Both the UK and the Republic of Ireland have pinned their hopes on wind power to reduce carbon emissions and hit climate change targets, in particular offshore. This is ostensibly a wise move. Both nations have thousands of miles of coastline and planning red tape is less of an issue when the required space is miles out to sea and, in the UK, belongs to the Crown.
It is estimated the amount of wind power required to hit the European Union’s Renewables Directive runs to 35-45 GW in Great Britain and 6-8 GW in the island of Ireland the combined Republic of Ireland and Northern Ireland’s Single Electricity Market (SEM) by 2030. Such a large amount of intermittent wind energy is bound to have a marked effect on the countries’ respective electricity markets.
Just how much impact was the job of Finnish energy analysts Pöyry Energy Consulting, which has released a £1 million ($1.7 million) report, entitled ‘Impact of Intermittency’. The report was commissioned by UK and Irish transmission system operators National Grid and EirGrid, utilities Centrica, DONG Energy, renewable energy project developers RES, as well as consultants ESB International.
Encompassing more than 20 000 hours of work, the year-long project used an unprecedented quantity of data. Hourly statistics for each of the years from 2000 to 2007 were taken from observations in 36 locations, totalling more than 2.5 million pieces of data. The findings, which have been presented to relevant government organisations including the UK’s the Department of Environment and Climate Change (DECC), are fascinating.
Put simply, a huge expansion of wind power in the UK and Ireland would utterly transform the nature of their respective electricity markets. Prices would no longer be determined by demand, but by how hard the wind is blowing or, indeed, not blowing. The market would become exceptionally volatile, with electricity prices veering wildly from sometimes negative levels to almost unimaginable and certainly politically untenable highs.
Pöyry’s core scenario of the build-out of wind capacity was developed with the guidance of a Steering Committee, which factored in likely licensing rounds and advantageous wind resources. The report also factored in additional intermittent generation from potential tidal barrage schemes in the Severn Estuary in western Britain. For wind power, Pöyry’s core scenario assumes a total wind capacity of 33 GW in Great Britain and 6 GW in the SEM in 2020. By 2030 these figures rise to 43 GW and 8 GW respectively.
After checking that their wind modelling produced close results with historical outputs, Pöyry was able to construct forecasts of the wind generation in future years based on the historical weather patterns. In understanding the statistical nature of the wind output, Pöyry was able to examine how often periods of ‘low wind’, i.e. when output from wind power is less than five per cent of its capacity, occurred.
The report found that between 2000-2007 there were 209 hours in the British market and 542 hours in the Irish market when wind generation was below five per cent of its maximum capacity for a single hour only, and just one period of almost three days at this low level. Pöyry found a large variation of wind output from year to year based on its eight sample years: annual output varies by almost 25 per cent in the Irish market and around 13 per cent in the British market.
Wind output and electricity demand
The next stage of the analysis was to subtract the wind output from the electricity demand to examine the demand pattern that the remaining power stations will have to meet. Previous analyses, says Pöyry, have concentrated on determining a ‘capacity factor’ for the wind, i.e. the likely equivalent proportion of thermal capacity.
However, a high wind market of the future cannot be considered in terms of averages. Instead, the analysis concentrated in understanding the probabilities of extremes occurring. Their models were able to generate patterns of ‘demand net wind’.
The charts illustrate the proportion of a year that system demand is above a given level: the upper line shows the character of the gross system, and the lower line is the remainder when the intermittent generation is subtracted. It is the lower line that the other power stations on the system will have to supply.
In order to examine to examine the impact of a massive expansion of wind power capacity in the Irish and British markets, Pöyry centred their analysis on a Core Scenario. This is not a forecast; it is deliberately designed to examine the impact of large amounts of wind generation in the market, while meeting current system security standards and tracking towards accepted decarbonisation levels.
To accentuate the impact, the Core Scenario deliberately considered modest demand growth and large amounts of nuclear build. This scenario does not represent the ‘base case’, or most likely outcome for the future, rather it provides a stress-test for exploring a future with intermittent generation.
Mixing with conventional power
Pöyry says that it was particularly interested in the way that thermal plant would have to operate to supply the ‘demand net wind’ in a way which maintains the system reliably at current levels. Based on the understanding of the dynamics of the power stations, in both markets the thermal plant and interconnectors appear to be able to deal with the dynamic requirements although there are some years where this is tight.
As expected the running regime for the thermal plant is altered drastically, as it is ‘squeezed’ into its own intermittent patterns. Figure 1 indicates the load factors projected in the Core Scenario by plant type.
Figure 1: Plant load factors in the British and Irish power sectors through to 2030
However, the load factors only paint part of the picture, as in practice the operational regimes of the plant at even quite high load factors are highly irregular. Pöyry says that it is quite possible that, particularly for the combined-cycle gas turbine fleet, plant availability will be reduced or need higher maintenance costs when faced with running regimes like this.
Lower availability would require additional capacity to maintain reliability standards. In this context, Poyry found that the Irish market relies heavily on the interconnectors to the British market, with these taking significant load flow variations in response to the wind.
Managing the grid
A significant part of ‘Impact of Intermittency’ was aimed at understanding the way in which the very nature of the wind output required system operators to manage the generating plant differently compared to present in order to maintain current reliability standards.
Pöyry looked closely at the needs and costs of holding additional plant on the system in readiness to generate within different periods of notice, combined with the wind squeezing out the thermal generators which provide these services. The report uses the terms ‘response’ and ‘reserve’ for generating plant that is able to come on-line within respectively a few seconds and a four-hour window.
The modelling found that response requirements did not appear to grow significantly in the British market – although the commissioning of the 1600 MW nuclear EPRs in our models had the expected effect of increasing response requirements in the British market because much of the response requirement is governed by fault levels and this type of plant will raise this threshold. In the Irish market there is already a challenge in managing response and Pöyry expects a need for appropriate incentives for dispatching off wind.
However, reserve requirements will be changed somewhat, and although these seem manageable, both markets will require a significant increase in the reserve capacity.
Pöyry underlines what it calls the almost critical importance to the Irish market of having interconnection to the British market, although the opposite is not true. However, while interconnection will assist the physical management of the system, it has the consequence that British market price spikes also become a feature of the Irish market.
Impact on market prices
Understanding how electricity prices will change hour by hour is particularly important in anticipating how wind can change markets. Using sophisticated computer models of all generating plant in the British and Irish markets, Pöyry found that with a high wind capacity prices are depressed somewhat, but they are also far more ‘spikey’.
This means that there will be increased periods of extremely high or very low, sometimes negative, prices. This is because the system will alternate between having too much wind generation, and being far tighter when there is little wind.
Figure 2 shows a price duration curve for the British market: effectively all prices in one year stacked from highest to lowest. Each coloured line represents one ‘Monte Carlo’ simulation. In 2020, with wide system margins, there are a few periods with zero prices, and there are very high prices for some periods.
By 2030, with even more wind on the system, the distribution of prices becomes even more extreme. There will even be periods of negative prices arising from the wind plant valuing its output at the opportunity cost of minus-1 Renewable Obligation Certificate (a government subsidy that pays renewable generators a fixed price per MWh), as well as very short periods with prices at almost £8000/MWh ($13 190).
For investors, there would be little incentive to support conventional power generating facilities able to ramp up at short notice to balance demand and wind intermittency. James Cox, the principal author of the report, says these spikes in price are necessary, in order for the market to operate. “Without them,” he said, “generators that only run a few hours each year cannot make sufficient returns.
“The commercial risk of operating in such a market is far greater than currently. It will be highly uncertain how prices might rise, and depending on the interaction between wind and demand, in any given year these spikes simply may not occur.”
A somewhat similar picture emerges in Ireland, although prices will not be as volatile as in Britain. This is due to the market design in the Irish market with the Capacity Payment Mechanism. However, the British market will maintain a strong influence and growing influence on Irish prices.
Outlook for investors
Together the increasingly uncertain and ‘spikey’ market prices, coupled with a reduction in overall average market prices, are not encouraging to investors in new thermal plant. New plant will have to operate at low and highly uncertain loads, and under current market arrangements, the likely returns do not look good.
If significant penetration of renewables is indeed achieved along the lines of the Core Scenario, power stations that are built now will face a future of not only far lower load factors, but also dramatically increased uncertainty of revenues than at present. Cox said: “Any generation built before 2016 to cover closure, under emission regulations, of existing coal-fired power stations, would face a volatile future, uncertain to the point that plant may only operate for a few hours one year and then hundreds of hours the next year.”
The problem is more acute in the British market. While the Irish market is able to continually incentivize new peaking plant via its capacity payment system where suppliers receive a fixed payment annually, Britain’s ‘energy-only’ market offers a real challenge in delivering very low load factor plant.
Cox said: “In our opinion, the price spikes needed to reward the risk for such plant will stretch the market design to its utmost. The risk of intervention in a market with very high prices for short periods is significant, and has been seen repeatedly in other markets. Equally a market with spikey and volatile prices is unlikely to send clear economic signals to new investors.”
In order to accommodate a huge expansion of intermittent renewables, it seems Britain’s ‘energy only’ market model may have to go in favour of a system that incorporates payments for availability. With fixed capacity payments, generators would be less at the whim of the wind and better able to manage the prospect of having energy generating facilities on the grid that are only ramped up very rarely.