Select Committee on Environmental Audit Written Evidence


Memorandum submitted by Malcolm Grimston

A.  THE EXTENT OF THE "GENERATION GAP"

  It is important to distinguish between potential "power gaps" and "energy gaps" when considering generation of electricity.

  The power gap refers to the possibility of electricity outages caused because of insufficient generating capacity being available to meet peak demand. The energy gap refers to a mismatch between the total electricity demand over a period of time, say a year, and the total amount of electricity generated over that period of time.

  For most commodities, including many energy sources such as oil, gas and coal, the focus is generally on the latter, since it is possible to stockpile large amounts of the commodity. (This being said, there are growing concerns about the UK's storage capacity for natural gas as North Sea reserves become depleted.) This is not the case with electricity—the absence of a large-scale storage method means that secure supplies can be threatened not only by a chronic shortage of fuel or failure of the transmission system but also by insufficient capacity to cope with unexpectedly high demand and/or high levels of unscheduled plant outage.

  While the UK has maintained a "capacity margin" of between 15 and 25% in recent years, the fall in investment in new plant since 2000 following the "dash for gas" suggests that this situation may not continue.

New installed capacity since 1991, UK (MW, cumulative)[160]

  (Capacity margin, expressed as a percentage, is defined as:

  Generation capacity—Average Cold Spell (ACS) demand

  It is generally accepted that a capacity margin of between 12% and 20% is needed to ensure secure power supplies against unexpected events such as a surge in demand, perhaps because of extreme weather conditions, or the unexpected breakdown of a considerable number of generating plants. The precise size of the required margin depends on factors such as access to imports and the fuel mix used for electricity production.)

  As it is, secure electricity supplies in the UK are already vulnerable in extreme circumstances. On 10 December, 2002, the UK faced its highest power demand then recorded, of 54,430 MW, some 5% higher than the previous maximum, as a result of a cold spell which developed over the previous four days. It occurred in the context of breakdown of some 3,500 MW of capacity over the previous week. In the morning of December 10 it seemed that the demand would be met comfortably but in the three hours before the hour of peak requirement a record amount of plant was withdrawn because of breakdown (about 2,400 MW). Plants with technical problems were called up or ordered to continue generating and all steam plant was instructed to operate at full stretch. Although outages were avoided it was close-run thing and the balancing price reached £10,250 for a single MWh tranche.[161]

  Higher futures prices for the winter of 2003 led to companies returning capacity from mothballing: in 2005 Ofgem announced that energy supplies to domestic customers could be maintained even in a 1-in-50 winter and that the electricity capacity margin stood at over 20% [162] However, bringing plant back from mothballing is a different matter from investing in new projects and it remains unclear whether enough investment is being made to deal with shortages in the medium term (say up to 2010).

  In the longer term, a combination of closure of most of the UK nuclear fleet by 2020 and of much of the UK's coal capacity in the same period (owing in part to the effects of the European Large Combustion Plant Directive which will severely restrict permitted emissions of sulphur dioxide) with ongoing growth in electricity demand suggests that considerable new investment in plant will be required simply to meet the potential gaps in both energy and power production. At the end of 2004 some 73,300 MW of capacity were registered in the UK by major power producers (with another 7,000 MW owned by auto-producers), of which 22,600 MW were coal-fired and 11,900 MW nuclear[163] Assuming capacity requirements in 2020 of about 85,000 MW (a central estimate derived from various government publications, notably the supporting statistics to the 2003 Energy White Paper) it is likely that some 34,000 MW (40% of 2020 requirements) of new capacity will be required by that date. It follows that the battle is not between "nuclear or renewables", as it is sometimes portrayed—large amounts of plant will be needed and there is plenty space (and perhaps even need) for both.

  It should be noted that, from a power gap point of view, some renewables, notably windpower, cannot be counted as a pro rata contribution towards overall capacity as their output is too dependent on weather conditions. Wind availability tends to be inversely correlated to electricity demand—anticyclones that bring cold winter nights and hot summer days tend also to bring low wind speeds. For example, in 2003 E.On Netz was taking output from over 6,000 MW of wind capacity in Germany. The output could fluctuate widely within relatively short periods of time.

Fluctuations in wind power feed in E.On Netz control area, November 2003[164]

HOW DO THESE RELATE TO ELECTRICITY DEMAND FORECASTS AND TO THE EFFECTIVENESS OF ENERGY EFFICIENCY POLICIES?

  Taking the middle estimates from publications such as Energy Paper 68[165] and the supporting documents to the 2003 White Paper[166] it is possible to construct a plausible middle estimate of electricity demand and fuel mix for 2020, which appears as follows:


UK Fuel mix 2020?-demand 381 TWh[167]

  The 2020 figures assume that the aspiration for 20% of electricity to be generated by renewables is achieved but that no new nuclear plants are built, so that in effect new renewable build simply replaces nuclear stations with little net greenhouse gas emission benefit. It also assumes that electricity imported from France is zero-carbon (ie nuclear). If the renewables aspiration is not met then the shortfall is likely to be provided by gas; if it is then spare capacity (again, probably gas-fired) will need to be built to compensate for the intermittency of renewable sources.

  The 2020 projection assumes considerable improvements in energy efficiency, as forecast in the source materials. Higher levels of technology-driven energy efficiency per se are unlikely to make much difference to the projections owing to "rebound" (Khazzoom-Brookes) effects.[168] However, if energy prices are increased significantly then overall energy use may be constrained further, although this would be in tension with government aims for "affordable" energy.


A.  FINANCIAL COSTS AND INVESTMENT CONSIDERATIONS

  The key point is that very large amounts of investment in new generation capacity—and, depending on its location (eg the wind resource offshore), on new grid connections and developments—will be required in any case. The comfort induced by the "dash for gas" of the 1990s has already proved temporary.

  For fossil fuels, notably CCGT (Combined Cycle Gas Turbine), costs of generation are deeply affected by the costs of the fuel itself. If we are moving into an era of oil prices at $60 per barrel plus (or even above say $40), with gas and (to a lesser extent perhaps) coal prices following suit, then the economics of these sources of electricity will look much less positive than they have done since the collapse of the oil price in the mid-1980s. Some renewables will indirectly be affected by high gas prices, since the back-up capacity necessary to underpin investment in windpower (against low or very high windspeeds reducing output) will in all likelihood be gas-fired.

  The new generation of simplified nuclear plants look economically attractive on paper if costs are viewed on a whole-cycle basis (ie including the external costs associated with environmental damage and averaged over the 50 year lifetime of the plant)—see for example the recent Royal Academy of Engineering report.[169] There are however two caveats.

  First, the new technologies have not yet been fully demonstrated, Potential investors would need to be confident that the "appraisal optimism" of the nuclear industry in the past, notably with respect to the British Advanced Gas-Cooled Reactors, will not be repeated. However, there is evidence that recent plants built in the Asia-Pacific region, which include many features of the new passive designs, are now being brought on line to time and cost. Furthermore, it is unlikely that the UK will follow a uniquely British design path in the future but will instead be able to take advantage of experience elsewhere.

  Secondly, in a competitive market high-capital low-running cost technologies tend to be at a disadvantage given the essentially short-term nature of the wholesale power market, making full-cycle costing difficult and perhaps of limited relevance owing to different levels of economic risk. Funding of new build may therefore require some mechanism for providing long-term contracts, perhaps through consortia of major electricity users/suppliers (as has been the case with the IVO plant under construction in Finland) or protected market share as the kind implied by the government's renewables obligation.

B.  STRATEGIC BENEFITS/D. HOW CARBON-FREE IS NUCLEAR ENERGY?

  The strategic benefits of nuclear energy are clear—a financial and resource hedge against fossil fuel prices and availability; and a near-zero carbon source at a time when UK greenhouse gas emissions are on a worrying increasing trend after the accidental benefits of the "dash-for-gas" and increasing nuclear output in the 1990s.

  That a major programme of nuclear energy can deliver reduction in carbon dioxide emissions of the sort required by the Royal Commission on Environmental Pollution[170] is easily demonstrated by considering the emissions per unit of electricity generated in a range of countries.


Carbon dioxide emissions per unit of electricity produced (g per kWh)

  Those countries whose electricity production is dominated by coal (Germany, Denmark) have emissions roughly 10 times those which have major nuclear (France), hydro (Norway) or both (Sweden) programmes. Should the transportation sector be penetrated by electricity (either directly or through hydrogen produced by electrolysis, for example) these benefits could be increased considerably. The costs of reducing greenhouse gas emissions by large nuclear programmes has varied considerably, but in the best cases (eg France) it is very low and may even be negative (ie very low carbon nuclear energy may be advantageous over fossil fuels in cost terms even without pricing greenhouse gas emissions by a tradable permit system or pollution taxation).

  Emissions from various fuels vary as follows.

Greenhouse gas emissions from electricity production[171]

  Assuming 90% availability, a 1,000 MW nuclear power station will produce some 7.9 TWh of electricity per year. If this were to be generated using coal (using mean life cycle figure of 1,136 grammes per kWh for coal and 15 g per kWh for nuclear) the emissions would be some 8.8 million tonnes of carbon dioxide (2.4 million tonnes carbon equivalent) higher; if generated by gas carbon dioxide emissions would be 4.3 million tonnes (1.2 million tonnes carbon equivalent) higher.

1 September 2005



160   http://www.nera.com/wwt/publications/5740.pdf, Shuttleworth G and MacKerron G, (2002), Guidance and commitment: persuading the private sector to meet the aims of energy policy, NERA: London. Back

161   http://www.nationalgrid.com/uk/indinfo/balancing/pdfs/DAY_IN_THE_LIFE_10_Dec_Issue_1_final_version_4_March_updated.pdf, Ball R. (2003), A day in the life-an operator's view of Tuesday 10th December 2002. Back

162   http://www.ofgem.gov.uk/temp/ofgem/cache/cmsattach/11583_r24_31may05.pdf, Ofgem (2005), NGT publish consultation on possible winter energy supply scenarios, Ofgem Press Release (May 31, 2005). Back

163   http://www.dti.gov.uk/energy/inform/energy_stats/electricity/dukes05_5_7.xls, DTI (2005), Digest of UK energy statistics Table 5.7. Back

164   http://www.eon-netz.com/frameset_reloader_homepage.phtml?top=Ressources/frame_head_eng.jsp&bottom=frameset_english/energy_eng/ene_windenergy_eng/ene_win_windreport_eng/ene_win_windreport_eng.jsp, E.On Netz, Wind Report 2004. Back

165   http://www.dti.gov.uk/energy/inform/energy_projections/ep68_final.pdf, DTI (2000), Energy projections for the UK. Back

166   http://www.dti.gov.uk/energy/whitepaper/ourenergyfuture.pdf, DTI (2003), Our Energy Future-creating a low carbon economy. Back

167   Grimston M (2003), Defining the value and role of nuclear power in the UK energy mix, IIR Conference Electricity Trading in the UK, London, September 30, 2003. Back

168   See http://www.rpi.edu/dept/economics/www/workingpapers/rpi0410.pdf, Stern D and Cleveland C (2004), Energy and economic growth, Rensselaer Polytechnic Institute: New York. Back

169   http://www.countryguardian.net/generation_costs_report.pdf, Royal Academy of Engineering (2004), The costs of generating electricity, RAE: London. Back

170   http://www.rcep.org.uk/newenergy.htm, Royal Commission on Environmental Pollution (2000), Energy-the changing climate, The Stationery Office: London. Back

171   http://www.iaea.org/Publications/Magazines/Bulletin/Bull422/article4.pdf, Spider J, Langlois L and Hamilton B (2000), "Greenhouse gas emissions of electricity generation chains-assessing the difference", IAEA Bulletin 42 2Back


 
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