In a number of earlier articles we looked at onshore wind because it is currently the lowest cost method of generating renewable electricity.

The installed onshore wind capacity (nameplate) in Europe at the start of 2015 was 121 GW. By comparison the offshore wind capacity (nameplate) by comparison was 8 GW. (Both figures from EWEA).

For recap – “nameplate” means what a wind turbine will produce at full capacity. A typical onshore wind farm in Europe will produce something like 16-30% actual output over the course of the year. If you pick some great locations in Oklahoma, you might get over 40%. It all depends on the consistency and speed of the wind. The actual output as a percentage of the nameplate capacity is usually given the term “capacity factor”. This isn’t some big disadvantage of wind – ‘it “only” produces 30% of its supposed capacity‘ – on the contrary, it’s just terminology. But it is important to check what value you are seeing in press releases and articles – so when you see that Europe has 121 GW of onshore wind installed, it usually means “nameplate”. And so the actual production of electricity, depending on location, will be something like 25-50 GW averaged over the year. End of recap..

There are three big advantages of offshore wind. And these are the reasons why a lot of money is being poured into offshore wind in Europe:

  • the intermittancy is lower – the wind blows more consistently
  • the capacity factor is higher – you get more out of your turbine, because the offshore wind speed is higher
  • they aren’t parked 300m from the houses of voters

In the last article XIV – Minimized Cost of 99.9% Renewable Study we saw an interesting point from one study – when storage costs were high (actually quite low, but higher than a “possible” super-low rental cost of storage from future owners of electric cars) the lowest cost method of building out the PJM network (eastern US) included a large portion of offshore wind.

This is the key to understanding the first major appeal of offshore. Intermittancy has a cost – something we will come back to again – that is a little difficult to quantify. You can smooth out the peaks and troughs by installing wind farms over a wide area, but you can’t eliminate the fact that at certain times in a given 10-year period there will be almost no wind for a week. Of course, it depends on the region, but so far even potential “super-grids” have a week’s down time (see XII – Windpower as Baseload and SuperGrids and also VIII – Transmission Costs And Outsourcing Renewable Generation)

Offshore gives you more consistent electricity production and less intermittancy.

The second point – more electricity on average from a given nameplate turbine – only helps when we consider the actual cost of different wind installations. Let’s say we put 1 GW of wind turbines onto land and these get a capacity factor of 25% – we get, on average, 250 MW. That is, across the year we get 2,190 GWh (0.25GW x 8760). Now we put 1 GW of nameplate offshore wind turbines into coastal water and we get a capacity factor of 40% on average – that is, 400 MW. So across the year we get 3,504 GWh (0.4 x 8760). This increased capacity factor only helps if the cost of installing the 1 GW of turbines offshore is less than 60% more expensive. Unfortunately, this is not the case (at the moment).

The third point is of great interest in Europe. Germany, Spain, the UK and Ireland have been installing a lot of onshore wind turbines. These are highly populated countries. For a later article, producing say 50% of each of these country’s electricity requires a lot of land area. Of course, the footprint on the actual land is quite small, but each turbine has to be some distance from every other turbine. This means that producing 15 GW of electricity from wind in the UK (about half of the average) would take up a lot of land area. The problem is more acute in Germany with a lower capacity factor.

So, those are the upsides. Now let’s look at the price tag. “If you have to ask, you can’t afford it..”

In an earlier article – IX – Onshore Wind Costs – we looked at the capex cost of onshore wind and (by the time we get into the comments) we find a current capital cost of about €1M per 1MW of (nameplate) capacity. There are lots of different numbers cited, but let’s use that for now. For people more familiar with the greenback, this is about US$1.2M per 1MW.

EWEA gives a current price tag for capex cost of offshore of €2.8 – €4.0M per 1MW of (nameplate) capacity. A larger proportion of the capital cost of offshore is the installation.

Remember that we have to factor in the “capacity factor”. So the capital cost of offshore is not 3-4x the onshore cost. If we calculate the cost based on the actual production of electricity then onshore costs (capex) something like €4M per 1MW of output and offshore costs (capex) something like €7-8M per 1MW – roughly double.

Now, we can be relatively sure of capital costs because there are enough datapoints and current installations. Governments publish figures when they are paying. Suppliers give out indicative pricing. Customers give out data on contracts.

But there are big questions about maintenance costs and, unlike onshore wind with a lot of data, this is still a little shrouded in mystery. I’ve consulted a lot of sources but it seems that, with only 9GW of offshore wind constructed in Europe – and much of this very recent – there is not enough public data to confirm any estimates.

One point only is clear (as you might expect) it is “quite a bit more” than the maintenance costs of onshore wind. The marine environment impacting on the equipment combined with the hazards of getting maintenance people out on the ocean.

So far it seems that offshore has some maintenance issues that are hard to cost up. It’s an industry still in its infancy.

Of course, to get more funding, many confident predictions are made: “Offshore wind will be cheaper than gas plants by 2020.

Without confident predictions, maybe no one will fund the next 5 years of development. I don’t want to delve any deeper into spruiking. Let’s just accept that most of what passes for discussion in the general media, repeated on many blogs, is simply press releases from governments, lobby groups and big companies, mostly repeated without any fact checking.

It’s quite possible that offshore wind will be much lower in 2020 than it is today. There are a lot of installation issues that might be improved with the combination of volume of installations, time on the job and engineering improvements. It’s also quite possible that offshore wind won’t be a lot lower in 2020 than it is today. (See points made in Renewable Energy I).

Here is IRENA for just 2 years:

From IRENA 2012

From IRENA 2012

And UKERC Offshore costs from a 2012 document:

From UKERC 2013

From UKERC 2012

And another from a different UKERC document, attempting to learn from experience, with reference to wind power cost projections vs how the world actually turned out:

In the short-term costs may rise before they can fall. Cost reductions from learning can be overwhelmed in the short-term by supply chain bottlenecks, build delays and ‘teething trouble’, for example lower than expected reliability at first. There is historical precedent for technologies deployed in the power sector to demonstrate cost increases during early commercialisation before supply chains and learning from experience are firmly established


From UKERC 2013

These graphs are only presented as a reminder that predictions don’t always come true. Engineering problems are hard and optimism is easy.

I’m sure offshore wind costs will come down in the long run, but as Keynes usefully reminded us, in the long run we are all dead. So “the long run” is not so useful. Whether offshore costs will come down to onshore costs in a reasonable time frame, and whether – in this time frame – they will further come down to the cost of gas turbine electricity production is open to question. Time will tell.

I’m generally an optimist. The glass is half full. Probably it’s almost full. And lots of people don’t have much, so my glass is anyway pretty amazing. It’s only the weight of blog world articles and media (lobby groups press releases) articles on this subject that compels me to remind readers that confident predictions of the future may not be correct.

Lots of sources quote LCOE (levelized cost of electricity) – this “adds” capital cost, factored by the cost of capital (interest rates), to maintenance costs and energy costs (when we consider conventional power stations with fuel costs). As explained in previous articles, this LCOE is not so useful (i.e., it’s misleading) when we consider intermittent renewables vs dispatchable conventional electricity.

As a rule of thumb consider offshore capex wind costs to be “about double” onshore wind costs, and offshore maintenance costs to be somewhat unknown, but definitely higher than onshore costs.

These rules of thumb are as much as I have been able to establish so far.


Wind in Power 2014 European Statistics, published February 2015 by European Wind Energy Association (EWEA)

Renewable Energy Technologies: Cost Analysis Series, Volume 1: Power Sector, Issue 5/5, Wind Power, IRENA (International Renewable Energy Agency), June 2012

Presenting the Future: An assessment of future costs estimation methodologies in the electricity generation sector, UKERC (2013)

UKERC Technology and Policy Assessment, Cost Methodologies Project: Offshore Wind Case Study, UKERC (2012)

Budischak et al (2013) is a very interesting paper (and free). Here is the question they pose:

What would the electric system look like if based primarily on renewable energy sources whose output varies with weather and sunlight? Today’s electric system strives to meet three requirements: very high reliability, low cost, and, increasingly since the 1970s, reduced environmental impacts. Due to the design constraints of both climate mitigation and fossil fuel depletion, the possibility of an electric system based primarily on renewable energy is drawing increased attention from analysts.

Several studies (reviewed below) have shown that the solar resource, and the wind resource, are each alone sufficient to power all humankind’s energy needs. Renewable energy will not be limited by resources; on the contrary, the below-cited resource studies show that a shift to renewable power will increase the energy available to humanity.

But how reliable, and how costly, will be an electric system reliant on renewable energy? The common view is that a high fraction of renewable power generation would be costly, and would either often leave us in the dark or would require massive electrical storage.

Good question.

We do not find the answers to the questions posed above in the prior literature. Several studies have shown that global energy demand, roughly 12.5 TW increasing to 17 TW in 2030, can be met with just 2.5% of accessible wind and solar resources, using current technologies [refs below]. Specifically, Delucci and Jacobson pick one mix of eight renewable generation technologies, increased transmission, and storage in grid integrated vehicles (GIV), and show this one mix is sufficient to provide world electricity and fuels. However, these global studies do not assess the ability of variable generation to meet real hourly demand within a single transmission region, nor do they calculate the lowest cost mix of technologies.

Emphasis added.

[Refs: M.A. Delucchi, M.Z. Jacobson, Energy Policy, Dec. 2010;    M.Z. Jacobson, M.A. Delucchi, Energy Policy, Dec. 2010;    L. Brown, Plan B 4.0: Mobilizing to Save Civilization, Earth Policy Institute, 2009]

This is also what I have found – I’ve read a number of “there’s no barrier to doing this” papers including Delucchi & Jacobson – so I was glad to find this paper. (As an aside, I question some points and assumptions in this paper, but that’s less important and brief comments on those points towards the end).

The key is investigating time series based on real demand for a region and real supply based on the actual wind and sun available.

Before we look at what they did and what they found, here are some comments that are relevant for some of our recent discussions:

In a real grid, we must satisfy varying load, and with high-penetration renewables, charging and discharging storage will at times be limited by power limits not just by stored energy. More typical studies combining wind and solar do not seek any economic analysis and/or do not look at hourly match of generation to load..

Hart and Jacobson determined the least cost mix for California of wind, solar, geothermal and hydro generation. Because their mix includes dispatchable hydro, pumped hydro, geothermal, and solar thermal with storage, their variable generation (wind and photovoltaic solar) never goes above 60% of generation. Because of these existing dispatchable resources, California poses a less challenging problem than most areas elsewhere, most or all practical renewable energy sources are variable generation, and dedicated storage must be purchased for leveling power output. We cannot draw general conclusions from the California case’s results..

The ability to reliably meet load will still be required of systems in the future, despite the variability inherent in most renewable resources. However, a review of existing literature does not find a satisfactory analysis of how to do this with variable generation, nor on a regional grid-operator scale, nor at the least cost. We need to solve for all three.

What does the paper do?

  • Use the demand load from PJM (East Coast grid operator) for 4 years as a basis for assessing the cost-minimized solution – with the average load being 31.5 GW
  • Assign a cost (unsubsidized) to each type of renewable resource: onshore wind, offshore wind, solar based on 2008 costs and forecasts for 2030 costs (roughly 50% of 2008 capex costs with similar O&M costs)
  • Assign a cost to 3 different storage types: centralized hydrogen, centralized batteries, and grid integrated vehicles (GIV)
  • And then run through nearly 2 billion or so combinations to first ensure demand is met, then secondly calculate the cost of each combination
From Budischak et al 2013

From Budischak et al 2013

Figure 1

An most important note for me, something we will review in future articles, rather than here, is the very low cost assigned to storage using vehicle batteries – at $32/kWh, whereas centralized storage is $318/kWh. It’s clear, as we will see, that storage costs skew the analysis strongly.

Here was their lowest cost solution for 30%, 90% and 99.9% renewables. The results are probably not so surprising to people who’ve followed the series so far. Energy Produced GWa is basically the average power over the year (so 8760 GWh, which is a constant 1GW all year = 1 GWa):

From Budischak et al 2013

From Budischak et al 2013

Figure 2

So we can see that the lowest cost method of matching demand is to produce almost 3 times the required demand. That is, the energy produced across the year averages at 91.3 GW (and appears to have peaks around 200GW). This is because storage costs so much – and because supply is intermittent. Here is the time series – click to expand:

From Budischak et al 2013

From Budischak et al 2013

Figure 3 – Click to Expand

We see that the energy in storage (middle row) is pulled down in summer, which the paper explains as due to less supply in summer (generally less wind).

Here is a challenging week in detail, the top graph shows the gaps that need to be filled in with storage, the bottom graphs with the gaps filled by storage and also how much supply is “spilled“:

From Budischak et al 2013

From Budischak et al 2013

Figure 4 – Click to Expand

Here is the mix of generation and storage for each of the 30%, 90%, 99.9% each under the two cost assumptions of 2008 and 2030:

From Budischak et al 2013

From Budischak et al 2013

Figure 5 – Click to Expand

Looking at the 99.9% cases we see that the projected solar PV cost in 2030 means it has a bigger share compared with wind but that wind is still the dominant power source by a long way. (We will investigate offshore wind costs and reliability in a future article).


The paper assesses that generating 30% of power from renewables today is already cheaper than conventional generation, and producing 90% in 2030 will be cheaper than conventional generation, with 99.9% at parity.

The key point I would like to draw readers attention to, is that unlike conventional generation, the higher the penetration of renewables the more expensive the solution (because the intermittency is then a bigger problem and so requires a more costly solution).

I’m not clear how they get to the result of renewables already being cheaper than conventional (for a 30% penetration). Their wind power cost from 2008 is roughly double what we found from a variety of sources (see IX – Onshore Wind Costs & XI – Cost of Gas Plants vs Wind Farms) and we found – depending on the gas price and the discount rate – that wind at that price was generally somewhat more expensive than gas. Using current US gas prices this is definitely the case. The authors comment that there are significant subsidies for conventional generation – I have not dug into that as yet.

The cost of storage seems low. If we take instead their cost of centralized storage – $318/kWh – and look at the lowest-cost solution to meet demand we find quite a different result. First, there is a lot less storage – 360 vs 891 GWh. That’s because it’s so pricey.

Second, although the final cost per kWh of energy is not given, we can see that whereas in the GIV storage case we build 16GW solar, 90GW offshore wind, 124GW inland wind = 230GW peak, with centralized storage we build 50, 129, 61 = 240GW peak and probably need the expensive offshore wind as a more reliable (less intermittent) source than onshore wind.

My basic calculation from his data is that the capital cost of the best case central storage solution is 45% more than the GIV storage solution. And more offshore wind will definitely require additional transmission cost (which was not included in the study).

I like their approach. What is clear is that finding the best cost solution depends heavily on the cost of storage, and the mix is radically different for different storage costs. Again, it is the intermittent nature of renewables for the region in question that shapes the result.

Questions on the Analysis

We simplify our grid model by assuming perfect transmission within PJM (sometimes called a “copper plate” assumption), and no transmission to adjacent grids. We also simplify by ignoring reserve requirements, within-hourly fluctuations and ramp rates; these would be easily covered with the amount of fast storage contemplated here. In addition, we assume no preloading of storage from fossil (based on forecasting) and no demand-side management. Adding transmission would raise the costs of the renewable systems calculated here, whereas using adjacent grids, demand management, and forecasting all would lower costs. We judge the latter factors substantially larger, and thus assert (without calculation) that the net effect of adding all these factors together would not raise the costs per kWh above those we calculate below.

Their analysis consumed a lot of computing resources. Adding transmission costs would add another level of complexity. However, I don’t agree with the conclusion that the transmission costs would be offset by adjacent grids, demand management and forecasting.

In brief:

  1. Adjacent grids have the exact same problem – the wind and solar are moving approximately in sync – meaning supply in adjacent regions is quite highly correlated; and hot and cold temperatures are likewise in sync so air-conditioning and heating demand is similar in adjacent regions – therefore another region will be drawing on their storage at the same times as the PJM region. Also, “using adjacent grids” means adding even longer transmission lines of very high capacity. That has a cost.
  2. “Demand management” is possibly a mythical creation to solve the problem of demand being at the “wrong time”. Apart from paying big industrials to turn off power during peak demand, which is already in play for most grid operators, it apparently equates to people not turning on the heating in the cold weather – or to people buying expensive storage. I will be looking for research with some data that puts “demand management” into some reality-based focus.
  3. Forecasting doesn’t exactly help, unless you have demand management. Better wind forecasting currently helps grid operators because it allows them to buy reserve (conventional generation) at the right time, making a more efficient use of conventional generation. I can’t see how it helps a mostly renewable scenario to be more cost-effective. Perhaps someone can explain to me what I am missing.

And I will dig into storage costs in a future article.


The paper is very good overall – their approach is the important aspect. There are a great many papers which all confidently state that there is no technical barrier to 100% renewables. This is true. But maybe two or three papers is enough.

If you add “enough” wind farms and “enough” solar and “enough” storage – along with “enough” transmission – you can make the grid work. But what is the cost and how exactly are you going to solve the problems? After the first few papers to consider this question, any subsequent ones that don’t actually cover the critical problem of electricity grids with intermittent renewables are basically a waste of time.

What is the critical problem? Given that storage is extremely expensive, and given the intermittent nature of renewables with the worst week of low sun and low wind in a given region – how do you actually make it work? Because yes, there is a barrier to making a 100% renewable network operate reliably. It’s not technical, as such, not if you have infinite money..

It should be crystal clear that if you need 500GW of average supply to run the US you can’t just build 500GW of “nameplate” renewable capacity. And you can’t just build 500GW / capacity factor of renewable capacity (e.g. if we required 500GW just from wind we would build something like 1.2-1.5TW due to the 30-40% capacity factor of wind) and just add “affordable storage”.

So, there is no technical barrier to powering the entire US from a renewable grid with lots of storage. Probably $50TR will be enough for the storage. Or forget the storage and just build 10x the nameplate of wind farms and have a transmission grid of 500GW around the entire country. Probably the 5TW of wind farms will only cost $5TR and the redundant transmission grid will only cost $20TR – so that’s only $25TR.

Hopefully, the point is clear. It’s a different story from dispatchable conventional generation. Adding up the possible total energy from wind and solar is step 1 and that’s been done multiple times. The critical item, missing from many papers, is to actually analyze the demand and supply options with respect to a time series and find out what is missing. And find some sensible mix of generation and storage (and transmission, although that was not analyzed in this paper) that matches supply and demand.

So this paper has a lot of merit.

It shows with their storage costs (which seem very low), that the lowest cost solution to building a 99.9% renewable network in one (reasonable sized) region is to build nearly 3 times the actual supply needed (this is not a “capacity factor” issue – see note 2).

In future articles we will look at storage costs, as I have questions about their costing. But the main points from this paper are more than enough for one article.

Articles in this Series

Renewable Energy I – Introduction

Renewables II – Solar and Free Lunches – Solar power

Renewables III – US Grid Operators’ Opinions – The grid operators’ concerns

Renewables IV – Wind, Forecast Horizon & Backups – Some more detail about wind power – what do we do when the wind goes on vacation

Renewables V – Grid Stability As Wind Power Penetration Increases

Renewables VI – Report says.. 100% Renewables by 2030 or 2050

Renewables VII – Feasibility and Reality – Geothermal example

Renewables VIII – Transmission Costs And Outsourcing Renewable Generation

Renewables IX – Onshore Wind Costs

Renewables X – Nationalism vs Inter-Nationalism

Renewables XI – Cost of Gas Plants vs Wind Farms

Renewables XII – Windpower as Baseload and SuperGrids

Renewables XIII – One of Wind’s Hidden Costs


Cost-minimized combinations of wind power, solar power and electrochemical storage, powering the grid up to 99.9% of the time, Cory Budischak, DeAnna Sewell, Heather Thomson, Leon Mach, Dana E. Veron & Willett Kempton, Journal of Power Sources (2013) – free paper


Note 1: Tables 1 & 2 of cost estimates with notes from Budischak et al 2013 – click to expand

Budischak 2013 table 1

Budischak 2013 table 2

Note 2: The 2-3 overbuilding is not the nameplate vs capacity factor question. Let me explain. Imagine we are only talking about wind. If we build 3GW of wind farms we might get 1GW of average output across a year. This is a 33% capacity factor. The % depends on the wind turbines and where they are located.

Now if we need to get 1GW average across the year and meet demand 99.9% of the time, the lowest cost solution won’t be to build 3GW of nameplate (=1GW of average output) and add lots of storage, instead it will be to build 9GW of nameplate and some storage.

In earlier articles we looked at wind power, what it costs, what it does to the grid, and what to do when the wind is not blowing.

Now a frequent comment – which conceals more than it reveals – is: “the wind always blows somewhere”. This is true – if you have lots of wind farms that are geographically dispersed you do average out your peaks and troughs, and you do also reduce the % change hour by hour.

However, if you have 20% of your average power coming from wind, then on one given day it might be 60% of your requirements, yet the next day it might be 0.3%. This means that sometimes you are “winding back” your conventional generation, and sometimes you are “cranking up” your conventional generation – and much more in absolute terms than in a network of 98%+ conventional generation. The larger the penetration of wind energy the more problems this causes.

The question has come up a few times without being answered – what is the impact on efficiency of conventional power generation?

It’s clear that the impact depends on the penetration of wind. Very recent analysis is hard to find.

First, here is an older NREL study from 2004:

It is important to understand that the key issue is not whether a system with a significant amount of wind capacity can be operated reliably, but rather to what extent the system operating costs are increased by the variability of the wind..

..Over the past two years, several investigations of these questions have been conducted by or on behalf of U.S. electric utilities. These studies addressed utility systems with different generating resource mixes and employed different analytical approaches. In aggregate, this work provides illuminating insights into the issue of wind’s impacts on overall electric system operating costs.

I extracted two useful examples from the NREL study:


PacifiCorp, a large utility in the northwestern United States, operates a system with a peak load of 8,300 MW that is expected to grow to 10,000 MW over the next decade. PacifiCorp recently completed an Integrated Resource Plan (IRP) that identified 1,400 MW (14%) of wind capacity over the next 10 years as part of the least-cost resource portfolio.

A number of studies were performed to estimate the cost of wind integration on its system. The costs were categorized as incremental reserve or imbalance costs. Incremental reserves included the cost associated with installation of additional operating reserves to maintain system reliability at higher levels of wind penetration, recognizing the incremental variability in system load imposed by the variability of wind plant output.

Imbalance costs captured the incremental operating costs associated with different amounts of wind energy compared to the case without any wind energy.

At wind penetration levels of 2,000 MW (20%) on the PacifiCorp system, the average integration costs were $5.50/MWh, consisting of an incremental reserve component of $2.50 and an imbalance cost of $3.00. The cost of additional regulating reserve was not considered. These costs are considered by PacifiCorp to be a reasonable approximation to the costs of integrating the wind capacity.

Great River Energy:

Great River Energy (GRE) is a Generation and Transmission electric cooperative serving parts of Minnesota and northeast Wisconsin. It is primarily a thermal system in the Mid- Continent Area Power Pool (MAPP) region with a summer peak load in excess of 2300 MW, growing at 3%-4% per year.. As part of its planning process to meet this objective, GRE performed a study with Electrotek that examined adding 500 MW of wind in 100 MW increments between now and 2015. GRE operates with a fixed fleet of generation and uses a static scheduling process, so it did not decompose the problem into the three time periods commonly used in the analysis of ancillary-service costs in larger utilities. It also looked at providing the ancillary services required from its own resources, including a 600-MW combined-cycle unit, which was subsequently cancelled. GRE found ancillary- service costs of $3.19/MWh at 4.3% penetration and $4.53/MWh at 16.6% penetration. It is likely that the costs would have been higher without the combined-cycle unit and self-providing the ancillary services without economical intermediate resources.

It appears that these studies are based on nameplate values (I didn’t find an explicit statement but the wording implies it and later references to the data agree). That’s a pretty big difference, because in GRE’s case it means that the “16.6%” would actually be something like “5-6% of average electricity production from wind”. The 16.6% would be when the wind farms were operating at their maximum.

It seems like there should be many more studies, especially given the increase in wind penetration of electricity networks in Germany, UK and Ireland. However, many references work their way back to the same papers. For example, Overview of wind power intermittency impacts on power systems, MH Albadi & EF El-Saadany, Electric Power Systems Research (2010) says:

Smith et al. reported that the existing case studies have explored wind capacity penetrations of up to 20–30% of system peak and have found that the primary considerations are economic, not physical [9].

The reference [9] is Utility Wind Integration and Operating Impact State of the Art, J Smith et al, IEEE Transactions on Power Systems (2007), which states:

On the cost side, at wind penetrations of up to 20% of system peak demand, it has been found that system operating cost increases arising from wind variability and uncertainty amounted to about 10% or less of the wholesale value of the wind energy [2]. This finding will need to be reexamined as the results of higher-wind-penetration studies—in the range of 25% to 30% of peak balancing-area load—become available. However, achieving such penetrations is likely to require one or two decades.

The reference [2] here is Wind plant integration, E DeMeo et al, IEEE Power Energy Mag (2005) which has the same data as the NREL study, not surprising as two of the authors are the same.

Albadi & EF El-Saadany 2010 compile some data, note the reference again is to peak penetration:

From Albadi & El-Saadany 2010

From Albadi & El-Saadany 2010

Figure 1

We can see a big range. For example:

  • the UK costs at the top of the graph, with peak penetration of 20-40% (=average penetration of 6-12%) having costs of around $5/MWh, or 0.5c/kWh
  • the Finland costs at the bottom right with 32-65% (=average of 10-20%, but I’m unsure of their capacity factor) having costs of around $1/MWh, or 0.1c/kWh

The study that produced these particular values (and some others) is H. Holttinen et al 2009. This is from 2009 and what appears to be the same data is in a paper in Wind Energy (2011). However, the studies that produced their data:  Finland and Nordic – PhD by Holtinnen 2004; Sweden – paper by U Axelsson et al from 2005; Ireland – 2004 study; UK – paper by Strbac et al from 2007; Germany – Dena Grid study from 2005; Minnesota – paper for Minnesota Public Utilities Commission from 2006; and California – paper by Porter et al from 2007.

Holtinnen et al 2011 summary:

From the cost estimates presented in the investigated studies it follows that at wind penetrations of up to 20 % of gross demand (energy), system operating cost increases arising from wind variability and uncertainty amounted to about 1–4 €/MWh of wind power produced (Fig. 5). This is 10 % or less of the wholesale value of the wind energy. The actual impact of adding wind generation in different balancing areas can vary depending on local factors. Important factors identified to reduce integration costs are aggregating wind plant output over large geographical regions, larger balancing areas, and utilizing shorter gate closure times with accurate forecast systems and sub-hourly schedule changes.

An important point, often missed by pundits looking at Denmark:

The interconnection capacity to neighbouring systems is often significant. For the balancing costs, it is then essential to note in the study setup whether the interconnection capacity can be used for balancing purposes or not. A general conclusion is that if interconnection capacity is allowed to be used also for balancing purposes, then the balancing costs are lower compared to the case where they are not allowed to be used.

The two points for Greennet Germany at the same wind penetration level reflect that balancing costs increase when neighbouring countries get more wind (the same applies for Greennet Denmark). For a small part of an interconnected system, a wind integration study stating a high penetration level can also be misleading if the wind penetration in neighbouring areas is low and interconnection capacity plays a major part in integration.

They have many interesting points in their paper:

In Denmark the TSO has estimated the impacts of increasing the wind penetration level from 20 % to 50 % (of gross demand) and concluded that further large scale integration of wind power calls for exploiting both, domestic flexibility and international power markets with measures on the market side, production side, transmission side and demand side ([19] and [20]).

This kind of implies there are big issues, but the documentation is locked away in conference proceedings. Surely some published papers have come out of this important question so I will continue to dig..

A digression, for people concerned that wind power research and costing ignores transmission costs, another (counter-) example:

Transmission cost is the extra cost in the transmission system when wind power is integrated. Either all extra costs are allocated to wind power, or only part of the extra costs are allocated to wind power – grid reinforcements and new transmission lines often benefit also other consumers or producers and can be used for many purposes, such as increase of reliability and/or increased trading. The cost of grid reinforcements due to wind power is therefore very dependent on where the wind power plants are located relative to load and on the grid infrastructure, and one must expect numbers to vary from country to country.

Grid reinforcement costs are by nature dependent on the existing grid. The costs vary with time and are dependent on when the generator is connected. After building some lines, often several generators can be connected before new reinforcement needs occur. After a certain time, new lines, substations or something else is needed.

The grid reinforcement costs are not continuous; there can be single very high cost reinforcements. Using higher voltages generally results in lower costs per MW transported but this also means that there are even higher increments of capacity and grid costs. The same wind power plant, connected at different times, may therefore lead to different grid reinforcement costs. For transmission planning, the most cost effective solution in cases that require considerable grid reinforcements would be to build the transmission network for the final planned amount of wind power in the network – instead of having to upgrade transmission lines in several phases.


It seems like everyone studying wind power believes the additional costs incurred as a result of having to ramp up and down conventional power systems are relatively low – typically less than 0.5c/KWh for 20% penetration. Likewise, everyone agrees that there is a real cost to be paid. The cost for 50% penetration is unclear, even if it is feasible.

There doesn’t seem to be any real world data for high wind penetrations, which is not surprising as Germany, a wind power leader, has only about 10% of (annual average) power coming from wind, and Denmark is effectively part of a much larger grid (by virtue of interconnection).

Whether or not the current estimates factor in the lifetime impact on power stations (due to lots more heating and cooling causing more stressing of various parts of the system) is something that might only be found by the real world experiment of doing it for a couple of decades.

[Note that many statements and press releases on the subject of wind do not clarify whether they are talking about “peak”, i.e., nameplate, or “average”, i.e. the nameplate x capacity factor – it is essential to clarify this before putting any weight on the claim].

Articles in this Series

Renewable Energy I – Introduction

Renewables II – Solar and Free Lunches – Solar power

Renewables III – US Grid Operators’ Opinions – The grid operators’ concerns

Renewables IV – Wind, Forecast Horizon & Backups – Some more detail about wind power – what do we do when the wind goes on vacation

Renewables V – Grid Stability As Wind Power Penetration Increases

Renewables VI – Report says.. 100% Renewables by 2030 or 2050

Renewables VII – Feasibility and Reality – Geothermal example

Renewables VIII – Transmission Costs And Outsourcing Renewable Generation

Renewables IX – Onshore Wind Costs

Renewables X – Nationalism vs Inter-Nationalism

Renewables XI – Cost of Gas Plants vs Wind Farms

Renewables XII – Windpower as Baseload and SuperGrids


Wind Power Impacts on Electric Power System Operating Costs: Summary and Perspective on Work to Date, JC Smith, EA DeMeo, B Parsons & M Milligan, NREL (2004)

Overview of wind power intermittency impacts on power systems, MH Albadi & EF El-Saadany, Electric Power Systems Research (2010)

Design and operation of power systems with large amounts of wind power, H Holttinen et al, VTT (2009) & Impacts of large amounts of wind power on design and operation of power systems, results of IEA collaboration, H Holttinen et al, Wind Energy (2011)


In Part I and IV – Wind, Forecast Horizon & Backups we looked at a few basics, including capacity credit which is basically how much “credit” the grid operator gives you for being there. If you are a 1GW coal-fired power station you probably get around 850MW – 900MW capacity credit. This reflects the availability that your power generation offers. The grid operator needs to ensure the region or country can meet the demand in any given second, minute, hour, day, week, month and year.

And so the grid operator’s calculation is a statistical one – given a “fleet” (always a strange name to me for such immobile units) of generating units how can we be sure that we can meet demand in every minute of the year? Conventional generation (gas, coal, nuclear) is mostly “dispatchable” – which means that, apart from unexpected outages, you can choose to run the gas plant or nuclear power station when you want.

Wind power, on the other hand, is not dispatchable. And it turns out that its capacity credit, as a proportion of actual capacity, reduces significantly as its penetration into the network increases. Another way of saying it is that wind is less reliable than conventional generation at any given point in time and this problem gets worse the more wind power you have available.

However, this doesn’t present some insuperable obstacle to using wind. What it means at the moment in various countries is that you can use windpower when the wind is blowing, and when it’s not blowing (or not much) you can crank up a gas plant. As wind power penetration grows in a given network the variability of this ever larger power source must result in less efficiency of the conventional units operating at part load or in reserve. Everyone agrees on this point. However, in this series so far we have not reviewed any actual papers or data on the loss of efficiency – something to look forward to.

Baseload Power

On a different point – the focus of this article – the intermittency of windpower raises an important question, especially as it is the cheapest source of renewable energy (given that hydro is “tapped out” in most developed countries).

Is it possible to generate base load power from wind?

If not, then there is clearly a limit to the growth of wind power. (We have already covered some real problems of high wind power penetration in V – Grid Stability As Wind Power Penetration Increases – those problems haven’t gone away). This is related to the question of the maximum reduction in GHG emissions from electricity generation while “keeping the lights on”.

Generally we can think of increasing wind power in a region as creating a benefit and a problem:

  • the benefit – more wind power usually means more geographical dispersion which averages out peaks and troughs (see IV – Wind, Forecast Horizon & Backups)
  • the problem – more wind power means peaks and troughs cause more problems for the grid (a 100MW unforecast fluctuation over a few hours is easily dealt with in most countries, but a 5GW unforecast fluctuation is more problematic)

So.. on with this article..

In Czisch & Ernst (2001), the authors consider a massive area wind power network. I don’t believe this paper is a complete answer because some questions are unanswered, but the idea is instructive.

As they state:

Europe currently has by far the highest installed wind power capacity of all regions in the world. However, this is not due to Europe being the best possible place to build wind power, but rather to a favourable political climate

It is a slightly different take on the question I asked in X – Nationalism vs Inter-Nationalism – why is Germany building windfarms in Germany instead of places with lots of wind?

In the graph below “Full Load Hours/Year” is basically a way of showing capacity factor (not to be confused with capacity credit). Capacity factor is average output/nameplate and depends how much wind you get – across the UK capacity factor is just over 30%, in Germany it is around 18%, in Oklahoma, maybe 41%.

In this genre of papers it’s common to dispense with the crazy idea of percentages – who can understand them? Instead of percentages, let’s use the much more intuitive idea of the output expressed as if the wind farm ran at full load for x number of hours in the year. So 2100 full load hours = the old school 24% (2100/8760)..

Anyway, via color coding (which at least follows a familiar pattern), we see why Ireland and the north of the UK has a windfarm advantage, along with European and African coastal regions:

From Czisch & Ernst 2001

Figure 1

The data above is based on wind speeds taken from reanalysis data (from ECMWF). “Reanalysis” is basically a blend of data and models filling in the blanks where data doesn’t exist. (See Water Vapor Trends under the sub-heading “Filling in the Blanks”).

Then they look at the correlation between different sites, based on actual measurements.

For people new to wind power, a low correlation is good. A high correlation is bad. Why? If you have 1000x 3MW wind turbines and the correlation of output power between the turbines is high then they will be producing 3GW some of the time, 1.5GW some of the time, and 0GW some of the time – their output power rises and falls in unison. If the correlation is low then they will be producing (for example) 1GW nearly all of the time – this is clearly much better – as one turbine slows down, another speeds up.

Low correlation implies sustained output. High correlation implies big peaks and troughs.

As we might expect – as the turbines get further apart their output power correlation reduces = good. For example, the wind in London is well correlated with the wind in Reading, England (60km apart), but not well correlated with the wind in Moscow (2,500 km apart).

And for any given geographical separation the correlation is higher (=bad) as we consider longer time periods. This is also expected. There might be considerable minute to minute fluctuation between two sites due to the turbulent nature of wind, but the average across 12 hours will be more correlated because the overall weather patterns cover bigger areas:


From Czisch & Ernst 2001

From Czisch & Ernst 2001

Figure 2

Super Grids

Now let’s look at longer time periods and longer distances (I don’t understand the dots in this graph):

From Czisch & Ernst 2001

From Czisch & Ernst 2001

Figure 3

The paper goes on to select the best regions, place large hypothetical wind farms in those regions and calculate the wind farm output:

The potentials described in the above section altogether make a capacity of nearly 950 GW and close to 2800 TWh annual electricity production. This is more than the total demand of the EU countries plus Norway which was 2100 TWh in 1997. The average production exceeds 2900 full load hours.

Electricity consumption in the EU has increased a fair bit since 1997 – EU consumption in 2014 was about 2800 TWh (which for reference is about 320GW continuously) – I’m not sure if this represents economic growth, adding countries to the EU or both.

But the regions that they propose have more than sufficient wind to meet much higher output. The population density is low and wind potential is high in the regions they select. Unlike the places where most European wind power is being built at the moment (with high population density and low wind speeds).

The key lines in the graph are the red line = demand and the black line = supply for one scenario:

From Czisch & Ernst 2001

From Czisch & Ernst 2001

Figure 4


To me their paper doesn’t quite complete the picture. They provide some more insights, including transmission and storage requirements, and propose providing baseload power but not peak power for the whole of the EU. Given the potential wind power in the regions they select it’s not clear what limits actually exist.

The questions seem straightforward:

  1. For a given scenario (nameplate per region) produce the usual graph of hourly output, not as a time-series, but in declining output order (e.g. fig 6 below), so we can see for how many hours the output drops below key values
  2. Calculate the actual nameplate capacity needed in the various production regions to ensure “Loss of Load Probability” (LOLP) below the standard 9 years per century (or some other metric)

Armed with this data we would be able to see the number of wind turbines required and the transmission requirements between each region. And what, if any, pumped hydro storage would be needed in addition. And what, if any, conventional backup generation would be needed.

In a scenario with wind power producing a large portion of EU energy any problems get amplified.

For example – and this is just my example – if we built a wind network to supply say 320GW it might be a nameplate capacity of 900GW (something like 450,000 wind turbines of 2MW). But if our analysis showed that individual regions at any given time would be supplying most of the load, the nameplate capacity of the whole system might need to be 3TW (1,500,000 wind turbines). If the system instead had gas power as a backup for say 10% of the time when the wind “super-system” dropped well below the demand, the fuel cost would be relatively low, but the construction cost would be very high for the power supplied – because we would have built 300GW of supply to run just 10% of the time.

Some of these ideas are taken up by other papers.

In Archer & Jacobson (2007) the authors look at the statistics of wind energy across 19 sites in the midwest of the USA:

In this study, benefits of interconnecting wind farms were evaluated for 19 sites, located in the Midwestern United States, with annual average wind speeds at 80 m above ground, the hub height of modern wind turbines, greater than 6.9 m/s (class 3 or greater). We found that an average of 33% and a maximum of 47% of yearly-averaged wind power from interconnected farms can be used as reliable, baseload electric power.

From Archer & Jacobson 2007

From Archer & Jacobson 2007

Figure 5

Unfortunately, their description of “reliable baseload power” indicates they are “having a laugh” – let’s hope they didn’t really mean it.

After noting the problem of intermittency of wind power they state:

On the other hand, because coal combustion can be controlled, coal energy is not considered intermittent and is often used as “baseload” energy. Nevertheless, because coal plants were shut down for scheduled maintenance 6.5% of the year and unscheduled maintenance or forced outage for another 6% of the year on average in the United States from 2000-2004, coal energy from a given plant is guaranteed only 87.5% of the year, with a typical range of 79-92% (NERC 2005, Giebel 2000).

And in their wind power analysis they are then content when their hypothetical system meets this 79% threshold, given that is the (minimum) benchmark for one coal-fired power station. Hopefully readers of this series can see the problem with this threshold. Grid operators provide baseload power by combining multiple units of dispatchable power. No one is under the illusion that one coal-fired power station is nirvana. This was probably true even 100 years ago in England. Grid operators provide some statistical inevitability of keeping the lights on by using more than one power station.

The real question we want to answer is whether combining ever more distant wind farms can actually provide baseload power to meet grid operator requirements and therefore replace a network of conventional power stations. And how many turbines in each of how many locations, what transmission capacity, and so on.

The key curves are given below, with the blue curve being the key one representing the combination of 19 sites, with output power placed in decreasing order. As we can see, moving from 1 to 7 to 19 sites increases our minimum output:

From Archer & Jacobson 2007

From Archer & Jacobson 2007

Figure 6

It’s a useful graph. In this example we would put up 19 wind farms in a wide area, with the furthest extremes separated by almost 900 km. And for 90% of the year we would get more than 13% of the nameplate output. And for 95% of the year we would get more than 10% of the output.

So does that mean we should build nameplate capacity at 10x our required demand, and provide gas plants to match demand for the 2½ weeks a year that the wind farms can’t keep up?

It’s half an answer, like the earlier paper we reviewed. At least it gives us the graph we need to see (figure 6, their figure 3) for this specific geographical distribution.


Baseload electric power is not an optional extra – unless the population decides to vote for it, which seems unlikely. It does seem possible that the right combination of wind farms across a super-grid might be a solution for most of the EU’s energy needs. It needs to be evaluated in more detail and costed.

If the statistics of wind power variability make this solution a possible contender, then the costs will be a minimum of $1-5TN plus transmission costs. Perhaps $2-10TN. Perhaps more. I’m just trying to get a broad idea of the cost.

For the EU this is not such a large amount. Germany has already spent more than €40BN just to get 10% of electricity from wind power.

If the EU is serious about decarbonizing electricity generation then putting up wind turbines in Germany and central Europe – instead of investigating a European super-grid capitalizing on the best regions – is possibly a monumental failure of policy (maybe this subject has already been discussed and discarded).

Articles in this Series

Renewable Energy I – Introduction

Renewables II – Solar and Free Lunches – Solar power

Renewables III – US Grid Operators’ Opinions – The grid operators’ concerns

Renewables IV – Wind, Forecast Horizon & Backups – Some more detail about wind power – what do we do when the wind goes on vacation

Renewables V – Grid Stability As Wind Power Penetration Increases

Renewables VI – Report says.. 100% Renewables by 2030 or 2050

Renewables VII – Feasibility and Reality – Geothermal example

Renewables VIII – Transmission Costs And Outsourcing Renewable Generation

Renewables IX – Onshore Wind Costs

Renewables X – Nationalism vs Inter-Nationalism

Renewables XI – Cost of Gas Plants vs Wind Farms


High wind power penetration by the systematic use of smoothing effects within huge catchment areas shown in a European example, Czisch & Ernst, Windpower (AWEA), 2001

Supplying baseload power and reducing transmission requirements by interconnecting wind farms, CL Archer & MZ Jacobson, Journal of Applied Meteorology and Climatology (2007)

In IX – Onshore Wind Costs we looked at the capital and O&M costs of building onshore wind power. We stayed away from converting the numbers into “Levelized Cost of Energy”, or LCOE, because it obscures too much – instead we just tried to get a rough idea of the costs.

The data presented in the article was a little dated and one of our commenters pointed to more recent values (corrected my information) for capital cost which makes it very simple:

Capital cost of onshore wind farms = €1M per MW nameplate. (The article itself had €1.2M per MW).

For reference, right now €1 = US$1.13, but at times during the last 10 years the rate has been above $1.40.

What does it cost to build a gas plant? Once again I’ll use out-of-date values, this time because a great textbook from 2009 has some pretty good breakdowns. And as we’ll see, the capital cost is not so significant, it’s mostly about the fuel cost.

These days, combined cycle gas plants are the fashionable item to have. Their efficiency is very high and they are relatively quick to build – typically around 2 years.

Kehlhofer-2009-Net efficiency conventional

Figure 1 – From Kehlhofer et al 2009

The efficiency figures for the gas plant are output electrical energy at the high voltage transformer terminals / energy of input fuel.

Like onshore wind farms, combined-cycle gas plants are proven technology. You know they are going to work – in fact, many are built by EPCs (the costs we will look at are EPC costs) = “Engineering, Procurement & Construction” companies. You pay the money and the EPC gets the job done – a turnkey job. On commissioning they have to run the plant for x number of days or months at nameplate for the customer to sign off. Penalties and rewards apply. While I’m sure there are some sad stories out there, as in any industry – with competent management you will get a plant of a given efficiency, given operation costs and given construction costs.

Here are some costs, for combined-cycle and other conventional technologies. We will focus on the other technologies another time (for example, the nuclear data is not reliable because so few have been built recently):

Kehlhofer-2009-Capex Costs Conventional Plants

Figure 2

So the capital cost of the gas plant is about $0.6M per MW, versus something like $1.1M per MW for wind (at prevailing exchange rates). These are nameplate values. As we saw, the actual “capacity factor” of wind is dependent on where you plant it. Oklahoma might be 41%. Ireland might be 31%. Germany might be 18%.

On the other hand, gas plants can run almost as much as you want. For well-designed and operated plants we have these figures, where reliability gives you what you lose from unplanned problems, while availability gives you what you lose from unplanned and planned outages (these are necessary for upgrades & maintenance):


Figure 3

So let’s run with 90% availability for the gas plant.

Readers might wonder why some gas plants only run for 10% of the time – it’s not (usually) because they have been badly designed, it’s because those plants are designed as peaker plants, deliberately designed to run only when the spot price is high. You can’t store electricity, so at times of high demand and problems with general supply the spot price can be 10x the normal price (or much more). Some plants are designed to start up quickly, throw caution to the wind, grab the cash and turn off. They turn on a dime, so to speak.

And as we will see, the numbers don’t change that much if we chose 85% or even 80% availability. Of course, if you designed a combined-cycle gas plant to run as much as possible and you only achieved 80% availability year after year – you wouldn’t be doing a great job.

Let’s look at operations and maintenance costs. These conventional plant O&M costs have been broken up between “per MWh” costs and fixed annual costs. We saw with the wind farms that these two categories existed as well, but the numbers had all been converted into “per MWh” and we only had that to work with – a value around $14/MWh):

Kehlhofer-2009-Conventional O&M costs

Figure 4


Figure 5

Comparing Combined Cycle Gas with Wind

Most discussions about “costs” throw out a number and the average reader can’t break it apart. If you are in one of the cheerleading squads this is excellent. Just pick your favorite LCOE quoted without any analysis, reference points, or clarity and “prove” your point. Hurray for my side!! We’re winning!!

Here, I will attempt to make it as clear as I can without equations (other than 1+1=2 and 10/2=5) how the costs compare.

Smaller gas plants are less efficient and have higher costs bases, and we are really interested in getting large amounts of power out of the door, so we are going to use the costs of the 800MW plant as the basis for our calculation (scaled up a little).

Let’s think about a reference 1GW plant.

For wind farms this means we have to think about where the wind farms will be located. For now, let’s think about Europe, which seems to average 25% capacity – that is, if you have 4GW of nameplate wind farm capacity you can expect over one year to average 1GW. (But note we’re using US currency). At the end, we will look at the magic of Oklahoma and what that does for our simple sums.

For the gas plant we will assume our 90% availability and so we need to build 1.1 GW of nameplate.

Now, a little conversion factor is necessary, if you produce 1GW (=power) for 1 hour you produce 1GWh (=energy), which is 1000MWh (=energy in different units). If you average 1GW of output and run for one year you produce (rounded up) 8.8M of these MWh (=8760 x 1000).

So both our wind farms and our gas plant are producing 8.8M “MWh” per year.

That’s so we can compare them.

Running Costs


Combined-Cycle Gas

  • Fuel = $ lots & lots
  • O&M = fixed $10M + $2.50/MWh =  $1.10/MWh (i.e., $10M/8.8M MWh) + $2.50 = $3.60/MWh

The fuel is easy to calculate (we’ll come to that), but obviously the cost depends on the gas price which fluctuates a lot. Here is the European and US price, over 7 years to end-2014:

From IEA 2015

From IEA 2015

Figure 6

And the US price up to July 2015 (also in that strange British unit):

Source: IEA Henry Hub Prices

Source: IEA Henry Hub Prices

Figure 7

So we need a couple of reference points. We’ll pick $3, around the recent US price – and $10, the end-2014 European price.

Our favorite gas plant has an efficiency of 56.5% so we need to input 1.77 (=1/0.565) units of energy for every 1 unit we turn into electricity at the output transformer.

Energy data is wonderful. Usually in one report you can read gas production in billion cubic meters (volume, new school), later in trillion cubic feet (volume, old school), then in MBTUs (energy, old school), then in GJ (energy, new school), then in MWh (energy, not quite new school, but easy to convert from your consumer bill of kWh). Somewhere in the report the energy will also be quoted as MBoe (million barrels of oil equivalent – energy, very old school but also very contemporary). It’s all designed so you need to pay expensive consultants to explain the report to you.

In other news, Usain Bolt ran the 100m in a new stadium record of 61,336 furlongs per fortnight.

For simplicity, pretend 1 GJ (a billion joules – energy) = 1 MBTU (million British thermal unit). The correct value is 0.95 but forget that.

And 1 GJ (energy) = 278 kWh (energy) = 0.28 MWh (1W running for 278,000 hours = 1W running for 278,000 x 3600 seconds = 1GJ)

Sorry for all the numbers, but I think it’s helpful to show the paper trail, rather than just pull a rabbit out of a hat. For people interested, you can do the numbers yourself..

So – for each MWh output at the transformer, we need to put 6.4GJ (=1/(0.278 x 0.565) of gas energy into the inlet flange of the plant.

Roughly speaking, we see gas costs for our two reference prices (taking into account plant efficiency) of $19/MWh (6.4 x $3) and $64/MWh (6.4 x $10). What does this mean? Nothing changes for wind, but we can add up our running costs for the gas plant:


  • Fuel = $0 (nice)
  • O&M = $14/MWh

Combined-Cycle Gas

  • Fuel = $ 19/Mhr & $64/MWh
  • O&M = $3.60/MWh
  • Total = $23/MWh & $68/MWh

Capital Cost

Now let’s look at capital cost. The gas plant can’t be built overnight, it takes a couple of years so converting the “overnight cost” to the real cost including interest adds about 10%. We’ll do the same to the wind farm, which probably takes longer to build out, but also it can start producing from day 90 instead of waiting until the end of how ever many years the wind project takes:

Wind – 4GW nameplate

  • Cost = €4BN x 1.1 (for capital during startup) x 1.13 (exchange rate) = $5BN

Gas plant – 1.1GW nameplate

  • Cost (see notes) = $0.75BN (includes capital during startup) x 1.1 (converting cost per GW to 1.1GW) = $0.83BN

If we do the nice simple calculation as I did in the wind farm example we can divide this capital cost by 20 for an annual cost. It’s simple, but unfortunately too simple:

  • Wind farm capex = $250M per year (no cost of capital) = $28/MWh (for 8.8 MWh per year)
  • Gas plant capex = $ 42M per year ( ” “) = $4.70/MWh (” “)

There is a annuity calculation that allows us to compare the cost year by year, depending on the life of the equipment and the cost of capital. I’ll present the results of the calculation and we will see that it doesn’t make a big difference for the gas plant (because the fuel cost is so much higher), but does have quite an impact on the wind farms.

By way of example, for capital upfront, if we take 1/20th of the cost per year, we get 5% of the total capex per year (=1/20).

But if we take into account a “cost of capital” of 8% per year, the capex “really costs” 10% of the total per year. So “cost of capital” has actually doubled our effective capital cost. This is normal.

So let’s look at the “real capex cost” for 15, 20 and 30 year lifetimes of equipment, at 5%, 8% and 12% cost of capital:

Capex cost

Figure 8

We see the ratios are the same. But because the gas plant costs 1/6 of the wind farm, the actual gas plant capex is very low compared with its fuel cost. In essence, it doesn’t really matter what values we choose when we look at the gas plant (it matters to the owner, but not to us, for our purposes of broad comparison). On the other hand, cost of capital (“interest rate”) and time of operation make a big difference for the wind farm because the capex costs dominates.

Lets review our total operating costs:

  • Wind = $14/MWh
  • Combined-Cycle Gas = $23/MWh (@$3/GJ)  – $68/MWh (@$10/GJ)
  • Extra operating cost of gas over wind = $9/MWh (@$3) – $54/MWh (@$10)

So now we can calculate the total cost. Overall, if we look at the difference between the two tables, i.e., the capex difference, and add the opex difference, at recent European gas prices, for 20 year+ time horizons, wind is a little more competitive than gas plants (unless the cost of capital gets too high). At recent US gas prices, wind is way more expensive than gas.

Hey, wind is cheaper than gas

Hey, gas is cheaper than wind

Something for everyone.


Lots of numbers. It’s deliberate.

If you just want the answer that helps your cause, there it is – pick the one you like. If you want to understand the real story, a little work is needed.

What we can see is that even for quite different costs of construction for the gas plant, it won’t affect the comparison of gas vs wind. This matters a lot for a gas plant owner, along with the plant efficiency. But it doesn’t have much impact on our comparison numbers.

All of the numbers calculated can be questioned. There is no right answer. But hopefully everyone can see that the values that affect the cost comparison are:

a) price of gas, and

b) capex cost of wind turbines along with interest rate and lifetime of the turbines

We’re Not in Kansas Anymore

Let’s consider Oklahoma. Now the capacity factor has jumped up to 41%. So our upfront capex cost to produce an average 1GW has reduced from $5BN to about $3BN. Lovely. I recalculated the numbers (gas capex hasn’t changed, opex hasn’t changed for either):

Capex cost at 41% cap factor

If we pick 8% and 20 years we see that wind power capex is only $25/MWh more than the gas capex cost.

So with our “gas opex adder” of $9/MWh for cheap “I can’t believe it’s not Christmas” US gas, wind is still pricey. Wind is still $16/MWh more expensive ($25-$9).

But with our “cor blimey what are those Europeans doing” opex adder of $54/MWh, wind is now $29/MWh cheaper ($25-$54) than gas.

And last but not least, who’s the buyer?

Route 66

If we have a local buyer for this 1GW of power, we are in good shape. Although the current low US gas prices still make wind a little more expensive than gas in the Oklahoma example, recent history might make a wind power entrepreneur feel positive.

But suppose our customers are in New York. It’s about 1,000km in old money to get from windy Oklahoma to New York. We have a 2.5GW nameplate wind farm, so during windy periods we are producing 2.5GW. Now we need to get it 1000km.

According to our calculations in VIII – Transmission Costs And Outsourcing Renewable Generation this will cost around $2.5BN, give or take a little (or maybe a lot).

So we have almost doubled our capex price. Possible we have moved (in the wrong direction) past our European example, to a worse cost base. At our benchmark 8%, 20 year lifetime we are at capex approaching $70/MWh. Add in opex of $14/MWh = $84/MWh. So we are way more pricey than gas if we want to supply New York.

Of course, we can redo our calculations for a wind farm closer to New York, and on the minus side we might have a lower capacity factor for wind, but on the plus side maybe we can connect to a nearby under-capacity transmission line. Or worst case, we might need to build a transmission line – but it will be a lot shorter.

The gas plant has a constraint too – building gas pipelines aren’t cheap. (I forget the numbers I learnt but they might be in the same order of magnitude as power transmission lines for similar GW).

However, the gas plant entrepreneur is lucky, they can look at a map of gas pipelines and a map of power transmission lines and pick the optimized spot. It’s quite likely they will be able to tap off an existing gas pipeline and connect to an existing transmission line.

The benefit of incumbency and decades of infrastructure that they don’t have to pay for.


A bewildering array of numbers.

If you want to get your hands around the problem, it takes a little work, but it’s not so hard. Gas plants are cheap to build by comparison with the fuel costs. The fuel costs dominate. Wind farms are very expensive to build, have no fuel costs but still cost a bit to look after.

Gas plants can mostly be cited where you want – so you choose close to pipelines and close to transmission lines. Wind farms are often (but not always) subject to more location constraints – what you gain in better capacity factor (more wind) you might lose in building expensive transmission.

Which is cheaper per MWh of energy delivered to the customer? It depends.

So many cheerleaders with so many confident answers. And yet the right answer depends on the situation, the gas price, the cost of capital, the current capital cost of wind turbines, and most of all, where you are citing the wind farm and where your customers will be.

If there’s a lesson, it’s that turning a complex problem into one number doesn’t reduce confusion, it increases it.

What’s the average age of the population of Japan compared with the USA? The comparison can be a useful one. Still, it would be nice to see the demographic bulge – the graph of population vs age is much more useful than one number.

What’s the average weight of the population of Germany vs Mexico? Now we are really getting to a useless number (don’t we want to know the proportion of under 10s and over 70s before we draw any conclusions? And the average height of Mexicans vs Germans?)

If you add a carbon price to gas, wind will look better. You can easily do that yourself with the numbers in the article.

For people convinced that decarbonization is urgent, any extra cost of wind is of no issue. For people convinced that decarbonization is a total or partial waste of time, any extra cost of wind just illustrates how pointless the exercise is.

I make no comment on those points – I simply wanted to get an understanding of the cost comparison (here’s hoping I didn’t miss a factor of 1000 in one of my calculations).

If you want to figure out how to get to 50% renewables (% of electricity production) none of these numbers help.

Baseload Power and Messianic Storage have not yet been covered. That’s still a mystery.

Articles in this Series

Renewable Energy I – Introduction

Renewables II – Solar and Free Lunches – Solar power

Renewables III – US Grid Operators’ Opinions – The grid operators’ concerns

Renewables IV – Wind, Forecast Horizon & Backups – Some more detail about wind power – what do we do when the wind goes on vacation

Renewables V – Grid Stability As Wind Power Penetration Increases

Renewables VI – Report says.. 100% Renewables by 2030 or 2050

Renewables VII – Feasibility and Reality – Geothermal example

Renewables VIII – Transmission Costs And Outsourcing Renewable Generation

Renewables IX – Onshore Wind Costs

Renewables X – Nationalism vs Inter-Nationalism


Combined-Cycle Gas and Steam Turbine Power Plants (3rd Edition), Rolf Kehlhofer et al, PennWell (2009)


Construction times:

Kehlhofer-2009-Conventional Construction Times

Their LCOE calculations:

Kehlhofer-2009-LCOE with inputs

Breakdown of the plant costs for interest:

Kehlhofer-2009-Capex Breakdown Combined Cycle

In 2014, Germany produced 56 TWh of electricity by wind power (BP Statistical Review of World Energy June 2015).

Over the last 10 years Germany produced 422 TWh by wind power. At the end of 2014, the country had 39.2GW installed nameplate capacity (EWEA: Wind in power 2014 European statistics), which looks like a capacity factor of 16% (this understates the factor as the wind power installed in December 2014 can’t contribute very much – if instead we use installed capacity at end 2013 – 34.3GW – this gives a capacity factor in 2014 of 19%, so the correct value is in the range of 16-19%).

If this windpower replaced coal-fired power stations at about 900g/kWh of CO2, this last 10 years of wind has reduced Germany’s CO2 emissions by 380M tonnes CO2. And over the next 20 years (assuming 17.5% capacity factor) this installed base will produce 1,200 TWh, reducing CO2 emission compared with coal of 1080M tonnes CO2.

At current costs (see last article), which understates the country’s expense, Germany has spent a capital cost of €39BN, plus some considerable O&M costs.

As wind power increases in grid penetration, the benefits reduce a little – basically you will be ramping up and down conventional generation more, as windpower gets priority. This ramping up and down reduces efficiency (how much is a question we will look at in another article). Even though Germany has about a 10% average penetration of windpower, at peak windiness times, wind power might easily be over 50% of the power in the network, leading in fact to curtailment at certain times (see V – Grid Stability As Wind Power Penetration Increases).

So, well done Germany.

However, CO2 is a well-mixed GHG. So CO2 emissions from Germany are exactly the same as CO2 emissions from the US. That is, whether the US or Germany reduced their emissions by 380M tonnes of CO2 over 10 years makes zero difference to the climate.

Suppose Germany had installed this 39GW of nameplate capacity in the mid-west of the US:

From Osmani 201

From Osmani at al 2013

Figure 1

The average capacity factor in Oklahoma in 2011/2012 was over 41%.

Let’s assume that the capital costs outside of buying the turbine are the same (grid connection, land cost, access roads, regulatory compliance, etc). In that case German windpower investment of 39.2GW of nameplate could have produced 2.3x the energy (41%/17.5%).

Instead of reducing CO2 emissions by 380M tonnes CO2 to date, and a potential 1,080M tonnes over the next 20 years – the reduction would have been 870M tonnes to date and 2,500M tonnes over the next 20 years.

Why not?

Just add a page to the national energy production figures which shows the benefit. It’s not hard to understand.

I don’t want to pick on Germany, but it’s a nice concrete example. When you spend over €40BN on something it’s no longer a hobby. Why not get two and half times the environmental benefit?

It’s a serious question.

Articles in this Series

Renewable Energy I – Introduction

Renewables II – Solar and Free Lunches – Solar power

Renewables III – US Grid Operators’ Opinions – The grid operators’ concerns

Renewables IV – Wind, Forecast Horizon & Backups – Some more detail about wind power – what do we do when the wind goes on vacation

Renewables V – Grid Stability As Wind Power Penetration Increases

Renewables VI – Report says.. 100% Renewables by 2030 or 2050

Renewables VII – Feasibility and Reality – Geothermal example

Renewables VIII – Transmission Costs And Outsourcing Renewable Generation

Renewables IX – Onshore Wind Costs

Onshore wind seems to be the lowest cost renewable energy source (perhaps excluding hydro – I haven’t looked into the costs of hydro because it is mostly “tapped out” in developed countries).

Wind power (onshore) is a mature technology – when you buy a wind turbine and install it, you know it’s going to work, and you can have some expectation, at least across a wind farm of many turbines, of your O&M costs. You can have a reasonable expectation that it will run for perhaps 20 years. (Of course, you can’t have certainty on any item like lifetime or O&M costs, but this is true of any piece of equipment).

You also know – based on meterological data for the location – roughly how much energy it will produce. This is the capacity factor – the percentage of energy produced vs the “nameplate” value (the nameplate tells you the output if the wind is blowing at the maximum value).

So if you install a 2MW turbine in some parts of the UK or Ireland, or coastal regions of Europe, you might get 30% of that as annual output – 2000kW x 8760 hours x 30% = 5.3M kWh (written another way – 5.3 GWh annually). If you install the same turbine in some parts of Europe, or other parts of the UK, you might get a little over half that – 3M kWh (3GWh).

You can have some confidence in the annual energy production in advance.

Depending on the regulatory structure in the country/state in question you can have a reasonable idea of how long the process of approvals will take, and the grid connection costs (we’ll come back to grid connection later).

If we compare this with building a gas plant, or a coal-fired or nuclear power station then wind is more “modular” and there is a lot less project risk – if you want to produce say 500 MW annually (4,380 GWh) from a given technology then you could build a 550 MW gas plant (expecting certain downtime each year). From design through to startup might take a few years and there are all kinds of “little” problems that can cause significant delays. All of these can be mitigated one way or another, but many plants are late. It’s just the reality of complex projects.

And by the time of startup, the gas price (your fuel) might have doubled in cost from when the design commenced (also it might have halved). Most “expert” predictions of future gas and oil price ranges are only accurate when the price doesn’t change much, so large fluctuations are difficult to deal with. It’s a bit like predicting the weather tomorrow will be same as today. You are mostly right but how useful is that prediction?

To get the same output of 4,400 GWh from wind farms you need to install around 1,000 2MW wind turbines, depending on location (this calculation assumes 25% average output – 2GW x 8,760 x 0.25). You don’t have to wait 5 years before your investment starts producing energy that you can charge for. You can install around 20 a month for 4 years and be producing energy from month 1.

So there are a lot of project benefits for wind. On the downside for wind, you have to stump up most of your cash at the start, so you are a little more dependent on interest rate risk than a gas plant builder.

There are three main downsides to wind:

  1. It’s not “dispatchable” so it doesn’t create baseload power – another way to say this is that wind power at significant grid penetrations gets very little “capacity credit” – something needs to provide power when the wind is not blowing, or not blowing much – we looked at this in IV – Wind, Forecast Horizon & Backups and in Renewable Energy I
  2. A lot of places where you might want to install wind farms there is no transmission grid, so there is a cost which is not usually factored in to wind power costs. Building transmission grids is expensive –VIII – Transmission Costs And Outsourcing Renewable Generation. Another way to look at it is you are constrained to put the wind farms where the wind blows best, rather than at a convenient point on the grid. The same is true of nuclear power, of course – for reasons that are unclear to me they are mostly get built a long way from big cities. Gas and coal power stations can have more flexibility. But the ideal place for a wind farm is often on top of an inaccessible hill with no transmission line for 100km.
  3. Wind has a very low energy density, so requires a lot of land. We will come back to this important point in a future article. This is why Europe has high projections for offshore wind despite major problems with offshore.. In places with high wind and low population density like, say, Oklahoma this is not so much of an issue.

Of course, many people don’t like wind farms cluttering up the countryside but I’m just going to ignore that. Many people don’t like roads or telegraph poles or coal-fired power stations or nuclear power stations or changing the color of phone boxes (what are they?) or the large quantity of birds killed each year by cats..

This series is about more practical energy considerations like how a grid works, how much power can be produced, what it costs, and so on.

Not hurting peoples’ feelings is for another series.


This numbers I’ve extracted come with quite a margin of error. If you buy one 2MW wind turbine you might pay $X. If you buy 10 you might get a 5% discount. If you buy 500 you might only pay 75% of $X per turbine. One year the prices will be lower because of exchange rate fluctuations and raw material costs. The next year they will be higher. If you negotiate better you might pay 15% less than the next guy for the same quantity in the same month. And so on. This is true for all purchasing. There is no “one price” in real life for most items.

Here I’m just trying to put a stake in the ground so we can get an idea what wind energy costs.

Onto numbers.

Blanco (2009): the capital cost of installing a 2MW (nameplate) wind turbine ≈ €2.4M, of which just over 70% was the ex-works cost of the turbine. (In 2009 this was about US$ 3.4M with the exchange rate quite high, at €1 = $1.4, vs today around €1 = 1.11).

From Blanco 2009

From Blanco 2009

Figure 1

As explained in the previous sub-section, wind energy is a capital-intensive technology, so most of the outgoings will be made at this stage. The capital cost can be as much as 80% of the total cost of the project over its entire lifetime, with variations between models, markets and locations. The wind turbine constitutes the single largest cost component, followed by grid connection.

After more than two decades of steady reductions, the capital costs of a wind energy project have risen by around 20% over the past 3 years. The results of our survey show that they are in the range of 1100–1400 €/kW for newly-established projects in Europe.

And The Economics of Wind Energy from 2009 has similar data:


Figure 2

So again installing a 2MW turbine and connecting it to the grid costs around €2.4M.

If we look at the capex cost of this wind turbine over 20 years in a many parts of Europe with a capacity factor around 15%, we see that it produces 53M kWh (2000 x 8760 x .15 x 20), so ignoring the cost of capital, a capex cost of 4.5 c€ per kWh. In Ireland and many parts of the UK, with a capacity factor around 30%, we get 2.3 c€ per kWh. This kind of cost is also written as €23/MWh – €45/MWh.

Operations and maintenance cost vary of course. Current estimates seem to be around 1-1.5 c€/kWh or 10-15/MWh. Some of these costs are “fixed” in that they are legal or regulatory so cannot be tied to the energy output while others are clearly related to the energy output (replacing parts, etc). And there is a lot of variability in all of these costs.

So to put this in a different perspective, for our 2MW turbine, running at an attractive 30% capacity in a high wind location, the O&M cost is around €53,000 – €79,000, and over 20 years (again ignoring cost of capital which increases the cost of initial payments vs later maintenance costs) this equates to €1.1M – €1.6M, which is not insignificant in light of the capital cost.

Of course, the long term maintenance costs are quite unclear, as there isn’t a lot of 20-year data on wind turbines, and no long term data at all for current generation products.

The 20-year life is also a value that exists more for planning purposes than a real consideration of actual lifetime. Many conventional power plants were given something like a “30-year life” yet are still operating 50 years on. In those cases, the “lifetime” was more for planning and purposes of financial measurement, rather than the belief that after 30-years they would fall apart. And the “30-year” plants still operating after 50 years may have had a number of expensive refits during that period.

If we sum it up in a “proper financial metric” like Levelized Cost of Energy (LCOE), we need to include the cost of capital and take into account the capacity factor. And then take a view on the number of years the wind turbine will operate.

All this does is obscure the costs, as anyone used to trying to compare the cost of different types of power will attest. So we will stick with raw numbers for now. It makes it easier to compare other forms of energy generation that we will look at in subsequent articles.

The International Renewable Energy Agency (IRENA), 2012 had higher costs:

Installed costs in 2010 for onshore wind farms were as low as USD 1,300 [€1100] to USD 1,400/kW [€1200] in China and Denmark, but typically ranged between USD 1,800/kW and USD 2,200/kW [€1500-€1800] in most other major markets. Preliminary data for the United States in 2011 suggests that wind turbine costs have peaked and that total costs could have declined to USD 2,000/kW for the full year (i.e. a reduction of USD 150/kW compared to 2010). Wind turbines account for 64% to 84% of total installed costs onshore, with grid connection costs, construction costs, and other costs making up the balance..

At this time the exchange rate was around €1=$1.20, I added the € cost in [] brackets at that exchange rate.

The US NREL 2011 Cost of Wind Energy Review has $2,100 per kW installed cost. Converted to Euro at the prevailing rate we get about €1,500 per kW. So for our 2MW turbine (reviewed earlier) the US cost would be (in Euros) €3M instead of the €2.4M.


Figure 3

Their operating expenses are in a different format. Here a 2MW turbine would cost $70,000 per year to operate and maintain, or (in that year) about €50,000 – a similar number to the lower end of the range given in Blanco (2009).

They also provide a nice graphic showing (to me at least) why producing LCOE (levelized cost of energy) values is not particularly helpful:


Figure 4 – Any value you like!

The report comments further:

Although the reference project LCOE for land-based installations was observed to be $72/MWh, the full range of land-based estimates covers $50–$148/MWh.


The largest factor, and the reason why a generic cost per MWh for wind and solar is a useless number, is it depends where it is located. High wind, lower LCOE. Low wind, higher LCOE. I doubt anyone would have come up with “LCOE” if energy generation had been dominated by wind and solar in the past. They would have come up with something like “LCOE per % capacity factor”. The “reference value” of $72/MWh was at a capacity factor of 37% (note 2), a value rarely seen in new European installations. I think the average for the UK (from memory, not checking) is around 30% currently, and it has gradually increased over the past few years. Many parts of continental Europe have capacity factors below 20%.

The NREL report also shows the formula for LCOE (for those interested). I’m assuming that the reason they have nearly $80/MWh for a 30% capacity factor (figure 4)  – vs our figure of €23+€10/MWh = $46/MWh in that year – is due to the 25% higher capital cost along with introducing the cost of capital.

This illustrates an important point with renewables – from country to country and region to region there will be very large differences in their ability to convert to high penetrations of renewables.

One further point to be noted from these data points is that we can’t always assume the costs over the next few years will go down – as outlined in Renewable Energy I. Due to high demand, the capex cost of wind power increased for a few years.

As far as I can tell, the above costs are all free of subsidies.

Transmission Costs

The grid connection costs have been considered in the capex costs, but these pre-suppose that transmission is available, or paid for by “someone else”. In some countries like Spain, this (paid for by someone else) has been true. As wind power grows, moving the costs to the grid operator becomes more problematic. If you connect to an existing transmission line and add 10 MW this is probably fine. Once you add 500MW at peak wind periods you might overload that transmission line and a $500M upgrade may be needed. On the other hand, if you are lucky, you might be replacing conventional capacity on an existing transmission line and no upgrade will be needed.

So it should be clear that this is one of the wild cards. Each case is different, but in most cases there will be substantial cost to be incurred – once wind power becomes significant, which of course is the idea.

In the last article we looked at building long transmission costs and as a massive over-simplification suggested that a cost of $1BN per 1GW per 1000km was a handy guide. So, if we build a large series of wind farms to replace a 500MW gas-fired power station, it will be something like 2GW nameplate. If we want to add 2GW into our transmission line at peak times, and it’s 500km long we can expect to incur a cost of $1BN.

Note that there will be other complications – see V – Grid Stability As Wind Power Penetration Increases.

If we compare the transmission estimate of $1BN with building 2GW nameplate capacity of wind power – a capex cost around €2.4BN – we see it will be significant.


Wind power is a mature form of energy generation with fairly well-known costs, minimal risks, and the benefit of not being subject to fuel costs with large fluctuations. Any cost analysis is always out of date but at least here we can see approximate values for capital costs and for ongoing costs – and the basis for these values.

Depending on where you locate your wind turbine you can get a factor of 3 change in annual output so €/MWh and $/MWh are not useful metrics without a location guide.

A good estimate from a few fairly recent studies is:

  • Capital cost = €1.2M per MW or $1.5M per MW of nameplate (including grid connection costs, but excluding bringing a transmission line to the area). So to convert that to cost per energy produced you divide that cost by the capacity factor (which depends on location and might be 15% in a poor location -40% in a prime location) / 8760 hours in the year / number of years you expect your turbine to operate – and you get € or $/MWh (excluding cost of capital)
  • Ongoing O&M costs = €10-15/MWh

We will look at the costs of other forms of energy in subsequent articles.

Articles in this Series

Renewable Energy I – Introduction

Renewables II – Solar and Free Lunches – Solar power

Renewables III – US Grid Operators’ Opinions – The grid operators’ concerns

Renewables IV – Wind, Forecast Horizon & Backups – Some more detail about wind power – what do we do when the wind goes on vacation

Renewables V – Grid Stability As Wind Power Penetration Increases

Renewables VI – Report says.. 100% Renewables by 2030 or 2050

Renewables VII – Feasibility and Reality – Geothermal example

Renewables VIII – Transmission Costs And Outsourcing Renewable Generation


The economics of wind energy, Isabel Blanco, Renewable and Sustainable Energy Reviews (2009)

The Economics of Wind EnergyEuropean Wind Energy Association (2009)

RENEWABLE ENERGY TECHNOLOGIES: COST ANALYSIS SERIES – Wind Power, International Renewable Energy Agency (IRENA), 2012

2011 Cost of Wind Energy Review, S. Tegen, E. Lantz, M. Hand, B. Maples, A. Smith & P. Schwabe, National Renewable Energy Laboratory (2011)


Note 1: From Blanca 2009:

Blanco-2009-Data sources for Capex

Blanco-2009-Data sources for O&M

Note 2: NREL report says:

The annual average wind speed chosen for the reference project analysis is 7.25 meters per second (m/s) at a 50-m height above ground level (7.75 m/s at hub height). This wind speed is representative of a Class 4 wind resource (7−7.5 m/s) and is intended to be generally indicative of the wind regime for projects installed in moderate quality sites in the “heartland” (Minnesota to Oklahoma).



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