This was due to a combination of factors. A modest reduction in the installation costs of onshore wind farms helped, but the more significant factor is the rising cost of gas and strong indications that the cost of nuclear generation is higher than many previous estimates had suggested.
It is difficult to make definitive statements about the cost of offshore wind, as only a few projects have been built recently. But indications are that installation costs are falling slightly. Significantly, last year for the first time, offshore wind became competitive with nuclear on costs in certain cases.
The following quoted data on cost comes from actual projects, based on material published in Windpower Monthly and elsewhere, and supported by analysis from a number of authoritative sources.
Several factors come into play when calculating the cost of wind energy. The cost of buying the turbines is the first significant consideration. Last year, the average price of an onshore wind turbine came in at around 5% lower than 2011 with most now costing between EUR820-1,000/kW. Those from China are cheaper by 25-30%, according to UK newspaper The Financial Times. An increasing tendency to include the first five to seven years' maintenance costs in the selling price may actually be masking a greater downward trend in prices.
For the offshore market, wind turbine prices came in around 10-15% more expensive than onshore turbines.
The installed cost of most onshore wind farms, which includes the cost of construction, has widened from €1,500-1,600/kW in 2011 to €1,300-2,000/kW in 2012.
At the bottom of the range, the lower cost can be attributed to lower turbine costs; at the top of the range this reflects higher construction costs in difficult terrains, or where there is little prior experience of developing wind.
The offshore market is somewhat opaque. An assessment by Deutsche Bank Climate Change Advisers suggests that the lowest installed cost is around €2,400/kW, slightly lower than in 2011. The maximum installed cost remains level at €3,500/kW. This is likely to rise later in the decade as wind farms are built further offshore and will be more expensive, analysts say.
The cost of offshore wind generation, however could fall significantly, according to a report from the UK's Crown Estate - the owner of the sea bed off the UK coastline - which suggests a drop from the current level of around €172/MWh to around €123/MWh. This is due to a combination of installed cost reductions - partly because of a more efficient supply chain – and higher wind speeds further offshore.
Shale gas price increases
Until last summer, it appeared that the exploitation of shale gas in the US would lead to persistently lower gas prices for the country. However, the latest projections from the Energy Information Administration (EIA) in the US Department of Energy suggest that prices may now be on an upward trend, as demand catches up with supply and the rate of opening new wells for exploitation of shale gas slows down.
The EIA expects that by 2020 gas prices to be close to $6 per thousand cubic feet (about €15/MWh), which is a rise of about 15% on the current level. At present, however, US gas prices are still significantly lower than those in Europe and elsewhere, and this is reflected in a wide range of costs for gas-fired generation. At one stage last year, European prices were about three times those in the US. This year, US prices are expected to average around €9-12/MWh and UK prices around €27/MWh.
The price of coal has been relatively stable during the past 12 months, but is likely to move upwards, albeit fairly slowly. US coal for electricity generators average around €6/MWh, world coal around €10/MWh and UK coal around €12/MWh. The range in construction costs of gas and coal-fired power stations is fairly narrow, with the installed cost of gas-fired power stations coming in around EUR870/kW, and coal-fired power stations €2,040/kW.
Nuclear financial uncertainty
In the past year there has been significant debate about the cost of nuclear power, with several high-profile nuclear industry experts pouring doubt on the financial viability of nuclear.
Jeff Immelt, chief executive of energy company GE, told The Financial Times in July that nuclear power was now so expensive that it had become "really hard to justify". And in March energy companies E.on and RWE pulled out of a plan to build a nuclear plant in Wales, UK. E.on CEO Johannes Teyssen said that nuclear was no longer attractive to his company and that it would shift its future strategy towards alternative energy.
However, establishing a reliable range for nuclear generation costs remains difficult, as robust figures for its construction costs are elusive. One difficulty is that both the European reactors that are under construction - Olkiluoto in Finland and Flamanville in France - are several years late and over budget. The table below summarises generation costs from each of these plants.
EDF Energy, the lead utility for UK plant Hinkley Point C, has suggested that its generation cost is likely to be more than the target offshore wind cost of €120/MWh, but lower than that of offshore wind in the UK, which is around €170/MWh. However, the unknown quantity, in the case if nuclear, is the interest rate, which will affect the generation cost.
If the UK electricity market reform succeeds in providing a more stable climate for investors, EDF may use a 10% test discount rate of interest (see "Nuclear and wind's interest", below), resulting in nuclear generation costs of €121-149/MWh.
Although the nuclear industry might well argue that the Finnish and French figures are higher because these plants are the first of their kind, the fact that the latest proposals in the UK and the US are carrying a similar range of costs suggests that the nuclear industry has accepted the high capital costs applied to the power stations currently under construction.
Installed costs, however, are only one part of the picture and are not a reliable guide to competitiveness. The productivity of the electricity-generating source, expressed by the capacity factor, is vitally important. Total generation costs depend on installed costs, productivity and operation and maintenance costs.
Capacity factors for the principal thermal sources, wind and photovoltaics (see chart, below) cover the majority of installations, worldwide.
These do not take into consideration outliers, such as exceptionally windy regions, for example, or Arctic regions for photovoltaics. The estimates shown are based on an 8% interest rate and a 20-year capital repayment period. Nuclear costs have been derived using a 10% interest rate to reflect the higher perceived risk (mainly technical) and an additional risk premium of 5%.
Generating cost comparisons
Looking at total generation costs, incorporating installation as well as capacity factor, the cheapest onshore wind at €1,300/kW over a range of wind speeds is now competitive with coal and nuclear, and most gas except in regions where prices are currently lower, such as in the US. In Europe, gas and coal-fired generation is expected to increase to replace old coal and nuclear power stations. Gas-fired generation is being championed by the UK Chancellor of the Exchequer, whereas further construction of coal-fired plant is likely to take place in Germany.
At its highest price of €2,000/kW, onshore wind remains uncompetitive unless it delivers in wind speeds above about 8.5 metres per second (m/s). Offshore, the cheapest generating cost of €2,400/kW is only competitive with the most expensive coal and gas generating costs, and only at sites with high wind speeds - above about 8.5 m/s.
One major achievement in the past year, however, is that offshore wind is now competitive with nuclear - in certain circumstances.
At the top end of the scale for both, they are comparable - the most expensive offshore wind is €3500/kW as is the most expensive nuclear. In sunny climes, offshore wind struggles to achieve cost parity with solar photovoltaics (PV), but does better in mid-latitudes, where solar PV generation costs rise. PV has a wide range of capacity factors, ranging from more 20% in southern California, through 9% in the UK and down to lower values in more northern climes.
Capacity factors of fossil-fired plants are generally high - in the range 90-95% - except in the case of coal, where they fall slightly lower due to the greater complexity of the fuel handling and ash disposal.
Capacity factors for onshore wind range widely from around 16% - at sites with low wind speeds of around 6 m/s - to over 40% on sites with high wind speeds of around 9 m/s. Offshore, the range of capacity factors is much less varied simply because of the better wind resource - one of the main attractions of offshore wind. The range used here is 30-42%.
Wind-turbine capacity factors appear to be rising. This is often attributed to turbines becoming more efficient, but in reality it is more likely to be achieved through changes in turbine configurations. At any given power rating, rotor diameters are getting bigger. This means that more energy can be delivered and, whatever the power rating, the capacity factor goes up.
Last May, the International Energy Agency published an analysis of wind energy generation costs. Its best-case scenario was that generation costs would fall by about 25% by 2020, and at the very worst, costs would stay level. Meanwhile, fossil-fuel price projections tend to suggest that they will rise. Nuclear costs are uncertain, but seem unlikely to move downwards. But wind will have to watch out for solar PV, which is now starting to compete with it on costs and could consolidate this position, particularly in sunny climates.
Our annual analysis once again shows the range of costs for power generation from key sources, measured against two average cost ranges for onshore and offshore wind power generation. This year shows a significant fall to EUR90/MWh in the lower potential generation cost of offshore wind - with a 40% capacity factor and installed cost of EUR2,400/kW. This cost is possible in shallow, nearshore, windy sites. The other noticeable change is the increase in nuclear costs.
The right hand graph shows the same wind generation costs and how they fall as wind speeds increase, ranging from flat lowland onshore sites with 6 m/s, to far offshore wind speeds of 10 m/s.
THE SHALE EFFECT - US GAS PRICES DRIVEN DOWN BY LARGE-SCALE FRACKING
The exploitation of shale gas has accelerated over the past few years and is seen by some as one answer to energy security. Shale gas is trapped in rock fissures and can be released by fracturing the rocks using water at high pressure. It has gradually developed in the US and now accounts for around 20% of the country's total gas needs.
Gas prices fell in the US after 2010, probably due to the rise of shale gas use. Extraction costs in the US are now roughly similar to those at conventional gas wells and shale's contribution is expected to increase.
Shale gas reserves exist in Europe, but may be expensive to exploit. Test drillings in the UK are thought to have been a possible cause of earth tremors in 2011. Other environmental concerns include pollution of underground water supplies.
A UK parliamentary committee concluded that shale gas is unlikely to greatly improve security of supply because of the limited extent of the resource. Energy markets illustrate this forecast. Gas prices in the US seem set to rise modestly but steadily, although they are still below oil prices by a factor of about four.
No price drop in Europe
European gas price trajectories are on an upward trend with no signs of levelling off in anticipation of large-scale exploitation of shale gas in the region.
NUCLEAR AND WIND'S INTEREST - A MAJOR COST ELEMENT
Interest rates have an important influence on the generation cost of all technologies. Their impact is most dramatic on the cost of nuclear and, to a slightly lesser extent, wind, because they are capital intensive.
This makes capital cost repayments a dominant feature of the overall generation cost for these two sources. For nuclear, capital costs repayments account for around 80% of the total generation cost, and slightly less for wind. With a low capital outlay for gas plants, capital cost repayments represent only around 20% of generation costs.
The risk effect
Most commercial projects in the utility sector are financed using a mixture of debt and equity. Both equity and utility investors look for higher returns if the project has some risk attached, usually relating to cost or construction overruns rather than technical failure. Investors also consider the integrity of any financial support mechanism - if it is perceived that the support may be withdrawn, or fluctuate, then there would be a political risk too.
For example, the UK's electricity market reform was originally conceived to minimise political risk, but continuing uncertainty over the structure of new support systems means that so far this aim has not been realised. That is why some experts have suggested that a 15% test discount rate may be appropriate for UK nuclear investments (see main article). The terms "interest rate" and "test discount rate" tend to be used interchangeably, yet the former reflects interest payments that will actually have to be made, whereas the latter includes risk premium.
State-owned utilities use test discount rates prescribed by the state's bankers. Private developers will calculate appropriate interest rates that depend on interest payable on any loans and to equity investors. They will add on a risk premium.
A cash-rich utility that finances power projects from its own resources is free to set its own test discount rate. In doing so, it will need to take into account commercial banking interest rates, to ensure adequate returns for the shareholders. It will probably include a risk premium.
The diagram, below, shows how interest rate increases have a varying affect on the generation cost of nuclear, wind and gas power generation.