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Examples of Wind Power to Learn From

Willem Post's picture
President, Willem Post Energy Consuling

Willem Post, BSME'63 New Jersey Institute of Technology, MSME'66 Rensselaer Polytechnic Institute, MBA'75, University of Connecticut. P.E. Connecticut. Consulting Engineer and Project Manager....

  • Member since 2018
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  • Mar 11, 2011


Various government entities, eager to show their greenness regarding global warming, passed laws to subsidize renewable power, so-called “green power”, as if there is such a thing. Some governments even passed laws that declare hydropower as non-renewable, but, on reflection of its implications, reversed themselves and passed laws that declare hydropower IS renewable, as recently did Vermont’s legislature.


President Andrew Jackson, Democrat, populist: “When government subsidizes, the well-connected benefit the most”. The renewables subsidies to the politically well-connected often result in uneconomic wind power projects, some of which are described in this article.


Vendors, owners, financiers often claim “trade secrets”, whereas in reality they want to obfuscate wind power’s shortcomings, a too-generous subsidy deal, or other insider’s advantage. It would be much better for all involved, if there were public hearings and full disclosure regarding the economics of any project receiving government subsidies, to ensure the people’s funds receive the best return on investment.




The University of Maine, UM, decided to install a 600 kW wind turbine made by RRB Energy Ltd, an Indian company, at its Presque Isle Campus. Results from a 20-month wind resource assessment indicated the campus receives enough wind for a community wind project, not a commercial wind project. 


Community wind power is defined as locally-owned, consisting of one or more utility-scale or a cluster of small turbines, totaling less than 10 MW, that are interconnected on the customer or utility side of the meter. The power is consumed in the community and any surplus is sent to the utility which supplies power as needed.


The purpose was to generate power and to use the wind turbine as a teaching tool for the students. Because it is almost impossible to obtain operating data from the vendors, owners and financiers of wind facilities, UM, to its credit, decided to make available all of its wind turbine operating data.


Capital Cost and Power Production


Estimated capital cost $1.5 million

Actual capital cost $2 million; an overrun of 33%

The project was financed by UM cash reserves and a $50,000 cash subsidy from the Maine Public Utilities Commission.

Estimated useful service life about 20 years.


Predicted power production 1,000,000 kWh/yr

Predicted capacity factor = 1,000,000 kWh/yr)/(600 kW x 8,760 hr/yr) = 0.190


Actual power production after 1 year 609,250 kWh

Actual capacity factor for 1 year = 609,250 kWh/yr/(600 kW x 8,760 hr/yr) = 0.116; a shortfall of 39%

Value of power produced = 609,250 kWh/yr x $0.125/ kWh = $76,156/yr; if O&M and financing costs amortized over 20 years are subtracted, this value will likely be negative. 


Actual power production after 1.5 years 920,105 kWh

Actual capacity factor for 1.5 years = (920,105 kWh/1.5 yrs)/(600 kW x 8,760 hr/yr) = 0.117


Operation and Maintenance


According to the European Wind Energy Association: “Operation and maintenance costs constitute a sizable share of the total annual costs of a wind turbine. For a new turbine, O&M costs may easily make up 20-25 percent of the total levelized cost over the lifetime of the turbine.” 


Energy Used by the Turbine (Parasitic Energy)


Parasitic energy is used by the wind turbine itself. During spring, summer and fall it is a small percentage of the wind turbine production. During the winter, it may be as much as 10 – 15 % of the wind turbine production. Much of this energy is needed whether the wind turbine is operating or not. At low wind speeds, the turbine production may be less than the energy used by the turbine; the shortfall is drawn from the grid.


Two low-wind-speed days were selected; a summer day and a cooler winter day to show that in summer the parasitic energy is less than in winter. In winter, the wind speed has to be well above 4.5 m/s, or 10.7 miles/hour, to offset the parasitic energy and feed into the grid. Speeds less than that means drawing energy from the grid, speeds greater than that means feeding energy into the grid. 


This will significantly reduce the net energy production during a winter. On cold winter days, even at relatively high wind speeds of 10.7 miles/hour, or greater, energy is drawn from the grid, meaning the nacelle (on big turbines the size of a greyhound bus) and other components require significant quantities of energy; it is cold several hundred feet above windy mountain ridges.


Summer day: 14 May, 2010, wind speed 2.9 m/s (6.9 miles/hour), net power output  -0.3 kW.


During summer days, University of Maine wind energy production is minimal, i.e., wind turbines draw energy from the grid for many hours.


Winter day: 20 Nov, 2010, wind speed 4.5 m/s (10.7 miles/hour), net power output -5.6 kW.


During winter days, University of Maine wind energy production is maximal; up to 200 MW from this poorly-sited 600 MW unit?


Below is a representative list of equipment and systems that require electric power; the list varies for each turbine manufacturer.


– rotor yaw mechanism to turn the rotor into the wind

– blade pitch mechanism to adjust the blade angle to the wind

– lights, controllers, communication, sensors, metering, data collection, etc.

– heating the blades during winter; this may require 10 – 15 % of the turbine’s power

– heating and dehumidifying the nacelle; this load will be less if the nacelle is well-insulated.

– oil heater, pump, cooler and filtering system of the gearbox

– hydraulic brake to lock the blades when the wind is too strong

– thyristors which graduate the connection and disconnection between turbine generator and grid

– magnetizing the stator; the induction generators used to actively power the magnetic coils. This helps keep the rotor speed constant, and as the wind starts blowing it helps start the rotor turning (see next item)

– using the generator as a motor to help the blades start to turn when the wind speed is low or, as many suspect, to create the illusion the facility is producing electricity when it is not, particularly during important site tours. It also spins the rotor shaft and blades to prevent warping when there is no wind.




The huge difference between predicted and actual capital cost and capacity factor would be disastrous for a commercial installation. Because this is for “teaching purposes” such a detail is apparently not that important. The capital cost and any operating costs in excess of power sales revenues will likely be recovered by additions to tuition charges.


UM should find less expensive ways to educate students in all areas, not just wind power. Cost per university student in the US is already well over 2 times that of Europe, a competitive disadvantage.




Dehumidification and heating of nacelles of the (4) 2.5 MW Georgia Mountain Community Wind Turbines on a 2500-ft high ridge line in Vermont is necessary to prevent rusting from condensation and electric shorts.


The HVAC equipment shown in the below video was an afterthought add-on.


On the ground are the noisy, air-cooled HVAC units with flexible hosing to the nacelle. These HVAC units use significant parasitic energy that is subtracted from the wind energy fed to the grid. Listen to the video.




The Bolton Valley Ski Area decided to be the first in Vermont to have a wind turbine. It decided to have a 100 kW wind turbine made by Northern Power Systems, Barre, Vermont. The purpose was to generate power and, by selecting a Vermont wind turbine, it would likely be favorably considered for a Clean Energy Development Fund subsidy.  


Capital Cost and Power Production


Actual capital cost $800,000;

The CEDF provided a $250,000 cash subsidy to the politically-well-connected Bolton Valley Ski Area.

Estimated useful service life about 20 years. 


Predicted power production 300,000 kWh/yr

Predicted capacity factor = 300,000 kWh/yr)/(100 kW x 8,760 hr/yr) = 0.34


Actual power production after 17 months (1.4 yr) 204,296 kWh from October 2009 to-date

Actual capacity factor for 17 months = 204,296 kWh/1.4 yr/(100 kW x 8,760 hr/yr) = 0.17; a shortfall of 50%

Value of power produced = 204,296 kWh/1.4 yr x $0.125/ kWh = $18,241/yr; if O&M and financing costs amortized over 20 years are subtracted, this value will likely be negative.


It is somewhat like selling a car and telling the new owner it will do 34 mpg, whereas it actually does only 17 mpg. 


Update: A recent check of the Bolton Valley website in January 2013 


Actual power production after 39 months (3.25 yrs) was 509,447 kWh from October 2009 to-date.


Actual capacity factor for 39 months = 509,447 kWh/(3.25 yr x 100 kW x 8,760 hr/yr) = 0.179; a shortfall of 47.4% of the 0.34 promised.


Value of power produced = (509,447 kWh x $0.125/kWh)/3.25 yr = $19,594/yr; if O&M and financing costs amortized over 15 – 20 years are subtracted, this value will likely be negative. STILL A VERY BAD INVESTMENT.


On April 2, 2011, the Bolton website showed the following readings: 


19.7 mph windspeed, 21.2 kW output 

22.3 mph windspeed, 22.5 kW output 

23.4 mph windspeed, 24.5 kW output 


Those outputs are much lower than the ones stated on page 6 of the NPS specifications. Outputs should be about 55-65 kW for these windspeeds, minus parasitic losses which appear to be about 11-12 kW at temperatures below 32F. May be the windspeed indicator reads high. Adding in some weeks of down-time further reduces power production and CF. This may explain the shortfall in power production and the low CF.




It appears the Bolton Valley Ski Area may have made a mistake selecting a 100 kW wind turbine to reduce its power costs. The value of the revenue will be grossly insufficient to justify the project. 


It seems the CEDF should do more due diligence before donating the people’s money to such projects. 


In the Great Plains wind power with moderate subsidies pays, i.e., is comparable to coal, gas and nuclear power, because there are many areas with capacity factors of 0.40 or greater, capital costs are about $2,000/kW and O&M costs are not high.


In New England much greater subsidies will be required to make wind power pay because there are few areas on suitable ridgelines with capacity factors greater than 0.35 and capital costs, based on Maine wind farms, are about $2,500/kW, or greater, O&M costs are high, especially in winter; frequent snow plowing at 2,000-plus ft elevation and outages due to freeze-ups and icing of the blades, etc., are common.




Texas had installed about 10,377 MW of wind turbines at the end of 2011, an increase of 686 MW from the end of 2010.


The 2010 energy production was (10,089 + 10,377)/2 x 8,760 hr/yr x CF 0.29285 = 26, 251,410 MWh


The CFs for the past 6 years were 0.205, 0.215, 0.179, 0.224, 0.235, and 0.293 from 2005 – 2010.


Whereas the West Texas Panhandle has excellent wind speeds, and most wind turbines are of recent vintage, i.e., have greater capacity factors, the state average capacity factors are average. It will be many years of retiring 10 to 12 year ”old” wind turbines before the state average CF will increase to about 0.30.


This is likely due to curtailments of wind energy during periods of greater wind speeds and low demands, mostly at night. The curtailments are needed, because wind turbine capacity was installed much sooner than the required, extremely costly, long distance transmissiion systems. 


Are the costs of the extra transmission systems to be rolled mostly into household electric rates, per past practice, or are they to be borne by the wind turbine owners?




Oahu has an island grid system with no/little interconnection with other islands. Wind energy must be smoothed before entering the grid. 


No existing conventional units can be shut down, because 10-15 % of the year there is no wind energy as wind speeds are too low (7.5 mph) to turn the rotors or too high for safety. 


The 30 MW IWT facility, with 12 Clipper Liberty wind turbines, @ $3,900/kW, requires a capital cost of about $117 million. The USDOE loan guarantee was for $117 million.


Xtreme Power, Inc., supplied the dynamic power modules and the battery back-up system (to smooth the wind energy) housed in a 10,000 sq ft building.


Xtreme Power, Inc. used 10 specially-designed inverters from Dynapower Corp. and installed them in 10 dynamic power modules (DPMs) housed in a building. During test operations, the inverters caught fire due to defective capacitors by Electronic Concepts, Inc.


The project will include 20 MW of advanced lithium-ion batteries from A123 System, Inc., a leading supplier of lithium-ion batteries that provide grid stabilization more efficiently and with less environmental impact than existing resources. The contained battery and related electrical systems are assembled, tested, and validated in an A123 manufacturing facility in Hopkinton, Mass. 


First Wind will sell the energy to Hawaiian Electric Company under a long-term PPA “at contract prices”, i.e., well above market prices. 


Unfortunately, a THIRD fire since start-up in Match 2011 completely destroyed the 10,000 sq ft building and the equipment. It will take at least $8 million to rebuild which will take about one year. 


The wind turbines were shut down until further notice, i.e., in about a year to clean up the mess, redesign, rebuild and perform test operations. Where would an additional $8 million come from? US DOE?


This an example of starry-eyed RE incompetents in the US DOE (who have no “skin in the game”) doling out the people’s money to incompetent wind turbine project developers; incompetence usually rules when the players use other people’s money.  Solyndra, A123, etc., come to mind. 


Recently, Solyndra and A123 declared bankcuptcy. Subsidies appear to attract not creative inventors, but hustlers, con men and scam artists, who are in it for the “free” money.


Danish Offshore: Offshore turbines are located in very windy areas. Their capacity factors range from 0.235 to 0.484, with an average of 0.391.


CFs in Europe: This URL has detailed information regarding energy conditions, wind energy, CFs in Europe.


Below are the averaged CFs in some widely-dispersed geographical areas for the 2006 – 2011 period.


Sample calculation: US wind energy CF in 2011 = 119,747 MWh/(46,919 MW, end 2011 + 40,180 MW, end 2010)/2 x 8,760 hr/yr) = 0.314; based on AVERAGE installed capacity. The US 6-yr average CF, similarly calculated, is 0.289; this is a more accurate value, as it evens out varying winds from year to year.


Germany, onshore                   0.187; dismal, but rising due to offshore IWTs

Denmark, including offshore    0.251; rising due to offshore IWTs

The Netherlands                     0.228

The US                                   0.289; a high value due to excellent winds in the Great Plains.

Texas                                     0.225

Ireland                                    0.283; Ireland and Scotland have the best winds in Europe.

New York State, 19 facilities    2009, 0.189; 2010, 0.227; 2011, 0.236; 2012, 0.235                   

Spain                                       0.241

China                                       2009, 0.153; 2010, 0.152; 2011, 0.161; 2012, 0.166

Australia                                 0.300

UK, 2012                                0.275; rising due to offshore IWTs




Maine plans to have 2,000 MW of IWTs by 2015 and 3,000 MW by 2020. About 400 MW were in operation at the end of 2012.


All US IWT owners connected to the grid have to report their quarterly outputs, MWh, to the Federal Energy Regulatory Commission, FERC. The data is posted on the FERC website, and, with some effort, can be deciphered.


Capacity Factors less than Estimated: Below are some numbers regarding the much less than expected results of the Maine ridge line IWTs for the 12-month periods indicated in the below table.


                               Oct 2011-Oct 2012       Dec 1011-Dec 2012


Mars Hill, 42 MW              0.353*                        0.3613 

Stetson I, 57 MW             0.254                          0.2140

Stetson II, 26 MW            0.227                          0.1837

Kibby Mtn 132 MW           0.238                          0.2278

Rollins, 60 MW                 0.238                          0.2408   

Record Hill, 50.5 MW        0.197                          0.2462


Weighed average              0.247                          0.2427

*Uniquely favorable winds due to topography.


Example: The Maine weighted average CF = (42 MW x CF 0.353 + 57 x 0.254 + 26 x 0.227 + 132 x 0.238 + 60 x 0.238 + 50.5 x 0.197)/(42 + 57 + 26 + 132 + 60 + 50.5) = 0.247; excluding Mars Hill, the weighted average CF is 0.234. 


Note: CF reduction due to aging is not yet a major factor, as all these IWTs were installed in the past 5 years.


Causes for Lesser Capacity Factors: The lesser, real-world CFs are likely due to:


– Winds entering 373-ft diameter rotors varying in speed AND direction under all conditions*; less so in the Great Plains and offshore, more so, if arriving from irregular upstream or hilly terrain, as on ridge lines. 


– Turbine performance curves being based on idealized conditions, i.e., uniform wind vectors perpendicularly entering rotors; those curves are poor predictors of ACTUAL CFs.


– Wind testing towers using anemometers about 8 inch in diameter; an inadequate way to predict what a number of 373-ft diameter rotors on a 2,500-ft high ridge line might do, i.e., the wind-tower-test-predicted CFs of 0.32 or better are likely too optimistic.


– Rotor-starting wind speeds being greater than IWT vendor brochure values, because of irregular winds entering the rotors; for the 3 MW Lowell Mountain IWTs rotor-starting speed with undisturbed winds is about 7.5 mph, greater with irregular winds.


– IWT self-use energy consumption up to about:


up to 4% for various IWT electrical needs during non-production hours; in New England, about 30% of the hours of the year (mostly during dawn and dusk hours, and most of the summer), due to wind speeds being too low or too high, and due to outages. This energy is drawn from the grid and treated as an expense by the owner, unless the utility provides it for free. 


up to 8% for various IWT electrical needs during production hours; power factor correction, heating, dehumidifying, lighting, machinery operation, controls, etc. 


Note: In case of the 63 MW Lowell Mountain, Vermont, ridge line IWT system, a $10.5 million synchronous-condenser system to correct power factors was required, by order of the grid operator ISO-NE, to minimize voltage variations that would have destabilized the local rural grid; self-use energy about 3% of production, reducing the IWT CF of about 0.25 or less, to about 0.2425 or less.


– CFs declining up to 1%/yr, based on UK and Denmark experience, due to aging IWTs having increased maintenance outages, just as a car.


– Reduced production for various other reasons, such as:


* Curtailment due to the grid’s instability/capacity criteria being exceeded

* Curtailment due to excessive noise; nearby people need restful sleep for good health

* Curtailment due to excessive bat or bird kill

* Flow of an upwind turbine interfering with a downwind turbine’s flow. As a general rule, the distance between IWTs: 


– in the prevailing wind direction should be at least seven rotor diameters 

– perpendicular to the prevailing wind direction should be at least three rotor diameters. 


Note: In case of the 63 MW Lowell Mountain, Vermont, ridge line system, 21 IWTs, with 373-ft diameter rotors, are placed on about 3.5 miles of 2,500-ft high ridge line. Construction drawings indicate the spacing varies from about 740 ft to about 920 ft, or 1.96 to 2.47 rotor diameters.


New England ridge line directions are from SW to NE, as are the prevailing winds. Significant wind flow interference, increased noise, increased wear and tear, such as rotor bearing failures, and lesser CFs will be the result.


GMP opting for the greater diameter rotor, to increase the CF, worsened interference losses, i.e., likely no net CF increase, but an increase in lower frequency noises that are not measured with standard dBA testing.



US bird kill = 1 bird/day x 39,000 IWTs x 365 days/yr = 14,235,000 birds/yr. 

US bat kill = 2 bats/day, or 28,470,000 bats/yr, for a total of 42,705,000 animals/yr.


The net effect of all factors shows up as real-world ridge line CFs of 0.25 or less, instead of the vendor-predicted 0.32 or greater, i.e., much less than estimated by IWT project developers to obtain financing and approvals. 


Note: Irregular air flows to the rotor cause significant levels of unusual noises, mostly at night, that disturb nearby people. Details in this article.  


Government Regulators Lack of Due Diligence: It appears regulators: 


– Did not ask the right questions on their own (likely due to a lack of due diligence and knowledge of power systems), or 

– Ignored/brushed aside the engineering professionals, who gave them testimony or advised them what to ask, or 

– Received invalid/deceptive answers from subsidy-chasing IWT project developers and promoters, or 

– Kowtowed to wind energy-favoring politicians allied with wind energy oligarchs, i.e., not hinder IWT build-outs, or 

– Did all of the above.


The developers told Maine regulators their IWT projects would have CFs of 0.32 or greater, and 25-year lives, to more easily obtain bank financing, federal and state subsidies, and “Certificate of Public Good” approvals. Once they get approval, there is no accountability for poor performance. Meaningful players in the IWT smoke-and-mirrors game, including regulators, know this. All understand IWTs are about subsidy chasing and tax sheltering, not about efficient, high-quality energy production. 


Because of subsidy-chasing by IWT project developers, and politicians wanting to be seen as doing something about climate change and global warming, the vetting process of proposed IWT projects by boards of political appointees is much compromised, which is creating distrust, resentment, anxiety and division among the lay public, and especially among the many thousands of people “living” nearby the IWTs, whose quality of life is greatly compromised. 



Below is the URL of a table that shows the performance of New York State’s wind turbines.


The Vendor promises were capacity factors of 30% to 35%, before installation.


The reality, after installation:


Installed capacity, MW: 1,162 in 2008; 1,274 in 2009; 1,274 in 2010; 1,348 in 2011

Production, MWh: 1,282,325 in 2008; 2,108,500 in 2009; 2,532,800 in 2010; 2,780,700 in 2011

Capacity factors: 18.4% in 2008; 19.8% in 2009; 22.7% in 2010; 24.3% in 2011


The 2006-2011 average CF was 0.249, much less than predicted before installation.


The data for the table was obtained from the 2011 New York ISO Gold Book.


The low CFs are not unique to NY State. It has replicated itself in The Netherlands, Denmark, England, Germany, Spain, Portugal, Ireland, etc. See above section “Worldwide CFs Below Expectations”.


UNSUBSIDIZED wind energy costs have bottomed out to about: 1.5-2 times annual average grid prices in the Great Plains, 3 times grid prices on 2,500 ft high ridge lines in New England, 4-5 times grid prices offshore, such as Cape Cod.


The production is invariably less than promised. Add this to the fact that the CO2 emissions reduction is much less than claimed by wind energy promotors, as shown in below articles, makes further subsidies and investments in wind energy an extremely dubious and expensive proposition. See URLs.



The Kibby Mountain, Maine, 132 MW wind turbine facility, capital cost $320 million, is owned by TransCanada and was built, after a lot of destruction, on one of the most beautiful ridge lines in Maine.  It was placed in service on 10/31/2009.TransCanada, an energy conglomerate, and Vestas, a Danish wind turbine company, claimed that the capacity factor would be 0.32, or greater.


Its FERC designation is “Trans Canadian Wind Development, Inc.”, in case you want to look up the below data.


In 2009 and 2010, the facility had a lot of startup problems and its energy production was negligible.


In 2011, it had a capacity factor of 22.5% for the first 9 months.

For the 3rd quarter of 2011, it was 14.42%. Monthly capacity factors were as follows:


July       18.48%

Aug       12.31%

Sept      12.41%


Why are the CFs so low?


Winds on ridge lines have highly-irregular velocities AND directions. This does not show up when one performs wind velocity testing with an anemometer, but when rotors are 373 feet in diameter (a football field is just 300 ft long), one part of a rotor will likely see a different wind velocity AND direction from another part. This leads to highly-inefficient energy production and low CFs. Wind vendors are very familiar with this, but do not mention it. However, all is explained in this article.


The VT-DPS and Senate and House Environment and Energy Committees, and all others, should finally read this article, before “leading” Vermont into an expensive energy la-la-land.




A $200-million wind facility in northern New Brunswick, consisting of 33 units @ 3 MW each made by Vestas, a Danish company, owned and operated by GDF SUEZ Energy, a French company, is frozen solid, cutting off a potential supply of renewable energy for NB Power which has a 20-year Power Purchase Agreement with GDF Suez Energy. 


The 18-mile stretch of wind turbines, located 44 miles northwest of Bathurst, N.B., has been completely shutdown for several weeks due to heavy ice covering on the blades. The same happened during the 2009-2010 winter.


For the 5th year in a row, the three New Brunswick wind turbine plants (150 + 99 + 45 = 294 MW) have UNDERPERFORMED.


In 2012, owner/vendor-promised production 904,000 MWh, for a CF of 0.35; actual production 694,000 MWh, for a CF of 0.27. The utility is not complaining, because the production shortfall enables it to by energy from the grid at about 5.5 c/kWh, about half the price of 10.5 c/kWh it HAS to pay, by law, for wind energy! 


A fourth proposed wind turbine plant has been put on hold, because of grid reliability/coping issues.




Cape Wind Associates, LLC, plans to build and operate a wind facility on the Outer Continental Shelf offshore of Massachusetts. The wind facility would have a rated capacity of 468 MW consisting of 130 turbines @ 3.6 MW each made by Siemens AG, a German company, maximum blade height 440 feet, to be arranged in a grid pattern in 25 square miles of Nantucket Sound in federal waters off Cape Cod, Martha’s Vineyard, and Nantucket Island. 


The Massachusetts Department of Public Utilities approved a 15-yr power purchase agreement, PPA, between the utility National Grid and Cape Wind Associates, LLC. National Grid agreed to buy 50% of the wind facility’s power starting at $0.187/kWh in 2013 (base year), escalating at 3.5%/yr which means the 2028 price to the utility will be $0.313/kWh. The project is currently trying to sell the other 50% of its power so financing can proceed; so far no takers, because significant quantities of less expensive power from other renewables is available.


A household using 618 kWh/month will see an average wind power surcharge of about $1.50 on its monthly electric bill over the 15 year life of the contract; if the other 50% of power is sold on the same basis, it may add another $1.50 per month. Tens of thousands of households and businesses will all be chipping in to make the owners of Cape Wind Associates richer.


Power production is estimated at 468 MW x 8,760 hr/yr x CF 0.39 = 1.6 GWh/yr. 

The capital cost is estimated at about $2.0 billion, or $4,274/kW. Federal subsidies would be 30% as a grant.




The residential wind system is for a recently built LEED Platinum house in Charlotte, Vermont, capacity 10 kW, grid-connected, 80-ft mast, all-in cost $40,500, or $4,050/kW. The project received a CEDF cash subsidy of $12,500


Power production is about 6,286 kWh/yr; 6,094 kWh is used, 192 kWh is sold to the utility as part of “net-metering” 

Capacity factor = (6,094 + 192) kWh/yr/(10 kW x 8,760 hr/yr) = 0.0712 

The owner pays the utility $9/mo. for standby power. 

Useful service life is about 10-15 years after which it will need to be replaced or refurbished. 


Levelized cost of buying electricity from the utility for 25 years is about $0.230/kWh 

Levelized cost of wind power with no incentives is about $0.701/kWh, base on a 15-year $40,500 mortgage at 5%/yr




Residential wind power systems are very uneconomical investments.

The legislature enacting subsidies for such projects is a grossly inefficient use of the people’s money.

It appears the CEDF should do more due diligence before donating the people’s money to such projects. 


Another Example of Small Wind:


Middlebury College turbine.


Bergey; 10 kW; on a 100 ft mast; 22 ft dia rotor; $ 45,000 to install; 50% paid for by DOE; production about 8,000 kWh/yr for about 10 – 15 years.


CF = 8,000 kWh/(8,760 hr/yr x 10 kW) = 0.091; miserable. 


$45,000/$4,500/kW = 8 kW of PV panels would produce: 8 x 8,760 x CF 0.143 = 10,021 kWh for 25 years.


I am glad I did not go to school at Middlebury College.




If grid power fails, then a wind turbine can provide its own parasitic power if there is enough wind. Three conditions are described: 


No-wind and Little-wind Conditions, Wind turbines are not operating or are turning on grid power: 


If a grid power failure, emergency back-up power (batteries or diesel-generator) is needed to provide parasitic power, especially in winter, as described above.


Medium Wind Conditions, Wind turbines are operating: 


If a grid power failure, emergency back-up power (batteries or diesel-generator) is needed to provide parasitic power, as described above. Wind turbines may not be allowed to feed into the grid, but may be operated to supply only parasitic power.


Too-high Wind Conditions, Blades are feathered, rotor is locked and facing the wind: 


If a grid power failure, emergency back-up power (batteries or diesel-generator) is needed to provide parasitic power, as described above.




Germany is very marginal for wind power, especially in the south. its national average wind power CF is 0.187, lower than the Netherlands (0.228) and Denmark (0.251).


A solution is to have wind turbines with very tall masts and oversized rotors. One such unit is the Enercon-82, capacity 2 MW, hub height 138 m (460 ft), rotor diameter 82 m (273 ft), for a total height of about 600 ft. The unit requires a substantial foundation. The installed cost is about $2,600/kW. 


The units have a fan in each blade with an electric heater that circulates warm air through the uninsulated, hollow blade to keep it warm in winter to prevent icing that impairs blade aerodynamics, as on an airplane wing, and to prevent excessive noise. 


Five of them are located on a flat hill in the Hof District of Bavaria, Germany. Total project cost about 18 million euros, or $26 million. A 25-year mortgage at 5%/yr to pay off the capital would have annual payments of $26 million/amortization factor of 14.09 = $1,845,280/yr.


However, an investor may want to make a profit, not just pay off the mortgage. Say 8%/yr for taking the risk to borrow the money, create the project and pay the borrowed money back over 25 years from risky future cash flows.


The gross capacity factor is 22,500 MWh/yr/(10 MW x 8,760 hr/yr) = 0.257 

The net CF is 10 – 15 % less, say 10% less, due to parasitic power. 

Unit power cost = $1,845,280/(22,500,000 kWh/yr x 0.90) = 0.091/kWh, excludes O&M of about 0.015/kWh and insurance and risk premium, i.e., making a profit.


The cost of baseload power in Germany is about $0.055/kWh, which means the Hof District wind power in Bavaria is at least $0.106/$0.055 x 100 = 93% greater than grid prices; if making a profit is included the percentage will be higher.    


A technical success? Maybe. An economic success? No. 




Because the NEEG has very minor wind power penetration, there would be no data to study fuel consumption and CO2 emissions related to cycling plants to accommodate wind power, as there are in other jurisdictions. Accordingly, a recent study of Colorado and Texas, both states with significant wind facilities, would be used to illustrate some impacts of wind power on plant operations. 


Power Plant Cycling In Colorado  


Public Service of Colorado, PSCO, lacks sufficient gas-fired CCGT capacity for cycling to accommodate wind power. Instead, it is attempting to use coal plants for cycling for which they were not designed and for which they are highly unsuitable. The results have been significantly increased pollution and CO2 emissions per kWh.


Fuel consumption in Btu/kWh is called heat rate; for a coal plant operated near rated output it is about 10,500 Btu/kWh for power delivered to the grid. It is lowest near rated output and highest at very low outputs. If a plant is ramped up and down (cycled) at a percent of rated output, its heat rate rises. See Pages 26, 28, 35, 41 of the Bentek study.  


On Page 28, the top graph covering all PSCO coal plants shows small heat rate changes with wind power during 2006. The bottom graph shows greater heat rate changes with wind power during 2008, because during the 2006-2008 period 775 MW of wind capacity was added. For the individual PSCO plants doing most of the cycling, the heat rate changes are much higher. 


On Page 26, during a coal plant ramp down of 30% from a steady operating state to accommodate state-mandated “must take” wind power, the heat rate rose at much as 38%.


On Page 35, during coal and gas plant ramp downs, the Area Control Error, ACE, shows significant instability when wind power increased from 200 to 800 MW in 3.5 hours and decreased to 200 MW during the next 1.5 hours. The design ramp rates, MW per minute, of some plants were exceeded.


On Page 41, during coal plant cycling across the PSCO system due to a wind power event, emissions, reported to the EPA for every hour, showed increased emissions of 70,141 pounds of SOX (23% of total PSCO coal emissions); 72,658 pounds of NOX (27%) and 1,297 tons of CO2 (2%) than if the wind power increase had not caused the plants to be cycled. 


Those increases of CO, CO2, NOX, SOX and particulate per kWh are due to instabilities of the combustion process during cycling; the combustion process can ramp up and down, but not too rapidly. As the varying concentration of the constituents in the flue gases enter the air quality control system it cannot vary its chemical stoichiometric ratios quickly enough to remove the SOX below EPA-required values. These instabilities persist well beyond each significant wind event. 


PSCO does not release hourly wind generation data. Such baseline information is critical for any accurate analysis and comparison of alternatives to reduce such emissions; deliberately withholding such information is inexcusable.


Power Plant Cycling In Texas


The Texas grid in mostly independent from the rest of the US grids; the grid is operated by ERCOT. The grid has the following capacity mix: Gas 44,368 MW (58%), Coal 17,530 MW (23%), Wind 9,410 MW (12% – end 2009), Nuclear 5,091 MW (7%). Generation in 2009 was about 300 TWh. By fuel type: Coal 111.4 TWh, Gas CCGT 98.9 TWh, Gas OCGT 29.4 TWh, Nuclear 41.3 TWh, Wind 18.7 TWh.  Summer peak of 63,400 MW is high due to air conditioning demand. 


Wind provides 5% – 8% of the average generation overall, depending on the season. Its night contribution rises from 6% (summer) to 10% (spring). Texas capacity CF = 18.7 TWh/yr/{(9,410 + 7,118)/2) MW x 8,760 hr/yr)} = 0.258. Texas has excellent winds and should have a statewide CF of 0.30 or greater. Explanations for the low CF likely are:


– grid operator ERCOT requires significant curtailment of wind power to stabilize the grid. 

– vendors, developers and financiers of wind power, eager to cash in on subsidies before deadlines, installed some wind turbine facilities before adequate transmission capacity was installed to transmit their wind power to urban areas.


Much of the gas-fired capacity consists of CCGTs that are owned by IPPs which sell their power to utilities under PPAs. That capacity is not utility-owned and therefore not available for cycling to accommodate the more than 10,000 MW capacity of wind power. Instead, utilities are attempting to use coal plants for cycling for which they were not designed. The results have been significantly increased pollution and CO2 emissions.


Unlike PSCO, ERCOT requires reporting of fuel consumption by fuel type and power generation by technology type, including wind power, every 15 minutes. The 2007, 2008, 2009 data shows rising amplitude and frequency of cycling operations as wind penetration increased. In 2009, the same coal plants were cycled up to 300 MW/cycle about 1,307 times (up from 779 in 2007) and more than 1,000 MW/cycle about 284 times (up from 63 in 2007) from one 15-minute period to the next. The only change? Increased wind power penetration.


On Page 69:  The ERCOT cycling of plants to accommodate wind power produced results similar to the PSCO system; increased cycling due to wind power resulted in significantly more SOX and NOX emissions than if wind power had been absent. CO2 emission reductions due to wind power are minimal at best.  


Remedy for Colorado and Texas Cycling Problems


A way out is for PSCO and ERCOT is to retire older coal plants that have efficiencies of about 30% and emit about 2.15 lb of CO2/kWh and replace them with utility-owned, gas-fired CCGTs that have efficiencies of up to 60% and emit about 0.67 lb of CO2/kWh. The CCGTs have short installation periods and capital costs of about 1,250/kW. 


If wind were entirely absent, this measure would reduce the most CO2/kWh at the least $/kWh and would produce power at the least $/kWh. 


If some of the new units were cycled to accommodate wind power, their Btu, NOX and CO2 per kWh would increase, mostly offsetting the CO2/kWh reduction due to wind power, as shown above.


In addition their operation as cyclers would incur an additional owning cost, because their CFs would be about 0.70, instead of about 0.85 – 0.90 as base-loaded units, as shown above.






Paul O's picture
Paul O on Mar 27, 2011

You should take a look at wilem’s profile before making conclusions about him.

Atomik Rabbit's picture
Atomik Rabbit on Oct 2, 2011

“Hatchet Man”? I would say more like an “Occam’s Razor Man”.

Now show us, with equal specificity, the great American wind power success stories (non-subsidized).

Willem Post's picture
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