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 Once again I’ll use out-of-date values, this time because a great textbook from 2009 has some pretty good breakdowns.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).


With the big growth, or planned growth, in wind and solar in many countries you need to connect up new windfarms and solar arrays with people. This requires power transmission lines.

Electricity grids also have to match supply and demand on a second by second basis. This presents a problem, especially with renewables like wind or solar which may produce 1 GW during a sunny windy day and 0.01 GW during a calm night.

One solution put forward is “affordable storage capacity”. Let’s say for now, along with everyone (serious) writing reports, papers and feasibility studies, that there is no “affordable storage capacity”, except for hydroelectric storage, which is mostly “tapped out” in developed countries. There might be – via some as yet unknown technology breakthrough – but until then storage isn’t an option. If this happens – problem solved – and the world has a major breakthrough.

So we need baseload supply for times when intermittent renewable supply is not available (at the moment this requires a conventional power plant, as we saw in earlier sections, e.g. Part IV)

Or maybe not.

Perhaps instead we can put massive solar arrays in Arizona, massive windfarms in South Dakota, more massive solar arrays in Libya and connect up the supply to Germany, or any country that wants to transform its electricity supply into renewable energy.

Kind of a massive outsourcing exercise. After all, why put solar arrays in Germany when there is so little sun? Why put windfarms in Germany when it really doesn’t have that much wind? Why not put up windfarms in places with lots and lots of wind and not many people, and solar into places with the highest solar insolation and not many people?

All you need is to connect them up with transmission lines. Not very difficult. Not a technical challenge at all. As one commenter said in an earlier article “An Atlantic interconnector may sound fanciful, but a UK Norway link is a live project, and an Iceland project is under feasibility.

So, it’s clear, we can get power from A (source) to B (population). It’s just a piece of wire.

But what does it cost? That’s the real question. Generally the answer is “pricey”. Because it’s very substantial pieces of heavy wire with large support structures to get it from A to B, and massive transformers or large banks of thyristors.

In one paper (Osmani et al 2013) I read the costs of building new transmission were quoted as $/kWh. Yes, a paper with a sense of humor..

Think of building a railroad. Your cost depends on the terrain, cost of material, and cost of contractors. And very important: the length – whether you are running from Washington DC to Richmond, Virginia or from Portland, Oregon to Fort Lauderdale, Florida. At the end you’ve built the railroad. If one person a day or 10,000 a day travels the railroad the cost invested will still be the same. So quoting $/passenger isn’t exactly useful for an overall idea of what it costs to build a railroad. Better to quote $/mile for construction across a few different terrains and let everyone else do the maths for different passenger numbers.

Quoting $/kWh for power transmission is about as useful as saying the average cost of a journey = $7.46, when averaging domestic & international plane flights, train & bus journeys, dinner with friends, and all those trips to the local 7-11.

Transmission Basics

There are two options with transmitting lots of power – a.c. (alternating current) or d.c. (direct current). AC is what you have in your homes, it is what is supplied by the grid, and it is how most power is moved around.

Once you get past a certain distance, DC is a lower cost option. The “break-even point” is always changing but in essence the actual transmission costs are always less with DC, but the conversion costs (from AC to DC and back to AC at the other end) are significant.

The crossover point is around 800km for overhead lines, and 50km for subseas lines (Electric Power Systems, Weedy et al, 2012 – and see extract for more details in note 1).

There is another important point – if you just want to get power from say Innamincka in central Australia to Melbourne, Australia (see Part VII where we looked at the failure, so far, to obtain power from 4km deep geothermal sources) then HVDC is a good choice. But if you want to add in the power from lots of wind farms or solar arrays on the way, then all those conversion stations will start to cost and using AC transmission would be better:


Figure 1 – Thyristor (top) and Thyristor Bank for AC-HVDC conversion (bottom) – these babies ain’t cheap

Cost Data

Finding quality data on transmission costs is not so easy. The people who really know are in companies that provide these construction services and their data is confidential, like any business.

For example, if you want to find out what an LNG plant costs you might be able to dig through some annual reports of a few customers of LNG plants and see their capex costs revealed in expenses lines or in notes/discussion, but then you wonder why one plant of the same capacity was 20% more than the other. Maybe one of them negotiated a better deal with Bechtel. Maybe one customer provided some of the key services themselves and that reduced the price. Maybe another customer insisted on a given subcontractor or technology because of their view on the long term O&M costs and that increased the price. Maybe Bechtel was stretched on the last plant and gave a higher price and the customer didn’t have a better EPC to build it.

Onto power transmission costs which has similar challenges for the outside observer.

In reviewing the AEMO report for Renewables VI – Report says.. 100% Renewables by 2030 or 2050 – I found a link to a transmission costing report – Network Extensions to Remote Areas Part 2 – Innamincka Case Study – which was very useful (I have lost the link where I downloaded this report, I can email the pdf report to anyone interested). This looked at the cost of power transmission from a possible geothermal source in central Australia to a few population centers.

The costs are given in Australian Dollars, but the report was 2009 and the conversion from the greenback was at US$1 = A$1.20 so the costs are basically similar in US$, given the lack of hard data, changes in costs of various materials, and so on.

My summary of their table, followed by the table itself:

  • AC transmission of 5GW – 1000 km (620 miles), 765kV double circuit line with series compensation – $3.3 BN to $5.1 BN
  • as above but with two cities as stop off points – $3.9 BN to $6.1 BN
  • DC transmission of 4GW – 1100km (680 miles), +/- 800 kV bipole – $2.5 BN to $3.5 BN


Click to expand

The report states:

Note that this study has not taken into account the following routing considerations which could add to the cost of the transmission options :

  • a) Excessive wind and ice loading (the study assumed moderate winds with no allowance for cyclonic conditions and no ice loading)
  • b) Minimization of visual impact
  • c) Complexity of terrain

The indicative costs in this report exclude :

  • a) Allowance for difficult terrain such as forested, hilly ,or mountainous
  • b) Costs for access roads
  • c) Statutory compliance costs
  • d) Consenting costs
  • e) Allowance for project scope accuracy
  • f) Price contingency for exchange rate variation, manufacturing market pressures, and price of materials
  • g) Interest During Construction
  • h) Operating and maintenance costs
  • i) Cost of losses

For example, if this was Europe or most parts of the US you would need to add “a lot” (maybe 25%) for additional costs to support the ice loading. If you have to consider very high wind conditions – that’s more cash. If you need to go through cities or over mountains, add “a lot more”.

So from this report, as a rule of thumb, think $1BN per 1GW per 1000km as the likely minimum. From the scaling in their calculations increasing the power by a factor of 10 increases the HVDC costs by a factor of around 4, but I can’t say whether that holds true if you want to increase by another factor of 10 (they weren’t trying to design for 10x the power).

If you live in a country which has an environmental lobby with political power then you can add “even more” due to costs of ensuring the lesser-spotted green frog is not at risk when putting up the necessary support structures:


If you want to ensure that a tower coming down doesn’t bring down the power transmission then you need two of the above for the whole journey, adding “a lot” to costs:


The cost of land access can be high, depending on the country and the right of easements given to utilities.

In future articles we will try to find other pricing points to see how this compares.

These costs also worked on the basis of keeping the losses below 10% for the 1000km distance. If you want to reduce losses then you need to spend more – bigger conductors (more cash), stronger support structures to support these heavier conductors (more cash).

Route 66 and Relocation Relocation

The US used 4,500,000 GWh of electricity in 2011 (Osmani et al 2013). This equates to an average (but not a peak) of just over 500 GW.

So if we wanted to bring 50GW of solar power from Arizona to the North East then we are looking at a distance of something like 3,500km and a cost (assuming the scaling holds from the report) of $100 BN, plus all the exclusions listed above. Maybe with economies of scale this might be $50BN, on the other hand it might be $300BN.

I’m just trying to some perspective  on the order of magnitude of the costs.

And for this distance, at the efficiencies noted, this would include a loss of at least 35% of the source energy. So multiply the cost of 50GW of solar in Arizona x 1.5 to cover the losses. And don’t forget to increase the AC-HVDC conversion costs at the source end by 1.5 – and so on. (Depending on the relative costs, it might be more cost-effective to spend less on solar arrays and more on transmission).

If we have distributed wind farms through the midwest and solar arrays in the southwest and we want to take that power around the country it’s clearly going to be a lot more. It all depends on the amount of power, the number of feed-in points, the number of extraction points, the distance, the terrain.. To do this we would probably have a mix of DC and AC lines. If the whole network was AC the cost might double.

We can see that locally-produced power has a large benefit over long-distance power. Moving, or outsourcing, power production has a significant price tag and a significant power loss.

Still, it’s a price point. When we have some approximate costs and efficiencies of local wind and solar production we can see whether the transmission costs justify the relocation.

Maybe someone has already done a detailed cost analysis of a “massive inter-state power transmission” project.

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


Electricity generation from renewables in the United States: Resource potential, current usage, technical status, challenges, strategies, policies, and future directions, Atif Osmani et al, Renewable and Sustainable Energy Reviews (2013) – paywall paper

Electric Power Systems, John Wiley & Sons Ltd, Weedy et al, 5th edition (2012) – textbook

Network Extensions to Remote Areas Part 2 – Innamincka Case Study, by Power Systems Consultants Australia Pty Ltd, for Australian Energy Market Operator Ltd, 2009


Note 1: Electric Power Systems, 5th edition (2012) has a good summary on AC vs DC:

Electric Power Systems -dc1

Electric Power Systems -dc2



In Renewables VI – Report says.. 100% Renewables by 2030 or 2050 we looked at a feasibility study for 100% renewables in Australia by 2030 and 2050. Many people see feasibility studies and say “look, it’s achievable and not expensive, what are we waiting for? Giddy up“. In fact, it was such an optimistic comment that led me to that report and to study it.

Feasibility studies are the first part of a journey into the unknown. Most things that look like they are possible usually are. But it might take 30 years longer and $100BN more than expected, even if we get there “in the end”. So feasibility studies attempt to get their hands around the scope of the task.

In my comment at the conclusion of the last article, after stating my point of view that getting to 100% renewables by 2030 was not at all realistic, I said:

Readers enthusiastic about renewable energy and frustrated by the slow pace of government action might think I am being unnecessarily pessimistic. Exactly the kind of attitude that the world cannot afford! Surely, there are upsides! Unfortunately, the world of large complex projects is a world that suggests caution. How many large complex projects finish early and cost only 80% of original budget? How many finish years late and cost 3x the original budget? How many apparently simple projects finish years late and cost 3x the original budget?

One of the questions that came up in the discussion was about geothermal – the report had an “optimistic on technology” 2030 scenario with 9 GW of supply, and the “optimistic” 2050 scenario with 13 GW of supply. We mainly focused in the report on the “non-optimistic” version which had no major technical breakthroughs and therefore little geothermal. I actually started digging into the detail because details are where the real stories are and also to understand why any geothermal was showing up in the “non-optimistic” 2030 scenario.

The Australian geothermal energy story turns out to be a salutary tale about feasibility and reality. So far. Of course, tomorrow is another day.

I would hate for readers to think I don’t believe in progress, in trying to break new ground, in new technologies. Far from it.

Most breakthroughs that have changed the world have started as ideas that didn’t really work, then half-worked, then inventors battled away for years or decades stubbornly refusing to “face reality” until finally they produced their “new steam engine”, their “wireless communication that spans countries”, their “affordable personal computer” and so on. The world we live in today is a product of these amazing people because inventions and technical progress change the world so much more than politicians.

All I am attempting to do with this series is separate fact from fiction, current technology from future technology and “feasible” from “accessible”. Many people want to change the world, to replace all of the conventional GHG-producing power with completely renewable power. Is it possible? What are the technical challenges? What will it really cost? These are the questions that this series tries to address.

And so, onto Lessons in Feasibility.

Here is a press release (originating from Geodynamics but on another website) in 2009:

An Australian geothermal energy company is at the forefront of one of the most important and exciting resource industries in the world and is preparing for a landmark year in 2009. Kate Pemberton reports.

By mid-2009, Brisbane-based Geodynamics expects to be providing Australia’s first hot rocks geothermal-generated electricity.

Following the successful completion of the Proof of Concept stage, the company’s joint venture operations with Origin Energy in the outback town of Innamincka, South Australia, will progress to commercial demonstration.

Geodynamics Managing Director and CEO Gerry Grove-White said Innamincka, which has a permanent population of just twelve, is set to be the proving ground for hot fractured rock (HFR) geothermal energy when it swaps diesel fuel power for geothermal power.

“From that one small step, Geodynamics aims to make the great leap into making the Cooper Basin a major new energy province for Australia,” said Mr Grove-White..

..Geodynamics said that the development of Australia’s vast geothermal resources could provide more than 25 per cent of the nation’s increase in demand for energy by 2050. The company believes Australia’s geothermal resources offer the most realistic and timely solution for the demand for clean, zero emission, base load power. In the coming year, Geodynamics will be seeking a significant proportion of the $500 [?] Renewable Energy Fund promised by the Federal Government to help finance its own commercial geothermal power demonstration plant.

I think the Renewable Energy Fund had $500M. On its own $500 wouldn’t get you far (just being realistic here), and another press release has:

Geodynamics also said it had submitted an application for $90 million of funding under the Federal Government’s Renewable Energy Demonstration Program (REDP).

The original press release went on:

Geodynamics’ Cooper Basin site is regarded as one of the hottest spots on earth outside volcanic centres. To date, the company has drilled three wells – Habanero 1 (named after the world’s hottest chilli), Habanero 2 and Habanero 3. Of these, Habanero 1 and 2 are not of commercial scale. Habanero 3, the first well to be drilled using the ‘Lightning Rig’, is the first commercially viable well to be drilled and its target depth of 4,221 metres was reached on 22 January 2008. The completion of drilling in Habanero 3 is the largest well of this depth ever drilled onshore in Australia and the first commercial scale HFR production well to be drilled. Geodynamics’ tenements – GELs 97, 98 and 99 – have been shown to contain more than 400,000 petajoules (PJ) of high-grade thermal energy. The company’s confidence is based on the fact that:

  • The size of the resource is clear – the large bodies of granite have been clearly delineated and proven to exist through drilling.
  • The quality and potential of the resource is proven – temperatures have been measured up to 250°C.
  • The world’s largest enhanced underground heat exchanger has been developed and initial flow tests have produced the first hot fluids to the surface.

Project studies, including long term production modelling, have shown that these resources have the potential to support a generating capacity of more than 10,000 megawatts (MW).

The company will now move forward to Stage 2 of the business plan – commercial demonstration – and expects to produce its first MW of geothermal power by the middle of 2009.

Mr Grove-White said “This great news, in conjunction with the impending commissioning of the 1 MW Pilot Plant, will allow the company to move on to building a commercial demonstration plant.”

The 1 MW pilot power station will enable the company to use geothermal energy to power its field operations near Innamincka, including workers’ accommodation, warehouses and workshops.

The company also plans to finalise its preferred design for a 50 MW power plant during 2009. Once operational (planned for 2012), the power plant will produce zero emissions with zero water requirements and will produce enough electricity to power approximately 50,000 households on a continuous basis.

Geodynamics is focused on delivering power to the national electricity grid in 2011, with a targeted production of more than 500 MW by 2016. The company said that eventually output will reach 10,000 MW – the equivalent of 10 to 15 coal-fired power stations – giving hot rocks energy a justifiable claim as a great Australian resource to rank with the Snowy Mountains Scheme. Geodynamics has conducted concept studies to define options for transmitting power from the Cooper Basin to major load centres such as Brisbane, Adelaide or Sydney.

So it’s very positive. About to start up a 1MW plant within a few months, a 50MW plant expected in 2012 and a 500MW plant for 2016.

Long term – 10GW. This is around 25% of Australia’s projected electricity demand in 2050.

We are almost in 2016, so let’s see their progress.

The 2012/2013 report (year ending June 30th, 2013):

The first milestone was the successful completion of the Habanero 4 well and commissioning of the 1 MWe Habanero Pilot Plant in April 2013. Realising this long held goal is a significant achievement and an important demonstration of EGS technology. As one of only three EGS plants operating globally and the first new EGS plant to be commissioned for a significant period of time, there has been a great deal of interest in our results around the world, particularly in the unique reservoir behaviour of the Innamincka granite resource..

So, close to mid-2009, the company was confident of generating 1MW of power “by mid-2009”. 1MW was finally produced in 2013. There are some nice technical descriptions within the report for people who want to take a look:


Innamincka – You should see the nightlife

As for plans going forward in mid-2013:

Our focus for the year ahead is demonstrating the feasibility of a viable small scale commercial plant to supply customers in the Cooper Basin. The first key objectives are the completion of a field development plan for a 5 – 10 MWe commercial scale plant, based on a six well scheme exploiting the high permeability reservoir created at Habanero. The feasibility of supplying process heat as an alternative to supplying power will also be investigated as part of this study.

A year later, the 2013/2014 annual report:

We are Australia’s most advanced geothermal exploration and development company, and a world leader in the emerging field of Enhanced Geothermal Systems (EGS). This year, the Company passed a major milestone with completion of the 1 MWe Habanero Pilot Plant trial near Innamincka, South Australia, one of only three EGS plants operating globally.

Following the successful pilot plant trial, the Company signed an exclusivity agreement with Beach Energy Limited, in regards to our exploration tenements in the Cooper Basin, an important step towards securing a customer for the geothermal resource. Under the agreement, a research program will assess the potential of the Habanero resource to supply heat and/or power to Beach’s potential gas developments in the area.

And now up to date, here is the 2014/2015 annual report (year ending June 30th, 2015):

In line with our search for profitable growth investment opportunities, on 14 July 2015 Geodynamics announced an all scrip offer to acquire Quantum Power Limited. The merger of the two companies will provide Geodynamics shareholders with entry into the biogas energy market, a growing and attractive segment of the clean technology and renewable energy sector, and exposure to immediate short-term attractive project opportunities and a pipeline of medium and longer term growth opportunities.

Geodynamics will continue to actively seek other opportunities to invest in alongside the Quantum investment to build a strong portfolio of opportunities in the clean technology sectors. Having successfully completed the sale and transfer of the Habanero Camp to Beach Energy Limited, additional field works in the Cooper Basin will be undertaken to plug and abandon and complete site remediation works associated with the Habanero-4, Habanero-1, Jolokia and Savina well sites and the surface infrastructure within the Habanero site in line with our permit obligations..

..As reported at 30 June 2014, the Company finalised the technical appraisal of its Cooper Basin project and associated resource. In the absence of a small scale commercial project or other plan to commercialise the project in the medium term, the Company impaired the carrying amount of its deferred exploration, evaluation and development costs in respect of the Cooper basin project to $nil.

[Emphasis added].


Who did they sell the camp to?

Beach Energy is an ASX 100 listed oil and gas exploration and production company, with a primary focus on the health and safety of its employees. The company also prioritises a commitment to sustainability and the improvement of social, environmental and economic outcomes for the benefit of all its stakeholders. Beach is focused on Australia’s most prolific onshore oil and gas province, the Cooper Basin, while also having permits in other key basins around Australia and overseas.

Whether or not anyone will be able to produce geothermal energy from this region of Australia is not clear. Drilling over 4km through rock, and generating power from the heat down below is a risky business.

It’s free renewable energy. But there is a cost.

One company, Geodynamics, has put a lot of time and money (from government, private investors and Origin Energy, a large gas and power company) into commercial energy generation from this free energy source and it has not been successful.

Feasibility studies said it could be done. The company was months away from producing their first 1MW of power for 4 years before they succeeded and, following that success, it obviously became clear that the challenges of producing on a commercial scale were too great. At least for Geodynamics.

The only lesson here (apart from the entertainment of deciphering CEO-speak in annual reports) is feasibility doesn’t equate to success.

The dictionary definition seems to be “if something is feasible, then you can do it without too much difficulty”. The reality of “feasibility studies” in practice is quite different, let’s say, “buyer beware”.

Lots of “feasible” projects fail. I had a quick scan through the finances and it looks like they spent over $200M in 6 years, with around $62M from government funding.

We could say “more money is needed”. And it might be correct. Or it might be wrong. Geothermal energy from the Cooper Basin might be just waiting on one big breakthrough, or waiting on 10 other incremental improvements from the oil and gas industry to become economic. It might just be waiting on a big company putting $1BN into the exercise, or it might be a project that people are still talking about in 2030.

Individuals, entrepreneurs and established companies taking risks and trying new ideas is what moves the world forward. I’m sure Geodynamics has moved the technology of geothermal energy forward. Companies like that should be encouraged. But beware press releases and feasibility studies.

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

Regular readers are probably used to the lack of clear direction as we progress through a series (and switch to a new series, and back to an old series). Better series would have a theme, an outline, an overall direction, basically some kind of plan. Instead, we have part VI.

As I was reading the comments in The Conversation – Australia’s 2030 climate target puts us in the race, but at the back I saw that getting to 100% renewables in Australia was perfectly achievable:

The AEMO and UNSW studies showed that 100% renewables is viable and affordable. There are no problems with 50%.

– and so I thought I would take a look. It’s quite appealing to be able to convert all of a country’s electricity supply to renewables. And Australia has a couple of big benefits – lots of sunshine, and lots of land compared with the population. Probably most countries in the developed world have commissioned a report on how to get to 40% and 100% renewables by year x and Australia is no different.

As a positive the study considered two different cases and two time horizons:

The modelling undertaken presents results for four selected cases, two scenarios at two years, 2030 and 2050. The first scenario is based on rapid technology transformation and moderate economic growth while the second scenario is based on moderate technology transformation and high economic growth. The modelling includes the generation mix, transmission requirements, and hypothetical costs for each.

The major difference to 2050 is more population and economic growth, so we’ll focus on 2030 – especially as sooner is obviously better (and perhaps more difficult). And the first scenario basically assumes lots of new stuff that doesn’t exist yet, so we’ll focus on the second scenario.

As always with papers and studies, I recommend readers to review the whole document, not rely on my extracts.

The modelling suggests that considerable bioenergy could be required in all four cases modelled, however this may present some challenges. Much of the included biomass has competing uses, and this study assumes that this resource can be managed to provide the energy required. In addition, while CSIRO believe that biomass is a feasible renewable fuel, expert opinion on this issue is divided.

The costs presented are hypothetical; they are based on technology costs projected well into the future, and do not consider transitional factors to arrive at the anticipated cost reductions. Under the assumptions modelled, and recognising the limitations of the modelling, the hypothetical cost of a 100 per cent renewable power system is estimated to be at least $219 to $332 billion, depending on scenario. In practice, the final figure would be higher, as transition to a renewable power system would occur gradually, with the system being constructed progressively. It would not be entirely built using costs which assume the full learning technology curves, but at the costs applicable at the time.

The 2030 “no great technology breakthrough” scenario is given as $252 BN – “Capital costs are based on DCCEE scope assumptions which include: assumed system build in 2030 or 2050 without consideration of the transition path; and no allowance for distribution network costs, financing costs, stranded assets, land acquisition costs or R&D expenditure.

These figures are in Australian dollars and in 2013-2014 government spending was around A$400BN. Over 15 years the estimated cost of going to 100% renewables is about $17 BN per year or roughly 4% of government spending per year. What governments euphemistically call “defence” is costed at $20BN in the Australian budget so it’s not impossible. Swords into ploughshares, and F-35A Lightning II’s into Vestas V112 wind turbines..

However, assuming that achieving 100% renewables starting in 2030 requires building stuff today (not starting on Jan 1st, 2030) we should look at what it costs to build renewables today. I’ve taken their numbers as a given. The same calculations come out as 50% – 100% higher (using their estimate of today’s costs rather than 2030 cost projections), so maybe $370-$500BN.

Given there is as yet no detailed project plan (and no budget) the best case is to start building close to 2020, so more like $30-$50BN per year. Let’s call it 10% of government spending. (The study looked at increasing electricity prices to pay the bill).

What was encouraging in the study – for the 2030 scenario 2 study – was:

  • no obvious assumption of “game changer” technology that would magically appear
  • some costing associated with upgrading the transmission network (critical requirement)
  • the current (estimated) capital costs were given, as well as the future estimated capital costs

Of course, many caveats come with a feasibility study:

It is important to note that the cost estimates provided in this study do not include any analysis of costs associated with the following:

  1. Land acquisition requirements. The processes for the acquisition of up to 5,000 square kilometres of land could prove challenging and expensive.
  2. Distribution network augmentation. The growth in rooftop PV and demand side participation (DSP) would require upgrades to the existing distribution networks.
  3. Stranded assets. While this study has not considered the transition path, there are likely to be stranded assets both in generation and transmission as a result of the move to a 100 per cent renewable future.

Costs for each of these elements are likely to be significant.

This report is not to be considered as AEMO’s view of a likely future, nor does it express AEMO’s opinion of the viability of achieving 100 per cent renewable electricity supply.

Buying 5,000 km² of land could be cheap if it is out in the desert or $10BN if in the country.

Transmission lines might be the the wild card – you need transmission lines to get power from the new supply locations to the load centers – i.e., people. People are in cities. Land in cities and close to cities is expensive. Building the transmission lines and connecting generation was estimated at $27BN but it’s not clear if it includes the land acquisition costs. Here is the map of the added infrastructure:


Figure 1

Where the Energy Will Come From

It was a surprise to find that solar was not the biggest by far. All that sun – and yet solar is still outclassed by wind:


Figure 2

CST = Concentrating Solar Thermal, in this case it comes with storage. The yellows and oranges are solar of various types, while blue is wind.

Focusing on scenario 2 for 2030:


Figure 3

Capital costs per unit energy, by type. Note the difference between “today” i.e., the first column, and the estimated future costs for the scenario in question:


Figure 4

The estimated capital costs, with the assumption that all the costs are incurred in the final year:


Figure 5

I noted that geothermal is very expensive in that 2030 scenario, and is currently unproven technology (there are lots of practical difficulties once the geothermal source is not close to the surface), so it’s not really clear why they didn’t go for biomass instead of limited geothermal. It seems that there is believed to be some limited, easier to access, geothermal supply close to population centers.

Common to all scenarios is the need to change the timing of demand load.

The most challenging power system design issue, or ‘critical period’, that emerged from the modelling was meeting the evening demand when PV generation decreases to zero on a daily basis.

To manage demand at this time, the modelling shifts the available flexible demand from evening to midday, to take advantage of the surplus of PV generation that typically occurs.

Even so, the majority of dispatchable generation and the largest ramps in dispatchable generation occur in the evening in all four cases. With EV [electric vehicle] recharging possibly being more efficient during the day rather than overnight (when a fossil fuelled system would have surplus generation), installing EV recharging infrastructure at workplaces and shopping centres may need to be considered.

This figure below is using scenario 1 (new technologies), but the changes in demand are in all scenarios:


Figure 6

However, the scenario we are looking closest at seems to have the least requirement for demand shifting, but it’s still there:


Figure 7

Expected DSP increases result from appropriate incentives being implemented to enable consumers to alter the quantity and timing of their energy consumption to reduce costs. This drives a shift in consumption patterns that responds to market needs and takes advantage of high renewable generation availability (usually when PV is peaking) to reduce energy spills.

Scenario 1 assumes up to 10% of demand is available for DSP and Scenario 2 assumes up to 5%. For each case modelled, half of the DSP is assumed to be curtailable load (that is, demand which can be reduced at a given cost) and half is modelled as ‘movable demand’ which can be consumed at an alternative time that day.

Both components of DSP represent voluntary customer behaviour. These are separate to unserved energy (USE), which is involuntary curtailment of customer demand. The reliability standard discussed in Section 5.2 refers to USE only, not DSP.

[Emphasis added].

Key Technical Points

There are four important points that we can see in this report:

  • a requirement for baseload – you can’t generate 100% of electricity from wind and solar, you need some “dispatchable” power source as a backup, either conventional power stations, or, in this case, biomass, and some solar which has the critical addition of (expensive) storage
  • new transmission – when you create a lot of new power generation you need to move it from the new supply locations to the demand centers (mostly cities) – this requires new transmission lines
  • demand management to improve the time of day matching of supply and demand – when you have significant solar there is a problem: peak power is often generated at a different time from peak demand
  • no new hydro – in most developed countries this renewable energy source is “tapped out”

We will look into the transmission issues and costs in future articles.

I’d like to highlight the 3rd point here – in many countries solar PV has been taken up by the population because of “feed-in tariffs” that give the (affluent) PV solar purchaser a kWh buy price many times the wholesale price. And this generous price is for electricity at a time when the grid demand is often low.

However, once solar PV moves from a hobby to a grid necessity, given that there is no conventional baseload, it is a necessity to move demand to the time of maximum sunshine. As a result, demand management seems to have two components:

  • price signals to move demand to times of maximum supply (perhaps new technology, aka smart metering, in each home, perhaps a news report?)
  • storage capacity to allow consumers to purchase at times of low demand or solar PV owners to supply at times of high demand

How does this transition happen? If I had purchased solar PV with a very favorable feed-in tariff for 20 years why would I double or treble my investment to add sufficient storage? (The answer is I wouldn’t). If I am a consumer without solar PV (or with solar PV but no feed-in tariff) what kind of punitive prices do I need to see on my electricity bill before I go out and purchase my very expensive battery pack? And/or what kind of subsidies from the government will be necessary?

It would be interesting to see where these costs of demand management appear – perhaps they are missing from the estimated price tag. If consumers demonstrate impressive resistance it’s not clear whether the 2030 scenario 2 works. That is, demand management may be a project plan dependency and therefore would need to be resolved first.

The Bill

I was surprised by the low price.

However, I was involved as a minor supplier in a commercial energy project (not a renewable) that was fully costed, with a detailed project plan, that had a cost estimate in many $BNs, yet increased by >50% during the life cycle of the project (a few years). Many factors increased the cost: the complexity of the project, escalating contractor costs, technical difficulties that had been underestimated – along with project delays due to land issues and environmental compliance. Some initial assumptions that seemed reasonable turned out to be wrong – and as anyone involved in big projects will affirm – small changes to scope, specification and timing can lead to very large unintended consequences.

Feasibility studies are a great starting point. Lots of projects pass feasibility but actual costs and risks – even before detailed design – turn out to be much higher than anticipated and the project never starts. One way to resolve the problem is to use an EPC (engineering, procurement and construction company) and get a fixed price proposal. The EPC takes the risk – and prices the risk into the job. They also write a specification with assumptions that ensure all variations (like project delays due to land acquisition) are extras. Running very large projects is difficult.

I’m sure no government has obtained an EPC price for a national 100% renewable project. Actually writing the specification would take a couple of years, and getting bids and negotiating the contract probably another year or two. If the price came out at $750BN instead of $250BN I wouldn’t be surprised. Of course, in any kind of competitive bid, intelligent bidders calculate the “missing elements” in the specification written by the client or their engineer, subtract that from their estimate of the final price and bid the difference. So the bid price is the minimum and doesn’t tell you the final bill – but it would have a lot more realism than a feasibility study.

As a counter, “big bang projects” have a huge risk, but changes that can take place incrementally, even ones that radically change the landscape over decades, have much lower inherent risk. If you told someone in England in 1880 that within 70 years virtually the entire country would have an affordable yet amazing new power source called “electricity” for lights, heating, cooking, industry – and a network of roads for motor vehicles that ran on “petrol” (= “gasoline” in America) – they would probably have laughed. “Who will pay for this?” “Where will all this infrastructure come from?”

But all of this did happen. In England the electricity supply was initially from wealthy landowners, private enterprises and municipal projects. Later, the CEGB was formed and took over all the little supply projects, linking them together. Somehow, an entire new industry was formed out of basically nothing. No overall project plan to be seen. Of course, the benefits of creating this system were huge and contributed to economic miracles by way of productivity. It’s a little different when you are displacing an existing system for a new system with the same output.

Of course, another point with the cost comparison is that over the next 35 years much of the current power generation will need to be replaced anyway – at what cost? So the real comparison cannot be “cost of 100% renewable electricity” vs zero, instead it must be “cost of 100% renewable electricity” vs “deferred cost of replacing conventional generation” – with the appropriate discount rates for deferred cost.

Overall, I found it an interesting document – with plenty of good explanations around assumptions. But as well as saying “The AEMO and UNSW studies showed that 100% renewables is viable and affordable..” we could equally say “The AEMO and UNSW studies showed that 100% renewables may be very expensive, with some critical elements that first need to be resolved..”  That’s the great thing about feasibility studies, something for everyone.

For example:

However, to fully understand the operational issues that such a system might pose, it would be necessary to undertake a full set of dynamic power system studies, which is beyond the scope of this report.

In a 100 per cent renewable NEM, there are likely to be instances when non-synchronous technologies would contribute the majority of generation. Many of these non-synchronous generation sources are subject to the inherent weather variations and forecast-uncertainty of the wind, sunshine or waves.

The resulting power system is likely to be one that is at or beyond the limits of known capability and experience anywhere in the world to date, and would be subject to a number of important technical and operational challenges. Many of the issues identified would require highly detailed technical investigations that are beyond the scope of this study.

Transitioning to a very high renewable energy NEM over time would allow more scope for learning and evolution of these challenges. Further refinement of the generation mix or geographical locations could also be applied to overcome particularly onerous operational issues. International collaboration and learning will also be helpful.

Now, just to be clear, none of this relies on new ground-breaking technology. I’m sure it is all solvable. But these kinds of issues are why I think a 2030 scenario is not one that has any relationship with reality.

2030 is “possible”, but there’s a lot of building to do and you can’t start building until you know what you are building, how it will be connected together and how it will be managed and controlled.

If you ask a competent team to work out an actual delivery plan there will be several years of work (at least) just in resolving the technical questions. Your front-end engineering design should be where all the hard work is done. Trying to redesign around new core assumptions once you are in detailed design will cost many times more. Trying to redesign around core assumptions once you are in implementation and commissioning will cost 10x more.

As a pithy summary, a software engineer I once worked with had this pinned above his desk: “Remember, you can save hours of design with just a few weeks of coding.

Readers enthusiastic about renewable energy and frustrated by the slow pace of government action might think I am being unnecessarily pessimistic. Exactly the kind of attitude that the world cannot afford! Surely, there are upsides! Unfortunately, the world of large complex projects is a world that suggests caution. How many large complex projects finish early and cost only 80% of original budget? How many finish years late and cost 3x the original budget? How many apparently simple projects finish years late and cost 3x the original budget?

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


100 percent Renewables Study – Modelling Outcomes, Australian Energy Market Operator Limited (2013)

This field is changing rapidly and so some of these issues may be better resolved than appears from some of the extracts. But it is useful to understand that currently there are limits to the penetration of some kinds of renewable energy on the electricity grid and it is still an area of international research.

In essence the “old-fashioned” power system had lots of big rotating equipment generating power at the business end. This has a lot of inertia – by which I mean inertia in the physics sense, rather than in the sense of institutional resistance..

The rotation is at a speed that generates 50 Hz or 60 Hz depending on where in the world you live. Supply has to match demand on a second by second basis. As the load on the system increases, it slows down the rotation of all of the large generation equipment and this allows two things:

  • automatic response from systems (that monitor the frequency) to increase power
  • flags to the operator to bring other power supply systems online (standby systems, aka reserves)

Wind turbines also rotate but they they don’t act the same as “old-fashioned” power systems – their inertial energy, in most cases, is effectively decoupled from the grid. This isn’t a problem at small penetration levels but the problem increases as the wind power penetration increases. This is called System Non-Synchronous Penetration (SNSP) – although in different places there may be different terms and acronyms.

There is also the critical issue of fault ride-through, which means that if the line voltage drops/collapses – when it comes back the wind farm should continue to provide power. This is critical at high penetration levels, because, without fault ride-through in wind farms, a temporary line voltage drop could take out the entire wind power generation system.

Here is Göksu et al (2010):

Conventional power plants, which are composed of synchronous generators, are able to support the stability of the transmission system by providing inertia response, synchronizing power, oscillation damping, short-circuit capability and voltage backup during faults. These features allow the conventional power plants to comply with the grid codes, thus today’s TSOs have a quite stable and reliable grid operation worldwide.

Wind turbine generator technical characteristics, which are mainly fixed and variable speed induction generators, doubly fed induction generators and synchronous generators with back to back converters, are very different to those of the conventional generators. As the installation of WPPs, which consist of these wind turbine generators, has reached important levels that they have a major impact on the characteristics of the transmission system..

Coughlan, Smith, Mullane & O’Malley (2007):

Renewable energy generation systems are being connected in increasing numbers to power systems worldwide. Of the commercially available systems, wind-turbine generators (WTGs) using non-synchronous-based technology are proving most successful. Unlike the synchronous machine whose operating characteristics have been documented and understood for decades, the generation of bulk ac electricity using non-synchronous machine-based generators is a relatively new phenomenon.

The effects of large penetrations of non-synchronous machine-based generators on power system stability have not been thoroughly studied. This problem is most serious in smaller power systems such as the Republic of Ireland, which have very large proportions of installed wind capacity compared to conventional generation and limited interconnection capability. Such systems are likely to experience possible stability issues related to wind generation, earlier than larger systems having lower proportions of installed wind generation..

..The level of wind turbine modelling detail required for power system stability studies remains an area where there is as yet not widespread agreement. This issue is complicated by the large number of wind turbine designs, the requirement for models in different time-frames, and the application of the model. As the end users of wind turbine models have predominantly been power system operators and due to the general lack of power system analysis expertise on the part of the wind turbine manufacturers, the wind turbine model development process has also proved cumbersome. Models are developed on behalf of manufacturers by third parties and supplied to system operators for use.

As many of the turbine models are not yet mature, system operators have acted as model testers reporting model bugs, irregularities, and errors and often advising manufacturers on appropriate action. Remedial action is then often relayed to third parties who make the necessary software changes.

Zhao & Nair (2010):

Renewable energy generation systems are being increasingly connected to power system networks worldwide. Among all commercially available systems, wind turbine generators (WTGs) using non-synchronous-based technology are being used predominantly. Unlike the traditional synchronous machine whose operating characteristics have been understood for decades, electricity generation using induction machine-based wind generators is relatively recent. In order to allow for the continued penetration of wind generation into electricity networks in the absence of operational experience, dynamic models of WTG have become more important for carrying out stability studies..

.. However, it is generally observed during large-scale wind integration studies that the so-called ‘standard’ components of the wind turbine models are quite often not standardised among manufacturers. Further during simulations, more detailed individual models (i.e. manufacturer-specific models) are used for analysis. The non-disclosure of the model details makes it very difficult to diagnose problems using simulation results. Considerable effort is needed to reproduce the model in a case containing no confidential data..

..Unlike conventional synchronous generators, where injection tests can be employed to test the unit response during a grid disturbance, a wind farm does not provide this option. Utilities rely solely on the WTGs model to determine how they would react to system dynamics, and therefore, the accuracy and validity of the model is important. To date, a very few number of wind turbine generator field test results are published..

..The validation of user-written models with field measurements needs careful planning and preparation, which includes obtaining permission from authorities, the power system operator and the wind turbine manufacturer. Disturbances which the wind turbines and the power system network can be subjected to are often limited. For example, it is not always easy to obtain permission to execute a balanced three-phase short-circuit fault in the transmission network, even though the results of such experiments would be highly valuable for validating the dynamic wind turbine model.

[Emphasis added].

Hansen & Michalke (2007):

Today, the wind turbines on the market mix and match a variety of innovative concepts with proven technologies for both generators and power electronics. The main trend of modern wind turbines/wind farms is clearly the variable-speed operation and a grid connection through a power converter interface.

Two variable-speed wind turbine concepts have a substantial predominance on the market today. One of them is the variable-speed wind turbine concept with partial-scale power converter, known as the doubly fed induction generator (DFIG) concept. The other is the variable-speed wind turbine concept with full-scale power converter and synchronous generator. These two variable-speed wind turbine concepts compete against each other on the market, with their more or less weak and strong features.

Nowadays, the most widely used generator type for units above 1 MW is the doubly fed induction machine. Presently, the primordial advantage of the DFIG concept is that only a percentage of power generated in the generator has to pass through the power converter. This is typically only 20–30% compared with full power (100%) for a synchronous generator-based wind turbine concept, and thus it has a substantial cost advantage compared to the conversion of full power

It seems that many national grid codes have been revised, and also that many people are studying the subject. Zhao & Nair compared wind farm models with reality under a line fault and found quite a discrepancy. However, in that case reality was a lot better than the model predicted, which is obviously a good thing.

A key question is what level of wind power the network can support before “curtailment”. Garrigle, Deane & Leahy (2013) discussed some scenarios in Ireland given that the current system non-synchronous penetration (SNSP) is set by the grid operator at 60%, but might be lifted to 75%.

You might think that a 60% limit on windpower means wind can achieve a penetration of 60% – pretty good, right?

But no. Remember that wind power is an intermittent resource. If wind power was like a conventional “dispatchable” generation source you would keep increasing wind farms and the output would rise up to 60% and then there would be no more wind farms built (until such time as the wind farm electrical characteristics were improved, or other methods of improving grid stability had been introduced).

Taking an extreme counter-example just for the purposes of illustration – imagine that some of the time there is zero wind, and the rest of the time all the wind-farms are running at 100%. And let’s say that the average output is 40% of nameplate capacity – i.e., we have no wind 60% of the time and lots of wind 40% of the time. Let’s say the country needs 5GW continuously and the government target to come from wind power is 40%, or 2GW on average. If we have 5GW of “nameplate” windpower capacity that implies that we can produce our target of 2GW.

However, the grid requires curtailment of any “non-synchronous” source above 60%. So in fact, from 5GW nameplate we will be producing 5GW x 60% for 40% of the time and 0 for the remainder. The result is an output of only 1.2GW, not 2GW – i.e., 24% of the national output instead of 40% of the national output.

Under this extreme scenario, it is impossible to produce the required 40% of national output from windpower.

Of course, this scenario is not reality. But the challenge remains – when the grid requires curtailment the limitation has a greater effect than we might first think.

Garrigle et al studied the effect of wind power curtailment under a variety of scenarios (including a certain amount of offshore wind power, currently a lot more expensive than onshore but less correlated to onshore wind power):

The primary result from this work is an estimate of the required installed wind capacities for both NI [Northern Ireland] and ROI [Republic of Ireland] to meet their 2020 RES-E targets. It is evident that this varies greatly due to the large differences in wind curtailment that will occur based on the assumptions made.

The required capacity estimates range from 5911 MW to 6890 MW which results in extra cost of c. € 459 million between what is considered to be the lowest technically feasible wind curtailment scenario (high offshore wind at SNSP limit of 75%, including TCGs) to that of the highest (low offshore wind at SNSP limit of 60%, including TCGS)

In the context of the electricity system this is a considerable extra expense similar in magnitude to the cost of two of the proposed North-South interconnector between NI and ROI. This illustrates the importance of increasing the SNSP limit as high as technically and economically feasible.

There were also dependencies on the interconnection to the rest of Great Britain. The way to think about this is:

  • can you export power to another country when you produce “too much”?
  • if that other country is also producing significant power from the same source (windpower in this example) how correlated is their output to yours?

Grid interconnections aren’t cheap. And if Great Britain is producing peak windpower at the same time as NI/ROI is producing peak windpower then the interconnections are of no benefit for that particular case.

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


Wind Turbine Modelling for Power System Stability Analysis—A System Operator Perspective, Coughlan, Smith, Mullane & O’Malley, IEEE Transactions on Power Systems (2007)

Assessment of wind farm models from a transmission system operator perspective using field measurements, S. Zhao N.-K.C. Nair, IET Renewable Power Generation (2010)

Fault ride-through capability of DFIG wind turbines, Anca Hansen & Gabriele Michalke, Renewable Energy (2007)

How much wind energy will be curtailed on the 2020 Irish power system? EV Mc Garrigle, JP Deane & PG Leahy, Renewable Energy (2013)

Overview of Recent Grid Codes for Wind Power Integration, Altin, Göksu, Teodorescu, Rodriguez, Jensen & Helle, 12th International Conference on Optimization of Electrical and Electronic Equipment (2010)