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Document 32005D0407

2005/407/EC: Commission decision of 22 September 2004 on the State aid which the United Kingdom is planning to implement for British Energy plc (notified under document number C(2004)3474) (Text with EEA relevance)

OJ L 142, 6.6.2005, p. 26–80 (ES, CS, DA, DE, ET, EL, EN, FR, IT, LV, LT, HU, NL, PL, PT, SK, SL, FI, SV)

In force

ELI: http://data.europa.eu/eli/dec/2005/407/oj

6.6.2005   

EN

Official Journal of the European Union

L 142/26


COMMISSION DECISION

of 22 September 2004

on the State aid which the United Kingdom is planning to implement for British Energy plc

(notified under document number C(2004)3474)

(Only the English text is authentic)

(Text with EEA relevance)

(2005/407/EC)

THE COMMISSION OF THE EUROPEAN COMMUNITIES,

Having regard to the Treaty establishing the European Community, and in particular the first subparagraph of Article 88(2) thereof,

Having regard to the Agreement on the European Economic Area, and in particular Article 62(1)(a) thereof,

Having called on interested parties to submit their comments pursuant to the provision(s) cited above (1) and having regard to their comments,

Whereas:

I.   PROCEDURE

(1)

On 9 September 2002, the United Kingdom (UK) Government put in place a rescue aid package for the UK electricity company British Energy plc (BE). The Commission took a decision not to raise objection in this case on 27 November 2002 (2). Under that decision, the UK authorities had until 9 March 2003 to submit a restructuring or liquidation plan for BE, or to demonstrate that the aid had been repaid.

(2)

On 7 March 2003, the UK authorities notified a restructuring plan to the Commission. The submission by the UK Government was registered under State aid case number NN 45/2003 since certain restructuring measures possibly containing aid had already entered into force. Further information was submitted on 13 March 2003. A meeting between representatives of the Commission and of the UK authorities took place on 28 March 2003. The Commission sent the UK authorities a request for information on 21 April 2003, to which the UK authorities replied on 2 May 2003.

(3)

By letter dated 23 July 2003, the Commission informed the United Kingdom that it had decided to initiate the procedure laid down in Article 88(2) of the EC Treaty in respect of the aid.

(4)

The Commission decision to initiate the procedure was published in the Official Journal of the European Union  (3). The Commission called on interested parties to submit their comments.

(5)

The UK authorities provided the Commission with their comments on the opening of the procedure by letter dated 22 August 2003, registered by the Commission on the same day.

(6)

The Commission received comments from interested parties. It forwarded them to the United Kingdom, which was given the opportunity to react; its comments were received by letter dated 29 October 2003, registered by the Commission on 30 October 2003.

(7)

The Commission met the United Kingdom authorities on 7 October 2003. Following that meeting, the United Kingdom submitted information in a letter dated 5 November 2003, registered on 10 November 2003. Another meeting took place on 28 November 2003. The Commission sent a request for information to the United Kingdom on 5 December 2003 to which the United Kingdom replied on 22 December 2003. Another meeting took place on 2 February 2004. The United Kingdom submitted information on 4 February 2004. New information was submitted by the United Kingdom on 10 March 2004. A meeting took place on 22 March 2004. The Commission sent a new request on 19 April 2004 to which the United Kingdom replied on 11 May 2004. A meeting took place on 7 June 2004. New information was submitted on 1 July 2004 and a meeting was held on 29 July 2004. The United Kingdom submitted further information on 23 August 2004

II.   DETAILED DESCRIPTION OF THE AID

1.   Beneficiary of the aid

(a)   The British Energy plc group

(8)

BE is an electricity generator. It was privatised by the UK authorities in 1996. Except for three special shares held by the UK authorities (one in BE and one in each of its two principal UK subsidiaries), BE is now wholly owned by private investors.

(9)

At the time of privatisation the primary components of BE’s business were six nuclear power stations in England and two nuclear power stations in Scotland. BE continues to operate these stations which have a total registered capacity of 9 820 MW, of which 7 281 MW is in England and Wales and 2 539 MW is in Scotland. BE is the only private sector owned operator of nuclear power stations in the UK. It supplies electricity to the wholesale market and to certain large industrial and commercial (I & C) customers but not otherwise by retail.

(10)

Since privatisation, BE has entered a 50:50 joint venture in the USA (called Amergen) to purchase and operate US nuclear generating plants and acquired an 82,4 % interest in the lease of Bruce Power LP in Ontario, Canada. In the United Kingdom BE acquired in 1999 the retail supply business of South Wales Electricity (subsequently sold in 2000) and, in 2000, the 1 970 MW Eggborough coal-fired station to get greater flexibility and a measure of security against outage of its nuclear plants.

(11)

Of the eight UK BE nuclear stations, seven are advanced gas-cooled reactors (AGR), a design and technology unique to the UK. The eighth, Sizewell B, is a pressurised water reactor (PWR), a design and technology widely adopted internationally.

(12)

BE’s principal UK subsidiaries are:

British Energy Generation Ltd (BEG), which owns and operates the six nuclear power stations in England and holds the supply licence for the direct supply business;

British Energy Generation (UK) Ltd (BEGUK), which owns and operates the two nuclear power stations in Scotland;

Eggborough Power (Holdings) Ltd (EPL), which owns and operates the Eggborough coal fired power station in England;

and

British Energy Power & Energy Trading Ltd (BEPET), which sells all of BE’s output (other than in relation to the direct supply business) and manages market risks.

(b)   The recent developments

(13)

As a consequence of the substantial fall in electricity prices in the market in which BE operates coupled with BE’s lack of hedging and the unplanned power station outages, revenues generated by BE’s power stations decreased markedly during 2002. The high proportion of non avoidable costs (4) in BE’s cost structure in its nuclear power stations has also given it little opportunity to respond to lower prices by reducing costs.

(14)

A price fall of GBP 8,56/MWh, that has occurred in two years preceding 2002, is equivalent to an annual reduction of income of GBP 642 million per annum on output of 75 TWh (the output of BE’s power stations in the financial year). Neither electricity trading contracts nor the direct sales business have sufficiently mitigated the effect of this price fall on BE’s income.

(15)

As a result of these factors, BE’s cash position deteriorated significantly during the summer of 2002, with cash balances reducing from GBP 231 million at the beginning of April 2002 to only GBP 78 million at the end of August 2002, with the decline accelerating from the end of June 2002. In addition to the significant reduction in cash balances, BE anticipated substantial cash outflows in the period from September 2002 to March 2003. These outflows included payments to British Nuclear Fuel Limited (BNFL) under its spent fuel management contracts, significant capital expenditure at BE’s Bruce Power facility in Canada and the repayment of the first tranche of its bonds, due on 25 March 2003.

(16)

On 5 September 2002, in the light of a failed bond offering in the summer and concern about its ability to access its undrawn bank facilities, BE’s Board received legal advice that the company would not be able to draw down credit facilities. Indeed, as the directors were not in a position to state that they believed that the Company could repay those credit facilities, drawing them down would have been equivalent to trading without any reasonable prospect of avoiding insolvent liquidation. This led BE to seek financial support from the UK authorities in order to avoid insolvency proceedings. That financial support was approved as rescue aid by the Commission’s decision of 27 November 2002.

(17)

That decision referred to the undertaking by the UK Government to notify a liquidation or a restructuring plan or proof that the facilities had been reimbursed in full and/or that the guarantee had been terminated to the Commission no later than six months after the rescue aid was authorised. On 7 March 2003, the UK Government notified BE’s restructuring plan to the Commission.

2.   The restructuring plan

(a)   Origin of BE’s difficulties

(18)

The UK Government has identified the origin of BE’s difficulties to be as follows:

(19)

Unlike the other large private sector generating companies, BE does not own a retail customer business that provides a natural hedge for its wholesale electricity price risk. BE instead sells its electricity primarily in the wholesale market and a small share to large Industrial and Commercial (I & C) Consumers.

(20)

BE’s position in the market for retail supply to large I & C Consumers did not provide a hedge against the fall in wholesale prices. This market has been fully open to competition since 1994. It is competitive with price sensitive consumers. Prices in this market have also fallen. These are largely passed directly through to customers. Accordingly, there has been no increase in retail margins to offset the effects of falling wholesale prices.

(21)

The cost structures of nuclear plants are characterised by very high non-avoidable costs and low avoidable costs (5).

(22)

Some of BE’s non-avoidable costs are unique to nuclear power stations. Firstly, nuclear decommissioning liabilities are unrelated to output, except in respect to their timing, which is based on the timing of station closures. Secondly, spent fuel management costs, the costs of reprocessing, storage and final disposal of spent fuel, are also not avoidable for fuel that has already been loaded into the reactor.

(23)

On the other hand, avoidable costs of nuclear plants are below those of other plants on the system, including other baseload power stations.

(24)

The fall in market prices has led to a large reduction in the margin BE earns above its avoidable costs. Consequently the funds available to meet its high non-avoidable costs, being mainly financing costs and nuclear liabilities arising from past actions, have been greatly reduced. This has led to difficulties in meeting payments to creditors, which have required a financial restructuring of the business.

(25)

In addition to long term non-avoidable costs arising from the nuclear liabilities, BE also suffered from high shorter term non-avoidable costs in the form of financing expenses, increased as a result of its return of capital to shareholders and its Eggborough and North American acquisitions, and the cost of power purchase agreements.

(26)

BE’s loss of income following the drop in electricity wholesale prices was further exacerbated by significant unplanned outages at BE’s Torness 2 and Dungeness B stations. On 13 August 2002, BE announced that, following the unplanned outages at Torness, the target for nuclear output in the United Kingdom had been reduced from 67,5 TWh to 63 TWh (± 1 TWh).

(b)   The restructuring measures

(27)

The restructuring package consists of the following seven measures, that were agreed between BE, its major creditors (including the publicly owned nuclear fuel processing company BNFL), and the UK Government:

— Measure A

:

measures linked to the funding of nuclear liabilities;

— Measure B

:

measures concerning fuel cycle agreed with BNFL;

— Measure C

:

standstill measures;

— Measure D

:

significant creditors restructuring package;

— Measure E

:

introduction of a new trading strategy;

— Measure F

:

asset disposals to help finance the restructuring;

— Measure G

:

local tax deferrals.

(28)

These measures are described in further detail in recitals (29) to (102).

(29)

Nuclear liabilities arise primarily from the need to reprocess or store and ultimately dispose of spent nuclear fuel (back-end liabilities) and from the need to decommission nuclear power stations at the end of their commercial lives (decommissioning liabilities).

(30)

For some of the Back-end Liabilities, BE has contracts for the provision of spent fuel management services by BNFL (contracted liabilities). Contracted liabilities represent amounts that BE is contractually liable to pay to BNFL in the future for the reprocessing and/or storage of AGR spent fuel and other services in connection with the management of the spent fuel. The contracts cover reprocessing and storage of spent fuel and associated waste products for the fuel of the AGR stations up to at least 2038 or 2086. These contracts are primarily for a fixed price with all the technical risks associated with the storage and reprocessing of spent nuclear fuel residing with BNFL. Title to all spent fuel and most associated wastes remains with BE throughout the life of the contracts.

(31)

There are other back-end liabilities, which may or may not be associated with the same spent fuel, for which no contract for services currently exists (uUncontracted liabilities). Uncontracted liabilities principally relate to final disposal of spent fuel, plutonium, uranium and wastes arising from the reprocessing of AGR fuel, the storage and final disposal of spent PWR fuel, including the construction of a dry store at Sizewell B, and the storage and disposal of operational wastes.

(32)

Decommissioning liabilities relate to the costs of defuelling, decontamination and dismantling of the nuclear power stations after the stations have ceased to generate electricity. Normally decommissioning is described as three stages:

stage 1: defuelling the reactor shortly after station closure and removing the fuel from the power station;

stage 2: dismantling redundant ancillary buildings and making the reactor complex secure and weather proof, following which it is maintained and monitored, usually over long periods;

and

stage 3: dismantling the reactor to allow the site to be reused (at least 85 years after the end of generation for AGR stations and up to 50 years for PWR stations).

(33)

Until now several arrangements have been put in place for funding the nuclear liabilities. At the time of privatisation, a separate fund, the Nuclear Decommissioning Fund (‘NDF’) was established in the form of a company limited by shares owned by an independent trust. Its purpose has been to accumulate a segregated fund, to be applied to discharge part of the decommissioning liabilities. Funding of all other Nuclear Liabilities has been expected to be met out of operational cash flows from BE’s ongoing business. However as a consequence of the fall in BE’s revenues, these existing arrangements are not sufficient for the funding of nuclear liabilities.

(34)

The UK Government has included in its restructuring plan a number of instruments in order to take on the financial responsibility for at least part of the nuclear liabilities funding. These new instruments will be established along with new arrangements for the contribution of funds by BE towards the costs of the Nuclear Liabilities together with the management of BE’s nuclear liabilities.

(35)

The restructuring plan provides for the existing NDF to be enlarged into, or supplemented by, a new fund, the Nuclear Liabilities Fund (NLF). The NLF is intended to be a company limited by shares owned by an independent trust. The NLF is intended to meet the costs of Uncontracted Liabilities and decommissioning liabilities for:

(a)

all AGR fuel that has been loaded into BE’s reactors prior to the date on which all the conditions precedent to the Restructuring are fulfilled, including the Commission decision on the Restructuring plan (the restructuring effective date) for all PWR fuel, as well as the storage and disposal of operational wastes from the power stations;

(b)

all stage 1 decommissioning liabilities of BE;

and

(c)

all stage 2 and 3 decommissioning liabilities of BE to the extent that the accrued value of the NDF is insufficient to meet the stage 2 and 3 decommissioning liabilities as payments fall due.

(36)

Once the restructuring is put in place, BE will contribute to the NLF, in paying:

(a)

fixed decommissioning contributions of GBP 20 million per annum -indexed to the retail price index (RPI)- but tapering off as stations close;

(b)

GBP 150 000, indexed to RPI, for every tonne of PWR fuel loaded into the Sizewell B reactor after the date where all the conditions precedent to the Restructuring Effective Date. According to the UK authorities GBP 150 000 per tonne is comparable to international costs for spent fuel management;

(c)

GBP 275 million of new bonds to the NFL. The new bonds will be high ranking and unsecured;

(d)

payments initially amounting to 65 % of BE’s consolidated net cash flow after tax and financing costs and after funding Cash Reserves (‘the NLF Payments’). These payments are hereunder known as ‘the cash sweep’. The trustees of the NLF will also have the right, from time to time, to convert all or part of the NLF Payments into a number of shares of BE. For so long as these shares are held by the NLF, they will be non-voting to the extent they would otherwise carry 30 % or more of the voting rights of BE.

(37)

The percentage of cash flow on which the NLF Payments are based may be adjusted from time to time on a fair and reasonable basis, so that shareholders benefit from retained cash flow and proceeds of new subscriptions for shares of BE and so that the NLF and shareholders are not adversely affected by any demerger, issue of securities to shareholders or other corporate actions.

(38)

Payment of the fixed contributions of GBP 20 million per annum (indexed and tapering as stations close) to the NLF or NDF for Decommissioning Liabilities will be accelerated to a net present value basis (discounted at a discount rate appropriate to the NLF or the NDF, as the case may be) and become immediately due and payable in the event of the insolvency of BEG or BEGUK. The accelerated payment(s) will be guaranteed by all principal companies in the BE Group and secured by charges on their assets.

(39)

The trustees of the NLF will have no roles or duties apart from the management of the fund and its investments and making payments against qualifying expenditure. This will include assessing whether it would be beneficial for the NLF to defer any NLF Payments or convert the NLF Payments into equity. The trustees of the NLF will not have any powers to review liabilities, funding requirements or set the contributions of BE.

(40)

The UK Government will take the four following measures in relation to the funding of nuclear liabilities:

—   Assumption of responsibility for BE’s liabilities under historic spent fuel contracts

(41)

The UK Government undertakes to assume responsibility for BE’s liabilities under contracts between BE and BNFL (the Historic Spent Fuel Contracts), concerning: (i) the reprocessing and/or storage of AGR spent fuel loaded into reactors before the restructuring effective date, and (ii) other services relating to flask maintenance, oxide management and rail transport under existing contracts with BNFL.

(42)

That undertaking does not cover the payments for fuel loaded into the AGRs after the restructuring effective date, the costs of which will continue to be borne by BE under new contracts which have resulted from the commercial negotiations between BE and BNFL. It does not cover payments in respect of PWR fuel, as PWR is not reprocessed by BNFL, but managed directly, as a matter of fact stored, by BE.

—   Undertaking to cover any shortfall in NLF funding for stage 1 decommissioning liabilities and uncontracted liabilities

(43)

The UK Government undertakes to cover any shortfall in funding within the NLF for stage 1 decommissioning liabilities and for uncontracted liabilities (including the cost of building the Sizewell B dry store and ultimate fuel disposal).

—   Undertaking to cover shortfall in NLF funding for stage 2 and 3 decommissioning liabilities

(44)

The UK Government undertakes to cover any shortfall in funding within the NLF in relation to Stages 2 and 3 of decommissioning.

—   Specific tax disregard

(45)

The aforementioned undertakings by the UK Government will be accounted for as an asset on the BE balance sheet with a corresponding credit to the profit and loss account. Under normal circumstances, the undertaking would be taxable. According to the UK Government, this would require the UK Government to ‘gross up’ the level of aid provided to BE in the restructuring process by the amount of tax arising on the grant of the undertaking in order to ensure that BE is solvent post restructuring.

(46)

In order to avoid this, the UK authorities are in the process of introducing specific tax disregard legislation via the Electricity Bill. Without this tax disregard legislation, a taxable receipt of approximately GBP 3 152 million would arise. According to the UK government, the tax disregard legislation has been drafted in a manner that aims to ensure that no asymmetrical tax relief is given to BE in the future. Any subsequent increases in the value of the undertaking, whether due to price changes or revalorisation, will be taxable, thereby matching the tax relief received by BE when the extra expense is recorded in the profit and loss accounts.

(47)

Table 1 below contains a valuation by the UK authorities of the instruments of aid described above. These estimates of the value are subject to considerable uncertainty. Both the costs of the Nuclear Liabilities relieved and BE’s contribution to those costs are highly uncertain. Indeed, the discharge of the liabilities will occur over extremely long time periods. For example, BE would not expect to begin dismantling an AGR until at least 85 years after a station has ceased generating, while spent fuel management must continue indefinitely. In addition, there are many tasks, including the decommissioning of AGRs, for which there is to date no direct experience. The estimated value of the aid has changed since notification. The main reasons are the increased returns from the cash sweep due to improvements in BE’s forecast performance, the impact of inflation, the updating of the amounts due under the Undertaking for Historic Spent Fuel Contracts, the increased volumes of historic AGR spent fuel due to the later restructuring effective date and the increase in value of the assets held within the Nuclear Generation Decommissioning Fund to reflect the latest market value.

Table 1

Valuation of Measure A aid instruments based on projections of July 2004 (6)

(GBP million)

 

Original submission

Current projections

NPV

(discounted at 5,4 % nominal (7))

Total future cash payments

(undiscounted)

NPV

(discounted at 5,4 % nominal (7))

Total future cash payments

(undiscounted)

Undertaking for Historic Spent Fuel Contracts

2 185

3 218

2 377

3 067

Undertaking for uncontracted liabilities

750

3 166

951

3 375

Undertaking for decommissioning liabilities

879

4 917

1 115

5 062

Amounts contributed by BE to NLF

– 1 432

– 1 845

– 2 007

– 2 510

Net amounts payable by Secretary of State

197

6 238

59

5 927

Tax disregard

916

946

1 047

1 077

Total

3 298

10 402

3 483

10 071

Original submission: Cash flow valued as of March 2003, In December 2002 prices.

Current projections: Cash flow valued as of March 2004, in March 2004 prices.

(48)

BNFL both provides nuclear fuel to BE for all its AGR reactors and processes or stores this fuel when it is spent (8).

(49)

As a part of the restructuring plan, BNFL, which is BE’s largest single creditor, has agreed to modify its contracts with BE both as regards fuel supply and as regards processing of spent fuel.

(50)

Pre-restructuring fuel supply agreements between BE and BNFL dated from 1997 and 1995 for BEG and BEGUK respectively. They were supposed to continue in force until 31 March 2006, but with the intent to renegotiate and extend those contracts from that date in respect of BEG and an option to extend in respect of BEGUK.

(51)

Charges for the supply of fuel comprised an annual fixed charge and an additional variable charge per fuel element delivered. The charges were defined, subject to an adjustment in accordance with an inflation index.

(52)

The renegotiated fuel supply terms came into effect from 1 April 2003 by way of addenda to the prior agreements. The new terms will also form the basis of new lifetime agreements for AGR fuel supply after 31 March 2006, to come into effect on 1 April 2006.

(53)

Under the new conditions, the fixed annual payment under the prior agreements will be reduced by GBP 5 million a year and there will be a further discount, linked to baseload electricity prices, but subject to a cap of GBP 15 million (both at 2003 prices and subject to RPI indexation). Prices will otherwise remain as in the prior contracts.

(54)

In respect of fuel supply from 1 April 2006, and subject to at least 4 of the 7 AGR stations remaining open, the fixed charge payable by BE will be GBP 25,5 million, less the discount described above, with a variable charge (as per the existing contracts) equivalent to GBP 191 000 per tonne of uranium. These prices are at July 2002 money values and will be indexed in accordance with RPI.

(55)

For the period when only three or fewer power stations remain open, the price may be set on the basis of recommendations of a joint BE and BNFL team, following a study of the end of life optimisation programme of BNFL’s fuel fabrication plant.

(56)

In 1995, the legal predecessors of BEG and BEGUK (Nuclear Electric and Scottish Nuclear respectively) entered into long-term contracts with BNFL for the storage and reprocessing of irradiated AGR fuel and related services. BEGUK (then Scottish Nuclear) entered a further contract in 1995 for the long-term storage of all AGR fuel arisings in excess of the quantity already contracted for reprocessing. In 1997, BEG also signed a further contract for spent fuel management services, which dealt with all lifetime arisings of irradiated AGR fuel in excess of those delivered under the 1995 contract from BEG reactors. All the contracts referred above will be referred to hereunder as ‘the existing spent fuel management agreements’. They provide services through to at least 2038 or 2086 (depending on the category of waste).

(57)

Under the existing spent fuel agreements, BE retains title to all spent fuel. Eventually, BEG and BEGUK will be required to receive from BNFL’s stores the vitrified high level waste, spent fuel, certain intermediate level waste and reprocessed uranium and plutonium to fulfil their responsibilities for the disposal thereof.

(58)

Pricing for these agreements is essentially fixed, subject to adjustment for inflation and, in the case of the storage and reprocessing commitments, based on the tonnage of fuel delivered. The pricing of the initial 1995 contracts also incorporates amounts in respect of the decommissioning of THORP (the thermal oxide reprocessing plant) at Sellafield, in which AGR fuel is being reprocessed. Given the nature of the services provided by BNFL, BE is committed to make continuing payments in respect of fuel delivered whether or not it terminates the contracts in respect of undelivered fuel.

(59)

The payment streams for the 1995 storage and reprocessing contracts are fixed and run through to completion of the contracts in 2086, with payments made monthly. The payment stream for the 1997 contract is based on the timing and tonnage of fuel deliveries to BNFL. These fixed payments correspond to a lump sum paid over a fixed schedule.

(60)

The renegotiated spent fuel management agreement (hereunder the new spent fuel management agreements) apply differently depending on whether the managed fuel was loaded prior to or after the Restructuring Effective Date.

(61)

The significant revisions for fuel loaded prior to the restructuring effective date will be as follows:

(a)

the payment scheduling will be foreshortened, in such a way that the Net Present Value of future payments, computed using the UK public sector discount rates, is unchanged;

(b)

the contracts’ termination clauses will be modified in such a way that, should BE become insolvent despite the restructuring, the contracts would terminate without recourse to BE. The UK authorities have indicated that, in this case, it would be likely that it would be necessary to continue to manage this fuel at BNFL’s site at Sellafield and that the UK Government or the NLF would need to enter into contractual arrangements with BNFL, or any successor company, to do this. In this event, the UK authorities have indicated that they would expect these new arrangements to be based on a review of all the relevant circumstances at the time, including existing contractual terms.

(62)

The significant revisions for fuel loaded on or after the restructuring effective date will be as follows:

(a)

title to the spent fuel will pass to BNFL at the time it takes on the risk for managing the spent fuel (that is, on delivery of the spent fuel to BNFL), after which point BE will have no further liability in respect of it;

(b)

payment for the spent fuel services will be payable in relation to the time of loading the unirradiated fuel to BE’s reactors, rather than at any later stage (for example, on delivery of the spent fuel to BNFL) and will be based on a loading plan with an annual reconciliation;

(c)

the base price for spent fuel will be GBP 150 000 per tonne of uranium, payable on loading of the unirradiated fuel, at 2003 prices. Thereafter it will be indexed to RPI. In each year an upwards or downwards adjustment will also be made according to a formula based on the amount of electricity generated by the AGR power stations and the value of baseload electricity in England and Wales, thereby offering BE protection from fluctuations in the price of electricity. The base price for spent fuel management approximates to GBP 0,6/MWh, before the upwards or downwards adjustment.

(63)

Table 2 shows the effect for BE of changes to BNFL fuel supply contracts, as estimated by the UK authorities under three possible scenarios for the evolution of the electricity market.

Table 2

Effect of changes to BNFL fuel supply contracts

(GBP million)

Computation of fuel supply savings

Year to 31 March

2004

2005

2006

2007

2008

Pre-restructuring costs

Bank case and upside case

221

247

232

203

213

Downside case

216

241

227

198

208

Post restructuring costs

Bank case

206

231

218

188

201

Upside case

207

231

227

198

207

Downside case

200

220

205

176

186

Savings

Bank case

15

16

14

15

12

Upside case

14

16

5

5

6

Downside case

16

21

22

22

22

(64)

The UK authorities have submitted that giving precise estimates of the savings by BE after 2006 would be difficult, as the pre-restructuring fuel supply contracts were planned to end in 2006. Any estimate of the benefit for BE of the changes would therefore have to take account in some way of the benefit to BNFL of the prolongation of the contracts until the end of BE’s plants’ lifetime, which is reflected in the new contracts’ prices. Bearing in mind these uncertainties, the UK authorities have indicated that BE's internal estimate of the cost savings over the lifetime of the plants would be GBP 239 million (undiscounted) and GBP 140 million (discounted at a real rate of 3,5 % (9)). Table 3 shows the effect for BE of changes to BNFL AGR spent fuel contracts, as estimated by the UK authorities, under the same three possible scenarios (10). The net present value is computed using the UK public sector discount rate of 3,5 % real. This table addresses only the impact of price changes in contracts for fuel loaded on or after the restructuring effective date. Impact of changes in contracts for fuel loaded prior to the restructuring effective date is difficult to quantify, at it would materialise only in the event that BE becomes insolvent. Besides, the benefit for BE of the transfer of title of spent fuel, and liabilities attached to it, to BNFL, is difficult to estimate, according to the UK authorities. The UK authorities have nevertheless submitted that a subjective estimate of the benefit for BE of this transfer of title would be at around GBP 1 421 million (undiscounted) and GBP 148 million (discounted at 5,4 % nominal). This benefit is not included in table 3.

Table 3

NPV impact of changes to future AGR spent fuel contracts (11)

(GBP million)

 

NPV

Undiscounted total payments

Pre-restructuring

Bank case

592

1 117

Post restructuring

Bank case

418

558

Upside case

881

1 204

Downside case

3

4

Savings

Bank case

174

559

Upside case

– 289

– 87

Downside case

589

1 113

(65)

Originally, the companies that are now BEG and BEGUK both themselves acquired uranics for transfer to BNFL and used by it in the production and fabrication of nuclear fuel for their AGR plants. The company that is now BEGUK then transferred its uranics procurement contracts to BNFL. Those pre-existing contracts were long-term and, in any event, sufficient only for the relatively small quantities of material required by BEGUK, and therefore that change gave BNFL only a limited base for the development of a uranics procurement and supply business unit.

(66)

As part of the renegotiation between BE and BNFL of the contracts for the future supply of fabricated nuclear fuel by BNFL to BE, it was agreed that BEG should also transfer its uranics procurement contracts to BNFL which thus becomes responsible for the making of future arrangements for the procurement of uranics for nuclear fuel for BEG’s AGR plants.

(67)

At the same time, BNFL will purchase BEG’s uranics stocks, the estimated book value of which is up to GBP 67 million.

(68)

As part of the restructuring plan, BE has reached agreements (the Standstill Agreements) in relation to a standstill, subject to certain conditions, of payments due to BNFL and a number of significant financial creditors (the significant creditors) which comprise the holders of the majority of the 2003, 2006 and 2016 sterling bonds issued by BE (the bondholders, the Eggborough bank syndicate including the Royal Bank of Scotland as letter of credit provider (RBS) (together the Bank lenders) and counter-parties to three out of the money Power Purchase Agreements (PPAs) and contracts for differences: Teaside Power Limited (TPL), Total Fina Elf (TFE); and Enron (hereunder collectively the PPA Counterparties).

(69)

Under the Standstill Agreements, the standstill period commences on 14 February 2003 and ends at the earliest on 30 September 2004 or the occurrence of a termination event or the completion of the restructuring. During this period, BNFL and significant creditors have agreed with BE that they will not take any steps to initiate insolvency proceedings or demand or accelerate any amounts due and payable by BE.

(70)

BE’s and BNFL and Significant Creditors’ obligations under the Standstill Agreements are described in recitals (71) to (73).

(71)

Under the Standstill Agreements:

(a)

interest will continue to be paid to bondholders and the Eggborough banks in accordance with existing arrangements,

(b)

interest at 6 % per annum will be paid to RBS (in respect of its letter of credit) on an amount of GBP 34 million and to the PPA Counterparties on their claim amounts (RBS GBP 37,5 million; TPL GBP 159 million; TFE GBP 85 million; Enron GBP 72 million);

(c)

EPL will be paid amounts attributable to its operating costs and capital expenditure;

(d)

BE will continue to purchase power from TPL at fixed prices at levels based on the current forward price curve for electricity until completion of the Restructuring;

(e)

interest will accrue to BNFL in respect of the amounts owed under the existing spent fuel management agreements from 1 April 2003 and will be waived if the Restructuring takes place. Amounts accruing under the existing spent fuel management agreements in respect of fuel loaded prior to the Restructuring Effective Date will be frozen to the extent they exceed the amounts that would have been payable had the new spent fuel management agreements been effective from 1 April 2003 and will be waived if the restructuring takes place.

(72)

Under the Standstill Agreements:

(a)

from November 2002 up to 31 March 2003, BNFL will freeze all payments due under the existing spent fuel management agreements from 1 April 2003, BNFL will stand still the difference between payments due under the existing and the new spent fuel management agreements;

(b)

bondholders will stand still principal due under the 2003 bonds;

(c)

Eggborough banks will stand still principal repayments and other payments due under the Capacity and Tolling Agreement (CTA) except those included in BE’s continuing obligations;

(d)

RBS will stand still all amounts in respect of the RBS counter-indemnity, composite guarantee or letter of credit;

and

(e)

the PPA counterparties will stand still all amounts arising under the PPAs except those included in BE’s continuing obligations.

(73)

The obligations of a significant creditor under its agreement to standstill payments will cease to apply if any of the following occurs and a Significant Creditor gives notice of termination to BE:

(a)

there is a default in payment of the non-deferred amounts due to that significant creditor which continues for more than 20 Business Days;

(b)

a winding up or administration petition or order is made in respect of BE or any of its subsidiaries;

(c)

the UK Government makes a written demand for repayment of the Credit Facility Agreement or under any replacement facility from commercial banks guaranteed by the UK Government and the related counter indemnity by BE and its subsidiaries in favour of the UK Government;

(d)

the requisite approvals have not been obtained from the Eggborough Credit Facility Agent, RBS, the TPL bank syndicate or Enron.

(e)

documentation is issued by BE or any of its subsidiaries which provides for distributions to significant creditors different to those in the Heads of Terms agreed by the significant creditors.

(74)

Table 4 sets out the level of cash that would be saved by BE through the Standstill Agreements according to the UK authorities, should the restructuring effective date be on 31 March 2004.

Table 4

Cash saved by BE through Standstill Agreements

(GBP million)

 

 

Year ending March 2003

Year ending March 2004

BNFL

 

132

265

Bondholders

 

110

0

Eggborough banks

 

47

40

TPL

 

13

33

TFE

 

3

14

Enron

 

4

19

VAT impact

 

0

– 8

Interest impact

 

– 9

– 21

Standstill impact

 

300

342

Cumulative cash

 

300

642

(75)

In addition to the Standstill Agreements, the restructuring plan provides for the claims of the significant creditors to be restructured and rescheduled. On 14 February 2003, BE reached non-binding agreement with the significant creditors for the compromise and allocation of their claims.

(76)

The liabilities of the significant creditors to be compromised, as reflected in BE’s unaudited financial statements for the six months to 30 September 2002, were as follows:

bondholders: GBP 408 million

bank lenders: GBP 490 million

PPA counterparties: GBP 365 million.

(77)

Under the Heads of Terms the claim amounts in relation to the PPAs have since been set at GBP 316 million for the purposes of the Restructuring Package.

(78)

The liabilities will be restructured and rescheduled as follows:

(a)

GBP 275 million of new bonds will be issued to the bondholders, bank lenders, RBS, TPL, TFE, and Enron;

(b)

a revised CTA will be entered into with the Eggborough banks with a financial return for the banks equivalent to GBP 150 million of New Bonds;

(c)

ordinary shares in BE will be issued to the bondholders, bank lenders, RBS, TPL, TFE, and Enron.

(79)

BE has revised its trading strategy, seeking to reduce its exposure to output and price risks. The revisions constitute one of the elements in the restructuring package which enhance BE’s financial robustness.

(80)

BE is one of the largest electricity generators within the United Kingdom, contributing over 20 % of UK power generation. This electricity generation portfolio consists of nuclear generation (83 % by capacity) and coal-fired generation (17 % by capacity), capable of producing approximately 75 TWh per annum.

(81)

The trading arm of BE, BEPET is responsible for selling the output of BE’s generation portfolio, managing the exposure of BE to electricity market price fluctuations and maximising the sales prices achieved by BE relative to the market. Since 83 % of BE’s generation capacity is nuclear, a key focus for BEPET is the sale of this mainly continuous production.

(82)

The coal-fired Eggborough plant is also an important element in the trading portfolio. It offers output flexibility to accommodate changing customers’ demand levels and valuable ‘insurance’ in the event of a nuclear outage. It offers flexibility in relation to the purposes of its large I & C customers and also part of its wholesale trading.

(83)

In order to manage BE’s exposure to market prices whilst maximising the sales price achieved relative to market, BEPET sells its output forward. By the time the electricity is produced, BEPET, in common with other generators, seeks to have sold 100 % of its generation to avoid exposure to the typically volatile prices in the balancing mechanism. By selling ahead, the Company is able to ensure that future output volumes are sold at the prevailing price at that time and, in some cases, that prices for future output are fixed.

(84)

BEPET has a number of routes through which it can sell BE generation and sells 32 % of its total generation through the Direct Supply Business (DSB). The DSB has grown organically and represents a key element of BE’s business strategy.

(85)

BE’s retail market position accounts for a small part of its generating output relative to other significant generators in Great Britain. BE’s growth in this market is driven by the goal of diversifying delivery channels for generation output rather than any goal with respect to the retail market by itself. BE achieves a gross margin of approximately 2 % (12) on its direct sales reflecting the competitive nature of this market.

(86)

The reasons for the financial difficulties faced by BE in September 2002 included three substantially out-of-the-money power purchase agreements and contracts for differences into which it had entered as part of earlier trading and corporate activity. Each was included in the compromise agreement with significant creditors reached as part of the restructuring package.

(87)

The first one is the contract with TFE. Compared to today’s prevailing market prices, the exercise price within this contract is very high. The agreement was struck in 1997, at a time when prices were on average much higher than is currently the case. The agreement is substantially out-of-the-money for BE and the claim amount due to TFE is GBP 85 million.

(88)

The second relates to the swap contract with Enron, dated 1 April 1996, which is a financially settled instrument, based on the difference between peak and off-peak pool prices. The contract was entered into by BE prior to its acquisition of Eggborough. It was intended as a hedge against the varying shape of BE’s growing I & C consumer business. The claim amount due to Enron recognised in respect of this out-of-the-money PPA in the restructuring package is GBP 72 million.

(89)

The third one concerns an agreement inherited through BE’s 1999 acquisition of SWALEC, with TPL. The contract was originally signed on 26 June 1991. The contract is substantially out-of-the-money. The claim amount due to TPL recognised in respect of this PPA in the Restructuring Package is GBP 159 million.

(90)

As part of the restructuring package, BE has determined to secure more medium-term fixed price sales of its output. According to the UK Government, the implementation of this strategy will reduce the volatility of cash flow and reinforce the longer-term financial viability of the Company.

(91)

Under the new strategy, fixed price forward sales of output will result in the Company pre-selling a higher portion of its output for the next three to five years at a fixed price, such that BEPET fixes the value of a greater proportion of its future generation.

(92)

The key objectives of the new trading strategy are: (i) to limit price risks by securing further fixed-price contracts; (ii) to maintain viable sales channels for significant generation volumes, and (iii) to provide additional cash to maintain adequate financial reserves.

(93)

Since the new strategy was articulated in early December 2002, BE has succeeded in selling or extending an additional 14,8 TWh of DSB sales for 2003 to 2006 through the renewal of annual contracts and some extensions to multi-year agreements. As at 6 March 2003, BE had also had negotiations with a number of wholesale counterparties on the subject of structured trades.

(94)

On 6 February 2003, a significant contract was signed with British Gas Trading Limited for the sale of approximately 10 TWh per annum until 1 April 2007, more than half of which is at a fixed price.

(95)

The new contracts with BNFL also provide some element of electricity price hedging to BE due to the variable price, linked to electricity prices, to be paid for AGR fuel supply and AGR spent fuel management services. At current market prices, the new agreements with BNFL provide a partial hedge on approximately 60 % of BE’s AGR output of approx. 58 TWh p.a.

(96)

BE proposes to focus on the following objectives in its medium-term strategy:

(a)

ensuring that BE’s nuclear plants are operating to world safety and performance levels,

(b)

enhancing safety while improving productivity and competitiveness;

(c)

reducing exposure to wholesale electricity prices in the United Kingdom whilst continuing to maintain a reliable route to market. This will be achieved through a mixture of contract terms, access to flexible generation through Eggborough and DSB, focusing primarily on the I & C Consumer sector;

(d)

developing a profitable renewables business to support the competitiveness of the DSB;

(e)

a continuing commitment to supporting EU-sponsored safety-related activities in the former Soviet Union and Eastern Europe.

(97)

On 23 December 2002, BE announced that it had entered into binding heads of agreement to dispose of its 82,4 % interest in Bruce Power as follows: 79,8 % to a consortium made up of Cameco, BPC Generation Infrastructure Trust and TransCanada PipeLines Limited (together, the Consortium) and 2,6 % to the Power Workers’ Union Trust No1 and The Society. In addition, the Consortium agreed to acquire BE’s 50 % interest in Huron Wind, a wind turbine project in Ontario. The sale of Bruce Power and Huron Wind to the Consortium was completed on 14 February 2003. At the closing, BE received CAD 678 million in cash. In addition, BE expects to receive up to CAD 140 million from contingent on the restart of two Bruce A units and escrow accounts.

(98)

The initial proceeds of GBP 275 million, less certain amounts for transaction costs, have been paid into an account approved by and charged in favour of the DTI under the rescue Credit Facility Agreement (CFA).

(99)

Exelon Generation Company, LLC (Exelon) and British Energy Investment Ltd. have been soliciting proposals for their respective interests in AmerGen with respect to a sale of AmerGen. On 22 December 2003, BE shareholders approved the disposal to Exelon Generation Company LLC of BE’s 50 % interest in Amergen. BE received approximately USD 277 million in cash.

(100)

A number of local authorities have agreed to defer without interest the payment of business rates owed to them by BE.

(101)

According to the information forwarded by the UK authorities, these authorities are:

Lancaster City Council, in respect of the Heysham plant, for GBP 1 775 240,

Shepway District Council, in respect of the Dungeness plant, for GBP 578 524,

Hartlepool Borough Council, in respect of the Hartlepool plant, for GBP 447 508,

North Ayrshire Council, in respect of the Hunterston plant, for GBP 735 947,

East Lothian Council, in respect of the Torness plant, for GBP 765 986.

(102)

In total, as much as GBP 4 303 205 in rates payments were postponed from November 2002 to February 2003. As to Measure G the rates were paid by BE in full in February 2003 and interest of GBP 65 656,24 for late payment was paid on 7 October 2003. The interest rate calculation is based on the Commission reference rates for the United Kingdom of 6,01 % up to 31 December 2002 and 5,42 % thereafter.

(c)   Financial implications of the restructuring package

(103)

Before presenting the effect of the restructuring plan on the viability of BE, the UK authorities described the economics of nuclear generation. In assessing the economics of BE’s generation activities the notification distinguishes between the avoidable costs and non-avoidable costs of running BE’s stations. Nuclear plants are characterised by very high non-avoidable costs and comparatively low avoidable costs, in particular short run marginal costs. According to the UK authorities, since the decision to generate is motivated by the level of avoidable costs and in view of the fact that nuclear plants have the lowest short run marginal costs, running nuclear plants is economically rational.

(104)

The UK authorities then argue that if BE’s restructuring succeeds, the firm will not structurally be loss-making. According to the UK authorities, the plan is able to address the issues at the origin of BE’s difficulties and lead to long-term viability. In particular, it will improve BE’s trading strategy to try to offset its unhedged position, relieve BE of some of its very high fixed costs in taking over historic nuclear liabilities and enable it to build sufficient cash reserves to secure its activities.

(105)

The objective of BE’s restructuring plan is to restructure BE’s costs and liabilities and to put in place a stable capital structure in order for BE to continue to operate in the long term as a financially viable entity. In order for BE to be considered financially viable, the UK Government has assumed that, over a period of time, the company must be profitable, with positive cash flow and able to finance its activities on an ongoing basis.

(106)

The following components of the restructuring plan were developed in order to achieve the objective of financial viability:

(a)

the sale of BE’s interests in Bruce Power and AmerGen, in order to build up cash resources within the business, enhance robustness and reduce the scope of the business;

(b)

reduction in BE’s ongoing cost base through commercial negotiations with existing significant creditors to compromise their historic claims, and enter into Standstill Agreements until the restructuring is effected, in exchange for a combination of new debt and new equity in BE following completion of the Restructuring;

(c)

the assumption of costs of certain nuclear liabilities by the UK Government; and the commercial renegotiation of front end and back end nuclear fuel contracts with BNFL; the new commercial arrangements with BNFL have also reduced BE’s exposure to adverse electricity price movements;

(d)

implementation of a new trading strategy to reduce BE’s exposure to electricity wholesale market volume and price risk.

(107)

According to the UK authorities, the restructuring plan has been developed to take account of a key requirement of financial viability, namely the ability of the company to finance its activities. Since the company would expect to face difficulty in obtaining financing from the bank or bond markets, particularly considering the relatively small number of lenders prepared to provide financing to a nuclear generating company, the restructuring plan has to be considered as an alternative to seeking external financing. It foresees the creation and build-up of cash reserves. These cash reserves would be designed to enable the company to enter into electricity trading contracts requiring collateral cover and to sustain cash shortfalls without the need to rely on external funding. Accordingly, the restructuring plan envisages the creation of two reserves: a cash collateral reserve and an outage and liquidity reserve. Although two separate pools of reserves have been identified, it is intended that these reserves will be fungible giving the ability to call on the outage and liquidity reserve to meet additional collateral requirements and vice-versa. This is to provide additional robustness for BE.

(108)

BE has undertaken several actions to improve its cash position through:

(a)

reducing the impact of seasonality by managing payment profiles where possible;

(b)

further cost saving initiatives;

(c)

securitising direct sales receivables.

(109)

In addition BE went through a business planning process which resulted in updated financial projections and has conducted a detailed review of issues surrounding the performance of its plant.

(110)

In the period ending 31 March 2004, the cash reserves were built up through two sources of funds: the Standstill Agreements (Measure C) and asset disposals (Measure F), after repayment of the liabilities outstanding under the rescue aid Credit Facility Agreement.

(111)

The UK authorities have developed three financial scenarios to take into account the variables to which BE’s financial position is particularly sensitive: generation output and electricity prices. The financial projections were reviewed by Deloitte & Touche in its capacity as economic and energy market consultants to the UK Government. Output and capex assumptions incorporated in the business planning cases have been reviewed by WS Atkins in its capacity as technical adviser to BE and Citigroup and by Stone & Webster Management Consultants, Inc. in its capacity as technical adviser to the UK Government.

(112)

The review has taken account of three main changes since the original notification in March 2003, namely the level of electricity prices, the Performance Improvement Programme (PIP) aimed at improving the nuclear plant reliability and the trading collateral.

(113)

Electricity prices have evolved significantly in recent months. According to the UK authorities, electricity prices are currently above GBP 28/MWh compared to GBP 16,4/MWh in March 2003. The key drivers of changes in electricity price forecasts are the movement in underlying fuel prices (coal, gas, oil), the carbon pricing introduced by the European Emissions Trading scheme and the capacity reserve margins.

(114)

BE’s nuclear fleet has historically been less performant than its international peers. The oldest plants have suffered from underinvestment and all plants have major potential for improvement and high short-term risk of outages. BE has therefore developed recovery plans for the plants. The benefits from PIP should derive from cultural and organisational change and increased investment in capital and staff. It should result, over time, in reductions in plant unreliability and increased output.

(115)

BE has also taken into account the recent significant increase in collateral requirements resulting from the market price increases.

(116)

In order to determine the impact on BE’s financial position of alternative assumptions for generation output and electricity prices, BE has considered one upside and one downside sensitivity which all take into account the evolution of electricity prices, the benefits of the PIP and estimated collateral projections:

(a)

the ‘upside case’ which is the basis for BE’s budget for the year and is used to set performance targets; It is broadly equivalent to the ‘upside case’ described in the decision to initiate proceedings;

(b)

the ‘relisting case’ which is the basis for disclosure in public statements and in the prospectus to be issued on listing; it is to be seen as a ‘bank case’. The ‘relisting case’ prices are derived from the forward curve using a market model which incorporates BE’s views on fuel costs and carbon pricing;

(c)

the ‘reasonable worst case’ (RWC) which is equivalent to the downside case and takes into account uncertainties regarding prices and output; the RWC prices are based on a price curve developed by BE.

(117)

The UK Government has taken as basis for testing the viability of BE the headroom numbers of the company. They have come to the following estimates for the period 2005-2010:

Table 5

Headroom figures

(GBP million)

Relisting case/Bank case

2005

2006

2007

2008

2009

2010

Liquidity reserve

[…] (14)

Impact of seasonality and receivables facility

Headroom post seasonibility

Cumulative impact of cash, output and collateral vulnerabilities (13)

Headroom post vulnerabilities

Cumulative impact of management actions on cash and collaterals

Headroom post management actions

RWC/Downside Case

Liquidity Reserve

Impact of seasonality and receivables facility

Headroom post seasonality

Cumulative impact of management actions on cash and collateral

Headroom post vulnerabilities

Cumulative impact of management actions on cash and collateral

Headroom post management actions

(118)

The UK authorities have also provided an estimated profit and loss account for the period 2005/2009 relating to the re-listing case.

Table 6

Profit and loss account in the relisting case

 

5-year forecast period

Profit and loss account

2005

2006

2007

2008

2009

Nuclear output TWh

[…]

Income

Generation sales

Miscellaneous sales

Total income

Operating costs

Fuel costs

Staff costs

Materials and services

Capital expensed to P/L

Depreciation and amortisation

Total operating costs

Operating profit/(loss)

Contributions from new business activities (PBIT):

AmerGen (before revalorisation)

Profit before finance charges and tax

Finance charges

Revalorisation (net)

Net interest and other finance charges

Total finance charges

Profit before tax

17

171

186

336

355

Minority interests (share of PBT)

0

0

0

0

0

Profit before tax (and HMG indemnity)

17

171

186

336

355

Movement in HMG indemnity

0

– 96

– 133

– 206

– 156

Profit before tax (and exceptionals)

17

75

53

130

199

Exceptionals

4 068

0

0

– 40

0

Profit before tax (post exceptionals)

4 085

75

53

90

199

Tax

0

0

0

– 26

– 87

Profit after tax and exceptionals (before tax on exceptionals)

4 085

75

53

64

112

Source: BE.

Note: The figures for 2004/2005 have been prepared on a pro-forma basis (i.e. to make comparability easier, for accounting purposes the fuel costs and revalorisation numbers reflect the new fuel contracts, even though technically these will not be in place until the restructuring effective date).

(119)

This estimate shows that profit before tax, minority interests, the UK Government’s undertakings and exceptional items improves from GBP 17 million in 2005 to between GBP 171 million and GBP 355 million in subsequent years. In 2005 the exceptional item relates to accounting inclusion of the UK Government’s undertaking to fund nuclear liabilities referred to in Measure A.

(120)

Profit before tax is substantially reduced by contributions to the NLF from 2005. However, these contributions are 65 % of cash flows available after debt service and are not payable when cash flows are negative or transfers to maintain target Cash Reserve levels are required.

(121)

An analysis of BE’s financial projections demonstrates that under the Re-listing Case, the restructured business is expected to generate profits and cash flows to service the various stakeholders and that significant contributions are expected to be made towards the discharge of uncontracted liabilities and decommissioning liabilities before any return to shareholders.

3.   Grounds for initiating the proceedings

(122)

In its decision to initiate proceedings, the Commission noted that the restructuring plan conferred a selective competitive advantage on BE in a sector where there is intra-Community trade. Measures A and G directly involve the United Kingdom central or local authorities’ budgets, hence State resources. They are State aid within the meaning of Article 87(1) of the Treaty. It is also possible that Measure B, and, at least partly, Measure C, involve State resources to the extent that the publicly owned company BNFL would not have acted following the private investor in a market economy principle. It therefore appears that these measures also constitute State aid within the meaning of Article 87(1) of the Treaty.

(123)

The Commission analysed the aid in the light of the Community guidelines on State aid for rescuing and restructuring firms in difficulty (15) (hereafter the guidelines).

(124)

This analyse raised the following doubts as regards the compatibility of the aid with the common market:

(125)

The Commission had doubts as to whether the plan would result in a restoration of BE’s viability in a reasonable timeframe. Indeed, some of the measures have a very long time span (until at least 2086). Furthermore, the improvement of BE’s position would seem to be only due to external support conceded by the Government and major creditors, rather than physical internal restructuring. Furthermore, should it be State aid, the renegotiation of fuel supply and spent fuel management prices with BNFL could be viewed as a life long operating aid for nuclear stations, which would be incompatible with the requirement that BE must face the market with its own forces alone after the restructuring is over, and with the polluter pays principle.

(126)

The Commission had doubts as to whether the aid could be authorised without any compensatory measure being offered in order to offset the impact of the aid on competitors. In this respect, the Commission acknowledged that it is likely that there was no or very little structural overcapacity on the relevant market. However, the Commission considered that, in view of the highly competitive nature of this market and of the high amount of the aid, it was likely that some sort of compensatory measure would be necessary for the aid to be compatible, even if this compensatory measure did not consist in irreversibly closing power plants.

(127)

The Commission had doubts as to whether the aid was restricted to the minimum necessary. In this respect, the Commission noted that the plan provided for a mechanism by which BE would participate in the restructuring costs via a percentage of its free cash flow. However, in view in particular of the great uncertainty as to the amounts of aid to be granted, the Commission was not then in a position to assess whether this aid was limited to the minimum.

(128)

Taking into account the foregoing considerations, the Commission concluded that there were doubts as to whether the restructuring plan complied with the criteria laid down in the guidelines and whether the aid awarded and to be awarded by the UK Government to BE could be considered as compatible with the common market. The Commission therefore decided to initiate the procedure laid down in Article 88(2) of the Treaty.

(129)

In the same decision, the Commission also added that the decision to open proceedings was without prejudice to the application of the Euratom Treaty. Some measures, notably Measures A and B, have to be assessed in view of the objectives of the Euratom Treaty. Therefore, the Commission requested the United Kingdom to provide all such information as might help it to assess the measures, in particular Measures A and B, in the light of the objectives of the Euratom Treaty.

III.   COMMENTS FROM INTERESTED PARTIES

(130)

Following the publication of the decision to initiate proceedings and within the deadline foreseen by that publication, the Commission received comments from 20 third parties including from BE itself. They can be summarised as follows:

(131)

BE stresses that the case is unusual due to the way the electricity market operates and due to the economic structure of nuclear plants.

(132)

BE stresses the fact that the costs of the past represented by BE’s nuclear liabilities could no longer be met by BE with the substantial fall in electricity prices that has taken place in the United Kingdom. Under the restructuring plan, BE is also required to make large contributions towards costs of the past. With regard to the costs of decommissioning and the other nuclear liabilities not covered by the new contracts with BNFL, a contribution will be made through the NDF/NLF. Other measures affecting BE and its investors include the sale of BE’s North American assets, the loss by the pre-existing equity shareholders of the whole of their investment, and the settlement by the pre-existing investors as well as the issue of new bonds.

(133)

BE stresses that a lump sum payment to the recipient would not be practicable, in particular because certain of these costs will be incurred at dates in the very distant future. Rejecting BE’s restructuring plan because it relieved BE once-and-for-all of certain defined, albeit presently unquantifiable, liabilities, would create a precedent against the approval of restructuring aid that was necessitated by the existence of costs of the past.

(134)

BE is of the opinion that no inferences can be drawn from a comparison of the arrangements with the privately owned creditors. In particular, in the case of BNFL, an important part of its core business would be threatened and perhaps rendered unviable if operations of BE’s stations were unviable.

(135)

BE stresses that BNFL adopted an extremely tough stance and may have been eventually constrained only by a concern that BE would otherwise face insolvency. The terms that were renegotiated were the least that BE believed could be commercially obtained while being robust following restructuring. According to BE, the Commission may have misunderstood the commercial nature of the new BNFL Contracts as a result of misunderstanding the facts and in particular their chronology. BE provides an annex to its submission that shows why it believes that the prices under the new contracts are not particularly favourable to it.

(136)

BE recalls that the problem to be addressed by the Restructuring Plan was essentially that in the new environment of much lower wholesale electricity prices, BE could no longer sustain the ‘costs of the past’. According to BE, the restructuring plan successfully addresses that problem.

(137)

Concerning the effect of the aid package on competition, BE argues that because the SRMCs of BE’s nuclear plants are so much lower than those of any other baseload supplier, BE’s nuclear plants are always bound to run. But the precise level of BE’s SRMCs is irrelevant for the determination of electricity prices, which reflect the higher SRMC of the marginal supplier.

(138)

BE explains that nuclear stations are technically and economically inflexible and that the operation of such plants other than as baseload plant is uneconomic. As far as its trading strategy is concerned, BE explains that the economics of nuclear generation tend to lead BE to focus on selling its output forward in longer-term markets.

(139)

In the view of BE, there is no overcapacity in the generation of electricity in Great Britain. As far as compensatory measures are concerned, BE argues that requiring premature closure of any of BE’s nuclear plant would be economically inefficient since the purpose of the aid package is to preserve BE’s nuclear capacity which, in terms of production of electricity, with the minimum avoidable expenditure of resources is the most cost-effective capacity in the British market. In addition it would encroach on the exercise by the UK Government of its competence in relation to sources of energy supply to the United Kingdom and would increase the emission of environmentally harmful gases into the atmosphere

(140)

BNFL is a publicly owned company operating in the nuclear sector. It supplies and reprocesses or stores BE's AGR nuclear fuel. Apart from its activities in the fuel cycle, BNFL also operates a few Magnox nuclear plants, and has activities as a nuclear plants designer.

(141)

The BNFL submission concentrates on the questions of the existence of aid to BE in Measure B and C. BNFL submits that all BNFL interventions in BE's restructuring plan followed the private investor in a market economy principle, and therefore contain no aid elements.

(142)

BNFL explains that following the advice of their financial advisers’ (NM Rothschild & Sons Limited – Rothschild), BNFL already concluded in April 2002 that an ‘orderly rescue package’ with value for BNFL was preferable to allowing BE to become insolvent given the very vulnerable position of BNFL as BE’s largest creditor, its lack of security and the weaknesses of its legal position. BNFL adds that its Board, however, agreed with a restructuring of the existing contracts with BE on the conditions that BE should not be kept solvent at any cost and that any package proposed to BE would need to establish the commercial advantage to BNFL, given its own balance sheet deficit.

(143)

BNFL gives details of each of the successive proposals and counterproposals from each side, together with Rothschild’s view on them. BNFL also sets out in great detail the chronology and content of the discussions that took place between BE and BNFL, which shows that BNFL already expressed itself willing to help BE before BE turned to the UK Government for assistance but realised that this would not be possible without a global restructuring plan.. The discussions already started in May 2000 when BE first requested, without success, the application of the hardship clause contained in the contracts. New discussions were initiated during 2002.

(144)

BNFL also stresses that it had no involvement in the discussions between BE and the UK Government. On the basis of the analysis of its independent legal and financial advisers, BNFL concluded that proceeding with a solvent restructuring was in its best commercial interest and came to an agreement with BE on the Final Term Sheet on 28 November 2002. It is only after it had agreed on its Final Term Sheet with BE that it was aware of precise details of the UK involvement.

(145)

BNFL’s comparison of the 3 September term sheet and the final term sheet concludes that there are considerable similarities between the two term sheets and that the final outcome was significantly closer to BNFL’s opening position than to that of BE.

(146)

BNFL gives details of its assessment of the commercial benefits to it of the solvent restructuring as compared to a BE insolvency based on the analysis by financial and legal advisers. It has identified considerable risks to BNFL in the event of BE’s insolvency in particular due to the fact that BE had large undocumented intercompany loan balances between different BE group companies and that BNFL’s contractual arrangements with BE were in many ways unique and no clear precedent could be drawn from previous insolvencies. Besides, as the only creditor that benefited from security on BE’s nuclear power plants, the UK Government would have had a central role in the outcome of insolvency. However BNFL was not granted any insights into the UK Government’s likely approach during any insolvency proceedings.

(147)

While BNFL’s role as a key supplier to BE might be expected to have placed it in a strong negotiating position in any insolvency, its ability to make a credible threat to stop providing goods and services to BE was undermined by a number of factors. In particular, BNFL notes that BNFL as BE’s largest single creditor would be the major financial loser if BE’s nuclear power stations were to shut down as a result of it exercising this threat. In addition, it is doubtful whether it could lawfully terminate the contracts and return to BE spent fuel and waste already received by it as this would not be permitted by UK nuclear safety legislation. Finally as a responsible nuclear services company, BNFL had to continue providing services to BE to the extent that not to do so would be unsafe or could even be perceived as being unsafe to third parties.

(148)

BNFL’s analysis of BE insolvency focused on three possible outcomes namely the closure of BE’s nuclear plants leading to a minimal recovery, BNFL taking ownership of BE’s nuclear plants meaning that it would assume all nuclear liabilities of BE, which is highly risky and unattractive, and the UK Government taking ownership and asking the existing creditors to accept very substantial write-downs.

(149)

Consequently, the proposed solvent restructuring appeared to be more commercially attractive since it reduced BNFL exposure to BE and offered a higher and more certain revenue stream for BNFL than insolvency. BNFL is therefore deemed to have acted in the same way as any other private creditor.

(150)

Finally, BNFL compared the return of other major creditors in aggregate to its own return to ensure that the terms did offer BNFL a reasonable deal. In order to protect its position further, BNFL also secured the inclusion of a clause in the Final Term Sheet allowing the withdrawal of the suggested concessions in the event that any other material creditor was offered more favourable terms than BNFL. Rothschild updated its analysis once the detailed terms that BE was agreeing with other major creditors were established and it confirmed that BNFL’s arrangements actually appeared to be no worse than other major creditors. Furthermore, none of the revised contractual arrangements will come into effect unless and until the restructuring is completed.

(151)

As regards Measure C, BNFL submits that, with the help of Rothschild, it checked that it did not concede more in the way of debt standstill than other significant creditors. When BNFL became aware that other creditors were obtaining more favourable terms than BNFL under the standstill arrangements (albeit that BNFL’s position was not directly comparable with BE’s other major creditors), it considered whether it should seek renegotiation and ask for interest. It concluded that it was unlikely that BE could pay interest to BNFL and generate sufficient surplus cash during the standstill period to allow the solvent restructuring to proceed. In addition despite its position under the standstill arrangements, BNFL would achieve better overall recovery if a solvent restructuring were to go ahead.

(152)

BNFL submits that its decision to enter into the arrangements with BE was an autonomous decision of BNFL and was not at the direction of the UK Government. The fact that BNFL is a publicly owned company does not suffice to consider that BNFL’s decisions are imputable to the UK Government. Although the UK Government is BNFL’s sole shareholder, BNFL is autonomous from the UK Government in relation to its day-to-day commercial business and is required to operate on a commercial basis. BNFL submits its legal status as an underlying document. BNFL adds that throughout its negotiations with BE, BNFL kept its shareholder (the DTI) informed of its discussions with BE. It describes that as a typical commercial situation where a company has a controlling shareholder. The DTI indicated to BNFL that it would only approve (under BNFL’s corporate government arrangements with the DTI) revised arrangements with BE that were on a commercial basis for BNFL.

(153)

Greenpeace Limited is the UK arm of Greenpeace International, two of the main activities of which are campaigning to end the use of nuclear power and promoting the use of clean and renewable energy resources in the United Kingdom.

(154)

Greenpeace submits that, in capping BE’s contributions to the funding of nuclear liabilities, Measure A constitutes unjustifiable operating aid to BE and/or BE’s shareholders as a means of enhancing BE’s attraction to investors on the market.

(155)

According to Greenpeace, Measures B and C constitute unjustifiable operating aid since they confer ongoing support by BNFL acting or deemed to be acting as the State or at the behest of the State in circumstances where:

(a)

BNFL is an ailing undertaking which survives only with the benefit of State aid;

(b)

BNFL was party to tri-partite negotiations with the government and BE which led to the formulation of BE’s restructuring package immediately following BNFL’s own refusal to vary the terms of its contracts with BE; Greenpeace therefore asked the Commission to ask BNFL to produce copies of internal BNFL documents to see whether BNFL was privy to BE’s discussions with the UK Government;

(c)

the agreements are in any event lacking in genuine commercial character; according to Greenpeace, BNFL’s contracts with BE are not and were not commercial arrangements from the outset and look more like an artificial device designed to provide BNFL with a guaranteed income stream; the restructuring aid package continues to provide BNFL with this income stream;

(d)

the renegotiated pricing terms do not reflect the actual costs associated with the service provided but are linked to wholesale prices; since the advantage conferred by the contracts is ongoing and pursuant to an open-ended agreement, the aid involves long-term support for BE, not a one-off benefit designed to restore its viability; the benefit is therefore ‘operating’ and not ‘restructuring aid’ and cannot be compatible with the common market.

(156)

Greenpeace supports all Commission doubts, and concludes that the aid is incompatible with the EC Treaty. It stresses in particular that the restructuring aid would not only have an effect on the existing operators but would also deter competition from new entry because other incumbents and new entrants are prevented from exploiting their own efficiency. Supporting nuclear energy operators would in addition be inconsistent with the Government declaration on diversity of energy sources including renewables.

(157)

As far as the issue of overcapacity is concerned, Greenpeace is of the view that the ‘planning margin’ used by the National Grid for planning the need for future generation in order to maintain safe capacity is not the appropriate data to take into consideration for assessing whether there is overcapacity on the market. According to Greenpeace, it is likely that significant structural overcapacity already exists in the relevant market and is set to increase.

(158)

Greenpeace doubts that the closure of some of BE’s plants would be more expensive to the taxpayers since BE’s ability to contribute towards paying off its existing liabilities is doubtful. Greenpeace adds that in the short term perspective there is no reason to believe that the United Kingdom would not be able to achieve its targets under the Kyoto Protocol.

(159)

Greenpeace submits that according to reports commissioned by it, it is both practicable and safe to close down nuclear plants immediately or progressively. Greenpeace concludes that the option of partial or phased closure of BE’s plants may result in a more limited intensity of aid being required.

(160)

Greenpeace is of the opinion that the Euratom Treaty does not preclude any State aid analysis under the EC Treaty. In the absence of sectoral rules applicable to aid to the nuclear industry in the Euratom Treaty, the general State aid provisions of the EC Treaty should therefore apply. Greenpeace quotes Joined Cases 188 and 190/80 France and others v Commission (16). Greenpeace further contends that the aid measures relate to matters which may be regulated by the Euratom Treaty, only to the extent that they relate to the safety of nuclear installations on the safety aspects of decommissioning. Greenpeace concludes that the measures in question are not necessary to achieve the stated objectives and that continuing operating aid of any sort cannot be considered necessary to preserve safety in circumstances where there exists a safe, viable option of a phased total or partial closure of BE’s plants. According to Greenpeace, the Commission ought to have regard to the Community guidelines on State aid for environmental protection (17).

(161)

Powergen is one of the major actors in the electricity sector in England and Wales. It has a 11 % share of the generation capacity (BE has 14 %), and has significant supply business aimed at large industrial and commercial customers as well as SMEs and residential customers. It is owned by E-ON.

(162)

Powergen is against the aid package. It submits that the aid will allow BE to continue the operation of its nuclear plants that it would otherwise have closed. In this respect, Powergen disputes the UK authorities' view that the plants would be run in any event. Powergen is afraid that the aid would allow BE to offer artificially low prices in order to gain market share in the supply to large customer business and to enter the supply to households business. BE may also be able to fund investments in non nuclear generation.

(163)

Concerning compensatory measures, Powergen wishes to be consulted on any compensatory measure that would be put in place and suggest three possible ones:

(164)

Firstly, advancing the closure of the Dungeness B nuclear reactor to April 2004. According to Powergen, if this advanced closure was made known sufficiently in advance, there would be time for the market to build up the corresponding capacity to keep sufficient margin.

(165)

Secondly, ring-fencing the aid, by forbidding cross-subsidy between BE’s loss-making assets (the AGR plants) and other BE business, constituting BE’s generation and supply business into separate bodies with separate accountancy, and imposing specific controls on the use of cash by BE to ensure that it will not divert cash paid by the State to fund its nuclear liabilities to other uses. These measures should remain in place as long as the restructuring plan measures are in place.

(166)

Thirdly, preventing distortion of competition on the electricity retail market, by prohibiting BE from selling power below cost (the cost of acquiring the power from the wholesale market plus other sales related costs), imposing a cap on BE’s market share in its industrial and commercial supply business (a 20 % indicative cap is given), and prohibiting BE from entering new retail markets. These measures should remain in place as long as the restructuring plan measures are in place and there efficiency should be reviewed by the Commission after five years from implementation.

(167)

Concerning the return to viability, Powergen submits that the scenarios taken into account by the UK authorities to assert BE’s future viability are too optimistic, in particular as regards the availability of BE’s plants as compared to past benchmark.

(168)

Finally, Powergen considers that ‘it is well established that the state aid rules contained in the EC Treaty apply to the nuclear industry, notwithstanding the existence of the Euratom Treaty’. They refer to the same 1990 case as the one referred to by Greenpeace.

(169)

InterGen is a global power generation firm, with activities in all continents. It has a 2 % share of the generation capacity in England and Wales, with two plants operating and one in construction (BE has 14 %). It sells most of its electricity to the wholesale market, and a part of it through long term contracts. It is also active in the gas trading market. It is jointly owned by Shell and Bechtel.

(170)

Intergen submits that there is security of supply concern in the United Kingdom, and that nuclear safety could be managed by company receivers. They draw the Commission's attention to the fact that aid to BE has been and is damaging InterGen, and to the fact that other InterGen competitors, like Teeside Power Limited, which are among BE creditors, are also favoured as compared to InterGen within the framework of the restructuring plan. InterGen submits that, should the Commission authorise the aid, it and its affiliate should be compensated for the damage they suffer.

(171)

This third party submits that earlier press reports suggest a reprocessing price prior to BE’s restructuring of some GBP 1 000/kg heavy metal (HM). Following BE’s restructuring a price of some GBP 150/kg HM has been agreed between BNFL and BE, which is 85 % below the original agreement. It adds that the initial reprocessing contracts between BNFL and BE were prices at cost plus value, which means that the baseload customers could by contract obtain reprocessing only if they accepted (pro rata) assumption of full costs of reprocessing plus a profit mark up. Against this background, if the reprocessing costs agreed with the baseload customers cover costs only at the level of GBP 1 000/kg HM, this means that the new price now agreed with BE cannot in any way come near to covering costs. Even in the case of new contracts, the price amounts to GBP 1 000/kg HM (prices as at 2003).

(172)

It concludes that these prices indicate that BNFL has not acted as a private investor in a market economy in its negotiations with BE, unless BNFL would be willing to extend these favourable conditions to other customers.

(173)

Drax is the largest coal-fired electricity generator in Western Europe. It was previously part of the AES Corporation, a US based energy group with interests in generation, distribution, and supply of electricity throughout the world. On 5 August AES Corporation ceded control of Drax to its creditors. On 30 August 2003, Drax announced that it had entered into an exclusive arrangement with International Power plc to participate in the restructuring of Drax.

(174)

According to DRAX, Measures A, B and G all constitute state aid in the sense of Article 87(1) of the EC Treaty. DRAX agrees that Measures D, E and F do not constitute state aid. DRAX is of the view that the amount of aid is difficult to estimate. As regards Measure A, DRAX believes that its amount could be considerably greater than currently estimated in particular due to the fact that decommissioning liabilities are uncharted in the United Kingdom and that it is unlikely that BE would contribute to the nuclear liabilities costs. The UK Government will always remain ultimately responsible for the back-end and decommissioning liabilities. The UK government will never allow BE to fail. DRAX is of the opinion that the tax disregard itself should be notified as aid.

(175)

DRAX believed concerning the re-negotiation of contracts with BNFL that no private investor would ever have agreed such uncommercial terms committing it to significant present and future losses, irrespective of the hardship clause and the fact that BE is its largest customer. It is clear that the re-negotiation severely disadvantaged BNFL’s position. It will lead to a reduction of the fixed annual payment in respect of fuel supply agreement of between GBP 5 million and GBP 20 million per year. This view is confirmed by BNFL’s 2004 Accounts report. Besides it appears that even if BE had to be placed under administration, BE plants would continue to operate and have the same need for the supply of fuel as well as management services, processing and disposal of that fuel after it has been used. The question should then be whether the administrator would have been able to extract those terms from BNFL. In addition, BNFL could pursue other business opportunities if its business with BE were to be reduced. BNFL is not organised on the basis of the market investor principle. Consequently Measure B is state aid.

(176)

DRAX is of the opinion that the BNFL standstill agreement contained in Measure C also constitutes state aid since BNFL does not receive interest during the standstill period unlike the other participating creditors.

(177)

Drax further commented on the compatibility of the aid package. DRAX does not question the fact that BE is a firm in difficulty. However it is of the opinion that BE’s unhedged position was entirely due to a curious decision on the part of its management to sell its retail business. Besides, BE could have reduced its costs by closing some or all of its plants as it is more expensive to run some nuclear plants than it is to temporarily close them

(178)

Concerning the restoration of viability, DRAX is of the opinion that the proposed plan is not a real restructuring plan. Furthermore, BE is and will always be in a different position from its competitors. It will continue to generate power and sell into the market at any price and will exert a permanent downward pressure on price to the detriment of all other competitors.

(179)

DRAX objects to the UK Government’s use of SRMCs as the proper measure of the viability of BE. The restructuring relieves BE of the liabilities for the major costs of a nuclear generator. A company’s decision on whether or not to enter a particular market or indeed to continue to compete in that market will be based on whether it can, over a reasonable period, meet its average costs, plus realise a reasonable return on its investment. This is not the case of BE, which has all the commercial risk removed from it.

(180)

Concerning the duration of the aid, DRAX is of the opinion that the funding of open-ended liabilities so far into the future is not compatible with the guidelines. It also argued that ongoing operational aid cannot be considered to be limited to the minimum necessary. Furthermore, as regards BE’s own contribution, DRAX notes that there is an uncertainty about the proceeds of the sale of assets and that BE’s contribution to the NLF derives from aided cash flow which cannot be taken into account.

(181)

On the issue of over-capacity and compensation to creditors, DRAX notes that the capacity margin of 20 % quoted in the decision to initiate the procedure only concerns winter peak demand. According to the NGC, the capacity margin over average peak winter demand is 20,3 %. According to DRAX, it would be a rational approach for any operator of BE to close down a proportion of generating capacity during the summer months. This would result in a net saving.

(182)

DRAX believes that there are a number of compensatory measures and/or amendments to the restructuring plan which would go some way to ensure that the restructuring is in accordance with the guidelines and offers compensations for unaided competitors. DRAX proposes the following:

(a)

removing BE from the competitive market by creating a system of compulsory purchase of nuclear energy at a fixed price that would be similar to the Renewable Obligation. BE can never be properly restructured to allow it to compete on the merits with non-aided market participants. The best solution if BE generation cannot be withdrawn from the market is that BE’s output be partitioned from the competitive market. The price of the nuclear generated electricity would need to be regulated and could be set according to cost of capital and other traditional price regulation parameters. This would meet the UK government’s concerns regarding security of supply and nuclear safety and there would no longer be any distortion of competition;

(b)

reducing the term and re-balancing the risk of BNFL contracts in favour of BNFL;

(c)

divesting of Eggborough;

(d)

banning further acquisitions or acting as market leader;

(e)

obtaining a commitment of the UK Government on the one time last time principle.

(183)

DRAX also commented on the relationship with the Euratom Treaty. DRAX is of the opinion that the EC and the Euratom Treaties pursue complementary rather than conflicting objectives.

(184)

Comments were also introduced by the Trade Unionists for Safe Nuclear Energy (within a Balanced Energy Policy) – TUSNE (18), Mr Robert Freer (19), the UK Chemical Industries Association (CIA) (20), John Hall Associates (JHA) (21), the Energy Intensive Users Group (EIUG) (22), Terra Nitrogen (23), Energywatch (24), Teollisuuden Voima Oy (TVO) (25), National Grid Transco (26), the Royal Academy of Engineering (27), Enfield Energy Centre Limited (EECL) (28), the Energy Information Centre Ltd (EIC) (29), Major Energy Users’ Council Ltd (MEUC) (30) and a second third party willing to remain anonymous.

(185)

TUSNE, Robert Freer, CIA, JHA, EUIG, Terra Nitrogen, EIC and MEUC are all concerned about the security of supply in the United Kingdom and submit that closing down BE’s nuclear plants would create the risk of power cuts and be contrary to consumers’ interests. Some of them also stress that the withdrawal of BE’s nuclear plants would make the United Kingdom’s commitment under the Kyoto Protocol very difficult to achieve since they participate in the diversity of power supply. They submit that the cost to the economy of allowing BE to fail would far outweigh the price of its restructuring and that the aid is necessary.

(186)

The anonymous third party submits that BE is using the State support in order to aggressively gain market share at dumped prices. It quotes cases where BE allegedly offered prices 10 to 15 % below competition. It submits that such offers could not be sustained without State backing, and can therefore not be claimed to restore the company's viability.

(187)

TVO submits that it should not be inferred from the difficulties undergone by BE that nuclear power cannot be competitive in a liberalised electricity market.

(188)

National Grid Transco submits that the present capacity margin in England and Wales is smaller than originally foreseen, and cannot be considered as structural overcapacity. National Grid Transco refers to 20 % security margin as the level above which one may consider there to be overcapacity. National Grid Transco foresees that the security margin will be below 20 % until at least 2006, in an optimistic scenario. Pessimistic scenarios would see security always below 20 %, even declining to 8,5 % in 2009. National Grid Transco concludes that if any plant closure was to be requested as a compensatory measure, it would need to be communicated to the markets well in advance (three to four years) in order to allow the market to compensate for it.

(189)

EECL submits that all electricity generators (not only BE) have been hit by low wholesale electricity prices in the United Kingdom. EECL disputes the UK authorities’ view that SRMC should be the benchmark to establish the distortive effect of the aid, as these costs do not reflect a plant’s medium to long term viability. EECL submits that low forward market prices are the best indicator that there is structural overcapacity on the market.

IV.   COMMENTS FROM THE UNITED KINGDOM ON THE INITIATION OF PROCEEDINGS

(190)

The UK authorities informed the Commission that local taxes were finally paid with normal interest.

(191)

As a preliminary comment, the UK authorities argue that even in the event that the Commission concludes that Measure B contains aid, the way the contracts are conceived ensures that any consequential benefit temporarily enjoyed by BE will automatically be eliminated with interest if the aid package is not authorised. The new contracts foresee that the new contracts will not take permanent effect if the aid package is not authorised.

(192)

The United Kingdom further comments on the private investor test. The United Kingdom submits that BNFL acted in the same way as any private creditor would. In particular the UK authorities argue that it cannot be said that the terms agreed by BNFL are more generous than those which would have been granted by a private creditor in comparable circumstances. The United Kingdom submits that it is necessary to analyse whether BNFL acted in a similar way to private creditors in renegotiating its contracts as defined by the Court of Justice in its judgment in DM Transport (31).

(193)

The United Kingdom argues that the Commission appears to have misunderstood the course of events. According to the UK authorities, BNFL did not resist the invocation of the hardship clause but, contrary to the Commission’s belief, had expressed itself willing to consider the possible amendments of the existing contracts prior to the announcement that BE had entered into negotiations with the UK Government. However following discussions with BE it became clear that no commercial offer which BNFL was reasonably able to make would be capable of resolving BE’s financial crisis in isolation. The development of a wider restructuring plan enabled the negotiations between BE and BNFL to restart and agreement was reached on terms which had many similarities to BNFL’s original offer. The United Kingdom considers that BNFL’s actions are consistent with those of a private creditor.

(194)

The United Kingdom adds that BNFL, as the only remaining commercial UK provider of nuclear fuel cycle services, would be particularly exposed in the event of BE’s insolvency; it would have no immediate income stream for the storing or reprocessing of the large quantities of AGR fuel already delivered to it and limited prospects of recovering much in the insolvency. It would have had to renegotiate a new spent fuel agreement with the liquidator or the Government with considerable uncertainty about the level of its ongoing remuneration. Faced with the same risk, disruption and uncertainty, the United Kingdom submits that a private creditor would undoubtedly have sought to participate in a restructuring that would necessarily have included the renegotiation of its contracts with BE with to a view to maximising the overall revenues and to ensuring BE’s viability was restored.

(195)

Furthermore, the United Kingdom submits that the fact that BNFL is publicly owned does not mean that BNFL’s actions were any less commercial as a result. It notes that BNFL is a public limited company incorporated under the Companies Act 1985. It has a board of directors consisting of executives engaged in its commercial activities and non-executive directors with corporate experience from other private sector activities. The board of BNFL has a duty to act autonomously in the interests of the company. The United Kingdom adds that the UK Government did not intervene to direct BNFL’s decision-making to encourage it to act other than commercially.

(196)

Finally, the United Kingdom has submitted an analysis of the creditor’s claims and the amounts compromised under the restructuring package.

(197)

The UK authorities conclude that Measure B should be considered as not containing State aid.

(198)

The United Kingdom submits that many of the same arguments set out in recitals (191) to (197) with respect to Measure B apply equally to Measure C. In particular the United Kingdom argues that it is necessary to consider the actions of BNFL in the context of its exceptional position as BE’s principal creditor, and with BE as BNFL’s largest customer. In view of the on-going long-term trading relationship between the two and the amount of BE’s liabilities to BNFL it is unsurprising that the standstill of liabilities to BNFL accounts for the largest absolute share of the benefit accruing to BE by virtue of the standstill arrangements. A private creditor in the same position as BNFL, with the greatest exposure in the event of BE’s insolvency, would have little option but to act similarly.

(199)

The United Kingdom also submits that it is wrong to contrast the standstill arrangements of BNFL on the one hand with those of all the other private creditors on the other. Without the participation of any significant creditor, the arrangements as a whole could not work. The United Kingdom submits a comparison of all BE’s outstanding debts with each party’s contribution to the standstill agreements and concludes that BNFL is actually contributing less as a percentage of its outstanding liabilities than most of the privately-owned creditors.

(200)

The UK authorities submit that paragraph 32 of the guidelines does not require the aid measures to be of limited duration. It requires that the restructuring plan be as short a duration as possible and that long-term viability be restored ‘within a reasonable time-scale’. According to the United Kingdom the intention of the guidelines appears to be that the grant of aid must be once-and-for-all and that it must not constitute ongoing operating aid. The intention is not to exclude aid to relieve long-tail liabilities.

(201)

The United Kingdom submits that the restructuring will be complete, that viability will be restored within a reasonable timescale and that the aid is once-and-for-all, even though BE’s liabilities are long-tail liabilities. BE will be cash generative from 2004 and will have positive annual operating cash-flows from 2005. Under the Re-listing scenario BE returns to viability in 2005. The restructuring plan is intended to secure that BE will stand alone without further support in the form of facilities from the UK Government from the date of restructuring; The restructuring plan demonstrates that this level of reserves generated by the company is sufficient to withstand reasonable downside scenarios and hence ensure viability.

(202)

On the issue of ongoing relief of current expenditure, the UK Government recalls that the Government’s undertaking covers only contracted historic liabilities, decommissioning liabilities and uncontracted liabilities associated with historic AGR spent-fuel, all PWR spent fuel and operational waste and other ancillary liabilities. The United Kingdom submits that contracted historic spent fuel liabilities relate to AGR fuel loaded into reactors prior to the restructuring effective date. BE has an obligation under the nuclear site licence to manage that fuel and consequently incur costs in so doing. These costs can therefore not be avoided.

(203)

A similar argument applies to the decommissioning of sites. BE will for these costs make contributions towards the decommissioning of the reactors to the Nuclear Decommissioning Fund and contribute consequently significantly to the overall decommissioning costs.

(204)

As far as the uncontracted liabilities associated with historic AGR spent fuel are concerned, the United Kingdom submits that these liabilities relate solely to AGR fuel loaded into reactors before the Restructuring Effective Date. The liabilities associated with PWR spent fuel concern all liabilities associated with PWR fuel loaded into the Sizewell B reactor. For the future liabilities BE will contribute GBP 150 000 for every tonne of PWR fuel loaded into Sizewell B after the Restructuring Effective Date. The level of contribution has been benchmarked against comparable international costs for spent fuel management with a view to covering all the future costs of PWR fuel. The remaining uncontracted liabilities relate to various types of non-fuel waste associated with the operation of BE’s plants and are not expected to be significant.

(205)

The costs of decommissioning and uncontracted liabilities are largely fixed and there is little scope for BE to increase them significantly through normal station operation. Besides any material increase in liabilities arising from a discretionary change in operating procedures for BE’s economic benefit or resulting from a breach of a minimum performance standard will have to be paid by BE. In addition, it is important to note that even if the Government directly pays for BE’s contracted liabilities, the Government support for decommissioning and uncontracted liabilities is in the form of a contingent guarantee. The United Kingdom submits that Measure A should not, therefore, be categorised as an ongoing relief of current expenditure. The accounting treatment of Measure A, which is accounted for in BE’s balance sheet as an asset, is consistent with this conclusion. BE is not in receipt of an on-going subsidy because Measure A is in no way related to the on-going operations of BE and the costs covered by Measure A will need to be borne irrespective of the duration and scale of BE’s future operations.

(206)

As to Measure B, the United Kingdom does not accept that it constitutes State aid.

(207)

The United Kingdom also submits that it is inappropriate to view Measure A as objectionable on the ground that it relieves BE from part of its ‘polluter pays’ obligations. Under the restructuring plan BE will be paying for pollution costs from future operations. In addition it will be contributing towards historic pollution costs through the cash sweep and its other contributions to the NLF. Without the Government’s undertaking, BE would have become insolvent and would have been unable to pay any future ‘polluter pays’ obligations.

(208)

The United Kingdom reacts further to the doubts expressed by the Commission in its decision to initiate proceedings on the question as to whether the restoration of viability of BE can be considered as mainly deriving from internal resources. The United Kingdom explains that the main reason for BE’s current predicament is its inability to meet unavoidable historic liabilities and regulatory and minimum safety requirements. Notwithstanding this the United Kingdom submits that the internal measures taken by BE are not insignificant. It has sold its stake in Bruce Power and in Amergen and is undertaking significant internal restructuring which will include the […]. It has also increased the proportion of medium term fixed price contracts, including with large industrial and commercial customers, with a view to limiting price risks in the wholesale market. In addition the most significant internal measures are its renegotiation of the fuel supply and spent fuel management contracts with BNFL.

(209)

Finally the United Kingdom considers that the guidelines require a balance to be struck between State contributions, private contributions and the company’s own contribution but does not mean that the company must be able to turn itself around without intervention from the State.

(210)

After having recalled why it is not possible to quantify precisely the costs of the nuclear liabilities, the UK authorities submitted that it is not necessary in this case to know the precise quantum of aid or to determine which measures amount to aid to reach a view on whether the package is the minimum necessary. The Government’s undertaking, covering defined categories of liabilities, is fundamental to the Restructuring Package and the restoration of BE’s viability. The UK authorities argued that the level of aid to BE is structurally minimised by the sale of assets (Bruce Power and Amergen), the reduction of liabilities owed to creditors, continued contribution by BE to the funding of its nuclear liabilities, other internal measures to reduce costs, and the mechanism by which BE will contribute in the future by 65 % of its free cash flow to the funding of its nuclear liabilities.

(211)

The UK authorities recalled the arguments presented in the notification according to which the aid has no impact on the competition structure since it has no impact on BE’s short run marginal costs which determine the day-to-day operations of a station. They recalled, based on updated data and comparisons with other Member States, that the market is not in structural overcapacity and claimed that, consequently, no compensatory measure should be imposed.

V.   COMMENTS FROM THE UNITED KINGDOM ON COMMENTS FROM INTERESTED PARTIES

(212)

In their comments, the UK authorities concentrate on those observations which take issue with their position, while noting other observations which support their position.

(213)

The UK authorities first recall their reasoning regarding BE’s SRMCs and their position according to which the aid package would have no effect on competitors. The argument is further supported by figures on BE’s offers on the DSB market, which show that BE has no incentive not to maximise its profit by pricing at marginal cost. The UK authorities continue by noting that BE has no incentive to leave plants on the market that could not recover their avoidable costs. In this respect, they present cost analysis aimed at proving that the Dungeness B plant does cover its avoidable costs with reasonable assumptions on electricity market prices.

(214)

The UK authorities go on to recall their view on the fact that there is no structural overcapacity on the market. They indicate that Powergen had demothballed plants for winter 2003-2004, which would indicate that Powergen itself considers that there is no structural overcapacity on the market. The UK authorities recall their view on the absence of necessity of compensatory measures and give their view on each of the measures proposed by Powergen.

(215)

The UK authorities then recall their position on Measures B and C and stress, in particular, that BNFL based itself on external advice. They claim that Powergen’s position on these measures are based on wrong assumptions on dates.

(216)

On viability, the UK authorities contest Powergen’s opinion regarding BE’s plant’s reliability and have submitted to the Commission a report from external consultant for the purpose of checking viability hypothesis.

(217)

Finally the UK authorities state, contrary to what is claimed by Powergen, that if electricity prices did recover, the clawback mechanism would ensure that no unnecessary aid wasgiven to BE.

(218)

The UK authorities do not accept Greenpeace’s view that the aid should be examined as aid to shareholders. Such a theory would mean that any aid to a quoted company would be an aid to its shareholders. The UK authorities note that BE’s shareholders give up 97,5 % of their interest in BE’s equity capital.

(219)

The UK authorities again state that they do not consider that BNFL acted under Government pressure when renegotiating its contracts with BE and note that BNFL’s own detailed accounts of events, which were sent to the Commission in parallel, would demonstrate the opposite. The extract from BE’s 2002/2003 Report, and the article in ‘The Business’, referring to the collapse of talks between BNFL and BE in August/beginning September 2002 are wrongly interpreted by Greenpeace as a sign that BNFL acted later under pressure from the Government. On the contrary they would show that BNFL was not ready to participate in BE’s plans without other creditors bringing similar contributions. The UK authorities note that BNFL had already submitted the internal documents that Greenpeace suggested the Commission require from it. Concerning the contracts between BE and BNFL which according to Greenpeace are designed to provide BNFL with a guaranteed income stream, the UK authorities note that most of these contracts were signed or renegotiated after BE was privatised and that therefore these contracts could not have been imposed on BE by the Government. Finally, the UK authorities indicate that the link between BNFL’s concession and electricity prices is proof that BNFL behaved commercially, by requiring BE to share some of the possible benefits with it and not the opposite.

(220)

The UK authorities recall their view on the application of the polluter pays principle to this case. They consider that Greenpeace did not add any new fact or argument in this respect.

(221)

Regarding the impact of the aid on competition, the UK authorities first object to Greenpeace’s view that the effect of the aid package is to maintain an inefficient producer in the market. BE cannot be considered as an inefficient generator since its avoidable costs are among the lowest on the market. Its problems are only linked to historical liabilities. Furthermore, the UK authorities recall their view that the aid does not distort competition, and therefore does not deter any entry to the market.

(222)

The UK authorities state that Greenpeace’s comments on overcapacity on the market were flawed because they were based on outdated forecasts, they wrongly interpreted NGTransco’s benchmark for capacity margin, they used wrong figures for present capacity margin, they envisaged only the more optimistic of the three possible scenarios for the future, and they ignored the difficulties in returning certain mothballed plants to the market.

(223)

The UK authorities go on to question the economics of Greenpeace’s arguments on the impact on the taxpayer of the possible closure of BE’s plants. They explain that Greenpeace itself acknowledged that this closure would increase electricity prices. Furthermore, a study by Deloitte and Touche showed that the early closure of a single nuclear power plant could incur additional costs. The early closure of more than one plant would bring even more costs because of constraints in the Sellafield plant that is used for the treatment of radioactive material. Finally, the UK authorities mention that both reports attached to Greenpeace’s comments (by Large & Associates and ILEX) are based on outdated capacity figures from NGTransco and overoptimistic hypotheses. They attach to their comments a counter expertise on the reports, by George Yarrow and Tim Keyworth of DKY Limited.

(224)

Finally, on the basis of the foregoing, the UK authorities challenge Greenpeace’s view that the aid is not proportionate.

(225)

Firstly, the UK authorities challenge Drax’s view that the aid package shows that the UK Government will never allow BE to fail. They recall that the package is subject to the approval by the Government of BE’s prospects for viability.

(226)

Concerning Measure A, the UK authorities recall that the UK Government will not assume all BE’s decommissioning liabilities but will only make up the shortfall in the NLF. On the issue of the estimate of the costs in Measure A, the United Kingdom notes that requiring that there be absolutely no uncertainty in their computation would make it impossible to grant relief for such long term liabilities, which would lead to a perverse application of State aid rules and go against the objectives of the Euratom Treaty. The UK authorities also dismiss Drax’s claim that the fact that the UK Government bears ultimate responsibility for nuclear safety under international agreements constitutes a State guarantee, and recall that the National Audit Office’s ultimate involvement in this respect is irrelevant since it is independent from the Government.

(227)

Concerning Measure B, the UK authorities note that BNFL’s observations contradict Drax’s opinion that BNFL would fare as well if BE was insolvent. They also recall that the renegotiation of BNFL’s agreements with BE was done at arm’s length. Concerning Measure C, the UK authorities indicate that the absence of payment of interest by BE to BNFL during the standstill is to be analysed as a part of the whole involvement of BNFL in the restructuring plan rather than a single element, since the whole package was negotiated together. As a whole, the package does not disfavour BNFL as compared to other BE creditors.

(228)

Concerning Measure G, the UK authorities recall that they had previously put forward proof that business rates had been finally paid by BE, with due interest.

(229)

On the compatibility of the restructuring plan with the guidelines, the UK authorities challenge Drax’s view that the plan will not restore BE’s viability because BE will not cover all its present avoidable and non avoidable costs. The United Kingdom recall that for BE to survive, it is necessary that part of the burden of the past, the unavoidable costs, be lifted from it. But as soon as it is, BE will become viable again since it will not only be able to repay all its ongoing costs but also to bring a significant contribution to its unavoidable costs of the past. It is therefore economically more efficient to run BE’s nuclear plants in order to get some contribution to the payment of unavoidable costs of the past. Advancing the closure of BE’s plants would actually bring more costs.

(230)

The UK authorities reject Drax’ argument that the aid will induce BE to sell into the market at any price. They claim that, as a baseload generator, BE has no generation in reserve that it could sell in addition by cutting price. On the contrary, its interest is to sell its generation at maximum price. BE’s bondholders and shareholders will also ensure that BE does maximise its profit, since they will benefit from part of it.

(231)

The UK authorities also reject Drax’ argument that the restructuring plan is too long in duration. They explain that the actual requirement stemming from the guidelines is that BE’s viability be restored within a reasonable timescale. According to them, the effect of Measure A, which they claim is the only one that constitutes State aid, will appear immediately in BE’s balance sheet.

(232)

Regarding the existence of overcapacity on the market, the UK authorities indicate that Drax’s assessment is based on outdated figures and on an error on the benchmark NGTransco applies for capacity margin. Drax’s suggestion to close nuclear plants in summer would be economically dubious and could also raise nuclear safety or security of supply concerns. The UK authorities then examine each of the four compensatory measures and conclude that putting them in place would either endanger the balance of the restructuring plan or affect BE’s viability prospects.

(233)

The UK authorities explain that the price referred to by the third party (around GBP 1 000/kgU) refers to prices for baseload spent fuel management contracts. Baseload contracts were the first batch of contracts signed by BNFL with BE or companies that now are a part of BE. These contracts were supposed to cover largely fixed costs associated to BNFL’s spent fuel management facilities. Later on, BNFL signed with BE, or companies that now belong to BE, incremental, post baseload contracts that no longer had to include a costs element linked to the repayment of fixed costs. These new contracts were priced […], and therefore at a much lower price than the one quoted by the third party. Any meaningful comparison of prices charged by BNFL to BE before and after the renegotiation of their arrangements would have to be based on post baseload contract prices, which were the ones prevailing at the time just before the renegotiation, rather than on baseload contracts prices.

(234)

The UK authorities do not accept EECL’s claim that the announcement of the aid package has exacerbated wholesale price falls. According to the UK authorities, spot prices were volatile both prior to and after the UK Government’s announcement of its involvement in BE’s rescue on 9 September 2002. They did not however show a sharp fall. As for forward prices, they were relatively unaffected. Finally, forward prices for summer 2004 baseload have increased since September 2003 despite the agreement of the restructuring package.

(235)

The UK authorities then object to EECL’s observation that they wrongly based their conclusion on the premise that BE would decide whether to close its nuclear plants by examining their SRMCs rather than their avoidable costs. The UK authorities did examine the impact of the aid package on BE’s avoidable costs and proved that these remained well below forward market prices, which is the right basis for an operator to decide not to close a plant.

(236)

Finally, the UK authorities recall their arguments on the absence of overcapacity on the market.

(237)

The UK authorities object to Intergen’s view that appropriate security of supply could be achieved even if BE was insolvent via a security arrangement with the receiver. The UK authorities go on to note that the guidelines do not foresee any type of monetary compensation of the type Intergen suggests it should receive. Finally, as regards the various types of arrangements between BE and its creditors, including, inter alia, Intergen, TFE and Centrica, the UK authorities indicate that these are complex arrangements that were all negotiated commercially prior to the restructuring. They are unrelated to the State aid package.

(238)

The UK authorities have submitted quantitative information aimed at showing that BE’s prices in the DSB segment have been consistently above forward wholesale prices, and that BE secured less than 20 % of the business for which it tendered, which goes against the third party’s allegation that BE offered unduly low prices. The UK authorities go on to recall that they consider that BE, as a baseload producer, has no incentive to offer artificially low prices.

VI.   ASSESSMENT

(239)

At least part of the measures in question concern issues covered by the Euratom Treaty and therefore have to be assessed accordingly (32). However, to the extent that they are not necessary for or go beyond the objectives of the Euratom Treaty or distort or threaten to distort competition in the internal market, they have to be assessed under the EC Treaty.

1.   Euratom Treaty

(240)

The measures under review, and notably, measures A and B, would have an impact on the funding of nuclear liabilities and the treatment of spent fuel. Decommissioning and waste management constitute costs which are necessary for a correct and responsible operation of the nuclear industry. In the context of nuclear industry, the need to address the risks linked to the dangers arising from ionising radiations constitute one of its major priorities. In fact, the Commission notes that these two aspects of the nuclear chain are becoming increasingly important and necessary to ensure the safety of workers and of the population.

(241)

In this particular regard, the Euratom Treaty, takes due care of this objective while at the same time, aiming at creating the ‘conditions necessary for the development of a powerful nuclear industry which will provide extensive energy sources…’. These objectives are further reiterated in Article 1 of the Euratom Treaty, which establishes that ‘it shall be the task of the Community to contribute to the raising of the standard of living in the Member States (…) by creating the conditions necessary for the speedy establishment and growth of nuclear industries’. The relevance of this objective today has been underlined in the recent Green Paper of the Commission ‘Towards a European strategy for the security of energy supply’ (COM (2002) 321 final of 22 June 2002). Furthermore, Article 2(b) of the Euratom Treaty provides that the Community, in order to perform its task, shall establish uniform safety standards to protect the health of workers and of the general public and ensure that they are applied. Article 2(e) of the Euratom Treaty also provides that the Community shall make certain, by appropriate supervision, that nuclear materials are not diverted to purposes other than those for which they are intended. On this basis, the Euratom Treaty establishes the Euratom Community, foreseeing the necessary instruments and attribution of responsibilities to achieve these objectives. In this regard, and as confirmed by the Court of Justice, nuclear safety is a Community competence which must be linked to the protection against the dangers arising from ionising radiations, laid down in Article 30, Chapter 3 of the Euratom Treaty, relating to Health and Supply (33). The Commission, must ensure that the provisions of this Treaty are applied and can therefore adopt decisions in the manner provided for in this Treaty or deliver opinions if it considers it necessary.

(242)

The Commission notes that the evidence provided by the UK authorities shows that the effect of the measures under review are, amongst others, to preserve the safety of nuclear power stations, to ensure the safe management of the nuclear liabilities, to enhance security of supply by maintaining diversity of fuel sources in Great Britain as well as to avoid carbon dioxide emissions. Sections III and IV above detail the arguments brought forward by the UK authorities and by third parties in this respect.

(243)

When assessing this information and notably in determining as to whether these measures are necessary or fall within the objectives of the Euratom Treaty, the Commission notes that the state aids and measures are addressing the risks linked to the current situation of British Energy and its eventual impact on the referred objectives of the Treaty. In fact, the UK authorities have decided to intervene in support of British Energy, inter alia, with a view of ensuring the continuity of the conditions for a safe and secure nuclear industry, whereas at the same time maintaining in functioning the nuclear plants as an extensive energy resource. This intervention has taken place in a context of risk of bankruptcy of the major UK nuclear operator. The continuity of a specific economic operator is not directly linked to the continuity of its nuclear activities. However in a case of insolvency, safety and security and/or security of supply issues have to be dealt with. The Commission therefore understands that the UK authorities have addressed these risks in a correct and responsible manner in a way which is compatible with the objectives of the Euratom Treaty.

(244)

The three compensatory measures that will be described below even further reinforce the fulfilment of the Euratom Treaty objectives by ensuring that the public intervention will not be used for other purposes that than payment of nuclear liabilities. Finally, a system of cap and threshold for the three types of historic liabilities payment will ensure that enough funds are available for the fulfilment of these goals, while restricting the intervention to the minimum necessary for their achievement.

(245)

The Commission concludes that the measures foreseen by the UK authorities are appropriate to address the combination of objectives pursued and which are fully endorsed by the Euratom Treaty.

2.   Aid in the sense of Article 87(1) of the EC Treaty

(246)

According to Article 87(1) of the EC Treaty, State aid is defined as aid granted by a Member State or through State resources in any form whatsoever which distorts or threatens to distort competition by favouring certain undertakings or the production of certain goods and affects trade between Member States.

(247)

It is obvious that the State’s intervention in BE’s restructuring plan is selective, since it favours only one undertaking.

(248)

Electricity is traded between the UK and other Member States via interconnectors to France and Ireland. Electricity has been traded between Member States for a long time and in particular since the entry into force of Directive 96/92/EC of the European Parliament and of the Council of 19 December 1996 concerning common rules for the internal market in electricity (34). According to figures sent by the UK in the notification, BE is the second largest electricity producer in capacity in England and Wales, and the third in Scotland. The State’s intervention in the restructuring plan may therefore clearly affect trade between Member States.

(249)

Among the seven restructuring measures, three: Measure D (Significant creditors restructuring package), Measure E (the new trading strategy) and Measure F (Assets disposal) do not derive from public resources. They can therefore not be qualified as State aid under Article 87(1) of the EC Treaty.

(250)

Measure A, in contrast, derives from public resources since it consists of a number of payments or undertakings to make payments by the UK Government. Since the payments from the UK Government will take over part of the Nuclear Liabilities that BE should normally have borne, Measure A also provides an advantage to BE. Taking into account all the above, the Commission concludes that Measure A is State aid within the meaning of Article 87(1) of the EC Treaty. This is not disputed by the United Kingdom.

(251)

Measures B and C involve resources from BNFL (totally for Measure B and partly for Measure C), which is a publicly owned undertaking. Resources belonging to a publicly owned undertaking are State resources. In view of the above, Measures B and C are State aid within the meaning of Article 87(1) of the EC Treaty if and only if they provide a competitive advantage to BE and the granting of this advantage is imputable to the State. Since this question was raised in the decision to initiate procedings, it will be analysed in depth in section VI(2)(b) below.

(252)

Measure G also involves resources from local authorities. Resources from such authorities constitute State resources. Measure G is therefore State aid within the meaning of Article 87(1) of the EC Treaty if and only if it provides a competitive advantage to BE and the granting of this advantage is imputable to the State. Since this question too was raised in the decision to initiate proceedings, it will be analysed in depth in section VI(2)(a) below.

(a)   On the existence of aid in Measure G

(253)

The UK authorities proved that local taxes addressed in Measure G were paid by BE with interest computed with the use of the reference and discount rate prescribed by the Commission for the United Kingdom. There is no specific provision in UK law that would require the use of any higher interest rate in the event that local taxes are deferred by local authorities. The Commission therefore considers that the rate that was used is a proper benchmark for deciding whether the tax deferral provides a competitive advantage to BE. In view of the above, the Commission concludes that Measure G does not constitute State aid within the meaning of Article 87(1) of the EC Treaty.

(b)   On the existence of aid in Measures B and C

(254)

In its decision to initiate proceedings, the Commission stated that ‘at this stage of its assessment, the Commission thinks that the renegotiation of the contracts between BNFL and BE can be considered as being State aid’. This was based on the fact that BNFL, a publicly owned company, announced that it was willing to amend the commercial terms of its existing contracts with BE only once BE had announced that it had initiated talks with the UK Government with a view to obtain financial support. It seemed doubtful that these contracts were renegotiated at arm’s length. The Commission came to the same preliminary conclusions as regards Measure C.

(255)

Using the data that was made available to it since the initiation of proceedings, the Commission has carried out a more in depth analysis as to whether Measures B and C met the criteria to be considered as State aid, and in particular whether they entailed a competitive advantage to BE. It came to the following conclusions:

(256)

Measure B consists of the renegotiation of contracts between BNFL, a publicly owned company, and BE. The Commission has examined whether Measure B confers an advantage on BE that no private operator would have conceded to this ailing firm in similar circumstances. In other words, the Commission has considered whether BNFL acted in conformity with the market economy creditor principle when agreeing to Measure B.

(257)

For this purpose, the Commission has in particular examined whether the renegotiation of BNFL’s contracts with BE were done at arm’s length and whether the concessions made by BNFL were of a commercial nature.

(258)

The first question the Commission has to consider is whether the new arrangements between BNFL and BE were negotiated at arm’s length. It has to be recalled that BNFL is BE’s largest single creditor and that BE is BNFL’s biggest customer. The Commission has therefore examined whether the conditions accepted by BNFL could have been accepted by a private operator put in a similar position. Within the context of a supplier faced with the difficulties of its major customer, this consists in checking whether BNFL acted as a diligent private creditor trying to maximise the chances of recovering its claims (35).

(259)

The Commission has examined the relevant reports of BNFL’s legal and financial advisers and extracts of BNFL’s board meetings, which were submitted by BNFL.

(260)

First, the Commission notes that BNFL already asked its advisers to consider its position vis-à-vis BE at the beginning of 2002, when BE first invoked the hardship clause of its agreements with BNFL. It was not possible to reach the definitive conclusion that the conditions of the hardship clause were indeed fulfilled, but its board instructed BNFL to consider the possible deals which would address BE’s difficulties, under the ex plicit condition that any deal must be commercially advantageous for BNFL.

(261)

The reports submitted by BNFL, that were written at that time, illustrate the particular situation of BNFL as a creditor and supplier of BE and analyse the impact of BE’s insolvency on BNFL. They conclude that in view of the great exposure of BNFL, a solvent restructuring would be in BNFL’s best interests, but not at any cost. They therefore define a proposed package of concessions to BE, and follow the evolution of this package during the negotiations with BE. It is clear from these reports that during these negotiations, BNFL always kept its initial idea which was to try and best preserve its interest by avoiding that BE be put under administration, but not at all cost, and within a balanced deal.

(262)

The UK authorities have submitted that BNFL’s renegotiated agreements must be seen as a package, and compared with the position BNFL might have been in if BE had become insolvent, rather than picking out individual elements. The reports submitted by the UK authorities and by BNFL conclude that the Final Term Sheets are more advantageous to BNFL than any insolvency scenario.

(263)

In view of the above, the Commission has come to the first conclusion that, in case of insolvency of BE, BNFL would be put in a very uncertain and most likely disadvantaged situation.

(264)

It is true that BE insolvency would not automatically mean that all its nuclears stations would be immediately closed nor would affect completely the need of decommissioning of existing stations and the management of historical spent fuel.

(265)

But in the case of an insolvency of BE, the Commission considers that BNFL would have been in a more difficult position to negotiate to whoever would be BE’s successor, either for running the stations or for decommissioning them. This would have implied a lot of risks and uncertainties, that a private investor has to take into account when considering the renegotiation of arrangements, in particular with its main client. The fact that BNFL’s advisors studied carefully this alternative gives a clear indication that BNFL took due account of these facts.

(266)

Trying and achieve a solvent restructuring of BE was therefore indeed the commercial interest of BNFL.

(267)

After having established this initial conclusion, the Commission considered the impact of the renegotiated agreements on BNFL revenues in view in particular of third parties’ comments, in order to check in more microeconomic terms whether these renegotiated agreements could have been accepted by a private company in a similar position.

(268)

As far as spent fuel management is concerned, spent fuel obligations are split between historic and future liabilities.

(269)

As far as the historic spent fuel liabilities are concerned, under Measure A of the restructuring plan, the UK Government will take over all these liabilities from BE (36).

(270)

Concerning future spent fuel management, the existing arrangements were amended. BNFL has submitted the following table concerning the new spent fuel management arrangements which shows that BE will pay BNFL on a sliding scale. The data in italics have been added by the Commission:

Table 7

New spent fuel management arrangement prices

Outturn electricity price (38) in GBP/MWh real 2003 terms

Unit amount of (rebate)/surcharge in GBP/MWh real 2003 terms

(in comparison with the original contracts)

Net unit amount of spent fuel payment in GBP/MWh real 2003 Terms

Payment in GBP/kgU (37)

14,8 and below

– 0,6

[…]

15

– 0,5

16

0

17

0,5

18

1

19

1,5

20

1,75

21 and above

2,0

(271)

It is important to note that the rebates and surcharge in Table 7 are in comparison with the arrangements for the management of spent fuel that were in place just before the restructuring, and not with older arrangements. This is the right benchmark for the analysis of BNFL’s concessions to BE, since this represents what BNFL would have received from BE had BE not run into difficulties. In contrast, comparing the new arrangements with older contracts, like the initial, baseload, contracts to which the first anonymous third party refers, would make no sense in terms of analysing the actual concessions made by BNFL during the negotiation of the restructuring plan.

(272)

Table 7 shows that if the outturn electricity price is less than the strike price of GBP 16/MWh, BNFL will grant a rebate to BE in comparison with the pre-restructuring spent fuel management arrangements. If the electricity price is greater than the strike price, BNFL will be paid a surcharge in comparison with the payments it received under the original spent fuel management arrangements.

(273)

As observed in recital (270), the income BNFL receives for the management and disposal of future spent fuel is dependent on wholesale UK electricity prices. Such a disposition cannot be construed by itself as non-commercial. It is rather usual in the sector, where actors want to share the risks linked to the large potential fluctuations in prices.

(274)

In order to check whether these price levels could have been accepted by a private company, the Commission checked to which extent they would allow BNFL to cover its avoidable costs in view of the foreseen evolution of electricity prices. Indeed, where faced with the likelihood of losing such a crucial customer as BE is for BNFL, a private company would be ready to go as far as decreasing its prices down to those costs that it could avoid by closing its operations. These costs are precisely the avoidable costs.

(275)

In this case, under the new spent fuel management arrangements, BNFL will receive title to the spent fuel when it is delivered by BE. This means that final disposal of this fuel will have to be handled by BNFL, which was not the case under the previous arrangements (39). Since this is an additional charge for BNFL as compared to previous arrangements, one cannot simply rely on the comparison between previous payments and new payments and conclude that BNFL recovers its avoidable costs as soon as electricity wholesale price exceeds GBP […]/MWh. On the other hand, the new spent fuel arrangements do not prescribe the way BNFL must handle the spent fuel to which it has title. BNFL can choose whether it wishes to reprocess the fuel before final disposal or not.

(276)

A further analysis is necessary, based on the actual avoidable costs for BNFL, including charges for final spent fuel disposal.

(277)

The Commission asked the UK authorities to provide it with a detailed description of these costs. Documentation provided by the UK authorities in this respect indicates that BNFL will cover its avoidable costs as soon as electricity prices are above a GBP […]/MWh to GBP […]/MWh range, depending on whether BNFL allows for risk provisions. The slight difference with the GBP […]/MWh figure in recital (275) is mainly due to the fact that ponds for long term storage already exist in BNFL’s site, and are presently in use for storage of fuel prior to reprocessing. […]

(278)

In order to cross-check this evaluation, the Commission has compared avoidable costs as computed by the UK authorities with costs reported by another source.

(279)

Greenpeace has published on its web site a report by Gordon MacKerron of National Economic Research Associates (40). This report quotes figures of USD 200/kgU (GBP 110/kgU (41)) for the temporary storage of spent fuel, and USD 400/kgU (GBP 220/kgU)for its final storage. According to the author of the report, they were extracted from an American study (42). There are many differences between the American types of reactors (primary LWR ones) and BE’s ones. Furthermore, it is not clear from the report whether the costs to which it refers are avoidable costs or include fixed costs elements, which would be out of the scope of the following analysis. They are also very dependent on discount rates since most ultimate disposal costs will be incurred far in the future. The Commission has used these figures nonetheless because it considered that figures published by a third party were a relevant source for the cross checking of figures sent by the UK authorities.

(280)

In view of the figures stated in recital (279), the electricity price above which BNFL could recover its costs would be GBP […]/MWh. These figures must now be compared with the anticipated evolution of electricity prices.

(281)

The proper benchmark for this comparison is the development of electricity prices now and in the future as expected by BNFL when the new arrangements between BNFL and BE were negotiated. It is indeed against that potential background that BNFL assessed the value of its concessions to BE.

(282)

From the documents provided by BNFL, it appears that the general expectations were that prices would stay in the range of GBP 16/MWh to GBP 19/MWh in the near future, and then raise to higher, more sustainable values.

(283)

In its assessment of the final terms of the plan, BNFL used four possible scenarios. Only the most pessimistic of them featured electricity price values staying consistently below GBP 17/MWh, reaching only values of around GBP 16,5/MWh in the medium term. The three others assumed that these prices would reach values around GBP 18/MWh as soon as 2007, and then gradually reach prices ranging from around GBP 19,5/MWh to GBP 23/MWh.

(284)

BNFL’s assessment of the renegotiation of its arrangements with BE was therefore done against a background of price evolution forecasts that were such that, even in the most pessimistic assumptions, prices would enable it to recover its avoidable costs as valued internally, and that in all but the most pessimistic scenario, prices would enable it to recover its avoidable costs as valued by Gordon MacKerron.

(285)

The actual evolution of electricity prices was finally higher than even the most optimistic of all four scenarios used by BNFL. Indeed, various price reporting agencies have reported values above GBP 20/MWh for winter baseload prices in the near future, even reaching figures as high as GBP 27/MWh (43). As far as summer prices are concerned a value of around GBP 20/MWh has been reported by the same agencies. The scenarios used by BNFL were therefore globally rather pessimistic.

(286)

One can conclude from this that BNFL expected to be able to cover its avoidable costs under the new arrangements, despite the fact that it would bear the costs of final disposal of spent fuel.

(287)

Similarly, the analysis of the new fuel supply arrangements, which are much simpler since they contain a variable charge that is not indexed on electricity prices, show that BNFL will cover its avoidable costs for fuel supply in all cases.

(288)

An in depth examination of avoidable costs therefore reveals nothing to suggest that BNFL acted uncommercially. To the contrary, the actual evolution of electricity prices suggests that BNFL may very well improve its position as compared to the previous situation, while at the same time having shown enough flexibility to allow its main customer to remain in the market.

(289)

After having examined the renegotiation from a microeconomic point of view, the Commission has checked whether BNFL was treated on an equal footing with that of private creditors of BE. In this second step of analysis, the Commission has examined whether the concessions made by BNFL are similar to those of the private creditors.

(290)

The information submitted by the United Kingdom and BNFL show that:

(a)

even if BNFL established terms with BE prior to the negotiation by BE of individual terms with each of its major creditors, it required the inclusion of a clause allowing the withdrawal of the suggested concessions in the event that any other material creditor was offered more favourable terms than BNFL;

(b)

in the whole negotiation process, BNFL always checked that other private BE creditors would be asked to contribute in a comparable way to that of BNFL;

(c)

detailed quantified comparison of the creditors’ claims and the amounts compromised under the finally agreed restructuring package shows that relative to other creditors, BNFL has forgone a smaller proportion of outstanding liabilities. It must be also noted in this respect that BNFL had no security of its debt over any of BE’s assets.

(291)

Therefore, the Commission concludes that BNFL was treated on an equal footing vis-à-vis the private creditors. This further indicates that BNFL did not behave differently in the restructuring plan negotiation than private creditors.

(292)

The Commission considers that the conclusion above gives sufficient proof that BNFL acted in conformity with the market creditor principle, and that therefore Measure B does not involve State aid within the meaning of Article 87(1) of the EC Treaty.

(293)

Moreover, the Commission considers that in the present case there is no indication whatsoever of the imputability of BNFL's behaviour to the State. The imputability condition was recalled by the Court of Justice of the European Communities in its judgment in Stardust (44). As the Court held, it cannot be automatically presumed that a measure is a State aid because it was taken by a public undertaking. It is not sufficient that the body granting the aid is a public undertaking within Article 2(1)(b) of Commission Directive 80/723/EEC of 25 June 1980 on the transparency of financial relations between Member States and public undertakings (45). The fact that the public authorities may exercise directly or indirectly a dominant influence does not prove that they actually exercised that influence in a given case. As explained by Advocate General Jacobs in his opinion on the Stardust case (46), the imputability to the State of an aid measure taken by a public undertaking may be inferred by a set of indicators from the circumstances of the case and the context in which the measures were taken. The Advocate General gives a list of facts and circumstances which could be taken into account in his view such as the evidence that the measure was taken at the instigation of the State, the scale and the nature of the measure, the degree of control which the State enjoys over the public undertaking in question and a general practice of using the undertaking in question for ends other than commercial ones or of influencing its decisions.

(294)

On the basis of the submissions of the UK Government and of third parties, the Commission has examined whether Measure B (and Measure C) could be attributable to the conduct of the State. It took into account the fact that BNFL decided well before BE’s financial distress was publicly announced and well before the UK Government announced its role in a potential solvent restructuring that it was in its best interests to make concessions to ensure the ongoing solvency of BE. From a chronological point of view, there is no evidence that the renegotiation took place at the instigation of the State. On the contrary, the fact that BNFL did not finally accept to participate in the restructuring plan before the UK Government announced its involvement can be viewed as proof that BNFL was not ready to save BE at any cost, and would preferred to wait for the intervention of the State, like all other creditors did.

(295)

The Commission also took into account that according to UK law it is the fiduciary obligation of BNFL’s directors to act in the best commercial interests of BNFL in order to maximise value and minimise financial exposure on the basis of the information available to them at the relevant time. This is substantiated by the relevant extracts of Board meetings minutes available to the Commission.

(296)

On the basis of all the above elements, the Commission concludes that Measure B does not constitute State aid within the meaning of Article 87(1) of the EC Treaty.

(297)

Measure C consists in standstill agreements concerning payments due by BNFL and a number of significant financial creditors of BE for a period starting on 14 February 2003 and ending at the earliest on 30 September 2004. Unlike other participating creditors, BNFL will not receive interest during the standstill period.

(298)

On the basis of the information available, the Commission notes that BNFL’s financial advisers’ reports, which were drawn up at the time BNFL was negotiating with BE, conclude that in its share of the restructuring package, BNFL has not conceded more overall than other creditors, as is shown by a comparison of each significant creditor’s contribution. As mentioned in recital (290), BNFL had no security over any of BE’s assets.

(299)

Furthermore, the Commission concludes that agreeing not to demand the payment of interest in order to preserve the agreed solvent restructuring option is conform to the behaviour of a private creditor aiming to ensure that the best possible commercial option available is preserved. The analysis of BNFL’s financial and legal advisers shows that demanding the renegotiation of the standstill conditions would have put at risk the whole of the agreements with BE and, above all, the solvency of BE as such. The risk would have been significant in that demanding the payment of interest would have led to BE’s insolvency, which BNFL thought would not be favourable to its interests. In renouncing to these interests, BNFL has acted in in a manner consistent with the conduct of a private creditor wishing to ensure the best revenue possible.

(300)

To conclude, the Commission could not establish that the part of Measure C involving BNFL was imputable to the State, for the reasons set out in the assessment of Measure B in recitals (256) to (296).

(301)

The Commission has therefore come to the conclusion that Measure C does not contain State aid within the meaning of Article 87(1) of the EC Treaty.

3.   Compatibility assessment under the EC Treaty

(302)

Article 87(1) of the EC Treaty provides for the general principle of prohibition of State aid within the Community.

(303)

Article 87(2) and 87(3) of the EC Treaty provide for exemptions to the general incompatibility set out in Article 87(1).

(304)

The exemptions in Article 87(2) of the EC Treaty do not apply in this case because the aid measures do not have a social character and are not granted to individual consumers, they do not make good the damage caused by natural disasters or exceptional occurrences and they are not granted to the economy of certain areas of the Federal Republic of Germany affected by its division.

(305)

Further exemptions are set out in Article 87(3) of the EC Treaty. Exemptions in Articles 87(3)(a), 87(3)(b) and 87(3)(d) do not apply in this case because the aid does not promote the economic development of areas where the standard of living is abnormally low or where there is serious underemployment, it does not promote the execution of an important project of common European interest or remedy a serious disturbance in the economy of a Member State, and it does not promote culture and heritage conservation.

(306)

Only the exemption in Article 87(3)(c) of the EC Treaty may therefore apply. Article 87(3)(c) provides for the authorisation of State aid that is granted to promote the development of certain economic sectors, where such aid does not adversely affect trading conditions to an extent contrary to the common interest.

(307)

In the guidelines, the Commission spelled out the preconditions for a favourable exercise of its powers of appreciation according to Article 87(3)(c) in cases such as this one.

(308)

In its decision to initiate proceedings, the Commission expressed a number of doubts on the compatibility of the restructuring plan with the guidelines. These doubts were recalled in section 3) above. The following sections present the assessment and the final conclusions of the Commission on each of those doubts.

(a)   On the restoration of BE’s viability

(309)

The award of restructuring aid requires a feasible, coherent and far reaching restructuring plan capable of restoring the long-term viability of the firm within a reasonable time span and on the basis of realistic assumptions. According to point 32 of the guidelines, the improvement in viability must derive mainly from internal measures contained in the restructuring plan and may be based on external factors such as variations in prices and demand over which the company has no influence if the market assumptions made are generally acknowledged.

(310)

Point 33 of the guidelines require the Member State to submit a restructuring plan describing the circumstances that led to the company’s difficulties and considering scenarios reflecting best-case, worst-case and intermediate assumptions. Point 34 of the guidelines adds that the plan should provide for a turnaround that will enable the company after completing its restructuring to cover all its costs including depreciation and financial charges. The expected return on capital should be enough to enable the restructured firm to compete in the market place on its own merits.

(311)

In its decision to initiate proceedings, the Commission raised several issues in relation to the restoration of viability of BE. These doubts were based on two observations. Firstly, the time span of certain items of Measure A and of Measure B seemed unlimited, which raised doubts as to whether the restructuring plan would allow BE to become able to face competition again on its own feet within a reasonable time frame. Secondly, it seemed that the restructuring plan did not include enough measures internal to BE.

(312)

The doubts of the Commission related in particular to Measures A and B. In view of the long duration of Measure A and the open ended nature of Measure B, the Commission wondered whether the restructuring aid in favour of BE was not awarded in the form of an on-going subsidy which would be contrary to the requirements of the guidelines. This concern was shared by third parties such as Drax.

(313)

As far as Measure B is concerned, the Commission came to the conclusion that it does not contain state aid in the sense of Article 87(1) of the EC Treaty. Consequently, the issue related to the open ended nature of Measure B is no longer relevant.

(314)

As regards Measure A, the Commission was concerned that the costs related to the decommissioning of the nuclear plants could arise until 2086 and that the financing of the costs associated with the management of PWR spent fuel loaded into the Sizewell B reactor of BE was also open-ended.

(315)

Concerning the decommissioning costs, the Commission notes that these costs will occur in the future but relate to the construction of nuclear plants which took place in the past. The Commission accepts the UK argument that it is not possible to quantify precisely the amount relating to decommissioning in view of the absence of precedent for AGR plants and the fact that it will be done in the distant future with possible technological evolution. In addition, the UK Government submits that decommissioning costs are already largely fixed and that any material increase in liabilities arising from a discretionary change in operating procedures for BE’s economic benefit or resulting from a breach of minimum performance standard will have to be paid by BE. In addition it is important to recall that the intervention of the State is foreseen in case of shortfall of the funding through the NLF.

(316)

Taking into account the particular nature of the nuclear industry that does not allow the handling of radioactive material before its radiation rate has reached safer levels and the inevitable time-scale of financing the decommissioning liabilities, the Commission concludes that part of Measure A relating to those liabilities cannot be qualified as on-going subsidy to BE since they are defined and relate to costs already incurred. A provision for these costs has already been made in BE’s balance sheet. The Commission concludes further that the late payment of the aid linked to these costs cannot be viewed as postponing the restoration of viability to the future.

(317)

Concerning the financing by the State of the management of PWR fuel loaded into Sizewell B, the Commission recalls that BE will contribute to the NLF in the amount of GBP 150/kgU for PWR fuel loaded into the Sizewell B reactor after the Restructuring Effective Date.

(318)

This value is certainly lower than the total costs of PWR spent fuel management, including final disposal. Indeed, this total cost was estimated by BE itself in its 2001/2002 accounts at GBP 240/kgU. The fact that only a part of these costs are covered by the BE payments to the NLF confirms that the NLF contribution to the management of this fuel contains State aid within the meaning of Article 87(1) of the EC Treaty.

(319)

In order to decide whether this aid is open-ended, the Commission must determine the split of the total costs between avoidable costs and unavoidable costs.

(320)

Unavoidable costs are sunk. It is thus economically rational for a company to operate as long as it can cover its avoidable costs, so that as much sunk cost as possible can be repaid. Granting aid for unavoidable costs therefore clearly gives an advantage to the beneficiary company in that it shifts its breakeven point. For companies facing difficulties, it aims precisely at helping them to return to viability more quickly. But since the company would operate in any case as soon as it cover its avoidable costs, aid to cover unavoidable costs does not result in artificially prolonging the life of the company. Such aid is therefore not open ended.

(321)

In contrast, aid aimed at covering avoidable costs, in particular variable costs, aims at artificially maintaining in operation a company that would otherwise have no economical reason to prolong its activities. Such aid is open-ended in that it ensures the company’s viability only if it is not limited in time.

(322)

The UK authorities have indicated that, out of the GBP 240/kgU costs referred to in recital (318), about GBP […]/kgU were avoidable. The remaining costs are mostly related to the unavoidable costs linked to the construction of the final repository for both historic and future PWR spent fuel, which will be done on the Sizewell B site. This repository is scheduled to be available late in this century, which, in view of the discounting effects, explains the relatively small value of these costs as compared to costs in other countries.

(323)

The figures provided by the Gordon MacKerron report referred to in footnote 38 cannot be used for the purpose of cross checking this estimate since the report does not indicate the extent to which they include unavoidable costs.

(324)

In order to cross-check the UK authorities’ evaluation, the Commission has used information available to the public concerning the Finnish nuclear programme, which is one of the most transparent nuclear programmes in the world. Like Sizewell’s waste, the waste produced by Finnish nuclear reactors will not be reprocessed before it is ultimately disposed of. The costs of the management of Finnish spent fuel is estimated by the Finnish company in charge of the disposal at EUR 325/kgU (GBP 217/kgU (47)), of which EUR 217/kgU (GBP 145/kgU) are related to avoidable costs (48).

(325)

The Commission notes that these figures are similar to the ones provided by the UK authorities. The Commission considers that they confirm the indication that a GBP 150/kgU payment is sufficient to cover avoidable costs of spent fuel management, plus a part of the unavoidable costs thereof.

(326)

In view of the above, the Commission concludes that the restructuring plan does not provide for an on-going subsidy to BE and that its duration is compatible with the guidelines in view of the specificities of the nuclear industry and the obligations of the UK under the Euratom Treaty (49).

(327)

The Commission notes that the UK Government has submitted a detailed plan containing a market survey and scenarios reflecting best-case, worst-case and intermediate assumptions, as required by point 33 of the guidelines. They have in addition provided a detailed cash-flow analysis updated in July 2004.

(328)

The plan describes in detail the origin of BE’s difficulties and the measures which have been or will be introduced to address these as already summarised in paragraph II(2)(c) of this Decision. The restructuring plan foresees the implementation of a new trading strategy (Measure E) seeking to address the unhedged position of BE. In securing more medium term fixed price sales of its output, BE aims at reducing the volatility of cash flows and reinforce its long-term viability. It will also reduce its exposure to wholesale electricity prices in the United Kingdom whilst continuing to maintain a reliable route to market through a mixture of contract terms, access to flexible generation through Eggborough and the Direct Sales to Business focusing on I & C consumers. Measures A and B aim at addressing the issue of the high proportion of non-avoidable costs faced by BE as a nuclear operator in partly relieving BE from its historic nuclear liabilities including historic spent fuel liabilities and decommissioning costs and in reducing its costs for future front end and back end fuel contracts with BNFL. In addition, the plan foresees the renegotiation of three out-of-money purchase agreements and the sale of BE’s North American assets which should contribute to solving BE’s problem linked to high shorter term non-avoidable costs in the form of financing expenses. As regards the third cause of BE’s difficulties, the significant unplanned outages, BE has defined a plan, the PIP, designed to improve the reliability of BE’s nuclear plants. In particular, the PIP foresees an increased investment in capital and staff to improve the quality of maintenance and the availability of its plants. Furthermore one of the vulnerabilities considered is the scenario where the availability of BE’s plants’ does not improve. Under that scenario, BE would still be cash generative.

(329)

The financial projections submitted by the UK Government indicate that viability would be restored within a reasonable time-scale since BE would be cash generative from 2004 and would have positive annual operating cash flow from 2005.

(330)

On the basis of the above, the Commission concludes that the restructuring plan addresses the problems at the origin of BE’s difficulties and is based on realistic assumptions as required by the guidelines, in particular in view of the evolution of electricity prices and the implementation of the PIP.

(331)

In its decision to initiate proceedings, the Commission doubted whether the restoration of viability could be considered as deriving mainly from internal measures. In particular, the Commission wondered whether the economies realised by BE following those measures were only due to concessions by creditors and suppliers and not any rationalisation of BE’s activities.

(332)

Following the opening of proceedings, Drax commented on this point. It is of the opinion that BE’s restructuring is not a real restructuring since it does not derive from internal measures and gives BE the guarantee that it will never be allowed to fail. Besides it adds that there is some uncertainty about BE’s contribution to the restructuring and that closing some nuclear plants would have been a better option. This last comment is shared by Greenpeace. The United Kingdom contests this view and replied that the package is subject to the approval by the Government of BE’s prospects for viability. The UK Government also made the point that the guidelines require a balance to be struck between State contributions, private contributions and the company’s own contribution but do not mean that the company must be able to turn itself around without intervention from the State.

(333)

The Commission accepts that the restructuring must not only be based on internal measures but can also include measures from the State and private parties such as creditors and suppliers. The Commission notes that BE has already implemented the following measures: it disposed of its North American assets (Measure F) and […]. From a commercial point of view, the Commission takes note of the fact that in line with its new trading strategy (Measure G), BE has increased the number of medium term fixed contracts to reduce its unhedged position. Furthermore, BE is not released of its nuclear liabilities but will contribute to the funding of the NLF.

(334)

As explained in section VI(3)(c)(v) below, the Commission also takes into account the fact that the closure of one or several BE nuclear plants is not a feasible option and that disposing of Eggborough would threaten BE’s prospects of returning to viability and would be disproportionate.

(335)

Considering the measures already undertaken and to be undertaken by BE and taking into account the fact that the issues at the origin of BE’s difficulties are addressed by the restructuring plan, the Commission concludes that the requirement of point 32 of the guidelines is fulfilled.

(336)

Some third parties have questioned in particular the prospects of return to viability of Dungeness B, which is the oldest of BE’s nuclear plants.

(337)

Powergen, the third party which best substantiated its reasoning, based its analysis of Dungeness B’s situation on a review of the power plant’s cost structure as originally submitted by the UK authorities, and set out in the decision to inititate proceedings.

(338)

According to Powergen, Dungeness B is a very inefficient power plant. Historic figures show that its load factor is small. Powergen estimates it at 46 %. With such a load factor, the power plant would produce about 4,5 TWh per year. According to Powergen producing this amount of electricity would cost about GBP 73,8 million, taking into account avoidable costs only. Powergen concludes that Dungeness B’s avoidable costs are about GBP 16,4/MWh where the electricity baseload price on the wholesale market is GBP 16/MWh (50).

(339)

In their comments on Powergen’s analysis, the United Kingdom authorities gave their own view on Powergen’s counter analysis of Dungeness B’s viability. According to the UK authorities, there are two mistakes in Powergen’s analysis. Firstly, Powergen’s hypothesis on the plant’s total costs was too low. BE’s data suggests that actual Dungeness B costs are higher than was estimated by Powergen, in particular for operation and maintenance costs. This tends to increase Dungeness B’s costs per MWh.

(340)

In contrast, the UK authorities consider that Dungeness B’s efficiency record has much improved in recent years. They claim that, since historical data show it is improving, one should not take for the future the hypothesis that it will perform like it did in its worst years, but rather that it will perform like it did in the most recent years. This would raise the power plant’s load factor to 61 %. This tends to decrease Dungeness B’s costs per MWh.

(341)

Taking into account both considerations in recitals (339) and (340), the UK authorities calculate Dungeness B’s avoidable costs as approximately GBP […]/MWh where the electricity baseload price on the wholesale market is GBP […]/MWh.

(342)

The Commission has examined Dungeness B’s avoidable costs, taking into account different hypotheses, depending on which estimates are correct for total costs and load factor. It has arrived at the following matrix:

Table 8

Dungeness B’s avoidable costs per MWh where the electricity baseload price on the wholesale market is GBP 16/MWh.

 

UK authorities’ hypothesis for output

Powergen’s hypothesis for output

UK authorities’ hypothesis for costs

[…]

[…]

Powergen’s hypothesis for costs.

[…]

GBP 16,4/MWh

(343)

Taking into account the sharing of the benefit of electricity price increases where the electricity baseload price on the wholesale market differs from GBP 16/MWh between BE and BNFL, the Commission has computed the electricity strike price above which Dungeness B covers its avoidable costs in the different hypotheses:

Table 9

Electricity baseload price on the wholesale market above which Dungeness B covers its avoidable costs

 

UK authorities’ hypothesis for output

Powergen’s hypothesis for output

UK authorities’ hypothesis for costs

[…]

[…]

Powergen’s hypothesis for costs.

[…]

GBP 16,8/MWh

(344)

In view of Table 9, it appears that in all but the worst scenarios, Dungeness B is able to recover its avoidable costs, and is therefore not loss making, as soon as the electricity baseload price on the wholesale market is above about GBP […]/MWh. This strike price corresponds to baseload electricity prices on the wholesale market, which, as was shown in recitals (282) to (285), is now reported as sometimes being well above GBP 20/MWh, and was in any case always expected to range between 16 and GBP 19/MWh even in the short term during which Dungeness B will remain operational. Furthermore, the Commission notes that, with present electricity prices, Dungeness B is able to cover its avoidable costs even under the most pessimistic scenario.

(345)

The Commission therefore considers that Dungeness B is a viable asset.

(b)   On the question whether the aid is restricted to the minimum necessary

(346)

In its decision to initiate proceedings, the Commission expressed doubts as to whether the aid was restricted to the minimum necessary, because the State aid nature of Measure B, C and G was not established, and because the exact amount of aid in Measure A was not fixed.

(347)

The Commission notes that it concluded in sections VI(2)(a) and VI(2)(b) above that Measures B, C and G do not constitute State aid within the meaning of Article 87(1) of the EC Treaty. The aid package is therefore restricted to Measure A only.

(348)

Measure A includes State aid aimed at meeting three categories of liabilities: the management of historic spent fuel, the management of uncontracted liabilities, and the decommissioning of nuclear power plants. At the time of the initiation of proceedings, the liabilities linked to each of these three categories, and consequently the State aid attached to them, was only estimated, but not capped.

(349)

Liabilities linked to the management of spent fuel represent the largest share of the total liabilities. They consist in the payment to BNFL of management services for fuel loaded in BE’s reactors prior to the restructuring plan’s effective date. These services are already contracted, and the amount owed by BE to BNFL in this respect is well defined in most circumstances.

(350)

For this reason, the Commission still considers that the extent to which these liabilities could be funded by the UK Government should be capped. The UK authorities have therefore accepted to turn their original estimate for these liabilities, namely GBP 2 185 000 000 (51) into a cap for the aid linked to such liabilities.

(351)

In contrast, liabilities linked to the decommissioning of nuclear power plant and to uncontracted liabilities are difficult to quantify precisely.

(352)

The decommissioning of nuclear plants is a very specific activity. There is little experience world wide of totally completed work in this field (52). Experts indicate that such costs may be 15 % of the total investments costs or more (53), or 50 % of the nuclear part of the investment (54). Even if such estimates proved completely consistent and accurate, one would need to compute the exact original investment costs in a power plant in order to estimate its decommissioning costs, which would be particularly difficult for old power plants like BE’s, for which costs history is very imprecise.

(353)

Furthermore, most of BE’s plants are AGR plants, which are not only different from plants existing in other countries, but also to a certain extent different from each other. One can therefore not expect to build on experience acquired either in other countries or in the United Kingdom to improve the accuracy of BE’s reactors’ decommissioning costs estimate.

(354)

Similarly, uncontracted liabilities are by their very nature difficult to determine. They relate mostly to the final disposal of spent fuel. The manner in which nuclear fuel will be finally disposed of in the United Kingdom remains uncertain, as the experience of the Nirex Intermediate Level Waste repository has shown. Experience in other countries has also shown that finding places to dispose of certain types of waste can be both technically and politically challenging. It is very hard to quantify with sufficient precision the cost of an activity where so little information is available as to how it will be achieved. Information forwarded by the UK authorities also shows that estimates of storage costs by institutions of other Member States may vary drastically.

(355)

In view of the above, the Commission considers that trying to determine a maximum cost for decommissioning and uncontracted liabilities would only be possible with a large margin of error. There would be a serious risk of overestimating that value.

(356)

This is why, in this case, the Commission considers that setting a highly uncertain and probably overestimated value as a cap for the aid would actually go against the minimum aid necessary requirement, as uncertainty margins may, where they do not materialise, turn into scope for granting unnecessary aid.

(357)

A much better way to ensure the fulfilment of the minimum necessary principle would consist in not trying to compute a cap for the aid but, rather, setting up a mechanism aimed at ensuring that future expenditure will be restricted to the minimum.

(358)

The UK authorities have therefore undertaken to put in place a series of mechanisms in this respect. In particular:

(a)

categories of liabilities the cost of which can be taken over by the State will be precisely defined;

(b)

the UK authorities will closely monitor these costs via the Nuclear Decommissioning Agency (NDA); This monitoring will be both ex ante and ex post;

(c)

decommissioning activities will be tendered by the NDA, which will ensure that costs are kept to market standards;

(d)

the NDA activities themselves will be ultimately controlled by the UK Department of Trade and Industry and the National Audit Office;

(e)

to further strengthen the Commission’s control on the spending, the original aggregate estimate of both liabilities (e.g. GBP 1 629 000 000 (55)) will be used as a threshold. Should the cumulated expenditure linked to the two liabilities exceed this threshold, the Commission will receive enhanced reporting both on payments made to meet liabilities costs and on steps taken to minimise these costs. This report shall be based on analysis carried out by independent accounting experts.

(359)

It could be possible that some very limited payments due by BE to BNFL in the framework of spent fuel liabilities exceed their original estimate. This is the case in particular where some spent fuel elements do not conform to specification and require special treatment. Indeed, in such a case, existing arrangements contracts between BE and BNFL allow the normal spent fuel management price to be increased. Should this happen, amounts to be paid by the State to discharge BE from these liabilities in excess of the original estimate would be counted against the GBP 1 629 000 000 threshold mentioned above, without that threshold being altered.

(360)

For the purpose of computing the amounts referred to in recitals (350) and (358), the Commission considers that the normal Commission reference rate should be used. Nevertheless, given the length of the period concerned the reference rate should be adapted every five years (56).

(361)

It is important to note that the cap and threshold referred to in recitals (350) and (358) apply to all expenditures made to meet liabilities, be they funded by the NLF or by the State. This means that the cap and threshold mechanism will automatically take account of moneys available in the fund.

(362)

Finally, the restructuring package also contains a tax disregard with respect to the increase of the accounting value of BE’s power plants due to the fact that part of the liabilities that are attached to them will be paid for by the UK Government. Since these liabilities used to be laid down in BE’s accounts, their partial and potential relief by the UK Government’s undertaking increases their value by an amount potentially up to the maximum value undertaken by the UK Government.

(363)

Under normal UK accounting and financial rules, this increase should be taxable. Its disregard by the Government is therefore a potential competitive advantage for BE within the meaning of Article 87(1) of the EC Treaty. However, the potential taxation would decrease BE’s ability to fund the liabilities itself, which would in turn increase the UK Government’s actual liabilities. Hence, all or part of the State aid element in the tax disregard may be offset by the increase in the final funding of the liabilities to be met by the Government. The actual State aid element in the tax disregard is only equal to that part of the disregard that is not offset by the increase of payments to be made by the UK Government to honour its undertaking to meet the nuclear liabilities.

(364)

This increase in power plant value is only artificial, since the liabilities will still remain until the UK Government undertaking is called for, and to the extent that it is actually available, and will have to be met as much as possible by the NLF to which BE contributes. Furthermore, should the Government have paid for the shortfall in liability funding in another way or at another time, for example through ad hoc grants paid at the time the liabilities were actually incurred, it is possible that no tax disregard would have been necessary.

(365)

In view of the above, the Commission considers that the State aid element in the tax disregard does not go beyond what is necessary for the aid to meet the restructuring objective.

(366)

Finally, the Commission notes that any increase in BE’s profits, like in the case of an increase of electricity prices, will largely be destined to finance BE’s contribution to the NLF. Such increase in BE’s contribution would automatically imply a reduction of the amount of aid.

(367)

The Commission considers that the mechanisms described above will altogether ensure that the State aid contained in Measure A will be reduced to the minimum necessary.

(c)   On the avoidance of undue distortion of competition

(368)

Point 35 of the guidelines provides that ‘measures must be taken to mitigate as far as possible any adverse effects of the aid on competitors’.

(369)

Except in exceptional cases where the size of the relevant market is negligible at Community and at EEA level or the firm’s share of the relevant market is negligible, such measures must be implemented in order for the aid element of a restructuring plan to be compatible with the Common market. They must take the form of a limitation of the company’s presence on the market and be in proportion to the distortive effect of the aid. A relaxation of the need for these measures may be contemplated where they could lead to a manifest deterioration in the structure of the market.

(370)

Where they are necessary, the form and extent of compensatory measures depend on the market capacity position. Where there is structural overcapacity on the market, compensatory measures must take the form of an irreversible reduction of production capacity. Where there is no structural overcapacity, compensatory measures may still be required, but they may take other forms than irreversible reductions of production capacity.

(i)   The relevant market

(371)

Footnote 20 of the guidelines indicates that the relevant geographical market usually comprises the EEA or, alternatively, any significant part of it if the conditions of competition in this area can be sufficiently distinguished from other areas of the EEA.

(372)

Electricity has been traded between Member States for a long time and in particular since the entry into force of Directive 96/92/EC.

(373)

However, electricity trade between Member States is limited by physical constraints due to shortfalls in interconnection capacity. These constraints are all the tighter where geographical limitations further limit the opportunities for the development of new interconnectors.

(374)

Within the framework of trans-European networks policy, the Commission has made a list of such bottlenecks in the internal electricity market. Annex 1 to Decision No 1229/2003/EC of the European Parliament and of the Council of 26 June 2003 laying down a series of guidelines for trans-European energy networks and repealing Decision No 1254/96/EC (57) shows that the United Kingdom is one of those geographical regions that are insufficiently connected to the rest of the network for the single market to function as a whole entity.

(375)

On top of its insulation from the rest of the Community’s electricity network, the United Kingdom’s electricity market is further characterised by its very specific trading system. This specific trading system, known as the New Electricity Trading Arrangements (NETA), is based mostly on bilateral contracts between generators, suppliers and customers, as opposed to more classical pool markets. Conditions of competition on NETA are very different from those on a pool market, as is evidenced by the fact that the transition in the United Kingdom from a pool structure to NETA in 2001 resulted in a large drop in electricity wholesale prices.

(376)

At present, NETA covers only England and Wales. However, the Scottish market is very much linked to NETA via the indexation of electricity prices in Scotland to prices witnessed in England and Wales. Furthermore, NETA is planned to be very soon extended to Scotland. The resulting Great Britain market is due to start operations in 2005. It must be noted though that Scotland will represent only a small part of this market, as installed capacity in Scotland is no more than slightly above 10 % of installed capacity in England and Wales.

(377)

The Northern Ireland electricity market will not be joined to the Great Britain market in the foreseeable future. Indeed, electricity links between Great Britain and Northern Ireland are for the moment weak (its nominal power is 0,5 GW, which represents less than 1 % of the registered installed capacity in Great Britain). Competition conditions in Northern Ireland will therefore remain very different from those in Great Britain.

(378)

In view of the above, and since BE operates only in Great Britain, the Commission considers that the relevant geographical market for the purpose of this Decision is Great Britain (58).

(379)

According to figures submitted by the UK authorities, the total installed capacity in the 15 States that were Members States at the time the restructuring plan was notified is about 565 GW. The total registered installed capacity in Great Britain is about 10 % of that value. Furthermore, the United Kingdom market, of which the Great Britain market represents about 95 %, is one of the largest in the EEA, second only to those of Germany and France. It can therefore not be considered that this market is negligible at Community and EEA level.

(380)

BE’s capacity represents about 14 % of the registered capacity in England and Wales and about 24 % in Scotland. BE can therefore not be considered to have a negligible share of the relevant market.

(381)

To conclude, there are many other actors in the relevant market than BE: BNFL, EDF-Energy, Innogy, Scottish and Southern Electricity, Scottish Power and Powergen to name only a few major ones. Should BE disappear, the relevant market would neither become a monopoly, nor a tight oligopoly.

(382)

The findings above confirm the Commission’s initial market analysis as described in the Decision to initiate proceedings. The Commission notes that none of the third parties that submitted comments questioned these preliminary findings.

(ii)   Capacity situation on the market

(383)

In its decision to initiate proceedings, the Commission made it clear that the assessment of the capacity situation of an electricity market should take account of the physical specificities of electricity, and of the potentially enormous disturbance that electricity black-outs can create both for the economy and for citizens’ everyday life. The assessment of the existence of structural overcapacity should therefore include a sufficient capacity margin such as to allow the satisfaction of peak demand under any reasonable scenario.

(384)

The Commission noted that the capacity margin existed on the relevant market was not particularly high as compared to international standards and to past values. It noted however that there might have been room for a small decrease in that capacity margin as compared to a few other Member States or to values in the United Kingdom in 1995/1996.

(385)

Third parties’ comments as regards the existence of structural overcapacity have focused on the evolution of prices, and on the assessment of the existing capacity margin in Great Britain.

(386)

Some third parties have indicated that there was a link between the evolution of electricity prices and the existence of structural overcapacity on the market. They consider that in such a competitive market as NETA, price plays the role of a signal for the need of new capacity. Where new capacity would be needed at a specific period in the future, the foreseen shortfall in capacity for this period would trigger an increase of corresponding forward prices. Prices would reach such a level as to enable the recovery of new plant construction costs, which would trigger new entry on the market.

(387)

At present, according to these third parties, although they have been increasing in the recent past, prices would not yet have reached a sufficient level to trigger new entry. This would demonstrate that there is overcapacity on the market.

(388)

The Commission acknowledges that there is a relationship between prices on a market and the capacity situation on that market. However, it considers that electricity markets like NETA are too complex to allow a definitive conclusion to be drawn as to the existence of structural overcapacity on the market on the basis only of price observation.

(389)

Firstly, unlike in markets structured around a pool, there is no such thing as a clearing price in NETA. NETA is based around bilateral contracts, that may take very different forms, and that do not always provide very transparent price reporting mechanisms. Power exchanges like UKPX are more transparent, but they do not represent a sufficient share of the market to make it possible to to draw significant conclusions. Furthermore, they focus on short term trade and are hence of limited use for gaining knowledge on future trends. One therefore has to rely on price indexes reported by independent sources like Heren or Argus. These price indexes themselves have their limits, since they represent only the wholesale market, which is about two thirds of the total exchanged electricity, and are therefore unable to catch non extreme shortfalls in foreseen electricity generation.

(390)

Secondly, the reasoning in recital (389) is based on the assumption that forward prices represent faithfully the market situation in the future. The Commission considers this might not always be the case. As a matter of fact, these prices reflect a more complex situation, rather based upon what both the buyer and the seller think their position will be in the future. This means that they are based on expectations on the future market, which can be very far from the reality, since both demand and offer are subject to many fluctuations on this market. In other words, forward prices do not really represent the balance between demand and offer in the future, but rather what current actors think the balance will be. Aside from fuel price fluctuation, this is one of the reasons why forward prices can fluctuate a lot with time, even for a fixed period in the future.

(391)

Thirdly, even if one accepts that reported prices are totally pertinent and reflect faithfully the offer and demand, there is a logical gap between the conclusion that prices do not allow the full repayment of new entrants’ costs and the conclusion that there is overcapacity on the market, and even more so that there is structural overcapacity on the market.

(392)

In view of the above, the Commission considers that the observation of prices alone is not a sufficiently reliable indicator to decide whether an electricity market such as NETA is in a situation of structural overcapacity.

(393)

The Commission notes however that since the time BE encountered difficulties, winter forward prices have very much increased. Various price reporting agencies have reported values above GBP 20/MWh for winter baseload prices in the next few years, even reaching figures as high as GBP 27/MWh (59). The upward trend seems to be continuing and sustainable. New entrant costs estimates range between GBP 20/MWh and GBP 25/MWh (60).

(394)

The Commission trusts that the existence of overcapacity is easier to assess by analysing the actual physical figures of installed capacity and peak demand. The margin by which installed capacity exceeds average cold spell peak demand (61) is known as the system’s capacity margin. In this framework, to assess whether the market is in structural overcapacity means to assess whether the present and foreseen capacity margin is adequate.

(395)

It is obvious that setting a definitive quantitative norm for adequate capacity margin is a very difficult task. The norm would have to depend on a number of parameters that vary from one network to the other. It would also depend very much on the level of security of supply to be achieved, which would in turn be linked to less objective notions, like the psychological impact of a given period without electricity in a specific region.

(396)

Furthermore, even if all physical and psychological parameters were under control, the necessary capacity margin would certainly also depend very much on market structure. Some experts believe that more liberalised markets need less capacity margin than strongly regulated centralised markets, although most agree that quantifying this effect is not possible at present in view of the lack of historical evidence.

(397)

Also, comments by third parties provide different views on the capacity margin that should be adequate for Great Britain. Most of the comments which address this issue quote figures from the England and Wales network operator’s (NGTransco) Seven Year Statements. In these statements, NGTransco states that it considers that a 20 % capacity margin should be the nominal benchmark for planning purposes. It hints though that smaller capacity margin could be possible for real time management of the system, and refers to a possible 10 % figure for such a use.

(398)

Drax and Greenpeace have suggested that this 10 % figure should be used as the proper reference for adequate capacity margin for the purpose of the assessment of the existence of structural overcapacity. Other organisations have preferred to keep the reference to the 20 % figure, including institutes commissioned by Greenpeace to provide reports on the subject (62).

(399)

In its own observations, NGTransco made it clear which of the two figures it considered should be used for the purpose of assessing the existence of structural overcapacity, by stating ‘In our role as System Operator for England and Wales, we would consider that any plant margin below the 20 % level can not represent overcapacity within the England and Wales market’.

(400)

In view of the above, the Commission considers that the 20 % level is a proper benchmark to assess the capacity situation in the England and Wales market. Although the Scotland market will soon be joined to the England and Wales market, it is still very much physically segregated from it. The 2 200 MW interconnection between the two regions is too small to allow a completely flexible use to balance each region’s lack or excess of power. As a matter of fact, it is nearly always used for export of energy from Scotland to England and Wales. Because of this major constraint, the Commission considers that the 20 % benchmark should be increased while considering the global Great Britain figures.

(401)

The England and Wales market is by far the largest geographical segment of the Great Britain market. It is also the segment on which most of the economical data are set, since prices in Scotland are set in line with the England and Wales data. The vast majority of third parties’ comments also concentrate on the England and Wales segment. The Commission has therefore begun its analysis of the market with this segment.

(402)

Historical experience has proven that the interconnector between the two segments was nearly only used for export from Scotland to England and Wales. NGTransco considers this interconnectors’ capacity as a source of power for England and Wales. Conversely, Scottish Power, which is the Scottish operator responsible for the part of Scotland that shares a border with England, considers the interconnection’s capacity to be dedicated to export. In view of the above, and to be consistent with both past experience and the hypothesis put forward by the local operators, the Commission will consider in the rest of this Decision that the England and Wales/Scotland interconnector’s capacity is attributed to England and Wales.

(403)

There is only one network operator for the whole of England and Wales: NGTransco. The Commission has based its analysis of the capacity situation on this segment on NGTransco’s forecast, which are published periodically in the company’s Seven Year Statement.

(404)

Since the opening of proceedings, NGTransco has revised its forecast for capacity margin in the England and Wales market. A new forecast was sent to the Commission with NGTransco’s submission. An even newer version of the same forecast has been published by NGTransco in its 2004 Seven Year Statement (63).

(405)

The Commission used this later newer version for the purpose of its analysis. Indeed, this newer version is based on the same fundamental hypothesis, in particular for input data, as that taken in the forecast that was considered as relevant by NGTransco in its submission to the Commission. It only incorporates more up to date input on market development.

(406)

This forecast envisages three scenarios. The most optimistic scenario (SYS background) assumes that generation availability will correspond to signed transmission contracts. The most pessimistic scenario (‘existing or under construction background’) assumes that no plants other than existing ones and plants currently under construction will be available. The intermediate scenario (‘consents background’) assumes that available plants will be the existing ones, the ones already under construction and the ones for which necessary consents under the Electricity Act and the Energy Act have already been granted.

(407)

The following chart summarises the forecast in the three scenarios.

Table 10

2004 NGTransco capacity margin scenarios for England and Wales

Scenario

2004/05

2005/06

2006/07

2007/08

2008/09

2009/10

2010/11

SYS background

22

21

23,1

26,8

24,5

25,6

22,5

Consents background

22

21,1

22,8

24,3

21,6

22,5

19,1

Existing and under construction background

22

21,1

18,7

17,1

14,5

12,8

9,5

Note: Capacity margin is over ACS peak demand. Interconnectors with France and Scotland are assumed to be fully used for import.

(408)

The three scenarios differ principally on the latest years, which is not surprising in view of the fact that their underlying hypotheses make differences mainly in the future. However, these years are not as relevant to assess the existence of structural overcapacity at present on the market.

(409)

In the next three years, the three scenarios foresee a capacity margin between 18,7 and 23,1 %, with an average of around 21,5 %. This value is slightly above the 20 % benchmark. However, the difference between 21,5 and 20 % of the ACS peak demand is 1,5 % of 57 000 MW (64), that is, 855 MW. This value is smaller than any of British Energy’s nuclear plants’ capacity. As it is furthermore the result of a statistical average, the Commission considers that it cannot be deemed to be statistically significant enough to represent a structural overcapacity.

(410)

In the following years, the difference between the three scenarios grows, which makes it even more difficult to draw meaningful conclusions from them. However, the Commission notes that during these years the average of the three scenarios fluctuates between 17,0 and 22,7 %, with two years at around 20,2 % This seems to indicate that there is an overall tendency for the capacity margin to stay very much around 20 %, including some margin of error.

(411)

The Commission concludes from the above that there is no structural overcapacity on the England and Wales electricity market.

(412)

In contrast with England and Wales, there are two network operators in Scotland: Scottish and Southern Electricity and Scottish Power. These two operators publish forecasts for their own regional area. These forecasts are however less detailed than NGTransco’s as to possible scenarios for the future. For these reasons, the Commission has concentrated its analysis for Scotland on the present situation, for which there is less need to envisage various scenarios.

(413)

Since neither of the two Scottish operators has submitted comments to the Commission in the context of these proceedings, the analysis is based on documents available to the public. For Scottish and Southern Electricity, the Commission used the figures provided in its 2003 Seven-year Statement (65). For Scottish Power, the Commission used the figures provided in its April 2003 Transmission Seven-year Statement (66).

(414)

The following chart summarises forecast peak demand and installed capacity in the various geographical regions for 2004/2005.

Table 11

Great Britain Capacity and demand forecasts for 2004/2005. All figures are in MW

Capacity connected to Scottish Power’s network

7 127

Capacity connected to Scottish and Southern Electricity’s network

2 844

Capacity connected to NGTransco’s network, excluding interconnectors

63 998

Ireland/Scotland interconnector capacity

500

France/England interconnector capacity

2 000

Available capacity in Great Britain

76 469

Maximum demand in Scottish Power’s zone

4 269

Maximum demand in Scottish and Southern Electricity’s zone

1 684

ACS peak demand in NGTransco’s zone

55 900

Aggregate peak demand (67)

61 853

(415)

Capacity margin for Great Britain is therefore about 23,6 % (68). This figure is higher than the 20 % benchmark referred to in recital (400), but as was noted, the 20 % benchmark that applies to a flexible network such as the one in England and Wales has to be increased to accommodate constraints in networks with bottlenecks. Furthermore, these figures are computed on the hypothesis that both interconnectors with Northern Ireland and France are available at full capacity for imports, which is not always granted. Should these interconnectors be used for export at the time of ACS peak demand, their capacity should be netted of the available capacity, and at the same time added to the power demand, which would decrease the capacity margin to 15,5 %.

(416)

In view of the above, the Commission considers that there is no statistically significant structural overcapacity on the Great Britain market.

(417)

In view of the above, the Commission judges that there is no structural overcapacity on the relevant market.

(418)

Compensatory measures in the form of irreversible reduction of production capacity are therefore not mandatory.

(iii)   Impact of the aid on competition on the relevant market

(419)

Since there is no structural overcapacity on the relevant market, the Commission must assess the necessity of compensatory measures and the form they should take on the case’s merit. Possible compensatory measures must take account of the potentially distortive effects of the aid on competition.

(420)

‘The UK authorities argue that the aid package has no impact on competition. According to them, within NETA, power plants’ economical ability to generate is determined by their short run marginal costs (SRMC). At a given time, the market operates as if power plants were called by their SRMC ranking, from the lowest to the largest, until their cumulated capacity reaches demand. Electricity price at that time is set by the SRMC of the last power plant called, which is known as the marginal power plant.

(421)

According to the UK authorities, the aid is aimed solely at the nuclear plants. It would not change their SRMC to such an extent as to modify their rank in the SRMC order. Furthermore, BE’s nuclear plants’ SRMC would be such that they are at all times below the marginal plant’s SRMC. The aid would never have an impact on BE’s competitors’ ability to generate, nor the price at which they can sell the electricity generated. There would therefore be no impact on BE’s competitors.

(422)

The Commission considers that the UK authorities’ reasoning might hold in a perfect market based on a single totally transparent auctioning process. However, as was explained in recitals (389) and (390), NETA is not such a market.

(423)

The Commission considers that the aid may have an impact on BE’s competitors in many ways. Two of them might have a major impact on competition.

(424)

Firstly, BE does not only own nuclear power plants. It also owns the Eggborough coal fired plant, which is by itself as big as some of BE’s competitors’ total capacity.

(425)

BE could use the aid it receives for its nuclear plants for the benefit of the Eggborough power plant.

(426)

For instance, it could use this money in order to fit Eggborough with flue gas desulphurisation devices that would allow it to comply with new environment regulations, which would in turn extend significantly the plant’s lifetime.

(427)

Alternatively, BE could also use the funds made available by the aid in order to purchase more non-nuclear generation assets.

(428)

Admittedly, BE needs some flexible source of electricity generation to compensate for its nuclear stations’ inflexibility. Whenever the aid allows BE to extend its non nuclear portfolio, it allows it to have more internal access to flexible generation, and therefore increases its possibility to offer better deals to its customers, while at the same time decreasing its need to purchase flexible generation from its competitors.

(429)

Secondly, NETA is not a single market. NETA comprises in particular a wholesale market segment, in which generators sell electricity to suppliers and a direct sales to business (DSB) segment, in which generators sell electricity directly to large end users.

(430)

Generators generally sell electricity on the DSB market with a premium over the wholesale market (69). It is thus preferable for a generator to sell electricity on the DSB market segment.

(431)

While analysing the impact of the aid, one should therefore consider not only the global amount of electricity sold by each generator, but also the spread of its sales on the wholesale and DSB market segments.

(432)

One element of the BE restructuring plan aims to increase the company’s share in the DSB segment. In order to do so, the company will have to try to offer DSB customers a competitively low premium over wholesale electricity prices. BE will be able to finance part or whole of this competitive offer via the decrease in its nuclear plants’ SRMC.

(433)

Therefore, even though BE’s plants’ SRMC ranking might remain the same and hence not have any impact on its competitors’ load, the variation of their level will allow BE to shift part of its sales from the wholesale market to the DSB market. This in turn will shift part of the competitors’ output from the DSB to the wholesale market. In this way, the aid might increase BE’s profits and decrease those of its competitors.

(434)

In view of the above, the Commission considers that the aid has a significant impact on BE’s competitors, and that compensatory measures are necessary to mitigate this impact.

(iv)   Compensatory measures to be implemented

(435)

Compensatory measures must strike a balance between the need to mitigate the impact of the aid on competitors and the need to preserve the beneficiary company’s prospects of viability.

(436)

For this purpose, the Commission considers that compensatory measures should target precisely the mechanisms by which the aid could be detrimental to BE’s competitors.

(437)

This means that compensatory measures in this case should aim at ensuring that BE will not use the aid granted by the Government for the purpose of unduly increasing its flexible generation portfolio or gaining DSB market shares.

(438)

This goal has lead the Commission to ask for three compensatory measures. These compensatory measures were proposed by the UK authorities on the basis of the measures suggested by BE’s competitors in their submission.

(439)

As was explained in recital (437), one way the aid could potentially have a greater impact on BE’s competitors would be if, instead of paying for charges incurred by BE’s nuclear fleet as intended, it was used for the purpose of improving BE’s non nuclear generation capacity.

(440)

This would allow BE to compete with its competitors’ plants more easily (70), and would give it more access to flexible generation than it presently has, which would in turn decrease BE’s need to purchase this flexibility from outside.

(441)

In order to avoid this possibility, BE’s different businesses should be separated into different legal entities with separate accounts.

(442)

For this purpose, BE’s structure should be modified in such a way that nuclear generation, non-nuclear generation, sales to the wholesale market and DSB sales are established in separate subsidiaries. The aid should be attributed solely to the nuclear generation business.

(443)

Cross subsidisation between the various subsidiaries should be forbidden.

(444)

This prohibition should be implemented as much as possible through the companies’ licensing regime and as such monitored by the Great Britain electricity system regulator: OFGEM. However, the Commission recognises that operators’ licences cannot be modified freely by OFGEM, which has a duty to consult third parties on such modifications and take account of comments received.

(445)

Should it not be possible for OFGEM to modify one of BE’s licences in such a way as to forbid cross subsidisation, the UK Government should provide the Commission with a not limited in time undertaking with the same effect. In such a case, in order to further ensure that trade between the subsidiaries does not involve elements of cross-subsidy, the UK authorities should provide the Commission with an annual report displaying evidence that no such cross subsidy has occurred. The report should be based on an analysis by independent accounting experts.

(446)

The UK authorities have undertaken to implement this compensatory measure.

(447)

Compensatory measure No 1 should in principle be sufficient to ensure that BE does not use the aid it receives for its nuclear reactors to improve or enlarge its existing non-nuclear fleet.

(448)

However, in view of the complexity of the electricity sector and in particular of the very large range of possible relationships between the different actors that NETA allows, the Commission considers that it is necessary to enforce other, more specific, measures, to further ensure that BE does not use the aid it receives for its nuclear reactors in other fields of its business.

(449)

Furthermore, although the capacity situation in the market does not make it economically sound to impose capacity reductions upon BE, the Commission judges that BE should nevertheless be required not to increase the scope of its activities.

(450)

In order to cope with those concerns, a series of prohibitions should be imposed on BE as regards its possible expansion in the generation fields where its competitors are active.

(451)

For that purpose, a specific type of capacity should be identified (‘Restricted Capacity’). That capacity is composed of:

(a)

registered operational fossil-fuelled capacity located in the European Economic Area,

and

(b)

registered operational large scale hydro (71) capacity located in the United Kingdom.

(452)

BE should be prohibited, for a period of six year from the date of this Decision, from owning or having the right of control over Restricted Capacity in excess of 2 020MW, which is the capacity of its existing Eggborough (1 970 MW) and District Energy (50 MW) stations.

(453)

The reason for the need to prohibit any increase in BE’s fossil fuel capacity was explained in recital (437). The Commission considers that there is a need to extend the prohibition to large scale hydroelectric stations to avoid any risk that BE might acquire existing large scale hydro stations especially in Scotland.

(454)

The prohibition should last for six years, which is roughly twice the time necessary for the construction of a combined cycle gas turbine power plant.

(455)

The objective of the prohibition is to prevent BE from acquiring more flexibility than it presently has with its Eggborough power plant, which should be sufficient to ensure its viability.

(456)

However, the Commission is aware that, under the restructuring plan, the bank syndicate that provided finance for the Eggborough project will retain the option to purchase Eggborough from BE. Should the banks decide to exercise this option, BE would be deprived of its only source of flexibility, which the Commission recognises is necessary for the success restructuring plan. In this case, BE should be allowed to prepare for the replacement of Eggborough as soon as it receives notice from the banks of their intention to exercise their option.

(457)

For this reason, the Commission considers that there should be some exception to the prohibition in the event that the banks exercise their option, in order to allow BE to acquire a source of flexibility to replace Eggborough, or in the event that Eggborough becomes definitively unavailable for a reason outside BE’s control. This should not however have the ultimate effect of allowing BE to acquire more flexibility capacity than it presently has, nor to use this replacement capacity to make profit during the possible overlap period between the end of its construction and the disposal of Eggborough.

(458)

In view of the above, BE should be allowed to own or have rights of control over more than 2 020 MW of Restricted Capacity, for the period between the date on which it receives the notice from the banks and the date on which Eggborough’s capacity is no longer available to BE, or the end of the six year period referred to in recital (452) if earlier than the date on which where Eggborough’s capacity is no longer available to BE, under the condition that it does not operate the Restricted Capacity in excess of 2 020 MW or that it divests itself of all operational control and interest in that excess Restricted Capacity.

(459)

From the time Eggborough becomes unavailable to BE, either as referred to in recital (458) or after an event of force majeure or an irreparable failure, BE should be allowed to own or have right of control of up to 2 222 MW of Restricted Capacity, under the condition that, until the end of the 6 year period referred to in recital (452), it declares its Restricted Capacity to the network operator as 2 020 MW and does not operate more than 2 020 MW of this capacity. This provision aims at allowing BE to have more flexibility for the replacement of Eggborough, without relaxing the prohibition in practice.

(460)

Finally, on top of the restrictions on Restricted Capacity as defined in recital (451), and in order to respect the philosophy of the guidelines on the necessity not to allow beneficiaries to use the State aid for the purpose of extending their market share, BE should also be forbidden to own nuclear generation assets other than those it presently owns, in the European Economic Area, without prior authorisation by the Commission, for six years following the date of adoption of this Decision.

(461)

The UK authorities have undertaken to implement this compensatory measure.

(462)

As was explained in recital (437), the aid would also be misused if, instead of aiming at covering BE’s nuclear reactors charges, it was used by BE to unduly acquire shares in the more profitable DSB market.

(463)

The sensitivity of this potential misuse is particularly demonstrated by the content of the comments sent to the Commission by a third party that wished to remain anonymous (72). Even if BE does not actually offer prices abnormally below market standards, the very suggestion that it might be able to do so thanks to the aid could also be harmful for BE’s competitors, since they would have to face customers with commercially incorrect expectations.

(464)

The Commission therefore considers that it is necessary to reinforce the guarantees already offered by Compensatory measure No 1 by a more specific compensatory measure aimed at BE’s behaviour on the DSB market. BE should be required not to act on this market in ways that are not similar to its competitors’ standard.

(465)

To ensure this, BE should be forbidden to offer prices below the prevailing wholesale market prices on the DSB market. The duration of this measure should be six years from the date of this decision, as for Compensatory measure No 2.

(466)

The compliance of BE with the prohibition should be monitored by an independent body to be selected via a transparent tendering process organised by the UK authorities. The independent body should report annually to the Commission.

(467)

In the past, DSB market prices have always followed the evolution of wholesale market prices with a premium. This prohibition will therefore ensure that BE does not behave commercially in a different way from that of its competitors.

(468)

However, NETA is only three years old. It is not impossible that, in the upcoming 6 years, the relationship between the DSB and the wholesale market could during some times differ from what has been experienced until today. One could imagine for instance that the wholesale market could become illiquid for some period, which could lead to abnormally high prices on this market. In this case, the Commission considers that in order not to lose their customers, generators would certainly offer prices on the DSB market that would be somewhat below the wholesale market price. If such a thing happened and BE did not have the capacity to react accordingly, it would be likely to lose its customer base on the DSB market, which would put its restructuring goal in peril.

(469)

It is therefore necessary that BE be left some flexibility to accommodate such exceptional events. Its margin of manoeuvre should however be very limited, described in objective terms, and monitored carefully to avoid any abuse. Criteria to allow BE to use its flexibility margin should be testable ex ante in order to avoid any abuse.

(470)

Since there is much less reliable reporting for DSB market prices than for wholesale market prices, it is very difficult to know during a DSB contract round whether DSB market prices will be offered below the wholesale market price. This means that the objective criteria referred to in recital (469) cannot be directly based on checking whether BE’s competitors offer DSB prices under wholesale market prices. Instead, tests must rely on indirect indications that are accessible in the short term to BE, and that could signal that the wholesale market has become illiquid and that pricing at or above the wholesale market price on the DSB market is no longer commercially viable.

(471)

The tests should be the following:

(a)

in any period of […], (ending not more than […] before the date BE invokes exceptional market circumstances) […] of those existing BE non-domestic end-users to whom BE has made offers of supply on terms where the margin on the supply of energy element of the contract over the prevailing wholesale price is […] have rejected BE’s offer;

(b)

volumes traded in the wholesale electricity market over a […] period have dropped to less than […] of the average of those traded in the same period in the last […] for which data is available;

(c)

BE offers to supply a minimum of […] of electricity in the wholesale market […] and that volume is not sold within a period of […] hours.

(472)

The same independent body that monitors the compliance of BE with the prohibition should be responsible for checking whether BE is aware that the tests have been fulfilled. The independent body will verify that test (a) together with either test (b) or (c) is fulfilled. If it is indeed the case, BE should be entitled to price on the DSB market below wholesale market price for […] from the independent body’s decision That time limit may be extended by a decision of the independent body if exceptional market conditions continue to prevail. During the […], BE should be obliged to behave in good faith and offer discounts that are comparable to what it can reasonably consider its competitors offer. The independent body should assess the compliance of BE with this criterion ex post, where the […] is over.

(473)

For the sake of transparency, the independent body should publish a statement at the end of the contract rounds confirming that the exceptional market circumstances actually occurred, and specifying the duration of the period of the exceptional circumstances. Details of the assessment should be forwarded to the Commission.

(474)

The UK authorities have agreed to implement this compensatory measure.

(v)   Compensatory measures that were considered by the Commission but rejected

(475)

The Commission judges that the three compensatory measures described in section 0 are sufficient in scope to mitigate the potentially distortive effect of the aid on competition, and thus meet the requirements of point 39(ii) of the guidelines. They are also to be considered as specific conditions attached to the authorisation of aid within the meaning of point (42)(ii) of those guidelines.

(476)

Other possible compensatory measures had been suggested by third parties.

(477)

Greenpeace suggested that BE’s nuclear plants be closed in a phased process. The Commission considers that in view of the absence of overcapacity on the relevant market, requesting the closure of BE’s generating assets would be disproportionate to the distortion of competition that the aid generates.

(478)

Powergen suggested that the Dungeness B reactor could be closed, since it is the least profitable BE asset. The viability of Dungeness B was already discussed in section VI(3)(a) above. The Commission notes that it is already planned to close Dungeness B in 2008 and that according to data provided by NGTransco on the notice necessary for significant closures, Dungeness B could at best be closed in mid 2007. The Commission considers that such a small shift would not justify the expenses that it would cause.

(479)

Drax suggested to remove BE’s nuclear assets from the competitive market by creating a system of compulsory purchase of nuclear energy at a fixed price that would be similar to the Renewable Obligation. This would mean that BE would become in practice totally and indefinitely assisted by the State which would be in total opposition with the Community competition policy.

(480)

Drax suggested allowing BNFL a greater share of BE’s potential profits if electricity prices grow in order to decrease the amount of aid. As was discussed in section VI(2)(b) above, the Commission came to the conclusion that Measure B did not include State aid elements. Allowing BNFL more of BE’s possible upside would have the effect of increasing the aid since it would decrease BE’s free cash-flow and hence its contribution to the NLF. This cannot be accepted by the Commission.

(481)

Drax suggested that the Eggborough plant should be divested. The Commission acknowledges that the divestment of Eggborough would not run against the necessity to preserve a capacity margin in the electricity system since the power plant would very probably still be operated by its new owner. However, in order to be able to achieve its restructuring plan and restore its viability, BE needs to have access to some source of flexible electricity generation. Should BE sell Eggborough, it would have to acquire this flexibility from outside sources.

(482)

On the basis of trials, the UK authorities came to the conclusion that it would not be economic for BE to purchase the services it gets from Eggborough from other generators. These services consist in insurance against nuclear reactors unexpected failures, power shaping for business contracts and flexibility to meet planned maintenance of reactors. The UK authorities have indicated that BE would save in total GBP 11million a year by keeping Eggborough. This estimate is based on Eggborough’s costs, which means that BE could possibly get the same services at the same costs only by owning another plants. Purchasing the services on the market would be much more expensive, if indeed possible.

(483)

In view of the above, the Commission considers that requiring BE to divest Eggborough would threaten BE’s prospects of returning to viability and would be disproportionate. The Commission judges that Compensatory measures No 1 and No 2 above impose the same type of restriction in a more proportionate way.

(484)

Powergen suggested imposing a cap on BE’s DSB market share. The Commission considers that imposing such a cap would be detrimental to competition on this market. Compensatory measure No 3 will be more efficient in mitigating the impact of the aid on competitors on this market without restricting BE’s ability to offer competitive deals on the market on its own feet.

(485)

Powergen suggested forbidding BE to enter new retail markets. This suggested measure would mostly affect the households’ market, which is at present served only by suppliers. The Commission considers that such a restriction would deprive customers of a possible source of competition in a market which is already the least competitive part of the UK electricity market (73). The Commission considers that Compensatory measure No 1 will be in this respect sufficient to ensure that, should BE wish to enter this market, it would do so on the basis of its own strength, without undue distortion of competition.

(486)

To conclude, the Commission considers that all other compensatory measures suggested by third parties that submitted comments are embedded in the three compensatory measures that were selected by the Commission.

(d)   Full implementation of the restructuring plan

(487)

The company should be required fully to implement the restructuring plan submitted to the Commission. The UK Government committed to ensure full implementation of the restructuring plan if approved.

(e)   Monitoring and annual report

(488)

If the aid package is approved, the UK Government committed to provide to the Commission a report not later than six months after the approval of the Aid Package and thereafter annual reports so that the Commission can monitor BE’s progress until the position has stabilised to a point at which the Commission no longer feels the need for further reports.

VII.   CONCLUSION

(489)

The Commission concludes that, insofar as they fulfil the guidelines in respect of restructuring aid and are in line with the objectives of the Euratom Treaty, the aids in questionnaire compatible with the common market.

HAS ADOPTED THIS DECISION:

Article 1

The aid which the United Kingdom is planning to implement under Measure A of the restructuring plan for British Energy plc (‘British Energy’) notified to the Commission on 7 March 2003, which consists in the undertaking by the United Kingdom Government to fund:

(a)

The payment of liabilities related to the management of spent fuel loaded in British Energy’s nuclear reactors prior to the restructuring plan’s effective date, as long as expenditures related to these liabilities, with the exception of Incremental Historic Liabilities as defined in the Historic Liabilities Funding Agreement between British Energy and the United Kingdom Government, do not exceed 2 185 000 000 GBP in December 2002 value;

and

(b)

Any shortfall of the Nuclear Liabilities Fund as regards the payment of liabilities related to British Energy’s nuclear assets decommissioning, British Energy’s uncontracted liabilities and the Incremental Historic Liabilities as defined in the Historic Liabilities Funding Agreement between British Energy and the United Kingdom Government,

is compatible with the common market and the objectives of the Euratom Treaty, subject to compliance with the conditions set out in Article 2 to Article 10.

Article 2

1.   The United Kingdom shall ensure that the restructuring plan as communicated to the Commission by the United Kingdom is fully implemented.

2.   The United Kingdom shall submit a report on the implementation of the restructuring not later than six months after the present decision and each year thereafter until such time as the Commission informs it that no further reports are necessary

Article 3

As soon as expenditure corresponding to the liabilities referred to in point (b) of Article 1 exceed 1 629 000 000 GBP in December 2002 value, the United Kingdom shall submit enhanced additional reports to the Commission demonstrating that the Government payments are restricted to meeting the liabilities referred to in that point, and that proper steps have been taken to limit expenditure to the minimum necessary to meet those liabilities. Those reports shall be submitted yearly. They shall be appended to the yearly reports referred to in Article 2.

Article 4

For the purpose of computing amounts in December 2002 value referred to in Article 1 and Article 3, the United Kingdom shall use the reference and discount rate published by the Commission for the United Kingdom, updating this rate every five years.

Article 5

1.   The United Kingdom shall require British Energy to undertake by not later than 1 April 2005:

(a)

to extract its electricity supply business from British Energy Generation Limited and incorporate it as a separate subsidiary company of British Energy plc (or successor parents);

(b)

to consolidate the existing nuclear generation activities in a single company;

and

(c)

to use all reasonable endeavours to obtain licence modifications under the Electricity Act 1989 or, if such licence modifications cannot be obtained, to give binding undertakings to the United Kingdom Government not limited in time to the effect that: (i) British Energy shall treat its existing nuclear and non-nuclear generation businesses as separate businesses for licensing purposes (or for the purposes of any undertaking to the United Kingdom Government); and (ii) the existing nuclear generation business shall not provide any cross-subsidy to any other business in the British Energy group.

2.   In the event that the undertaking in paragraph (c) is not implemented by licence condition, the United Kingdom shall submit a yearly report to the Commission establishing evidence that there has been no cross-subsidisation by the existing nuclear generation business to any other business of the British Energy group. This report shall be based on analysis carried out by independent accounting experts. It can be added to the report referred to in Article 2. This should not prejudice the possibility that an implementation by licence condition be put in place later on if it becomes possible.

3.   The United Kingdom shall inform the Commission as soon as undertakings in paragraphs 1 and 2 are implemented.

Article 6

The United Kingdom shall require British Energy to undertake, for a period of six years from the date of this decision, not to own or have rights of control over:

registered operational fossil-fuelled generating capacity (74) in the European Economic Area,

or

large scale registered hydro-electric, as defined in the Renewables Obligation Order 2002, generating capacity in the United Kingdom,

(both types of capacity being known hereunder as restricted capacity) which in aggregate exceeds 2 020 MW provided that:

(a)

during a pending disposal period (as defined below), British Energy shall be entitled to own or have rights of control over restricted capacity in excess of 2 020 MW on condition that it does not operate such excess restricted capacity or divests itself of all operational control and interest in the excess restricted capacity or the power generated from the excess restricted capacity. For this purpose, a ‘pending disposal period’ is the period between:

(i)

the receipt by Eggborough Power Limited or Eggborough Power Holdings Limited of a notice that: 1. an option to acquire the shares in Eggborough Power Limited or the Eggborough station is to be exercised; or any of the security over the shares in Eggborough Power Limited or the Eggborough station is to be exercised;

and

(ii)

the date on which the registered generating capacity of the Eggborough station is no longer available to the British Energy group;

(b)

if one of the disposal options over the shares in Eggborough Power Limited or the Eggborough station is completed, British Energy shall be entitled to own or have rights of control over restricted capacity not exceeding 2 222 MW on condition that it declares its restricted capacity to the operator of the National Grid as 2 020 MW and does not operate more than 2 020 MW of restricted capacity;

or

(c)

if the capacity at the Eggborough stations becomes unavailable to the British Energy group through irreparable failure or force majeure, British Energy shall be entitled to own or have rights of control over restricted capacity not exceeding 2 222 MW on condition that it declares its restricted capacity to the operator of the National Grid as 2 020 MW and does not operate more than 2 020 MW of restricted capacity.

Article 7

The United Kingdom shall require British Energy to undertake, for a period of six years from the date of this decision, not to own or have rights of control over registered operational nuclear generating capacity in the European Economic Area other than its existing nuclear generation assets or operation and maintenance contracts where British Energy has no interest in the electricity output, without the prior written consent of the Commission.

Article 8

The United Kingdom shall appoint, within four months of this decision, and following an open and transparent process, an independent expert for the purpose of monitoring the compliance of BE with the conditions set out in Article 9 (hereafter the independent expert). It shall inform the Commission immediately of this appointment.

Article 9

1.   The United Kingdom shall require British Energy to undertake:

(a)

for a period of six years following the appointment of the Independent Expert, not to offer to supply non-domestic end-users who purchase electricity directly from British Energy on terms where the price of the energy element of the contract with the users is below the prevailing wholesale market price, provided that in exceptional market circumstances where certain objective tests are judged by the independent expert to be satisfied as described in Article 10 (exceptional market circumstances), then British Energy shall be entitled, while such exceptional circumstances continue to prevail, to price the energy element of the contract at below the prevailing wholesale market price in good faith where necessary to enable British Energy to respond to competition, under the conditions of Article 10;

and

(b)

to cooperate in good faith with the independent expert, and to comply with all reasonable requests from the Independent Expert in a timely manner including requests for information, documents or access to staff or management.

2.   The independent expert shall report yearly to the United Kingdom on the compliance of British Energy with these conditions. The United Kingdom shall make the reports available to the Commission.

Article 10

1.   The tests used for the purpose of deciding whether exceptional market circumstances occur shall be the following:

(a)

in any period of […] (ending not more than […] before the date of the Amber Notice as defined below), […] of those existing British Energy non-domestic end-users to whom British Energy has made offers of supply on terms where the margin on the supply of energy element of the contract over the prevailing wholesale price is […] have rejected British Energy’s offer;

(b)

volumes traded in the wholesale electricity market over a […] period have dropped to less than […] of the average of those traded in the same period in the last […] for which data is available;

(c)

British Energy offers to supply a minimum of […] of electricity in the wholesale market […] and that volume is not sold within a period of […].

2.   When faced with circumstances approaching these and if British Energy considers it was possible it might need to invoke exceptional market circumstances, British Energy shall first inform the Independent Expert, outlining its analysis of the situation and the position in relation to the objective tests (Amber Notice).

3.   If circumstances do not improve following the Amber Notice, and if test (a) together with test (b) or test (c) above is met, British Energy shall notify the Independent Expert that it is going to respond to competition by pricing below the wholesale price and supplies the most recent evidence available to British Energy. The independent expert shall have then no more than 24 hours to confirm or otherwise that test (a) together with (b) or (c) above are met and accordingly declare the existence of Exceptional Market Circumstances.

4.   If the independent expert declares the existence of exceptional market circumstances, British Energy shall be entitled for a period of […] of the Independent Expert’s decision to make bona fide offers at prices to meet competition in the direct sales to business market.

5.   The […] period may be renewed by the independent expert for as long as test c) above is met.

6.   At the end of the period, the price restriction set out in Article 9 shall apply again to British Energy.

7.   After the period, British Energy shall provide a report to the independent expert summarising its sales activities during the period. This information shall be reviewed in the Independent Expert’s yearly report.

8.   Following the end of the contract round during which Exceptional Market Circumstances occurred, the Independent Expert shall publish the fact that he had made a determination of such circumstances and how long they lasted.

Article 11

This Decision is addressed to the United Kingdom of Great Britain and Northern Ireland.

Done at Brussels, 22 September 2004.

For the Commission

Mario MONTI

Member of the Commission


(1)  OJ C 180, 31.7.2003, p. 5.

(2)  OJ C 39, 18.2.2003, p. 15.

(3)  See footnote 1.

(4)  That is, those costs which cannot be avoided by ceasing to generate or by shutting down stations.

(5)  That is, those costs which can be avoided by ceasing to generate or by shutting down stations.

(6)  Original submission: cash flow valued as of March 2003, In December 2002 prices. Current projections: cash flow valued as of March 2004, in March 2004 prices.

(7)  The discount rate is the 5,4 % nominal rate recommended as the reference rate from 1 January 2003 in accordance with Commission notice on the method for setting the reference and discount rates (OJ C 273, 9.9.1997, p. 3).

Original submission: Cash flow valued as of March 2003, In December 2002 prices.

Current projections: Cash flow valued as of March 2004, in March 2004 prices.

(8)  BE purchases the fuel for its only PWR nuclear plant from another party, and has no contract for PWR spent fuel as it stores it on site.

(9)  This percentage corresponds to the public sector discount rate.

(10)  The definition of these three scenarios is given at recital (111) below.

(11)  This assumes that the restructuring effective date is 1 April 2004. NPV at March 2003.

(12)  Gross margin is based on total revenue before interest and tax less direct cost of supply (including electricity and delivery costs). Source: BE.

(13)  Vulnerabilities are areas where BE and its advisers feel there is a higher risk that underlying assumptions may not be achieved. Sensitivities relate to output levels in the various cases to reflect the historically poor performance of the plants.

(14)  Business secret.

(15)  OJ C 368, 23.12.1994, p. 12.

(16)  [1982] ECR 2545.

(17)  OJ C 37, 3.2.2001, p. 3.

(18)  TUSNE describes itself as ‘an informal organisation of trade unionists who are supportive of the civil use of nuclear power as means of energy generation within a balanced energy policy and a safe and clean environment’.

(19)  Robert Freer is a consultant.

(20)  CIA is a trade association comprising 180 operating companies, which comprise some of the major electricity consumers in the United Kingdom.

(21)  JHA is a large British energy market analyst.

(22)  EIUG is an organisation that represents consumers in the energy intensive sectors of the UK industry.

(23)  Terra Nitrogen is a nitrogen producer, part of the Terra group, that also produces methanol. It is a major electricity consumer in the United Kingdom.

(24)  Energywatch is a non-departmental public body representing the interests of gas and electricity consumers across Great Britain.

(25)  TVO is a Finnish electricity generator and nuclear plant operator.

(26)  National Grid Transco is the owner and operator of the England and Wales transmission system. It is a privately owned company, which independent from generation and supply business interests.

(27)  Royal Chartered academy founded in 1976 with the purpose to promote excellence in engineering.

(28)  EECL operates a 396 MW CCGT in north London. It belongs to the American company Indeck Energy Services Inc.

(29)  EIC is an independent organisation whose objective is to provide support and market information to business energy users in the UK.

(30)  Body that represents the interests of some 200 large industrial, commercial retail and public sector for whom the cost of electricity and gas is an important factor.

(31)  Case C-256/97 [1999] ECR I-3913.

(32)  Article 305(2) of the EC Treaty lays down that ‘the provisions of this Treaty shall not derogate from those of the Treaty establishing the European Atomic Energy Community’.

(33)  Judgment of the Court of Justice of 10 December 2002 in Case C-29/99 [2002] ECR I-11221.

(34)  OJ L 27, 30.1.1997, p. 20.

(35)  See Judgment of the Court of 29 April 1999 in Case C-342/96, Kingdom of Spain v Commission of the European Communities [1999] ECR I-2459.

(36)  Including all liabilities in relation to the final disposal of such historic spent fuel.

(37)  Determined on the basis that BE efficiency results in GBP […] /MWh being equivalent to GBP […] /kgU.

(38)  The outturn electricity price reflects the value of baseload electricity traded in NETA.

(39)  BE has at present finally disposed of none of its spent fuel due to the fact that the way nuclear spent fuel will be finally disposed of in the United Kingdom has not yet been defined.

(40)  This report is available on Greenpeace UK’s website at the following url: http://www.greenpeace.org.uk/MultimediaFiles/Live/FullReport/6273.pdf.

(41)  Using the same GBP 1= USD1,82 conversion rate as in the report.

(42)  M. Bunn et al. The Economics of Reprocessing vs. Direct Disposal of Spent Nuclear Fuel. Final Report December 2003.

(43)  In July 2003, Argus reported the winter 2003/2004 baseload contract at GBP 20,96/MWh. On 7 August 2003, UKPX reported the baseload future contracts prices for same period at GBP 22,55/MWh. On the same day, UKPX reported summer 2006 future baseload contract at GBP 20,50/MWh and settlement price for winter 2006 at GBP 27,15/MWh. Source: Argus and UKPX as cited by the Frontier Economics report ‘Plant margins in the markets where BE operates in Great Britain’, August 2003, attached to BE’s submission.

(44)  See Judgment of the Court of 16 May 2002 in Case C-482/99 French Republic v Commission of the European Communities [2002] ECR I-04397, at paragraph 24.

(45)  OJ L 195, 29.7.1980, p. 35. Directive as last amended by Directive 2000/52/EC (OJ L 193, 29.7.2000, p. 75).

(46)  Opinion of Advocate General Jacobs in Case C-482/99.

(47)  Using a exchange rate of GBP 1= EUR 1,5.

(48)  Source: website of Posiva Oy, www.posiva.fi. This estimate is based on the costs per kg of spent fuel. Translating this value in tons per uranium (loaded prior to use) may very slightly understate the actual costs since the spent fuel elements also include a small share of non uranium material in spacers and tubes.

(49)  See also section VI(1) above.

(50)  The electricity baseload price on the wholesale market has an impact on BE’s plant’s costs structure, since it an input for the price BE pays to BNFL for the management of its spent fuel.

(51)  Net present value at December 2002 discounted at 5,4 % nominal.

(52)  According to the International Atomic Energy Agency, only 6 nuclear power plants worldwide had been completely decommissioned in 2003. Source: IAEA – Nuclear Technology Review 2003.

(53)  See ‘A European Perspective on the Funding of Decommissioning and Related Activities of the End of the Nuclear Cycle’. José A. Hoyos Pérez. NEA International Seminar on ‘Strategy Selection for the Decommissioning of Nuclear Facilities’; Tarragona, Spain; 1 to 5 September 2003.

(54)  Radioactive Waste Management and Decommissioning in an Enlarged European Union. Derek M. Taylor. 19th Residential Summer School on Decommissioning and Radioactive Waste Management; Cambridge UK; 30 June to 4 July 2003.

(55)  Net present value at December 2002 discounted at 5,4 % nominal.

(56)  See Commission notice on the method for setting the reference and discount rates (OJ C 273, 9.9.1997, p. 3) in conjunction with Commission notice on technical adaptations to the method for setting the reference and discount rates (OJ C 241, 26.8.1999, p. 9) and Article 9 of Commission Regulation (EC) No 794/2004 of 21 April 2004 implementing Council Regulation (EC) No 659/1999 laying detailed rules for the Application of Article 93 of the EC Treaty (OJ L 140, 30.4.2004, p. 1).

(57)  OJ L 176, 15.7.2003, p. 11.

(58)  This conclusion is in addition in line with the one drawn by the Commission in the Merger cases where the geographic market was considered as national.

(59)  In July 2003, Argus reported the winter 2003/2004 baseload contract at GBP 20,96/MWh. On 7 August 2003, UKPX reported the baseload future contracts prices for same period at GBP 22,55/MWh. On the same day, UKPX reported summer 2006 future baseload contract at GBP 20,50/MWh and settlement price for winter 2006 at GBP 27,15/MWh. Source: Argus and UKPX as cited by the Frontier Economics report ‘Plant margins in the markets where BE operates in Great Britain’, August 2003, attached to BE’s submission.

(60)  PowerInk report ‘Survey of the markets served by British Energy’, March 2003, attached to the UK authorities’ notification quotes best new entrant prices between GBP 20 and 25/MWh. Previous Commission decisions in the sector have been based on best new entrance costs estimates of EUR 35,5/MWh (about GBP 23,7/MWh). See for instance Commission decision in case N133/01 – Stranded costs in Greece (OJ C 9, 15.1.2003, p. 6).

(61)  Average cold spell peak demand is that scenario of winter peak demand that has 50 % chance of being exceeded for reasons of weather only. This definition is the one that is used by the England and Wales Network Operator: National Grid Transco.

(62)  20 % in report The Closure of British Energy’s UK Nuclear Power Plants' by John H Large from Large & Associates, April 2003, attached to Greenpeace’s submission. 20 % in report The closure of British Energy’s UK nuclear power stations by ILEX energy consulting, September 2002, attached to Greenpeace’s submission.

(63)  The report is published on the web at the following url:

http://www.nationalgrid.com/uk/library/documents/sys_04/default.asp?action=&sNode=SYS&Exp=Y.

(64)  57 000 MW is the average of the forecast ACS peak demand for the three years concerned.

(65)  Available at http://www.scottish-southern.co.uk/popups/7yearstatement.asp.

(66)  Available at http://www.scottishpower.com/applications/publish/downloadPublicDocument.jsp?guid=2e0a12_fa5719a547_-7ff60a026463&folderPath=/root/ScottishPower Media Library/Documents and Reports/&downloadParameter=Attachment.

(67)  ACS peak demand in each zone may differ slightly from forecasted maximum peak depending on the severity of expected weather as compared to ACS weather. The actual ACS peak demand in Great Britain may also differ slightly from the straightforward sum of the three geographical values. Computing it precisely would require an analysis of the correlations between demands in the three regions, for which no figures are available. However, it is reasonable to trust that peaks are indeed correlated since there is no significant time lag between the geographical areas and the three regions are subject to the same type of weather.

(68)  76 469 exceeds 61 853 by 23,6 %.

(69)  This can remain beneficial for the customer since there is no intermediary between the generator and the customer.

(70)  Except BNFL, none of BE’s competitors operates nuclear reactors in Great Britain.

(71)  Within the meaning of the Renewable Obligation Order 2002.

(72)  See recital (186) above.

(73)  See in that sense Energywatch Annual report April 2002-March 2003, available at http://www.energywatch.org.uk/uploads/20022003_Annual_Report.pdf.

(74)  Excluding auxiliary fossil-fuelled capacity at its nuclear stations.


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