 | 228 | ||||||||
| Payments in the year |
(59 | ) | — | — | (59 | ) | (115 | ) | |||||
| As at March 31, 2004 |
2,447 | 729 | 1,047 | 4,223 | 3,937 | ||||||||
The year end balances of nuclear liabilities are included in the balance sheet as follows:
| 2004 |
2003 | |||
| £m | £m | |||
| Creditors: |
||||
| —amounts falling due within one year |
554 | 355 | ||
| —amounts falling due after more than one year |
1,893 | 1,909 | ||
| Provisions for liabilities and charges |
1,776 | 1,673 | ||
| 4,223 | 3,937 | |||
Fuel costs—back end
Accruals for AGR fuel services relating to spent AGR fuel are based on the terms of contracts with BNFL (dated March 30, 1995 and June 3, 1997), most of which include fixed prices subject to indexation, or the Group’s estimates where no contracts exist. Provisions for services relating to the disposal of nuclear waste and the storage and disposal of PWR spent fuel are based on cost estimates derived from the latest technical assessments.
Decommissioning
The costs of decommissioning the power stations have been estimated on the basis of technical assessments of the processes and methods likely to be used for decommissioning under the current
F-47
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
regulatory regime. The estimates are designed to reflect the costs of making the sites of the power stations available for alternative use in accordance with the Group’s decommissioning strategy.
Projected payment details
Based on current estimates of station lives and lifetime output projections, the following table shows, in current prices, the likely undiscounted payments, the equivalent sums discounted at 3% per annum to the balance sheet date and the amounts accrued to date.
| Back end fuel costs contracted |
Back end fuel costs uncontracted |
Decommissioning |
Group 2004 Total |
Group 2003 Total | ||||||
| £bn | £bn | £bn | £bn | £bn | ||||||
| Undiscounted |
5.2 | 4.7 | 5.1 | 15.0 | 14.7 | |||||
| Discounted |
3.5 | 1.1 | 1.1 | 5.7 | 5.3 | |||||
| Accrued to date |
2.4 | 0.7 | 1.1 | 4.2 | 3.9 | |||||
The differences between the undiscounted and discounted amounts reflect the fact that the costs concerned will not fall due for payment for a number of years. The differences between the discounted amounts and those accrued to date will be charged to the profit and loss account over the remaining station lives since they relate to future use of fuel.
Under the terms of the contracts with BNFL referred to above and in accordance with the projected pattern of payments for decommissioning and other liabilities, taking account of the decommissioning fund arrangements described in note 2 (xvii), the undiscounted payments in current prices are expected to become payable as follows:
| Back end fuel costs contracted |
Back end fuel costs uncontracted |
Decommissioning |
Group 2004 Total |
Group 2003 Total | ||||||
| £m | £m | £m | £m | £m | ||||||
| Within 1 year |
552 | — | 19 | 571 | 373 | |||||
| Within 1-2 years |
223 | 7 | 19 | 249 | 253 | |||||
| Within 2-3 years |
182 | 8 | 19 | 209 | 242 | |||||
| Within 3-4 years |
205 | 16 | 19 | 240 | 207 | |||||
| Within 4-5 years |
178 | 12 | 50 | 240 | 228 | |||||
| Total within 5 years |
1,340 | 43 | 126 | 1,509 | 1,303 | |||||
| 6 - 10 years |
1,181 | 123 | 206 | 1,510 | 1,391 | |||||
| 11 - 25 years |
1,575 | 422 | 320 | 2,317 | 2,375 | |||||
| 26 - 50 years |
649 | 1,079 | 54 | 1,782 | 1,845 | |||||
| 51 years and over |
485 | 3,060 | — | 3,545 | 3,489 | |||||
| 5,230 | 4,727 | 706 | 10,663 | 10,403 | ||||||
F-48
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
23. OTHER PROVISIONS
| Eggborough site restoration |
Interest rate swaps |
Restructuring |
2004 Group total |
2003 Group total |
2004 Company interest rate swaps |
2003 Company interest rate swaps | |||||||||||||
| £m | £m | £m | £m | £m | £m | £m | |||||||||||||
| As at April 1, 2003 |
3 | 56 | 3 | 62 | 349 | 9 | — | ||||||||||||
| Provided in year |
— | — | — | — | 64 | — | 9 | ||||||||||||
| Revalorization |
— | — | — | — | 10 | — | — | ||||||||||||
| Revaluation to market value |
— | (5 | ) | — | (5 | ) | — | — | — | ||||||||||
| Utilized in the year |
— | (13 | ) | (3 | ) | (16 | ) | (45 | ) | (3 | ) | — | |||||||
| Reclassified as other creditors |
— | (5 | ) | — | (5 | ) | (316 | ) | (1 | ) | — | ||||||||
| As at March 31, 2004 |
3 | 33 | — | 36 | 62 | 5 | 9 | ||||||||||||
The interest rate swaps provision of £33m is in respect of swap contracts, which were put in place to hedge interest rate risk. The Directors have reviewed the necessity for these swaps in the context of the Proposed Restructuring and have concluded that the swaps are no longer effective as hedges. A provision of £56m was created at March 31, 2003 and was reduced to £33m at March 31, 2004 through utilizations of £13m, amounts reclassified as other creditors of £5m and revaluation to market value of £5m. The Company share of the provision was £9m at March 31, 2003, which was reduced to £5m at March 31, 2004 through utilizations of £3m and an accruals movement of £1m.
24. DEFERRED TAXATION
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Accelerated capital allowances |
30 | (56 | ) | |||
| Other long-term timing differences |
(85 | ) | (64 | ) | ||
| Short-term timing differences |
28 | 20 | ||||
| Corporation tax losses |
(348 | ) | (262 | ) | ||
| Undiscounted asset for deferred tax |
(375 | ) | (362 | ) | ||
| Discount |
84 | 212 | ||||
| De-recognition of asset |
291 | 150 | ||||
| Discounted provision of deferred tax |
— | — | ||||
The Company does not have a deferred tax liability at March 31, 2004 (2003: £nil).
F-49
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
25. POST RETIREMENT BENEFIT OBLIGATIONS
UK Pension schemes
British Energy operates two separate pension arrangements in the UK within the Electricity Supply Pension Scheme (‘ESPS’), BEGG for the majority of employees and BECG for the employees at Eggborough Power Station. The ESPS is a defined benefit scheme, which is externally funded and subject to triennial actuarial valuation. Each pension group that participates in the ESPS is financially independent from the other groups.
The most recent triennial valuations of the BEGG and BECG schemes were carried out at March, 31 2001 by the independent ESPS actuary. The valuations for accounting purposes have been carried out by a separate independent actuary using the projected unit method. The principal assumptions adopted for both these accounts valuations were that, over the long-term, the investment rate of return would be 6% per annum for benefits already accrued, and 6.5% for the return achieved on future contributions. The rate of salary increase would be 4% per annum and the rate of pension increase would be 2.5% per annum. Assets were taken at market value. At the date of the valuation, the combined market value of assets of both schemes was £1,944m. This represents 119% of the benefits that had accrued to members after allowing for expected future increases in earnings.
Formal triennial valuations of BEGG and BECG pension schemes at March 31, 2004 are currently being undertaken, but the results of these valuations will not be finalised until later in 2004. However, initial indications are suggesting a range of deficit between £330m to £440m.
British Energy contributed 17.1% to the BEGG pension scheme and 15.3% to the BECG pension scheme for the period April 1, 2003 to March 31, 2004. Contributing members contribute 5% and 6% to the respective plans. Any deficiency disclosed in the BEGG or BECG pension schemes following an actuarial valuation has to be made good by British Energy.
The Group’s UK pension costs for the year to March 31, 2004 were nil net of surplus amortization (2003: £6m). At that date there was a SSAP24 prepayment of £101m (2003: £72m) in the UK.
Bruce Power Pension Scheme
Following the disposal of British Energy’s interest in Bruce Power in 2003 the Group no longer operates the Bruce Power Pension Plan. As a result FRS17 disclosures are only made with regard to this scheme in relation to prior year comparatives as applicable.
Bruce Power provided pensions, group life insurance and health care benefits for retirees in Canada. Pensions were provided through the Bruce Power Pension Plan, which was a defined benefit scheme and was externally funded and subject to triennial actuarial valuations. Members of the plan contributed on average 5% of their salaries to the scheme. Bruce Power contributed the balance of the cost of providing the pension.
Bruce Power also operated a supplemental retirement pension plan that provided additional pensions to some retirees. This plan was not funded. Retiree group life insurance and health care benefits were also not pre-funded.
The Group’s Bruce Power related pension costs for the period of ownership from April 1, 2002 and February 14, 2003 were £12m.
F-50
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
FRS17 Disclosures
The Group has not implemented FRS17 ‘Retirement benefits’ in the accounts for the year ended March 31, 2004. The disclosures required under the transitional arrangements for UK and Canadian plans within FRS17 as advised by the Company’s actuaries are, however, set out below:
(i) UK Pension Schemes
a) Major assumptions for FRS17 disclosures 31 March:
| 2004 |
2003 |
2002 | ||||
| % pa | % pa | % pa | ||||
| Price inflation |
2.75 | 2.25 | 2.75 | |||
| Rate of general increase in salaries |
4.25 | 3.75 | 4.25 | |||
| Rate of increase of pensions in payment |
2.75 | 2.25 | 2.75 | |||
| Discount rate |
5.50 | 5.50 | 6.00 |
b) The assets and liabilities of the scheme on an FRS17 basis and the expected rates of return at 31 March are:
| Rate of return |
Value at March 31, 2004 |
Rate of return |
Value at March 31, 2003 |
Rate of return |
Value at March 31, 2002 |
||||||||||
| % | £m | % | £m | % | £m | ||||||||||
| Equities |
8.25 | 1,102 | 8.5 | 878 | 8.0 | 1,248 | |||||||||
| Bonds |
4.75 | 469 | 4.5 | 438 | 5.3 | 412 | |||||||||
| Property |
6.4 | 223 | 6.5 | 183 | 6.7 | 175 | |||||||||
| Others |
3.75 | 28 | 3.75 | 26 | 4.75 | 7 | |||||||||
| Total market value of plan assets |
1,822 | 1,525 | 1,842 | ||||||||||||
| Present value of plan liabilities |
(2,147 | ) | (1,877 | ) | (1,799 | ) | |||||||||
| Pension (liability)/asset before deferred tax |
(325 | ) | (352 | ) | 43 | ||||||||||
| Related deferred tax liability |
— | — | (13 | ) | |||||||||||
| Net pension (liability)/asset |
(325 | ) | (352 | ) | 30 | ||||||||||
No deferred tax asset is recognizable on the pension deficit in 2004 and 2003, based on application of the deferred tax accounting policy set out in note 2 (xv).
c) Analysis of the amount that would be charge to operating profit on an FRS17 basis:
| 2004 (Gain)/loss |
2003 (Gain)/loss |
|||||
| £m | £m | |||||
| Operating profit |
||||||
| Current service cost |
35 | 32 | ||||
| Past service cost |
1 | 13 | ||||
| Total charge to operating profits |
36 | 45 | ||||
| Finance income |
||||||
| Expected return on assets in the pension scheme |
(106 | ) | (132 | ) | ||
| Interest on pension scheme liabilities |
102 | 107 | ||||
| Net credit to finance income |
(4 | ) | (25 | ) | ||
| Total profit and loss account charge before tax |
32 | 20 | ||||
F-51
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
d) Movement in plan (deficit)/surplus during the year on an FRS17 basis:
| 2004 |
2003 |
|||||
| £m | £m | |||||
| (Deficit)/surplus in plan at beginning of the year |
(352 | ) | 43 | |||
| Contributions paid |
34 | 31 | ||||
| Current service cost |
(35 | ) | (32 | ) | ||
| Past service cost |
(1 | ) | (12 | ) | ||
| Other finance income |
4 | 25 | ||||
| Actuarial gain/(loss) (note 25(e)) |
25 | (407 | ) | |||
| Deficit in the plan at the end of the year |
(325 | ) | (352 | ) | ||
e) History of experience gains and losses which would have been recognized on an FRS17 basis:
| 2004 |
2003 | ||||||||||
| (Gain)/loss |
As % of plan |
(Gain)/loss |
As % of plan | ||||||||
| £m | £m | ||||||||||
| Consolidated statement of total recognized gains and losses |
|||||||||||
| Actual return less expected return on post employment plan assets |
(228 | ) | (13 | ) | 410 | 27 | |||||
| Experience losses arising on plan liabilities |
34 | 2 | (3 | ) | — | ||||||
| Changes in assumptions (financial and demographic) |
169 | 8 | — | — | |||||||
| Actuarial (gain)/loss recognizable in consolidated statement of total recognized against and losses before tax |
(25 | ) | 407 | ||||||||
| As % of plan liabilities at end of year |
1 | 22 | |||||||||
(ii) Bruce Power Pension Scheme
Due to the Group’s disposal of its interest in Bruce Power during 2003 the following disclosure has only been provided where applicable.
(a) Major assumptions for FRS17 disclosures at 31 March:
| 2003 |
2002 | |||
| % pa | % pa | |||
| Price inflation |
2.75 | 2.75 | ||
| Rate of general increase in salaries |
3.75 | 3.75 | ||
| Rate of increase of pensions in payment |
2.75 | 2.75 | ||
| Discount rate |
7.0 | 7.0 |
F-52
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
b) The assets and liabilities of the scheme on an FRS17 basis and the expected rates of return at 31 March are:
| Rate of return |
Value at March 31, 2002 |
||||
| % | £m | ||||
| Equities |
8.5 | 255 | |||
| Bonds |
6.0 | 151 | |||
| Others |
5.0 | 16 | |||
| Total market value of plan assets |
422 | ||||
| Present value of plan liabilities |
(396 | ) | |||
| Net pension asset |
26 | ||||
| Other non-pension post retirement benefits |
(64 | ) | |||
| Related deferred tax asset |
11 | ||||
| Net deficit for post retirement benefits net of tax |
(27 | ) | |||
c) Analysis of the amount that would be charged to operating profit on an FRS17 basis:
| 2003 (Gain)/loss |
|||
| £m | |||
| Operating profit |
|||
| Total charge to operating profits—current service cost |
15 | ||
| Gain on settlements—disposal of Bruce Power |
(103 | ) | |
| Finance income |
|||
| Expected return on assets in the pension scheme |
(26 | ) | |
| Interest on pension scheme liabilities |
26 | ||
| Net credit to finance income |
— | ||
| Total profit and loss account credit before tax |
(88 | ) | |
Due to the Group’s disposal of its interest in Bruce Power during 2003 there was no balance sheet impact of the Bruce Power Pension Plan for the March 31, 2003 and 2004 year ends.
d) Movement in plan deficit during the year on an FRS17 basis:
| 2003 (Gain)/loss |
|||
| £m | |||
| Deficit in plan at April 1, 2002 |
(38 | ) | |
| Current service cost |
(15 | ) | |
| Gain on settlement |
103 | ||
| Foreign exchange |
2 | ||
| Actuarial loss |
(52 | ) | |
| Deficit in the plan at March 31, 2003 |
— | ||
F-53
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
e) History of experience gains and losses which would have been recognized on an FRS17 basis:
| 2003 (Gain)/loss |
|||
| £m | |||
| Actual return less expected return on post employment plan assets |
50 | ||
| Experience gains and losses arising on plan liabilities |
— | ||
| Changes in assumptions (financial and demographic) |
2 | ||
| Foreign exchange adjustments |
(4 | ) | |
| Actuarial loss recognizable in consolidated statement of total recognized gains and losses before tax |
48 | ||
(iii) Group reconciliation of net liabilities and reserves under FRS17
| 2004 |
2004 |
2003 |
2003 |
|||||||||
| Net liabilities |
Profit and loss account reserve |
Net liabilities |
Profit and loss account reserve |
|||||||||
| £m | £m | £m | £m | |||||||||
| As reported |
(3,164 | ) | (3,960 | ) | (3,383 | ) | (4,179 | ) | ||||
| SSAP 24 prepayment |
(101 | ) | (101 | ) | (72 | ) | (72 | ) | ||||
| Net liabilities excluding defined benefit asset |
(3,265 | ) | (4,061 | ) | (3,455 | ) | (4,251 | ) | ||||
| FRS17 pension asset |
1,822 | 1,822 | 1,525 | 1,525 | ||||||||
| FRS17 defined benefit liability |
(2,147 | ) | (2,147 | ) | (1,877 | ) | (1,877 | ) | ||||
| Including FRS17 pension liability |
(3,590 | ) | (4,386 | ) | (3,807 | ) | (4,603 | ) | ||||
No deferred tax asset is recognizable on the pension deficit or pension repayment in 2004 and 2003, based on application of the deferred tax accounting policy set out in note 2 (xv).
26. CALLED UP SHARE CAPITAL
| 2004 |
2003 | |||
| £m | £m | |||
| Authorized |
||||
| 991,679,020 ordinary shares of 44 28/43p each |
443 | 443 | ||
| 720,339,029 ‘A’ shares of 60p each |
432 | 432 | ||
| One special rights redeemable preference share of £1 |
— | — | ||
| 875 | 875 | |||
| Allotted, called up and fully paid |
||||
| 620,362,444 ordinary shares of 44 28/43p each |
277 | 277 | ||
| Non–equity shareholders funds |
||||
| 80,908,247 ‘A’ shares of 60p each |
48 | 48 | ||
| 74,752,351 deferred ‘A’ shares of 60p each |
45 | 45 | ||
| One special rights redeemable preference share of £1 |
— | — | ||
| 93 | 93 | |||
| 370 | 370 | |||
F-54
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Special rights redeemable preference share of £1
The special rights redeemable preference share is redeemable at par at any time after September 30, 2006 at the option of the Secretary of State, after consulting the Company. This share, which may only be held by a Minister of the Crown or other person acting on behalf of HM Government, does not carry any rights to vote at general meetings, but entitles the holder to attend and speak at such meetings. The special share confers no rights to participate in the capital or profits of the Company beyond its nominal value. Certain matters, in particular, the alteration of specific sections of the Articles of Association of the Company (including the Article relating to limitations that prevent a person having the right to have an interest in 15% or more of the voting share capital), require the prior written consent of the holder of the special share.
‘A’ shares and deferred shares
The ‘A’ shares are traded on the London Stock Exchange and at March 31, 2004 had a market value of 6p (2003: 3p). The deferred shares have a £nil fair value at March 31, 2004 (2003: £nil).
The ‘A’ shares and deferred shares do not carry any rights to receive notice of, attend, speak or vote at any general meeting, unless in the case of ‘A’ shares the meeting is due to consider a resolution for the winding up of the Company, or the non-cumulative preferential dividend to which the ‘A’ shares are entitled remains unpaid six months or more after it fell due. On a winding up of the Company, the ‘A’ shares have preferential rights over the ordinary shares in respect of the distribution of capital. The deferred shares do not confer any rights to participate in the capital or profits of the Company, including on a winding up of the Company.
The impact on the Company’s share capital as a result of the Proposed Restructuring is discussed more fully in note 1.
F-55
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Share Option Schemes
Options outstanding at March 31, 2004, together with their exercise prices and earliest dates of exercise, are as follows:
| Exercise price per share |
Exercise Date |
No. of Ordinary Shares | ||||||
| £ | 2004 |
2003 | ||||||
| British Energy ShareSave Scheme |
4.44 | 2003 | 4,353 | 174,600 | ||||
| 4.39 | 2004 | 99,444 | 113,268 | |||||
| 1.36 | 2003 | 32,449 | 4,895,405 | |||||
| 1.36 | 2005 | 3,069,904 | 3,624,113 | |||||
| 2.61 | 2004 | 435,619 | 484,116 | |||||
| 2.61 | 2006 | 410,851 | 485,011 | |||||
| 2.29 | 2005 | — | 499,455 | |||||
| 2.29 | 2007 | — | 453,946 | |||||
| 1.36 | 2005 | 1,832,153 | 3,726,626 | |||||
| 1.36 | 2007 | 2,633,723 | 4,616,840 | |||||
| Employee Share Scheme |
2.60 | 2000 | 6,282,958 | 6,423,428 | ||||
| 4.08 | 2000 | 502,572 | 516,572 | |||||
| 5.08 | 2001 | 3,829,474 | 3,915,603 | |||||
| 5.29 | 2002 | 3,922,000 | 4,022,000 | |||||
| Senior Management Share Scheme |
2.60 | 2000 | 1,023,941 | 1,099,802 | ||||
| 3.95 | 2000 | 22,264 | 22,264 | |||||
| 5.08 | 2001 | 402,252 | 444,425 | |||||
| 6.67 | 2002 | 19,865 | 19,865 | |||||
| 5.29 | 2002 | 537,985 | 599,337 | |||||
| 3.57 | 2002 | 33,952 | 33,952 | |||||
| 2.41 | 2003 | 1,454,203 | 1,636,752 | |||||
| 3.18 | 2004 | 125,786 | 125,786 | |||||
27. PROFIT AND LOSS ACCOUNT
| Group |
Company |
|||||||||||||||||
| 2004 |
2003 |
2002 |
2004 |
2003 |
2002 |
|||||||||||||
| £m | £m | £m | £m | £m | £m | |||||||||||||
| As at April 1, 2001, April 1, 2002 and April 1, 2003 |
(4,179 | ) | (213 | ) | 372 | (4,563 | ) | 1,495 | 1,855 | |||||||||
| Profit/(loss) for the year |
234 | (3,941 | ) | (577 | ) | (616 | ) | (6,058 | ) | (360 | ) | |||||||
| Foreign currency translation adjustments |
(15 | ) | (25 | ) | (8 | ) | — | — | — | |||||||||
| (3,960 | ) | (4,179 | ) | (213 | ) | (5,179 | ) | (4,563 | ) | 1,495 | ||||||||
The Company did not have distributable reserves at March 31, 2004 (2003: £nil).
28. RECONCILIATION OF MOVEMENT IN EQUITY SHAREHOLDERS’ FUNDS
| Group |
||||||
| 2004 |
2003 |
|||||
| £m | £m | |||||
| As at April 1, 2003 and April 1, 2002 |
(3,476 | ) | 490 | |||
| Profit /(loss) for the financial year |
234 | (3,941 | ) | |||
| Foreign currency translation adjustments |
(15 | ) | (25 | ) | ||
| As at March 31, 2004 and March 31, 2003 |
(3,257 | ) | (3,476 | ) | ||
F-56
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
29. RECONCILIATION OF OPERATING PROFIT TO OPERATING NET CASH FLOWS
| Group |
Group |
|||||||||||
| 2004 |
2003 |
|||||||||||
| Total |
Continuing activities |
Discontinued activities |
Total |
|||||||||
| £m | £m | £m | £m | |||||||||
| Operating profit/(loss) |
340 | (3,899 | ) | 97 | (3,802 | ) | ||||||
| Depreciation (credit)/charges (includes fixed asset write-(up)/down and lease amortization) |
(245 | ) | 4,012 | 13 | 4,025 | |||||||
| Nuclear liabilities charged to operating costs |
130 | 105 | — | 105 | ||||||||
| Nuclear liabilities discharged |
(59 | ) | (115 | ) | — | (115 | ) | |||||
| Other provisions discharged |
(3 | ) | (45 | ) | — | (45 | ) | |||||
| Regular contributions to decommissioning fund |
(19 | ) | (18 | ) | — | (18 | ) | |||||
| Operating exceptional decommissioning fund movement |
(13 | ) | 13 | — | 13 | |||||||
| Decrease/(increase) in stocks |
10 | 72 | (12 | ) | 60 | |||||||
| Decrease/(increase) in debtors |
4 | 12 | (30 | ) | (18 | ) | ||||||
| Increase in creditors |
11 | 107 | 24 | 131 | ||||||||
| Net cash in flow from operating activities |
156 | 244 | 92 | 336 | ||||||||
| Payments to acquire tangible fixed assets |
— | (112 | ) | (170 | ) | (282 | ) | |||||
| Net cash inflow from operating activities net of capital expenditure |
156 | 132 | (78 | ) | 54 | |||||||
30. RECONCILIATION OF NET CASH FLOW TO MOVEMENT IN FUNDS
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Increase in cash in the year |
175 | 87 | — | ||||||
| Increase/(decrease) in liquid resources |
65 | 37 | (18 | ) | |||||
| Decrease/(increase) in debt |
— | 185 | (111 | ) | |||||
| Decrease/(increase) in net debt in the year |
240 | 309 | (129 | ) | |||||
| Net debt at start of year |
(550 | ) | (859 | ) | (730 | ) | |||
| Net debt at end of year |
(310 | ) | (550 | ) | (859 | ) | |||
31. ANALYSIS OF NET DEBT
| Cash at bank and in hand |
Term Deposits |
Debt due within one year |
Debt due after more than one year |
Net (debt) |
|||||||||
| £m | £m | £m | £m | £m | |||||||||
| As at March 31, 2002 |
— | 209 | (153 | ) | (915 | ) | (859 | ) | |||||
| Cash flows |
87 | 37 | 1 | 91 | 216 | ||||||||
| Disposal of Bruce Power debt |
— | — | — | 93 | 93 | ||||||||
| As at March 31, 2003 |
87 | 246 | (152 | ) | (731 | ) | (550 | ) | |||||
| Cash flows |
175 | 65 | (45 | ) | 45 | 240 | |||||||
| As at March 31, 2004 |
262 | 311 | (197 | ) | (686 | ) | (310 | ) | |||||
F-57
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
32. CONTINGENT ASSETS
On May 16, 2003 the Company announced that it had exchanged the last of the suite of contracts covering front end and back end fuel services required to give effect to the non-binding heads of terms entered into with BNFL on November 28, 2002. The front end contracts became effective on April 1, 2003 but may be terminated if the Proposed Restructuring is not completed. The back end contracts are conditional on completion of the Proposed Restructuring but payments are being made as if the revised back end contracts had become effective on April 1, 2003. The financial statements for the period to March 31, 2004 have been drawn up on the basis of the historic BNFL contracts in respect of back end fuel contracts, pending satisfaction of the restructuring conditions set out in the revised contracts, thereby creating a contingent asset of £306m (2003: £113m) which will be recognized upon completion of the Proposed Restructuring as one of a number of expected adjustments at that time. An analysis of amounts included in current liabilities due to BNFL but not expected to be paid by the Group provided the Proposed Restructuring is completed is shown as follows:
| £m |
£m |
|||||
| Opening balance at April 1, 2003 |
113 | |||||
| Amounts payable to BNFL under the historic back end contracts for the period |
249 | |||||
| Less: amounts paid/payable for the period under the revised BNFL back end contracts, analyzed as follows: |
||||||
| Amounts settled |
(59 | ) | ||||
| Amounts included in accruals at year end |
(11 | ) | ||||
| Cash flow benefit arising within the year |
179 | |||||
| Finance charges accrued on amounts stood still |
14 | |||||
| Closing balance at March 31, 2004 |
306 | |||||
| £m |
||||||
| Amounts payable under historic BNFL back end contracts |
||||||
| Opening balance at April 1, 2003 |
113 | |||||
| Amounts falling due in year |
249 | |||||
| Amounts settled |
(59 | ) | ||||
| Standstill interest accrued |
14 | |||||
| Closing asset balance at March 31, 2004 |
317 | |||||
| Less: amounts payable under revised BNFL back end contracts |
||||||
| Opening balance at April 1, 2003 |
— | |||||
| Amounts falling due in year |
70 | |||||
| Amounts settled |
(59 | ) | ||||
| Closing liability balance at March 31, 2004 |
11 | |||||
| Contingent asset at March 31, 2004 |
306 | |||||
On February 14, 2003 the Company announced that it had completed the disposal of its 82.4% interest in Bruce Power in Canada to a consortium of three parties. 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 June 15, 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 August 1, 2003. An amount of C$5m
F-58
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
is deducted from the C$50 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 March 22, 2004 and C$10m on May 25, 2004 in partial consideration under the Trust Agreement. British Energy is seeking the payment of additional consideration under the Trust Agreement on the basis that Bruce A Unit 4 restarted in October 2003 and Unit 3 restarted in January 2004 but has not recognized any additional amounts on its balance sheet at March 31, 2004 because of uncertainties regarding their realization. The Company is in discussion with the Ontario Provincial Government which has indicated that it considers that the units may have restarted, for the purposes of the Trust Agreement, or at later dates. The amounts recoverable in respect of the restarts will be substantially lower than the maximum C$100m but the amounts and timing of the payments have still to be confirmed.
33. CONTINGENT LIABILITIES
These accounts are drawn up on a going concern basis, the basis of which is explained more fully in note 1 to these accounts. This note describes the contingent liabilities that are applicable to the Group and the Company.
The Group has been provided with a credit facility by the Secretary of State. As at March 31, 2004, the Group had no drawings under the Government Facility. Also at March 31, 2004, the Group had cash and liquid investments of £573m of which £297m had been deposited as collateral to support trading and other operations.
The following security has been granted for obligations under the Government Facility made available by the Secretary of State:
| • | an all monies debenture creating fixed security (by way of assignment and/or fixed charge) over certain intra-group receivables and special accounts and a floating charge between the Secretary of State and certain Group companies; |
| • | fixed charges in relation to the UK nuclear power stations; and |
| • | pledge and mortgage of shares in certain Group subsidiaries in favour of the Secretary of State. |
Amounts owing by EPL to the Eggborough Banks are not guaranteed by the Company. However, the Company guarantees the payment of amounts by BEPET to EPL, calculated to cover EPL’s borrowing and operating costs. In addition the Company also provides a subordinated loan facility to EPL.
On October 1, 2003, the Company announced that it had entered into the Creditor Restructuring Agreement with certain significant creditors (including the Eggborough Banks) and BNFL relating to the standstill, recognition and compromise of their claims. However, while the Directors believe that the amounts of the agreed claims agreed for the purposes of the Proposed Restructuring currently reflect the amounts legally claimable, in the event of the Proposed Restructuring not being completed different amounts may be calculated as being claimable.
On September 25, 2002 the Nuclear Generation Decommisioning Fund Limited (the ‘NDF’) served a default notice relating to the solvency of the Company, BEG and BEGUK. Unless the default is cured to the satisfaction of the NDF, or waived, the NDF has the right to require accelerated payment of all of
F-59
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
the contributions due to the NDF prior to the next quinquennial review in Autumn 2005. Annual payments are in the region of £18m. The NDF has agreed not to take enforcement action without further notice while the Group progresses satisfactorily towards achieving the Proposed Restructuring. If the conditions to the Proposed Restructuring are satisfied, the NDF and others will enter into a Deed of Termination whereby the NDF agrees that it shall take no action to enforce its rights pursuant to the default notice.
On February 12, 2004 British Energy received a notice of warranty claims from the consortium which purchased the Group’s 82.4% interest in Bruce Power alleging breach of certain warranties and representations relating to tax and to the condition of certain plant at the Bruce Power Station.
The claim relating to the condition of the plant is based upon alleged erosion of some of the steam generator 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.
The principal tax claim relates to the treatment of expenditure at the Bruce Power Station during the period of the Company’s ownership, which 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, which has not been recognized in the financial statements of the period. The consortium claims that allowance of the expenditure for that period would cause it to lose further deductions. British Energy has rejected the tax claim and expects to defend it if it is pursued further. On the basis of advice received, 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.
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. As a result of an accounting adjustment made by Exelon to the value of nuclear fuel contained in AmerGen’s balance sheet dated December 21, 2003 British Energy may be required to make a payment to Exelon of up to US$13.7m. British Energy disputes the claim and served a Dispute Notice on Exelon on June 4, 2004 to preserve its rights. The agreement with Exelon for the sale of AmerGen requires that, prior to instituting any litigation or other dispute resolution procedure, the companies will in good faith seek to resolve any dispute.
The Group is involved in a number of other claims and disputes arising in the normal course of business which are not expected to have a material effect on the Group’s financial position.
The Company has given certain indemnities and guarantees in respect of its subsidiary undertakings. No losses are anticipated to arise under these indemnities and guarantees, provided relevant subsidiary undertakings continue as going concerns.
F-60
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
34. FINANCIAL COMMITMENTS
(i) Capital commitments
| 2004 |
2003 | |||
| £m | £m | |||
| Capital expenditure contracted but not provided |
17 | 40 | ||
(ii) Analysis of annual commitments under operating leases
| 2004 |
2003 | |||
| £m | £m | |||
| Other operating leases expiring in: |
||||
| Two to five years |
3 | — | ||
(iii) Other contractual commitments
Under contractual arrangements, the Group has the following fuel commitments at March 31, 2004:
| 2005 |
2006 |
2007 |
2008 |
2009 |
Thereafter |
Total | ||||||||
| £m | £m | £m | £m | £m | £m | £m | ||||||||
| Commitments to purchase in the year |
200 | 183 | 93 | 67 | 63 | 859 | 1,465 | |||||||
At March 31, 2004 the estimated minimum commitment for the supply of coal was 2.4 m tonnes, which, at contract prices on March 31, 2004, equates to approximately £82m (2003: £68m).
In addition to the liabilities and provisions recognized and described in the notes to the financial statements the Group has provided certain guarantees and commitments in respect of the extent of capital expenditure by Eggborough Power Limited. The Group also enters into commitments to purchase and sell electricity in the normal course of business.
35. POST BALANCE SHEET EVENTS
(i) Audited
The Company was in receipt of a further C$10m on May 25, 2004 in partial consideration of the restart of the Bruce A units, see note 32.
(ii) Unaudited
Output Forecast
On July 30, 2004 we announced that following the evaluation of structural inspections carried out during the statutory outage at the Hartlepool power station and discussions with the Nuclear Installations Inspectorate, we decided that further work to demonstrate the integrity of certain boilers was necessary. This work entails visual inspections of a number of boiler closures at Heysham 1 (one reactor is shut down and the other was shut down for its statutory outage in early September) and at Hartlepool (one reactor is currently shut down and there is no impact on the operation of the other reactor).
At the same time we also announced our revised target of annual nuclear output of around 61.5TWh for the 2004/05 financial year. We are satisfied that, in our current circumstances, the impact of this downward revision in output target on the carrying value of our nuclear assets is not material. The expected annual nuclear output for the year ending March 31, 2005 will be given in the prospectus which is to be published pursuant to the Proposed Restructuring.
F-61
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Exelon
As a result of the ongoing discussions with Exelon outlined in Note 33, we are reviewing with Exelon a working capital adjustment resulting from a change to the estimated tax recoverable for prior periods made after the consummation of the sale and this, if agreed, may result in a reduction in the purchase price payable by Exelon, with the reduction currently estimated to be in the range of up to US$6.3m.
Polygon
On September 3, 2004 two groups of shareholders, together holding 10.22% of our ordinary shares, requisitioned an extraordinary general meeting. Those groups of shareholders were Polygon, Brandes and their respective associates. We are, as a result, obliged under the Companies Act to call the Requisitioned EGM.
We announced on September 23, that the Requisitioned EGM will be held on October 22, 2004. On that date we also announced that as a result of this attempt to frustrate the Proposed Restructuring agreed by the Company in October 2003, we would be applying to cancel the listings of our ordinary and A Shares. As a consequence, and as announced on September 23, 2004, the NYSE suspended trading in our ADRs prior to the opening of trading on September 28, 2004. At that time, the NYSE also instituted delisting proceedings. The suspension and possible delisting from the NYSE does not affect our status as a SEC registrant under the US Securities Exchange Act 1934 or our periodic obligations.
On September 24, 2004 the Company announced (i) the unanimous recommendation of the Board to shareholders to vote against the resolutions proposed by Polygon and Brandes at the Requisitioned EGM, (ii) that it intended to seek an extension to the Creditor Restructuring Agreement long stop date of January 31, 2005 for the Proposed Restructuring and (iii) that, in accordance with the Creditor Restructuring Agreement, it would execute a business transfer agreement whereby the Company’s assets would, conditional on the Proposed Restructuring becoming effective, be transferred to a new intermediate holding company of the restructured British Energy group.
On September 30, 2004 Polygon announced that it would withdraw its support for the Requisitioned EGM. Polygon stated that, having considered the Company’s recent circulars, they now believe there is no commercial logic for it supporting the resolutions to be considered at the Requisitioned EGM and consequently have confirmed that they will vote against the resolutions and not further oppose the Proposed Restructuring. The Requisitioned EGM will take place on October 22, 2004 as described in the notice mailed to our shareholders. Our Board continues to reiterate its unanimous recommendation to all shareholders to vote against the resolutions proposed for the Requisitioned EGM.
Corporate Headquarters
On September 15, 2004 we announced the proposed sale of our corporate headquarters located at Peel Park, East Kilbride, Scotland to Kenmore Capital East Kilbride Limited in consideration of a cash payment of £6.625m and a potential additional cash payment of up to £0.25m if certain letting arrangements come to fruition. We have also entered into a ten year lease for part of the building. It is expected that the sale will be completed in January 2005. In August 2004 we signed a lease for our new corporate headquarters in Alba Campus, Livingston, Scotland.
State Aid
On September 22, 2004 we announced the receipt by the Secretary of State of notification from the European Commission that as far as the Proposed Restructuring involves the grant of State Aid by
F-62
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
the UK Government, such aid is compatible with the Common Market. The European Commission’s decision is subject to the following conditions:
| • | The Company’s nuclear and generation business will be ring-fenced from its fossil fuel, supply and trading businesses to ensure the aid to the nuclear businesses is not used to cross subsidize any of the Company’s businesses. This measure will last indefinitely; |
| • | There will be no nuclear or fossil-fuelled capacity expansion (above our current capacity) by the Company in the European Economic Area for six years, and no hydro-electiric capacity expansion in the UK for the same period; and |
| • | A restriction on the Company selling to its industrial and commercial customers at prices below the prevailing wholesale market prices for six years unless there are exceptional market circumstances as determined by an independent expert. |
The European Commission has set down an additional requirement that a threshold of £1.629 billion be set for the aid, above which the European Commission can request enhanced reporting to satisfy themselves that the state aid is being kept to a minimum and is only being used to authorized purposes.
Credit Rating
On September 23, 2004 we announced that we had received indicative non- investment grade ratings for the £550m of new bonds that are to be issued to certain of our creditors and to the Nuclear Liabilities Fund Limited upon completion of the Proposed Restructuring pursuant to the terms announced on October 1, 2003.
Pension Scheme Valuation
A triennial valuation of the Group’s pension schemes is being carried out by the schemes’ actuaries as at March 31, 2004, however, the result of the valuation will not be concluded until October 2004. The combined funding deficiencies (on the actuarial bases used for the valuations) in the two pension schemes is expected to be £385m, within the range of £330m to £440m previously disclosed. The impact of this deficit will be reflected in our financial results for the year ending March 31, 2005.
Classification of British Energy in the Public Sector
On September 24, 2004 the United Kingdom Office for National Statistics (“ONS”) announced that, with effect from September 9, 2002, the date on which the Government Facility was granted, we would be classified as in the public sector. This classification was stated by the ONS to reflect the degree of control that can be exercised by the Government over us, first through the Government Facility, and then as a result of the terms of our Proposed Restructuring. Prior to this announcement the ONS classified British Energy as part of the private sector.
The ONS’s decision was made for UK National Accounts purposes and was dependent upon a judgment about the degree of control exercised by Government. The ONS has acknowledged that, following completion of the Proposed Restructuring, no one factor constitutes the degree of control necessary for a classification in the public sector. The decision is based on the view that, taken together, a number of factors represent a high degree of Government control. The background to and terms of the Proposed Restructuring are detailed in note 1 to the financial statements.
F-63
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The ONS has noted that as the Proposed Restructuring process has not been finalized, some of the details of its decision may change, and as a result this classification (as it applies to the Company post-restructuring) is provisional.
We are currently assessing the implications of this decision for our business. In particular, we are giving thought to those relationships that will exist post-restructuring that may require to be disclosed under FRS 8—“Related Party Disclosures” in our financial statements for the year ending March 31, 2005. We have not, as yet, finalized our conclusions on this but provide the following information to enable an understanding of the nature of our more significant relationships with Government connected with the Proposed Restructuring negotiations that exist at the present time:
Government: We were provided with the Government Facility by Government in September 2002 which matures on January 31, 2005 and has ranged between £200m and £650m during this period. The Government Facility is secured by certain group assets and cross-guaranteed by the principal group entities (excluding Eggborough Power Limited and Eggborough Power Holdings Limited). Under this facility, borrowings peaked at £123m in November 2003. The balance owed as of March 31, 2004 was £nil (£nil as at March 31, 2003). In addition, the Government has also provided various guarantees during this period to support the Company’s collateral and other commitments.
BNFL: We transact with BNFL, a Government owned body, in relation to certain fuel purchases and other fuel related services. In addition, we have in the past sold inventories and provided IT services to BNFL. In relation to fuel purchases and other fuel related services, purchases in the year ended March 31, 2004 amounted to £411m (March 31, 2003 £387m; March 31, 2002 £435m), and amounts owed to/(receivable from) BNFL as at March 31, 2004 were £333m (£127m as at March 31, 2003; £(26)m as at March 31, 2002). Amounts invoiced to BNFL in respect of sales of inventories were £64m in the year ended March 31, 2004 (£50m year ended March 31, 2003; £nil year ended March 31, 2002). Amounts invoiced to BNFL in respect of sales of IT services were £15m in the year ended March 31, 2004 (£3m year ended March 31, 2003; £3m year ended March 31, 2002). In addition, BNFL has provided financial support to the Company since September 2002 in the form of their participation in the Proposed Restructuring by renegotiating the contractual terms as set out in Note 32 to the financial statements and by rescheduling payment terms.
F-64
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
36. SUMMARY OF DIFFERENCES BETWEEN UK AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”)
(i) Notes on US GAAP Adjustments (Restated)
British Energy’s consolidated statements have been prepared in accordance with UK GAAP which differs in certain significant respects from US GAAP. The effects of the US GAAP adjustments, as restated, to the profit/(loss) and equity shareholders’ deficit are set out in the tables below.
Effect on Profit/(Loss) of Differences Between UK GAAP and US GAAP
| Note | 2004 |
2003 |
2002 |
|||||||||
| £m | £m | £m | ||||||||||
| (Restated) | (Restated) | (Restated) | ||||||||||
| Profit/(loss) for the year under UK GAAP |
234 | (3,941 | ) | (527 | ) | |||||||
| US GAAP adjustments: |
||||||||||||
| Decommissioning costs |
(a | ) | 13 | (70 | ) | (151 | ) | |||||
| Back end fuel costs |
(a | ) | 37 | (450 | ) | (155 | ) | |||||
| Decommissioning fund |
(b | ) | (87 | ) | — | 6 | ||||||
| Amortization of capitalized interest |
(c | ) | — | (6 | ) | (4 | ) | |||||
| Bonds renegotiation |
(d | ) | (5 | ) | (9 | ) | (9 | ) | ||||
| Employee stock compensation schemes |
(e | ) | — | — | (4 | ) | ||||||
| Employee share trusts |
(f | ) | — | 102 | 12 | |||||||
| Capitalization of Bruce costs |
(g | ) | — | (1 | ) | (5 | ) | |||||
| Pension costs |
(h | ) | (48 | ) | (1 | ) | (8 | ) | ||||
| Investment in joint venture |
(i | ) | 142 | 42 | (5 | ) | ||||||
| Disposal of joint venture and Bruce Power |
(j | ) | (157 | ) | 29 | — | ||||||
| FAS 133 adjustments |
(k | ) | (90 | ) | (112 | ) | 236 | |||||
| Fixed asset impairment adjustments |
(l | ) | (225 | ) | (2,942 | ) | 300 | |||||
| Adjustment for Bruce Power lease |
(m | ) | — | (11 | ) | (11 | ) | |||||
| Deferred income tax |
(n | ) | 13 | (1,420 | ) | 38 | ||||||
| Tax effect of US GAAP adjustments |
95 | 990 | 30 | |||||||||
| Profit/(loss) for the financial year under US GAAP before cumulative adjustment(1) |
(78 | ) | (7,800 | ) | (257 | ) | ||||||
| Cumulative adjustment for FAS 143 (net of tax) |
(a | ) | 7,640 | — | — | |||||||
| Cumulative adjustment for FAS 133 (net of tax) |
(k | ) | — | — | (86 | ) | ||||||
| Profit/(loss) for the year under US GAAP |
7,562 | (7,800 | ) | (343 | ) | |||||||
| 2004 |
2003 |
2002 |
||||||||||
| (Restated) | (Restated) | (Restated) | ||||||||||
| Basic and diluted net earnings/(loss) per share under US GAAP |
|
1,256 | p | (1,296 | )p | (57 | )p | |||||
| Basic and diluted net earnings/(loss) per share under US GAAP—continuing operations |
|
(13 | )p | (1,305 | )p | (46 | )p | |||||
| Basic and diluted net earnings per share under US GAAP—discontinued operations |
|
— | 9 | p | 3 | p | ||||||
| Basic and diluted earning/(loss) per share before cumulative adjustments |
|
(13 | )p | (1,296 | )p | (43 | )p | |||||
| Basic and diluted earnings/(loss) per share arising from cumulative adjustment for FAS 143 (2002: FAS 133) |
|
1,269 | p | — | (14 | )p | ||||||
| 1,256 | p | (1,296 | )p | (57 | )p | |||||||
| (1) | Profit/(loss) for the financial year under US GAAP before cumulative adjustment is split between continuing operations of £(7,853) million and £(274) million and discontinued operations of £53 million and £17 million for the years ended March 31, 2003 and March 31, 2002 respectively. |
F-65
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Effect on Equity Shareholders’ Deficit of Differences Between UK GAAP and US GAAP
| Note | 2004 |
2003 |
|||||||
| £m | £m | ||||||||
| (Restated) | |||||||||
| Equity shareholders’ deficit under UK GAAP |
(3,257 | ) | (3,476 | ) | |||||
| US GAAP Adjustments: |
|||||||||
| Decommissioning costs |
(a | ) | 663 | (1,375 | ) | ||||
| Back end fuel costs |
(a | ) | 1,624 | (1,630 | ) | ||||
| Capitalization of interest |
(c | ) | 54 | 54 | |||||
| Bonds renegotiation |
(d | ) | 24 | 29 | |||||
| Employee share trusts |
(f | ) | (2 | ) | (2 | ) | |||
| Capitalization of Bruce costs |
(g | ) | (16 | ) | (16 | ) | |||
| Pension costs |
(h | ) | (215 | ) | (215 | ) | |||
| Investment in joint venture |
(i | ) | 175 | 33 | |||||
| Disposal of joint venture and Bruce Power |
(j | ) | (128 | ) | 29 | ||||
| FAS 133 adjustments |
(k | ) | (87 | ) | 3 | ||||
| Fixed asset impairment adjustments |
(l | ) | (196 | ) | (2,642 | ) | |||
| Adjustment for Bruce Power lease |
(m | ) | (22 | ) | (22 | ) | |||
| Deferred income tax |
(n | ) | 375 | (1,739 | ) | ||||
| Tax effect of US GAAP adjustments |
(554 | ) | 1,739 | ||||||
| Deficit on Equity shareholders’ funds under US GAAP |
(1,562 | ) | (9,230 | ) | |||||
Reconciliation of movement in deficit on equity shareholders’ funds under US GAAP
| 2004 |
2003 |
|||||
| £m | £m | |||||
| (Restated) | ||||||
| As at April 1, 2003 |
(9,230 | ) | (1,145 | ) | ||
| Profit/(loss) for the year under US GAAP |
7,562 | (7,800 | ) | |||
| Dividends under US GAAP |
— | (32 | ) | |||
| Cumulative translation adjustments |
(15 | ) | (25 | ) | ||
| Other comprehensive income—FAS 133 |
— | 21 | ||||
| Additional minimum pension liability |
34 | (249 | ) | |||
| Unrealized gain on available-for-sale securities |
87 | — | ||||
| As at March 31, 2004 |
(1,562 | ) | (9,230 | ) | ||
F-66
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The cumulative effect of the differences between UK GAAP and US GAAP on the consolidated balance sheets of the Group at March 31, 2004 and 2003 is set out in the following summarized US GAAP balance sheet information:
| As at March 31, 2004 |
As at March 31, 2003 |
|||||
| £m | £m | |||||
| (Restated) | ||||||
| Assets |
||||||
| Current Assets |
943 | 736 | ||||
| Property, Plant and Equipment |
1,166 | 997 | ||||
| Deferred Debits and Other Assets |
444 | 442 | ||||
| Total Assets |
2,553 | 2,175 | ||||
| Liabilities and Shareholders’ Equity |
||||||
| Current Liabilities |
1,525 | 1,190 | ||||
| Long-term Debt |
662 | 702 | ||||
| Deferred Credits and Other Liabilities |
1,835 | 9,420 | ||||
| Shareholders’ Equity |
(1,469 | ) | (9,137 | ) | ||
| Total Liabilities and Shareholders’ Equity |
2,553 | 2,175 | ||||
(ii) Restatement of Results
Year ended March 31, 2004
We adopted Statement of Financial Accounting Standards No.143, Accounting for Asset Retirement Obligations (“FAS 143”) as of April 1, 2003.
We determined that application of Statement of Financial Accounting Standards No. 109 Accounting for Income Taxes (“FAS 109”) as a result of our adoption of FAS 143 did not appropriately record the tax impact for the year ended March 31, 2004. Consequently, we have restated our 2004 consolidated financial statements in accordance with U.S. GAAP to reflect the correct allocation of income tax expense/benefit between income from continuing operations and the cumulative effect of a change in accounting as of April 1, 2004. These changes are reflected below and labeled “Restated” in the section “Decommissioning Costs and Back End Fuel Costs” which is our discussion on the adoption of FAS 143.
| March 31, 2004 | ||||||||||||||||
| As previously reported |
Impact of Restatement |
As restated | ||||||||||||||
| £m |
Earnings per share |
£m |
Earnings per share |
£m |
Earnings per share | |||||||||||
| Profit/(loss) under US GAAP before cumulative adjustment for FAS 143 |
2,023 | 336p | (2,101 | ) | (349 | )p | (78 | ) | (13)p | |||||||
| Cumulative adjustment for FAS 143 (net of tax) |
5,539 | 920p | 2,101 | 349 | p | 7,640 | 1,269 p | |||||||||
| Profit/(loss) under US GAAP for the year |
7,562 | 1,256p | — | — | 7,562 | 1,256 p | ||||||||||
| Deficit on equity shareholders’ funds under US GAAP |
(1,562 | ) | — | — | — | (1,562 | ) | — | ||||||||
F-67
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Years ended March 31, 2003 and March 31, 2002
We adopted Statement of Financial Accounting Standards (“FAS”) 133—“Accounting for Derivative and Hedging Activities”, as amended—(‘FAS 133’), as of April 1, 2001.
Upon adoption of FAS 133, we identified certain electricity purchase and sale contracts as being derivatives in accordance with FAS 133. For the years ended March 31, 2002 and 2003 certain of these contracts were not included in the annual mark to market calculations on the basis that they qualified for the Normal Purchase Normal Sale (“NPNS”) scope exemption.
During the year ended March 31, 2004 we adopted FAS 149—“Accounting for Derivative and Hedging Activities”. As part of the process of implementing FAS 149 we conducted a broader review of our compliance with derivative accounting regulation. During this exercise, the Group determined that the analysis supporting NPNS, and the documentation of compliance with the requirements of FAS 133 was not sufficient to support the accounting method previously applied. As a result of the review we determined that it was necessary to restate the results for 2002 and 2003. The impact of the restatement on the US GAAP financial statements is as follows:
| March 31, 2003 |
March 31, 2002 |
||||||||||||||||||||||||||||||||||
| As previously reported |
Impact of Restatement |
As restated |
As previously reported |
Impact of Restatement |
As restated |
||||||||||||||||||||||||||||||
| £m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
£m | Earnings per share |
||||||||||||||||||||||||
| US GAAP net loss (net of tax) before cumulative adjustment for FAS 133 |
(7,732 | ) | (1,284 | )p | (68 | ) | (12 | )p | (7,800 | ) | (1,296 | )p | (337 | ) | (56 | )p | 80 | 13p | (257 | ) | (43 | )p | |||||||||||||
| Cumulative adjustment for FAS 133 (net of tax) |
— | — | — | — | — | — | (89 | ) | (15 | )p | 3 | 1p | (86 | ) | (14 | )p | |||||||||||||||||||
| Loss for the year under US GAAP |
(7,732 | ) | (1,284 | )p | (68 | ) | (12 | )p | (7,800 | ) | (1,296 | )p | (426 | ) | (71 | )p | 83 | 14p | (343 | ) | (57 | )p | |||||||||||||
| Tax Effect of US GAAP adjustments |
959 | — | 31 | — | 990 | — | 65 | — | (35 | ) | — | 30 | — | ||||||||||||||||||||||
| Deficit on equity shareholders’ funds under US GAAP |
(9,245 | ) | — | 15 | — | (9,230 | ) | — | (1,228 | ) | — | 83 | — | (1,145 | ) | — | |||||||||||||||||||
(iii) Notes on US GAAP Adjustments
(a) Decommissioning Costs and Back End Fuel Costs (Restated)
Effective April 1, 2003, the Group changed its method of accounting for asset retirement obligations upon adoption of FAS 143—“Accounting for Asset Retirement Obligations”. The adoption of FAS 143 has an impact on the way the Group has accounted for decommissioning costs and contracted and uncontracted back end fuel costs. The impact of adopting FAS 143 on these specific liabilities is discussed in greater detail below.
Under the new accounting method, the Group determines the fair value of the asset retirement obligation by discounting the expected future cash flows at the credit adjusted risk free rate effective at the date of adoption. Upon adoption of FAS 143, an asset retirement cost is capitalized by increasing
F-68
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
the carrying amount of the related long-lived asset. For the purposes of calculating its asset retirement obligation under FAS 143, the Group has used a long-term real rate of interest of 12.2% per annum which is equivalent to its credit adjusted risk free rate. The charge to the profit and loss account under US GAAP reflects the accretion of the asset retirement obligation and the depreciation of the asset retirement cost.
As noted in (ii), during the preparation of our financial statements and our annual report on Form 20-F for the year ended March 31, 2005, we determined that the allocation of income tax expense/benefit between income for continuing activities and the cumulative effect of a change in accounting policy as of April 1, 2004 was incorrect.
The cumulative effect of the change on prior years resulted in a credit to income of £7,640m (net of taxes of £273m) (as restated), which is included in the reconciliation of profit and loss between UK GAAP and US GAAP for the year ended March 31, 2004.
The following table illustrates the component values of the cumulative effect and related tax for year ended March 31, 2004:
| Decommissioning |
Back End Fuel |
Total |
|||||||
| £m | £m | £m | |||||||
| (Restated) | (Restated) | (Restated) | |||||||
| Cumulative adjustment |
4,696 | 3,217 | 7,913 | ||||||
| Tax |
(162 | ) | (111 | ) | (273 | ) | |||
| Cumulative adjustment net of tax |
4,534 | 3,106 | 7,640 | ||||||
Had FAS 143 been adopted on April 1, 2002, the asset retirement obligation would have been as follows:
| March 31, 2004 |
March 31, 2003 |
April 1, 2002 | ||||
| £m | £m | £m | ||||
| Decommissioning costs |
301 | 263 | 228 | |||
| Back end fuel costs |
1,722 | 1,530 | 1,379 | |||
| Total asset retirement obligation |
2,023 | 1,793 | 1,607 | |||
The following table sets out net (loss)/income, adjusted as if FAS 143 had been applied effective April 1, 2001:
| 2003 |
2002 |
|||||
| £m | £m | |||||
| (Restated) | (Restated) | |||||
| Reported (loss) before adopting FAS 143 |
(7,800 | ) | (343 | ) | ||
| Earnings effect of adopting FAS 143 |
3,140 | 455 | ||||
| Pro forma net (loss)/income |
(4,660 | ) | 112 | |||
| Pro forma basic and diluted (loss)/net earnings per share under US GAAP |
(774 | )p | 19 | p | ||
The asset retirement obligation is adjusted each period for any liabilities incurred during the period, accretion expense and any revisions made to the estimated cash flows.
F-69
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The following table illustrates the reconciliation of the asset retirement obligation liability for the year ended March 31, 2004:
| Decommissioning |
Back End Fuel |
Total |
||||||
| £m | £m | £m | ||||||
| Balance as at April 1, 2003 |
263 | 1,530 | 1,793 | |||||
| Liabilities incurred during the year |
— | 46 | 46 | |||||
| Liabilities settled during the year |
— | (60 | ) | (60 | ) | |||
| Accretion expense |
38 | 206 | 244 | |||||
| Balance as at March 31, 2004 |
301 | 1,722 | 2,023 | |||||
The previous accounting treatment, the impact of FAS 143 and the differences between UK GAAP and US GAAP are considered for decommissioning costs and back end fuel costs below.
Decommissioning Costs
The estimated costs of decommissioning the Group’s power stations are provided for when stations begin operating commercially and are capitalized as part of the costs of construction and are depreciated over the same lives as the stations. Under UK GAAP these estimated costs are initially recorded in the balance sheet at current prices and discounted at a long-term real rate of interest of 3% per annum to take account of the time scale whereby the work will take place many years after station closure (this equates to a present value calculated by assuming an inflation rate of 2.1% and a risk free discount rate of 5.2%). In each subsequent year, the provision is revalorized to reflect the movement in current price levels and the unwinding of one year’s discount. This revalorization is classified as a financing charge in the UK GAAP income statement.
Under US GAAP, prior to the adoption of FAS 143, liabilities in respect of decommissioning were recognized on an undiscounted basis and the annual movement in current price levels was capitalized each year. Following the adoption of FAS 143, the decommissioning liabilities are discounted at a credit adjusted risk free rate of return, which results in a higher discount rate under US GAAP than that applied under UK GAAP.
The higher discount factor adopted for US GAAP results in a lower decommissioning liability as at March 31, 2004 than that reported for UK GAAP purposes. The lower liability has also resulted in a lower accretion charge for the year under US GAAP.
F-70
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The difference between UK GAAP and US GAAP relating to decommissioning costs is analyzed below, showing the effect on separate line items in each year and the impact of the adoption of FAS 143.
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Balance Sheet |
||||||
| Fixed assets |
||||||
| Cost |
4,913 | 4,913 | ||||
| Cumulative adjustment for FAS 143 |
(5,202 | ) | — | |||
| Total difference in cost between UK GAAP and US GAAP |
(289 | ) | 4,913 | |||
| Depreciation |
(2,326 | ) | (2,326 | ) | ||
| Cumulative adjustment for FAS 143 |
2,531 | — | ||||
| Total difference in depreciation between UK GAAP and US GAAP |
205 | (2,326 | ) | |||
| Total difference in net book value between UK GAAP and US GAAP (before impairment charge see note (l)) |
(84 | ) | 2,587 | |||
| Decommissioning liability |
(3,949 | ) | (3,962 | ) | ||
| Cumulative adjustment for FAS 143 |
4,696 | — | ||||
| Total difference in decommissioning liability between UK GAAP and US GAAP |
747 | (3,962 | ) | |||
| Total shareholders’ funds adjustment |
663 | (1,375 | ) | |||
| 2004 |
2003 |
2002 |
||||||
| £m | £m | £m | ||||||
| US GAAP adjustments to Profit and Loss Account |
||||||||
| Depreciation expense of undiscounted decommissioning costs |
— | (127 | ) | (199 | ) | |||
| Accretion of decommissioning liability |
13 | 57 | 48 | |||||
| Total profit and loss adjustment |
13 | (70 | ) | (151 | ) | |||
Back End Fuel Costs
Back end fuel costs comprise the estimated costs of reprocessing and storage of spent nuclear fuel and the long-term storage, treatment and eventual disposal of resulting waste products. The vast majority of these costs relate to reprocessing, treatment and storage services that are the subject of contracts with BNFL. The other costs, which are not subject to fixed contractual arrangements, primarily represent estimated disposal costs and are based on long-term cost forecasts which are regularly reviewed and adjusted where necessary.
Under UK GAAP, both contracted and uncontracted back end fuel cost liabilities are recorded in the balance sheet at current price levels and discounted at a real rate of interest of 3% per annum to take account of the timing of payments (this equates to a present value calculated by assuming an inflation rate of 2.1% and a risk free discount rate of 5.2%).
Under US GAAP, prior to the adoption of FAS 143, uncontracted back end fuel liabilities were recognized on an undiscounted basis, because the precise amount and timing of the related payments are not fixed or reliably determinable. This difference in methodology between UK GAAP and US
F-71
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
GAAP resulted in significant adjustments to the profit and loss account and shareholders’ funds under US GAAP. Previously, the Group treated contracted back end fuel liabilities using the same methodology for both US GAAP and UK GAAP.
Upon adoption of FAS 143, both contracted and uncontracted back end fuel liabilities are discounted at the Group’s credit adjusted risk free rate under US GAAP. As such, there is a difference between UK GAAP and US GAAP for both contracted and uncontracted back end fuel liabilities as a result of the difference in the discount factor used. The tables below reconcile the shareholders’ funds adjustment and analyzes the effect on profit before tax of differences between UK GAAP and US GAAP with regard to contracted and uncontracted back-end fuel costs.
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Back end fuel liability—UK GAAP |
3,176 | 2,941 | ||||
| Back end fuel liability (net)—US GAAP |
(1,552 | ) | (4,571 | ) | ||
| Total shareholders’ funds adjustment |
1,624 | (1,630 | ) | |||
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Adjustments from UK to US GAAP |
37 | (450 | ) | (155 | ) | ||||
| US GAAP Adjustments: |
|||||||||
| Back-end fuel costs |
130 | (460 | ) | (150 | ) | ||||
| Reclassifications |
— | 32 | — | ||||||
| Amortization |
(51 | ) | — | — | |||||
| Revalorization of back-end fuel costs |
(42 | ) | (22 | ) | (5 | ) | |||
| Back-end fuel costs |
37 | (450 | ) | (155 | ) | ||||
(b) Decommissioning Fund
The amount of the Group’s decommissioning fund as recorded in its UK GAAP balance sheet represents the contributions made by the Group, together with an estimated actuarially determined long-term rate of return on the fund. The change in amount arising from applying the estimated long-term rate of return is taken to the profit and loss account and disclosed as part of revalorization. See note 2(xvii). If the actuarial value exceeds the market value of the investment in the fund then the decommissioning fund is stated at the lower amount.
Under US GAAP, the debt and equity securities held by the Group’s independently administered decommissioning fund are classified as “available-for-sale” securities within Investments (non-current) and stated at market value. Under UK GAAP there was an exceptional credit of £59m made in the year ended March 31, 2004 (2003: charge of £124m) to write up (2003: down) the carrying value of the investments to market value. Consequently there is no difference in the carrying amount of these investments between UK GAAP and US GAAP in the year ended March 31, 2004 or March 31, 2003.
In accordance with FAS 115, “Accounting for Certain Investments in Debt and Equity Securities”, these securities are reported at their estimated fair value of £440m as of March 31, 2004 and £334m as of March 31, 2003 in the Group’s Consolidated Balance Sheet under “Decommissioning Fund”. Realized gains and losses from these securities are included in profit. Unrealized gains and losses are
F-72
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
excluded from profit until realized and reported as a separate component of equity shareholders’ funds unless the unrealized loss is deemed to be “other-than-temporary”. At March 31, 2003 the decline in value was deemed to be “other-than-temporary” by the Directors, and a charge of £94m was recorded in the profit and loss account for US GAAP. This charge represented the sum of the exceptional and revalorization charge recorded for UK GAAP in the year ended March 31, 2003.
Information on investments in securities held by the decommissioning fund by major security type (in millions):
| March 31, 2004 |
March 31, 2003 | ||||||||||||||||||||
| Gross gains/(losses) (£m) |
Gross gains/(losses) (£m) | ||||||||||||||||||||
| Cost |
Unrealized Gain |
Unrealized Loss |
Fair value |
Cost |
Unrealized Gain |
Unrealized Loss |
Realized Loss |
Fair value | |||||||||||||
| UK equities |
173 | 53 | (9 | ) | 217 | 225 | 8 | (4 | ) | (62 | ) | 167 | |||||||||
| Non-UK equities |
100 | 36 | (2 | ) | 134 | 123 | 8 | (2 | ) | (30 | ) | 99 | |||||||||
| Index linked gilts |
38 | 5 | — | 43 | 23 | 3 | (1 | ) | — | 25 | |||||||||||
| Property |
42 | 5 | (1 | ) | 46 | 43 | 2 | — | (2 | ) | 43 | ||||||||||
| 353 | 99 | (12 | ) | 440 | 414 | 21 | (7 | ) | (94 | ) | 334 | ||||||||||
Using the specific identification method to determine cost, the gross realized gains and losses were:
| 2004 |
2003 |
||||
| £m | £m | ||||
| Gross realized losses |
— | (94 | ) | ||
| — | (94 | ) | |||
Proceeds from sales of available-for-sale securities were £40m and £69m during the years ended March 31, 2004 and 2003 respectively. These proceeds were not withdrawn from the fund.
(c) Capitalization and Amortization of Capitalized Interest
Under UK GAAP, interest payable may be capitalized where borrowings are specifically financing the construction of a major capital project with a long period of development. Up until April 1, 2001 British Energy had elected not to capitalize interest. US GAAP requires that interest incurred on borrowings, which could have been avoided if the expenditure on the asset had not been made must be included in tangible fixed assets and depreciated over the lives of the related assets. For US GAAP purposes the amount of interest capitalized is determined by reference to average interest rates on outstanding long-term borrowings. As a result of the impairment review performed in 2003 the interest capitalized under US GAAP was fully impaired. Under US GAAP, the gross amount of capitalized interest is £2,037m (2003: £2,037m), the total accumulated depreciation is £1,983m (2003: £1,983m). An additional £54m of capitalized interest was included in the fixed asset impairment charge at March 31, 2003.
F-73
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
(d) Bonds Renegotiation
Under UK GAAP, gains and losses on linked transactions should be recognized only where justified by a change in the substance of the entity’s assets and liabilities. The Group concluded that the repurchase and sale of bonds constituted two distinct transactions that caused a significant change in the substance of its commitments due to the increase in the bond principal and changes in underlying covenants.
For US GAAP purposes, only gains and losses arising from an exchange of debt instruments with a substantially different economic substance should be recognized. A modification of debt is considered substantially different if the present value of the cash flows under the terms of the new debt instrument differ by at least ten percent from the present value of the remaining cash flows under the terms of the original instrument. The renegotiation occurred immediately before March 31, 1999. The increase in principal of £66m is amortized, on a weighted average basis, over the life of the bonds.
(e) Employee Stock Compensation Schemes
The Group has three stock compensation schemes—a ShareSave Scheme, an Employee Share Scheme and an Executive Share Option Scheme. Under UK GAAP, the ShareSave Scheme is specifically exempt by the Inland Revenue from the requirement to recognize compensation cost. For the Employee Share Scheme and the Executive Share Option Scheme, the total compensation charge is recognized as the difference between the cost of the shares and the price at which the options can be exercised. This charge is amortized over the period from the grant date to the earliest date of exercise. No options were granted under any of the schemes during the period.
Under US GAAP, the Group has elected to account for its stock compensation schemes in accordance with FAS 123—“Accounting for Stock-Based Compensation” using the Black-Scholes option-pricing model, under which a fair value is calculated for the share option schemes as at the date of grant of the options. This fair value, less amounts to be contributed by employees is charged to the profit and loss account over the period from the date the options were granted to the date at which the options are expected to vest to the employees. The corresponding credit is included in Shareholders’ Funds. The additional amount recognized in income under US GAAP as compensation expense for the period was £nil (2003: £nil, 2002: £4m) A reconciliation of the options outstanding is as follows:
| ShareSave Scheme |
Employee Share Scheme |
Executive Share Option Schemes | ||||||||||||||||
| Number of Shares |
Weighted Average Exercise Price per Share |
Number of Shares |
Weighted Average Exercise Price per Share |
Number of Shares |
Weighted Average Exercise Price per Share | |||||||||||||
| Outstanding March 31, 2001 |
21,850,582 | £ | 1.63 | 16,906,495 | £ | 3.99 | 6,278,104 | £ | 3.30 | |||||||||
| Options granted |
7,376,968 | £ | 2.45 | — | — | 125,786 | £ | 3.18 | ||||||||||
| Options exercised |
(8,818,218 | ) | £ | 1.60 | (647,282 | ) | £ | 2.60 | (61,538 | ) | £ | 2.60 | ||||||
| Options forfeited |
(1,079,866 | ) | £ | 2.52 | (869,210 | ) | £ | 4.35 | (1,221,004 | ) | £ | 3.53 | ||||||
| Outstanding March 31, 2002 |
19,329,466 | £ | 1.89 | 15,390,003 | £ | 4.03 | 5,121,348 | £ | 3.25 | |||||||||
| Options granted |
9,194,761 | £ | 1.36 | — | — | — | — | |||||||||||
| Options exercised |
(13,348 | ) | £ | 1.36 | — | — | — | — | ||||||||||
| Options forfeited |
(9,437,499 | ) | £ | 2.13 | (512,400 | ) | £ | 4.04 | (1,139,165 | ) | £ | 3.22 | ||||||
F-74
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
| ShareSave Scheme |
Employee Share Scheme |
Executive Share Option Schemes | ||||||||||||||||
| Number of Shares |
Weighted Average Exercise Price per Share |
Number of Shares |
Weighted Average Exercise Price per Share |
Number of Shares |
Weighted Average Exercise Price per Share | |||||||||||||
| Outstanding March 31, 2003 |
19,073,380 | £ | 1.52 | 14,877,603 | £ | 4.03 | 3,982,183 | £ | 3.26 | |||||||||
| Options granted |
— | — | — | — | — | — | ||||||||||||
| Options exercised |
— | — | — | — | — | — | ||||||||||||
| Options forfeited |
(10,554,884 | ) | £ | 1.51 | (340,599 | ) | £ | 4.08 | (361,935 | ) | £ | 3.25 | ||||||
| Outstanding March 31, 2004 |
8,518,496 | £ | 1.52 | 14,537,004 | £ | 4.03 | 3,620,248 | £ | 3.26 | |||||||||
Of the options outstanding, 18,097,701 were exercisable as at March 31, 2004 (2003: 17,097,248, 2002: 13,401,538)
At March 31, 2004 the option groups outstanding, based on a range of exercise prices, were as follows:
| Option Groups Outstanding | |||||||
| Number Outstanding |
Weighted Average Remaining Contractual Life (Years) |
Weighted Average Exercise Price | |||||
| ShareSave Scheme |
|||||||
| £1.36 to £2.29 |
7,568,229 | 2.6 | £ | 1.36 | |||
| £2.30 to £4.44 |
950,267 | 1.8 | £ | 2.80 | |||
| Employee Share Scheme |
|||||||
| £2.60 to £4.07 |
6,282,958 | 3.3 | £ | 2.60 | |||
| £4.08 to £5.29 |
8,254,046 | 4.7 | £ | 5.12 | |||
| Executive Share Option Schemes |
|||||||
| £2.41 to £3.17 |
2,478,144 | 3.0 | £ | 2.49 | |||
| £3.18 to £5.08 |
642,070 | 2.4 | £ | 4.59 | |||
| £5.09 to £6.67 |
500,034 | 2.4 | £ | 5.35 | |||
Using the Black-Scholes option-pricing model, the weighted average fair values on the date the options were granted were as follows:
| ShareSave Scheme |
Employee Share Scheme |
Executive Share Option Schemes | ||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 | |||||||
| £ | £ | £ | £ | £ | £ | |||||||
| Weighted average fair value of those options for which the exercise price: |
||||||||||||
| —exceeded market price on date of grant |
— | 0.27 | — | — | — | — | ||||||
F-75
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The following assumptions were used in the Black-Scholes option-pricing model:
| ShareSave Scheme |
Employee Share Scheme |
Executive Share Option Schemes | |||||||||||
| 2004 |
2003 |
2004 |
2003 |
2004 |
2003 | ||||||||
| Risk free interest rate |
— | 4.5-4.7 | % | — | — | — | — | ||||||
| Expected dividend yield |
— | 5.7 | % | — | — | — | — | ||||||
| Expected volatility |
— | 55 | % | — | — | — | — | ||||||
| Expected life (years) |
— | 3.1-5.1 | — | — | — | — | |||||||
The risk free rate is the yield on the date of grant of an UK government bond with the closest maturity to the expected term of the option.
(f) Employee Share Trusts
Under UK GAAP, the Company’s shares held in Employee Share Trusts are classified as “own shares” within fixed assets. The cost of these shares to the Employee Share Trusts is subsequently written down to the amount expected to be received from employees over the period at the end of which the underlying options are exercisable by the employees. Under US GAAP, the issuance or sale of the Company’s shares to the Employee Share Trusts is recorded as a debit balance within equity shareholders’ funds. This account is subsequently credited as options are exercised, based on the cost of the shares to the Employee Share Trusts.
In 2002/03 as the long-term prospects of the Company had deteriorated considerably, a charge of £102m was recorded under UK GAAP to recognize a permanent diminution in the value of the shares held. Therefore, for US GAAP purposes this amortization and impairment were reversed.
(g) Capitalization of Bruce Costs
UK GAAP allows for certain direct and indirect costs attributable to bringing an asset into working condition to be capitalized. Such costs would be written off over the estimated useful life of the associated asset. Certain of these costs would not be permitted to be capitalized under US GAAP and would be expensed as incurred. British Energy disposed of its interests in Bruce Power on February 14, 2003.
(h) Pension Costs
Under UK GAAP, the cost of providing pension benefits is expensed over the average expected service lives of eligible employees in accordance with the provisions of Statement of Standard Accounting Practice (SSAP) 24, which aims to produce an estimate of cost based on long-term actuarial assumptions. Variations from the regular pension cost arising from, for example, experience deficiencies or surpluses, are charged or credited to the income statement over the expected average remaining service lives of current employees in the schemes.
Under US GAAP, employee pension costs are recognized in accordance with FAS 87—“Employers’ Accounting for Pensions”. FAS 87 requires the use of an actuarial method for determining defined benefit pension costs and provides for the deferral of actuarial gains and losses (in excess of a specified corridor) that result from changes in assumptions or actual experience differing from that assumed. FAS 87 also provides for the prospective amortization of costs related to changes in the benefit plan, as well as the obligation resulting from the transition. US GAAP also requires disclosure of the components of periodic pension cost and the funded status of the pension plans.
F-76
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The following analysis sets out the disclosures applicable to continued and discontinued operations. The discontinued operations amounts in 2003 relate to Bruce Power (which was sold on February 14, 2003) and are set out on a 100% holding basis. British Energy’s share in Bruce Power was 82.4% prior to disposal.
| 2004 |
2003 |
|||||||||||
| Discontinued Canadian Operations |
Continued Operations |
Total |
||||||||||
| £m | £m | £m | £m | |||||||||
| Change in benefit obligation: |
||||||||||||
| Projected benefit obligation at beginning of year |
1,905 | 402 | 1,821 | 2,223 | ||||||||
| Foreign exchange movement |
— | (42 | ) | — | (42 | ) | ||||||
| Service cost |
34 | 13 | 28 | 41 | ||||||||
| Interest cost |
103 | 22 | 107 | 129 | ||||||||
| Contributions by plan participants |
10 | 4 | 10 | 14 | ||||||||
| FAS 88 termination cost |
1 | — | 13 | 13 | ||||||||
| Net actuarial loss |
200 | — | 6 | 6 | ||||||||
| Benefits paid |
(81 | ) | (1 | ) | (80 | ) | (81 | ) | ||||
| Settlement of benefit obligation |
— | (398 | ) | — | (398 | ) | ||||||
| Benefit obligation at end of year |
2,172 | — | 1,905 | 1,905 | ||||||||
| Change in plan assets: |
||||||||||||
| Fair value of plan assets at beginning of year |
1,525 | 423 | 1,842 | 2,265 | ||||||||
| Foreign exchange movement |
— | (44 | ) | — | (44 | ) | ||||||
| Actual return on plan assets |
334 | (24 | ) | (278 | ) | (302 | ) | |||||
| Employer contributions |
34 | — | 31 | 31 | ||||||||
| Non participants contributions |
10 | 4 | 10 | 14 | ||||||||
| Benefits paid |
(81 | ) | (1 | ) | (80 | ) | (81 | ) | ||||
| Settlement of plan asset |
— | (358 | ) | — | (358 | ) | ||||||
| Fair value of plan assets at end of year |
1,822 | — | 1,525 | 1,525 | ||||||||
| Net pension liability recognized: |
||||||||||||
| Funded status |
(350 | ) | — | (380 | ) | (380 | ) | |||||
| Unrecognized transition asset |
(35 | ) | — | (46 | ) | (46 | ) | |||||
| Unrecognized prior service cost |
38 | — | 41 | 41 | ||||||||
| Unrecognized net actuarial loss |
548 | — | 600 | 600 | ||||||||
| Net amount recognized |
201 | — | 215 | 215 | ||||||||
| Additional minimum liability |
(346 | ) | — | (397 | ) | (397 | ) | |||||
| Net pension liability |
(145 | ) | — | (182 | ) | (182 | ) | |||||
| Net periodic pension cost: |
||||||||||||
| Service cost |
34 | 13 | 29 | 42 | ||||||||
| Interest cost |
103 | 22 | 107 | 129 | ||||||||
| Expected return on plan assets |
(105 | ) | (25 | ) | (131 | ) | (156 | ) | ||||
| Amortization of transition asset |
(12 | ) | — | (12 | ) | (12 | ) | |||||
| Amortization of prior service costs |
3 | — | 3 | 3 | ||||||||
| Amortization of actuarial loss |
24 | — | — | — | ||||||||
| Net periodic pension charge/(credit) |
47 | 10 | (4 | ) | 6 | |||||||
| FAS 88 termination cost—current year |
1 | 27 | 13 | 40 | ||||||||
| Net periodic pension cost |
48 | 37 | 9 | 46 | ||||||||
F-77
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The above FAS 88—“Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” cost refers to the cost of providing enhanced early retirement benefits to certain members following redundancy.
| 2004 |
2003 |
2002 | |||||
| % | % | % | |||||
| Assumptions used to determine benefit obligations and net periodic pension costs were as follows: |
|||||||
| UK |
|||||||
| Discount rate |
5.50 | % | 5.50% | 6.00% | |||
| Expected return on plan assets |
7.10 | % | 7.00% | 7.25% | |||
| Rate of compensation increase |
4.25 | % | 3.75% | 4.50% | |||
| Pension increases |
2.75 | % | 2.25% | 2.50% | |||
| Canada |
|||||||
| Discount rate |
— | 7.00% | 7.00% | ||||
| Expected return on plan assets |
— | 7.50% | 7.50% | ||||
| Rate of compensation increase |
— | 3.75% plus merit | 3.70% plus merit | ||||
| Pension increases |
— | 2.75% | 2.75% | ||||
Under US GAAP the cost of other post retirement benefits (excluding pension costs) are recognized in accordance with FAS 106—“Employers’ Accounting for Post Retirement Benefits other than Pensions”. FAS 106 requires the use of an actuarial method for determining other post retirement benefits. FAS 106 only applied to our Canadian operation which was sold on February 14, 2003. The disclosures required under US GAAP are set out below on a 100% holding basis. British Energy’s share of Bruce Power was 82.4% prior to disposal.
| 2004 |
2003 |
||||
| £m | £m | ||||
| Changes in benefit obligation |
|||||
| Bruce obligation transferred in |
— | 46 | |||
| Service costs |
— | 2 | |||
| Interest cost |
— | 3 | |||
| Amendments |
— | 7 | |||
| Settlement of benefit obligation |
— | (58 | ) | ||
| Benefit obligation at end of year |
— | — | |||
There were no plan assets during the period for the purposes of FAS 106.
The Group adopted FAS 132(R)—“Employers’ Disclosures about Pensions and Other Postretirement Plans” for the year ended March 31, 2004. The standard requires that more details are provided about plan assets, benefit obligations, cash flows, benefit cost and other relevant information. These additional disclosures are presented below.
Measurement and Valuation Method
The measurement date was March 31, 2004. The assets were valued using the market value method. The 10% corridor for amortising gains and losses has been utilized.
F-78
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Plan Assets
| 2004 |
2003 | |||||||
| Asset category |
Percentage of Plan assets |
Expected return On assets |
Percentage of Plan assets |
Expected return On assets | ||||
| % | % | % | % | |||||
| Equity securities |
61 | 8.25 | 58 | 8.5 | ||||
| Debt securities |
26 | 4.75 | 29 | 4.5 | ||||
| Real estate |
12 | 6.4 | 12 | 6.5 | ||||
| Other |
1 | 3.75 | 1 | 3.75 | ||||
| Total |
100 | 7.1 | 100 | 7.0 | ||||
The overall expected return on asset assumption is derived from the weighted average of the expected returns from each of the main asset classes at the beginning of the period. The expected return for each asset class represents a combination of historical performance analysis, forward looking views of the financial markets (suggested by the yields available) and the views of investment organisations.
Description of Investment Policies
The Trustees of the BEGG pension scheme, which makes up 98% of the total assets of the pension schemes, are responsible for the investment strategy of the Scheme, in consultation with the Company. The objective is to have sufficient assets, in normal market conditions, to meet the accrued benefits on an ongoing basis, as assessed by the Actuary to the Scheme. The Trustees have determined a long term benchmark which takes into account the relationship between the assets and liabilities in the Scheme, and is on the basis of approximately half of the assets being held in UK bonds, with the balance invested in long term higher return seeking assets such as equities and property. The Trustees believe this provides an adequate balance between maximising the return on the assets and minimising the risk of failing to meet the liabilities over the long term. The long term benchmark is being phased in gradually, with the timing being driven primarily by the relative movement between the yields on UK equities and bonds, with the aim of avoiding switching from equities into bonds in adverse market conditions. The assets are invested in a diversified range of asset classes and investment managers. A similar approach is adopted by the BECG, though the actual strategy differs as it takes into account the BECG liability profile.
Cashflows
| 2004 |
2003 | |||
| £m | £m | |||
| Employer’s contribution |
34 | 31 | ||
| Benefit payments |
81 | 80 |
The employer’s contributions estimated for the year ending March 31, 2005 is £33m.
Reconciliation of prepaid pension cost
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Prepaid pension cost at start of year (before adjustment to recognize minimum liability) |
215 | 193 | ||||
| Company net pension cost |
(48 | ) | (9 | ) | ||
| Company contributions |
34 | 31 | ||||
| Prepaid pension cost at end of year (before adjustment to recognize minimum liability) |
201 | 215 | ||||
F-79
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Accumulated Benefit Obligation, minimum liability, intangible asset and other comprehensive income
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Accumulated benefit obligation (ABO) |
1,967 | 1,707 | ||||
| Plan assets at market value |
1,822 | 1,525 | ||||
| Minimum liability (excess of ABO over market value of assets) |
145 | 182 | ||||
| Prepaid pension cost at end of year (before adjustment to recognize minimum liability) |
201 | 215 | ||||
| Additional minimum liability |
346 | 397 | ||||
| Intangible asset |
(38 | ) | (41 | ) | ||
| Accumulated Other Comprehensive Income |
308 | 356 | ||||
(i) Investment in Joint Venture
The management accounts of AmerGen are prepared on a US GAAP basis and these are translated into a UK GAAP basis when they are reported through to the Group for incorporation into the Group’s UK statutory accounts. There are a number of differences between US GAAP and UK GAAP, primarily relating to the acquisition of AmerGen nuclear power stations, and the valuation of decommissioning fund assets and decommissioning liabilities, including the adoption of FAS 143 for US GAAP purposes. These differences impact on reported income and the carrying values of its investment in AmerGen on the Group’s balance sheet.
(j) Disposal of Joint Venture and Bruce Power
The UK GAAP results for the year ended March 31, 2003 include a loss of £35m in respect of the disposal of our interests in Bruce Power and Huron Wind. However, the book value of the Bruce Power assets which were disposed of as recorded under US GAAP differed from the UK GAAP book value as a result of the accounting adjustments described in (g), (h), (k) and (m), and exclusion of a pension payment received after the balance sheet date which had been recorded in the UK GAAP results at March 31, 2003.
During the current year the Group disposed of its 50% interest in AmerGen. The cumulative effect of differences between UK GAAP and US GAAP as described at note (i) above has resulted in an additional loss on disposal for US GAAP purposes of £175m due to there being a higher carrying value of the investment in AmerGen under US GAAP. The remaining adjustment in 2003/04 relates to Bruce Power.
(k) FAS 133 Adjustments
The Group uses derivative instruments in the normal course of business to offset fluctuations in earnings and cash flows associated with movements in exchange rates, interest rates and commodity prices. As explained more fully in Note 2 (xix), energy trading financial derivatives and open positions on physical energy trading contracts are recognized as either assets or liabilities and are marked to market each reporting period using externally derived market prices under UK GAAP. Subsequent movements in their fair value are reflected in the profit and loss account. Interest rate swaps and forward rate agreements are not marked to market each reporting period. Rather profits and losses on such derivatives are reported in the profit and loss account in the period in which the underlying hedging transactions are completed. When an anticipated transaction is no longer likely to occur, any
F-80
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
deferred gain or loss that has arisen on the related derivative is recognized in the profit and loss account together with any gain or loss on the terminated item. FAS 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by FAS 137—“Accounting for Derivative Instruments and Hedging Activities—deferral of the effective date of FASB statement No. 133”, FAS 138—“Accounting for certain Derivative Instruments and certain Hedging Activities and FAS 149 (hereinafter referred to collectively as ‘FAS 133’) was adopted by the Group with effect from April 1, 2001. FAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities.
US GAAP requires that an entity recognize all derivatives as either assets or liabilities and measure those instruments at fair value each reporting period. US GAAP prescribes specific requirements for designation and documentation of hedging relationships and ongoing assessments of effectiveness in order to qualify for hedge accounting.
Derivative instruments are generally not held by the Company for speculative trading purposes. To the extent that such instruments are held for speculative trading purposes they are measured at fair value with gains and losses recorded in earnings. The fair value of trading derivatives at March 31, 2004 was £21m positive (2003: £9m positive).
In 2002/03 the remaining £21m of the cumulative effect of adopting FAS 133 at April 1, 2001 that was reported in other comprehensive income was recognized in earnings at March 31, 2003. This was due to the reduced term of the underlying debt and the resulting ineffectiveness of such interest rate swaps.
Certain contracts that meet the definition of derivative under FAS 133 may qualify as a normal purchase or a normal sale and be excluded from the scope of FAS 133. Specific criteria must be met in order for a contract that would otherwise be regarded as a derivative to qualify as a normal purchase or a normal sale. The Group has evaluated all commodity contracts to determine if they meet the definition of a derivative and qualify as a normal purchase or a normal sale. The Group also evaluates contracts for “embedded” derivatives, and considers whether any embedded derivatives have to be separated from the underlying host contract and accounted for separately in accordance with FAS 133 requirements. Where embedded derivatives have terms that are not clearly and closely related to the terms of the host contract in which they are included, they are accounted for separately from the host contract as derivatives, with changes in the fair value recorded in earnings, to the extent that the hybrid instrument is not already accounted for at fair value. As noted in note (ii), during the year ended March 31, 2004 management conducted a broad review of the Group’s compliance with derivative accounting regulations. During this exercise, the Group determined that the analysis supporting NPNS, and the documentation of compliance with the requirements of FAS 133 to claim the election was not sufficient to support the accounting method previously applied.
(l) Fixed Asset Impairment Adjustments
In the March 31, 2004 UK GAAP accounts the Directors reassessed the carrying value of fixed assets compared with the economic value and net realizable value of those assets. In carrying out the economic valuations, significant estimates were made of the future cash flows being generated by the assets, taking into account current and expected future market conditions and the expected lives of the Group’s power stations. The actual outcome can vary significantly from these future forecasts, thereby affecting the Group’s assessment of expected future cash flows. The expected future cash flows were discounted at a rate approximating the Group’s weighted average cost of capital as this is the rate
F-81
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
most representative of those assets. The assessment resulted in the value of the power stations being written up by £295 million (2003: written down by £3,738 million) for UK GAAP reported results.
The Directors have also performed an impairment review of the Group’s fixed assets under US GAAP, using consistent assumptions and estimates as those used for purposes of the impairment review under UK GAAP. However under US GAAP, fixed assets are written down to their fair value only when their carrying value exceeds their undiscounted future cash flows. In the current year the US GAAP impairment test indicated that the carrying value of the Group’s power stations did not exceed their undiscounted future cash flows. The Group did not reverse any previous year impairment charges as this is not permitted under US GAAP. The additional US GAAP impairment charge in 2003 was due to the different treatment of certain plant costs, such as capitalized interest and decommissioning. Significant estimates are made when performing an impairment review. A change in any estimates of the future cash flows or in the method of determining the fair value of the Group’s power stations could result in a different impairment charge.
Upon adoption of FAS 143 at April 1, 2004, approximately £2,671m of the US GAAP impairment charge recorded at March 31, 2003 was reversed and credited to the 2004 profit and loss account. This amount represents the reversal of the historical impairment charge taken prior to adoption of FAS 143 on the undiscounted asset retirement cost. In accordance with the FAS 143 transition provisions, this amount was credited to the current year profit and loss account as part of the cumulative effect of the change in accounting principle.
In addition, following the asset impairment review at March 31, 2003, no additions were recorded to fixed assets in the period under UK GAAP. As a consequence, the Group expensed £70m to the profit and loss account for the year ended March 31, 2004 that may have been capitalized in the absence of the impairment review. The Directors have assessed this expenditure under US GAAP and have concluded that the expenditure benefits future periods by extending the useful life and/or productivity of the assets concerned. This has resulted in fixed asset additions in the period of £70m under US GAAP.
In the March 31, 2002 UK GAAP accounts, following a review of the economic values and net realizable value of the Group’s assets compared with their carrying value in the accounts, Eggborough power station was written down by £300m for UK GAAP purposes. Under US GAAP the economic value must be compared with carrying value on an undiscounted basis in order to be impaired. As a result the Eggborough power station was not impaired on a US GAAP basis and the write down was reversed for the purposes of arriving at US GAAP profit and net assets.
(m) Adjustment for Bruce Power Lease
Under UK GAAP the Bruce Power lease is treated as an operating lease. As a result the lease is not capitalized in the Group balance sheet and the lease obligations are not recognized as a liability in the balance sheet. Rental payments are charged in the period to which they relate. Under US GAAP the lease is treated as a capital lease with interest and depreciation charges being recognized in the Group profit and loss account. British Energy disposed of its interests in Bruce Power on February 14, 2003.
(n) Deferred Income Taxation
British Energy has applied the discounting provision of the UK’s accounting standard on deferred tax reporting. This means that the amount provided is less than the full potential deferred tax liability or asset on an undiscounted basis. Deferred tax assets are recognized under UK GAAP only when they are expected to be recoverable within the foreseeable future.
F-82
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Under US GAAP, deferred tax is provided for on a full liability basis. Deferred tax assets or liabilities are recognized for all differences between the financial and tax bases of assets and liabilities, and for tax losses carried forward at the statutory rate at which they are expected to be utilized. Valuation allowances are provided against deferred tax assets to the extent that it is considered more likely than not that some or all of the deferred tax asset will not be realized.
Loss before tax under US GAAP is calculated as follows at March 31:
| 2004 |
2003 |
|||||
| £m | £m | |||||
| (Restated) | ||||||
| Profit/(loss) before tax under UK GAAP |
234 | (3,941 | ) | |||
| Effect of US GAAP adjustments |
(420 | ) | (3,429 | ) | ||
| Loss before tax under US GAAP |
(186 | ) | (7,370 | ) | ||
The provision for income taxes under US GAAP is calculated as follows:
| 2004 |
2003 |
|||||
| £m | £m | |||||
| (Restated) | (Restated) | |||||
| Deferred tax provision under UK GAAP |
— | — | ||||
| Adjustment under full provision method |
(375 | ) | (362 | ) | ||
| Tax effect of US GAAP adjustments |
2,655 | (1,739 | ) | |||
| Valuation allowance |
(2,101 | ) | 2,101 | |||
| Deferred tax provision under US GAAP |
179 | — | ||||
There is a current income tax credit for the year ended March 31, 2004 of £2m and a charge of £18m in the year ended March 31, 2003. There are UK tax losses carried forward of £1,162m and £874m at March 31, 2004 and 2003 respectively, giving rise to potential undiscounted deferred tax assets of £348m and £262m. The discounted deferred tax assets under UK GAAP of £291m and £150m at March 31, 2004 and 2003 respectively, have not been recognized for US GAAP purposes. There was no utilization of losses in either year. There is a deferred tax liability under US GAAP of £179m and £nil at March 31, 2004 and 2003 respectively. The full amount of the deferred tax provision in 2004 relates to continuing activities. There are no overseas tax losses brought forward or carried forward.
The components of the net deferred tax liability, valued at the enacted UK tax rate of 30% (2003—30%) under US GAAP are as follows at March 31:
| 2004 |
2003 | |||
| £m | £m | |||
| (Restated) | ||||
| Non-current assets: |
||||
| Tax losses carried forward |
348 | 262 | ||
| Pensions |
65 | 65 | ||
| Book depreciation in excess of tax depreciation |
30 | 849 | ||
| Nuclear liabilities |
— | 1,741 | ||
| Decommissioning asset |
24 | — | ||
| 467 | 2,917 | |||
F-83
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
| 2004 |
2003 |
|||||
| £m | £m | |||||
| (Restated) | ||||||
| Non-current liabilities: |
||||||
| Decommissioning asset |
— | (777 | ) | |||
| Nuclear liabilities |
(627 | ) | — | |||
| Capitalized interest |
(16 | ) | (16 | ) | ||
| Other |
(3 | ) | (23 | ) | ||
| (646 | ) | (816 | ) | |||
| Net deferred (liability)/tax asset under US GAAP |
(179 | ) | 2,101 | |||
| Valuation allowance |
— | (2,101 | ) | |||
| (179 | ) | — | ||||
The reconciliation between the statutory tax rate in the United Kingdom and the effective tax rate is as follows on an UK GAAP basis:
| 2004 |
2003 |
2002 |
|||||||
| % | % | % | |||||||
| Provision/(benefit): |
|||||||||
| United Kingdom statutory tax rate |
30 | 30 | 30 | ||||||
| Differences relating to: |
|||||||||
| —impact of discounting |
(60 | ) | (14 | ) | (11 | ) | |||
| —deferred tax asset/(liability) not recognized |
49 | (3 | ) | — | |||||
| —decommissioning assets/(liabilities) |
1 | (1 | ) | (2 | ) | ||||
| —decommissioning fund |
(7 | ) | (1 | ) | — | ||||
| —write down of QUEST |
— | (1 | ) | — | |||||
| —overseas tax in excess of UK rates |
— | — | (4 | ) | |||||
| —impact of joint venture |
(6 | ) | — | — | |||||
| —write down of Eggborough |
— | (1 | ) | (18 | ) | ||||
| —adjustment in respect of prior years |
(1 | ) | — | 2 | |||||
| —other |
(6 | ) | — | (2 | ) | ||||
| Effective income tax rate |
— | 9 | (5 | ) | |||||
Under US GAAP the effective current income tax rate is approximately nil for the years ended March 31, 2004 and March 31, 2003 respectively.
Tax losses arising in the United Kingdom are available for carry forward and utilization in future years. There is no expiry date.
(iv) Additional Disclosures (Restated)
a) Consolidated Statement of Cash Flows
The consolidated statement of cash flows prepared in accordance with FRS 1 (Revised) presents substantially the same information as that required under US GAAP. US GAAP requires presentation of cash flows from (i) operating; (ii) investing; and (iii) financing activities. Under FRS 1 (Revised), cash flows are presented separately for (i) operating activities; (ii) dividends received from joint ventures and associates; (iii) returns on investment and servicing of finance; (iv) taxation; (v) capital expenditure and financial investment; (vi) acquisitions and disposals; (vii) equity dividends paid; (viii) management of liquid resources; and (ix) financing activities. Cash flows from taxation and returns on investments and servicing of finance would be included as operating activities under US GAAP. Equity dividends paid would be included in financing activities.
F-84
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
Under US GAAP, cash equivalents consist of highly liquid investments that are readily convertible into cash and have maturities of 90 days or less at the time of purchase. Cash and cash equivalents are not offset by book overdrafts repayable within twenty-four hours from the date of the advance, as is the case under UK GAAP, and instead book overdrafts are classified within financing activities. Under US GAAP, contributions to the decommissioning fund are classified as investing activities while under UK GAAP they are classified as operating activities. The prior year US GAAP presentation has been restated to reflect contributions to the decommissioning fund as investing activities rather than operating activities. The US GAAP definition of cash and cash equivalents does not include the amounts which the Group has deposited in collateral bank accounts for trading purposes as availability of this cash is restricted over the period of the collateralized position. Non-cash equivalent components of net debt under UK GAAP consist of term deposits having maturities of 90 days or greater. Short-term debt represents the book overdraft in the UK accounts at the end of the year.
The table below summarizes the statement of cash flows for the Group as if presented in accordance with US GAAP.
| Year ended March 31 |
|||||||||
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Cash inflow from operating activities |
226 | 336 | 380 | ||||||
| Returns on investment and servicing of finance |
(75 | ) | (84 | ) | (53 | ) | |||
| Ordinary taxation |
(12 | ) | 3 | 4 | |||||
| Regular contributions to decommissioning fund |
19 | 18 | 18 | ||||||
| Net cash provided by operating activities |
158 | 273 | 349 | ||||||
| Acquisitions and disposals |
171 | 262 | (129 | ) | |||||
| Amounts placed on restricted use term deposit |
(88 | ) | (209 | ) | — | ||||
| Capital expenditure and financial investment |
(70 | ) | (282 | ) | (187 | ) | |||
| Regular contributions to decommissioning fund |
(19 | ) | (18 | ) | (18 | ) | |||
| Net cash used in investing activities |
(6 | ) | (247 | ) | (334 | ) | |||
| Financing |
— | (80 | ) | 13 | |||||
| Movement in book overdraft |
(7 | ) | (54 | ) | 55 | ||||
| Equity dividends paid |
— | (31 | ) | (46 | ) | ||||
| Net cash used/(provided) by financing activities |
(7 | ) | (165 | ) | 22 | ||||
| Net increase/(decrease) in cash and cash equivalents |
145 | (139 | ) | 37 | |||||
| Cash and cash equivalents at beginning of year |
131 | 270 | 233 | ||||||
| Cash and cash equivalents at end of year |
276 | 131 | 270 | ||||||
The US GAAP cash flow reconciles to the UK GAAP net debt figures as follows:
| Year ended March 31 |
||||||
| 2004 |
2003 |
|||||
| £m | £m | |||||
| Cash |
262 | 87 | ||||
| Term deposits with maturities less than 90 days at end of year |
14 | 44 | ||||
| Cash and cash equivalents under US GAAP at end of year |
276 | 131 | ||||
| Restricted use term deposits |
297 | 209 | ||||
| Book overdraft at end of year |
— | (7 | ) | |||
| Long-term debt at the end of year |
(883 | ) | (883 | ) | ||
| Net debt under UK GAAP at the end of the year |
(310 | ) | (550 | ) | ||
F-85
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The increase of term deposits for 2004 under UK GAAP is £65m. This is represented within the US GAAP cash flow as follows:
| 2004 |
2003 |
Movement |
||||||
| £m | £m | £m | ||||||
| Term deposits with maturities less than 90 days at end of year |
14 | 44 | (30 | ) | ||||
| Restricted use term deposits |
297 | 209 | 88 | |||||
| Book overdraft at end of year |
— | (7 | ) | 7 | ||||
| Term deposits under UK GAAP |
311 | 246 | 65 | |||||
There are no significant non-cash investing or financing activities during the period.
b) Information about Major Customers
In the year ended March 31, 2004 there were three UK customers who each accounted for more than 10% of Group turnover. The two largest customers each accounted for 19% of turnover, the other accounted for 16%.
In the year ended March 31, 2003 there were two UK customers who each accounted for more than 10% of Group turnover. The largest customer accounted for 14% of turnover, and the other accounted for 11%. In 2002 there were three customers who accounted for more than 10% of Group turnover. The largest customer accounted for 20% of turnover and the others accounted for 15% and 11% respectively.
In Canada all the output from Bruce Power was sold to Ontario Power Generation Inc (OPG) prior to the market opening on May 1, 2002. These sales totaled £375m or 20% of Group turnover in the year ended March 31, 2003 and totaled £348m or 17% of Group turnover in the year ended March 31, 2002. British Energy disposed of its interests in Bruce on February 14, 2003.
c) Income and Cost Recognition
The revenues from the sale of electricity are recognized on the basis of the metered output supplied by the Group’s power stations during the accounting period. The income is matched with the cost of fuel burnt and other associated generation costs in each accounting period on an accrual basis. The revenues arising from direct supply sales are based on the metered consumption of each customer during the period and matched with the associated cost of purchasing this volume of electricity.
d) Earnings/(Loss) per Share
The following table sets forth the computation of basic US GAAP earnings/(loss) per share:
| Year ended March 31, |
||||||||
| 2004 |
2003 |
2002 |
||||||
| £m | £m | £m | ||||||
| (Restated) | (Restated) | |||||||
| Numerator for basic earnings per share—earnings/(loss) available to shareholders |
7,562 | (7,800 | ) | (343 | ) | |||
| Number | Number | Number | ||||||
| Denominator for basic earnings/(loss) per share—weighted average number of shares (millions) |
602 | 602 | 598 | |||||
F-86
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
e) Exceptional Items
Under UK GAAP, income and expenses from non-recurring but significant transactions arising otherwise than in the course of the Group’s ordinary activities are recorded as exceptional items. Items classified as exceptional for purposes of UK GAAP generally do not meet the definition of “extraordinary” under US GAAP and, under US GAAP, would be classified as operating income or expenses.
f) Statement of Comprehensive Income
FAS 130, “Reporting Comprehensive Income”, requires the presentation of comprehensive income (net income plus all other changes in equity shareholders’ funds from non-owner sources) and its components. Comprehensive income and other changes in equity are as follows:
| Total |
Retained Losses |
Other hensive |
Treasury Stock |
Additional Paid in Capital |
Non- Equity |
Common Stock | ||||||||||||
| £m | £m | £m | £m | £m | £m | £m | ||||||||||||
| Balance at April 1, 2001 |
(643 | ) | (1,389 | ) | 58 | (181 | ) | 499 | 93 | 277 | ||||||||
| Cumulative adjustment for FAS 133 (net of £10m tax charge) |
(23 | ) | — | (23 | ) | — | — | — | — | |||||||||
| Net income (Restated) |
(343 | ) | (343 | ) | — | — | — | — | — | |||||||||
| Translation adjustments |
(8 | ) | — | (8 | ) | — | — | — | — | |||||||||
| FAS 133 (net of £1m tax credit) |
2 | — | 2 | — | — | — | — | |||||||||||
| Unrealized (losses) on securities |
(11 | ) | — | (11 | ) | — | — | — | — | |||||||||
| Total comprehensive income (Restated) |
(383 | ) | (343 | ) | (40 | ) | — | — | — | — | ||||||||
| Dividends declared on common stock |
(48 | ) | (48 | ) | — | — | — | — | — | |||||||||
| Treasury stock |
18 | — | — | 18 | — | — | — | |||||||||||
| Compensation plans |
4 | — | — | 4 | — | — | — | |||||||||||
| Balance at March 31, 2002 (Restated) |
(1,052 | ) | (1,780 | ) | 18 | (159 | ) | 499 | 93 | 277 | ||||||||
| Net income (Restated) |
(7,800 | ) | (7,800 | ) | — | — | — | — | — | |||||||||
| Translation adjustments |
(25 | ) | — | (25 | ) | — | — | — | — | |||||||||
| FAS 133 (net of £9m tax credit) |
21 | — | 21 | — | — | — | — | |||||||||||
| Pensions (net of £107m tax charge) |
(249 | ) | — | (249 | ) | — | — | — | — | |||||||||
| Total comprehensive income (Restated) |
(8,053 | ) | (7,800 | ) | (253 | ) | — | — | — | — | ||||||||
| Dividends declared on common stock |
(32 | ) | (32 | ) | — | — | — | — | — | |||||||||
| Balance at March 31, 2003 (Restated) |
(9,137 | ) | (9,612 | ) | (235 | ) | (159 | ) | 499 | 93 | 277 | |||||||
| Net income |
7,562 | 7,562 | — | — | — | — | — | |||||||||||
| Translation adjustments |
(15 | ) | — | (15 | ) | — | — | — | — | |||||||||
| Pensions (net of £14m tax charge) |
34 | — | 34 | — | — | — | — | |||||||||||
| Unrealized gains on securities |
87 | — | 87 | — | — | — | — | |||||||||||
| Total comprehensive income |
7,668 | 7,562 | 106 | — | — | — | — | |||||||||||
| Balance at March 31, 2004 |
(1,469 | ) | (2,050 | ) | (129 | ) | (159 | ) | 499 | 93 | 277 | |||||||
F-87
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
g) Discontinued Operations
On February 14, 2003 the Group completed the sale of its 82.4% interest in Bruce Power Limited Partnership, its majority-owned Canadian subsidiary, and its 50% share in Huron Wind Limited Partnership (collectively referred to as “Bruce”). Under US GAAP the results and subsequent disposal of Bruce would be classified as a discontinued operation in accordance with the provisions of FAS 144 “Accounting for the Disposal and Impairment of Long-Lived Assets”. Proceeds from the sale of Bruce totaled C$698m which included a C$20m retention initially held in escrow pending confirmation of the pension deficit which was subsequently received in April 2003. The loss on disposal of Bruce totaled £6m under US GAAP. The difference between the loss on disposal of Bruce under US and UK GAAP was due to the different treatment of certain costs incurred at Bruce as described in paragraphs (g), (h), (k) and (m) of Note 36 (iii), the additional derivatives recorded at Bruce for US GAAP and the recognition of the C$20m retention payment received which were recognized for UK GAAP but not for US GAAP at March 31, 2003. The following table sets forth turnover and net income of Bruce Power for the year ended March 31, 2003, reclassified as discontinued operations under US GAAP on an 82.4% holding basis.
| Year ended March 31, 2003 | ||
| £m | ||
| Turnover |
309 | |
| Net income (before tax) |
69 |
Net income from continuing operations and the discontinued operations of Bruce under US GAAP can be reconciled as follows:
| Year ended March 31, 2003 | ||
| £m | ||
| (Restated) | ||
| Profit/(loss) from continuing operations before income taxes |
(7,807) | |
| Income credit/(taxes) on continuing operations |
(46) | |
| Profit/(loss) from continuing operations |
(7,853) | |
| Discontinued operations: |
||
| Net income before tax from operations of Bruce |
69 | |
| Income taxes on discontinued operations |
(16) | |
| Profit on discontinued operations after tax |
53 | |
| Profit/(loss) for year under US GAAP |
(7,800) | |
h) Provision for Unburnt Fuel at Shutdown
Due to the nature of the nuclear fuel process there will be some unburnt fuel in the reactors at station closure. The front end and back end costs of this fuel are charged to the profit and loss account over the estimated useful life of each nuclear station on a straight-line basis. The movements in provision are analyzed as follows:
| £m | ||
| Provision for unburnt fuel at March 31, 2002 |
266 | |
| Charges to profit and loss account |
6 | |
| Provision for unburnt fuel at March 31, 2003 |
272 | |
| Charges to profit and loss account |
8 | |
| Provision for unburnt fuel at March 31, 2004 |
280 | |
F-88
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
i) Segmental Analysis
Following the disposal of its investment in Bruce Power in February 2003 all ongoing Group operations are focused in the UK. Discontinued segments represent the results of the AmerGen joint venture, the Group’s interest in which was disposed of in December 2003.
The Group has determined its reportable segments in accordance with FAS 131—“Disclosure about Segments of an Enterprise and Related Information”, through consideration of the Group’s product, geographic area and regulatory environment, and 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.
Revenues and operating profits/(losses) are measured on a segmental basis in accordance with UK GAAP as this is the basis on which management information is prepared, and has been reconciled to the primary statements which have also been prepared in accordance with UK GAAP. The chief operating decision maker evaluates segment performance and makes decisions on the basis of UK GAAP 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, reconciled to the consolidated net profit in the primary accounts. All segment revenues arise from external customers:
| 2004 |
2003 |
2002 |
|||||||
| £m | £m | £m | |||||||
| Segmental analysis |
|||||||||
| Generation and Trading revenues |
1,493 | 1,492 | 1,681 | ||||||
| Segmental operating profit/(loss) |
100 | (1 | ) | 207 | |||||
| Including: Depreciation |
(50 | ) | (281 | ) | (286 | ) | |||
| Settlement of Siemens claim |
18 | — | — | ||||||
| Head office |
(26 | ) | 113 | 24 | |||||
| Discontinued segments |
|||||||||
| North America |
21 | 43 | 37 | ||||||
| Total segmental operating profit |
95 | 155 | 268 | ||||||
| Reconciliation to UK GAAP consolidated net profit before tax |
|||||||||
| Restructuring costs |
(43 | ) | (35 | ) | — | ||||
| Exceptional items: |
|||||||||
| Stock obsolescence |
— | (57 | ) | — | |||||
| Onerous trading contracts |
— | (2 | ) | (209 | ) | ||||
| Fixed asset write up/(write down) |
295 | (3,738 | ) | (300 | ) | ||||
| Investments in own shares write down |
— | (102 | ) | (3 | ) | ||||
| UK decommissioning fund write up/(write down) |
13 | (13 | ) | — | |||||
| Discontinued operations |
— | 97 | 52 | ||||||
| Other statutory reclassifications |
1 | (64 | ) | (52 | ) | ||||
| Consolidated operating profit/(loss) |
361 | (3,759 | ) | (244 | ) | ||||
| Gain/(loss) on sale of joint venture and businesses |
47 | (35 | ) | — | |||||
| Gain on sale of investments |
— | — | 4 | ||||||
| Interest income |
11 | 9 | 16 | ||||||
| Interest expense |
(75 | ) | (81 | ) | (82 | ) | |||
| Revalorization charge |
(185 | ) | (205 | ) | (160 | ) | |||
| Exceptional interest credit/(charge) |
5 | (62 | ) | — | |||||
| Exceptional revalorization credit/(charge) |
68 | (159 | ) | (27 | ) | ||||
| Profit/(loss) on ordinary activities before taxation |
232 | (4,292 | ) | (493 | ) | ||||
F-89
NOTES FOR FINANCIAL STATEMENTS—(Continued)
for the year ended March 31, 2004
The following table presents segment revenues reconciled to the consolidated revenue in the primary accounts. All segment revenues arise from external customers:
| 2004 |
2003 |
2002 | |||||
| £m | £m | £m | |||||
| Reconciliation of revenue to UK GAAP consolidated accounts |
|||||||
| Generation and Trading revenues from external customers |
1,493 | 1,492 | 1,681 | ||||
| Head office |
38 | 5 | 5 | ||||
| Discontinued operations |
|||||||
| North America |
— | 342 | 348 | ||||
| Total segmental revenue |
1,531 | 1,839 | 2,034 | ||||
| Exceptional income reclassified for statutory accounts |
(18 | ) | 41 | — | |||
| Other statutory reclassifications |
3 | 23 | 15 | ||||
| UK GAAP Group turnover |
1,516 | 1,903 | 2,049 | ||||
j) Presentation of Prior Year Results
Certain reclassifications have been made to prior year presentation of results to conform to the current year presentation.
k) Guarantees and Indemnities
British Energy has certain guarantees in respect of AmerGen, a company in which British Energy previously held a 50% interest which has now been sold to Exelon. These guarantees relate to obligations to pay deferred consideration under certain sale and purchase contracts. The guarantees may be called if payments are not made when they fall due and shall subsist until all outstanding payments are made. British Energy’s potential exposure under such guarantees currently stands at $74.6m, however, in connection with the sale of its interest in AmerGen, British Energy has received back-to-back indemnification from Exelon for any amounts due to be paid by British Energy in respect of such guarantees.
l) New US Accounting Standards
In January 2003, the Financial Accounting Standards Board issued FASB Interpretation No. 46 (“FIN 46”), “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51.” FIN 46 requires certain variable interest entities, or VIEs, to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all VIEs created or acquired after January 31, 2003. For VIEs created or acquired prior to February 1, 2003, the provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. We currently have no contractual relationship or other business relationship with a variable interest entity and, therefore, we do not expect that the adoption of FIN 46 will have a material effect on our consolidated financial position, results of operations or cash flows.
F-90