power in europe

Analysis

Vattenfall/Nuon makes the top five 3German CO2 store draft under attack 5Drax assesses impact of early closures 6CCS: into the execution phase 8Italy needs stimulus of new coal 10CEZ, J&T buy Germanys Mibrag 11

The Longer View

Rolling down the mountain 12

News highlights

Nuon re-tenders for Seneffe CCGT 14EP pushed to vote again on CO2 14Areva absorbs 47% O-3 overspend 15Areva warns Siemens 16State needs nuclear earnings: RWE 17Power exports strengthen 18Intrakat, Suez target EfW 18Board room blitz at Acea 19Edison hit by tax, demand slump 19NWEA calls for subsea cable 20Statnett ordered to restore Oslo cable 20Enova projects total 2.15 TWh 21Endesa moves back to Portugal 21EDP awards Baixo Sabor contract 21Ren lines up stimulus package 22Acciona moves on 22Gazprom for GN CCGTs? 23Wind projects focus on Vaud 24Dong buys Severn CCGT 25EIB considers Hatfield funding 25Nuclear justification a shambles 25RWE acquires Cumbrian options 26SSE plans Ferrybridge CHP unit 26

News

Belgium 14 / Europe 14 / Finland 15 /France 16 / Germany 17 / Greece 18 /Italy 19 / Netherlands 19 / Norway 20 /Portugal 21 / Spain 22 / Sweden 23 /Switzerland 24 / United Kingdom 25

Data

German power tracks DAX 27Bilateral Market Assessments 28Feedstock Comparisons 29European Exchange and Pool Prices 30

Most EU countries back extending thedeadline for existing opted-in largecombustion plants to meet stricter airpollution limits by at least four yearsto 2020, the Czech EU presidencysaid on March 2.

The majority of [EU countries]support interim measures from 2016 to2020 for current installations so therewould be room for their alignment [withthe new limits] or so that they could bedecommissioned if their useful life wasover, Czech environment minister MartinBursik said after a public debate betweenEU environment ministers in Brussels.

The ministers were discussing theEuropean Commissions December 2007proposals to update and consolidate EUemission rules into a single EU industrialemissions law (see PiE 545/1).

These rules include the IntegratedPollution Prevention and Control directiveand the Large Combustion PlantDirective, which cover industrialemissions, excluding carbon dioxide,that pollute the air, ground or water.

Opted-in plants meet currentemission controls set out in the LargeCombustion Plant Directive, but manywill have to retrofit abatementtechnologies in order to meet the ECstougher proposals.

Key among the proposals for 500-MWth and above coal-fired powerstations is a 60% reduction in NOxemissions from the current limit in theLCPD of 500 mg/Nm3 to 200 mg/Nm3

from 2016, a level seen as achievablewith Best Available Techniques (BAT in

Electricite de France and Enel of Italyhave signed a deal to co-developnuclear power plants in Italy andFrance, EDF said on February 24. Theannouncement was made during aFranco-Italian political summit in Romebetween French president NicolasSarkozy and Italian prime ministerSilvio Berlusconi, during which Sarkozyoffered unlimited partnership onnuclear power development.

Italys plans for nuclear new-buildshave yet to be put to law, but EDF saidthat if Italy did succeed with nuclearlegislation, the deal would include thecreation of a 50:50 consortium betweenEDF and Enel charged with coming upwith feasibility studies for thedevelopment of at least four EPR[European pressurized water reactor]reactors in Italy.

A second deal, according to EDF,includes the 12.5% participation of Enelin Frances nuclear EPR program at

Penly, Seine Maritime. Enel already hasa 12.5% share in EDFs Flamanville EPRnuclear reactor, under construction andexpected to begin service in 2017. Theagreement also covers research andwaste treatment.

Italys draft law reintroducing nuclearpower generation will go beforeparliament for approval in March,economic development minister ClaudioScajola said in a February 23 statement.

Beyond its stake in Flamanville,Enel said further growth opportunitiesin the French power market includedconstruction of an 800-MW clean coalpower plant, a stake in two CCGTplants of 930 MW, and a stake in thetender for the renewal of 25 hydropower plants concessions.

Enels French subsidiary Erelis had 8-MW of operational wind capacity at theend of 2008 and a pipeline of around500 MW. In French power trade, Enelsold over 1,000 GWh in 2008.

EDF, Enel in nuclear cooperation

Issue 546 / March 9, 2009

(continued over page)

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EU ministers call for 2016 opt-out

fact this radical step down in NOx emissions was alreadyset out in the LCPD final text of November, 2001).

Many ministers now argue that the proposalswould force older plants to close by 2016 because itwould not make commercial sense to upgrade themto the new limits, and that this could hurt the securityof energy supply.

We do have very serious concerns about the largecombustion plant provisions, UK environment secretaryHilary Benn said during the debate. About 25% of ourinstalled capacity would have to close by 2016 if wedidnt change what was proposed. If that was replacedby gas, well, it raises questions of security of supply.

Council conclusions reflected this sentiment: Somedelegations supported the Commissions proposals tobring emissions of existing large combustion plants(including power plants) into line with current BAT by2016. A number of others underlined the costs ofretrofitting existing installations and expressed concernthat the associated investments could impact thesecurity of energy supply. Given that many MemberStates have recently upgraded their combustion plantsto comply with current legislation, they asked for alonger phase-in of BAT. A third group of delegations couldaccept the implementation of BAT by 2016, on thecondition that there is a certain transitional flexibility.

Benn, along with other ministers, supported theCzech EU presidencys proposals for interim flexibilitymechanisms. These include a new opt-out derogationwhereby plant with a life span of less than about 10,000to 15,000 operational hours between 2016 and 2020would continue to meet the emissions standards requiredunder the current EU large combustion plant directive.

Most ministers also rejected the ECs proposal tolower the threshold for large combustion plants covered

by EU rules to 20 MW from 50 MW, Bursik said. Hesaid that the Czech EU presidency wants to reach aninformal political agreement between the 27 EUgovernments on the proposals at the EU environmentcouncil meeting June 25.

The European Parliament is set to vote on theproposals on March 12, after its environment committeeadopted recommendations in a vote January 22. EUgovernments, the EP and the EC all have to agree acommon text before the proposals can become law.

The EUs integrated pollution prevention and controldirective currently covers around 52,000 installationsacross the EU, encouraging them to fit best availabletechniques and requiring them to use the most cost-effective means to achieve a high level ofenvironmental protection.

The LCPD covers power stations larger than 50 MW,oil refineries, coke ovens and coal gasification andliquefaction plants.

All 3,870-MW of UK coal-fired power station Drax isopted in to the LCPD. The plant meets current NOxemission values comfortably, spokeswoman MelanieWedgbury told Platts, but would have to invest to meetthe tougher limits proposed. The problem facing all opted-in plant is the threat of further legislation in 2020 makingredundant any investments made to meet 2016 emissionlimit values, Wedgbury said. See Drax feature, page 6.

Meanwhile another attempt is being made, this time by across-party group of 44 European Parliament members,to get CO2 emission performance standards into theindustrial emissions legislation. The group is proposingthat all power plant with more than 500 MW thermalinput permitted after the law takes effect comply with anemissions limit of 350g CO2/kWh from 2020, and thatall existing similar-sized power plant comply with thesame limit from 2025. See European news, page 14.

INDUSTRIAL EMISSIONS

POWER IN EUROPE / ISSUE 546 / MARCH 9, 2009

ANALYSIS

2

EU ministers call for 2016 opt-out( continued from front page )

Issue 546 / March 9, 2009(ISSN: 0955-6079)

Power in Europe

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Swedish utility Vattenfalls 8.5 billion all-cash offer forDutch utility Nuon pushes the new group into the top fivepower generators in Europe, but Platts data showsVattenfall/Nuons relatively benign carbon intensitymakes it the envy of its immediate peers.

The deal, announced on February 23, promotesVattenfall up the European league table to fifth in termsof electricity production (185 TWh/yr), putting it justahead of GDF Suez and behind EDF/British Energy,E.ON, Enel/Endesa and RWE/Essent.

But in terms of carbon emissions, Vattenfall/Nuon isdown in eighth place, emitting some 20 million tonsCO2 less than near rival GDF Suez in 2007 (seePowervision data). At todays 11/t carbon price,Vattenfall/Nuon would be saving 220 million oncarbon credit purchasing over GDF Suez in a 100%-auctioned ETS Phase 3.

At first glance this conclusion is puzzling, asVattenfall/Nuon has over 12 GW of coal plant to GDFSuezs 5 GW. The key, however, is hydro. V/Ns 11-GW ofzero-emission Nordic hydro is balanced in the rivalry byGDF Suezs 15-GW of gas-fired plant.

Vattenfalls relatively small gas-fired portfolio and heavycoal portfolio explains its commitment to developingcarbon capture technology. In this and several otherareas, the Vattenfall/Nuon merger appears to be ameeting of minds, in contrast some suspect to therecent RWE-Essent fusion.

Both Nuon and Vattenfall are known for theirinnovations in renewable and clean energy, the twosaid. The companies will join forces, to continue todevelop projects, such as the CCS installations atSchwarze Pumpe (Vattenfall, Germany) and Buggenum(Nuon, the Netherlands). Both companies are globalfront runners in the development of CCS. Investing in off-shore wind will be a key priority, adding to current largewind farms such as at Egmond aan Zee (Nuon), Lillgrundand Kentish Flats (Vattenfall). This will support thecombined groups ambition to generate 15 TWh of windpower by 2015 (compared to 2.5 TWh in 2009). Otheralternative energy sources, such as solar foildevelopment and ocean power, are part of the R&Dinvestments of the combined companies.

Learning from Dutch strengthsWith reference to the Netherlands, Vattenfall noted thatan ageing asset portfolio and capacity shortages in theDutch market provided the opportunity for a shifttowards renewables and clean energy. The Dutchmarkets proximity to and good connectivity withVattenfalls core markets would serve to consolidate itsNorthwest European footprint, and provide a strongplatform for further growth in Belgium, France and theUK. Finally, the Dutch market was emerging as a gasand biomass hub, in tune with Nuons biomass andCCGT strengths. Indeed one of Vattenfalls priorities is tosupport Nuons strategy of securing 10-20% of its owngas demand through upstream gas assets in addition tolong and short term gas contracting.

In supply meanwhile Vattenfall said it would seek tobuild on Nuons highly successful customer servicemodel and dual-fuel offering expertise to acceleratecustomer growth and profitability in Germany. And itwould explore growth opportunities in de-centralized heatgeneration technologies.

The dealIn an initial acquisition, Vattenfall is paying 5.052billion for a 49% stake in Nuons unbundled commercialactivities. Subsequent acquisition of the remaining 51%will take place in the form of deferred share purchasesin 2011, 2013, and 2015. The equity value for 100% ofNuon is fixed at 10.31 billion.

In a conference call, Vattenfall management saidsubstantial divestments would be made to help fundthe deal. The sale of Vattenfall Europe TransmissionsGerman network is progressing and is expected to be

VATTENFALLS BID FOR NUON


ANALYSIS

3

Vattenfall/Nuon makes the top five

Installed Capacity (MW)

Existing Existing Planned Planned Vattenfall GDF Vattenfal GDF

Plant type -Nuon Suez -Nuon Suez

Hydro 11,313 3,424 155 8Nuclear 5,117 6,525 1,722 0Fuel Oil 2,059 1,779 0 0Coal 12,210 5,094 6,257 2,335Coal Gasification 284 0 0 0Natural Gas 4,305 15,117 2,437 8,057Other Gas 518 530 0 436Biomass & Waste 408 126 35 19Offshore wind 350 9 3,109 379

Note: excludes onshore wind

Source: Platts Powervision

2007 verified CO2 emissions by company(million mt)

Source: Platts Powervision

0 10 20 30 40 50 60 70 80

Scottish & Southern Energy Plc

Drax Group Ltd.

Vattenfall /Nuon

Iberdrola, SA

CEZ

EDF / British Energy

GDF SUEZ

Enel / Acciona

RWE / Essent

E.ON AG

completed in 2009, with the proceeds potentiallybeing used to reduce leverage. In addition, Vattenfallsaid it would reduce its 2009-2013 capitalexpenditure programme from SEK 202 billion to SEK191 billion (16.7 billion).

The utility has arranged a 5 billion bridge creditfacility with nine banks, with a 12-month maturityand an option to extend by 50% for a further 12months. The margin on the credit is Euribor + 150basis points for the first six months, stepping up75bp for the second six months and then 50bp stepups every six months thereafter. Vattenfall said itexpected to refinance the 5 billion bridge in thebond markets during 2009.

The acquisition is conditional on 80% approval ofshareholders, unbundling of the networks occurring andapproval of the competition authorities. Vattenfall is totake operational control with effect from completion andwill consolidate with effect from January 1, 2009.

Synergies from the deal would be significant, Vattenfallsaid, but no figures were given. Trading operations are tobe combined and extended, pushing the new group intothe top three European energy traders. Savings wouldflow from reduced IT costs, improved purchasing powerand substantial skill transfer opportunities in trading,customer product offering and plant operations. Thereare no redundancies planned, with Nuon retaining itshead office and regional office.

VATTENFALLS BID FOR NUON


ANALYSIS

4

Vattenfall-Nuon: plants by MW and operational/development status

Source: Platts Powervision. Contact: [email protected], tel +44 207 176 6277

Minsk

Prague

Copenhagen

Helsinki

Paris

Riga

Vilnius

Amsterdam

Oslo

Warsaw

Stockholm

Brussels

Tallinn

Berlin

Dublin

Luxembourg

London

FINLANDSWEDENNORWAY

GERMANYFRANCE

DENMARK

POLAND BELARUS

UKRAINE

CZECH REP.SLOVAKIA

NETH.

BELGIUM

IRELAND LITHUANIA

LATVIA

ESTONIA RUSSIA

RUSSIAUNITEDKINGDOM

LUX.

420-3,090 MW Early Development

40-420 MW Operational

0-40 MW Under construction

TRANSPOSITION OF EU CCS DIRECTIVE


ANALYSIS

5

A draft law on CO2 capture and storage agreed betweenGermanys federal environment and economy ministriesis to be put before cabinet later this month. It hasalready met with sharp criticism from environmentalists.

The draft is a first step towards transposing theEuropean CCS directive, passed last December, intoGerman law and contains arrangements on CO2transport through pipelines, investigations into suitabilityof geological formations for CO2 storage and planningrules on construction and operation of CO2 stores.

Greenpeace takes issue with the draft for three mainreasons. Firstly, it says there are no effective measuresagainst CO2 leakage from end stores. Secondly, nothorough investigation of the CO2 stores is plannedbecause these are expected to be formations fromwhich natural gas has been extracted yet how muchgas has migrated out of natural gas reserves is notknown. When the reserve is opened, only that amount ofgas is found that is present in the reserve at that time,Greenpeace notes. And thirdly, the draft proposes thatCO2 end store operators take full responsibility forstorage for only 20 years, after which the taxpayer islikely to have to foot any bills.

A study by consultancy Intac for Greenpeace analyzing thedraft law recommends the setting up of a fund into whichall CO2 operators would contribute to cover future CO2storage costs and so prevent these being passed throughto the public. The study recommends beginning with a fewpilot storage projects from which standards can bedeveloped. It warns that use of best available technologiesdid not guarantee success, pointing to problems at theAsse nuclear waste end store, a former salt mine, whereunexpected substantial influx of salt water into the storehas presented state authorities with major problems.

Meanwhile nature protection association NABU(Naturschutzbund Deutschland) has said that permittingprocedures should not favour CO2 stores over othercompeting issues of public interest such as geothermalenergy or ground water protection. It fears that if allevaluations, permitting and controls become the

responsibility of the mining authorities, environmentaland nature protection issues will be neglected. Further,NABU said there should be clear limits on the amount ofpolluting substances allowed in the CO2 stream.

If all coal and lignite power stations under constructionor planned are completed and retrofitted with CCStechnology, nearly 190 million metric tons/yr of CO2would need storage, according to environment groupDeutsche Umwelthilfe (DUH). Some 9.6 GW underconstruction is set to emit about 59 million mt/yr CO2.Another 22 planned projects totalling 22.8 GW wouldemit 131 million mt/yr CO2. Two pilot projects includingcarbon capture planned by RWE (450 MW) and Vattenfall(up to 500 MW) would add to the total said DUH.

A study by Prognos, meanwhile, commissioned byEuropes second largest carbon-emitting generator, RWE(behind E.ON), concludes that carbon capture andstorage should result in lower electricity prices andincrease security of supply. Depending on whether weexpect scenarios of constant or falling electricitydemand, the wholesale price for electricity could be 17%or 22% lower when using CCS by 2030 compared withno CCS. The main reason lies in the lower CO2 pricesthat result through use of CCS. Savings to 2030 wouldadd up to 52 billion (lower electricity consumption) or66 billion (unchanged electricity consumption)depending on the scenario, predicts the study.

The study looks at the effects of CCS on Germanysfuture power station fleet. If electricity demand isreduced by 15% over the period 2005-2030, some 14.5GW of new capacity would be built in the decade 2020-2030, compared with 21 GW if electricity demandremained constant.

Assuming CCS technology is widely used, the new plantwould comprise more coal and lignite plant and less gascapacity, the opposite being the case if CCS was notemployed. The scenario with constant electricity demandand use of CCS sees, for instance, 12 GW of new coalcapacity being built over the period 2020-2030, alongwith 6 GW of new lignite, but no new gas plant at all.

German CO2 store draft under attackSara Knight

CCS scenarios and CO2 certificate prices

Scenario: reduction in electricity consumption Scenario: no change in electricity consumption

Without CCS With CS Without CS With CCS

Electricity consumption 2005-2030 -15% -15% No change No changeShare of renewables 2030 40% 40% 40% 40%Share of cogeneration 25% 25% 25% 25%Nuclear Phased out Phased out Phased out Phased outCO2 emissions 2005-2030 -50% -50% -50% -50%CO2 certificate price 70/tonne 55/tonne 75/tonne 55/tonne

Source: Prognos

Around 6,000-MW of opted-out UK coal-fired powercapacity may have less than three years left to run ifcurrent rates of production are maintained, Drax Groupchief executive Dorothy Thompson said in a 2008results conference call on March 3.

The story of 2008 was undoubtedly the LargeCombustion Plant Directive, which created opted-outplants with 20,000 hours of operating life that mustclose by 2016, Thompson said. Some of thatopted-out plant has been running very hard inJanuary this year it produced 14% of total UK output.If they continue to run at these rates, quite a lot willclose early. We calculate that 6-GW could comeoffline by end-2011.

The timing was probably not coincidental, becausethat is when the cost of Phase Three carbon [under theEUs Emissions Trading Scheme] starts kicking in,Thompson said. We will no longer have nationalallocation plans for UK plants and there will be lessincentive to remain in the market.

The recession and resulting fall in electricity demandwould delay effects flowing from a generatingcapacity squeeze for two to three years, Thompson

said. When you adjust for weather, we estimate thatthis winter demand is down about 5-6%. Thattranslated into 2-3 GW. This is partly recession andpartly to do with prices. Wholesale prices havehalved since the time of the highest commodityprices, so in time some of the response may bedampened as commodity price falls come through.

Previous forecasts for capacity tightness around 2011-12 have eased back a bit, but 11.5 GW of coal and oilplant have to close by 2016, and from 2016 all theopted-in plant will be subject to new NOx regulations[under proposed EU legislation], Thompson said.Some of that plant will not retrofit to meet the newregulations and will either be forced to close or acceptreduced running hours.

Thompson warned that the 6-GW of coal plant likely toclose by 2012 would be replaced by new gas-firedcapacity and that by 2015, over 50% of our electricity isgoing to be fuelled by gas, and if anything the gas importstory is getting more complex. As of January 2009, 36%of UK supply was gas-fired. Some 9 GW of new gas plantis expected by 2015.

All of this underlined the importance of Drax in ensuringsecurity of supply and reinforces the need for investmentin the sector, Thompson said.

Industrial emissions focus on opted-in plantThompson was not aware of any pressure in Brusselsto relieve the conditions for opted-out plant under thecurrent LCPD, but there is real pressure to easethe proposed conditions for opted-in plant in theperiod 2016-2020.

Quite substantial investment is needed if opted-inplants are to meet tougher NOx emission standards asproposed by the European Commission in the IndustrialEmissions Directive (IPPC see PiE 545/1), Thompsonsaid. There was pressure from east European memberstates (and the UK) to allow non-compliant plant tocontinue operating under some form of derogation to2020, she said.

All 3,870-MW of Drax is opted in to the LCPD. The plantmeets current NOx emission values comfortably,spokeswoman Melanie Wedgbury told Platts, but wouldhave to invest to meet the tougher limits proposed.LCPD is 500 mg/Nm3, we are at the 400-450 mg/Nm3

and the 2016 proposal is for a 60% cut to 200 mg/Nm3,so wed have to invest to meet that.

The problem facing all opted-in plant is the threat of yetfurther legislation in 2020 making redundant anyinvestments made to meet 2016 emission limit values,Wedgbury said. You need to look at the whole suite ofenvironmental laws when making an investment

DRAX AND UK CAPACITY MARGINS


ANALYSIS

6

Drax assesses impact of early closures

Opted-Out Hours Used

Source: Elexon, Drax estimates

0%

10%

20%

30%

40%(Drax Assessment @ 23rd February)

33%

600 M

W

34%

700 M

W

36%

20

00

MW

33%

600 M

W

36%

20

00

MW

34%

350 M

W

36%

10

00

MW

35%

10

00

MW

37%

13

00

MW

37%

14

00

MW

36%

10

00

MW

(Efficiency and Capacity)

Oil Fired

Coal Fired

Opted-Out Plant Capacity Closure

Source: Elexon, Drax estimates

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000(Drax Assessment @ 23rd February MW)

2011 2012 2013 2014 2015

decision. For instance the National Emissions CeilingDirective could increase the stringency of pollutantcontrols in 2020.

If there was a risk of assets being stranded in 2020,that would dissuade generators from investing to meet2016 controls, Wedgbury said. Typically you need a 10-15 payback period for major investments of this sort.One option is that everything runs to 2020, allowingbetter visibility of regulatory changes ahead and avoidingpremature retirement of plant, she said.

Carbon outlookTodays weak CO2 price was due to lower emissionsand heavy selling of allowances by industrials seekingto raise short term cash, Thompson said. There hasbeen debate as to whether Phase 2 will mirror Phase1, when prices went to zero. We dont think it willbecause there is real value for Phase 2 certificates inPhase 3 [Phase 2 EUAs can be banked into Phase 3]and all our analysis shows that the allocation plans arenot sufficient to cover emissions. So ultimately thecarbon price is based on Kyoto credits and on banking[into a much tighter Phase 3 carbon market]. Kyotocredits appear to be floored by the Chinese positionof somewhere between 8-12/ton CO2.

Use of Kyoto credits in Phase 3 was much more limitedthan envisaged a few years back, Thompson said. InPhase 2 were allowed to use 4.4 million tons of Kyotoinstruments. In Phase 3 the increment is only 0.8 milliontons [giving a 2008-2020 total of 5.2 million tons].

12-year output highDrax Groups 2008 profit after tax fell 6% to 333million despite revenue growth of 41% to 1,753million, the generator reported on March 3. Profitswere squeezed by higher fuel costs, increasedpurchase of power in the market and reducedmargins in the fourth quarter 2008. Power salesreached 1,692 million in 2008 compared to 1,204million in 2007, boosted by a 29% hike in averageachieved electricity price to 58.3/MWh and anincrease in net power sold to 25.4 TWh, compared to24.9 TWh in 2007.

This was the highest output at Drax for 12 years, CEODorothy Thompson said, and despite unbelievablevolatility in commodity prices, winter dark green spreads(the price of power less coal and carbon) generallyremained within a band of 18-30/MWh, and ourprofitability remained robust.

Looking ahead, Drax said it had sold 20.7 TWh for 2009, ofwhich 16.2 TWh at an average achieved price of 51/MWh;17.3 TWh for 2010, of which 11.2 TWh at 56.6/MWh;and 10.3 TWh for 2011, of which 4.6 TWh at 62.6/MWh.Thompson said dark green spreads in the forwardmarket were 5-10% above those it had been taking thistime last year so while spreads have come down fromthe real highs of last year, they are still positive for us.

Fuel costs in 2008 were 858 million, compared to471 million in 2007. The increase was due to highergeneration, an increase in the price of coal and otherfuels, and the impact of higher prices for and increasedbuying of CO2 emissions allowances.

Drax buys power in the market when this is below itsown marginal cost of production. The cost of powerbought in 2008 increased to 212 million compared to76 million in 2007, it said.

The generator said that the last quarter of 2008 saw anarrowing of dark green spreads, as plant was returnedto service and fears of a capacity shortfall were allayed,together with reduced peak electricity demand, reflectingthe economic climate.

Revenue benefited from the sale of by-products (ash andgypsum), Renewable Obligation Certificates, LevyExemption Certificates and SO2 emissions allowances, thegenerator said. Significantly higher ROC sales in 2008were driven by our growing biomass burn, Drax said.

The groups carbon abatement projects have led to a 3%reduction in CO2 emissions in 2008 compared to 2006,due to biomass co-firing and investments in thermalefficiency improvements, it said. The generator said itled UK coal-fired generation performance with availabilityof 86% and a load factor of 76%.

DRAX AND UK CAPACITY MARGINS


ANALYSIS

7

Committed Large CCGT / CHP Power Plant Build Announcements

Announced Owner Contractor Plat type Location Capacity (MW) Estimated commercialoperation

March 2008 Severn Power Siemens CCGT Uskmouth, Wales 800 Winter 2010 January 2008 EDF GE CCGT West Burton, Notts 1,300 2011 August 2007 RWE Alstom CCGT Pembroke, Wales 2,000 H1 2012 June 2007 E.ON Alstom CHP Isle of Grain, Kent 1,275 2010/11 May 2007 RWE Alstom CCGT Staythorpe, Newark 1,650 First unit 2010 August 2006 ConocoPhillips GE CHP Immingham 480 Summer 2009July 2006 SSE/ESBI Siemens CCGT Marchwood, Southampton 850 Winter 2009/10 June 2006 Centrica Alstom CCGT Langage, Devon 885 H2 2009

Note: Commitment deemed to be at the letting of the turbine supply and maintenance contract. Plans for other plant have been announced but arebelieved to be at earlier stages in the process.

Source: Market Announcements, Drax Estimates as at February 20, 2009

A successful policy year for carbon capture and storagehas left the technology facing its make-or-breakchallenge financing demonstration projects to de-riskCCS in the eyes of society, delegates at Platts thirdannual European Carbon Capture and Storageconference in Brussels heard February.

Industry speakers expressed satisfaction at theswift achievement of a CCS Directive in December2008, and the emergence of not one but twosources of institutional subsidy for demonstrationprojects (the 300-million EU Allowance specialreserve for CCS and innovative renewables; and the1.15-billion proposed stimulus package from EUbudget under-spend).

But this was no time for complacency, ShellsGraeme Sweeney told the conference (he is alsochairman of zero emission fossil fuel plant platformZEP). We need to move fast if the currentcompetitive opportunity is to be realized. The UShas proved many times how it can catch up quickly,and the Canadians have moved from a 10-pageexpression of interest to plans for two CCS schemesin six months. Ive not seen Europe move that fastin a generation, he said.

Four issues needed urgent resolution, Sweeney said.First, we need criteria for the division of the 300 millionEU Allowances [recently granted by the EU] between CCSand innovative renewables. Then we need the criteria forCCS demonstration project selection, with clear tenderrules. Third, we need guidance on how funds are to bedisbursed. Finally, we need progress on how projectknowledge is to be shared project coordination getsyou a ten-year start.

Sweeney said that to meet current timelines for 10-12demonstration projects up and running by 2015,project selection needed to be made at the verylatest by 2010. That is tomorrow in political terms.Then we need allocation of funding by mid-2011. Weare into the execution phase for CCS and must get theshow up and running.

The European Commissions climate change committeewas about to meet for the first time to discuss criteriafor division of the 300 million EUAs, Sweeney toldPlatts. We need the demonstrations urgently tovalidate technologies across all variants, he said. Wehave to learn enough from the demos to de-risk thetechnology in the eyes of the public, and begin to getcosts down. Our job is to reassure the public, becauseit is going to be extremely difficult to get support,especially for onshore storage.

Some 34 CCS projects in all have been proposed acrossEurope. In the demonstration phase (4 GW built), CCS

costs are estimated at 60-90/tonne CO2 abated,Sweeney said. For the early commercial phase (20 GW),he put the cost at 40-70/t CO2 and for a final, maturephase at 30-50/t CO2.

There was general recognition of the steep mountainCCS has to climb with regard to funding during arecession. There are no customers for CCS itreduces revenue and increases costs, so it needspublic/private partnership, Sweeney said. As difficultas the recession is, however, once its over climatechange will still be there.

Emission Performance StandardsThe conference heard differing views on whether theEmissions Trading Scheme was an adequatemechanism for driving CCS forward. One of themain architects of the CCS Directive, Scott Brockettof DG Environment, said the European Commissionhad absolute confidence in the scheme. The capwould be tightened over time, carbon prices wouldrecover and there was no need to consider furtherregulation as yet.

Less sure was MEP and rapporteur Chris Davies,another key actor in CCS promotion to the topenergy/environment policy table last year. He tolddelegates that member states would have to reconsiderintroducing CO2 emission performance standards forpower stations if the EUs ambitious climate changetargets were to be met.

The Council of Ministers comprehensively dismissedthe idea in December, with only the Netherlands insupport of my proposal for a 500 gram CO2 per kWhlimit, but it is back on the agenda, Davies said.

Standards for CO2 would be discussed by theEuropean Parliament as revisions to the IntegratedPollution Prevention and Control directive worked theirway through the Brussels legislative process, he said.Im not convinced that the Emissions Trading Schemeis enough to drive CCS development. Regulationhowever has a great track record of success. Whenindustry is presented with new technical requirements,it meets them on time; there is no room for memberstates to play the system.

Davies acknowledged that any CO2 regulation wouldhave to include all fossil fuel-fired generation. Wewould have to reduce the standard to 350 gCO2/kWh to include gas, so the rule is not limitedto coal alone. Im going to have discussions with UKrepresentatives soon, to explore the potential torelax some of the [NOx, SO2 and dust] requirementsunder the Large Combustion Plant Directive in orderto get a deal going from 2020 on CO2 emissionperformance standards, he said.

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CCS: into the execution phase

Capture race is onA number of detailed presentations given by generators(RWE, E.ON, Enel, GDF Suez, ConocoPhillips) indicatedthat the capture element of CCS is receiving significantamounts of seed money, is close to scale demonstrationand has definable risks.

Carbon capture and storage can be done at20/tonne CO2 but not before 2020, Vattenfall vicepresident, R&D, Lars Stromberg told delegates. Themajor challenges facing CCS were the permitting ofCO2 transport pipe lines, a critical variable in termsof project timing, and getting through the high-costdemonstration phase, Stromberg said. In the demophase CCS would cost around 90/tonne CO2, by2020 that cost would be down to 40, falling to 20-25 by 2030, he said.

Our 30-MW oxyfuel boiler at Schwarze Pumpe is workingbeautifully, even if it is probably the most expensiveboiler ever built, he said. Vattenfalls next planned toreplace two 250-MW boilers at its Janschwalde plantwith oxyfuel boilers, removing around 90% of CO2emissions from one 500-MW block.

Meanwhile E.ONs Bernhard Fischer said the Germanutility was focusing its efforts on post-combustioncapture technologies because its more advancedcompared to IGCC and oxyfuel, is suitable for the retrofitmarket and is the only option for capture-ready projects.

Monitoring of storageWhile utilities jostle for position on capture, some of themost pressing questions and anxieties were raised onCO2 transportation and storage. Two major issues facingCCS are potentially disruptive lead-times for pipelinepermitting; and the absolutely critical need to avoidleakage. As ex-Shell Transport chairman Lord RonOxburgh noted, with diligence the risk of leakage shouldbe small, but geology always has surprises.

Presentations by StatoilHydro and BP on CO2 storageat Sleipner and In Salah prompted in-depth debate ofrisk assessment and monitoring options.StatoilHydros Trude Sundset openly discussedlessons learnt from a rupture in the Utsira geologicalformation in the North Sea, caused by high pressureinjection of water from the Tordis field, leading to aleak of oily water (this was nowhere near the SleipnerCO2 store, Sundset noted).

With more extensive seismic surveying, leakage couldhave been avoided, she said. This was a valuable lessonfor CCS, Sundset concluded: thorough geological surveysof sites will be crucial for CO2 stores. We must never reston this issue if we are to gain public acceptance.

BPs Iain Wright said the overarching principles ensuringsafe geological storage had been set out in the CCSDirective, but now we need much more detail.Commercial entities could not shoulder CO2 storage

liabilities indefinitely, he said; at some point afterclosure of a store, it must be handed over to the nation.

Risk of leakage peaks during the injection phase, withleaks from wells the most likely path, Wright said. Wecan add up all the risks but what we dont know yet iswhat constitutes the overall level of unacceptable risk.

Wright said that every CO2 store would have its ownmost suitable monitoring techniques. If this is to beregulated, I want the regulator to help me define themost cost-effective monitoring techniques.

He listed wellhead monitoring, wellbore sampling, soilgas, dynamic modelling, water chemistry, 4D seismic,geomechanics and geochemistry as among keymonitoring techniques. Seismic surveying was not apanacea for all monitoring ills, Wright noted, and othertechniques were cheaper. Satellite imagery for instancehad good potential for public acceptance, with In Salahtests showing that a combination of satellite imageryand geomechanical techniques tracked surface and sub-surface behaviour of CO2 in a low-cost, non-invasive waythat could be made publicly available.

Investment case weak: JP MorganPouring liberal amounts of cold water on what had beena generally positive conference, Marc Levinson,Economist, JP Morgan Chase gave a final daypresentation on financing.

The economic drivers for CCS were too uncertain tointerest investors under current conditions, he said.CCS does not produce anything you can sell, andrevenue from enhanced oil recovery is extremely unlikelyif CO2 streams are plentiful. The only reason for CCS isif it costs less to pump into the ground than emitting it.At the current cost of CO2, why would anyone want toinvest in CCS? Levinson asked.

Only in the long term, and only in the European Union,did integrated gasification combined cycle plant withCCS appear to be cost-competitive compared toconventional coal plant without CCS, Levinson said,assuming extension of the EU Emissions TradingScheme and a declining cap on emissions.

Nowhere else in the world did IGCC with CCS approachcost competitiveness with traditional coal over a 20-yearhorizon, Levinson said. Neither was IGCC with CCScompetitive over that period with renewable baseloadpower options such as biomass. And if new nuclear wassubsidized, as proposed in the US, that would pushIGCC with CCS further out of the investment frame.

It is far from certain that developers in the US canprove to regulators that coal and CCS constitutes areasonable and prudent investment, allowing them topass-through costs to customers, Levinson said. USinvestors are certainly not going to get excited by CCSwhile those decisions remain cloudy.

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Levinson said he would be more bullish on privateinvestment if governments showed long-termcommitment to consistently higher CO2 prices. Asthings stood, we think governments will be funding thisfor the next five years.

Reserve auction priceResponding to this, Deutsche Banks Mark Lewis saidthe European Commission must be ready to interveneto support the EU Emissions Trading Scheme if thecarbon price failed to recover. If the European economycontinues to deteriorate this year, we could be in a verydifficult position. If the carbon price is very depressedin the run-up to Copenhagen [COP15 UN Kyotomeeting], it will be very difficult to get agreement

because China and India will point to what they perceiveas a failure of the scheme, Lewis said.

If push comes to shove, the EU has to be prepared totake action to defend this market, he said. It would be toodifficult to tighten the overall CO2 cap to 2020, as thiswould require all 27 EU Member States to agree on thechange. But one measure that could strengthen the ETS,without compromising the essential free market designof the scheme, would be for the EC to introduce a reserveprice for auctions in Phase III, which would see a muchgreater use of auctioning and a reduction in free allocation,he said. They must be prepared to put a minimum priceon the auctions from 2013, as that would send a clearsignal not to sell allowances in Phase II, Lewis said.

Italy must press ahead with new coal projects to createjobs, stimulate the economy and prevent investmentcapital going abroad, chairman of Italian coal associationAssocarboni Andrea Clavarino told Platts on March 4.

Last year was positive, with Tirreno Power receivingtowards the end of 2008 the environmental authorizationto build a new 460-MW coal-fired unit at Vado Ligure [inthe northwest coastal province of Savona]. The unit willhave a very high efficiency of 47%, Clavarino said.

Tirrenos plan includes 180-MW of renewables, so thetotal investment will be 800 million, out of which200 million will be for renewables, Clavarino said.Globally, although capacity will rise, emissionsincluding CO2 will be reduced. At present the VadoLigure site has two 330-MW coal units and a new CCGTof 760-MW. With the new coal unit total site capacitywill rise to around 1,800-MW.

Now some local resistance must be addressed, andTirreno is negotiating terms with local municipalities. Welook forward to starting work soon because constructionwould involve 1,000 workers over four years and provide250 jobs thereafter, Clavarino said.

The existing infrastructure does not allow for futurecarbon capture equipment, but Clavarino noted that thenew unit would have a beneficial impact on emissions bydisplacing less efficient plant.

Meanwhile at Porto Tolle, Enels 2,000-MW oil-to-coalconversion project in Veneto, we are talking about thepotential for 4,000 construction jobs over four years,Clavarino said. After two years development, however,the project still awaits environmental approval, thereare national park restrictions that need to beovercome, and Clavarino is fearful the investmentopportunity could be lost. Italy is 60%-dependent ongas-fired electricity; coal supplies 12% of Italian power

compared to Europes 33% average. However there isan alternative project Enel is pursuing in Albania, withthe aim to have 1,500-MW [of coal-fired capacity] inAlbania and an interconnector to Italy. I think we runthe risk that, if we dont have environmentalauthorization for Porto Tolle, our country will bedeprived of an important facility and another countrywill benefit from the investment.

Local trade unions are of the same opinion. Some3,000 workers protested recently in favour of theproject, with a delegation received by the environmentministry. The government supports Porto Tolle but,under regional law, only gas plant can be built in thePo Delta national park, where the oil-to-coalconversion is proposed. This is a restrictiveinterpretation of the law that the court has given, andEnel is disputing it, Clavarino said.

Opposition to new coal across Europe is well organizedand highly motivated. In December environmental groupGreenpeace staged a demonstration at Porto Tolle,painting No Carbone on the stack, as part of its pan-European campaign against construction of coal plant.The action, and rallying of local opposition, has certainlyadded to development delays if not actual cancellationsin Italy, Germany and the UK.

In the short term this has led to gas plant continuing todisplace coal in several west European markets. Longerterm, nuclear is an option, although Clavarino wascautious on a nuclear power renaissance in Italy. Letswait and see how things are going at the end of 2009,he concluded. New nuclear is a very long way out, Imnot worried that the focus is shifting because economicconsiderations will dictate choices and we shouldconcentrate for now on less costly oil-to-coal conversion.Once approved, Porto Tolle would take 42 months tocomplete and could be online during 2013. New nuclearwould only become available in 2020.

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Italy needs stimulus of new coal: Assocarboni

Czech power group CEZ has made its first foray into theGerman market with the acquisition, in consortium withthe Czech-Slovak investment company J&T Group, ofMibrag, the German integrated coal mining and powergenerating business.

CEZ announced February 25 that it and J&T Group hadsigned a share purchase agreement to acquire 100% ofMibrag from the German companys joint US-basedshareholders URS Corporation and NRG Energy for404 million. CEZ said the transaction, which is subjectto customary closing conditions including EuropeanCommission approval, is expected to be concludedduring the second quarter of 2009.

Mibrag will be owned by a joint venture company, equallyowned by CEZs brown coal mining subsidiarySeveroceske Doly Chomutov and J&T Group. The localdaily Leipziger Volkszeitung reported February 25 thatCEZ and J&T had outbid ENBW, Germanys third-largestutility, in the tender.

Mibrag owns and operates two opencast lignite mines,Profen and United Schleenhain near Leipzig, with acombined annual production of around 19 million tons.The company has proven reserves of around 530million tons of lignite, with significant options forexpansion, CEZ said.

Coal from the two pits is primarily supplied to the 2,900-MW Lippendorf and 2,450-MW Schkopau power plantsas well as three combined heat and power plants(Mumsdorf, Deuben and Whlitz) with a total installedcapacity of 208 MWe, owned and operated by Mibrag.

In 2008, Mibrags power plants produced 1.4 TWh ofpower and over 2,000 TJ of heat. Mibrag also runs acoal dust processing factory. In its most recentfinancial results for 2007, Mibrag posted a net profitof 43.2 million and EBITDA of 128.5 million onrevenues of 372.5 million.

Neither CEZ nor J&T would elaborate on the reasons forthe acquisition of Mibrag or their plans for the futuredevelopment of the company, beyond saying that it wasof strategic importance. The acquisition of Mibrag . . .means further development in our business in Germanywhere we are now active in the wholesale [power] tradingbusiness, said Daniel Benes, chairman of thesupervisory board of Severoceske Doly Chomutov andvice board chairman of CEZ.

NRG said that it had decided to sell its 50% stake inMibrag as part of a wider exit from international holdings,in order to redeploy capital in the US. NRG said it wouldmaintain its 41.9% interest in Schkopau, a coal-fuelledpower station near Halle, Germany, which obtains its fuelunder a long-term contract from Mibrags Profen mine.

Prague-based J&T has emerged in recent years as agrowing force in the Czech power market. Itsambitions were underlined last April with theannouncement of plans to invest CZK 20-25 billion(790-900 million) over the next five years in thedevelopment of some 1,000 MW of new generationcapacity to secure control of at least 10% of theCzech power sector.

The company currently owns and operates 330-MWeand 1,430 MWth of coal-fired generating capacity inits home market as well as a 41% stake in the Pragueregional distributor, PRE. In December J&T announcedthe signing of a preliminary agreement with thegovernment of Moldova for the construction andoperation by 2015 of a 350-MW hard coal-firedthermal power near the city of Ungheni in westernMoldova, on the border with Romania. The agreementprovides for the possible development of two further350-MW units at the same site. The company alsoplans to develop a 350-MWe hard coal-fired plant at asite in Strazske in eastern Slovakia.

Severoceske Doly Chomutov is the largest producer ofbrown coal in the Czech Republic, with a domesticmarket share of just under 50%.

The company produces annually approximately 20million tonnes of coal, from two mines in the NorthBohemian brown-coal basin. Doly Bilina produceslow-sulphur graded and boiler coal. Doly NastupTusimice mainly produces boiler coal. Its largestcustomer is CEZ.

CEZ Groups fourth quarter 2008 net income fellCZK 7 billion to CZK 13 billion (466 million) onrevenues that were down CZK 1.25 billion to CZK 49.8billion, the Czech generator said on March 3. A swiftdecline in demand and a two-month outage at unit 1 ofnuclear power plant Temelin were key drivers of thepoor performance, CEZ said. Fourth-quarter EBITDA wasdown CZK 1.8 billion at CZK 18.4 billion. Electricitydemand for the quarter was down 4% because of therecession, and had a material impact on the yearsoverall figures, CEZ said. Czech electricity prices fell inthe final quarter of 2008, CEZ said, with calendar2009 baseload power down 28% during the quarterfrom 78/MWh to 56/MWh.

For the full-year 2008, net income grew 10.7% in 2008to CZK 47 billion on revenues that were up 104% toCZK 182 billion. Some 64 TWh was generated in CEZGroup power plants in 2008, down 6.1 TWh year-on-year. Trading activity was up some 64% for 2008, withCEZ expanding its trading to include coal, gas andCertified Emission Reductions. Electricity purchasedoutside of own generation in 2008 reached 59.5 TWh,up from 36.1 TWh in 2007.

MIBRAG SOLD TO CZECH DUO


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CEZ, J&T buy Germanys Mibrag

THE LONGER VIEW


ANALYSIS

12

PiEs latest longer view charts, laid out below, amplyillustrate what utilities have been saying through the 2008results season; last year was the most volatile commodityprice period witnessed in most working lifetimes.

For the European power sector the rollercoasterhighlights are as follows: year ahead baseload power inGermany/France down from 85-90/MWh in September2008 to 46-47/MWh March 4, 2009; coal down in thesix months to January 2009 from $190 to $80 permetric ton, and down another $20 to $62/mt by earlyMarch; Q2 2009 UK NBP gas down from 85 pence/thSeptember 4 to 38.5 pence/th February 19; andDecember 2009 carbon down from 30 in June 2008 tounder 10 in early February.

Through all the turmoil, utilities have struggled tomaintain a semblance of stability in their margins.Even ignoring the Everest-like ascent/descent of UKday ahead spark spreads in late 2008, continentalgas plant spreads have been volatile, yo-yoingbetween 10-20-30/MWh depending on the marketthrough November and December, before fallingheavily in January and staggering up and down since.

According to Platts data, on March 4 the monthahead clean spark spread in the UK stood at justunder 8/MWh, in Germany at 5.30/MWh and inthe Dutch market at 6.16/MWh. Little wonder thatthe newsflow on CCGT project development hasalmost entirely dried up.

Month ahead dark green spreads for coal plantmeanwhile have plummeted from over 30/MWh inGermany and 40/MWh in the UK last October to below7/MWh and 10/MWh respectively March 4. It is worthnoting, however, that through February 2009, clean darkspreads were little changed (UK) or indeed stronger(Germany) than in February 2008. A coal trader onMarch 4 noted that despite the recent drop in the darkspread, European coal-burn was still strong. Powerprices may have fallen, but coal is still in the money andmany coal-fired plants are running flat out, he said.

While running coal plant flat out in Germany has noimplications for capacity margins in future, in the UK itdoes (see Drax feature on potential early closure of 6-GW of opted-out capacity as old plants burn throughallotted hours). This has clearly unnerved the UK

Platts Year Ahead Base Power Assessment (/MWh)

Source: Platts

20

40

60

80

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120

Feb-09Nov-08Aug-08May-08Feb-08Feb-07 Aug-07May-07 Nov-07

United Kingdom GermanyNetherlands SpainFrance

30

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80

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CIF ARA 90-day forward coal price ($/mt)

Source: Platts

50

90

130

170

210

250

Feb-09Aug-08Feb-08Feb-07 Aug-07

Coal-power green dark spreads (front month)

35% efficient coal plant (MWh)

March 4, 2009

UK 9.96Germany 6.86

October 28, 2008

UK 43.85Germany 33.20

July 25, 2008

UK 24.30Germany -7.76

Source: Platts Coal Trader International

Rolling down the mountain

The Longer View

THE LONGER VIEW


ANALYSIS

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government, which, in the absence of any forwardmomentum in new coal plant development, has beenleading the charge in Brussels for a second wave of opt-outs from industrial emissions legislation starting in2016 (see page one).

The high level of coal burn has no doubt beenencouraged by recent low CO2 prices, and more broadlyby the fact that the power sector is now into the lastfour years of free carbon allowances under the ETS,during which time excess coal-fired generation hasmanageable carbon cost implications at least atprices of 10-12/t CO2.

A price today of 12/t CO2 will be welcome in EuropeanCommission circles considering the 8-9/t lows of mid-February, which prompted speculation that Phase 2 couldrun the same way as Phase 1, prices could fall to zero ina recession-hit market, damaging the ETS credibility.

In fact the low carbon price (caused by large, distressedindustrials selling allowances to raise short-term cash)has drawn a wave of speculative money into the market.The rush of industrials to sell quota opened up arbitragepossibilities for speculators to buy low and sell to thosewho still need carbon allowances, a trader said.

Looking ahead, the spread between German year-ahead (2010) and calendar year 2011 baseload

power prices has been widening, suggesting that themarket thinks any economic recovery will be delayeduntil 2011, traders said.

The German Cal 10/11 baseload spread has grown from2.20/MWh on February 12 to 3.35/MWh on March 2,when Cal 10 baseload closed at 42.65/MWh and Cal11 baseload around 46/MWh. With Cal 12 baseloadaround 49.80/MWh, the German far power curve wasin full contango that day.

Cal 11 isnt quite as bearish as its front-year relative,and this is certainly because fewer and fewer playersbelieve in an economic recovery in 2010 but rather expectit to be delayed until 2011. This is reflected in powerdemand projections for those years, one trader said.

Another source said the more bearish sentiment forCal 10 was because of the current correlation betweenGerman forward power and oil and equity prices, whichreact fastest to macroeconomic developments, he said.In the long-term, however, coal will remain the biggestprice driver for German forward power and while wehave no serious information about oil and equityprices for 2011, the coal forward curve is in contango,with CIF ARA 2010 at $72/metric ton and Cal 11 coalat $78/metric ton, putting the spread around $6/mt,he said. In the second week of February, this spreadwas around $4.50/metric ton.

December 2009 Carbon (/mt)

Source: Platts

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Oil and Gas comparisons

Source: Platts

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160Dated Brent ($/bbl)UK NBP day-ahead (p/th)Dutch TTF day-ahead (p/th)

Feb-09Aug-08Feb-08Feb-07 Aug-07

Platts Day Ahead Base Spark Spread (/MWh for 7,000btu/kWh)

Source: Platts

-20

0

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United KingdomGermanyNetherlands Belgium

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Feb-09Jan-09Dec-08Nov-08

Feb-09Nov-08Aug-08May-08Feb-08Feb-07 Aug-07May-07 Nov-07

NEWS

Belgium

Nuon re-tenders for Seneffe CCGTDutch utility Nuon has tendered for a 400-500-MWcombined cycle gas turbine power station at Seneffe,Walloon, Belgium.

In a note in the EU Official Journal March 3, Nuonsaid an engineering, procurement and constructioncontract for the gas-fired power plant was due to startFebruary 1, 2010. No completion date was given. Bidsor requests to participate in the competition are due byApril 7, Nuon said.

A previous EPC tender for the project was cancelledin October 2008. Nuon has said it hopes to gain finalconsents to proceed with Seneffe during 2009.

On February 23 Swedish utility Vattenfall made a8.5 billion all-cash offer for 100% of Nuon. The Dutchutilitys management and supervisory boards haveunanimously recommended the deal to shareholders.

Contact: Jacques van den Dool, NL-1009 DCAmsterdam. Tel. +31 610569437. E-mail:[email protected].

Belgium in brief . . . SPE has obtained its construction permit for itsproposed CCGT at Navagne. The plant will cost 550million. Construction will begin at the end of this year,with the 860 MW plant due to be generating by early2012. SPE is a Centrica affiliate, in which the UKcompany holds 49%.

Belgian bank, Dexia, and Econcern of theNetherlands, have confirmed that they hope to completeby Spring this year the finance package for the Belwindoffshore wind farm project. This would enable the firstphase of the project to be completed by end-2010.Belwind N.V. is a project company of Evelop (an Econcerncompany) set up to develop the wind farm on Bligh Bank,46-km offshore. Once both phases are complete,capacity will be 330 MW. Belwind has agreements withElia on a grid connection and sale of green certificates.

Europe

EP pushed to vote again on CO2A cross-party group of 44 European Parliament membersis pushing for proposals for emission limits for largecombustion plant to be included in the report on a newEU industrial emissions law that the EP is due to vote onMarch 12, environment group E3Gs Mark Johnston toldPlatts on March 5.

The group is proposing that all power plant with morethan 500-MWth permitted after the law takes effect

comply with an emissions limit of 350g CO2/kWh from2020, and that all existing similar-sized power plantcomply with the same limit from 2025.

The 500-MW thermal rating would translate intoabout 210 MW power capacity for coal plant and about260 MW power capacity for combined cycle gas turbineplant, said Johnston.

The group has also proposed that the EuropeanCommission review these provisions by June 30, 2014,and consider lowering the emissions limit to 150gCO2/kWh, bringing forward the 2025 deadline andwidening the scope beyond the power sector.

A 350g CO2/kWh limit rules out new coal unlessfitted with carbon capture and storage, Johnston told ameeting in the EP March 3. The tighter limit of 150gCO2/kWh would mean only gas and coal plant with 90%CCS would be allowed. The 500-MW thermal thresholdwould mean that the emission limits would apply to about500 power stations in the EU today, said Johnston.

A similar proposal was thrown out of the reportadopted on the new emissions law by the EPsenvironment committee on January 22 by the committeeschairman on a procedural technicality without a vote,said Johnston. The same procedural issue, centered onwhether including CO2 extends the scope of the originallaws, could see the latest proposals thrown out againbefore the EP votes on the committees report, he said.

The new Industrial Emissions Directive (IPPC) is toreplace the EUs integrated pollution prevention andcontrol directive, which sets limits on pollutants (excludingCO2) and the EUs large combustion plant directive.

Coal lobby group Eurocoals secretary generalThorsten Diercks told the EP meeting that the EP hadtwice rejected power plant emission limits in the lastyear once as part of the EUs third energy marketopening package and again as part of the EUs climateprotection package.

Diercks argued that mandatory emission limitsshould only be considered once CCS had been provencommercially. Meanwhile it must be possible to buildcapture-ready plant that will knock out half or two-thirds of the new coal plant planned in the EU, he said.We wont be locked in because [CCS] will be retrofitted.If in 2016 or 2017 we see that CCS is possible, then wecould have an obligation for it after that.

ETS needs floor price: TurnerThe European Union should consider introducing a floorprice in the EU Emissions Trading Scheme to protect thesystem from price collapses, the chairman of the UKscommittee on climate change, Lord Turner, said March 4.

Speaking in a public evidence session in London,Turner said a minimum price for EU Allowances could beintroduced to provide a more robust price signal forclean investment.

When asked whether his committee believes thecarbon price under the EU ETS is capable of achievingits emissions reduction goals, Turner said: If the carbonprice continues at current levels, it would not send thesignals which are required. We will look again at the

BELGIUM / EUROPE


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whole issue of the carbon price in our September report.There is a part of the report that looks at theimplications of the current economic recession.

The carbon price has come down a lot this yearbecause emissions are coming down. But aninteresting issue is whether the price has come downmore than market economists would predict. What theywould say is that there is a fungibility of supply anddemand for carbon permits across the whole of PhaseII and Phase III, he said.

Since the overall carbon cap in Phase III, from2013-2020, is expected to be more stringent than thecurrent cap, this should be driving up the carbon pricenow, he said.

So the price today ought to be reflecting not justhow many emissions there are today but also aforesightful markets view of the balance between supplyand demand in 2019 and 2020. I think its highly likelythat the fall in the market price has been significantlylarger than you might think is logical if you believe thatefficient market theory, he said.

EUAs for delivery in December 2009 fell from30.45/metric ton CO2 in July 2008 to a low of8.33/mt February 12 before staging a rebound toalmost 12.00/mt March 4.

Turner said the committee on climate change hadsuggested a range of tools to improve market direction,one of which would be to combine the EU ETS with afloor price for carbon.

There has been a debate among economists as towhether the best approach is a fluctuating price forcarbon in a trading system or a straight tax on carbon,but it is completely possible to combine that using ahybrid system which has a fluctuating price [and] also afloor price within it, so that participants know that atthat point it becomes a tax and will not be allowed to fallbelow that level, he said.

The committee was established as an independentbody under the climate change act to advise thegovernment on setting carbon budgets and report toparliament on progress in cutting GHG emissions. In linewith the EU framework, the committee has produced anintended target of a 42% cut in GHG emissions from1990 levels by 2020, which should apply following aglobal deal on climate change, and an interim target tocut emissions by 34% from 1990 levels by 2020 toapply before a global deal is reached.

GDF Suez pulls out of BeleneFrances GDF Suez said February 18 that it had decidednot to pursue its interest in participating in the 2-GWBelene nuclear power project in Bulgaria and wouldinstead focus on other nuclear projects. GDF Suez hadbeen in talks with RWE to take part of the German utilitys49% stake in Bulgarias second nuclear power plant but acompany spokesman said it had decided to focus on newreactors in France, the UK, Romania and Abu Dhabi.

RWE Power acquired a 49% stake in a joint venturecalled Belene Power Company to plan, build and operateBulgarias second nuclear power plant at Belene on the

Danube with the signing in December of an agreementwith state utility NEK. RWE Power, which was selectedlast October as NEKs preferred partner over a rival bidfrom Electrabel, invited GDF Suez to join the projectunder its leadership, and had expected to split its stake.RWE Power said it remained committed to the project.

Greeks target Bulgarian windTwo affiliates of Greeces Copelouzos Group are planningto build a series of wind parks with a combined capacityof just over 300 MW south of the Bulgarian town ofKrumovgrad, near the border with Greece. Bulgariassector regulator, the State Energy and Water RegulationCommission, announced February 2 that powerproduction licences should be given, after financialclosure, to NECO for three wind parks with a combinedcapacity of 72 MW, and to Elika Bulgaria, for five parkswith 236 MW installed capacity. The firms applied forand received 15-year licenses, but indicated clearly thatextensions would be requested at the end of this period.

The investment budget for the NECO parks is 79.2million while that of the Elika projects is put at 259.6million. Non-binding letters of intent from the NationalBank of Greece indicate a willingness to supply creditsworth 70% of budgeted investment in each wind park.The calculations involved in the two business plansassume, inter alia, that relevant feed-in tariffs will risefrom Lev 185.95/MWh now to Lev 208.93 in 2010 andLev 297.73 in 2024.

Finland

Areva absorbs 47% O-3 overspendFrench nuclear firm Areva is to absorb a 47% costoverrun of 1.7 billion on its turnkey contract for theOlkiluoto-3 nuclear power plant it sold to Finnish utilityTeollisuuden Voima Oy, Areva officials said February 25.The EPR project is three years behind schedule and nowtargeted for completion in 2012.

The running total loss includes a 749 millionprovision taken for 2008, Areva officials said during awebcast on 2008 results. The 1.7 billion total does notinclude additional amounts that are the subject ofpending arbitration between Areva and TVO. The 47%cost overrun is based against the full 3.3 billioncontract, which included fuel supply, as well as thereactor construction.

The project should meet its 2012 completiondeadline if TVO can pass on documents faster, ArevaCEO Anne Lauvergeon said during the webcast.Lauvergeon said it takes an average of more than 12months for TVO to validate the technical documentationbefore passing it on to Finnish regulator STUK. Thecontract for Olkiluoto-3, which Areva and Siemens arebuilding for TVO, calls for the work to be done in twomonths. If TVO can speed up the processing ofdocuments, theres quite a likelihood well make that2012 date, she said.

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France

CCGT tariffs reviewedEnergy regulator CRE has launched a consultation onhow to handle a request from GRTgaz (the gas networkoperator) for a change of tariff structures, andoperational terms and conditions, for supplyingcombined cycle plants.

GRTgaz informed CRE at the end of January that inthe current framework, it cannot meet the significantneed for intra-day flexibility which will be generated bypeak and semi-baseload demand from new gas-firedpower units coming on stream. TIGF, the TSO in southwestFrance, has told the CRE it has similar problems.

As part of the consultation GRTgaz has submitted anote of its intentions, setting out the principles itproposes to use to deal with the situation. The contextis a sharp increase in potential gas-fired capacity. CREsays some forty projects have applied for access to thegas transmission network since 2006. Twelve contractshave been signed four from 2009, four from 2010 andfour from 2011 a total generating capacity for thesetwelve alone of 6,000 MW.

The core issue is flexibility services, and who shouldoffer them. GRTgaz does not believe it should. CRE saysthere are precedents in Europe for models in which theTSO offers them and for third parties to offer them, andit has not formed a judgment for the time being.

A key issue for CRE is non-discrimination. It is askingkey players what criteria should be used for decidingpriorities the location of the plants in relation to thenetwork, or the status of the project (operational, with anaccess contract, or still in the planning stage). In addition,it wants to know whether, if hourly balancing obligationswere introduced, these should only apply to power plants(as GRTgaz envisages) or should be extended to otherlarge consumers, or even all gas consumers.

Areva warns SiemensFrench nuclear power technology group Areva has warnedSiemens, the German engineering giant, that Siemensplan to create a nuclear joint venture with Rosatom ofRussia is a breach of Siemens contract with Areva.

Siemens has a 34% share in Areva NP and under ashareholder agreement from January 2001 entered intoobligations including a non-compete clause, Areva saidin a statement on March 4. Areva has informedSiemens that by announcing this joint venture it is inbreach of contract, with all the ensuing consequences byvirtue of the shareholders agreement, said Areva.

On March 3 Siemens announced a nuclear jointventure with Russian nuclear company Rosatom.Siemens said the joint venture would work to developRussian pressurized water reactor (VVER) technology.It would handle marketing, sales and theconstruction of new plants, Siemens said, as well asupgrades of existing plants.

Siemens had said in January that it wanted to pullout of the agreement with Areva NP. Siemens AG will

terminate the shareholders agreement for the Franco-German joint venture Areva NP...specified effective latestJanuary 30, 2012, and sell its entire stake to themajority shareholder Areva SA under the terms of a putagreement, Siemens said.

Under the shareholders agreement, Siemens isnot allowed to compete in activities it brought toAreva NP for a period of eight years. That includesnuclear reactor design and engineering, turnkeynuclear power plant construction, fuel design andmanufacture, services, and safety-relatedinstrumentation and control systems.

Siemens said it can, however, market turbines,generators and electrical systems for nuclear powerplants since those items are not produced by Areva NP.

Meanwhile on February 25, Areva CFO Alain-Pierre Raynaud said Areva must compensateSiemens 2.05 billion for giving up its share inAreva NP. The figure is based on values assigned forthe Siemens share in 2007.

Mixed bag for new entrantsNew entrants are nibbling away at the incumbentsshare of the French residential power market, but losingground in the business market according to the latestQuarterly Observatory from the French regulator, theCRE. Alternative suppliers had 19% of the residentialmarket by number of sites as of end 2008, up from18.1%. They had 10.6% of the non-residential sites,down from 12.7%.

In terms of consumption, the picture is the same:alternative suppliers had 2.3% of the residentialmarket, i.e. 3.3 TWh, and this was up from 1.7% threemonths earlier. In the case of the non-residentialmarket, the figures were 11.6% and 34 TWh at the endof the fourth quarter, whereas alternative suppliers had12.4% of non-residential consumption at the end of thethird quarter of 2008.

GDF Suez targets third EPRGDF Suez is in discussions with EDF over its involvementin Frances second European pressurized reactor,planned by EDF at the Penly site, GDF Suez CEO GerardMestrallet said March 5. And the government supportsGDF Suez role as prime contractor and operator of athird EPR, Mestrallet said. The government has yet tocommit to a third EPR.

GDF Suez posted a net profit of 6.5 billion for2008, 13% up on 2007. This included 1.9 billion indisposals, mainly stakes in Belgian companiesDistrigas and Fluxys, the company said. Regulatoryfactors hampering group profits included the inabilityto pass on to customers the full increase of naturalgas supply costs, it said, as well as a 250 millionlevy charged by the Belgian government on nuclearproducers in Belgium, of which GDF Suez subsidiaryElectrabel bore the brunt. The company is to take theBelgian government to the Constitutional Court toappeal against the tax.

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France in brief . . . French grid operator RTE recorded a 36.7% decreasein 2008 net profit to 295 million as operating costsincreased 13% to 1.062 billion mainly because of moreexpensive wholesale power purchasing, the networkoperator said March 4. A 2.6% drop in industrialconsumption in 2008, which accelerated in the last threemonths of the year, had not had a significant effect onresults, RTE said. At the end of December 2008, RTEsnet debt had risen by 108 million to 6.064 billion.

Germany

ENBW inches into onshore windENBW has bought three small onshore wind projectswith together 52-MW from wind developer PlambeckNeue Energie for a high eight-digit figure, raising itsonshore wind capacity to 80 MW. The 10 MWSchwienau 2 project was commissioned in January2009. The Buchholz plant with 36 MW was beingcommissioned in February. The 6 MW Alt Zeschdorf isunder construction. The additions take ENBW a smallstep towards its target of a 20% renewables share ofelectricity generation by 2020.

The onshore activities follow an offshore initiativestarted in May 2008 when ENBW acquired Eos Offshoreand Offshore Ostsee Wind. These companies own therights to Hochseewindpark Nordsee and He dreiht(bothof 400-MW and both in the North Sea), and KriegersFlak 1 with 400 MW and Baltic 1 with 52.5 MW in theBaltic Sea, totalling over 1 GW. Installation of Baltic 1may begin this year.

State needs nuclear earnings: RWEThe global financial crisis could help persuadeGermanys next government, after elections inSeptember, to reverse the nuclear phase out law,according to RWE chairman Jrgen Grossmann, speakingat a press conference on February 26.

If the nuclear phase-out continues, the first plant toclose will be Biblis A in summer 2010, he said. But hebelieved nuclear lifetimes should be extended,describing the benefit to energy companies of longeroperation of written-off reactors as an advantage to theeconomy rather than windfall profits. The state mustdecide what to do with this advantage, he said. Idont want to speculate he continued, but in view of themassive public support being poured into banks andindustry, the state needs new sources of income andhere is one readily available.

Longer running times for nuclear would put downwardpressure on the wholesale price of power, observed RWECEO Ulrich Jobs. Ironically, this would run counter toRWEs intention of increasing its operating result by anannual average of 5-10%, instead of the previous targetof 5%, to 2012 (not including the planned acquisition ofEssent) since this aim assumes an average realisedGerman electricity price of at least 60/MWh during theperiod. Sales of RWEs 2008 generation in Germanyfetched an average price of 58/MWh, compared with47/MWh in 2007, according to the company.

Outside Germany, RWE is already pursuing newnuclear projects. It has the option of a 49% stake in ajoint venture with Bulgarian NEK to build two 1-GWnuclear units at Belene. RWE is also one of six partnersin plans at Romanias state-owned SNN to build twoCernavoda 720-MW units. If the project stays onschedule the units could go online in 2015/2016. Andthe company has set up a joint venture with E.ON tobuild up to 6-GW of nuclear capacity in the UK.

On the question of disposal of radioactive wastefrom the new projects, Grossmann said it was EU policyfor each member state to deal with its own waste. Hebelieved problems associated with end storage weremore of political and social-acceptance character thantechnical. Nuclear is growing world wide, its not just atheme for Germany, he said.

RWEs electricity generation was up 4% in 2008 to224.1 TWh, of which 180.3 TWh was contributed by RWEPower in Germany. At the start of 2009, RWE hadalready sold 90% of 2009 generation, 70% of 2010generation and 30% of 2011 generation.

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RWE generation 2007-2008 (TWh)

RWE Power RWE Npower RWE Group

2008 2007 2008 2007 2008 2007In-house generation 180.3 178.9 36.7 33.8 224.1 216.1Lignite 73.9 76.1 - - 73.9 76.1Coal 43.1 55.3 18.0 15.1 62.0 71.0Nuclear 49.3 32.1 - - 49.3 32.1Gas 11.5 10.1 18.2 17.7 31.2 29.3Renewables 0.6 3.2 - 0.8 5.3 5.2Pumped storage, oil, other 1.9 2.1 0.5 0.2 2.4 2.4purchased from third parties - - 18.1 23.7 110.1 108.2Total 180.3 178.9 54.8 57.5 334.2 324.3

RWE Power figures include electricity procured for plants not owned by RWE but deployed at its discretion according to long term agreements in2008, this amounted to 30.6 TWh, of which 28.6 TWh was coal generated, largely by coal plant owned by Evonik Industries. RWE Group figuresinclude generation and purchase of RWE Energys regional companies and the renewables business transferred to RWE Innogy in 2008. RWENpower largely purchases electric via RWE Supply and Trading

Source: RWE, Platts

Meanwhile, despite government and energy regulatorpressure for a single high voltage network company inGermany (instead of the current four), RWE has nointention of shedding its network, but rather is creatingan independent transition operator to meet thestipulations of the European Commissions upcomingthird internal energy market package. Grossmann saidthe regulated business worked well in RWEs portfolioand would remain a core business, not least because itbrought a steady income flow.

Power exports strengthenGermany recorded an even larger electricity exportoverhang in 2008 than in the previous two years, at22.5 TWh compared with 19.1 TWh in 2007 and 19.8TWh in 2006. Exports flowed mainly to the Netherlands,Austria and Switzerland, while imports flowedpredominantly from France, Denmark and the CzechRepublic, according to figures from electricity, gas andwater federation BDEW.

Nuclear power was back in form last year with outputof 149 TWh, after 140.5TWh in 2007, displacing inparticular coal generation which clocked up just 129TWh in 2008 compared with 142 TWh in 2007.

The higher nuclear share contributed to a reductionin specific CO2 emissions, to an estimated 0.57 kgCO2/kWh compared with 0.6 kg/kWh in 2007. A 5-TWhincrease in renewables output to 93 TWh in 2008 alsoplayed a role, although the year on year rise to 2008was just a third of the 15 TWh increase in renewablesgeneration between 2006 and 2007. Most of the wind,solar and other (also largely renewables) generationwas accounted for by independent operators, thecorporate energy companies playing only a minor rolein renewables.

Greece

Intrakat, Suez target EfWGreek construction company Intrakat and SuezEnvironnement of France are to co-develop Energy fromWaste projects in Greece, the companies said in a jointstatement February 23.

At present there are no waste-to-energy plants inGreece, where most municipal solid waste is landfilledwithout treatment, in contradiction with EU environmentalobjectives, the companies said.

Several large Greek municipalities are expected tolaunch public-private waste management partnerships inthe coming months, the companies said, where waste-to-energy systems could play a crucial role.

Suez Environnement, a 35%-owned affiliate of Frenchenergy group GDF Suez, operates 50 large waste-to-energyfacilities in Europe, processing seven million metric tonsof municipal waste a year. The largest facilities in Europeburn around 600,000 metric tons of waste and produce500 GWh of electricity a year. Heat offtake is used indistrict heating systems or industrial applications.

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German imports/exports 2008 (provisional)

Import Export Balance

Country TWh % change TWh % change TWh

France 10.6 -35.7 0.9 +19.1 +9.7Luxembourg 0.8 +2.1 5.3 +1.7 -4.5Netherlands 0.8 +176.0 18.9 +4.4 -18.0Austria 5.6 +24.3 15.0 -7.0 -9.4Switzerland 2.7 -12.8 13.9 -7.8 -11.1Denmark 9.2 +17.2 1.4 -7.3 +7.8Czech Republic 7.9 -15.7 1.3 +49.7 +6.6Sweden 2.5 +36.4 0.5 -44.1 +2.0Poland 0.1 +100 5.6 +14.0 -5.5Total 40.2 -9.1 62.7 -1.1 -22.5

Source: BDEW

German generation by fuel (TWh, 2007/08 provisional)

2006 2007 2008

Lignite 151.1 155.1 150.0Nuclear 167.4 140.5 148.8Coal 137.9 142.0 128.5Gas 73.4 75.9 83.0Oil 10.5 9.7 10.5Hydro 26.8 28.1 27.0Wind 30.7 39.7 40.2Other 39.1 46.4 51.1Gross generation 636.8 637.6 639.1Electricity imports 46.1 44.3 40.2Electricity exports 65.9 63.4 62.7Import/export balance -19.8 -19.1 -22.5Electricity consumption including network losses 617.0 618.4 616.6

Source: BDEW

German renewable energy generation (TWh)

2006 2007 2008

Hydro 20.0 21.2 20.8Wind 30.7 39.7 40.2Biomass 15.5 19.4 23.0Waste (only renewables share of 50%) 3.7 4.5 5.0Photovoltaic 2.2 3.1 4.0Total 72.1 87.9 93.0

Source: BDEW

German net power station capacity (MW)

2007 2008

Including Without Including WithoutFuel IPPs IPPs IPPs IPPs

Hydro 5,166 4,300 5,205 4,310Pumped storage 5,710 5,710 5,710 5,710Lignite 20,516 19,860 20,516 19,860Coal 27,596 25,305 27,405 25,305Nuclear 20,470 20,470 20,470 20,470Oil 6,258 5,700 6,190 5,650Gas 23,394 19,300 23,394 19,300Wind/solar 26,159 235 28,728 255Other 9,000 3,508 9,471 3,607Total 144,269 104,388 147,089 104,467

2008 figures provisional

Source: BDEW

Italy

Board room blitz at AceaAcea, Romes power and water utility, has been throwninto uncertainty by top management upheaval. At aboard meeting on March 3, Andrea Mangoni, the firmsmanaging director, tendered his resignation on thegrounds that he no longer enjoyed the confidence ofthe main shareholder. Mangonis resignation wasaccepted by the board.

The board, whose chairman is Giancarlo Cremonesi,also received the resignations of Roberta Neri, Aceashead of planning and finance, and of Massimiliano Salvi,head of energy networks. With responsibilities that includecompany financial records, Neri holds an importantgovernance role. The board is expected to meet on 27March to approve Aceas 2008 financial statements.

Behind the boards troubles are disagreements onstrategy, in particular alliances with GDF Suez on whichMangoni had been working for more than a year. Holdingalmost 10% of Aceas share capital, the French group isAceas second largest shareholder after the cityauthorities, which own 51%. Francesco GaetanoCaltagirone, a Rome constructor and newspaper-owner,owns just over 5% through three of his companies.

The situation at Acea provides another example ofthe role of politics in Italys local utilities. Elections lastyear took Gianni Alemanno, a politician who made hiscareer in the post-fascist Alleanza Nazionale party, to themayors office, where his predecessor was WalterVeltroni, a leading centre-left politician. Mangoni hadbeen appointed during Veltronis term.

Edison hit by tax, demand slumpEdison has reported 2008 sales of 11,066 million, upby 33.7% on 2007, while the groups gross operatingmargin improved by 2.4% to 1,643 million and the pre-tax profit by 6.3% to 730 million.

Introduction of what is generally called the Robin HoodTax and of an anti-crisis decree, coupled to a non-recurringpositive tax item that had helped the results in 2007, leftEdisons post-tax profit down 30.4% at 346 million.

Edison pointed out that demand for energy fell in Italyin the fourth quarter 2008, the first time demand hasfallen since the 1981 crisis. Between October andDecember, electricity demand fell 5%, helping the full-yearsfigure to slip by 1%. Due to a fourth-quarter drop of 15%,industrial power demand fell by 9% in the year overall.

Power continued to be Edisons principal businesslast year, sales of electricity advancing by 28.1% to8,689 million, compared with 5,093 million fromhydrocarbons. Gross operating margin from Edisonspower business rose by 7.1% from 6,783 million in2007 to 1,326 million last year, equivalent to 15.3% ofsales against 18.3% in 2007.

From its capacity of 12,100 MW, which includes its50% interest in Edipower, Edison produced 50.2 TWh in2008, equivalent to 16.4% of total Italian production of305.5 TWh. The groups market share was, however,

somewhat greater in terms of sales. Of last years totalItalian demand of 337.6 TWh, Edison provided 67.2TWh, equal to 19.9%. Taking 28.4 TWh, clients in thefree market provided the main demand for Edisonssales, followed by the power exchange, through whichthe company sold 21.1 TWh. Edisons CIP6/92 salesamounted to 13.1 TWh in 2008. The company notedthat sales to markets, both to clients supplied in thefree market and through the exchange, advanced by20.3% last year on the 41.2 TWh sold in 2007.

Most of the 50.2 TWh net production came fromthermal plant which accounted for 34.0 TWh, down10.5% on 2007. Net hydro output was 30.1% higher at3.9 TWh, while Edipowers contribution was 1.4% lowerat 11.8 TWh. Edisons imports were significantly lower at0.4 TWh, against 1.2 TWh in 2007, while suppliesobtained within Italy increased by 83.5% to 16.9 TWh.

Contributing to the fall in thermal output was thesale of six small CIP6/92 plants in April last year andthe consequent loss of about 370 MW of ca

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