“On the surface, it appears that a resource which cannot be controlled at will threatens this hard-won reliability. Fortunately, a better understanding of wind technology is slowly overcoming the once bedeviling specter of wind energy’s intermittency–what to do when the wind stops blowing. Though, “technology has surpassed the institution,” says BTM Consults’ Per Krogsgaard, the idea lingers. Krogsgaard notes that executives now directing utilities base their perceptions on ideas conceived in the 1940s. According to conventional wisdom, utilities would still need the same amount of generating capacity with or without wind power plants, because the wind is intermittent: it is sometimes unavailable when most needed. A reporter for the widely read Washington Post swallowed this myth as late as 1991. “Because it is unavailable when the wind isn’t blowing,” wrote Thomas Lippman, “wind power will never be more than a supplemental source of electric power, even in high wind areas such as the Great Plains.”(1)

“Disregarding the fact that no technology, alone, whether coal or natural gas, is more than a supplement to a utility with a diversified mix of generating plants, Lippman ignored findings of utilities in the United States and Europe that wind energy does indeed provide capacity benefits. Although wind turbines may be idle due to a lack of wind at times of a utility’s peak demand, there is a statistical probability that they will be available, especially if there are multiple turbines dispersed geographically. In this, wind turbines are no different from conventional power plants. No generating plant operates 100% of the time, and no power plant is 100% dependable during peak loads.

“The work of Don Smith, a consultant to Pacific Gas & Electric, as well as that of engineers in Europe, has refuted the notion that wind energy cannot supply secure power. The firm power of wind energy per kilowatt-hour generated is remarkably similar to that of conventional sources. The question then becomes not if there is any capacity value in wind energy, but what its value is in offsetting the construction of conventional power plants. Utilities have traditionally viewed wind energy solely as a fuel saver. Each kilowatt-hour generated by a wind turbine offsets a kilowatt-hour that would have been otherwise generated. But in some cases, the capacity value of wind energy to a utility is equal to that of the fuel it offsets.(2)

“Smith, for example, found that an exceptional fit between the wind resource in Solano county and Pacific Gas & Electric’s demand justified a credit of nearly 80% of a wind plant’s installed capacity, based on a loss of load analysis. This is equivalent to that of a fossil-fired power plant. Using the same analysis, he found a lesser, but not insignificant, value of 20% for the Altamont Pass.(3) The capacity value for the Altamont is surprisingly similar to the area wide capacity factor. . .”

Don Smith was an engineer with the California Public Utility Commission in San Francisco and he worked with wind integration.

Here’s a posting by Smith in 2003 that summarizes a meeting reviewing an extensive new report by California’s Energy Commission (the full 2004 report is cited below).

1. Increased costs of “regulation” due to any extra Automatic Generation Control required by wind or solar to maintain voltage and frequency. This turned out to be a negligible cost. Wind and solar variability were essentially “noise” compared to the system load variability and generation variability. Also, costs associated with the variability of uncorrelated factors, such as wind and load are added as the square root of the sum of the squares, not as a linear addition.
2. Increased cost due to “load following”, that is, having to buy or sell electricity for the next hour due to the unpredictability of wind or solar energy. A crude “forecasting” model was used: the assumption that the solar output would be the same as it was during the same hour of the day on the day before, and wind was “predicted” by assuming that the output would be the same the next hour as it is during this hour. This cost also proved to be negligible, although this may be a “flaw” in the market system, as the SCE people claimed.
3. The effective load carrying capability (ELCC) of wind was calculated for the 3 wind areas. One unpleasant surprise for renewables was that solar energy didn’t have the near perfect fit to load it was expected to have. At least part of the bad solar fit may be due to the fact that the hours of greatest chance of a loss of load came in October, when solar (and wind) were waning. This happened because the utilities and merchant generators had already taken a significant amount of capacity out of operation in October, which had some high load days. (The highest load days had been earlier in the summer.) Regardless of the issue of this study, the fit of renewables to load, if the finding of major risk in October is true, it may indicate that the timing of maintenance for power plants in California may be putting the state at undue risk of blackouts.

Further, here is a summary by John Dunlop, formerly AWEA’s midwest representative, of a presentation by Carl Weinberg, former manager of R&D at Pacific Gas & Electric Co. in 1996.

1. PG&E has provided up to 8% of its power supply from wind plants (in low load, high wind conditions) with no impact on service quality.
2. Typical utilities experience average minimum loads as low as half of their peak generating capacity. Consequently, they have the ability to ramp from 50% of their peak capacity to their peak capacity.
3. Since utilities can modulate up to 50% of their peak capacity to match load, they can also use that capability to track variable wind power equaling up to 50% of their peak non-wind capacity, so long as the ramp rate does not exceed the ramp rate of their load- following capacity. (He suggests that if wind energy was the cheapest source of power, utilities would quickly accommodate wind energy into their generation mix; Weinberg estimates that they could incorporate up to 50% of their peak non-wind capacity without additional dispatchable reserves.)
4. Since a utility can possibly accommodate wind power up to 50% of their peak non-wind capacity with their existing generation mix, Weinberg adopts a “conservative” estimate that virtually any utility can incorporate wind power up to 20% of their non-wind capacity with no changes to their system and no decrease in their system reliability.

Based on the discussion following Weinberg’s presentation, Dunlop added the following clarification.

• Annual energy contribution should not be considered in determining peak “penetration levels” of wind energy. The relevant relationship is between the peak generation capacity of a wind power plant and the peak firm capacity of the utility.
• “Back up power” for wind energy already exists within all utility systems; it is used to follow variable loads. That capacity can be used to accommodate wind power equaling at least 20% of virtually any utility’s firm generating capacity.
• A distinction needs to be made between total generating capacity and firm generating capacity. Wind energy, in the first many years of adoption, will parallel existing load-following dispatchable firm capacity. Experience will help determine the actual percentage of firm capacity, if 20% or even greater, that can reliably be supplied by an intermittent resource like wind.
• The capacity value paid for wind energy will be dependent upon the loads and generation mix of the host utility. It is feasible that demonstrated peak load matching quality of wind energy in a particular application would actually increase the power penetration level beyond the perceived 20%.

Peter Freere, formerly an engineering professor at Monash University in Australia, has also contributed to a discussion of this topic on AWEA’s list serve in 1997.

Freere notes that “although there have been numerous studies predicting the maximum penetration level of wind energy in a system, the actual experimental results in the case of diesel systems indicate that 70% penetration is fine.”

Early integration studies, says Freere, were overly cautious on maximum penetration because they assumed

1. that all the wind turbines would experience the same wind velocity at the same time,
2. that the turbine generators were driving fixed-speed induction generators directly connected to the power grid, and
3. that the conventional generators in the system are coal or nuclear and are therefore unable to respond quickly to changes in wind speed.

Freere responds that

• in practice there is usually sufficient variation in the wind speeds at each turbine, so that the average output power of the wind farm does not vary nearly as much as the power output of individual turbines,
• the advent of large, variable-speed generators for wind turbines and inverter connection to the grid, the turbine control system is able to respond to the grid’s needs and actively support it to produce voltage and power flow stability,
• fast responding conventional generators inlcude hydro, gas turbines and diesel gensets. These are well able to compensate for variations in the power output of a wind farm.

He goes on to say that “it is correct that in normal electric grids (without energy storage – eg batteries, flywheels etc), a wind farm would not work well on its own and some conventional energy sources are also required. The same applies to the conventional energy sources, especially nuclear, whose response time is so slow that they must have a fast responding generation system in parallel. It is also true that due to the large sizes of modern generators in conventional systems (eg. 500 MW per generator), to allow for maintenance and breakdowns, it is necessary to have a complete spare generator ready to take over when another stops working (for whatever reason).”

“Hence the risk with wind farms is not so great – no more than many conventional systems. In Canada and New Zealand, the wind resource may be more predictable and more regular than the rainfall required for the hydro system. It is suggested that in New Zealand wind power could be used to save hydro water, because at times there is insufficient or nearly insufficient water for generation.”

The largest study on grid integration was done in Germany by DENA. An English summary of the massive report is available. The gist is that investment in the grid will be necessary to integrate the new renewable generation needed meet the German target of 20% of supply from renewable energy by 2020. The investment required is less expensive than additional grid expansion if new central-station plants are built, and this investment will result in making the grid more stable with or without the renewable generation.

More recently (March 2006) the UK’s Energy Research Centre issued a report analyzing the results of some 200 studies on the grid integration of intermittent renewables. The following are excerpts from the summary of The Costs and Impacts of Intermittency: An assessment of the evidence on the costs and impacts of intermittent generation on the British electricity network. (This work has been updated. See intermittency – 2016 update.)

• It is sometimes said that wind energy, for example, does not reduce carbon dioxide emissions because the intermittent nature of its output means it needs to be backed up by fossil fuel plant. Wind turbines do not displace fossil generating capacity on a one-for-one basis. But it is unambiguously the case that wind energy can displace fossil fuel-based generation, reducing both fuel use and carbon dioxide emissions.
• Wind generation does mean that the output of fossil fuel-plant needs to be adjusted more frequently, to cope with fluctuations in output. Some power stations will be operated below their maximum output to facilitate this, and extra system balancing reserves will be needed. Efficiency may be reduced as a result. At high penetrations (above 20%) energy may need to be ‘spilled’ because the electricity system cannot always make use of it. But overall these effects are much smaller than the savings in fuel and emissions that renewables can deliver at the levels of penetration examined in this report.
• None of the 200+ studies reviewed suggest that introducing significant levels of intermittent renewable energy generation on to the British electricity system must lead to reduced reliability of electricity supply2. Many of the studies consider intermittent generation of up to 20% of electricity demand, some considerably more. It is clear that intermittent generation need not compromise electricity system reliability at any level of penetration foreseeable in Britain over the next 20 years, although it may increase costs. In the longer term much larger penetrations may also be feasible given appropriate changes to electricity networks.
• The introduction of significant amounts of intermittent generation will affect the way the electricity system operates. There are two main categories of impact and associated cost. The first, so called system balancing impacts, relates to the relatively rapid short term adjustments needed to manage fluctuations over the time period from minutes to hours. The second, which is termed here ‘reliability impacts’, relates to the extent to which we can be confident that sufficient generation will be available to meet peak demands. No electricity system can be 100% reliable, since there will always be a small chance of major failures in power stations or transmission lines when demands are high. Intermittent generation introduces additional uncertainties, and the effect of these can be quantified.
• System balancing entails costs which are passed on to electricity consumers. Intermittent generation adds to these costs. For penetrations of intermittent renewables up to 20% of electricity supply, additional system balancing reserves due to short term (hourly) fluctuations in wind generation amount to about 5-10% of installed wind capacity. Globally, most studies estimate that the associated costs are less than £5/MWh ($0.0087/kWh) of intermittent output, in some cases substantially less. The range in UK relevant studies is £2 – £3/MWh ($0.0035-$0.0052/kWh).
• Unless there is a large amount of responsive or controllable demand, a system margin is needed to cope with unavailability of installed generation and fluctuations in electricity requirements (e.g. due to the weather). Conventional plant – coal, gas, nuclear – cannot be completely relied upon to generate electricity at times of peak demand as there is, very approximately, a one-in-ten chance that unexpected failures (or “forced outages”) in power plant or electricity transmission networks will cause any individual conventional generating unit not to be available to generate power. Even with a system margin, there is no absolute guarantee in any electricity system that all demands can be met at all times.
• Intermittent generation increases the size of the system margin required to maintain a given level of reliability. This is because the variability in output of intermittent generators means they are less likely to be generating at full power at times of peak demand. The system margin needed to achieve a desired level of reliability depends on many complex factors but may be explored by statistical calculations or simplified models. Intermittent generation introduces new factors into the calculations and changes some of the numbers, but it does not change the fundamental principles on which such calculations are based.
• Intermittent generators can make a contribution to system reliability, provided there is some probability of output during peak periods. They may be generating power when conventional stations experience forced outages and their output may be independent of fluctuations in energy demand. These factors can be taken into account when the relationship between system margin and reliability is calculated using statistical principles.
• Capacity credit is a measure of the contribution that intermittent generation can make to reliability. It is usually expressed as a percentage of the installed capacity of the intermittent generators. There is a range of estimates for capacity credits in the literature and the reasons for there being a range are well understood. The range of findings relevant to British conditions is approximately 20 – 30% of installed capacity when up to 20% of electricity is sourced from intermittent supplies (usually assumed to be wind power). Capacity credit as a percentage of installed intermittent capacity declines as the share of electricity supplied by intermittent sources increases.
• The capacity credit for intermittent generation, the additional conventional capacity required to maintain a given level of reliability and thus the overall system margin are all related to each other. The smaller the capacity credit, the more capacity needed to maintain reliability, hence the larger the system margin. The amount by which the system margin must rise in order to maintain reliability has been described in some studies as “standby capacity”,”back-up capacity” or the “system reserves”. But there is no need to provide dedicated “back-up” capacity to support individual generators. [Emphasis added] These terms have meaning only at the system level.
• This assumes around 20% of electricity is supplied by well dispersed wind power. Current costs are much lower; indeed there is little or no impact on reliability at existing levels of wind power penetration. The cost of maintaining reliability will increase as the market share of intermittent generation rises.
• The aggregate ‘costs of intermittency’ are made up of additional short-run balancing costs and the additional longer term costs associated with maintaining reliability via an adequate system margin. Intermittency costs in Britain are of the order of £5 to £8/MWh ($0.0087-$0.0139/kWh), made up of £2 to £3/MWh from shortrun 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 approximately £30 to £55/MWh ($0.052-$0.0958). If shared between all consumers the impact of intermittency on electricity prices would be of the order 0.1to 0.15 p/kWh ($0.0017-$0.0026/kWh).

In summary then, there are a number of myths surrounding the integration of renewables, especially wind energy, into an electricity network because of the variability of the resource. Though there are technical issues surrounding grid integration they are in no way insurmountable, nor the costs of integration excessive. Where there has been a desire to integrate large amounts of renewable energy into a utility system as in Denmark, Germany, and Spain, there have been the technical and managerial means to do so at modest cost.

Below are a few links to other reports on grid integration of renewables. This list is by no means exhaustive.

• Managing Variability: A report to WWF-UK, RSPB, Greenpeace UK and Friends of the Earth EWNI by David Milborrow, June, 2009
• Impact of Intermittency: How Wind Variability Could Change the Share of the British and Irish Electricity Markets July, 2009
• Design and Operation of Power Systems with Large Amounts of Wind Power, IEA Wind Task 25, 2007
• Supplying Baseload Power and Reducing Transmission Requirements by Interconnecting Wind Farms, Cristina Archer, Mark Jacobson, Stanford, 2007
• Wind Power in Power Systems by Thomas Ackermann
• The Costs and Impacts of Intermittency: An assessment of the evidence on the costs and impacts of intermittent generation on the British electricity network
• Summary of the Essential Results of the Study, Planning of the Grid Integration of Wind Energy in Germany Onshore and Offshore up to the Year 2020 (Dena Grid study), by the Project Steering Group, Deutsche Energie-Agentur, Berlin, 2005.
• Large Scale Integration of Wind Energy in the European Power Supply: analysis, issues, and recommendations, EWEA, Brussels, 2005.
• An Analysis of the Impacts of Large-Scale Wind Generation on the Ontario Electricity System, CanWEA, AWS TrueWind, 2005.
• California Renewables Portfolio Standard Renewable Generation Integration Cost Analysis Phase III: Recommendations For Implementation, Publication Number: 500-04-054, 2004, ,
• The Costs of Wind’s Variability: Is There a Threshold?, Joseph F. DeCarolis and David W. Keith, January/February 2005.
• The Economics and Environmental Impacts of Large-Scale Wind Power in a Carbon Constrained World, by Joseph Frank DeCarolis (PhD dissertation), Carnegie Mellon, 2004
• The Economics of Wind Power with Energy Storage, Liliana E. Dragulescu, Pablo C. Benítez and G. Cornelis van Kooten, Resource and Environmental economics and Policy Analysis (REPA) Research Group Department of Economics University of Victoria, January 2006.

---

1. Thomas Lippman, “A Breath of Fresh Air for Wind Power, Washington Post, November 25, 1991.

2. Leon Freris, Wind Energy Conversion Systems (London: Prentice Hall, 1990), Chapter 17, “System Integration,” by E. Bossanyi, 357-371.

3. Don Smith, “Wind Energy Resource Potential and the Hourly Fit of Wind Energy to Utility Loads in Northern California,” proceedings, proceedings of Windpower 90, the annual conference of the American Wind Energy Assoc., Washington, DC, September 24-28, 1990, 47-52.