Interesting to note that the best strategy to enable wind generation on a grid (which religious enviros love) is to match it's capacity with storage hydro dams (which religious enviros love to hate).

Question: How much can the availability characteristics of a large wind generation farm be improved by installing variously oversized propellers on smaller generator units, which means more of them need to shut down and lock out at lower wind speeds than normal but enables some of them to pick up at significantly lower wind speeds, meaning the overall wind farm more closely approaches eg. continuous power at 1/3 it's gross rating?

In addition, much existing hydro is currently committed as baseload power, already offsetting fossil fuel consumption. A strategy which reserved that output to compensate for wind variability, in whole or in part, would reduce the availability of the hydro for baseload and increase fossil fuel consumption.

Also, current hydro resources must be re-evaluated to determine the portion of the typical hydro resource which is reliable, as opposed to "source of opportunity" in protracted drought conditions, as demonstrated by BPA in the CA "fiasco".

Another strategy to improve wind farm CF is to use intermediate storage capacity to soak up the peaks and fill in the troughs, so that the wind farm can maintain a steady output over a contract period without having to discard excess power. That's what the VRB battery system at the Sorne Hill wind farm is intended to do.

Regarding use of hydro to balance wind, I'll have more to say about that in Part 3, on energy storage. But the gist is that you need at least a small outflow buffer reservoir and adequate transmission capacity. The outflow buffer serves two functions: it averages discharge over the daily cycle to maintain downstream flow, and it enables pumping into the primary reservoir to enable higher peak output.

http://www.windturbinecompany.com/contact/index.html

They use a downwind blade where the blades are flexible enough to flap. Still in development, but a theoretically promising track. With proper materials and development, this strategy should allow a blade where the tips simply "curl inward" in very strong winds to reduce swept area, and so stresses. And being downwind the blades don't need the stiffness of the upwind designs to avoid tower contact, and the towers may even be guy-supportable.

You mentioned coal plants being the next-best choice for buffering wind output. First, I have a question. How useful would IGCC plants be for performing this function? Does the process inherently involve all the syngas being burned immediately, or can any gas (or energy) be stored for any time period? Barring that, to what extent can IGCC units be cycled. Given the gas situation, it would be nice if we could use IGCC plants, as opposed to gas plants, to backup wind. I'd rather use them than conventional coal for environmental reasons.

Another reason for the above concern is the possibility that high use of wind could actually increase our use of gas. The theory is that wind "doesn't get along with" baseload plants, because those plants do not like to be cycled. And because of their high capital but low fuel costs you wouldn't want to cycle those plants anyway. If one knew that there would be a lot of wind around, resulting in a highly variable and unpredictable remaining load, one might be inclined to build a gas plant as opposed to a coal or nuclear baseload plant. This leads to an interesting result. Whereas the initial (and intuitively obvious) effect of wind would be that it displaces gas generation when the wind is blowing (thus reducing gas consumption), the long term effect may be to increase gas usage by causing gas plants to be built in lieu of baseload (coal/nuclear) plants. In effect, wind would rope us into using gas for a higher generation fraction, because we need more reactive load (vs. baseload).

The above argument also leads me to another question for you. You say that coal plants are the next choice, behind hydro, for buffering wind. Why wouldn't gas plants be the next choice? As you say, wind is largely avoiding fuel costs, and the fuel costs for gas plants are several times as high as those of coal plants. If the wind is blowing hard, wouldn't you wait for all gas generation in the region to be shut down before throttling back any coal plants? Is part of the reason the fact(?) that combined-cycle plants are not good at varying their output?

Regarding IGCC vs. gas vs. coal for dispatchable capacity: The gas-fired capacity that it sounds like you're thinking of, James, is simple CT peaking capacity, not combined cycle. Although cheap, it hasn't traditionally been very efficient. Most simple cycle turbines have been below 30%. So they weren't generally used until dispatchable intermediate capacity--usually coal--was fully committed. The high-efficiency GTCC units were both more expensive and less tolerant of cycling, so they tended to be reserved for baseload use. That's all begun to change, but not quickly.

The reason that coal is good for dispatchable capacity is that the key unit is a boiler, whose firing rate and steam output can easily be varied. It's true that the steam drives turbines which, like all turbines, operate best over a narrow throttling range. However, that's handled simply by varying the number of turbines being driven.

The same approach can be used with combined cycle plants of various types. The only difference is that instead of firing the boilers with flue gases from coal combustion, they're fired with high temperature exhaust from combustion turbines or (in the future) from high temperature fuel cells. With CTs, the firing rate would be stepped by stepping the number of CTs operating on the front end. The number of steam turbines operating would be stepped in parallel. The steam boiler and condenser remain at operating temperature at all times--aside from maintenance shutdowns.

I don't know how widely that approach to CC generation is currently implemented, but I expect that we'll see more of it in the future. I don't know of any reason that it would matter whether the front end CTs were fired by gasified coal instead of natural gas.

In any case, the point about wind variation is that, to the system, there's no inherent difference between normal load variation and wind-related supply variation. My understanding is that the average daily peak in most RBAs is three times the average daily minimum; that implies that at most one-third of our generating capacity can be baseload. In fact, I think the usual is more like a quarter--although that quarter delivers abut half of kilowatt-hours consumed. The other three quarters or generating capacity is dispatched, and operates with low CF.

One possibility that I neglected to mention in the upcoming part 3 for this series (covering large-scale energy storage) is thermal storage fed by the exhaust heat from such units. It would be decoupled combined cycle operation: instead of being used immediately to drive a bottom cycle steam turbine, the 600 degree C exhaust gases would charge a thermal storage unit. The stored heat could then be tapped later to provide peaking power.

Apparently the conversion of DC power into an AC waveform has some detrimental side-effects on transmission operations. Inverters produce anything from "square" waves to waves that are somewhat sinusoidal but still not as nicely formed as the output from an AC generators. Once wind energy penetration levels rise above some threshold level, there appears to be the potential for some adverse impacts that could be quite costly to rectify. I'm not personally familiar with the details other than to note when EPRI installed an experimental, solid-state phase angle regulation (Flexible AC Transmission, or FACTS) device in the WSCC some 20 or 30 years ago, it created a sub-synchronous resonance problem that was subsequently blamed for cracks in the steam turbine rotors at the Four Corners coal plant in Arizona (800 MW machines).

1st: From an economic standpoint (direct costs, not externalities), some clarification is needed regarding the statement that the value of wind is based on the fuel it displaces. For instance, the fuel displaced by wind will vary in cost and type depending on the demand, timing and resources of the region in which it operates. Assuming wind generation is random (which it is not), the value of the fuel displacement would be the weighted average of the fuel it displaces at the time it is generated. In the Midwest, that means wind may displace coal off-peak, during the night (at the 1.5 cent/kWh variable cost mentioned in the article) and then displace much higher cost gas during the on-peak periods. The fuel value that is displaced also depends on whether combined cycle plants are "at the margin" or during higher peaks, when simple cycle plants are needed. The value of displaced gas depends not only on the technology used, but also the current price of gas. Assuming $6.00/mmbtus (pick any number this past year!), the value of the displaced fuel would be roughly 4.2 cents/kWh for the combined cycle, while the savings from backing off the simple cycle peaker could easily exceed 6 cents/kWh. The point to recognize is simply that the direct economic payback value of wind energy is the weighted average of the resources that it affects throughout the year - at the time it affects those resources. .

2nd: Care is required in making any assumptions of capacity value since the annual average can be considerably different than the capacity actually contributed by wind during peak periods. For instance, in the Midwest, the wind is not expected to produce significant generation duriing the hot summer peaks, or the very cold winter peaks. (Winds are usually low on hot summer days and most wind turbines shut down at -20 degrees F.) Unfortunately, these are the times peaker generation is needed and the price of gas is the highest. For instance, during the peak hours of July, the actual generation percentage of wind project namplate may frequently be in the single digits.

3rd: Coal units are not good units for rapid load following (which may be required for expected rapid wind generation changes). Coal generator ramping rates are slow, plus coal units lose efficiency at lower levels of operation. Gas turbines can respond more quickly. Although gas turbines also lose efficiency at lower levels, they are typically smaller and more modular, allowing individual turbines to be shut down or started up as needs vary.

4th: The need for conventional resources to adjust to compensate for wind variability is exacerbated by the fact that the energy available from wind varies with the cube of the wind speed (i.e., if the wind velocity doubles, the amount of generation possible increases by 8 times). For that reason, new technology to better utilize lower speed winds will not produce commensurate increases in generation. Additionally, this phenomenom adds to the volatility of wind generation from a project. Howerve, as more wind projects are developed, the natural diversity among the projects should reduce the overall generation volatility of the combined projects.

The above notwithstanding, wind probably offers the best alternative energy source that can be developed at the lowest cost. To accomplish that goal, a national backbone grid for "'long haul" deliveries of energy from the wind-rich regions to the load centers is needed.

The nation's current transmission system is balkanized, congested and stressed. We need to develop a national grid system that will overlay the local and regional transmission systems that weren't designed to move power over long distances. Just as the Interstate Highway overlaid the state and local road system without displacing them, a national grid can accomplish the same result. The local transmission systems could continue to operate, just as the state and local roads continued to function after the Interstate Highway system was built.

And just as each state did not build the Interstate so other states could drive through their state, utilities cannot justify building transmission grid upgrades to areas they don't serve. A national approach is needed. That will allow wind to achieve its potential to become a significant energy source for the country.

Regarding DC to AC conversion issues, I'm unfamiliar with EPRI's experience with solid state phase regulation. It seems very unlikely to me that harmonics from the solid state regulator could have damaged turbine blades through induced resonance, but I suppose it's possible. Stranger things have happened. I do know, however, that there's no fundamental issue with DC to AC conversion. It's an integral part of the operation of high voltage DC power transmission, and there are HVDC lines all over the country.

Regarding valuation of wind based on the cost of fuel it displaces, I don't think it's quite correct to consider only the cost of fuel at the margins. Because of its unruly nature, wind does force TSOs to rely more on regulated capacity and quick-start units than they would like to. In the absence of compensating measures, it tends to displace fuel at the level of intermediate dispatchable units, while leaving fuel consumption by peaking units unchanged or even somewhat higher.

There are ways to avoid that problem, with a good example being the VRB battery system being installed for the Sorne Hill wind farm in Ireland. But wind farms that don't include any compensatory energy buffering or load shifting facilities are at best delivering less than full value. Regulations that require TSOs to purchase whatever power a wind farm may produce at the same rates they pay for scheduled generation are granting wind farms a huge effective subsidy, at the expense of other suppliers.

Regarding down wind machines and machines with furling blades, personally I see little prospect for these. Both have been tried in the past, and whilst they work very well on a small scale (see http://www.provenenergy.co.uk), no-one has yet managed to design a competitive machine for grid-connected operation. Most industry professionals feel that the disadvantages outweigh the advantages, and few seem willing to contend with the gyroscopic effects of a 150 tonne rotor furling as the wind gusts.

With regard to matching wind to another technology to resolve variable output, I disagree with the view that wind matches well with hydro. Firstly, much of the hydro power being developed today is run-of-river, and thus itself is a variable resource, Secondly, the experience in Europe over the last 20 years has taught us that in years when wind speeds are below average, rainfall is also below average! Realistically, matching depends on the portfolio of generating plant available within the "regional balancing area", however a personal observation is that the more diverse the generation mix, and the larger the balancing area, the more easily it seems that variable energy sources can be accommodated. This experience indicates that the creation of a super-grid for the continental US would allow greater up-take of wind, as well as providing other benefits such as the spreading of peak demand over a greater number of hours. Assuming that this allows more power plant to operate at optimum for longer, it would be interesting to hear from grid engineers if the benefits would outweigh the cost of establishing and running the grid.

Finally, concerning the issue of harmonics and grid instability, this was a great fear of grid operators in Europe 10 years ago. With over 42,000 MW of wind power now installed, those fears have not yet been realised. However, in areas with the highest wind energy penetration changes to the grid have sometimes been required. Wind power developers are also generally required to follow strict grid connection codes. There is an issue in Ireland, where there has been a moratorium on development of new wind farms, but this is more to do with the under-capacity of the grid than problems caused by the turbines themselves.

The accurate answer is that we just don't know what upper limit can be accommodated in any grid. 1. As no balancing area in the world (apart from a few island systems)* has yet to reach 20% penetration of variable generation, no-one has actually been able to demonstrate that it holds true in the real world**.

2. Grids are dynamic entities, the generation mix will change (as gas becomes more expensive and new coal & nuclear are brought on line) and demand profiles are changing (in response to higher energy costs). Therefore, in developing models to calculate the amount that can be accommodated, a lot of assumptions have to be made about the conditions that will exist in the future. Call me a cynic but I suspect that most of the assumptions are likely to be proven wrong when that future becomes the here and now. After all, twenty years ago who was predicting that gas fired power stations would expand so rapidly (and get into difficulties so rapidly)?

3. When people talk about variable power sources, they tend to think exclusively about wind power. They ignore the effects of other variable sources such as run-of-river hydro and combined heat and power (which when it is operated primarily for heat production, is the most variable generation source of all). In the distant future, we may also have to contend with meaningful amounts of solar, wave and tidal power

4. It is impossible to accurately assess the effect of non-technical issues on system operation. A prime example of this is electricity trading arrangements which penalise variable output and or consumption, or which are subject to political or regulatory caprice.

The 20% figure first surfaced in the UK about 18 years ago, when the (then) highly respected research arm of the then nationalised electricity industry calculated that no major changes to the grid or the way that it operated would be required until variable energy sources accounted for 20% of peak demand. This surprised a lot of people as it was allegedly commissioned by industry executives*** who did not want to have to accommodate variable generation in a system that at the time worked very nicely with coal, nuclear and a very small amount of hydro(2%). It seems to me that every study that I have seen since then has borrowed heavily from that piece of work.

The key issue is of course is what is meant by major changes to the grid. The Midwest Wind Integration Study**** has found that 25% of the Minnesota's energy could come from wind provided that it was operating in the Midwest Independent System Operator (MISO) service area, control area consolidation takes place, turbines are widely dispersed and there is adequate transmission. That sounds like a major change to the grid to me. There is a similar issue in the UK where about 4% of the total supply comes from variable sources (mainly wind and CHP), but where there is currently about 2,000 MW of wind capacity permitted or in the permitting process which is unable to connect because there is insufficient transmission capacity. This problem was not foreseen by the CEGB study because in my opinion it did not accurately take into account the fact that the majority of the UK's wind power resource is located in the relatively sparsely populated north and west, whereas demand is concentrated in the south-east.

Turning back to the non-technical factors, my experience also suggests that centrally dispatched systems where electricity is traded through a pool (allowing baseload to equal aggregated minimum demand) will be able to accommodate more variable generation than systems that rely on bilateral trading and where the SO buys and sells at the margin to balance the system. This is because in the former, variability is smoothed by pooling all the variable sources and balancing costs are spread across all generation. In the latter system, balancing costs tend to fall disproportionately on variable generation sources, reducing their viability.

* The Fair Isle (a small island off the north coast of Scotland) gets the bulk of its power from wind with a diesel back-up and a simple form of demand management – the residents only switch on heavy loads if they can see the turbines are turning! ** Experience in Northern Germany and Denmark suggest that 20% can be accommodated, but this ignores the fact that the two regions are interconnected to the Nordpool area and to the German grid and are thus part of a larger balancing area *** personal communication from former employees of the CEGB research laboratory **** More info and links on the Minnesota study are available at http://www.awea.org/newsroom/releases/Groundbreaking_Minnesota_Wind_Integration_Study_121306.html

Wind is, in fact, one of the highest cost options that exist for putting electricity onto the grid. Electricity from wind, costs about two to five times more than electricity from nuclear power, and also more than that from coal, gas, or even oil.

One high profile example of the many that I have analysed across Canada and elsewhere, may be familiar to you.

The Altamont Pass wind Farm has about 5,400 windmills. In 2004 they produced 820 million kWh of electricity. Just in case it may not be obvious to you, this production of electricity, is equivalent to that provided by a (small) 100 MW (electrical output) facility operating at 94%, for the year. And the reliable and controllable single unit, cost a lot less than the 5400 wind turbines in both capital costs and operating costs combined, is more reliable, and is expected to live longer.

Wind power is not cheap.

John K. Sutherland.

You give the example of Altamont, which is not one but a series of wind farms that happen to be some of the oldest in the world and which bear little relation to the installations now being built. That is a bit like using the example of a generator driven by a steam engine to claim that modern high temperature coal-fired power stations are not worthwhile.

As an engineer turned financier (of power and waste projects), my experience of real projects that reached financial close during the last 2 years is that wind power on sites with an average wind speed above 7.5 m/s (16.75 mph) is cheaper than new-build thermal power stations, even when the cost of variability is taken into account. We will not know with certainty if nuclear is cheaper or more expensive until someone actually reaches financial close on a new-build nuclear power station and publishes the details. Those countries that are actively looking at new nuclear plant tend to be those where there carbon taxes or carbon trading systems will give a boost to the price a nuclear generator will receive. This, coupled the 40% rise (in real terms) of the capital costs of large thermal power plant that has occurred over the last 5 years, suggests to me that new-build nuclear will be more expensive than new-build coal and new-build wind for at least a few years (until the cost of coal rises more).

I do not have the time right now to go into a detailed opinion of the economics of wind power versus coal or any other technology, but I can tell you this. There is a large pool of banks and investors willing to put money into new-build wind power on a non-recourse finance basis. There is a smaller pool willing to put money into new-build coal on a non-recourse finance basis. I do not know of anyone willing to put money into new-build oil or nuclear on a non-recourse basis. And this is in the post-Enron era, when investors are much more cautious than they were before 2000.

The planned wind development in the Tantramar marshes (New Brunswick/Nova Scotia) noted that 19 wind turbines will be erected in the Amherst Wind Energy Project, with a total of 31 megawatts (MW) of installed capacity, and that the total cost will be about $60 million (plus). It was described as likely to produce about 100 gigawatt hours (GWh) of electricity each year – or enough to supply about 10,000 homes, but omitted to say that this might be so only when the wind blows.

The installed cost works out to about $3.1 million, for each 1.6 megawatt windmill. If each windmill were to operate at full power for the entire year, then each would produce 14 million kWh (14,000 MWh or 14 GWh), and all of them would produce about 266 gigawatt hours (GWh) of electricity. Thus, the operators are assuming that these windmills will spin for an average of about 37% of the year at full capacity to produce the estimated 100 GWh (or 5.3 GWh per windmill). I know that the Tantramar marshes – close to sea level - are a windy place, but even the 5,000 plus windmills in the Altamont pass, high in the hills of California, can only manage to operate at about 20% of their capacity on average, so the assumption of 37% may be over-optimistic. Data from Denmark, Germany and Spain suggest that less than 20% (15%) is more likely. The limited data on the Pickering windmill (1.8 megawatts) show that it operates about 25% of the time or less.

However, let us assume for now that the 37% is correct, until actual operating experience provides better data. If one scales up this power output to match that of the nearby operating 680 MW nuclear reactor at Point Lepreau, which has operated at a lifetime factor of about 83% for the last 23 years (and allowing for only 630 MW of net capacity, as 50 MW of the 680 MW station, supplies the in-station needs), then Point Lepreau generates an average of 4,580 GWh each year. The equivalent output from the Amherst Project windmills operating 37% of the time, would require 864 of them, costing close to $2.7 billion of capital cost, or about twice the cost of the Lepreau re-furbishment of about $1.4 billion (including several hundred millions of purchased electricity during the down time)! If, as is more likely, the average operating time is about 20%, then the equivalent windmill cost (1600 of them) becomes about $5 billion, or almost four times the cost of Lepreau refurbishment for the same power production.

As one must build and have, the necessary reliable replacement power on hand – along with all of its costs - for those times when the wind does not blow, the obvious question should be asked: why bother with wind power at all? It is a surplus and un-needed environmentalist dream that causes capital costs of electrical energy derived from it, to be a factor of three to five and more, higher than the cost of electricity from the reliable ‘standby’ asset - in this case - Nuclear Power. If it is from coal or other fossil fuels, then having such stand-by power ticking over at a low level, as in Germany, Denmark, and Spain, also contributes much more to air pollution; pollution that should also be chalked up against wind energy operation. Not surprisingly, nuclear power and nuclear refurbishment look like great investments, and wind power doesn’t. Similar projects with similar very high costs relative to nuclear power are planned and under construction in Manitoba (Schneider Power), and at Melancthon and Grey Highlands in Ontario.

The Melancthon-GH project, to be constructed by Canadian Hydro Developers will cost $126 million in Capital Cost to erect 45 windmills each of 1.5 MW, for a total of 67.5 MW capacity. The maximum theoretical output (100% operation) from these windmills, and which cannot be achieved anywhere in the world, is 591,300 MWh. With a more likely operation of about 20% of capacity in the year – not even achieved by either Germany or Denmark, which are closer to 15% - the output will be about 118,000 MWh (118 GWh, costing $120 million) – the company assumes 190GWh. A comparable nuclear facility (details above) can generate 4,580 GWh or more, costing $1.4 billion.

And now a proposed wind farm at Taber in Southern Alberta with similar excessive cost: $140 million for 80 MW capacity, and unavoidable intermittency and unreliability.

Gigawatt for gigawatt, these projects demonstrate that wind project electricity costs more than three times more than that of nuclear electricity. Definitely not a good deal.

Invariably, all wind power projects clearly demonstrate that they are not only unjustified and unnecessary, but that they are too expensive, grossly unreliable, and environmentally damaging to an unacceptable degree. The British recently estimated the costs of their various options. Onshore wind costs are 5.4 pence/kWh (about 12 cents Canadian/kWh). Offshore wind costs are 7.2 p/kWh (these also include the fractional costs of the essential standby backup energy sources for when the wind does NOT blow and the reliable alternatives must be brought on line), and nuclear power, whose costs are 2.3 p/kWh.

The Utility Data Institute figures in the US show coal and nuclear as the cheapest overall, followed by gas, then oil and above all of them (but not shown by the UDI),is wind and solar.

John K. Sutherland

You correctly state that any benefit from reduced demand accrues to the fuel consumers. However, your statement that "subsidies can serve to motivate beneficial behavior that the market alone has no means to reward" seems to imply (in the context of the paper) that cheaper natural gas prices are beneficial to society. A careful comparison of the negative impacts for fuel suppliers with the positive impacts for fuel consumers would be necessary to determine whether the public subsidy actually results in a net societal benefit.

I was, indeed, writing from an assumed position that cheaper natural gas prices would be beneficial to society. That would be the working assumption for most readers--certainly for most economists and business execs--and I didn't see any point in questioning it. But you're right, one could moot the case that we'd be better off, as a society, if energy were not so cheap. That's a complex issue, and one I'd rather not get into here. In any case, I certainly wouldn't argue against renewables on the grounds that they will reduce the cost of fossil fuels. There is a school of thought that opposes any attempt to address energy issues, because they want the system to crash. I'm not a subscriber.

Regarding John's comments, all I think I'll say is that the economic payback for wind projects does, indeed, depend on PTCs and similar subsidies. But if one believes that rising atmospheric CO2 levels are real problem that needs to be addressed, then subsidies for non-carbon energy resources are not a bad thing. A carbon tax might be better, but the political reality is that subsidies are easier to pass than taxes.

And, yes, nuclear power is probably a better way to achieve significant reductions in CO2 emissions. But Adrian is also right: it's a lot easier to secure funding for a wind farm than it is for a nuclear plant.

The mix of generation capacity in ISO NE (30,931 MW) is natural gas 38%, oil 24%, nuclear 14%, coal 9%, hydro 5.5%, pumped storage 5.4%, other renewables 3.0%. The clearing price is set by oil and gas 80% of the time.

Capacity factors: over 90% for nuclear; 66% for base load oil (the Canal Unit #1, 620 MW); 50% for cycling oil (Canal Unit #2, 620 MW), and projected offshore Cape Wind project (454 MW) 40%.

Knowing the heat rate of the plants, the calculated cost of fuel alone for oil generation is about 7 c/kWh, for gas about 5 cents, coal and nuclear about 2 cents. Obviously the generation cost is much higher.

So wind power bid in at ISO at zero fuel cost will always bump the most expensively generated electricity off the top of the stack. Thus it will avoid consumption of the equivalent oil and natural gas (which may I remind you, can be, and is stored in tanks as energy).

As for load following, as Mr. Arnold points out, hydro is perfect. As is as pumped hydro or even more so since grid power is consumed to do the pumping. And in NE there is plenty of both. Incidentally, no one complained during the hay-day of nuclear that the cost of building pumped storage that would be required to meet peak day loads while storing nuclear generated power at night was detrimental or overly costly because of the nuclear industry that is just base load.

Thus the beginning penetration of wind power from the proposed Cape Wind offshore project (454 MW) in Nantucket Sound will have minimal effect on the grid stability and will always lower the cost to the end consumer by bumping oil and gas.

Charles Kleekamp, P.E. Ret.

When does the wind blow? In New England, the wind blows the most in the winter.

A case study. The proposed Cape Wind offshore, had it been in operation during the cold snap of Jan. 14-16, 2004, would have operated at a capacity factor of 62% based on the met tower data as reported in a DOE report delivering averaging 396 MW per hour over those three days.

At that time, there was something like 2,000 MW of gas generation off-line in ISO NE because there was no more available supply in the gas lines or in storage tanks. What was available was needed for heating supplies. Gas hit a record high price. There was speculation that some generating utilities were selling their gas on the spot market at more profit than generating electricity. ISO NE barely scraped through by reducing grid voltage 5% and physically manning substations if rolling blackouts were required (fortunately they were not).

Last August, ISO NE set another record hot delivery day in New England, again getting though only by reducing system voltage 5%. Offshore wind, unlike perhaps the great planes, picks up with the afternoon sea breeze just at about the same time the peak air conditioning load is prevalent.

On that hot August 8, 2006, the ISO ticker hit $1,000/MWh at 4:39 PM. The offshore windfarm would have been producing 150 MW at that hour had it been in operation. The next day was hotter. At 2:36 PM the grid hit another record, at that time the windfarm would have been delivering 236 MW.

Just a one time occurrence? No. Records show that this offshore wind farm would have added substantial power over the last 6 record breading summer days in New England.

In Europe? Some CPs for reference. Denmark, Horn Rev offshore: 45% Denmark all offshore average CP: 39% in 2005, a year if relatively low winds. Denmark average CP (both land and offshore): 24% Germany average CP (all land based): 16% (not so good!)

So now do you still think wind is not effective in avoiding CO2, and saving oil and gas (much from importation), and helping stabilize our consumer costs?

C. Kleekamp, P.E. Ret.

When making my earlier comments, I was specifically referring to costs rather than prices received as I wanted to avoid the confounding issue of subsidies. I am afraid I cannot name individual projects because I am bound by client confidentiality, however I have been authorised by one developer to release the following details of their last wind project (Nov 2006): The project is being constructed by a utility that also runs coal, gas and hydro plants, and purchases nuclear output.

Nameplate capacity Size: 23.1 MW Average Annual Capacity factor : 33.2% Average Annual Production 67,182 MWh Capital Cost $55.7 million Operating life of project 25 years Operating cost (real terms) including property taxes, head office charges, and use of grid charges $1.36 m per annum year 1 rising to $1.75 m per annum year 25

Taking into account interest charges on the debt, in real terms the whole life cost of the wind farm will be $121.3 million. This translates into a whole life cost of 6.97c per kWh, which is more than natural gas, but is less than coal (the last thermal plant I looked at had a whole life cost of about 8c per kWh in 2005). It is more or less equal to just the fuel costs of an oil fired power station.

As I pointed out earlier, until someone is willing to publish the details of a new-build nuclear plant, it is not possible to say what is the whole life cost of nuclear. However, I cannot see nuclear being less than coal – the fuel cycle cost of nuclear is similar to that of coal, but the capital costs are greater. The construction period is also longer, which means that the interest during construction will be higher even if the debt margin is the same (which is doubtful unless government underwrites the debt)

Turning to John's point about the cost of variability of wind output, in my opinion the UK is a good gauge of the maximum cost of variability. It has a punitive balancing mechanism, to which wind generators are exposed to through the suppliers who buy their output. Suppliers typically pay wind generators about 90% of the wholesale price of power, however some of the discount also covers the suppliers' costs of administration. This leads me to guess that the cost of managing variability is about 8% of the wholesale price.

How can I get a contract for that plant you're pricing?

As always the devil is in the detail. I was simply looking at the whole life costs of new-build projects of which I have detailed knowledge. My intention was not to produce the definitive league table of total costs of different technologies, simply to put an actual value to the cost of wind power to rebuff John's claim that wind power is three times more expensive than coal or nuclear.

Having said that, and within the caveat that cost per MW is inversely proportional to the size of the plant, I think your estimates of capital costs are too low. This morning I am looking at two new proposed coal plants. One is over 1000MW and is a replacement for an existing power station, so there is no infrastructure cost (i.e. the yard, the railhead, the grid connection are already there). It has a projected capital cost of $1.3M per MW. The other is a new build of approx 650MW and has a projected capital cost of $2.83M per MW.

Likewise, bear in mind that major maintenance charges over the life of the project (i.e. equipment replacement) typically amount to about 50% of the capital cost, also interest charges have doubled since the start of the decade.

"Canada and China have signed a final contract for the construction of two 700 MWe CANDU-6 nuclear reactors worth C$4 billion (US$2.99 billion) at Quinshan."

(Among the ) most recent reactors built, though agreed still negotiated 10 yrs ago. Even allowing that today in North America the price may have risen to eg. US$4 billion, that's a capital cost of $2857 / kw

Taking interest during construction at 12% for 4 yrs, and interest at 8% over 30 yrs to finance the resulting $4.148 billion investment, O&M at 37% of capital, and fuel at 0.0081 / kwh has these units generating electricity at $0.0575 / kwh, which I think should be more in line with the high side of simple rankine coal generation.

Wind can provide 25% of sales in MISO (~10% of peak demand, based on ~40% load factor), according to this study. This is well below the conventional capacity reserve margin.