The real cost of nuclear electricity in the UK

The detailed capital costs of the power stations for which CEGB provided comparative costs statistics in Appendix 3 of its 1979/80 Report, have become available in answer to a Parliamentary Question. Inflation corrected cost figures, calculated from these new data, support the conclusion of the previous approximate calculations, that the real cost of electricity from nuclear stations is greater than that for coal-fired stations. A previously unrecognized effect of inflation on nuclear fuel costs, together with the escalation of reprocessing costs, enhances this difference. An explanation and criticism of the CEGB's NEC calculation shows that this cost advantage to coal-fired stations is likely to be at least as great in the future. The amazing effects of Current Cost Accounting in the 1980/81 CEGB Report are commented on in an Appendix.     

Fattening up for the market? Higher electricity prices and the value of the CEGB

A mathematical model of the evolution of the electricity supply industry to beyond the end of the century is used to forecast the cost and revenues of electricity generation after privatization. Subracting the costs from the revenues gives a time profile of profits that is discounted back to the date privatization to give a valuation of the Central Electricity Generating Board (CEGB). The model shows that every 1% rise in the price of electricity before privatization adds between 2.2% and 3.3% to the value of the CEGB. The exact increase depends mainly on whether the price rises are permanent, or are clawed back after privatization by price cuts until turn of the century. The tougher financial targets for the industry announced by the Department of Energy in 1987 are expected to add about 7% in real terms to the price of electricity before privatization. The government's proceeds from the sale of the CEGB should receive a 15–20% boost as a result.     

The economics of large-scale wind power in the UK A model of an optimally mixed CEGB electricity grid

Previous calculations of the economics of large-scale wind power have been generally limited to the evaluation of the marginal cost of energy, assuming that the addition of a wind farm to an electricity grid does not change the mix of base, intermediate and peak load plant in that grid. Here a simple but powerful numerical generation planning model has been constructed for grids containing wind farms and three classes of thermal power station, but no storage. Electricity demand and available power are specified by empirically based probability distribution functions and the plant mix which minimizes the total annualized costs of the generating system is determined. Capacity credit of wind power is automatically taken into account in the optimization. Using the model, the breakeven costs of wind energy in a model British CEGB grid, containing coal, nuclear, oil and wind driven power plant, are evaluated under various conditions. For a wide range of parameter values, large-scale wind power is likely to be economically competitive in this grid.     

Communication on energy a critique of the CEGB's economic case for a PWR at Sizewell

Evidence given by the author at the Sizewell Inquiry led to the Inspector requesting a document, agreed with the CEGB, explaining the very different results obtained by the two parties on the economics of a nuclear reactor, and analysing the separate effects of changes in the assumptions on future conditions, in producing the differences in the results. Based on this agreed document, the probabilities of the two sets of assumptions are examined, and those adopted by the CEGB, especially in relation to coal prices, are criticized in detail. Assumptions on the future demand for electricity are shown to be crucial, and this question is dealt with in an Appendix.     

Fuelling costs of nuclear reactors A comparison of CANDY versus PWR nuclear fuel cycle costs using UK data PWR nuclear fuel cycle costs using UK data

Nuclear fuel cycle costs for a single PWR electricity generating station have been calculated and reported as part of the CEGB Proof of Evidence to the Sizewell B Public Inquiry. In the present study, a similar calculation is carried out for a CANDU-type station. The comparison of results shows a considerable advantage in favour of CANDU fuel cycle costs. In view of uncertainties regarding the cost and availability of reprocessing, this cost is not included in the comparison.     

Optimum sizing of investment in CHP plant for beverage-related processing industries

Using basic data for a specific brewery project, the sensitivity of discounted project net worth to capital costs and to fuel price relativities are explored. The precise balance of electricity demand to steam usage on the plant is another crucial factor and a number of marginal applications within the brewing and distilling sectors are likely to depend on the export value of surplus electricity to the national grid and the relative time-sequencing of plant demands. These demands are seen to be less severe than those associated with the interdependence of heat pump economics on supportive coactivation of other conservation techniques. Despite current decline of industrial CHP application in the UK, a widened choice of technological options with economic potential now exists and this is explored. New regulations governing the purchase of power by the CEGB are expected to contribute only marginally in the short term to economic viability of these private investments.     

Cost estimates for nuclear power in the UK

Current UK Government support for nuclear power has in part been informed by cost estimates that suggest that electricity from new nuclear power stations will be competitive with alternative low carbon generation options. The evidence and analysis presented in this paper suggests that the capital cost estimates for nuclear power that are being used to inform these projections rely on costs escalating over the pre-construction and construction phase of the new build programme at a level significantly below those that have been experienced by past US and European programmes. This paper applies observed construction time and cost escalation rates to the published estimates of capital costs for new nuclear plant in the UK and calculates the potential impact on levelised cost per unit of electricity produced. The results suggest that levelised cost may turn out to be significantly higher than expected which in turn has important implications for policy, both in general terms of the potential costs to consumers and more specifically for negotiations around the level of policy support and contractual arrangements offered to individual projects through the proposed contract for difference strike price.     

Conversion of Brighton power station to combined heat and power (CHP)

The technology of whole city heating by CHP is well established in Holland, West Germany, Denmark and Sweden. There most big towns have schemes, and the metered hot water that they supply is popular, being cheapest, safest and most trouble-free. The paper describes the technical and economic issues, but concentrates on the institutional and political obstacles to the implementation of CHP in the UK. These are due to the CEGB which wrongly seeks to build electricity-only stations (nuclear and coal-fired) with cheap public money, thus crowding out more cost-effective private investment in conservation (CHP and insulation) and renewables (e.g. tidal power). The author considers that privatisation of power stations, both projected and existing, is the best way to halt the present misallocation of resources and obtain better value for investment in electricity supply.     

Review of OECD study into “Projected costs of generating electricity—2010 Edition”

This joint report by the International Energy Agency (IEA) and the OECD Nuclear Energy Agency (NEA) is the seventh in the long established series of studies into electricity generating costs. It presents the main results of the work carried out in 2009 for calculating the costs of generating baseload electricity. The study is quite comprehensive in covering almost all financial aspects facing investors in the electricity generating system. Therefore this study although useful, its usefulness lies in explaining methodologies, mentioning factors that affect investment and cost, educating planners and improving investment evaluation and planning methodologies, its resulting figures and cost comparisons are however controversial. Generation planning and investments are case and country specific, and should be studied correspondingly and as close as possible to the timing of decision making to take account of trends. Most likely such case specific results will differ from figures calculated in the study. Therefore we need to emphasize a key conclusion of the study which is “that country-specific circumstances determine the LCOE”; it is this that needs to be considered and not the results represented in the study.     

Nuclear uncertainties: Energy loans for fission power

The energy requirements and costs of the complete nuclear fuel cycle of a light water reactor (LWR) power plant are analysed, from mining the uranium ore to dismantling the nuclear facilities and final disposal of the radioactive wastes. The most critical parameters are identified and discussed. The analysis has an empirical character: only data which are supported by practice are used. The conclusions differ significantly from previous studies, mainly because of the complete approach and the use of recent figures and trends.     

MODEST-An energy-system optimisation model applicable to local utilities and countries

MODEST, an energy-system optimisation model is described. It has been applied to a typical local Swedish electricity and district-heating utility and to the national power system. Present and potential installations and energy flows should be considered and their best combination can be obtained through optimisation. MODEST uses linear programming to minimise the capital and operation costs of energy supply and demand-side management. Seasonal, weekly, and diurnal variations of, for example, demand, costs, and capacities are considered. MODEST may be used to decide which investments to make, the dimensioning of new installations, and the operation of all system components. The municipal utility under study should now expand its heat production using woodchips. Electricity export or nuclear phase-out will probably raise the Swedish electricity prices. In this case, cost minimisation is achieved by introducing combined heat and power (CHP) production in the municipality. Fossil fuels should be used in the cogeneration plant at current taxation levels but biofuels are favourable if higher environmental fees are imposed for CO₂ emissions. Biomass capacity expansion could decrease local CO₂ emissions by 80%. Efficiency improvements for electricity use have robust profitability at high electricity prices. The Swedish electricity demand may be satisfied without nuclear power and fossil fuels through massive biomass use, wind-power supply, and energy conservation.     

Economies of scale in electricity generation in the United Kingdom

The investment programme of the Central Electricity Generating Board (CEGB) since the late nineteen fifties has been predicated in principle on economies of scale and has been largely based in practice on 500 MW(e) turbine generator sets. This paper compares the strategy adopted by the CEGB with alternative hypothetical strategies based on smaller units of plant. Simulation of the supply system over ten years suggests that the economies of scale in very large plant have not been sufficient to offset the attendant disadvantages. Allowance is made for the variation with capacity of the capital cost, thermal efficiency, construction time, planning margin and availability. It is concluded that better results might have been obtained with sets between 200 MW(e) and 300 MW(e). It is acknowledged that this post hoc analysis has only an indirect connection with the decisions that now face the CEGB. the potential economics of scale in nuclear stations are not of the same form as those in fossil fuelled stations. There are also unsatisfactory aspects of the analysis which leave some uncertainty about the validity of the conclusions. But what the analysis does show is that there are conditions where economies of scale are outweighed by other factors, that these conditions are not especially remarkable, that they seem to have been satisfied by the CEGB system and that supply utilities in developing countries, where comparable decisions have now to be taken and where the disadvantages of scale are more pronounced, should examine carefully the case for large generating units in local circumstances.     

RENEWABLE ENERGIES IN EUROPE : STATISTICS AND THEIR PROBLEMS

Eurostat official figures for 1991 show that renewable energy contribution to primary production in the European Union (12) was 7% and to gross consumption 3.7%. These figures were calculated by a methodology which takes into account the actual energy content of renewable electricity from water, wind and other sources in terms of oil equivalent as for nuclear energy, a 3 times higher value is calculated by applying a Carnot conversion efficiency of 33%.

In this paper, corresponding figures of 10.16% for primary production and 5.6% for gross consumption are calculated by applying equivalent Carnot efficiency of 38½ % for all non fossil electricity. With the addition of Austria, Finland and Sweden into the energy mix of the European Union, the renewable energy contribution for 1991 would have been 14.4% of.primary production and.7.8% for gross consumption.     

On the production of hydrogen via alkaline electrolysis during off-peak periods

This article studies the opportunity for producing hydrogen via alkaline electrolysis from electricity consumption during off-peak periods. Two aspects will be discussed: electricity spot markets and nuclear electricity production in France.

From a market point of view, when there is a significant fluctuation in electricity prices, the use of an electrolysis installation during off-peak periods makes it possible to make quite considerable savings in production costs. Savings vary enormously from one market to the next; some highly fluctuating markets offer very low off-peak prices and allow for viable hydrogen production, even if average electricity prices first appear to be quite high. Very fluctuating spot prices market may be difficult to predict and makes operations of an electrolysis installation more complicated and risky. For other more stable markets, the use of an electrolysis installation during off-peak periods does not appear to be a relevant proposition.

From the point of view of French electricity production, the availability of current nuclear power plants and the estimation of available energy for mass production of hydrogen show that the installations studied would not be viable. For “peak period” use, it would certainly be more useful to have electrolysers with a lower investment proportion, even if this means slightly higher operating costs. Research into large-capacity electrolysers should, therefore, both develop low-production-cost electrolysers, for use in base load mode where dedicated production means are concerned, and highly flexible electrolysers, with low investment costs, which could easily be viable with low rates of use.     

Large-scale economic integration of electricity from short-rotation woody crops

This paper presents an assessment of the installation of a large-scale biomass scheme for production of electricity for distribution via the national grid in Spain. The biomass scheme studied is based on woody biomass (eucalyptus, acacia and poplar) as short rotation crops in arable lands. The site selection process has been carried out with a Geographical Information System (GIS). The criteria applied in the selection, cultivation and location of the plantation as well as the biomass power plants have taken into account environmental aspects and the economic costs, always pursuing the lowest energy cost and environmental impacts. The size of each power plant has been calculated taking into account the annual productivity of biomass and the available surface of arable non-irrigated land. The costs of energy crop production in each area have been calculated as well as the storage and transport costs to supply the power plants. The technologies considered for generating electricity are fluidized bed combustion (FBC) and biomass gasification integrated into a combined cycle (BIGCC). The costs of electricity, considering also the connection costs to the electricity grid, have been calculated for all power plants. Cost figures along the fuel cycle have been obtained and a sensitivity analysis of the most relevant variables has been made. The main conclusion of the analysis is that from an economic and environmental point of view, the scheme proposed is feasible.     

Modelling the competitiveness of first generation commercial OTEC power plants

First generation OTEC plants are expected to be used mainly for baseload electricity generation in the United States Gulf Coast region. In this application, OTEC plants would compete directly with nuclear and coal-fired power plants. The prospective competitiveness of OTEC is evaluated by comparing the delivered cost of electricity generated by the three types of plant for a geographical scenario typical of the region. The comparison is carried out using a modified version of the cost of energy model developed by the Jet Propulsion Laboratory and current estimates of future construction, operating and maintenance costs for the three power plant types. Four main independent variables are considered in this study: OTEC plant capital costs, real fuel escalation rates, real cost of capital resources, and OTEC plant operating capacity factors. The first two factors are found to be prime determinants of OTEC competitiveness. The values commonly forecasted suggest that OTEC plants are likely to deliver electricity at roughly the same cost as nuclear and coal-fired power plants by the year 2000. By contrast, variations in the real cost of capital resources and in OTEC plant capacity factors are found to have only a minor impact on the competitiveness of OTEC with conventional modes of electricity generation.     

Steps toward the hydrogen economy

The hydrogen economy is defined as the industrial system in which one of the universal energy carriers is hydrogen (the other is electricity) and hydrogen is oxidized to water that may be reused by applying an external energy source for dissociation of water into its component elements hydrogen and oxygen. There are three different primary energy-supply system classes which may be used to implement the hydrogen economy, namely, fossil fuels (coal, petroleum, natural gas, and as yet largely unused supplies such as shale oil, oil from tar sands, natural gas from geo-pressured locations, etc.), nuclear reactors including fission reactors and breeders or fusion nuclear reactors over the very long term, and renewable energy sources (including hydroelectric power systems, wind-energy systems, ocean thermal energy conversion systems, geothermal resources, and a host of direct solar energy-conversion systems including biomass production, photovoltaic energy conversion, solar thermal systems, etc.). Examination of present costs of hydrogen production by any of these means shows that the hydrogen economy favored by people searching for a non-polluting gaseous or liquid energy carrier will not be developed without new discoveries or innovations. Hydrogen may become an important market entry in a world with most of the electricity generated in nuclear fission or breeder reactors when high-temperature waste heat is used to dissociate water in chemical cycles or new inventions and innovations lead to low-cost hydrogen production by applying as yet uneconomical renewable solar techniques that are suitable for large-scale production such as direct water photolysis with suitably tailored band gaps on semiconductors or low-cost electricity supplies generated on ocean-based platforms using temperature differences in the tropical seas.     

Nuclear reactors' construction costs: The role of lead-time,standardization and technological progress

This paper provides an econometric analysis of nuclear reactor construction costs in France and the United States based on overnight costs data. We build a simultaneous system of equations for overnight costs and construction time (lead-time) to control for endogeneity, using change in expected electricity demand as instrument. We argue that the construction of nuclear reactors can benefit from standardization gains through two channels. First, short term coordination benefits can arise when the diversity of nuclear reactors' designs under construction is low. Second, long term benefits can occur due to learning spillovers from past constructions of similar reactors. We find that construction costs benefit directly from learning spillovers but that these spillovers are only significant for nuclear models built by the same Architect–Engineer. In addition, we show that the standardization of nuclear reactors under construction has an indirect and positive effect on construction costs through a reduction in lead-time, the latter being one of the main drivers of construction costs. Conversely, we also explore the possibility of learning by searching and find that, contrary to other energy technologies, innovation leads to construction costs increases.     

Comparative assessment of future power generation technologies based on carbon price development

The long-term assessment of new electricity generation was performed for various long-run policy scenarios taking into account two main criteria: private costs and external GHG emission costs. Such policy oriented power generation technologies assessment based on carbon price and private costs of technologies can provide information on the most attractive future electricity generation technologies taking into account climate change mitigation targets and GHG emission reduction commitments for world regions.Analysis of life cycle GHG emissions and private costs of the main future electricity generation technologies performed in this paper indicated that biomass technologies except large scale straw combustion technologies followed by nuclear have the lowest life cycle GHG emission. Biomass IGCC with CO₂ capture has even negative life cycle GHG emissions. The cheapest future electricity generation technologies in terms of private costs in long-term perspective are: nuclear and hard coal technologies followed by large scale biomass combustion and biomass CHPs. The most expensive technologies in terms of private costs are: oil and natural gas technologies. As the electricity generation technologies having the lowest life cycle GHG emissions are not the cheapest one in terms of private costs the ranking of technologies in terms of competitiveness highly depend on the carbon price implied by various policy scenarios integrating specific GHG emission reduction commitments taken by countries and climate change mitigation targets.