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No limits to high wind penetration

The world's wind resource is huge. Global demand for electricity could be met by wind power alone several times over. The presumption, however, is that it is neither technically nor economically feasible to run powersystems based entirely on wind power. In recent times a number of studies have put paid to the myth of a technical barrier. This article demonstrates that the so-called economic barrier barely exists either

Limits to the proportion of wind generation in any large and well interconnected power system are economic, not technical. Pay enough money and the lights will stay on, even if the system is based on 100% wind power. But is there an economic limit? Not if an increase in power system regulating cost that adds less than 10% to consumer electricity bills is an acceptable price to pay for going all-wind without compromising security of supply.

Indeed, depending on which technology wind is replacing, consumers can save money with high levels of wind penetration. If wind is built instead of gas at today's high gas prices, wind's contribution to electricity demand can be as much as 60% before the economic tipping point is reached and the total price to consumers -- power system cost together with generation and delivery costs -- is higher.

That power systems can technically accommodate large volumes of wind without disturbing security of supply is a concept that some utility engineers, let alone politicians and the general public, have had a hard time grasping. Times are changing, however. No longer is it only the wind industry saying the wind does not have to blow all the time to contribute significantly to meeting electricity demand, any more than a thermal plant has to stay online all the time. Power system operators with practical experience of wind are coming to the same conclusion, based in particular on studies in Britain and Denmark. In America at least half a dozen utilities have looked at the issue and agree. Even the Spanish system operator, not historically known for its forward thinking on wind power integration, is discovering it can cope with far greater levels of wind penetration than it at one time believed possible (Windpower Monthly, May 2006).

Economic basics

With the perceived technical barrier to lots of wind power shrinking to the status of myth, the focus is turning to the perceived economic barrier. When wind is only meeting a fraction of peak electricity demand, the only extra cost to the system is paying for the additional spinning reserve needed over and above that required for an electricity network based mainly on thermal generating technology. The additional reserve needed is small, so the cost of providing it is negligible. But as the wind penetration level increases, so does the requirement for reserve power -- and extra back-up.

The explanation for the rising system cost of adding wind lies in the decreasing volume of thermal plant displaced by wind power. As more wind is added, relatively more back-up has to be provided by thermal plant. In other words, wind's "capacity credit," which is the volume of thermal plant displaced by wind power expressed as a percentage of the installed wind power, declines. In practice, 10,000 MW of wind with a 30% load factor, say, may only displace 2000 MW of thermal plant, but deliver energy corresponding to 3000 MW of thermal plant. As a consequence the load factor of the remaining thermal plant -- the amount of time it operates at full power -- is depressed. That results in the thermal plant's fixed costs being spread over a smaller number of units of electricity, which means those units cost more.

Just how much more (or little) consumers will have to pay for high proportions of wind power in the broad electricity supply mix is only now beginning to emerge. The greater understanding is a direct result of greater experience with operating larger volumes of wind power leading to greater knowledge. Denmark is setting the agenda. Its system operator, Energinet, has taken the ultimate step of studying the economic impact of basing its power system on 100% wind (Windpower Monthly, February 2006). Today, the country gets about 20% of its power from the wind and is discussing a target of 80% electricity from renewables by 2025.

A system based on 100% wind power does not mean that at all times, all electricity is supplied by wind plant. At times, thermal plant step in to make up any gap between supply and demand; at other times, the wind plant generate more than is required. But over the course of a year, the total wind capacity on Energinet's virtual all-wind system, with an effective penetration level of about 70%, can potentially cover the total requirement for electricity.

How it was done

The Energinet study, Market Impacts of Large Scale System Integration of Wind Power, conducts an hour-by-hour time series simulation of consumer demand -- the load on the electricity system -- against available wind power generation, using wind power production data from western Denmark, where wind penetration is 23%. Having determined the volume of wind capacity needed to supply a given fraction of the energy demand, the study sets the wind power output alongside the demand data on an hour-by-hour basis. In this way it determines how often and for how long thermal generation is needed to satisfy the load when consumer demand is exceeding wind power production. The reference level of electricity demand used by Energinet is 26 TWh. Assuming an average capacity factor for wind plant of 25%, an all-wind power system would require around 12,000 MW of wind power.

The conclusion on cost reached by Energinet is that the rate of increase in the penalty that must added to wind to account for the additional cost to the system of managing its variability slows as more wind is added (fig ure1). At a wind penetration of 10%, the penalty is EUR 10/MWh, rising to EUR 14.5/MWh at 50% wind and EUR 14.8/MWh at 100% wind. In other words, if the generating cost of wind is EUR 50/MWh, the total cost -- allowing for extra reserves for Energinet's nominal 100% penetration -- is EUR 64.8/MWh.

For the consumer a steady increase in wind penetration ups the "variability cost" (the cost of supplying extra reserve and back-up) in a gradually rising curve (figure 2). At 30% penetration, the extra cost is around EUR 3/MWh. Ultimately, when enough wind capacity is installed to theoretically deliver all the electricity needs, the extra system cost reaches EUR 9/MWh, well under 10% of average domestic electricity prices in the developed world.

The increased variability cost includes all the extra reserve and back-up required to maintain the same secure supplies of electricity associated with a no-wind system. It is a worse-case scenario in that it presumes that in periods when the wind plant are producing more electricity than required, the extra production is worthless: it is dumped or wind output is curtailed. In other words, not only is western Denmark treated as an isolated system with no cross-border interconnections, but any potential for using excess wind power to create hydrogen for transport is ignored, as is the possibility for storage. In reality it is more likely that production in excess to demand will have a value.

Testing the approach

Detailed studies have also been made of integrating up to 20% of wind into the British power system, most recently in a 2004 report, Total Cost Estimates for Large-Scale Wind Scenarios in the UK. Unlike Denmark, Britain does not have a wealth of wind power production data gathered over a number of years to draw on, so the report synthesises wind power data from wind measurements to examine the economics of adding 26,000 MW of wind to the British system, or 20% penetration.

Similar methodology can be used to assess the variability cost of adding 130,000 MW of wind to the British system for a 100% wind-based supply by scaling Energinet's time series wind data (hour by hour production from 2400 MW of wind plant in western Denmark for a 23% wind penetration over the whole of 2002). The results of that exercise support Energinet's conclusion -- even with very high levels of wind penetration, the cost of keeping the lights on adds less than 10% to domestic electricity bills.

The UK is several times bigger than western Denmark with a diverse topography and far more varied wind resource, considerably reducing the chance of there being zero wind production at peak demand. As a result, the volume of extra back-up needed in the UK is lower, reducing wind's "variability penalty." Using Energinet financing parameters to enable a comparison, with 10% wind penetration, the "cost of variability" in the UK is EUR 4/MWh of wind, compared with Energinet's EUR 10/MWh. The disparity narrows at higher wind energy penetrations. With 50% wind, the UK cost is EUR 11/MWh, compared with Energinet's EUR 14.5/MWh. With 100% wind, the figures are EUR 13.3/MWh for the UK and EUR 14.8/MWh in Denmark. If the UK capacity credit is reduced there is closer agreement between the two studies.

Transmission reinforcement

The Energinet study does not include the cost of any wind-specific transmission -- new wires to alleviate transmission congestion that would not have been built had thermal plant been added at another location instead of wind. The total system costs cited in the UK study do take account of this aspect. Transmission congestion occurs when significant amounts of wind power generating capacity are concentrated in the windiest regions, with the result that there is insufficient capacity to transmit all the wind power when it is operating at or near peak output. No general rules apply to transmission congestion economics, which can only be studied on a case-by-case basis.

The value of surplus wind

With high penetrations of wind power there will be times when more electricity is being generated than is needed. The point at which surplus wind power may need to be rejected, or diverted to other markets, will depend on the capacity factor of the wind and the electricity demand pattern. With a penetration level of 23% in western Denmark today, there have been rare occasions when total demand has been less than the total wind production.

At a penetration of 30% wind power, the wind energy surplus over the course of a year will be 0.5% of the generation, rising to 3.5% with 50% wind, 17.5% with 80% wind, and 30% with 100% wind (figure 3). On a nominal 100% wind power system, consumers actually only get 70% of their electricity from the wind -- 30% of the time it is delivered by thermal plant. In theory it is quite possible to increase the wind capacity further, but the economics become progressively unrealistic.

Wind power surplus to system requirements is not necessarily worthless, as the Danish and UK curves in the main graph presume. If the system has links with other networks, as Denmark has, the surplus can be exported, provided it does not exceed the capacity of the links. Another option is to divert the surplus into new markets.

The lower the price at which the surplus electricity is sold, the greater the chances of finding a market. Energinet assumes a modest value of EUR 13.3/MWh for the surplus, which reduces the maximum cost of the variability penalty from EUR 14.5/MWh to around EUR 13.5/MWh (with 50% wind), falling to EUR 9/MWh with 100% wind because of the extra revenue derived from those sales.

The selling price assumed by Energinet -- EUR 13.3/MWh -- is well below the market price for electricity. The system operator suggests the surplus may be used for electric heating in its widespread district heating systems, heat pumps, or to produce hydrogen, by electrolysis, for use in vehicles.

The hydrogen option only makes sense if hydrogen-fuelled vehicles come onto the market. Even then, the cost of the electrolysis plant needs to be taken into account. Energinet does not suggest using the hydrogen as a storage medium, with a view to feeding electricity back into the system. That would necessitate additional plant, such as fuel cells, and incur significant losses, so it is unlikely it would be economic.

If electricity markets with high wind penetration do evolve, the prospects for storage technologies such as flow batteries and compressed air may improve. The storage facility must be paid for, which requires that the electricity sent out from the store has a higher value than the electricity used to charge the store. Much depends on the efficiency of the storage device. If the higher cost of the electricity leaving the store is still economically attractive to the electricity network, then storage can be used. That will often not be the case. On the other hand, a storage system that can be charged with electricity at below market cost can possibly be used for arbitrage -- releasing electricity into the system when market prices are high.

The financial penalty that must be added to wind power to cover the requirement for more thermal reserves is only part of the overall cost to the consumer of building wind instead of thermal plant. In most cases, however, wind is being built instead of gas. At today's high gas prices, that saves the consumer money -- a point that Xcel Energy, which buys more wind power than any other utility in America, has been at pains to point out (Windpower Monthly, July 2006). During 2005, wind power was typically around EUR 4/MWh cheaper without allowing for the carbon penalties, which can add up to EUR 10/MWh to the price of gas fired generation. The resulting EUR 14/MWh cost differential cancels out the variability premium, indicating that it makes sense to add wind instead of gas up to a penetration level of around 60%. Up to that point the variability penalty is less than the gas penalty.

Is all-wind sensible?

The estimates of extra variability cost quoted in this analysis may be on the high side -- for two reasons. First, as more wind is added to the network, it is likely to be more widely spread and this smoothes the wind fluctuations, possibly also reducing the periods of very low wind output. Thus the estimates for thermal reserve could be on the high side. Second, neither the Danish nor British studies examine the implications of demand side management, which could significantly reduce the requirements for the thermal reserve. A considerable amount of work is in progress on this issue worldwide. Improved demand side management is likely to have a significant impact on the ability of electricity networks to absorb increasing quantities of wind energy.

Without storage, which is generally not economically viable in today's markets with existing technologies, the economic limit seems to lie with Energinet's nominal "100% wind" system, which actually delivers 70% wind power to consumers, with the remaining 30% exported or channelled into other markets. Beyond that level requires large amounts of both wind and storage -- in effect considerable overcapacity to retain security of supply. The storage capacity would need to cover lengthy periods when the wind power output was inadequate to system demand.

But a nominal "100% wind" supply can be achieved at an additional cost for system reserves and back-up of less than 10%. For society as a whole it seems likely that high penetrations of wind power are a money saver. As more wind is added to the system, total CO2 emissions steadily fall. By the time a (nominal) 100% wind penetration level is reached, the emissions are around 30% of a "no wind" level, according to the Energinet study.

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