Power generation technologies generally compete with each other both in regulated and deregulated markets to supply electricity through a ‘merit order’ based on availability and marginal cost of production for any given period. Fossil fuel, nuclear, biomass and hydro power generators can all to varying degrees supply electricity ‘on demand’, in other words supply from these sources can be called upon or adjusted to meet demand. In contrast to renewable hydro, the feed-in of wind and solar output is uncontrollably intermittent due to the uncertainty of meteorological conditions. In grid management terms they are not dispatchable. Therefore the energy system needs backup capacity from the on-demand-sources to bridge periods with high or low generation from renewables. The targeted rapid increase of power supply from intermittent renewable sources in many countries presents a fundamental challenge to the smooth functioning of many electricity supply systems.
Wind and solar power are the forms of renewable power that are expected to grow most rapidly. They accounted for 35% of EU renewable capacity in 2009, a percentage that the IEA in World Energy Outlook 2011 expects to increase to 55% in 2015 in its central ‘new policies’ scenario. By 2030 the IEA expects wind and solar to constitute 34% of total EU electrical capacity, up from 11% in 2009. However, the intermittency of wind and solar generation meant that the amount of electricity supplied from wind and solar capacity in 2009 was less than 5% of the total; 133 TWh was generated by EU wind turbines in 2009 which equated to a capacity factor of 20%. In the same year, nuclear had a capacity factor of 73%; thus to generate an equivalent amount of potential power to nuclear on the basis of these load factors, it is necessary to install three or four times as much wind capacity*. But that is not the main problem.
* This factor is likely to deteriorate over time as the optimal sites for wind and solar are progressively utilised, leaving only less favourable sites
Wind and solar power supply is largely governed by wind speed and the level of sunlight, which can only loosely be related to periods of power demand. It is this feature of intermittent renewable power supply that results in the imposition of additional costs on the generating system as a whole, which will implicitly be paid for either by other generators, consumers or taxpayers.
The IEA disaggregates these system costs into three components:
As noted above, additional back-up capacity is needed to meet demand rapidly when meteorological conditions result in insufficient wind and solar power generation. The adequacy and balancing capacity must itself have a high degree of availability, ie, it should be from a dispatchable source. This reserve or backup capacity is most likely to be needed during periods of high demand and lack of wind and solar, for instance on a calm winter’s evening. In such a situation significant levels of dispatchable backup capacity are needed to ensure security of supply.
Estimates of the wind/solar reserve requirement suggest that the reserve capacity ratio is expected to increase exponentially in proportion to the reliance of the system on intermittent power generation*. Germany is planning to increase wind and solar input to 20% of the total by 2020 and about 35% by 2030**. The EU as a whole is targeting a 27% renewable contribution to power supply by 2030. The adequacy and balancing capacity requirements for such high levels of intermittent renewable penetration can only be estimated theoretically.
* For instance, the DENA Grid Study of the German grid estimates a capacity credit (the contribution made by the capacity to securing the availability of the power supply system) of 6-8% at a 20% wind penetration and 5-6% at 45% penetration. A metastudy (The Costs and Impacts of Intermittency, UK Energy Research Council, Imperial College, March 2006) of capacity credit estimates shows a wide range, but with declining values in almost all cases.
** The requirements are set in the Renewable Energy Sources Act, as reported by Renewable Energy World (25 July 2011), however, the share of intermittent renewables in these percentages is not specified.
In World Energy Outlook 2010 the IEA estimates that adequacy and balancing costs for intermittent renewable power supply range from 0.18-0.8c/kWh of intermittent renewable power supply in the USA and from 0.13-0.65c/kWh in the EU in the New Policies Scenario in 2035*. The New Policies Scenario envisages that intermittent renewable power supply would constitute 13% of the 2035 total power supply in the US and 22% in the EU; these levels of penetration are relatively modest and the adequacy and balancing costs could be expected to increase significantly at higher levels of penetration.
* Distributed PV adequacy costs are assumed to be zero and large PV costs for the EU were not included due to the paucity of studies. Balancing costs were assumed to be 50% of the costs of onshore wind for Concentrated Solar Power and large PV and 75% for offshore wind.
IEA estimates* of generating (busbar) costs of wind in the USA and EU vary between 7.0-23.4c/kWh (solar is even more costly), so these adequacy and balancing cost estimates are equivalent to no more than 11% of the levelised wind generating cost. However, the costs of backup capacity clearly depend on the type of backup capacity envisaged. Pumped storage is often cited as an ideal renewable form of flexible backup but is relatively expensive (between 1.1-23.2 c/kWh); gas turbines would be generally cheaper, but still quite expensive given that they would be operating only for part of the time and therefore suffer low load factors (probably less than 20%). Gas turbines would also emit greenhouse gases as it would likely be prohibitively expensive to install CCS for sources with such low load factors. It is possible that where supply reliability cannot be guaranteed, many electricity users placing a premium on reliability (eg, hospitals) will invest in expensive local generating capacity (typically diesel generators).
* Projected Costs of Generating Electricity, IEA/NEA, 2010.
The third category of intermittent renewable integration cost is grid interconnection. Wind and solar farms are ideally sited in areas that experience high average wind speeds and high average solar radiation respectively. These sites are often, even typically, distant from areas of electricity demand. Transmission and distribution networks will often need to be extended significantly to connect sources of supply and demand – this is a current challenge in UK and North Germany. The IEA estimates these costs at 1.2 c/kWh in the USA and 0.9 c/kWh in the EU, which again must be recovered either from other producers, consumers or taxpayers.
The three categories of intermittent renewable integration costs are estimated by the IEA to vary approximately in sum from 1.1 to 1.7 c/kWh in the EU and 1.3 to 1.9 c/kWh in the USA. As footnoted above, these estimates are theoretical and pertain to the penetration of intermittent renewables forecast by the IEA in their ‘New Policies Scenario’ for 2035.*
* The figures given in the chart represent the higher values of the range of values given by the IEA. For some of the assumptions used please refer to earlier Footnote.
However, there is another category of costs that result from the operation of renewables and these can be described as the external costs borne by other power producers, in particular base-load power producers, as a result of intermittency. The structure of wind and solar levelised generation costs is characterised by high capital, significant O&M costs and zero fuel costs. As a result, the operating costs for these sources are very low and when power is generated they undercut and are able to displace all other sources of power in a utility’s merit order. In a situation of high levels of wind and solar power penetration and during periods of low demand, baseload generators will be displaced in the merit order. This is also required by legislation in many countries.
The impact of high levels of intermittent, low cost power will be to reduce the load factors of base-load power generators, and thereby increase their unit costs per kilowatt-hour. Given the high capital costs of nuclear, such an impact will significantly increase the levelised generation costs of nuclear. For example, a 15% decrease in the capacity factor of a nuclear power plant could increase its levelised cost by about 24%. In a situation similar to that targeted by Germany for 35% of supply to be intermittent renewable by 2030, renewable capacity when fully utilised would provide up to100% of supply. Inevitably there would be periods when a great deal of base-load capacity would be forced off-line.