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Seeking Consensus on the Internalized Costs of Mature Energy Storage Technologies

Schalk Cloete's picture
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My work on the Energy Collective is focused on the great 21st century sustainability challenge: quadrupling the size of the global economy, while reducing CO2 emissions to zero. I seek to...

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What is meant by “internalized costs”?

Internalized costs are the costs which can be accurately accounted for in our current systems. In energy production, these costs typically consist of capital costs, financing costs, operation and maintenance costs, and exploration costs. Some energy options incur these costs in various stages such as extraction, transportation and refinement. Profits and taxes are excluded wherever possible in order to isolate the pure cost of production.

Internalized costs of energy storage

This article will cover three mature energy storage solutions: 1) thermal power plants, 2) pumped hydro storage and 3) compressed air energy storage (CAES).  Pre-commercial technologies such as batteries and synthetic fuels will be covered in subsequent articles.

Thermal power plants

The neatly packaged chemical potential energy in fossil fuels offers the simplest energy storage solution through thermal power stations. This is also the most economical solution at low to medium penetrations of intermittent renewables. Costs stem from three main components which increase with the intermittent renewable energy penetration: 1) profile costs primarily from the underutilization of generating capacity, 2) balancing costs from imperfect forecasting and 3) grid-related costs from longer-distance transmission and congestion.

The profile costs in the above figure are primarily a function of the cost of the underutilized capital and the capacity credit of the intermittent renewable energy resource. Capacity credit is a measure of the ability of intermittent renewables to displace dispatchable capacity and is highly case-specific depending on the match between load and intermittent output. In general, increasing penetration of intermittent renewables causes underutilization of more expensive capital and also reduces the overall capacity credit, hence the increase in costs with increasing deployment.

Profile costs related to energy storage in fossil fuels are given below as a function of the capital costs of the underutilized generating capacity and the capacity credit. Other assumptions include fixed O&M costs of $20/kW/yr, a 30 year lifetime and 70% capacity factor of the backup plant and a 5% discount rate. Other smaller effects like decreased efficiency and increased wear on increasingly cycled plants are neglected. The figure is valid up to ~20% penetration where significant curtailment of intermittent renewables becomes necessary. The Excel datasheet used to create this figure can be accessed here.

General comments on energy storage economics

Before moving on, it can be useful to briefly discuss the most important factors influencing the economics of specialized energy storage technologies: capital costs and capacity utilization. Capacity utilization is an especially important issue in energy storage because of the trade-off between capacity factor and the spread between the price at which the storage facility can buy and sell electricity. At higher capacity factors, the initial capital investment will be better utilized, but the spread between the buying and selling price will also narrow.

Germany currently offers a good example of the type of buy-sell spreads available in a system with substantial intermittent renewable energy penetration. As shown from the graph below, a buy-sell spread of about €20/MWh is available for probably about 20% of the average day while spreads of €50/MWh are only available on isolated occasions.

It is important to note that spreads required for economic energy storage are generally larger than those available in the open market. This explains the very low penetration of mature energy storage technologies.

The USA has the most developed energy storage capacity with about 20 GW of pumped hydro capacity. However, calculations using the reported net-energy consumption of these facilities under the assumption of a 75% round-trip efficiency reveals a capacity factor of only 7.5%, indicating a very limited time-window where the buy-sell spread is sufficient for profitable operation.

Finally, it should be mentioned that numbers utilized in the remainder of this article are guided by data available from the reviews of Duke University and DNV.

Pumped hydro storage

After fossil fuels, the simplest and most mature storage options are pumped hydro storage (PHS) and compressed air energy storage (CAES). Both these storage options have been in operation for decades (although deployment is very small relative to total electricity generation).

The required breakeven buy-sell spread for PHS is given below. Additional assumptions include a 40 year plant lifetime, 5% discount rate, fixed O&M of $5/kW/yr, 75% round-trip efficiency, and an average electricity buying price of $30/MWh. The Excel datasheet used to create this figure can be accessed here.

As shown in the graph above, PHS can become economically viable to a limited extent if capital costs can be kept very low. For example, capital costs of $1000/kW and the US capacity factor of 7.5% would require a spread of just over $100/MWh which does occasionally present itself. It is therefore clear that PHS is a very simple energy storage option which can be economically viable at very low penetrations as a peak-load generator or provider of additional short-term grid services. It should be mentioned, however, that PHS is strongly limited by geography and can have sizable environmental impacts.

Compressed air energy storage (CAES)

CAES facilities can be either diabatic (heat generated during compression is lost) or adiabatic (heat generated during compression is retained). In general, diabatic designs are simpler, but less efficient. Only diabatic facilities are currently in operation although the first adiabatic facility should go online in Germany around 2016. 

The breakeven spread for CAES is given below under the assumptions of a 30 year plant lifetime, 5% discount rate, fixed O&M of $10/kW/yr, 60% round-trip efficiency, and an average electricity buying price of $30/MWh.

It is clear that CAES performs very similarly to PHS and can therefore also play a significant part in future energy storage markets. The main drawback of currently mature diabatic CAES technology is that it is dependent on natural gas to replenish the energy lost during compression in order to effectively drive a gas turbine.  Adiabatic CAES can be a standalone energy storage solution, but will be substantially more expensive. CAES is also limited by geography, although much less so than PHS.

Commenting

If you have a number that differs significantly from the estimates given above, please add it in the comments section below together with an explanation and a reference. 

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Schalk Cloete's picture
Schalk Cloete on Jun 23, 2014

DATA: Cost of using thermal plants as storage at a 10-20% intermittent renewables penetration: $35/MWh.

This number is based on the profiling and backup costs in the first figure of this article within the 10-20% penetration range. Transmission costs are neglected since these are associated with the solar/wind technology itself and not with the thermal backup. 

Schalk Cloete's picture
Schalk Cloete on Jun 23, 2014

DATA: Breakeven spread for broader deployment of PHS and CAES: $150/MWh.

This estimate is based on a capacity factor of 10% and a capital cost of $2000/kW for PHS and $1500/kW for CAES (the red lines in the graphs). Naturally, spreads of $150/MWh are not available for 10% of the time in modern electricity markets, implying that these technologies are not suitable for broad (unsubsidized) deployment. 

Roger Arnold's picture
Roger Arnold on Jun 23, 2014

CORRECTION? The indicated breakeven spread appears to be based only on storage used for arbitrage. It does not consider the role of storage systems for voltage and frequency stabilization or for contingency reserve. It’s not clear to me how one translates those functions to internalized cost of the storage technology, but they do strongly affect the breakeven spread and the economics of deployment.

Roger Arnold's picture
Roger Arnold on Jun 23, 2014

CORRECTION?  There’s a dimension to profile cost for fossil fuel as storage that is significant but hard to quantify.  That’s the difference between using installed older technology vs. acquiring newer flexible generation technology.  

Older technology is capable of backing intermittent renewables, but at a cost.  The cost is more than just the obvious CF-related underutilization that your model captures.  It includes higher specific fuel consumption and increased maintenance / shorter lifespan.  The costs are hard to quantify because they are non-linear with degree of penetration and highly dependent on the specific equipment installed.

New fossil-fueled technology is available that largely eliminates those non-CF-related costs.  It provides a relatively flat power band that allows for a degree of load following with minimal loss of fuel efficiency or increase in wear. But acquisition is a large capital expense that is hard to justify in a steady or shrinking power market.  So utilities generally make do with what they have.  

Schalk Cloete's picture
Schalk Cloete on Jun 23, 2014

I was thinking of including the effect of various shorter-term grid services as well, but this would probably introduce more complexity than it is worth. It appears as if frequency response is the most important short-term grid service and has a value of $10-60/MWh as given here. However, I think the frequency response market is very small relative to the potential time-shifting market driven by increasing arbitrage opportunities as intermittent sources scale up. Being so small, I therefore do not think it is important to include in the big picture view.

I’m not sure about the size of the frequency response market though, and if you have some evidence that it is large enough to include, I will gladly do so. 

Schalk Cloete's picture
Schalk Cloete on Jun 23, 2014

Good point. The simple model I have in the first graph excludes these effects on the assumption that they are negligible which they probably are not for most existing capacity. For example, this report estimates the cost of additional fuel consumption as $6/MWh for gas and $9/MWh for coal. I cannot find any information on the cost of additional wear.

Do you think it is a good assumption to add about $10/MWh to the above figure for increased fuel consumption and wear? If so, I’ll add another DATA comment with these costs included.

Roger Arnold's picture
Roger Arnold on Jun 24, 2014

$10/MWh is perhaps a reasonable ballpark number “on average”. But any specific “per MWh” number implies a linear cost, whereas the salient point is that the cost is not at all linear.  

At penetration levels of a few percent, the non-CF related cost for this type of “storage” is negligible, even for systems with older generating technologies.  The variations encountered will remain within the limited throttling range of the generators.  At higher penetrations, however, the increase in variability will exceed the throttling range for efficient operation.  Then it becomes necessary to operate some equipment below its efficient power band, and / or increase the frequency of stressful and inefficient start-up and shut-down of individual generators.  

At some level of penetration, the variability becomes too much for the system to handle, and the grid breaks down.  But loss of efficiency can be significant well before the point of breakdown.  The problem is that it’s invisible to the usual cost / benefit analysis for renewables.

Nathan Wilson's picture
Nathan Wilson on Jun 24, 2014

Rebuttal: 

I think the baseline costing case should assume the grid needs new capacity to meet demand.  Global energy use is growing, so this case is more representative than the special case of flat or shrinking demand.  

Nathan Wilson's picture
Nathan Wilson on Jun 25, 2014

DATA: round trip energy efficiency of CAES w/ natural gas re-heat is only 35.7%.

I calculated this based on the 2005 Ridge Energy Storage proposal (website, whitepaper) from Texas (which was never built), by calculating:

efficiency = (net electricity out)/(electricity in),

where (net electricity out)  is the nameplate output minus the electricity that would have been produced by a modern combined cycle gas plant with the same fuel flow rate (heat rate).

The Ridge proposal would have used 200 MW for compression, and 270 MW output, and provided 1 MWh out for each 0.8 MWh electrical input.  The heat rate was predicted to be 4500 Btu/MWh, compared to a CC plant heat rate of 5700 Btu/MWh.

This same calculation gives a more viable 68% efficient, when the natural gas is valued at 7500 Btu/MWh, as would be the case for a simple combustion turbine.  So it might make sense when very fast throttling capability is needed, and combustion turbines are the only alternative.

Bas Gresnigt's picture
Bas Gresnigt on Jun 24, 2014

“…good data on the cost of fossil fuel backup at a wind/solar penetration of 10-20%..”
Those costs are highly dependent on the capability of grid management, especially its production predictions.
Normally grid management can predict that production some days in advance within a few percent, based on wheather predictions (increasing accuracy when the period shortens).

With 10-20% the changes for the remaining power plants are similar to the normal load changes.

Hydro
When there is 5-10% stored hydro, then the cost of fossil fuel backup will be near zero.
Management of hydro will utilize the stored energy capacity only when prices are high.

Assuming they run their facilitiy ~30% of the time, they will compensate the variability of ~15-30% wind/solar penetration.
So the costs of FF backup are then zero.

 

Bas Gresnigt's picture
Bas Gresnigt on Jun 24, 2014

This presentation shows the different storage technologies and their position in the costs / storage duration (sheet 19). It also shows that:

– Load changes in Germany are >50%.
So 20% wind+solar generate only small changes.

 

– the electricity costs rise with only €1/MWh (from €77 to €78/MWh) when the share of renewable rises from the 2010 situation (7.8% wind+solar) to 40% (=30% wind+solar).

Note that wind+solar are very flexible;
Solar installations can be switched on/of automatic in a fraction of a second
Wind can be up/down regulated between 0% and 100% in a few minutes.
In Germany grid management made agreements so they can do that themselves directly.

 

 

If the system is optimized it may well be that 10-20% share of wind+solar decrease the total costs (incl. compensation for switching off wind+solar capacity). Because:
– wind+solar can absorb fast load changes easily, so power plants can avoid inefficiencies and continue to operate optimal.
– wind+solar production is rather accurately predicted days ahead now (weather). No sudden surprises as with a big power plant failure. So less spinning reserves needed.

 

German experience shows that the distributed (less vulnerable to power line outages) and easy to switch on/off wind/solar capacity, increased reliability with a factor two; total outage now ~15min/a per customer. That also generates important value.
Seems to me the USA figure need some improvement (connections now ~2hrs/a down).

——–
Your article uses the biased Vattenfall simulation study produced by then Vattenfal employee Hirth, who now found a few others at the Potsdam. Vattenfall has big interest in power plants (nuclear, fossil), little in wind, none in solar. The study conclusions are in line with these interests.

The German Energiewende scientists (Universities, Agora, Fraunhofer) concluded that:
– no storage is needed until ~30% wind+solar (pumped storage makes losses in Germany).
– until ~70% wind+solar the extra costs to integrate wind+solar production (system costs) will be small.

 

 

Those German conclusions are in line with the results of:
– US studies, such as by NREL;
– international studies such as this study by the International Energy Agency.

 

Max Kennedy's picture
Max Kennedy on Jun 24, 2014

How would thermal power plants reliant on fossil fuels be considered energy storage?  Unless of course the fuels used in them are somehow generated using renewable energy, though that is not what this article seems to be about.  Energy storage is about not needing fossil fuel based backup.  To include this technology in a discussion of “energy storage” is misleading and not conducive to an honest discussion of moving beyond the intermittancy of renewables.  

Storage is not that difficult, what is difficult is the expectation that it will be as cheap as oil/coal has been to this point.  We hit the jackpot in stored energy, literally millions if not billions of years of storage, and have used it in a couple of centuries.  The economic model based on this bonanza is FUBAR!  As reasoning and thinking entities one would hope to be able as a species to move beyond the baby kicking our feet tantrum of “I WANT” to a more realistic view of what actually is.  If we don’t stop with this lack of reality acceptance old Ma Nature will inevitably provide the swift kick in the rear as history tells us over and over!

Schalk Cloete's picture
Schalk Cloete on Jun 24, 2014

1. I can’t see any reference to costs on the figure you referenced. It is simply a graph of potential storage capacity of different technologies. 

2. Average capcity factors of German wind/solar are roughly 20% and 10% respectively. This implies that 20% wind/solar can have an instantaneous effect of everything from 0% to 100+%. The recent record of 75% instantaneous generation from wind/solar is a good example. The large effect of even small penetrations of wind/solar on the grid is best expressed by the correlation of spot prices with wind/solar output. See my analysis on this here

3. I’ve seen many estimates of reserve costs for wind/solar and none of them were negative. Granted, these costs are not large, but they are certainly positive. 

4. I would argue that the increase in German grid reliability is more a function of enormous overcapacity than anything else. Thus far German utilities are carrying the cost of this overcapacity, but calls for compensation are getting increasingly loud. 

5. The crucial difference in Hirth’s study is the profile costs – the costs related to underutilization of dispatchable capacity due to wind/solar enjoying priority dispatch. This is by far the largest cost of balancing wind/solar with thermal powerplants and is very easy to understand. The first Excel graph in this article illustrates this cost related to underutilization of capital in a very simple manner. 

6. Currently profile costs are carried by German utilities with serious financial consequences. Naturally, if the utility business becomes unviable in Germany, the Energiewende will fail because wind/solar is totally dependent on a healthy centralized generating system and will be so for decades into the future. It appears as if profile costs are neglected in the slides you referred to. For example, on slide 16, it shows that plant capital costs actually decrease as a component of the total electricity price when moving towards 40% renewables. This is quite bizarre because the added wind/solar capacity will impose very large capital costs and almost all existing dispatchable generating capacity will still be required. 

7. The NREL study you referenced covers only the smallest cost of wind/solar integration. If you read the article, you will see that I neglected these wear & tear costs because it is small relative to profile costs. 

8. The IEA study you referenced does not support your assertions, but supports Hirth’s work almost perfectly. Primary conclusions: 1) Balancing costs are about €3/MWh for thermal-dominated systems in the 10-20% penetration range. This is in line with Hirth’s findings. 2) Grid costs amount to about €100/kW (or about 7% of wind capital costs and LCOE) for the 10-20% penetration range. This is also in line with Hirth’s results. 3) Wind capacity credit falls to about 20% at 20% penetration. Estimating the profile costs from the first Excel graph in the article under the assumption that average European power capacity costs about €2000/kW returns profile costs of about €20/MWh – again in good agreement with Hirth’s results in the first graph in the article. 

 

Schalk Cloete's picture
Schalk Cloete on Jun 24, 2014

No argument that hydro is a good match with wind/solar. Denmark is a shining example of this. However, aside from the obvious restriction regarding hydro technical potential, profile costs can quickly start to hurt the economics of a hydro-based wind/solar integration. 

Roger Arnold's picture
Roger Arnold on Jun 25, 2014

Global energy use is growing, certainly.  But that’s mostly in China and a few other places whose energy policies have little to do with anything we discuss here.  In the U.S. and the E.U., the market for utility power has been shrinking.  Not dramatically, but enough to influence decisions about new capacity. That’s one reason why new nuclear plants are hard to sell.

Utilities here are reluctant to follow Germany’s lead and retire assets early so they can be replaced with new technology “flexible” thermal plants.  The result is to distort the cost / benefit analyis of renewables and the policies that support them.  The actual benefits are less than anticipated, the costs more.  Our policies are blind to the inefficiencies that follow from accomodation of “must take” RE with the currently installed equipment base.

Snce I don’t know how to account for the additional costs outside of detailed studies of individual RBAs (Regional Balancing Areas), I’ll concede your point: the costing case should apply to an assumed requirement for new capacity.  But I’d insist on a footnote about policy differences for cases where renewables are intended to replace existing capacity.

Schalk Cloete's picture
Schalk Cloete on Jun 25, 2014

Well, you explain yourself why fossil fuels count as storage. The point is just that intermittent and non-dispatchable renewable energy will always require stored energy which can be deployed to balance the intemittent output. Aside from the limited potential of hydropower, the neatly stored energy in fossil fuels is currently the best way in which to do this.

While I agree about the unsustainability of the current economic model, this is totally off-topic in this article, so let’s save that discussion for another day. 

Bas Gresnigt's picture
Bas Gresnigt on Jun 25, 2014

@Schalk,
Thanks for your excellent response!

Here you find the presentations of a recent German storage study day, regarding best methods with ~40%-90% renewable.
In short:

 

– (sheet 31) Wind+solar capacity ~140GW in 2030 = twice the max. capacity Germany needs.
– (sh.36) Development of storage costs. Pumped Storage (‘PSW’) may never become competitive.

– (sh.44) Redispatch costs  €60mln/a with 45-50% renewable (=30-35% wind+solar).
That is <0.1cnt/KWh. New storage capacity makes no sense with that share of renewable.


 

– (sh. 45) With renewable share of 69%, extension of Power-to-Gas installations is adviced (seasonal storage). However others think, EU-wide grid extension may be cheaper (sh.59).

– (sh 50-62) Assume a renewable share of 88% in Germany and 82% in the relevant EU countries. What would be optimal? Different scenario’s.

Scenario C; high share wind+PVsolar.
Economic storage capacity: 5-9GW (= ~10-18% of av. consumption) for 4-6hrs.

In general; DSM (Demand Side Management) has important beneficial influence on the costs. So smart grid will become really economic.

 

Schalk Cloete's picture
Schalk Cloete on Jun 25, 2014

Thanks for the presentation. I’m really starting to think I should learn a bit more German to aid in my energy analysis efforts…

From the storage costs analysis I have done recently (topic of future posts), I tend to agree that storage will not become economic until very high wind/solar penetrations. I think Hirth’s estimation of €60/MWh balancing costs (primarily profile costs from underutilization of thermal plants and curtailment of wind/solar) at 40% penetration of wind is quite realistic, but all storage solutions I have analysed remain substantially more expensive than this even under optimistic price assumptions. €60/MWh is smaller than the current EEG surcharge, so it is definitely not economically impossible for the German economy to carry these costs.

I think the expected role of efficiency should also be emphasized strongly. The presentation shows that the base power consumption drops by almost 20% over the next four decades while people would obviously like to see continued economic growth of about 2% p.a. Quite ambitious, but probably very necessary to make the Energiewende work. 

The role envisioned for DSM is really large. Any indication on how this will work in practice? From what I have read, DSM in practice will probably be more about scheduling energy-intensive industry than the smart-grid ideal where every household has a smart meter and lots of smart devices. This will of course pose serious capacity utilization issues (similar to profile costs in power plants).

It also remains to be seen how much energy intensive industry Germany manages to maintain as the Energiewende continues. I’ve read recently that new legislation is now being implemented to ask industry to contribute more to the costs of the Energiewende. 

Max Kennedy's picture
Max Kennedy on Jun 25, 2014

Fossil fuels aren’t storage unless they are being made not mined and thus are in themselves off topic for an article titled “Energy Storage”.  Let’s not discuss the problem as if it was the solution!

Bill Hannahan's picture
Bill Hannahan on Jun 25, 2014

Schalk, thanks for your work, always interesting.

If fossil fuel is stored solar energy, uranium and thorium are stored solar energy from an older star that went super nova.

If we mass produce the simplest molten salt reactor design we can have thousands of years of reliable disspatchable low cost stored solar energy.

By mass producing a simple design, it can be cheap enough to be profitable at capacity factors down to 50%, eliminating the need for unreliables, wind and solar, or any other storage or source of energy. There would be no need to replace aging fossil plants with new fossil plants.

Bas Gresnigt's picture
Bas Gresnigt on Jun 25, 2014

Germany seems to move toward towards electricity-to-gas/fuel conversion as an important factor to overcome the seasonal variability of wind+solar.

Ideas are that power plants burning this renewable generated gas/fuel in combination with biomass & waste, will fill the gaps that wind+solar+batteries leave (especially in winter).

So the combination will deliver the 100% renewable electricity during the whole year.
Even if the country cannot use hydro or geo-thermal.

Bas Gresnigt's picture
Bas Gresnigt on Jun 26, 2014

“…storage will not become economic until very high wind/solar penetrations…”
At grid scale; yes.
Especially since the general conclusion in Germany is that grid extension & improvements can solve most of the intermittency issues, while being much cheaper and having other advantages (more redundancy, etc).
Thought pumped storage would become economic with ~35% wind+solar penetration. Now I doubt that. May be the minimum wind+solar penetration is ~45%.
And when that 45% is reached in ~2030, grid batteries may be cheaper than pumped storage.

Different situation for customers.
For customers that have PV-solar, batteries may become economic at ~2020. Those store the cheap PV-solar electricity for use in the evening/night (so 4-6hrs storage), avoiding the 28cnt/KWh electricity from the grid.
The subsidy program to install those batteries, 30% investment subsidy only for small rooftop owners, is already a big success. So those battery installations only have to become ~30% cheaper.
I estimate that in 2030 most (90%) PV-installations will have such batteries.

“…€60/MWh balancing costs (primarily profile costs from underutilization of thermal plants and curtailment of wind/solar…”
Check sheet 72 (my translation). Conclusion 3
Also with renewable share of 90% in Germany and 80% in Europe, supply and demand can be matched without much extra storage capacity and only 1% curtailment of wind/solar.

That €60/MWh: May be with old base load power plants only, and the excellent predictability of wind+solar production not used, etc. (German grid management has special weather forecast, and can see wind flaws passing through their area in 8hrs as they see the production of the windturbines).

Thanks to the predictabilty of wind+solar, power plants that take 24-48hrs to come online can be switched off. Considering also that less spinning reserve capacity is needed (>1000x more generators, dispersed over the delivery area), the average load of the running power plants won’t be much lower.

And Germany’s power plants are now far more flexible. Utilities replace old baseload plants with new flexible plants that keep their high efficiencies at low load, require less staff, etc.
Thanks to the 50years long scenario, utilities could wait until the old plants are written off and then replace those so little losses. Even the hated NPP’s can run until they are written off (30-35years).

Energiewende experts will laugh about that €60/MWh figure, their estimations are at ~€10/MWh with ~50% renewable (=35% wind+solar).

Indications on how DSM will work in practice?
At the moment German grid operators have some agreements with electricity intense facilities (factories, etc) that they switch part of their machines off when asked (often by phone). Only few in which grid management can control the consumption.

Smart grid is coming in The Netherlands & Germany, there is a program to install smart meters, so everybody will have them in a few years. You get one if you install rooftop solar. However those are still rather primitive. Those allow for changing tarrifs, etc.
But automatic switching of equipment (dish washer, dryer, rooftop solar, etc) will take another 10years I think. There are issues regarding standards, etc.
We (I too) have a primitive time-of-day tariff; Electricity is cheaper in the night and in weekends. So I set the timer of my dish washer such that it starts at 2 AM.

At the supply side, grid management itself can reguate the output of some wind parks; that is faster and more accurate. But little to regulate if there is no wind.
I’m not aware of similar regarding PV-solar parks. Regulating PV-solar output is really fast; similar as with batteries & flywheels.
(owners get compensation for missed production)

“… efficiency … base power consumption drops by almost 20% over the next four decades…”
Many folks on the forum here have the strange idea that you need more energy to live more comfortable. My experience is that living in a better isolated, well ventilated house delivers more luxus, while delivering lower energy bills.

The trend is set by Denmark (~15years ahead of Germany).
Regarding new houses; only 100% energy neutral houses are allowed!
Germany may follow that example at ~2030 (some debate in Germany about it).

“…how much energy intensive industry Germany manages to maintain… new legislation…”
German energy intense industry gets lower rates than our energy intensive industry, and that in UK, and and USA; they pay whole sale rates. And Germany has lowest whole sale rates now (~€35/MWh).
We in NL recently lost our aluminum smelter because German electricity is cheaper.

The new legislation creates some marginal increases only for less energy intense industries. It is a compromise with Brussels in which Merkel got what she wanted. Normally Brussels would give a huge fine such as the ~$2billion to Microsoft, and ban the system.

Language
Sorry, the most interesting stuff is nearly always in German.
I found an only slightly older English interim report, that spends some attention to system costs (Agora, Consentec and Fraunhofer).

Rick Engebretson's picture
Rick Engebretson on Jun 26, 2014

I don’t know if this fits your screened criteria, but there is an emerging consensus on stored energy in Minnesota worth mention. A good starting reference is the Department of Natural Resources scientist, Anna Dirkswager. Anna was among several presenters at a Grand Rapids, MN. meeting held April, 2014.

Grand Rapids is where Blandin Foundation (Finland) has offices. The idea is to use enormous amounts of stored energy in American forests. Other groups mentioned include the US Forest Service, US EPA, USDA, other state agencies, and several non-profit advocacies. Sweden has had a group here.

I don’t know where it stands. But I had the opportunity to speak with Anna and suggested including a comparison with fuel oxygenate success of gasoline/ethanol; coal combustion efficiency and EPA emissions concerns. I also urged others to consider biomass railroad transport, given that the trucks now used are VERY heavily loaded.

Since North American forests are roughly the size of Europe, and growing at unprecedented rates due to new CO2, and as Anna said “will burn one way or another,” we can’t completely ignore it.

Having benefitted from Minnesota Department of Natural Resources experts for well over half a century, I’m delighted by their leadership. Please refer to them for numbers and many further references.

Nathan Wilson's picture
Nathan Wilson on Jun 26, 2014

I believe that the intent of listing fossil fuel under storage was to be able to account for the cost associated with using them to cover the external cost of added variability due to solar and wind power.  We need to account for this extra cost when comparing solar and wind to energy sources like geothermal and nuclear which do not produce additional variability.

This is very important, as it helps to explain that even when solar and wind match the cost of conventional generation, adding them to the generation mix will make the total cost of electricity go up! (i.e. the annectodotal reports of wholesale power costs going down when wind power is added must be ignoring some costs somewhere in the system).  

Max Kennedy's picture
Max Kennedy on Jun 26, 2014

Then it needs to be dealt with under a separate heading.  It is NOT a storage option.  To have it as a primary option in a storage discussion is entirely misleading.

Robert Bernal's picture
Robert Bernal on Jun 28, 2014

Just a little bit of molten salt storage could be the MSR’s way to deal with the daily grid fluctuations. I believe it is the most efficient storage option (in this case) since the generator already relies on thermal for generation.

Robert Bernal's picture
Robert Bernal on Jun 28, 2014

It is only misleading that storage options will need FF backup because of costs of said storage. Note that the graphs only go up to about 40% capacity. If they were to back up solar and wind 100%, then, there would be no need of the mention of FF’s. I believe these costs are based on renewable mandates rather than a sincere plan to save the biosphere (that RE forcings arise from the love of money). The best way is to find the cheapest storage for the application (for example, molten salt for excess thermal generation and pumped storage for excess electrical generation).

Schalk Cloete's picture
Schalk Cloete on Jun 29, 2014

In an open market, all generating technologies would receive the current market price for the electricity they produce. If wind/solar would really be investable in such an open market and thereby push thermal power out of the market, I would have no problems with that, but that is certainly not the case. Subsidies and priority dispatch are by far the most important driver of wind/solar investment. Just look what happens to US wind deployment every time the ITC is removed (note that the US is arguably the best place on earth to deploy the most competitive intermittent renewable technology – onshore wind).

In an open market, wind/solar would receive ever-decreasing compensation as deployment increases. I did an analysis about this for the German system here. The more the wind/solar peaks grow, the lower the average price received by wind/solar during these peaks. If all subsidies were removed and we had a free market system, there would be no significant investment in wind/solar because this self-cannibalizing effect would make it impossible to recover the costs of investment.

Baseload plants, on the other hand, generate a constant output both during the wind/solar peaks (low prices) and during the wind/solar troughs (high prices). The large amount of output during times of high prices can keep these plants in business.

Schalk Cloete's picture
Schalk Cloete on Jun 29, 2014

I calculate costs based on a levelized approach where the net present value of all output over the lifetime of the asset is used to recover the upfront costs. This methodology requires an appropriate discount rate which I divide into three categories: 1) the time-value of money (opportunity costs of making a big fixed investment in a growing economy with many opportunities / the interest rate required to keep a growing economy from overheating and crashing), 2) a risk-premium (costs related to occasional under-performance or expensive failure of the asset) and 3) operational costs of the financial sector (compensation of the people who make large monetary transactions possible).

This methodology technically requires inclusion of the decomissioning costs (which are usually very small in terms of net present value because of the positive discount rate used), but does not require inclusion of the cost of replacement over time.

Schalk Cloete's picture
Schalk Cloete on Jun 29, 2014

How will this work in practice? Will the biomass from the forests be burned in co-fired power plants? Such solid-fuel power plants generally have fairly high investment costs and are also not very flexible, implying that they will be expensive when used to balance intermittent wind/solar output.

Nathan Wilson's picture
Nathan Wilson on Jun 29, 2014

The “open market” you describe, wherein electrcial energy is bought using the lowest bid for each hourly or sub-hourly interval, was created to generate profits for merchant fossil fuel powered plants by taking market share from utility owned power plants.  It is not the only type of market possible, nor is it optimal for other situations.

In the US, the market design in which most wind and utility solar power is purchases is using a 20 year power purchase agreement.  In this type of market, the buyer agrees to buy all of the delivered output from a plant for an agreed-upon price schedule.  A similar market design is being used in the UK for new nuclear power plants.

In Canada, some nuclear power is purchases as a public-private partnership.  The plant is owned by the public utility, and companies bid the contract to operate the plant for a period of time. 

In Europe, there is some talk of splitting the electricity market into energy and capacity markets (the energy market is the conventional purchase of sub-hourly MWh energy units; in the capacity market, the supplier agrees to keep a certain number of MWatts of power plant available to sell energy, regardless of whether any is sold).  In the past, when fossil fuel merchant producers dominated the market, they effectively gave away the capacity for free, assuming there were able to sell enough energy to stay in business.  With the growth of energy-only merchants (i.e. wind and solar PV), utilities may need to buy the capacity separately.

In China, merchant power plant (typically coal-fired) owners are guaranteed a minimum energy sales per year.

All of these are valid market designs, and the choice of market design will clearly be driven by what energy sources are preferred by society.

Nathan Wilson's picture
Nathan Wilson on Jun 29, 2014

As described in this article on the American Nuclear Society blog, it is not really true that nuclear plants can’t load follow.  But it is almost always the case in a mixed generating portfolio, energy sources with low fuel cost (i.e. nuclear, wind, solar, geothermal) get dispatched first, and high cost fuels will only get used when demand hits peaks.  A big difference is because of their high capacity factor, nuclear and geothermal can provide all of the baseload demand, whereas wind and solar must split the baseload demand with fossil fuel backup.

You can’t make solar’s and wind’s integration costs go away by proclaiming it to be so (no matter how many solar enthusiasts side with you).  Please read some of Schalk’s references.

Schalk Cloete's picture
Schalk Cloete on Jun 29, 2014

It will be interesting to have a more thorough discussion about the different market designs in a future article. Perhaps I can write such an article on this in the future in order to learn a bit more about the details of all the options.

It will be interesting to see how the capacity market develops in Europe. Currently there is a large overcapacity so this is not yet much of a practical problem, but the technology-forcing of wind/solar is making the utility business increasingly unprofitable which can have serious longer-term consequences.

Rick Engebretson's picture
Rick Engebretson on Jun 30, 2014

I’m not sure how biomass energy use will develop, Schalk.

One interesting possibility is beginning to appear in national advertising. Koch Industries includes their Georgia Pacific wood processing giant, as well as their large energy portfolio, in a PR effort on broadcast TV channels. I have not seen this effort until recently.

There are certainly many good scientists with many good ideas. In simplest physics terms I do know trees have gravity on their side compared to digging in the ground for energy. Nothing seems cheap or easy to me. Yet somehow an amazing energy system works.

Bas Gresnigt's picture
Bas Gresnigt on Jun 30, 2014

“…not really true that nuclear plants can’t load follow….”
The experience based graph below shows the inability of nuclear to load follow.
Nuclear continues to produce at >70% of max. even while prices are negative!

Schalk Cloete's picture
Schalk Cloete on Jul 1, 2014

How on Earth do you get 3-6c/kWh for rooftop solar in the US? According to SEIA, rooftop solar costs $4.56/W at present. At this cost, electricity from rooftop solar costs 22.3c/kWh under assumptions of a 30 year lifetime with no degradation, 0.15 capacity factor, a modest 5% discount rate and no O&M costs over the entire lifetime. Adding the free balancing services received by rooftop solar owners would further inflate this price as outlined in the first part of this article. Your 3-6c/kWh value is just completely out of touch with reality and such misinformation is very much unhelpful to the broader energy discussion on this site.

About subsidies, please see my analysis here using broader and more objective data than the CleanTechnica link you provided. BTW, the most interesting thing for me from the CleanTechnica link was the wind power projection of 52.7 GW of global installations in 2013 – 50% higher than the 35.4 GW actually installed. If you want to debate about subsidies, please leave a comment under the linked article. Here is not the place.

Robert Bernal's picture
Robert Bernal on Jul 1, 2014

Waste to fuels is a good idea at the dump. Nevertheless it can’t power much (because it is negative EROI). Once technology is around to convert trees into methanol, that’s end of story, like a trillion times worse than nuclear (and even worse than coal) because greed will set in and devour what’s left of the forests (and the dead stuff that needs to be left in the ground to make good soil for CO2 retention!

Robert Bernal's picture
Robert Bernal on Jul 1, 2014

High temp nuclear could be developed in line with molten salt (heat) storage. Such could then be of a lower nameplate capacity and still deal with daily grid fluctuations as long as the turbine itself can be throttled up and down.

Bas Gresnigt's picture
Bas Gresnigt on Jul 1, 2014

“…How on Earth do you get 3-6c/kWh for rooftop solar in the US?”
Big solar in the US is already within that range, as confirmed by the Austin PPA.

Assuming:
– US installers will learn, and migrate towards similar efficiency as the German installers;
– the big import tariffs (~40%) will be off in 10years (China complained at the GATT);
– progress in efficiency continues (Sunpower plans to deliver 23% efficient panels next year);
You can expect that price levels in USA in 2030 or so

Remember that the present Feed-in-Tariff for rooftop solar is 13cent/KWh in Germany (going down with 1%/month). As av. insolation in USA is ~30% better, this translates to 13$cnt/KWh.

With the long term decrease of 8%/a that price level will be reached in a decade.
Taking into account the fast technology improvements the labs find, I estimate it will go down further towards <3$cnt/Kwh for rooftop and wall-covers in ~2035 (using thin-film).

Nearly all new houses will get a roof with integrated solar. Last year I saw the first of those in Italy. This spring the first in the Nethelands.

Schalk Cloete's picture
Schalk Cloete on Jul 1, 2014

The question here was about the claim of “Without subsidies breaks and protection, electricity prices for newly installed generators would be: rooftop solar Power: 3-6 cents/KWH” made by Donovan above. I am familiar with your optimistic view of future fully installed solar PV costs, but this is not applicable in this thread.

About the insinuation that Germany proves that rooftop solar is currently at about $13c/kWh, the very slow rate of current PV deployment in Germany shows that this is not sufficient to drive the kind of deployment that is required. In addition, as we have discussed before, German housholds install rooftop solar primarily to avoid retail electricity costs of 30c/kWh, not to get 13c/kWh for electricity fed into the grid. This implies that a household which manages 40% self consumption gets about 20c/kWh of value from their solar installation (together with free balancing services from the stuggling utilities). To me, this data suggests that rooftop solar is still not scalable even if owners are effectively paid 20c/kWh of solar PV electricity, recieve free balancing services from the grid and recieve very low financing costs which misprice the risks involved.

Schalk Cloete's picture
Schalk Cloete on Jul 1, 2014

I am still waiting for a credible source to back up the claim of 3-6c/kWh for unsubsidized rooftop solar.

The discount rate is an interesting topic which will be discussed in detail in a future article in the Seeking Consensus column when we discuss the internalized costs of solar PV. This article will probably appear in about 2 months’ time and then we can debate this issue at length.

Nathan Wilson's picture
Nathan Wilson on Jul 2, 2014

I don’t see the relevance of data on German nuclear plants which are not representative a plants which would be built today (and which apparently lack the load following features of their French competitors which were built in the same timeframe).

Also, you are mistaken in citing the examples of Scotland and Denmark.  These are not complete grids, but small pieces of larger grids with much lower renewable penetration.  

German policians can promise whatever they like for 2050; it will someone else’s problem to actually make it work (and as I have said, Germany already has a very large amount of energy storage on their grid:  enough for 15% of their average demand; you’re counter claims that their storage is not cost effective under the  current market design does not prove that it is not needed).  

Rick Engebretson's picture
Rick Engebretson on Jul 2, 2014

There is a difference between doing and talking. Since I’m sweaty and need a break from the wood chipper, allow me to try restrain my disappoinment with the ignorant.

I have 50 more poplars laying on the ground (for next year) to make room for DNR supplied trees (like white cedar) to enhance biodiversity. Tree swallows are everywhere. Raspberries ripening, ready to give away (some Indians once traded walleye). I’m a Biophysicist by training, my wife a food scientist. I got “solar biofuels” on the national reasearch agenda. I can’t keep up as it is, so please take a hike.

Robert Bernal's picture
Robert Bernal on Jul 2, 2014

I don’t believe we should use the forests as industrial energy supply source because it is not sustainable (at the large scale). Other than building materials, it should only be used for small scale (wood burners, etc). If there is “too much”, then we should somehow sequester the CO2 from the wood and isolate it “forever” to try to reverse the excess CO2 that is causing warming and chemical changes. If possible, this should be done to the bark beetled wood before it burns from wildfire.

Robert Bernal's picture
Robert Bernal on Jul 2, 2014

I definitely agree that we should not use virgin crops for energy. However, although a good idea (being that you addressed the more important concerns about good soil) wastes can only be a rather small part of the overall energy picture. And thanks for the link, I want to learn more about biochar!

Schalk Cloete's picture
Schalk Cloete on Jul 2, 2014

Where did you provide this link before? But anyway, if you think the world will make its energy investment decisions based on a 100 year lifetime and 0% discount rate for rooftop solar, you are living in a very different reality from the rest of us.

Schalk Cloete's picture
Schalk Cloete on Jul 2, 2014

Sure, peer-review is definitely not perfect, but it serves a very important purpose in the information age we live in today. I have published and reviewed many scientific papers for international journals and conferences and I can tell you that the peer-review process forces you to be very critical of your own work. This serves to prevent a flood ignorant and subjectively biased opinions from prolifirating exponentially and completely obscuring the objective reality. In the times we live in where anyone with a computer can share his/her views with thousands of others, this is incredibly important.

Thus, credibility is a question of relativity. Given the enormous complexity of the energy and climate issues discussed on this site, no person or group can be fully credible. However, respected groups of highly educated and experienced professionals and papers published in peer-reviewd journals are certainly much more credible than some obviously subjectively biased comments from someone with no profile information on TEC. When it comes to the question of which source to use for important strategic decision-making, the choice really is blatantly obvious.

Bas Gresnigt's picture
Bas Gresnigt on Jul 2, 2014

“…forests as industrial energy supply source … not sustainable (at the large scale). Other than building materials, it should only be used for small scale (wood burners, etc)…”

Small scale wood burners create big scale pollution, which is worse than large scale wood burners.

Of course it is sustainable with good wood management as shown in NW-Europe (nealy only production woods) since centuries.

 

Thomas Maloney's picture
Thomas Maloney on Aug 19, 2015

I agree with Udy on some of his comments here. We shouldn’t be talking so much on consensus and the like rather than actually getting things done. Storage solutions for the future energy sources really require us to focus on getting battery units or whatever things implemented not theoretically argued about.

Robert Bernal's picture
Robert Bernal on Aug 20, 2015

I’d like to know just what is the cheapest storage. If Highest efficiency, then less collection capacity needed. But really cheap storage might afford a little more capacity build up. 

However, what really counts is if the system can energy pay for itself. For example,  the whole world could be powered by solar and batteries but if they were lead acid, it would require more energy than it’s worth (and way to much land). I do believe that other kinds of batteries will require far less energy input.

It might be easier once we figure out aneutronic fusion by use of picowatt scale lasers… (or simply deal with molten salt nuclears for the time being).

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