Select Committee on Innovation, Universities, Science and Skills Written Evidence

Memorandum 2

Submission from David Milborrow, Independent Consultant


  1.  The author has been studying renewable energy issues for 30 years and has been an independent consultant for the past 15 years, working on technical and economic issues for clients in both public and private sector, at home and abroad. Particular specialities are wind energy and the integration of variable sources, such as wind, into electricity networks. I have no permanent affiliations, but act as technical adviser to the British Wind Energy Association and to the Journal Windpower Monthly. The submission is, however, my own.

  2.  This submission is mainly concerned with addressing the Committee's request for information on "feasibility, costs, timescales and progress in commercialising renewable technologies as well as their reliability and associated carbon footprints". As there is a very wide range of views on wind costs (onshore and offshore) at present, it examines these and compares UK costs with those recorded in Europe and America. It also comments on reliability and availability statistics and looks at projections for future costs. A summary of work on "carbon footprints"—for wind, PV, hydro and nuclear—is also included.


  3.  World wind energy capacity has doubled every three years since 1990 and there is now (mid-2007) about 80 GW installed, worldwide. Until around 2001, each doubling was accompanied by a 10-15% reduction in the price of wind turbines. The price of wind-generated electricity fell more rapidly, as there were also improvements in energy productivity. The continuous decline in prices halted around 2001, partly due to substantial increases in commodity prices, partly to a shortage of wind turbines.

  4.  To estimate wind-generated electricity prices, it is necessary to examine the prices of wind turbines and of wind farms, the energy productivity, operation and maintenance costs and financing assumptions. Energy production depends on the site wind speed and has a crucial effect on energy prices. Each of these factors is examined in turn.


  5.  The most reliable current figures for wind turbines come from two of the major European wind turbine manufacturers, who quote almost identical average sales prices of £614/kW for 2006. This is close to the figure (£594/kW) quoted in a recent American analysis (Wiser and Bolinger, 2007).

  6.  The total installed cost of a wind farm includes "Balance of plant" costs, such as the cost of foundations, transport and internal electrical connections. These add between 15 and 30% to the cost of the wind turbines, and there are wide variations that depend on the difficulties of construction and the size of the project. In addition, the cost of the grid connection can often add a substantial sum to the project cost. A Carbon Trust (2006) report suggests these additional costs add up to about £260/kW. Adding 10% to this figure (to account for recent price increases) and then adding it to the 2006 wind turbine price quoted in the previous paragraph suggests wind farm costs may be around £900/kW. This is consistent with one of the supporting documents to the 2007 Energy White Paper. (Redpoint, 2007)

  7.  The author maintains a database of wind turbine projects, worldwide, thatforms the basis of an analysis of electricity generation costs, published each year in the Journal "Windpower Monthly". In 2004 the average onshore project cost was £667/kW, in 2005 it was £816/kW, and in 2006 it was very similar. The average price for 1650 MW of plant completed so far in 2007 is £880/kW, close to the figure suggested in the previous paragraph, although the average price of 700 MW of UK projects is a fraction under £1,000/kW (Power UK, 2007). As with wind turbine prices, there is some uncertainty, as completed contract prices often include the cost of the first three to five years of operation and maintenance.

  8.  American wind farm costs appear to be lower than European costs. The average installed cost in 2006 was around £760/kW, although the American report notes that proposed projects now average around £850/kW.


  10.  Operational costs have also fallen steadily over the years, partly due to increases of turbine size, partly due to experience. A detailed breakdown of UK costs comes from the Scottish Energy Environment Foundation (SEEF) (2005). The data are summarised in table 1 and add up to £50/kW/yr. Transmission charges, however, vary across the country and are often not included in generation costs for other technologies, although they are, of course, a real charge to the operator. If they are taken out of the SEEF total and the land rent is converted to a £/kW figure, the total is around £30/kW/yr. That agrees reasonably well with data from Ofgem (2005)—£28/kW/yr. It should be noted that projects in the South of England incur significantly lower transmission charges.

Table 1


All figures are in £/kW/yr, except where noted.

Cost, £/kW/yr

Routine maintenance
Unscheduled maintenance
Electricity charges
Management fees
Transmission charges
Non turbine expenses
Land rent, % revenue

  11.  The American analysis cited earlier suggests operation and maintenance costs are in a range up to about £10/MWh. That also corresponds to about £28/kW/yr, but the average American figure is lower.

Electricity generation potential

  12.  The usual measure of electricity generation is the "capacity factor". This is simply the ratio of the average power during a year and the rated, or nameplate, capacity of the wind farm. Capacity factors of UK wind farms vary between 0.15 and 0.50. The average is about 0.30, and most wind farms have capacity factors between 0.24 and 0.36 (Milborrow, 2005), although these will vary from year to year, as the energy content of the wind varies.


  13.  Two further parameters need to be established before generation costs can be derived: the project test discount rate and the capital recovery period. Although the analysis in the 2007 Energy White Paper uses a discount rate of 10%, that, in the context of renewable energy, reflects policy risks associated with the Renewables Obligation. As onshore wind is now an established technology the "technology risk" is low and the Carbon Trust (2006) suggested 7.75% as an appropriate discount rate. The UK Energy Research Centre (2007) recently discussed the important distinction between policy risks and technology risks. 20 years is an appropriate project lifetime for "generic" generation cost calculations, but costs have also been calculated for a 15-year life, as this length of contract is quite common in the UK and elsewhere.

  14.  Broadly speaking, wind farms with the highest capital costs are likely to be in remote areas—but with high wind speeds. This is logical. If the lowest-cost plant is linked with low output, and vice versa, the range of generation costs for UK conditions ranges from £45.5/MWh to £58.3/MWh, as shown in table 2. Generation

Table 2


Installed cost, £/kW
Capacity factor
Generation cost,
£/MWh, 20-year life
Generation cost,
£/MWh, 15-year life


  15.  Transmission costs can add up to around £6/MWh to these figures, but vary across the country, and also depend on whether plant is connected to the transmission or distribution network.

  16.  The central estimate of £56/MWh for a 15-year contract is consistent with a "value analysis" quoted by the Carbon Trust (2006). They suggest that suppliers pass 70% of the value of Renewables Obligation Certificates (currently about £45/MWh), plus 80% of electricity prices (currently about £30/MWh) to developers.

  17.  The prices derived in table 2 can be compared with the prices paid for wind energy around the world. Wiser and Bolinger (2007) suggest that, in the absence of the American "Production Tax Credit", wind power prices for 2006 projects would range from approximately £25/MWh to £43/MWh. Other tariffs pay high prices for a few years, and then the price drops (Milborrow, 2007); making allowances for this, average tariffs vary between about £40/MWh (Ireland) to £56/MWh (Spain), although it must be emphasised that tariffs are adjusted frequently.

  18.  Other costs: when an electricity network is operated with wind, extra balancing costs are incurred, to deal with the additional uncertainty in forecasting the supply/demand balance. Numerous studies have shown that these additional costs are small—around £2/MWh of wind, when it contributes 10% of the electricity supply. As the wind energy proportion increases, additional costs are incurred for additional backup and for extra transmission costs. To deal with these issues, an estimate of the "total extra costs" for the GB network in 2020 with 20% wind, was derived, compared with an all-gas system (Dale et al, 2004). The estimate of additional costs—£3/MWh across all consumers—applied to a particular set of assumptions about gas price and the installed costs of onshore and offshore wind in 2020. Since that time the estimate of gas prices has virtually doubled and wind plant costs have also increased. These changes tend to cancel each other out. If the analysis is re-worked with a gas price of 40p/therm, a carbon price of £15/tCO2 and an onshore wind installed cost of £750/kW; the final answer is very similar.


  19.  Although there is some over uncertainty over offshore costs, responses to a recent consultation (DTI, 2006) suggested that the current range of installed costs is around £1,300-1,500/kW. The upper end of this range is used to derive current generation costs in Table 3, below, which also includes estimates for 2020, discussed in paragraph 25.

Table 3


Value, 2007
Value, 2020

Installed cost
DTI (2006)
ODE (2007)—75% of £1,600
DTI (2006)
Danish Energy Authority
Capacity factor
DTI (2006)
Discount rate
DTI (2006)
Assumes no technology risk
Generation cost

  20.  European tariffs: Germany and Greece both pay around £60/MWh for offshore wind and France pays around £88/MWh—but only for the first 10 years. After that, the payment depends on the capacity factor of the installation.


  21.  Onshore: Analysis of data from German wind farms and wind turbines shows that the availability of many types of machine is in the range 96-99%. Data from Germany and from Denmark reveals that numerous machines that are at least 15 years old are still achieving satisfactory levels of electricity production.

  22.  Offshore: Despite early problems, reports submitted to DTI showed that North Hoyle wind farm achieved a capacity factor of 36% (budget 37%) between July 2004 and June 2005. Scroby Sands achieved a capacity factor of 29% in 2005, a year when its availability was 84% against a target of 95%. If the latter figure had been achieved, it may be inferred that the capacity factor might have been around 33%. The wind farm at Nysted in Denmark, completed in 2003, has realised a capacity factor close to 40% over the last two years, which suggests that target electricity production estimates can be realised.


  23.  As noted earlier, the steady downward trend in wind energy costs halted around 2001-02. There were two contributory factors: increases in steel, copper and other commodity prices and a worldwide shortage of wind turbines. Although wind turbine prices may be starting to level out, steel prices are still rising. There is a reasonable consensus, however, that improved production techniques, the use of larger machines and other factors will continue to exert a downward pressure on prices. The extent of this downward pressure depends on perceptions of market growth and the "learning curve" effect (usually expressed as the price reduction per doubling of capacity)

  24.  There are numerous projections of market growth. A review by Molly (2006) suggested the "mid range" growth was two doublings of capacity by 2014. Historically, installed costs have fallen by 10-15% per doubling of capacity (Uyterlinde et al, 2007), which suggests they may fall by 20%, at least, by 2014. If an onshore installed cost of £800/kW is realised in the UK by 2014 (roughly equal to the 2006 American average) that would suggest generation costs might be about £42/MWh, even if operation and maintenance costs barely changed.

  25.  There is a wide range of cost estimates for offshore wind in 2020 in the literature. Installed cost estimates range from around £1000/kW (Uyterlinde et al, 2007) to £1,500/kW (Ernst and Young, 2007). However, there is more potential for cost reduction, particularly with the moves toward much larger wind farms. A recent analysis of costs by ODE (2007) suggested that installed costs offshore in 2020 may be about 75-80% of the 2006 level, which is put at £1,600/kW. That may be a cautious estimate, as the study did not look at very large wind farms, and is used in Table 3. If the offshore market is thriving by 2020, with 2000 MW per year being installed in Germany alone (Molly, 2006), it is likely that the "technology risk" premium will disappear, so generation costs could fall to around £52/MWh, as shown in Table 3. If offshore wind does not "take off" prices will be higher.


  26.  The working definition of Carbon footprints, or life-cycle emissions, used here is: "Emissions of carbon dioxide and other pollutants resulting from the construction, operation and decommissioning of wind plant (or solar, or hydro), per unit of electricity generated by the facility during its lifetime".

  27.  Construction phase energy requirements for wind turbines lie between 611 and 1,800 kWh/kW (references are in Table 4, below), whilst a much more limited dataset for lifetime energy requirements suggest these lie between 2,400 kWh/kW (for sub-megawatt machines) and 1,437 kWh/kW for a 3 MW machine (Vestas, 2005)

  28.  The emissions corresponding to lifetime energy usage depend on the type of energy used in the manufacturing, installation, operation and decommissioning phases. A wind turbine manufacturer in France, where the majority of the electricity production is from nuclear sources, can reasonably claim that the emissions associated with the electricity used are quite low, whereas a manufacturer in America—where much of the electricity comes from fossil fuels—may use higher estimates.

  29.  There is a measure of agreement between most of the estimates listed in table 4. Almost all suggest that wind plant emit between 7 and 20 gCO2 unit of electricity generated. Data from the Vestas (2005) study has not been included, because Vestas source a high proportion of their electricity from renewable sources and so bring their figure down to 4.6 gCO2/kWh. This figure is perfectly valid, but probably not comparable with most of the other data. If Vestas wind turbines were manufactured using electricity from a typical mix of European sources (coal, gas and nuclear) the emissions would be about 15 gCO2/kWh. Offshore emissions are similar to onshore wind emissions—more carbon dioxide is generated during manufacture and installation, but this is offset by higher energy productivity.

  30.  Table 4 shows that wind, hydro and nuclear have low carbon footprints, while PV figures are higher. Gas and coal generate significantly more emissions due, of course, to the combustion of fossil fuels. Gas typically generates about 350-400gCO2 /kWh and coal around 850-1,000g CO2 /kWh

Table 2



Wiese, A, Kaltschmitt, M, 1996. Comparison of wind energy technology with other electricity generation systems: a life cycle analysis. EU Wind Energy Conference, Goteborg
White, S and Kulcinski, G, 1998. Net energy payback and CO2 emissions from wind-generated electricity in the Mid-West. University of Wisconsin
International Energy Agency, 1998. Benign Energy? The environmental implications of renewables. OECD, Paris
The environmental implications of renewables in the UK, AEAT-2945, 1998
Serchuck, A, 2000. The environmental imperative for renewable energy. Renewable Energy Policy Project
International Energy Agency, 2003. Integrating energy and Environmental goals: Investment needs and Technology options
Danish Energy Agency, 2004. Technology data for electricity and heat generating plants


  Carbon Trust, 2006. Policy frameworks for renewables.

  Dale, L, Milborrow, D Slark, R and Strbac, G, 2004. Total cost estimates for large-scale wind scenarios in UK. Energy Policy, 32, 1949-56.

  DTI, 2006. Regulation of offshore electricity transmission. Government response to the joint consultation by DTI/Ofgem.

  Ernst and Young, 2007. Impact of banding the Renewables Obligation—costs of electricity production.

  Milborrow, D, 2005. UK capacity factor analysis corrects controversial figures. Windstats, 18, 4, 1-3.

  Miborrow, D., 2007. "Back to being a model of stability". Windpower Monthly, January.

  Molly, J, 2006. Wind energy market prognosis, 2010, 2014 and 2030. Dewi Magazine, 29 (August).

  ODE (Offshore Design Engineering Ltd), 2007. Study of the Costs of Offshore Wind Generation. Report to the Renewables Advisory Board and DTI.

  Ofgem, 2005. Assessment of the benefits from large-scale deployment of certain renewable technologies. Report by Cambridge Economic Policy Associates Ltd and Climate Change Capital.

  Oxera, 2004. Results of renewables market modelling. Report for the DTI.

  Power UK, 2007 (May). Power station tracker.

  Redpoint Energy, 2007. Dynamics of GB Electricity Generation Investment.

  Scottish Energy Environment Foundation, 2005. Impact of Transmission Charging on Renewable Electricity Generation. Report to the DTI.

  UK Energy Research Centre, 2007. Investment in Electricity Generation: the role of costs, incentives and risks. Imperial College Centre for Energy Policy and Technology.

  Uyterlinde, M A, Junginger, M, J. de Vries, H, Faaij, A and Turkenburg, W C, 2007. Implications of technological learning on the prospects for renewable energy technologies in Europe. Energy Policy, 35, 8, 4072-4087.

  Vestas, 2005. Life cycle assessment of offshore and onshore sited wind power plants based on Vestas V90-3.0 MW turbines.

  Wiser, R and Bolinger, M, 2007. Report on US wind power installation, cost, and performance trends: 2006. Lawrence Berkeley National Laboratory.

June 2007

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