Policy News, BB200605
Wind Power: Cost and reliability not the barriers imagined, says influential UK report
A key policy report produced by the UK Energy Research Centre’s Technology and Policy Assessment unit (TPA) has destroyed the credibility of the assumption that integrating wind in a meaningful quantity into the system poses undesirable, or even unacceptable, costs and risks.
The TPA was set up to inform decision makers. It’s first report, carried out by leading energy policy scientists at Imperial College, London, in association with an expert group drawn from the Supergen Future Network Technologies Consortium, examined the evidence of the costs and impacts of intermittent generation on the UK electricity network. Of the more than 200 studies reviewed, none suggested that the introduction of significant levels of intermittent renewable generation should necessarily lead to reduced reliability of electricity supply.
The term ‘intermittent’, though known to be controversial, has been used by the authors as they felt it was in wider usage. They are well aware that the term variable is preferred by many, and that thermal plant demonstrates true intermittency, being either in operation or not.
The first myth they debunk is the notion that dedicated back-up is required for wind farms on a unit for unit basis, a myth rubbished in the EWEA publication ‘Large Scale Integration of Wind Energy in the European Power Supply: analysis, issues and recommendations,’ published at the end of last year. The aggregation of wind energy output decreasing the need for standing reserve is a major pillar of analysis in the book.
At the launch of the UK report, Malcolm Wicks, UK Energy Minister, said: “Suggestions that [wind] is excessively expensive or that traditional power stations are needed to back up the energy produced by all our wind farms are just two of the myths that have been peddled by their opponents. The study demonstrates that these claims have been exaggerated.”
The UK report focuses on wind energy and the costs and implications of intermittency over an approximately twenty year framework on the assumption that developments will be incremental. It does not look at the direct costs of extending the transmission system to accommodate new generation or any other costs.
Its prime focus is whether a 20% contribution of wind, or other RES, in the electricity mix, would compromise the reliability of the electricity system. The UK government is aiming for a 20% contribution of electricity from renewable sources by 2020. The EWEA report showed that wind energy can meet up to 20% of electricity demand on a large electricity network without posing any serious technical or practical problems.
The scientists in the UK report separate the analysis of the effect of intermittency to reliability into two categories: balancing short term fluctuations; and maintaining adequate system margin.
Keeping the system in balance
The report found that additional system balancing reserves needed for penetrations of up to 20% wind power amount to about 5 – 10% of installed wind capacity. From global studies, the cost range pushes up to £5/MWh (€7.2) of intermittent output but in many places it is substantially less. In the UK the range is £2-3/MWh (€2.8- €4.3).
EWEA, in its publication, produces estimates based on national studies of increase in secondary load for reserve: €1-3/MWh (of wind) for a wind power penetration of 10% and €2-4/MWh for higher penetration levels. No additional conventional plant is needed for reserve purposes of up to 20% penetration.
Secondary reserve is measured in the 10 to 15 minute range whereas primary reserve refers to the second/minute time scale and is activated automatically on frequency fluctuations. Primary reserve is needed to cope with outages in thermal generation, and when wind power is aggregated to demand, it has very little effect on primary reserve. EWEA points out that studies made so far show that only from penetration levels of 10% onwards of gross consumption will wind power have any significant impact on secondary reserves.
Fine tuning adjustments will clearly be more a feature of the balancing mechanism. The report does however point out, like EWEA, that the standard deviation of fluctuation in wind power from minutes to a few hours is relatively modest. “This is because there is considerable smoothing of outputs in the sub-hourly timeframe, and considerable prediction accuracy over a few hours.”
System margin is the buffer against peak demand not being met, and has traditionally been measured and provided for through the statistical concept of LOLP (Loss of Load Probability). It is noted in the report that conventional plant cannot be relied upon to ensure absolute system reliability as unexpected failures in power plant or electricity transmission networks can occur and “even with a system margin, there is no absolute guarantee in any electricity system that all demands can be met at all times.”
The variability in output of wind power increases the size of the system margin. But conversely, wind power can make a contribution to system reliability, provided there is some probability of output during peak periods, which there is. It is measured by the capacity credit. Again the complex relationship between the range and average output of intermittent plants, and the range and expected level of demand at peak times is a statistical process. The UK ERC delineates the key determinants of capacity credit as: (1) the degree of correlation between demand peaks and intermittent output; (2) the range of intermittent outputs, and (3) the average level of output. EWEA has strongly made the case described in number (2) that a decrease in the range of intermittent outputs will tend to increase capacity credit, because in statistical terms, the variance decreases. The more consistent wind regimes decrease variance, and this can be achieved through geographical dispersion of plants.
The researchers raise the point that when intermittent generation becomes a significant part of the system, the traditional definition of ‘system margin’ needs to be redefined as “the difference between installed capacity and expected peak demand is no longer a good indicator of how reliable supplies are likely to be.” This is because of capacity factors. They suggest:
(i) For a system comprised entirely of ‘çonventional’ plant the system margin as a percentage of peak demand is defined as: System margin = Capacity on the system – Peak demand.
(ii) When intermittent generation is added to the system, it is: System margin = ‘çonventional’ capacity on the system + Capacity credit of intermittent generation – Peak demand.
The point in general is quite forcefully made as well that conventional plant cannot be relied upon to ensure absolute system reliability as unexpected failures in power plant or electricity transmission networks can occur and “even with a system margin, there is no absolute guarantee in any electricity system that all demands can be met at all times.”
LOLP is found to be inadequate in measuring reliability of a system with much intermittent plant as it does not capture the full range and weight of impacts.
In its search for quantifying the ‘system reliability costs of intermittency’ the report proposes a defined methodology of studying the difference between the contribution to reliability made by intermittent generation plant and the contribution to reliability made by conventional generation plant. To arrive at the cost you subtract the fixed cost of thermal plant displaced by the capacity credit of wind plant from the fixed cost of thermal plant. The authors stress that the comparison must be done on the basis of plants operating at maximum utilization as comparisons made by policy makers use levelised costs (£/MWh) that assume that plants are operating at maximum utilization.
A critic of the report, a campaigner against wind farms, said that the study failed to give a true picture by omitting the overall system costs [such as expansion of the national grid] of integrating.. variable renewables such as wind.
EWEA’s report does include the all-rounded analysis and on the question of costs of wind requiring grid extension, draws on the European Commission’s RE-Xpansion project that gathered national studies. Results amounted to €0.1 - €5/MWh of wind capacity, equal to approximately 10% of wind energy generation costs on a 30% wind energy share.
A strong conclusion from EWEA’s analysis and review, that concurs with this UK report, is that system integration costs, under the most conservative assumptions (such as low gas price) are only a fraction of the actual consumer price of electricity and are in the order of €0-€4/MWh on a consumer level.
The UK ERC report concludes that the ‘aggregate costs of intermittency’ (on the assumption that is primarily wind) are made up of additional short-run balancing costs and the additional longer term costs associated with maintaining reliability via an adequate system margin.
In Britain, assuming a 20% penetration, they would be in the order of £5 to £8/MWh, made up of £2 to £3/MWh from short-rum balancing costs and £3 to £5/MWh from the cost of maintaining a higher system margin. For comparison, the direct costs of wind generation would typically be about 10 times higher, at approximately £30 to £55/MWh. If shared between all consumers the impact of intermittency on electricity prices would be of the order 0.1 to 0.15 p/kWh.
At current penetration levels costs are much lower, and if the market share were to rise above 20%, the costs would rise above these estimates.