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The GWPF’s submission, written by Professor Gordon Hughes, to the House of Commons Energy and Climate Change Committee for it public evidence session on the Economics of Wind Power on Tuesday 10 July. The meeting will take place in Committee room 16, Palace of Westminster

1. The economics of wind (and solar) power depend upon two critical features which determine the contribution which they make to meeting overall demand for electricity. The first feature is that wind power has very high capital costs and low operating costs per MWh of electricity generated. As such, it competes with electricity generated by nuclear or coal-fired generating plants (with or without carbon capture). The second feature is that the availability of wind power is both intermittent and random, so only a small portion of total wind capacity can be treated as being reliably available to meet peaks in electricity demand.

2. Neither of these features has a large impact on the operation of an electricity system when the level of installed wind capacity is less than 10% of peak demand, but they begin to impose increasingly heavy costs on system operation as the share of wind power in total system capacity approaches or exceeds the minimum level of demand during the year (base load). This threshold is due to be passed in the UK shortly after 2015.

3. When wind power is available, its low operating cost and market arrangements mean that it displaces other forms of generation. Market prices are lower, so that other generators require higher prices during periods of low wind availability to cover their operating and capital costs. It is expensive and inefficient to run large nuclear or coal plants to match fluctuations in demand or wind availability, so that their operating and maintenance costs will be higher.

4. At the same time, the risks of investing in new generating capacity will be increased by the impact of wind power on market prices, so that the cost of capital will be higher. Even if wind power was no more expensive per MWh than power from other sources its impact on other generators would still increase the aggregate cost of meeting the UK’s electricity demand, probably by a substantial margin.

5. One way of minimising the impact of wind power on other generators would be to impose a constraint on the amount of wind capacity that can be despatched at any time, so that, for example, no more than 20 GW out of 36 GW of installed capacity can be fed into the grid. Of course, that would be resisted by wind operators as it would reduce the already low load factor for wind farms. The guaranteed price per MWh would have to increase to attract the investment required to meet the Government’s targets for renewable generation in 2020, so that customers would have to foot even larger bills for wind power.

6. There is no escape from the consequences of the impact of wind power on other parts of the electricity system. In other areas of environmental policy this would be treated as a negative externality because the costs fall on electricity consumers as well non-wind generators. It follows that there is a prima facie case for taxing the source of the externality. Just as for fossil fuels, there would be strong arguments against the provision of subsidies designed to stimulate investment and output in wind generation.

7. A number of electricity markets outside Europe have developed arrangements to deal with intermittent or unreliable sources of generation, particularly hydro power. The most transparent approach is to require that there are long term contracts for the supply of reliable energy which in aggregate cover the predicted level of demand looking five or more years ahead. Hence, wind farms would have to either contract for storage and/or backup generation or absorb the cost of intermittency in some other way. Variants of this mechanism operate successfully in the US and Latin America (notably Brazil). They are more transparent and less likely to impose large costs on electricity customers than the hodge-podge of proposals for guaranteed prices (feed-in tariffs) and a capacity mechanism drafted by DECC. In addition, a proper market for long term reliable energy need not interfere with existing market arrangements designed to optimize generation and despatch on a half-hourly or daily basis, whereas it is inevitable that DECC’s proposals will compromise the efficient operation of such markets in the medium term.

8. Enthusiasts for wind power often suggest that the costs of intermittency can be reduced by (a) complementary investments in storage (pumped storage, compressed air, hydrogen, etc), and/or (b) long distance transmission to smooth out wind availability, and/or (c) transferring electricity demand from peak to off-peak periods by time of day pricing and related policies. However, if the economics of such options were genuinely attractive, they would already be adopted on a much larger scale today because similar incentives apply in any system with large amounts of either nuclear or run-of-river hydro power.

9. With sufficient commitment to research and development, some of these technologies may become economic within 20 or 30 years. However, up to 2030 and beyond it will remain much cheaper to transport and store natural gas, relying upon open cycle gas turbines to match supply and demand. As a consequence, any large scale investment in wind power up to 2020 will have to be backed up by investment in gas-fired open cycle plants. These are quite cheap to build but they operate at relatively low levels of thermal efficiency, so they emit considerably more CO2 per MWh of electricity than combined cycle gas plants.

10. The amount of investment in backup generation that will be required depends upon the minimum level of availability from wind farms spread over the UK. This is the amount of “reliable energy” offered by wind power. Calculations based on the geographical distribution of wind speeds have suggested that this might be as high as 25-30% of total wind capacity. Reality turns out to be rather different. In 2011-12 the minimum output from wind plants was less than 1% of actual installed capacity. This may rise as the share of offshore wind increases, but it would be unwise for any planner to rely upon this. For practical purposes, wind power in the UK must be discounted when considering the system requirement for reliable sources of generation. This means that all retirements of nuclear, coal or gas-fired plants plus any growth in peak electricity demand must be matched exactly by investment in new non-wind plants, most of which will be gas-fired capacity.

11. Meeting the UK Government’s target for renewable generation in 2020 will require total wind capacity of 36 GW backed up by 21 GW of open cycle gas plants plus large complementary investments in transmission capacity. Allowing for the shorter life of wind turbines, the investment outlay for this Wind scenario will be about £124 billion. The same electricity demand could be met from 21.5 GW of combined cycle gas plants with a capital cost of £13 billion – this is the Gas scenario.

12. Wind farms have relatively high operating and maintenance costs but they require no fuel. Overall, the net saving in fuel, operating and maintenance costs for the Wind scenario relative to the Gas scenario is less than £200 million per year, a very poor return on an additional investment of over £110 billion.

13. Further, there is a significant risk that annual CO2 emissions could be greater under the Wind scenario than the Gas scenario. The actual outcome will depend on how far wind power displaces gas generation used for either (a) base load demand, or (b) the middle of the daily demand curve, or (c) demand during peak hours of the day. Because of its intermittency, wind power combined with gas backup will certainly increase CO2 emissions when it displaces gas for base load demand, but it will reduce CO2 emissions when it displaces gas for peak load demand. The results can go either way for the middle of the demand curve according to the operating assumptions that are made.

14. Under the most favourable assumptions for wind power, the Wind scenario will reduce emissions of CO2 relative to the Gas scenario by 21 million metric tons in 2020 – 2.6% of the 1990 baseline ¬at an average cost of about £415 per metric ton at 2009 prices. The average cost is far higher than the average price under the EU’s Emissions Trading Scheme or the floor carbon prices that have been proposed by the Department of Energy and Climate Change. If this is typical of the cost of reducing carbon emissions to meet the UK’s 2020 target, then the total cost of meeting the target would be £120 billion in 2020, or about 6.8% of projected GDP, far higher than the estimates that are usually given.

15. Wind power is an extraordinarily expensive and inefficient way of reducing CO2 emissions when compared with the option of investing in efficient and flexible gas combined cycle plants. Of course, this is not the way in which the case is usually presented. Instead, comparisons are made between wind power and old coal or gas-fired plants. Whatever happens, much of the coal capacity must be scrapped, while older gas plants will operate for fewer hours per year. It is not a matter of old vs new capacity. The correct comparison is between alternative ways of meeting the UK’s future demand for electricity for both base and peak load, allowing for the backup necessary to deal with the intermittency of wind power.

16. In summary, wind generation imposes heavy costs on other parts of the electricity system which are not borne by wind operators. This gives rise to hidden subsidies that must be passed on to electricity consumers. In the interest of both transparency and efficiency, wind operators should be required to bear the costs of transmission, storage and backup capacity needed to meet electricity demand. Only then will it be possible to get a true picture of the costs and benefits of relying on wind power rather than alternative ways of reducing CO2 emissions.