Norway Preparing for Balancing European Wind Power

This is a guest post by Paul-Frederik Bach. Paul-Frederik has more than 40 years experience in power system planning. He worked with grid and generation planning at ELSAM, the coordinating office for west Danish power stations, until 1997. As Planning Director at Eltra, Transmission System Operator in West Denmark, he was in charge of West Denmark's affiliation to the Nordic spot market for electricity, Nord Pool, in 1999. Until retirement in 2005 his main responsibility was the integration of wind power into the power grid in Denmark. He is still active as a consultant with interest in safe and efficient integration of wind power.

Since 2007 the end of year water level in hydro storages in Norway has been steadily falling. In 2010 a low inflow of water combined with a substantial increase in electricity consumption has caused Statnett to classify the energy balance in Southern Norway as on “Alert”. This is step 2 of 5, where step 5 is rationing.

Currently, the market seems to be ignoring the decline of such short term energy reserves. This article is an attempt to understand the reasons and perspectives underlying current changes in Norwegian electricity supply policy.

The Skagerrak HVDC link

The Norwegian hydro power system has unique properties. It was designed for the supply of a certain annual quantity of electrical energy (MWh) as needed for electricity supply in Norway, with the consequence that it also offered a surplus of power (MW) as a side effect. Other properties include the considerable flexibility of the generators, and large hydro storage capacity.

The annual inflow of water varies. In wet years it may be 20% above average and in dry years 20% below average. For many years it was Norwegian policy to be self-sufficient in nine years out of ten. The result was a surplus of energy and, in some cases, spilled energy.

In the thermal power system in West Denmark the design criteria was security of supply during peak hours. Due to a low load factor Denmark had a surplus of energy available during most hours of the year.

In 1977 the Skagerrak HVDC power line between West Denmark and Norway went into service with two cables. The total capacity of Skagerrak 1 and 2 was 500 MW.

The agreement between Norway and Denmark on the Skagerrak link made it possible for both countries to save installed capacity. Norway could rely on energy supply from Denmark during dry years, and Denmark could import power during peak hours. Furthermore the agreement included rules for the pricing of Norwegian overflow energy.

The link has been successful, both technically and economically. After the Danish affiliation to the Nordic power market in 1999 the handling of the Skagerrak link was transferred to the market operator, NordPool Spot. Since then approved market operators have access to the capacity of the link on equal terms.

In 1993 Skagerrak 3 (500 MW) was commissioned. An agreement on Skagerrak 4 has been signed, and the 700 MW link is expected to be operational by the end of 2014.

Norway introducing the deregulated electricity market

In 1991 the Norwegian Parliament decided to deregulate the market for trading with electrical energy, with the aim of ending the monopoly era for the power industry and introducing competition. The main objective changed from security of supply to efficiency of the sector.

The immediate consequence was an increased risk to investors and a reluctance to install new power plants, and after a few years the result was a new balance between supply and demand of electricity.

Due to the Norwegian self-sufficiency policy Norway had mainly been a net exporter of electricity, but after 1991 years with substantial net import of electricity also occurred. This indicates a better balance between electricity demand and supply capacity in Norway.

The inflow of water is very low during the winter. Therefore it is necessary to store sufficient energy for the electricity supply until the spring flood, usually at the beginning of May. This is one of the main purposes of the large hydro reservoirs in Norway.

From the end of 2007 to the end of 2010 the storage content has been reduced from 77% to 45%. The falling water level from 2008 to 2010 right before the spring flood seems to indicate that the owners of the storage prefer to sell energy rather than store it.

The year 2010 looked more or less normal during the first half of the year, but during the third quarter a reduced inflow of water and a sustained increase in demand for electricity combined to create a deficit. At the end of 2010 the supply gap was up 30 TWh compared with the previous year.

Sources: and

The shortfall has been met by transforming a 9.1 TWh export into a 7.3 TWh import, and by drawing 15.4 TWh from hydro storage.

Total, theoretical, Norwegian storage capacity is estimated to be about 80 TWh, but since the end of 2007 the end of year content has been reduced by 25 TWh.

There are good reasons for the apparently relaxed Norwegian attitude to low short term energy reserve:

  • Considerable resources abroad will be available for export to Norway if needed. Besides interconnections with Sweden and Denmark, the NorNed interconnection to Netherlands has been in service since 2008.
  • Market prices will respond to a real shortage of electricity. The Norwegian electricity consumption per capita is very high. Therefore the market should be able to balance demand and supply in a reasonable way.

An ambitious interconnection program

Statnett’s Grid Development Plan 2010 (“Nettutviklingsplan 2010”) presents ambitious plans for the extension of interconnections. The plans are based on the following expectations:

  • increasing Norwegian surplus of energy in years with normal inflow of water
  • increasing occurrence of extreme wet and dry years
  • increasing demand for Norwegian system and balancing services

The plan includes the following list of projects, but with reservation for uncertainties:

The Norwegian investments are estimated to between 12 and 20 billion NOK.

Denmark, Germany, the Netherlands, the UK and Ireland are all installing wind power plants in order to reduce carbon emissions and dependency on fossil fuels. These plans all rely on the future availability of foreign services for balancing wind power variations. Smart grid measures for domestic balancing are being developed, but a large scale implementation of such internal measures will probably lag very much behind the policy targets for rapid growth in wind power capacity.

Norway has seen the forthcoming opportunity to sell system services to this market, and new interconnections can go into service in due time for meeting the demand. The total capacity of the interconnection projects may seem tremendous, but it is rather modest compared to the wind power variations which they are supposed to absorb.

This growing business will not affect the security of supply in Norway. The storage capacity is ample for the balancing services and the new interconnections will add to the opportunities for purchasing energy abroad. The bottleneck will be the interconnector capacity.

The European grid expansion will be an important contribution to the integration of an increasing wind power capacity, but it should not be an excuse for the customer countries to postpone the development of local alternatives. Most countries will need to integrate energy systems for electricity, gas supply, heating and transport in order to meet the long term energy policy targets. This will require increased use of electricity and a substantial thermal generation capacity. These changes will require a broad range of new technologies.

The price of the Norwegian services will depend on the alternatives in the countries concerned. If the customer countries have no alternatives, the trade in balancing services will be a seller’s market, with the consequence that the overall cost of wind energy will be needlessly high.

Therefore the customer countries should proceed with the development of clean and flexible generators and local smart grid measures.

This is one of the most informed articles on Northern European hydropower in layman's terms I've seen. Thank you Paul-Frederik for taking the time to explain the situation carefully and thank you Euan for bringing him to TOD. The last sentence is not least, by any means. Nimble generation and smart grid implementation will take us out of the 1950s in terms of managing our electrical power supply.

Good to see Paul-Frederik here.
The laying down of HVDC cables can be relatively quick (China provides some recent very high capacity examples), perhaps a rapid process when compared with major strategic NG pipelines or even construction of some new thermal generation capacity?
Because of the potential high value of connectors for making best use (less waste, better return on investment) of electricity from all sources, even when these are separated by large distances, could we see fairly rapid adjustment to networks in the future? (I seem to remember that Swiss hydro helps 'balance' the massive concentration of nuclear power in France?)
best wishes to Paul-Frederik

Thanks Phil.
I suppose that offshore HVDC links will be an essentil part of the future grid reinforcements because it will be increasingly difficult to establish new overhead lines onshore.

The new 1,000 MW HV DC connector between HydroQuebec and New York City will be overhead in Quebec but mainly underwater in Lake Champlain and the Hudson River in New York State.

It will go above water and above railroad tracks for 87 miles (140 km) where General Electric dumped large amounts of PCBs in the Hudson River and they do not wish to disturb the sediments.

Best Hopes for More HV DC connections,


Actually under the river and/or the lake? Does that imply that someday when (not if) it fails, it will be down for weeks or months - or even forever if some posturing bureaucrat decides arbitrarily that it can't be dug up for repair because some clam might be disturbed?

Yes, covered by water except for that stretch around Schenectady.

I would be careful dredging in the area.


One has to wonder about the Norwegian potential for pumped storage.  If water can be moved from lower to higher reservoirs (or even between watersheds), the net energy capacity of the system might go up considerably.  It would still require more interconnections, though.

I think many of the Norwegian hydro systems empty into fjords - nice reservoirs of brackish water that could not be pumped back up the hill. But many probably empty into lakes creating potential to pump. I don't know if this potential has been assessed yet - perhaps Paul-Frederik can answer?

In the UK we currently have plans for two new pumped storage schemes each with capacity 300 to 600 MW. These are still at planning stage. I'm thinking in Scotland at least we could have huge potential for pumped hydro since we have many low level lochs (e.g. Loch Ness) with high ground alongside. If my understanding is correct, pumped hydro could be environmentally much less damaging than conventional hydro since you don't need to dam a major river system but simply to build a large high level reservoir connected to a low level loch by pipes that flow through a turbine / pump.

There are many places in the mountians of the American southeast where such pumped hydro reservoirs could be built, if the political problems could be solved.It would cost the proverbial arm and leg to build hvdc links from the high plains, where the wind is, to the southeast, but once built, we could make great use of the juice in rebuilding our local area manufacturing economy.

Does anyone know something about the potential for multiple usage of such reservoirs? About the prospects for possible declines in the cost of building hvdc links due to economies of scale in manufacturing the components and maturing technology, expiring patents, as more such lines are built, etc?

Is it customary to bury hvdc lines, on new projects, or to run them above ground, or both?

If a hvdc line or link fails in a spectacular way, say for example due to a fire or earth quake , how long does it take to make repairs, in comparision to a conventional hv transmission line? I know next to nothing about the technology, but my impression is that the end of the line infrastructure at each end of a hvdc line is where the real money is spent and where the potential for trouble mainly lies.Have there been any disastrous failures of these facilities- meaning it took months or years to make repairs-?

My personal gut feeling is that "we ain't seen nothing yet" in terms of rising ff prices.New pumped storage plus wind with either long distance transmission via hvdc, or new pumped storage with new nukes and conventional transmission lines would appear to be the most obvious, and obviously workable , solutions to the need for affordable , dispatchable power over the next couple of decades.

In the end it is not going to be mostly about balancing loads and availability of wind or solar powqer; it's also going to be about saving every possible billion on the purchase of increasingly expensive coal and natural gas.

It would be a real coup for TOD if somebody could persaude an economist with the necessary expertise to write an article about the potential for wind power expansion to slow the inevitable long term increases in the prices of coal and natural gas.I strongly suspect that when this is taken into account that wind, hvdc, and pumped storage are going to prove out as long term bargains.

Many thanks to the author of the article for donating his time and expertise to TOD!

You have touched a tender spot. A very long story could be told about the availability of HVDC links and particularly HVDC cables.
The average availability of the links between Denmark and the neighbouring countries, Germany, Sweden and Norway, is much lower than generally assumed in the super grid analyses.
There are 3 main reasons:

  • Insufficient transfer capability of local grids. This is a matter of grid and market design.
  • Cable damage. Cable repair requires calm weather and may take months during the winter.
  • Transformer breakdown. Transformers for HVDC converters are usually tailored for the purpose. The repair time can be a year or more. Spare transformers have been made for the Skagerrak link.

I am currently collecting recent availability data for the Danish links.

Noatun - Paul Frederik
The HVDC example that I like personally, (I have no expertise or professional experience in the subject) is the 1700km from Inga (hydro) to the copper region in Katanga in Congo. Not exactly wild North Sea, but hazardous terrain nevertheless. Connected in 1982 and undergoing refit last year.
Your data will be very useful in the European context to pinpoint and flag up potential bottlenecks.
Again personally, I wonder if strategic overland connections will be always so difficult to negotiate? We have high concentrations of high voltage AC grid lines crossing the 'attractive' rural area where I live near the Scottish Border (many connect with the Torness nuclear power station; itself subject to shut down and sometimes lengthy repair over the years). Some major AC lines have recently been reinforced. Perhaps a future replacement of just one of these,with some judicious re-routing, could provide a trunk route for a strategic HVDC line? I hope we get access to some of that Scottish wind power by the time Torness finally goes off-line.

HVDC links are extremely useful components of modern power grids. The terminals are quite expensive. Therefore they are usually built for bulk transport in order to keep the cost per kWh transferred down.
Expensive links built for the transfer of balancing power will have a quite high cost per kWh transferred. I suppose that the value of the balancing services can justify the cost.
HVDC links are used for connecting separate AC grids and for reinforcing weak AC grids. I do not know if it was considered for reinforcement of the British grid.
Building new overhead lines is difficult in Germany and unacceptable in Denmark. It may be less difficult in other countries.
Therefore I expect offshore HVDC grids to play an increasing role in the future. One reservation is that multiterminal HVDC links have not yet been built.

One reservation is that multiterminal HVDC links have not yet been built.

ABB has been actively marketing HV DC Lite with multi-terminal capacity, reactive power (Norway will always need some hydro for reactive power unless they use HV DC Lite) and black start capacity.


The Norwegian power system is quite complex with many rivers connecting reservoirs at different levels and a large number of power stations. The potential for adding new capacity of energy (MWh)and power (MW) is being carefully mapped.
I suppose that the need for pumping is limited because inported power can replace hydro production and save water without pumping.
I hope that Norwegian TOD readers will contribute with an adequate explanation.

Paul-Frederik, the idea would be for Norway to go a step beyond balancing to actually begin to absorb European wind surplus when this arises. Its been pretty windy here in Aberdeen today and if we had 5 GW on wind (in Scotland) we would be running a large power surplus that probably wouldn't have anywhere to go.

Set that against the low reservoir levels in Norway, if they could pump using limited modification of some of their existing infrastructure, then they could absorb this surplus and release it next time the wind doesn't blow so hard.

Euan, my point is that the Norwegian power system can absorb the full import from all existing and planned interconnectors without pumping.
But there is no doubt that pumps can be installed if and when they turn out to be profitable business cases.

Its been pretty windy here in Aberdeen today and if we had 5 GW on wind (in Scotland) we would be running a large power surplus that probably wouldn't have anywhere to go.

Norway consumes 130 TWh per year. This corresponds to an average power demand of 15 GW. In the winter it's probably closer to 20 GW and in the summer closer to 10 GW (due to electric heating).

So, as long as the Scottish-Windfarms produce less than 20 GW in February, Norway could absorb everything without having to pump.


Seawater can also work as the pumped hydro fluid and fjords are an idea place to do this. Thus, Norway and California have something in common.

Norway seems to use a system that I call "Deferred Hydro", which has essentially no energy losses above the inefficiency of the generator/turbine (generally about 95% or more). With pumped hydro, there is the loss of pumping water up a height - somewhere between 80 to 85% is about as good as it will get. But maybe electromagnetic pumps can be used because seawater has something in common with sodium metal - it is decently electrically conductive (though nowhere as good as sodium metal). However, it looks like the efficiencies just aren't there yet to make this worthwhile, even with big magnets, so traditional high flow high pressure pumps can be used.

Costs would be a lot less than this one ($744/kw of capacity) because the fjords allow the pumped hydro system to have minimal lengths of piping. See

And this would also allow Norway a means of storing up its humongous coastal wind resource and selling that for peak power rates.


Niobium, I believe all Norwegian hydro networks lie on large freshwater drainage systems. So it would not be permissible to pump marine water into these. But custom built pumped stores using brackish water from fjords may work. But it is the case that at the head of many Norwegian Fjords there are large lakes, that lie adjacent to 1000 m of relief. Ecologically safer to use these than fjords. Pumped storage is the most efficient store in town. Seems there is plenty cross border cooperation on this in the Alps.

Why use electromagnetic pumps? Their efficiency is well below that of a standard centrifugal pump. And mechanical seals for seawater applications are no trouble to find.

Molten metals are the only place I know that uses electromagnetic pumps, because there mechanical seals do not work.

has some efficiency data on electromagnetic pumps. Ironically, one of the main problems is keeping the electrodes clean, which will be real fun in seawater. What doesn't corrode bioslimes.

Actually, just two weeks ago, a study came out that investigated the Norwegian potential for pumped storage (unfortunately in German language, an executive summary in English exists, though without the interesting details). Their conclusions: a staggering 84 TWh storage capacity! Enough to let Norway become the swing provider of European electricity. And the most important about it, it is already there, no need to build additional dams or lakes. Though additional pumps, generators and of course lots of transmission lines to Germany, U.K., Netherlands, Denmark are needed.

The details are on page 227-234 of the study. Also some storage capacity in Sweden (34 TWh) and Austria + Switzerland (30 TWh) are identified.

It is interesting to see in this article that especially in winter remaining storage capacity goes down, as this is exactly the season winds are strongest over western Europe. Thus, a perfect fit!

Do you have a note of the current generating capacity of the Norwegian Hydro system and what Norway uses during peak winter demand?

Hello Euan.
You can get that info from the statnett website. Look at this section. Unfortunately only in Norwegian.

Altogether there is 31800 MW in total in Norway. 450 MW wind, 265 MW small industrial natural gas- and diesel turbines, 915 MW natural gas and 30164 MW Hydro (1336 MW of which is pump turbines).

For the winter 2010/11, 27191 MW is considered dispatchable. (26243 MW Hydro, 926 MW Thermal, 23 MW Wind).

For the winter 2010/11, maximum load is calculated to be 23900 MW (Extremely cold weather, 10 % likelyhood) and 22000 MW (Normal winter temperature, 50% likelyhood)

There is a probability curve for maximum load in the PDF, this curve approaches 25000 MW for the 1-2 percentile.

2000+ hours of storage isn't just great, it's staggering.

Of course, that goes down a lot if it's serving regional demand rather than just national.

Thank you Mr Iswith,

So Norway has 27 GW dispatchable and peak requirement of 22 GW leaving 5 GW to play with. Exisiting links to Denmark are 1 GW and planned links add up to 7.1 GW suggesting a 3 GW expansion of capacity would be required by 2020 to service these links, which is a quite modest expansion.

As Paul-Frederik points out the sum of these links are very modest in relation to continental demand. The vast potential of Norwegian hydro could only be unlocked by fairly massive expansion of generating capacity and pumping capacity. The huge storage figure doesn't get you anywhere without big pipes to release it.

So Norway has 27 GW dispatchable and peak requirement of 22 GW leaving 5 GW to play with.

Peak requirement means that you usually have much more to play with.
Besides the fact, that Norway peak requirements only appear when there's little wind have a small probability: Norway has lots of electric heating which is a flexible load (Norway consumes 60% more electricity per capita than Sweden and 380% more than Denmark) and heating demand is also mostly needed in the winter when wind energy peaks. Electricity prices for endconsumers can be adapted flexibly such that electric heaters will reduce their load when there's lots of demand or increase their load when there's little demand or lots of wind.

The huge storage figure doesn't get you anywhere without big pipes to release it.

This is not really a big issue. Here are 4 examples of Swiss turbine/pump additions on existing dams and this is mostly to benefit from inflexible baseload plants and European demand/price fluctuations: (600 MW) (1000 MW) (1040 MW - 1140 MW) (600 MW)
(And Switzerland has 'only' 9 TWh of hydro storage capacity).

I have been trying to figure out what the last sentence of the post means:

Therefore the customer countries should proceed with the development of clean and flexible generators and local smart grid measures.

I presume this means that countries developing wind should develop lots of natural gas backup generators. The local smart grid measures presumably have to be pretty strong, in order to hold demand down, when supply is not available. I would wonder if the smart grid measures would include the ability to cut off users, when power is not available.

I presume this means that countries developing wind should develop lots of natural gas backup generators.

Actually, small, flexible, efficient combined heat and power plants would be a great fossil fuel saving measure even if absolutely no renewable power plants were to be built:
Combined heat and power plants which power heat pumps which replace fossil fuel furnaces reduce the fossil fuel consumption by 60%. (Figure 7).

More fossil fuel energy is currently burnt in Europe for heating and hot water than what Europe consumes electric energy.

CHP is wasteful.
For every kwh of electricity you produce a kwh of heat whether you want it or not.
So in the dead of winter you produce waste electricity and in the summer you produce waste heat.
Do store the excess heat or electricity?
If not you will produce lots of waste.

The proper course is to reduce space heating per Passivehaus, so that hot water = electricity, before even looking at CHP.
Electricity generation isn't a trival or cheap option below utility scale. Do you want to be responsible for your electricity and heat?

Even hot water can be reduced on an annual basis by using solar
Batteries and hot water have about the same energy density though
storing hot water in giant tanks is cheaper.
Smart metering and large municipal batteries will buffer demand with intermittent supply.

There is no excess winter electricity from CHP plants since all of it can be used for heat pumps.
I would enjoy lots more CHP capacity in Sweden since that would add capacity when we need it the most.

There are excess summer heat when electricity prices are good. In my town Linköping are some of it use to run absorbtion chiller for the district cooling network and thus replace electricity and some is used to heat an outdoor swimming bath.

So in the dead of winter you produce waste electricity and in the summer you produce waste heat.

No you don't because you only need the electricity to power heat pumps which you only need in the winter.

Again, current fossil furnaces are replaced with CHP and heat pumps. This reduces the fossil fuel consumption compared to the fossil furnaces by 60% even if you do not invest in renewable power and insulation.

This is just a simple fact.

Read carefully: I am not talking about replacing the power plants in the grid with CHP plants.
(Although 40 flexible, distributed 10 MW CHP plants with an electric efficiency of 48.7% replacing an old gas turbine have less transformation and transmission losses even if the waste heat would not be used).

Even hot water can be reduced on an annual basis by using solar panels.

So? You can do CHP and solar. But keep in mind if you want 100% solar heating and hot water in the winter you need a considerable amount of thermal storage:

The proper course is to reduce space heating per Passivehaus

Of course it is, but you can't tear down entire European cities and towns and build Passivehaus cities and towns instead. On the other hand, you can replace fossil furnaces relatively quickly.

One of the links today refers to automobile dependent suburbs becoming future slums.But as Anyone points out, we can't simply tear down "entire cities and towns" in Europe, nor can we tear down the American suburbs.

It believe it is VERY likely that existing surburban infrastructure can be satisfactorily up graded in terms of conservation, efficiency, and energy self sufficiency FAR cheaper than new housing can be built elsewhere.

Affordable electric cars suitable for commuting are soon going to be a reality- and everybody who is currently wearing out his present car commuting will find that it will last many many years if reserved for the occasional longer drive or emergency, taking a lot of the sting out of the purchase of the electric commuter car.

Laws can and will be changed, or ignored, in respect to zoning and common carrier motor vehicles, when gasoline supplies eventially get really tight and super expensive.

My elderly relatives will never use computers to shop or arrange a ride, although some of them do cruise the net and use email;but the coming generation will take a virtual tour of the grocery store,order online, and one delivery trip by the store van will save ten trips by car.The lawyer, the cpa, and many other professionals will be able to take care of most former face to face client interactions by means of live video.

Fifty to a hundred thousand dollars even now is more than enough to even now is enough to install a substantial pv system, as well as lots of insulation, solar domestic hot water, triple glazed windows, and other such goodies.

Even in a depressed economy, new houses and associated infrastructure are still going to cost more than this to build-a LOT more.

So you use CHP electricity to run heat pumps?
Why not just use the waste heat? That is the idea of CHP.

What would be logical is to use intermittent wind electricity to make and then store hot water for domestic water and space heating which is what the author is probably proposing--in a way it is a kind of wind CHP turning waste electricity into hot water.
This probably won't work because of grid instability.
The best solution is megawatt battery storage as a buffer which protects the grid against fluctuation.

For example,
CHP(33% heat,33% electricity, 33% waste) versus separated
power(33% efficient electricity and +75% efficient heat)where
heat is 80% of FF consumption and electricity is 20% such as residences probably saves ~20% in overall FF consumption,
CHP would overproduce electricity as to make 80 units of heat you'd need 80 units of electricity and 80 units of waste or 240 units of FF.
A separated system to make 20 units of electricty you need 61 units of FF and to produce 80 units of heat you need 106 units of FF or 167 units of FF total. In a solely residential situation CHP would make no sense as CHP would overproduce electricity by 300%.

In the case of Denmark the country as a whole consumes 1 unit of electrical energy for 1 unit of heat.
In that case a CHP system would produce 80 units of electricity, 80 units of heat and 80 units of waste or need 240 units of FF while a separated system would need 242 units of FF to make 80 units of electricity and 106 units of FF to make 80 units of heat
totalling 348 units of FF. So 240/348 = 69% or a 31% saving in FF.

Suppose you had a country that used 80 units of electricity for 20 units of heat.

Under CHP you'd overproduce/waste 60 units of heat and require 240 units of FF.
Under a separated system you'd produce 242 units of electricity,
plus 27 units of heat and require 269 units of FF. so 240/269 =89%
or an 11% saving in FF.

Here it is the savings versus the cost of a far more complex and expensive FF energy system(CHP), when we should be transitioning away from FF entirely.

Read carefully: I am not talking about replacing the power plants in the grid with CHP plants;(Although 40 flexible, distributed 10 MW CHP plants with an electric efficiency of 48.7% replacing an old gas turbine have less transformation and transmission losses even if the waste heat would not be used).

That's actually worse.

You should be talking about turning power plants to CHP because that is where the waste is. If you can cut heat loss down to a demand of 1 unit of electricity to 1 unit of heat (close to Passivehaus 15 kwh/m2-yr space heat versus 15 kwh/m2-yr electric) then your idea might work. In a 80:20 residential setting CHP is a waste.

The idea isn't to just use the heat pump, or just use the waste heat. The idea is to use both.

A typical heat pump is 400% efficient. That means, it takes 1 watt of input power to produce 4 watts of heat. The extra 3 watts come from the outside air or ground and are moved inside by the heat pump.

Suppose, for example, you needed 4000 watts worth of heat to keep your house warm. So you buy 1000 watts worth of electricity from the power company and run your heat pump with that. But the power company must burn much more gas than just 1000 watts worth, to produce that power. They are 33% efficient. So it costs, all told, 3000 watts worth of gas to heat your house. So this system is, overall, 133% efficient. (4000 watts out divided by 3000 watts in)

Now assume a system where you generated your own electricity in your own house, and ran the heat pump with that. The waste heat from the heat pump also heats the house. Now you have the heat pump putting out 4000 watts of heat, and the generator adds 2000 watts of "waste" heat, for free. You get 6000 watts of heat in the house, and you needed to burn 3000 watts of gas to get it. This system is 200% efficient (6000 watts out divided by 3000 watts in.)

Where do you get 400%?
Is'nt it for geothermal heat pumps?
An air source pump won't even operate below freezing.
Geothermal pumps save about 50% more energy than air AC and 90% AFUE furnaces in swampy Washington DC which is a lot warmer than Denmark.
Geothermal systems costs twice as much as conventional high efficiency gas electric.

If you are talking about the Southern USA, which has long hot summers and short winters and plenty of land to bore holes in you might have a point but in Denmark you'd have problems.

You could use electricity to heat water in a big tank and circulate it for heat.
Really, this doesn't add up.

An air source pump won't even operate below freezing.

What a remarkable statement. Care to substantiate this claim?


Most air source heat pumps put out negligible heat below freezing
for example a 5 ton Trane 2TWB3060A1 (60 MBH) heat pump produces 3 tons of heat(36 MBH) at 32 degF and 2 tons(24 MBH) at 2 degF.
The air handler barely can put out 80 degree air.

Do you think a heat pump that transfers half the heat at freezing or 1/3 the heat when it's 2 degF outside than it does on a summer day is operating practically?

IMO, it's a total joke.

All heat pumps need electric heater back up below freezing or operate inside furnaces as 'hybrid gas heat'.

Okay, there is the mysterious Hallowell(Shaw patent) two stage air source heat pump that operates to -30 degF. To be fair the Arcadia uses 60% more power(41.5 MCA) of a normal 4 ton heat pump(25 MCA). Shaw couldn't sell it to the big HVAC companies.

The idea is not to use more energy right?

Let's be clear. You said "[a]n air source pump won't even operate below freezing" which is patently false. If you had wanted to say that heat output diminishes as temperatures fall, then we wouldn't be having this conversation.

With respect to heating performance, my humble little Sanyo 12KHS71 has a nominal heating capacity of 14,300 BTU/hr at 43°F; 12,660 BTU/hr at 33°F (88%); 11,050 BTU/hr at 23°F (77%); 9,560 BTU at 13°F (67%) and 8,250 BTU at 3°F (58%).


Sanyo's CHX03652, a larger 3 ton unit, maintains 65 per cent of its rated heating capacity at -4°F, so clearly there are air source systems that outperform the aforementioned Trane.


And if you require a heat pump that performs especially well at very low temperatures, Mitsubishi's Zuba-Central operates down to -22°F.


Let's be clear. You said "[a]n air source pump won't even operate below freezing" which is patently false.

And sawdust works as good as transmission fluid.

Don't you think it is misleading to tout heat pumps as heaters when they produce much less heat when it gets cold outside?

Dance on the head of a pin if you like, practically speaking a heater that produces meaningless heat at low temperatures is a fraud (unless you never get low temperatures).

I call that a waste of energy and outright greenwashing.

I think it is reasonable to say something doesn't operate if it puts out less heat when you need it; do we need more heat on warm days?

Your statement is analogous to saying a car that get 50 mpg gas mileage at 20 mph, 30 mpg at 40 mph and 20 mpg at 60 mph saves lots of energy. In a long distance commutes it would suck.

If you noticed I said that heat pumps work in the USA South because of the climate in my comment.
It was also posted in the context of someone claiming that heat pumps fed from grid electricity were more efficient than burning fuel for heat (to the point where people didn't need superinsulated houses like Passivehaus); unless the heat pumps are geothermal that's totally ridiculous.

IMO, any gizmo that increases the amount of electricity consumed just encourages wasteful FF consumption per Jevon's.

OTH, a Passive House uses a tiny amount of space heat so small that minisplits could work( but a pellet stove would work better).

The design temperature for Copenhagen is -12 degC(10 degF) a Sanyo
KHS1271 would produce ~9500 btuh with a 60 degree temperature difference but in the summer with the AC blasting it transfers
~12000 btuh with a 20 degree temperature difference.

That house will get cold without supplimental heating(boiler, electric baseboard).

Minisplits are riding the green energy craze but
are basically energy wasting toys.
Actually in most places outside the Tropics people don't need any air conditioning which is the selling point of heat pumps.

Do you in Halifax even need AC?

You simply don't have a clue of what you speak. I live in a cold climate* and our 43 year old, 2,500 ft2 home is heated by two ductless heat pumps; combined, they displace over 2,000 litres of fuel oil each year.

Our twelve month running average as at January 25th is 10,381 kWh/year and that includes space heating, domestic hot water, cooking and all plug loads.

And if I were to replace the older of our two units with a high efficiency model I could likely get that below 9,000 kWh/year.

All of the electricity we consume is supplied by wind and small impact hydro via Bullfrog Power ( I don't have the option to go "green" if I were to continue to burn fuel oil.

Lastly, if you're concerned that a KHS1271 can't supply all the heat you require at the specified design temperature, simply select a larger system such as the 36KHS82; it provides 33,000 BTU/hr @ 43°F and 21,770 BTU/hr @ 13°F.


* February 1st: high: -6.0°C/low: -16.0°C; February 2nd: high: -10.0°C/low: -19.0°C; February 3rd: high: -8.0°C/low: -20.0°C; February 4th: high: -6.0°C/low: -14.0°C; February 5th: high: -10.0°C/low: -16.0°C; February 6th: high: -10.0°C/low: -17.0°C; February 7th: high: -1.0°C/low: -14.0°C.

Halifax has about 7570 degree days per year and the winter design temperature is 4 or 5 degF(+10 degF).

You feel you can heat a 43 year old 2500 sf(232 m2) house with a 3 ton unit producing 21,770 Btu/hr 8.7 Btu/hr per SF at 13 degF?

Let's backcheck this based on 2000 liters of fuel oil per year which contains 73.3 Mbtu of FF energy. 73.3 Mbtu x(65-10)/(24x7570)= 22,190 Btu/hr (16,642 Btu/hr net). Assuming the furnace is 75% efficient that works out to a microscopic 6.6 Btu/hrSF of space heating.

Two 12KHS71s would put out 17,600 Btu/hr at design temp of 10 degF
or 7 Btu/hrSF.
That's really very good insulation(or the house is smaller) given that basements are about 12 Btu/hrSF.

A superinsulated Passivehaus is recommended to have the 'impossible' 10 W/m2 which is 3.17 Btu/hrSF.

The HPSE rating for the two Sanyo unit is 9.3.
That means it should use about 10000 kwh/year of electricity for space heating; (2 x 0.77 x (7570x24/(65-10)) x 16,642 )/(1000 x 9.3) = 9103 kwh/yr. The 3 ton unit would take 10170 kwh/yr.

By contrast electric baseboard sized for 16,642 Btu/hr net would take 16107 kwh/yr of electricity and a +90 gas furnace would take 600 therms of gas or 17584 kwh/yr of natural gas energy.

Even grid electricity from CCGT(54% with 10% transmission loss) at 50% delivered efficiency with minisplit heat pumps would be less efficient that high efficiency gas furnaces; 9103/50% > 17584.

You use 10,318 kwh/yr of electrity for everything
which compares how the per capita residential electricity consumption in Nova Scotia(Fig 4.9) in 2005 at ~4500 kwh/yr person?

I'd say your house is much better well-insulated than most to the point where a minisplit would make sense if you wanted AC and you had cheap renewable electricity.

This was the point I was making before about the need for superinsulation first(Passivehaus), which wasn't necessary according to the commenter I was originally responding to.

You feel you can heat a 43 year old 2500 sf(232 m2) house with a 3 ton unit producing 21,770 Btu/hr 8.7 Btu/hr per SF at 13 degF?

21,770 BTU/hr is 6.4 kW of heat and multiplied by 24 hours that comes to 153 kWh per day. Add in the additional heat generated by occupants, lighting, appliances and other plug loads and the final tally is likely to exceed 160 kWh; frankly, if a home leaks that much energy over the course of 24 hours then there are more serious matters at hand. And if you don't consider a 3 ton system sufficient for your needs, you always have the option of installing a larger capacity system.

Let's backcheck this based on 2000 liters of fuel oil per year which contains 73.3 Mbtu of FF energy. 73.3 Mbtu x(65-10)/(24x7570)= 22,190 Btu/hr (16,642 Btu/hr net). Assuming the furnace is 75% efficient that works out to a microscopic 6.6 Btu/hrSF of space heating.


This is an account of our fuel oil consumption since date of purchase. Our first heat pump was installed in August 2005 and in the winter that followed it displaced approximately 1,100 litres of fuel oil.

     2002 - 2003
       Date      Litres    $/L        Cost       Days    L/Day
     09/12/02     53.5    0.479      $29.47        31     1.73
     09/18/02     36.8    0.499      $21.12         6     6.13
     11/04/02    161.3    0.529      $98.13        47     3.43
     12/04/02    196.9    0.529     $119.78        30     6.56
     12/28/02    208.7    0.549     $131.76        24     8.70
     01/18/03    245.6    0.559     $157.88        21    11.70
     02/21/03    497.1    0.649     $371.01        34    14.62
     04/04/03    440.4    0.589     $298.30        42    10.49
     07/29/03    241.3    0.509     $141.24       116     2.08
               2,081.6    0.572   $1,368.71       351     5.93

     2003 - 2004
       Date      Litres    $/L        Cost       Days    L/Day
     10/06/03    107.2    0.499      $61.52        69     1.55
     12/16/03    388.4    0.525     $234.50        71     5.47
     02/01/04    632.6    0.525     $381.93        47    13.46
     03/16/04    513.7    0.525     $310.15        44    11.68
     05/19/04    320.5    0.525     $193.50        64     5.01
               1,962.4    0.524   $1,181.59       295     6.65

     2004 - 2005
       Date      Litres    $/L        Cost       Days    L/Day
     09/07/04    217.0    0.629     $156.97       111     1.95
     12/10/04    330.3    0.629     $238.92        94     3.51
     01/28/05    523.7    0.629     $378.82        49    10.69
     03/09/05    514.3    0.629     $372.02        40    12.86
     05/24/05    388.0    0.629     $280.66        76     5.11
               1,973.3    0.629   $1,427.39       370     5.33

     2005 - 2006
       Date      Litres    $/L        Cost       Days    L/Day
     08/15/05    107.7    0.765      $94.75       83      1.30
     12/08/05    161.4    0.749     $139.02      115      1.40
     01/21/06    154.4    0.779     $138.32       44      3.51
     03/10/06    291.7    0.769     $257.96       48      6.08
     05/25/06    113.1    0.839     $109.12       76      1.49
                 828.3    0.776     $739.18      366      2.26

     2006 - 2007
       Date      Litres    $/L        Cost       Days    L/Day
     09/08/06    129.3    0.819     $120.73       106     1.22
     01/11/07    193.9    0.759     $156.00       125     1.55
     04/18/07    462.0    0.819     $401.08        97     4.76
                 785.2    0.804     $677.81       328     2.39

     2007 - 2008
       Date      Litres    $/L        Cost       Days    L/Day
     09/17/07    163.3    0.809     $140.05       152     1.07
     01/23/08    335.5    0.889     $313.17       128     2.62
     04/29/08    226.3    0.889     $211.24        97     2.33
                 725.1    0.871     $664.46       377     1.92

     2008 - 2009
       Date      Litres    $/L        Cost       Days    L/Day
     10/24/08    152.2    0.969     $154.85       178     0.86
     02/23/09    160.6    0.679     $114.51       122     1.32
                 312.8    0.820     $269.36       300     1.04

     2009 - 2010
       Date      Litres    $/L        Cost       Days    L/Day
     08/24/09     79.8    0.759      $63.59       182     0.44
                  79.8    0.759      $63.59       182     0.44

Our second heat pump was installed in late December 2008 and in the year that followed we used less than 80 litres (we operate the boiler during extended power cuts as needed and we also exercise it from time to time to help keep things in proper working order). Our last fill was 533 days ago and the gauge is currently resting between 3/4 and 7/8th (900 litre tank).

Our base line consumption is approximately 10 to 12 kWh/day or about 4,000 kWh/year (we operate our dehumidifier from May through October and this nearly doubles our off-season usage). That leaves some 6,000 kWh that we can largely attribute to space heating -- multiple this number by a seasonal COP of 2.74 and this represents roughly 16,500 kWh of delivered heat, or about the same amount of heat as would be supplied by 2,000 litre's worth of oil. Thus, the numbers seem to jive reasonably well for me.

Back to my point -- air source heat pumps work well even in colder climates and, as in our case, they can operate on 100 per cent renewable energy.


Halifax is NOT cold at 10 degF winter design by Canadian or even northern US standards and is comparable in terms of cold with BC or Toronto though the chilly weather lasts a lot longer. It may feel colder because of the humidity but the heater doesn't feel humidity.

We fundamentally disagree on the definition of 'work well'.
IMO even the best of them(air cooled minisplits) operate/work poorly at subfreezing temperatures especially in a house with standard levels insulation. With COPs less than 2 they are barely better than baseboard and the usual practice is to add cheap resistance heat as a backup rather than buy twice the heater capacity.

Halifax comes in at 7,570 HDD and Buffalo NY is 6,693. I guess that makes Buffalo a tropical paradise by comparison.

Give it up.


The winter design temperature for Buffalo is -5 deg F and Halifax is 10 above.

But by the internation climate definition Halifax is colder (>7200 dd).

OTOH plants find Halifax to be less cold than Buffalo.

As I had stated above, Sanyo's CHX03652 maintains 65 per cent of its nominal heating capacity at -20°C/-4°F. Mitsubishi's Zuba-Central delivers 100 per cent of its rated capacity at -15°C/5°F and 75 percent at -25°C/-13°F. I don't see a problem here, do you?


Yep, I still have a problem despite manufacturer's claims.

It's a little thing called the Carnot principle which states
efficiency= Work/ Heat = 1-Toutside/Tinside which defines the efficiency of the most efficient heat engines theoretically possible(reversible ones).

A heat pump is a heat engine in reverse so Heat/Work = Tinside/(Toutside-Tinside).

Obviously the greater the temperature difference the greater the required Work
for the same amount of heat.

You see I was brought up to obey the Laws of Thermodynamics.

Apparently the Laws work differently in Nova Scotia.

So now the manufacturers of heat pumps and, by extension, the ASHRAE are lying to the public. Why don't you launch an official complaint with the FTC, or is the government part of this great conspiracy as well?

I must say, this keeps getting better and better.


I struggle to see what Maj's point actually is - it is obvious that when sizing a heat pump the design point is the combination of lowest outside temperature and highest heat demand and that efficiency, heat output and power (not energy) consumed all drop with temperature. It is no more oversizing to specify a heat pump's performance based on the worst case temperature situation than to specify a car based on hauling a caravan you a hill even though you rarely need that much power.

One beef I do have with heat pump manufacturers is that they sometimes quote the nominal output at a silly outside temperature (20ºC seems quite common and I saw one using 40ºC!). Not all those available in the UK graph output against temperature either which ruled them out when I bought one.

I struggle to see what Maj's point actually is - it is obvious that when sizing a heat pump the design point is the combination of lowest outside temperature and highest heat demand and that efficiency, heat output and power (not energy) consumed all drop with temperature. It is no more oversizing to specify a heat pump's performance based on the worst case temperature situation than to specify a car based on hauling a caravan you a hill even though you rarely need that much power.

Precisely. Past practice in North America has been to size heat pumps based on cooling rather than heating loads so as to ensure good dehumidification. As a result, heat pumps are often undersized for our heating needs and a back-up source of heat (typically electrical resistance) is required to bridge the gap. Dual stage compressors have helped to address this problem and with inverter-drive systems, we now have the opportunity to size this equipment more appropriately. [That doesn't mean you'll want it to cover-off 100 per cent of your needs; it may be more cost-effective to simply let the remaining 5 or 10 per cent be handled by something else such as electric resistance.]

One beef I do have with heat pump manufacturers is that they sometimes quote the nominal output at a silly outside temperature (20ºC seems quite common and I saw one using 40ºC!).

That does sound rather dodgy -- performance ratings based on higher operating temperatures may be appropriate in some industrial applications where source temperatures are higher and more uniform (e.g., heat pump water heaters operating in commercial laundries), but certainly not the residential sector. In North America, nominal heating capacity is rated at 47°F/8.3°C and most manufacturers also note output at 17°F/-8.3°C.

Not all those available in the UK graph output against temperature either which ruled them out when I bought one.

Years ago, Bob Kerr hosted a popular afternoon music programme on CBC Radio entitled "Off the Record" ( Bob was always lamenting the lack of liner notes in albums because their inclusion told us so much more about the music and artist. I share a similar frustration when it comes to heat pumps. Granted, most consumers could care less, but it is helpful information to some of us. It's also one of the reasons why I chose Sanyo over some of the other offerings.


Some quite interesting data there, thanks for posting
I see that you need around 45kWh per day in the winter
(I had been wondering (for another unrelated reason) how much storage would be required per day in cold climates - now I have a good idea)

You're most welcome. I've logged hourly temperature data since our date of purchase and match this to our fuel oil consumption and heat pump output and, with that, estimate our home's demand point as 13°C and its average heat loss as 0.175 kW/°C when temperatures fall below this. This is a rough approximation and there are other factors that come into play, in particular, wind which can skew the numbers rather dramatically at any one point in time, but it's a workable guide.

Over the past twenty-four hours, our high and low were -5°C and -17°C respectively, for average temperature of -10.4°C; if my calculations are more or less correct, this suggests a space heating requirement of approximately 98 kWh beyond what would have been meet by other internal heat gains (all of which, I might add, supplied by our two ductless heat pumps).


Hi Paul,

I appear to have lost you at the turn. Are you saying that at the relatively balmy temperature of average -10.4C the heat pumps are using 98kWh divided 2 for the day (67% of 3:1 optimum conversion efficiency)? That doesn't gell really well with the 49.5 kWh a day total use for your last bill, so I'm guessing either I got something screwed up or this sort of weather is rather cold for you, or both.

I use maybe a bit less than 3 gallons #1 diesel a day at those temps. Your house is slightly larger and somewhat older than mine. I'm just kind of trying to get a real handle on heat pump power cost in moderately cold weather. When it really drops here I can burn five gallons a day. I use about 750 US gallons a year. I'm guessing we've 5-10% fewer heating degree days than the 14000 or so town has--with luck the school the other side of the hill (doing the solar thermal ground recharge experiment) will have good data for all that in a year. Those ductless air source heat pumps just seem so simple and if some can get 75% efficiency at -15F it would seem not too difficult to build new with them in mind.


Hi Luke,

My apologies for the confusion. The 98 kWh estimate is the amount of heat that would be required to keep our home at its set temperature over this 24-hour period. The actual amount of energy consumed would be less than half that as the heat pumps' COP at this temperature is approximately 2.4 (at -10.6°C/13°F, the Sanyo KHS12 supplies 9,560 BTU/hr or 2.8 kW of heat and draws 1,165-watts). Thus, we're looking at about 41 kWh of electricity demand in all.

As a cross check, we've used a total of 980 kWh in the nineteen days since our meter was last read -- an average of 51.6 kWh/day -- and if I were to subtract 10 to 12 kWh/day for cooking, laundry, domestic hot water, lighting and various plug loads, that leaves roughly 40 kWh/day leftover for space heating purposes, which sounds about right. In terms of operating cost, 40 kWh/day x $0.125 per kWh = $5.00. If those 98 kWh of heat demand were met by our oil-fired boiler (82% AFUE), the cost would be more than twice that (11.2 litres x $1.00/litre = $11.20).

Just to clarify, the Mitsubishi Zuba-Central provides 75 per cent of its nominal heating capacity at -15°F. I don't have any information on its COP, but we're told that it continues to operate down to -30°C/-22°F and that its minimum COP is 1.4, which is presumably at this low temperature. Our Sanyo KHS12 is rated down to -18°C/0°F but, in reality, still produces a reasonable amount of heat all the way down to -25°C/-13°F, at which point it suspends operation, so I wouldn't be surprised if the Zuba has a little extra wiggle room at the low end.


Even grid electricity from CCGT(54% with 10% transmission loss) at 50% delivered efficiency with minisplit heat pumps would be less efficient that high efficiency gas furnaces; 9103/50% > 17584.

Actually a power plant with a 50% electric efficiency powering Heliotherm HP10L-WEB air source heat pumps would be close to double as efficient as a high efficiency gas furnace:

Most air source heat pumps put out negligible heat below freezing

No they don't.

For example the Heliotherm HP10L-WEB air source heat pump has a COP of:
4.2 at 2C (35F)
3.4 at -7C (19F)
2.8 at -15C (5F)

So you use CHP electricity to run heat pumps?
Why not just use the waste heat? That is the idea of CHP.

You use both. The waste heat of the CHP plant heats an office building or an industrial complex and its electricity powers heat pumps in many homes at different locations.

1 unit of gas produces:
0.44 units of heat and 0.48 units of electricity with this CHP plant:
0.48 units of electricity produce 1.92 units of heat with a COP of 4.
So you end up with 0.44 + 1.92 = 2.36 units of heat with 1 unit of gas.

Therefore, compared to a fossil furnace you save 60% of gas.

By the way, if you replaced fossil furnaces with heat pumps and powered them with a combined cycle gas power plant (no usable waste heat) you would still come to a similar result.

The idea is that 100 MWh of fuel for an ordinary powerplant gives say 35 MWh electricity and
65 MWh waste heat. 35 MWh * heat pump efficiency of four gives 140 MWh residential heating.

CPH gives say 30 MWh electricity, 65 MWh heat 5 MW waste heat. Distribute those 65 MWh via a district heating network and get 60 MWh to the customers. 30 MWh electricity * 4 gives 120 Mwh heat pump heating for a sum of 180 MWh heating.

A district heating network is best in densely populated areas sine it gives lower capital costs och losses, the equipment in the houses is cheap.
Heat pumps needs a slightly more powerfull grid but the cost is minor but ground source heat pumps are expensive, the equipment for the house is expensive.

Air source heat pumps are much cheaper but do not work well with low air temperatures.

Low hour by hour electricity prices when wind power is overproducing and customers buying cheap power for heating tap water, a heat accumulatir or the house when power is cheap is a good old idea. The price variations during day and night can also be used to even out the load, simply use the heat pumps more at night.

CHP and hour by hour pricing creating a market incentive for a "smart grid" is good for the system stability as is district heating with large thermal masses in the system.

No you don't because you only need the electricity to power heat pumps which you only need in the winter.

Indeed.  It's depressing that people can hang out here for so long and ignore the analysis and figures posted in detail years ago.  It's almost like some minds are impervious to facts contrary to their currently-held dogma.

Thanks for the link to your post--nice and simple way to frame it. The Maj doesn't like electric trains, cogen or heating with heat pumps I guess. If he had the final say that would certainly thin out the viable paths forward. I gave heat pumps a quick look but with 14,000 heating degree days or so a year and electricity coming mostly from oil and coal selling at near $.20 kwh I opted for a pellet boiler for my stopgap system.

I am wondering just how much the district heat needs of the cogen coal plants we have in the area will affect the decision making process on just how large a hydro project to pursue. We have no place to sell power we can't use up here. I'm hoping to get some good answers by the end of the month.

My main story was the Norwegian preparations for meeting a large European demand for balancing services.
My concern is that the European countries developing wind will rely too much on Norwegian services. I am convinced that these countries will need a combination of foreign and domestic balancing services.
Flexible generation and smart grids are complex issues beyond the scope of my story.
There are no easy solutions. We will need fossil fuel for many years. The EU dependency on imported gas is growing. We are about to replicate the dependency of imported oil prior to 1973. Therefore we must develop a broad range of measures in order to improve energy efficiency and reduce the import od fossil fuel.
The discussion on CHP seems to be very confused and I do not understand the calculations. If you compare Sankey diagrams for the UK and Denmark it is obvious that the power stations in the UK have a remarkably high waste of energy.
In Denmark CHP based district heating is the main source of heating. Practically all power plants i Denmark are CHP-plants.
The bad news is that both wind power and CHP need electricity demand. Therefore we have an overflow of electricity during winter.
The good news is that overflow electricity can be convertet to heat and stored in the district heating systems. The conversion can be made by heat pumps and electric heaters.
It is important to understand that the design of the Nordic spot market has made an efficient coordination between power system and heating systems possible.
The Danish CHP systems are already active market participants. I have analysed the potential for a future with 50% wind energy in Denmark, see
I expect that the district heating systems quite soon will be able to absorb considerable wind power variations while the smart grid measures involving electricity end users will require a longer development and implementation period.

The Karahnjukar Hydropower plant in Iceland was originally conceived of as a 2 GW peaking power plant for export. Instead it was built as base load plant to smelt aluminum.

It could be re-engineered to supply not only the aluminum plant, but also 1 GW of export power for up to a month (or longer) if it was repaid in kind.

Iceland has enough baseload electrical demand served by hydropower to accept slightly over 1 GW of electrical imports by holding back water when wind is in excess of demand in Scotland, Ireland, etc.

HV DC Lite (ABB) or HV DC Plus (Siemens) is capable of multi-drop applications, supplies reactive power and blackstart capacity.

Consider a 1.2 GW HV DC Lite line starting at Burfell (south Island) and continuing on to the Alcoa aluminum plant served by Karahnjukar in East Iceland, then the Faeroe Islands (either absorbing excess wind there or supplying hydropower), Scotland and Northern Ireland.

It would transport excess wind power north and supply hydropower when required.

In addition, 9 out of 10 years, Island spills 150 MW of hydropower in the summer because they they have no use for it. And lots of wind potential, and summer hydro potential that has not yet been developed.

Any thoughts ?

Best Hopes,


Am I wrong or is Iceland far from pretty well anywhere?

I got Dublin to Reykjavic 1500 km. Greenland to Reykjavic 1200 km
Newfoundland to Rekajavic 2600 km

Where would Iceland export electricity to?

Start in Burfell, southern Iceland, overland (along the coast) to East Iceland and then onto the Faeroe Islands and then landfall in northern Scotland, after the drop in the Faeroe Islands. Overland in Scotland and then to Northern Ireland and the Irish grid.



Desertec is promoting that idea exactly. While they mostly talk about CSP from deserts, the plan is actually for a EU-MENA supergrid that incorporates wind, biomass, hydro, PV and geothermal from Iceland. Here is the rough idea, though this is clearly an artists rendition.

Given the large hydro resources in Norway, they might want to start including those HVDC lines ;-)

UK government thinking flies close to this concept:

The 2050 Pathways report (250 pages) is a thorough examination of sustainable energy (without hot air).

It is curious how this EU concept manages to avoid Norway - Europe's main power house, not even showing the existing links!

Thanks for the update. I'm not all that familiar with the North Atlantic geography.

It is still two 400 km sections through moderately deep water (400-550m deep to get to the Scotland coast.

It looks to be possibly feasible technically, but I would guess it to be a very expensive alternative.

My thoughts are that it's better to make aluminum with Icelandic hydropower than Chinese coal.

At 14500 kWh/ton, 1 GWe yields 69 tons/hr, 1655 tons/day, 604000 tons/year.  China produces more than 20 times that much; I'd say that Iceland should get busy building dams and smelters, and let the undersea cables come if they will.

That 1 GW would be balancing generation. Iceland would need to import wind power of = MWh either before and/or after to meet the needs of the Alcoa smelter that Karahnjukar supplies (steady 540 MW from memory, but Alcoa wanted a bit more after opening). Landsvirkjun would just speed up and slow down Karahnjukar after re-engineering the complex plant, with small additional MWh/year. Speed up to 1.6 GW total for a bad week or two in Scotland, but get that power back and run, say, a quarter of the Icelandic load off imported power for several weeks to balance the ledger.

Almost 90% of Icelandic power is used for "power intensive" industry. Most of that is steady 24/7 demand and the rest of the demand is winter peaking (greenhouse lighting, the 8% or so of homes w/o geothermal heat, street & general lighting, etc.)

Geothermal generation is flat 24/7 and ideal for flat demand but it is about 1/3rd of Icelandic generation. Water becomes a solid for much of the year in Iceland (kind of obvious :-) and only hydropower projects with access to large amounts of liquid water (reservoirs), enough for 5 or 6 months generation, are built.

Also, hydropower generation is built for a dry year, which means that, 9 out of 10 years, that there is an unused summer surplus of 150 MW.

Iceland has tremendous wind resources, winter peaking, and summer hydroelectric (small reservoirs or run-of-river). With balancing from their installed hydroelectric plants (all with enough water to get through winter), their renewable generation could be significantly increased.

Best Hopes,


Only bad news is hydroplants makes minced meat of the river ecosystem. If the river ends in a delta, it mess up the delta as well. (See Colorado, Mississippi, the Nile for good examples). If that delta is breeding ground for fish (often the case), you mess up the ecosystem in the see as well. Luckily for the scandinavian rier systems they don't end in deltas. But it is still a local disaster in that river. There just is no free meal.

I really like this article. It provides a balanced and cautious approach toward the integration of hydro and wind power that implies the best use of each power sources underlying operating properties and it does not make spurious claims that this integration is an all encompassing solution. The key underlying properties of hydro power are large amounts of storage and fast spin up time. Essentially, this means that when the wind drops, it is possible to quickly open up a gate on a penstock (the pipe leading from the reservoir to the generator), and replace the lost wind power quickly (the time frame is typically on the order of 1 minute).

Note that the hydro power is available without the big disadvantage of having to have a fossil fuel plant idling away just in case the wind drops. I believe that the requirement of a fossil fuel plant of equivalent capacity as back up for installed wind power capacity is what Gail is referring to in her question about back up plants.

I think that this post makes it clear that the ideal way to integrate wind and hydro would be to only run the hydro plants when the wind is not blowing subject to constraints on storage capacity in the hydro system and availability of stored water.

The article also makes it clear that there is a limited amount of power that can be generated using hydro power. Currently, hydro power produces something like 6% of electric power. Most of the rivers that can easily be dammed in the continental US and Western have been dammed. It is important to recognize the limitations on expansion of hydro power.

I believe that there is significant hydro development in the Northeast and Maritime Canada, the Southeast, the Pacific Northwest and British Columbia that could be combined with near coastal wind generation to good effect. I have often wondered why this isn't happening. Somehow the arguments against doing this (which seem to amount to damage to migrating bird populations and damage to water views) seem a bit weak.

I believe that there is significant hydro development in the Northeast and Maritime Canada, the Southeast, the Pacific Northwest and British Columbia that could be combined with near coastal wind generation to good effect.

There's been some movement in that direction here in Atlantic Canada; to whit:

The electricity generated at Muskrat Falls will flow from Labrador as far as the Northeastern United States via several new and upgraded transmission lines, including a 180 km subsea link that will be built by NS Power between Cape Ray in Newfoundland and Sydney, Cape Breton. You can read more about the specifics of these projects here.

Certainly, I believe this agreement is representative of a growing sense of energy independence, self-sufficiency and even pride among many Newfoundlanders and Labradoreans. For Nova Scotia, this new source of energy will help us achieve our renewable energy goals, such as reaching 40% renewable generation by 2020 and will allow for greater interconnection of intermittent sources of renewable generation like wind and tidal energy that could use the new and upgraded transmission lines.


See also:


As far as I understand it, the hydro developments in Newfoundland and Labrador tap some rivers that are a bit farther north and a bit harder to get to than previous hydro developments. They also get around some jurisdictional disputes within Canada that have prevented these developments from coming on stream.

I think that what this article points out is the key role that hydro can play in providing on demand backup power for wind development. I haven't seen is effective efforts for integrate these developments with wind power.

For the most part, the wind blows a lot more steadily and a bit harder a mile or two off the coast than it does on land. The water is often shallow (200 feet deep, not thousands of feet deep). I suspect that it would be easier to build some platforms in shallow water and lay a mile of under water cable to connect the power to the grid, than to lay underwater cables for hundreds of miles under the sea or to build HVDC lines for thousands of miles from Wyoming or North Dakota to bring power to the East Coast.

I still don't see it.

It seems like a no brainer to me.

Offshore construction is MUCH more expensive. Salt water is a major problem (not an issue in the Great Lakes), Jones Act applies to all wprlers (US waters), building stable platforms on underwater sediments can be a big problem and adds LOTS of costs.

However, importing wind from Iowa and offshore gives geographic diversity. One may be blowing when the other is not.


I have no doubt that building in shallow water is more expensive than building on land. Salt water is far more corrosive than freshwater. I believe that Spain has had problems with tidal power from corrosion. However, building platforms in shallow sea water is feasible technology. The oil industry has hundreds of platforms (both resting on the bottom and floating) that are currently in use. It is obvious that wind turbines could be placed on similar platforms. It is likely that cheaper alternative platforms could be designed. The technology is technically feasible.

It should be noted that technically feasible does not mean economically viable. I guess that there is little point in arguing about the costs in a qualitatively. It would be nice if there is someone around who has tried out some ideas and run the numbers. Higher wind speed, more constant wind, and proximity to demand centers add value. Extra construction costs and damage to equipment from salt water are negatives for sea based wind turbines.

Wind turbines exert an large "lever arm" force against their platforms. A strong wind blowing against idled wind turbine blades, force transmitted to the hub xx meters above base, with pivot of lever in the base. Big #s.

More force than oil production platforms.


The East Coast of Canada has a major problem with icebergs drifting down from the Arctic Ocean. An offshore oil platform must either be a massive concrete gravity base structure that can survive a collision with an iceberg, or be an FPSO ( floating production storage and offloading) unit that can drop its anchors and run for safety when an iceberg bears down on it.

Offshore wind turbines would have similar problems with icebergs.

The West Coast of Canada doesn't have a problem with icebergs, but it also doesn't have a problem with a shortage of hydroelectric power potential. It's similar to Norway, but much bigger.

If the following article, based on Statistics Canada data, is to be believed, the West Coast of Canada has operated in a fairly similar fashion to how the Norwegian system operated before the expansion in wind power. It is now facing the prospect of a shortage of power in the next decade or two. Responses have included incentives for small hydro development, a proposal to build another large dam, and calls for conservation based on incentives and proposals to increase electricity rates. (

It should be pointed out that this system is heavily integrated with the Bonneville Power Authority and significant flows of power go back and forth across the border to balance loads and to facilitate sales further south along the coast.

There has been no serious attempt to integrate the system with wind power.

There is an estimated 160,000 megawatts of undeveloped hydroelectric potential in Canada, versus the 70,858 MW already installed, but most of the undeveloped potential is in Northern Quebec, Northern BC, and Yukon Territory. See Hydropower in Canada: Past Present and Future

Wind power has potential in some parts of Canada but must compete against the abundant undeveloped hydroelectric potential. It would be easy to balance wind with hydro, but in most provinces it is also feasible to supply the entire demand with hydro.

The problem areas are Ontario and the Maritime Provinces, who have insufficient hydro potential and had to use a mix of nuclear and coal to fill the demand.

Ontario has a problem in that its people got used to cheap hydro power from Niagara Falls, the nuclear plants they built didn't last nearly as long as they expected, and anything else they develop won't be nearly as cheap, including wind.

No doubt that your assessment pretty much correct. The upside for Canadian hydro development is that there are a number of potential hydro sites that have not been developed. The downsides are that they are far from demand centers and located in fragile environments with difficult building conditions. Perhaps if prices go up and improved transmission capabilities such HVDC are brought on stream, more of these hydro sources will be put into use.

It is important to keep enthusiasm for balancing wind power with hydro in check (which is something that this article does well). For North America as a whole, hydro provides something like 6% of electric power. If the Canadian sources were all developed that percentage might well go up to 10%.
The experience in Europe has been that hydro works to balance wind power with between 10 and 20% of system capacity. Even if fully developed, the hydro capacity could be used to support 3% of system capacity from wind generation. 3% of system capacity as wind generation is a tripling of wind generation capacity over current levels, but clearly not the solution to the replacement of fossil fuels with renewable power.

While the sheer scale of Norway's overbuilt hydroelectric power system certainly makes using these interconnects for balancing wind power economically viable, the discussion is not complete without mentioning less geographically-constrained power storage options like reversible heat pump electric power storage in hot & cold reservoirs.

Ok, so I'm a one-trick pony :-)

When I mentioned it yesterday AlanFromBigEasy replied that it would probably have a limited round-trip efficiency and a short storage lifetime. The creators joined in a discussion of these limitations in the comments on this article:

The relevant numbers mentioned are 1% loss of stored heat per day (less in a really large system) and 72-80% electric RTE. Of course the idea is not yet in production; it would be nice to see if these figures can be reproduced at scale.

The round-trip efficiency is not as good as batteries but it is not very much worse (if at all) than pumped hydro, if the numbers mentioned above by Niobium41 are accurate (RTE figures on pumped hydro are hard to find). The capital costs are absolutely lower than any form of battery, though higher than hydro (offset by the relative lack of geographical constraint).

I'm not sure how 72% RTE compares to the RTE of sending power to Norway and back. I know Norway's dams do not use pumped storage, just deferred consumption, but an undersea HVDC interconnect to the Netherlands or Britain must have some losses, perhaps as much as 10% each way?


HV DC losses are, rule of thumb, 3% per 1,000 km.

81% RTE is considered very good for pumped storage. Deferred generation is of course much better.



Congratulations! This is fully up to your usual stratospherically high standards. May we publish it at please?

There is one small problem, though.

Despite a record price of $10,000/ton last weekend (and rising), global production of copper is not rising and at many major mines, production is falling. In fact, we might be seeing the beginning of "peak copper (extraction rates)"?

What copper price was used in the published estimate for the new Skaggerak connection? I suppose there is a copper price escalator in the contract!

I wonder what copper price assumption the enthusiasts for inter-connection are using? I hope it is more realistic than our politicians are using for oil, coal and (especially) gas.

Best regards,


World production of copper continues to rise. US production dropped in 2009 as the price of copper went from four dollars (per pound) to a buck fifty. But production is now rising here too. Five dollar copper is a recent phenominon. It takes time to go through the licensing procedure to constructing a new mines. Plus investers want to see that the new prices will hold before plunking down their multi-billion dollars to open a new mine.

In general high voltage lines are made out of aluminum clad steel because of strength to weight considerations. Do we know the skag connector is made out of copper? Even if the world is copper constrained, high power cable contruction can continue.

The current driver for copper demand is new construction in China. Do we know if Chinese peasants can continue to make their mortgage payments? I suspect real estate in China is in a bit of a bubble.

Robert a Tucson

I don't remember the numbers, but Peak Copper is waiting for us somewhere down the road. Remember that copper has been mined for 5000 years. It is the oldest (or one of) non renewable we still use (demand for flint stone is very low these days, I have heard).

But copper is reusable, so in theory all copper ever mined acumulates. Should we ever get into a population decline, we would get an endless source of copper from building deconstruction.

Another worry around here is Peak Silver. There are few pure silver mines, silver is frequently produced as a by product from copper mines. When copper peaks, so will silver. Silver is harder to replace for its uses, and is also used in some non recycleable applications.

Arizona isn't going to run out of copper porphyry this century. Or this millenium. What's the rule? Some small downtick in oregrade means 10X more metal is available. The guys that build the mine don't seem to look for the richest ore body. They want a pile of rock they can mine for a hundred years, a rail connection to get equipment in and copper out, high power electrical service, and who knows what else. The guys trying to put in a mine here in the Santa Ritas sold the silver rights to somebody in Canada so they'll have the scratch to be tied up in court the next decade. You might think five dollar copper will cause the stuff to evaporate out of the ground but at ground zero things move at government speed.

What is normally forgotten when copper prices rise is that you have peak pilfering from the infrastructure. We have had a few trains delayed lately here in Holland for that very reason.

Thank you! I see no problems in a publication at, but please add a link to
You are right. The Super Grid is a vision with several bottlenecks, but it is natural that suppliers of converter equipment and cables are eager to boost their business together with the Norwegian power companies and create seller’s markets for their products and services.
I am happy that some participants in the discussion have caught my concluding message that the wind power nations should develop local measures in order to limit their dependency on foreign services.

A few remarks concerning any possible long term reduction of HVDC costs due to expiring patents, possible economies of scale as component manufacturing is ramped up, standardization of designs, etc, will be greatly appreciated by everybody.

It is my understanding that undersea cable has significant economies of scale, if extra capacity comes from greater amperage rather than higher voltage.

The insulation for a 350 kV system that carries 250 MW/leg (500 MW total) is little more for a thicker wire capable of carrying 500 MW/leg (1 GW total). The cost of aluminum is not extreme.

If the wires are oversized for the initial demand, then less power will be lost to resistance.

So, if long undersea links are to be built, build them big.

Best Hopes,



Thanks. Have you posted your work in book or essay form anyplace where your fans can read it straight thru ?

I am mightily impressed with your broad based knowledge and realistic approach.

Personally I wouldn't walk a block to meet all the pro athletes and Hollywood celebrities in the Big Easy during the big party, but I would walk ten miles for the privilege of spending a lazy afternoon fishing and talking with you.

I do not know much about the cost development of HVDC components. I am convinced that HVDC technology will gain even more importance in the future and I suppose that the cost will depend on supply and demand at any time.
I agree with Alan that long distance HVDC links should be built as large as possible in order to take advantage of economy of scale.


This is really a problem of electrical storage in Denmark, or time shifting it too be more precise, but is this going to be a problem if Better Place takes off as they are hoping it will in Israel where they hope to get off oil for transportation in 2020. Dong I gather is going to be the supplier of the renewable electricity, They will certainly have an incentive to push it as they produce 59% of there electricity from renewable s, and are paying Germany to take it off there hand when they produce too much electricity. The Danes have certainly skewered the tax system if favour of EVs with 0% for EVs and 180% for ICE vehicles. If Israel can do it so can Denmark. I don't know how many vehicles Denmark has but at a rough guess it must be in the region of a couple of million. If in 10 years Denmark has 2,000,000 EVs each with a 50K/w/hr battery. I would suspect that you would have the best distributed and robust electrical storage system in the world and have no need to expand the present system. Do you have any information of the experimental compressed air storage system that Dong is mucking about with in that depleted gas field I think somewhere too the East of Aarhus, I came across an article in a Danish Newpaper a while back and I can't seem to find it again.


Yorkshire Miner

Yorkshire Miner

Electric vehicles (EV) are supposed to contribute considerably to smoothing out the wind power variations in Denmark. So far the EV technology was not successful in Denmark. Heating the cabin during winter has been a major problem. Technical improvements may overcome this problem in the future.

Compressed air (CAES) has been considered. There is no depleted gas field east of Aarhus and the salt domes which could be used for CAES are too far from urban areas for utilization of waste heat from the process.

The Danish strategy is based on development of a range of wind power integration measures:

  • Reinforcement of interconnections with new cables to Norway and the Netherlands.
  • Coordinated operation of power system and district heating systems with active use of large heat pumps and the large hot water storages.
  • Flexible end user electricity demand such as EV and private heat pumps.

The development and implementation of smart grid measures at end user level may take some years. Therefore the first two elements are so important.

I recommend other wind power nations to aim at broad ranges of integration measures instead of relying only on foreign services.


the salt domes which could be used for CAES are too far from urban areas for utilization of waste heat from the process.

The proper disposition of that heat is regeneration, and it appears that some newer CAES companies are doing just that.

Thanks for the easy to follow post Paul-Frederik. Your point on heating EV cabins is something I've wondered about for a while. Do you have any idea what sort new tech is being considered? Power drain for resistance heat and high volume blowers would seem substantial. Winter is the norm where I live but I'm guessing Denmark has a long enough one itself.


Thanks for the easy to follow post Paul-Frederik.

Alan upthread mentioned ABB's reputed 'black start' capacity.
ABB have just today updated their website on the Skagerrak interconnection.


I did not want to exaggerate my scepticism about EV.

It has been predicted that the number of EVs in Denmark would be 400,000 by 2020. A newspaper recently said that it would take 40,000 new EVs per year and that we are 399,730 EVs from the target. Very few EVs have been sold so far.

Oil-firing has been suggested for cabin heating and it is not a joke.

I welcome any progress of the EV technology but I would not rely too much on this solution but aim at other measures as well.

Well my Monitor oil fired space heater is way more efficient than the drip models everyone was using in the 70s, so I'm guessing the oil fired car heaters would be far more efficient than the gasoline fueled cabin heater I put in my 68 VW Fastback (it used at least as much fuel as the engine in temps bracketing zero F if memory serves).

Preconditioning certainly looks to be very useful especially for short commuter trips. Not too much learning curve for the operator. Far north ICE drivers who already precondition the running gear by plugging in the resistance heat installed in their engine blocks, and on their oil cases and batteries learn to remember to push the auto start button ahead of drive very quickly.

NREL study finds pre-conditioning a PEV cabin using off-board power increases range up to 19% and reduces battery wear.

No new tech required, just the equivalent of a remote starter to have the car ready before it unplugs.

Thanks for the link. Looks like the range loss from AC at 95F is similar to that from heat at 20F, around 35%. Thermal preconditioning can cut that down to about a 25% loss, plus the ride will be more comfortable. But this analysis was done through computer modeling. It was not apparent whether or not variances in time stopped in traffic or moving slowly were factored in properly.

Climate control power drain is much more time than miles dependent. I'm assuming the city and highway driving scenarios had average speed as well as average acceleration components. But traffic conditions that substantially lowered the average speed per trip could have far greater impact on the climate control power usage than on the drive train power usage. On the other hand ice or slushy snow covered roads might substantially increase the drive train power needed.

Real world performance data would be more convincing.

I see that the BritNed HVDC is at the commissioning stage. Since there is one from Norway to Holland already it the only missing link is from the UK to Norway?

HVDC Norway–UK ... more details Will explore HVDC connection between Norway and Great Britain

Actually the proposed landfall site in Norway is Kvilldal , which is part of the largest combined hydro_complex in Norway called Ulla-Førre - already with pumped storage facilities in place. This complex is on par with the Hoover Dam at an average annual production of 4,5 TWh and with a total head of 1000m but with a drainage basin of just a fraction of the Hoover Dam's.

For the Scandinavian-tongue audience here is a link to Norwegian Statkraft's video-archives concerning building many of the Norwegian hydro infrastructures, dams, lines, also HVDC's to Denmark and more. ( scroll down to select from content, and at least one English commented as well)

Btw- a great article.

For the Scandinavian-tongue audience

Jeg liker din definisjon...Dansk, Norsk, Svensk...all the same:-)

Islenska nei enda Føroyskt nei


I don't know any Scandinavian languages and probably won't learn any as I am in Australia now (and getting on in years), but thanks for the links. Maybe the proposed North Sea grid could turn out to be reality. UK to Norway could be the final link.

Not sure where the UK end of the line should be. Whether near to the London array and a longer line or near to generation capacity in the North of England. I suspect it may end up like the link the France and be mainly import only. After all, UK already buys gas from Norway for power generation so why not just buy the power.

Maybe a link from UK to Iceland. They had better hurry though otherwise Ireland may get there first. Seems like everyone wants to be Norway's friend at the moment with all the HVDC links to Norway. I hear that people call Norwegians the 'Blue-eyed Arabs of the North'.

In Australia there is a small one (HVDC) Basslink linking Tassie to Victoria.

A 500 MW HV DC link between the Republic of Ireland and Wales is under construction. Ireland is looking for places to sell excess wind power on windy days.


Most interesting. Seems like everyone is getting in on the HVDC act. I remember that Ireland once had peat-fired power stations but now mostly oil and gas-fired I believe and, as you say, increasing wind turbines also. From the wording of the website on the cable it also appears that Ireland is footing the whole E$600m cost of this venture.

I wonder, since Norway appears to be the peaking generation of choice for a lot of Northern Europe these days, what the impact on new gas-fired peaking generation will be, or even on existing gas-fired peaking generation. Also what Prime Minister Vladimir Putin of Russia thinks of it all given that just a few years ago he was preparing to have all of Europe over a barrel supplying their gas needs for the future.

Also whether having wind turbines so far apart in a HVDC linked grid (i.e. Ireland in the West to Germany in the East) will have a 'smoothing' effect on the normally very variable output of wind farms spread across vast distances.

Unfortunately Mr. Putin has no reason for concern. EU will under all circumstances depend increasingly on imported gas.

Combining wind power in Ireland and Denmark certainly has a smoothing effect. It can be demonstrated by the following duration curves:

However the combined production will still have a high variability and long periods with very low output:

I should add that combining Denmark and Germany shows practically no smoothing.

And the other major wind nation (today) in the EU, Spain ?

And if Icelandic wind and, say Ukrainian wind were added in the future ?

Best Hopes,


International exchange of power can contribute to the integration of wind power, but it can never be a complete solution.

Future market forces must decide how far it is profitable to move electricity around.

The wind power nations must also develop local measures such as coordination with heat supply and transport and other types flexible electricity demand.

And local pumped storage in nations more mountainous than Denmark.

Ireland has but one smallish pumped storage unit.


Thank you for the graphs Noatun. It seems like you are very knowledgeable in this field. My experience is restricted to Australia and New Zealand. Australia is mostly coal, 90% but with some wind. I think South Australia is the state that has most wind with about 10-15% nameplate capacity of generation. Australia has two grids, Eastern states and Western Australia, separated for geographical reasons. Large pumped storage schemes Murray and Tumut in the Snowy Mountains of up to 1500MW with a good 1000m hydraulic head. Could be good to use for wind storage. Also there has been talk of building a hydro power station in Southern New Guinea and suppling the output to Queensland by HVDC cable.

New Zealand is mainly hydro 55-75% of generation depending on rainfall and 5% wind (and very windy conditions in places) and 10% geothermal, rest mostly coal and gas evenly split. No pumped storage. New Zealand's problem is that in winter much hydro capacity is spilled without generation while in spring summer autumn there is not enough hydro generation due to limited water storage capacity in hydro lakes so there is more coal and gas generation at these times. There has been talk of build a monster 3000MW pumped storage capacity with several months storage capacity in the Manorburn basin. Note this would use output from other hydro stations for pumping. Unlikely to happen due to cost, environmental reasons and also the sheer weight of water in an 80km long lake may cause earthquakes, Lots of possibilities of other pumped storage elsewhere but smaller.

Also New Zealand had a system to control domestic hot water tank heating elements remotely using a variety of methods. One was a 3kHz ripple on the 50Hz mains waveform. Other was applying a DC voltage to the waveform and yet another method involved a signal wire. Since a hot water cylinder could retain heat for say 18 hours this meant that some leveling of demand could be controlled by the electric grid system operator over the course of the day. I believe that this system is gradually falling into disrepair and new houses don't have the controls built in.

So these two isolated countries have found some different ways of leveling their demand which could also be used for fluctuating wind power generation over 1 to 2 days.