I’m wondering what happens when you generate the green hydrogen in one place and transport it to another.
For example, here in Atlantic Canada, we have at least two organizations vying to plant offshore and onshore wind turbines all over the place and then use the power generated to make hydrogen, which they hope to sell overseas. Beyond the costs you’ve calculated, it seems to me that adding in transport by ship (likely burning fossil fuels!) would likely make the whole enterprise even less financially viable.
The other bit of stupidity, in our case, is that over half of our electricity in Nova Scotia comes from coal, so they should have a market to sell wind power here, without going through all the nonsense of making hydrogen.
Sadly, our provincial and federal governments seem quite supportive of the whole hydrogen project, even to the extent of subsidies, which of course may be the reason why the business people wish to proceed.
One does not have to look far to discover that the energy to produce and isolate 1 kg of hydrogen exceeds the amount of energy that 1 kg of hydrogen contains.
That's not correct, although you do use a lot of energy in making hydrogen whichever way you do it. An optimal PEM electrolysis system is about 60% efficient - i.e. the energy content of the hydrogen compared with the electrical energy used in making it. Actual efficiency in intermittent use will be somewhat lower. The embedded energy in the plant itself does enter a full EROEI calculation, but given enough use that is overcome.
Of course it would not make sense to use hydrogen to fuel a generator to enable power for an electrolyser to make hydrogen, but that only happens in CCC fantasies.
The energy density of 1 kg hydrogen is 142 Kilojoules/kg. Thats alot on the relative scale of combustable materials, which sounds good at first.
Unfortunately, to produce, purify, and contain 1 kg of hydrogen the enrgy input exceeds that number. Google is your friend in this case. There are a number of academic and industrial peer reviewed articles that describe this.
This may help in the short term as well:
The Energy Density of Fuels and Why We Need Nuclear Now
The Energy Density of fuels is a critical concept in the field of energy
If google is your friend I suggest you provide a proper reference for your claim.
Hydrogen based systems have low round trip efficiencies (hydrogen is after all merely an energy store, not an energy source), but they are not completely destructive of energy. For example, if you start with 60% efficient production via PEM, and then compress it and transport it for use in a hydrogen fuelled vehicle that process is ~75% efficient, so at the point of fuelling we are at 45% efficient, and the fuel cell and motor operates at say 50% efficiency, so we are now down to 22.5% of the electricity input.
Having started my career working at AERE Harwell, I can assure you I am well aware of the energy density of nuclear fuels, which is not really relevant to this particular discussion, though you will find David has written some very good articles on nuclear. This one is a good place to start:
Thank you for your reply. I have a chemist's perspective, having 30 years in academia and industry. I always start with Chem 101, which includes the First and Second Law of Thermodynamics.
The energy content of hydrogen is high, but there are great number of disadvantages with regards to production, purification, storage, handling and transport. It is very lossy and expensive. That is because it is a very small molecule with very little affinity for itself.
Hydrogen is.commonly used in many chemical processes, and sometimes is produced as a byproduct. To that end, local production and consumption is a great advantage, and the chemical industry takes advantage of this routinely. Bulk transport is expensive and requires great energy input at our STP.
With regards to efficiency, it is everything. There is strictly no such thing as sustainable or renewable due to the Laws. The closest thing is the planet, without people, in equilibrium. But again, the sun is the input source, so the example is still weak.
I have seen no real data that convinces me that a widespread non-local hydrogen economy is feasible. This is due to the chemical character of hydrogen itself which I touched upon.
Nuclear hydrolysis could be a good local source of hydrogen for local distribution and use, but alas, politics and other barriers continue to block nuclear, as you know.
Thank you for the excellent nuclear article. I am a proponent of nuclear. As far as references via Google that you request, I am sure you can locate some easily, but I can supply when I get back to my local PC in a day or so.
I am having difficulty reconciling some of your calculations.
Your line D shows storage cost and overbuild wastage/loss is some £54.63/MWh, or £31.1bn p.a. on 570TWh, of which the overbuild is 171TWh at £89.05, or £15.1bn, leaving £16bn for the storage. The annualised charge is 11.5% capital charge at 11% interest plus 1.5% OPEX, or a total of 13% of capital cost, implying 16/0.13 or £123bn or £1bn per TWh, not the £0.4bn/TWh they assumed.
Your Line E adds another £62.46 for electrolysers and generators. AFAICS you are assuming electrolysers cost 7.5 times as much as the RS assumption (£2,500 vs £333/kW), and generators 2.70 times as much (£850 vs £315/kW). The per MWh costs in the RS figures are £4.19/MWh of demand for electrolysers, and £4.42/MWh or demand for generators per their formula I already quoted. Using your costs the total would be £43.37/MWh at 5% discount, so your are using an annual charge factor of (62.46/43.37)x(6.51+1.5)% or 11.5%. Subtracting the 1.5% for OPEX the financing capital charge is 10%, implying an interest rate of 9.3%.
These discrepancies echo through the rest of the calculations. Perhaps you can show where I am wrong, or you may wish to revise your calculations or clarify your assumptions.
Agreed. An extra 171TWh of generation (=30% of 570TWh) at a cost of ~£90/MWh whether you factor it as average current administrative strike prices or by your realistic LCOE for standalone renewables before backup and integration costs.
And if storage costs are rather higher, the economic optimum is less storage and more generation even at high marginal curtailment rates, at least so long as the generation isn't also equally more expensive.
If we start with the storage your DCF model presumably shows a year zero investment, and cash outflows for debt interest and OPEX at 11% and 1.5% of the overnight capital cost for the next 30 years, though if we look at Stublach cavern leaching took 9 years, so I suspect the book cost of the assets probably includes capitalised interest during construction, but that is extra sophistication given the cost uncertainty. That can be equally assessed using capital charge methodology, which is just the mortgage amortisation required to pay off the capital cost. It's a very handy way of cross checking.
I suspect your spreadsheet is simply taking the capacity of 123TWh and not multiplying it by the £400/MWh=£0.4bn/TWh cost, because it is otherwise a strange coincidence that back calculation using capital charge methodology shows a capital cost of £1bn/TWh.
As it happens, my model is for 1% of the entire system, assuming the whole thing could be scaled up. As per the Government's Gen Cost report, there's a small amount of pre-development spend over five years, then the main capex over two years. I put the capex for the whole storage system over the same two years in years 6 & 7, spread 50:50. For the base case in line D, I used the costs that RS used £333/kW for electrolysers, £400/MWh for the caverns and £315/kW for the generators. 11% costs of capital. Life 30 years (generous), that starts in year 8. 1.5% opex throughout.
I am quite happy with your line C £89.05/MWh value (if anything I'd guess current evidence might even boost it a little - NYISO just ran an offshore auction at $145.07/MWh though you have to be careful comparing depending on what connection costs are borne by the wind farm), and boosting that by 30% to allow for overbuild, to get to £115.77/MWh levelised cost for the WTG input to the system.
I took your description of line D quite literally, to include WTG input (including uplift) and storage only - and not including electrolysers and generators which you appeared to introduce in line E. If I now include electrolysers and generators, then the simple capital charge methodology for line D works out at £141/MWh, which is close enough for government work.
I think we are back on the same page. I apologise for having queried your calculations, but I hope you do not mind my having done so: it is always worth ensuring that figures that start getting quoted more widely in the public domain are robust, and that room for misunderstanding is removed.
Sorry I should have been clearer. Line D is for the full storage system. Electrolysers, Storage, using their unit numbers. Line E then uses 2018 (or average 2018-2050) numbers for the whole system.
Thanks so much for doing all these calculations. It seems like every one of these official-looking pro-Green reports are loaded with extremely optimistic assumptions that are not obvious to casual readers. Given that almost all the error is in one direction, it is clearly deliberate.
But it is difficult to prove that the assumptions are heavily biased without a huge amount of research. Thanks for doing the grunge work!
I have been scouring the Supplementary Information and other sources to try to verify and understand what the Royal Society actually did in making their cost assumptions. On p162 I found:
Power ↔ Hydrogen
At 5% discount rate £[(26.7 x electrolyser power in GW + 32.1 x size of the store in
TWhLHV +25.2 x maximum power output in GW)/(Annual Output TWh)]/MWh
At 10% discount rate £[([40.3] x electrolyser power in GW + [48.4] x size of the store in
TWhLHV +[38.1] x maximum power output in GW)/(Annual Output TWh)]/MWh
It is useful to note capital charge factors for 5% and 10% discount rates =-PMT(5%,30,1,0) =6.51% at 5% and 10.61% at 10%. Then we can verify base electrolyser cost as £333(0.0651+0.015) for capital plus OPEX at 5% discount rate on their assumptions - £26.67/kW (or £26.67m/GW), and likewise for the generators. I am still struggling to reproduce their figure for the actual storage: the procedure comes out over 80% more costly at 5%.
At the start of the cost chapter there is a limited discussion of transmission and grid stabilisation costs. The grid stabilisation they have assumed is provided by 15GWh of 1 hour duration batteries. These will need to turn over about twice a day to be economic, generating round trip losses of about 7.5GWh/day, or 2.7TWh/year. Their assumptions about battery life and installed cost seem to be very low. Taking 10 years life and an installed cost of £500/kWh I get to about £1.90/MWh of demand or about £1.1bn: however, this is way below current BSUoS charges of ~£4bn, and even if we subtract curtailment (as this is costed at LCOE) it still remains very substantially higher and growing. Their costing of transmission is something else altogether. Checking up on TNUoS figures I found that for 2018/19 the total cost was £2.67bn, with charging split between generators (£430m) and demand (£2,240m): that would have been just under £10/MWh. For the current year we are looking at £3.5bn - and the costs are growing rapidly, with NG's announced £200bn+ investment in upgrades to be paid for likely to add over £10bn p.a. when complete. Yet the study only includes £3/MWh, forgetting that the cost allocation is not the real basis for a whole grid cost. Moreover, dedicated connection lines for renewables will see low average utilisation rates, so the cost per MWhkm delivered will be substantially higher than grid averages, and the need for STATCOMs, synchronous condensers, etc. will add substantially. Even diluted by the higher 570TWh demand we should expect £23+/MWh. For comparison, IIRC the balance sheet cost of the grid was about £80bn, depreciated to ~£40bn on an 80 year life, with investment running at a little over £1bn p.a. to match depreciation back before renewables became a thing - and the grid carried ~400TWh in its peak year - total TNUoS was £1.35bn in 2008/9.
That of course excludes DUoS costs, a good chunk of which will be incurred in accommodating embedded renewables, as well as completely recabling the streets to provide power for heat pumps and EVs. The division of cost is trickier here.
Now add in the "ambitious" assumptions about wind and solar costs and capacity factors, and take proper account of the flattening of the demand projection by AFRY to remove major peaks and troughs and look at the other cost assumptions and I think we are going to end up with a much more expensive system. Moreover, I suspect that the lowest cost options will include more renewables generation and curtailment, because the hydrogen storage element will prove too costly to be extensive. There will be a slight offset from more economically viable shorter term storage, but it isn;t going to rescue the situation.
The quoted cost for the storage of £727/MWhe are for the electrical equivalent of hydrogen. Factoring in their 55% efficiency of the generators brings the cost down to £400/MWh (LHV) hydrogen.
I hadn't previously looked a their transmission cost estimate. But your numbers seem to indicated they should add at least another £20/MWh to their numbers.
Seeing that explanation reminds me that we have a direct cost comparison with Stublach (I passed a few miles away through the attractive part of Cheshire 10 days ago). That has 400mcm of storage or 4.4TWh as methane, at a cost of £500m. Operating pressures are to some extent governed by the pressure of the overburden or ρgh e.g.~2500x10x500=12.5MPa=125bar. When I researched this previously I found that hydrogen stores operate at lower pressure than methane stores, meaning that instead of taking up 3 times the volume, hydrogen actually takes up more like 5 times the volume. So the base cost is likely somewhat higher per MWh than they assume. It is hard to see the costs of leaching coming down: these are probably dominated by brine disposal which might involve disposal at sea rather than shore discharge when larger quantities are involved.
Perhaps an offset is that a storage cavern should last longer than 30 years. Some have already been operating for over 60 years, which is just as well - if new caverns had to be leached every 30 years we would soon run out of space. The cost of financing will largely depend on the perceived risk to revenues. That is lower if there is no threat of a foreshortened asset life (a big risk with WTGs) and if it is simply granted the right to make a fixed charge to cover its financing costs, as with e.g. TNUoS.
What a nutty idea! There is a lot missing from the cost calculations. One thing is the cost & losses of compressing that H2 for transmission to ~1400psi. And then pump stations to pump that H2 to the salt caverns. And we know H2 is the leakiest gas, very hard to stop leakage, so there will be leakage losses in all stages of the H2 facilities. And that's very inefficient transmission as the energy density of the H2 will be 34% of CNG at the same pressure. And H2 embrittlement of all that hardware means high O&M costs. I don't see anything on those high H2 transmission costs.
As you assumed, dubious the electrolysers will be near the storage area. And you have water pumping stations and pipelines. Then the problem is wind/solar are vary widely in output. So the electrolysers will not be running in baseload mode. Running at a CF probably of ~25%. I doubt they took that into account in their calculation of electrolyser cost. That's 4X the capital cost. Nasty having to pay for all those expensive, H2 high pressure, low energy density pipelines and run them at a CF of 25% also. So you probably would want one days H2 storage on the site of the electrolysers at a considerable added cost.
And then the long distance transmission lines from the solar/wind plants to the electrolysers. You will have high line losses because you get low ROI by adding aluminum to the transmission lines. Since with solar you are running max output for only ~3hrs/day. Not like a baseload plant savings for a full 24hrs/day. Add transmission lines from the H2 generators to the grid.
All that infrastructure will be vulnerable to damage from H2 leaks & explosions. Even for much more valuable, much more localized Rockets, these leaks & explosions have been a constant nightmare, with several massive explosions destroying rockets and launch facilities. With long flight delays and cancellations due to H2 leaks. That's why Elon Musk & Jeff Bezos both chose methane instead of H2 for their rockets in spite of the substantial energy/mass ratio of H2. I see very high insurance costs in all of this.
This whole idea is just crazy. Imagine the EROI for that massive infrastructure, starting with the already abysmal EROI of the wind & solar. I would bet an overall EROI of <1:1. A net energy drain. A physically impossible energy source.
Yes, they have made no allowance for compression and cooling losses. The H21 report has a big section on that. And you're right, they haven't included any costs for some sort of hydrogen transmission system.
I'm working on an article about the EROEI of the system. It's not as bad as you might think, but not something anyone should be advocating.
One of the sources of the seriously underestimated costs is a document produced by the UK government that has been used in studies, which then purport to show that renewables are cheap, and complete the loop by feeding that same erroneous estimate back to the government to establish policy. A process I named "the cheap wind energy echo chamber"
Perhaps the biggest problem of all is that after building a massively expensive energy system dependent on wind and solar with massive storage, that energy system will still be unreliable. The massive storage suggested by the Royal Society (and I think the storage number they suggest is in the right ball park) takes ten years to fill but it empties in one year of exceptionally low wind. How will you know, once it is empty that you will have another ten years to fill it again before the next year of exceptionally low wind?
I also think the forecasts of renewables and storage costs for 2050 are just wishful thinking on the part of the renewables proponents. I see no compelling reason why offshore wind, for example, should be half the cost in 2050 versus 2023.
The one technology that has the biggest potential for cost reductions is nuclear.
Not stated, but your Figure A/RS Figure 24 is in 2021 money according to the RS footnote describing the figure. Looking up CPI data at the ONS, the index was at 111.3 in Jun 2021 and 131.5 in Jun 2023, giving an uplift of 18.1%. That somewhat reduces the apparent differential between their base costs and yours. If you use RPI instead, then the difference is 23.8%.
I’m wondering what happens when you generate the green hydrogen in one place and transport it to another.
For example, here in Atlantic Canada, we have at least two organizations vying to plant offshore and onshore wind turbines all over the place and then use the power generated to make hydrogen, which they hope to sell overseas. Beyond the costs you’ve calculated, it seems to me that adding in transport by ship (likely burning fossil fuels!) would likely make the whole enterprise even less financially viable.
The other bit of stupidity, in our case, is that over half of our electricity in Nova Scotia comes from coal, so they should have a market to sell wind power here, without going through all the nonsense of making hydrogen.
Sadly, our provincial and federal governments seem quite supportive of the whole hydrogen project, even to the extent of subsidies, which of course may be the reason why the business people wish to proceed.
One does not have to look far to discover that the energy to produce and isolate 1 kg of hydrogen exceeds the amount of energy that 1 kg of hydrogen contains.
Probably best to start there.
That's not correct, although you do use a lot of energy in making hydrogen whichever way you do it. An optimal PEM electrolysis system is about 60% efficient - i.e. the energy content of the hydrogen compared with the electrical energy used in making it. Actual efficiency in intermittent use will be somewhat lower. The embedded energy in the plant itself does enter a full EROEI calculation, but given enough use that is overcome.
Of course it would not make sense to use hydrogen to fuel a generator to enable power for an electrolyser to make hydrogen, but that only happens in CCC fantasies.
Not correct? Please consider the following:
The energy density of 1 kg hydrogen is 142 Kilojoules/kg. Thats alot on the relative scale of combustable materials, which sounds good at first.
Unfortunately, to produce, purify, and contain 1 kg of hydrogen the enrgy input exceeds that number. Google is your friend in this case. There are a number of academic and industrial peer reviewed articles that describe this.
This may help in the short term as well:
The Energy Density of Fuels and Why We Need Nuclear Now
The Energy Density of fuels is a critical concept in the field of energy
https://tucoschild.substack.com/p/energy-density-and-why-we-need-nuclear
Regards,
TC
If google is your friend I suggest you provide a proper reference for your claim.
Hydrogen based systems have low round trip efficiencies (hydrogen is after all merely an energy store, not an energy source), but they are not completely destructive of energy. For example, if you start with 60% efficient production via PEM, and then compress it and transport it for use in a hydrogen fuelled vehicle that process is ~75% efficient, so at the point of fuelling we are at 45% efficient, and the fuel cell and motor operates at say 50% efficiency, so we are now down to 22.5% of the electricity input.
Having started my career working at AERE Harwell, I can assure you I am well aware of the energy density of nuclear fuels, which is not really relevant to this particular discussion, though you will find David has written some very good articles on nuclear. This one is a good place to start:
https://davidturver.substack.com/p/how-to-make-nuclear-power-cheaper
Thank you for your reply. I have a chemist's perspective, having 30 years in academia and industry. I always start with Chem 101, which includes the First and Second Law of Thermodynamics.
The energy content of hydrogen is high, but there are great number of disadvantages with regards to production, purification, storage, handling and transport. It is very lossy and expensive. That is because it is a very small molecule with very little affinity for itself.
Hydrogen is.commonly used in many chemical processes, and sometimes is produced as a byproduct. To that end, local production and consumption is a great advantage, and the chemical industry takes advantage of this routinely. Bulk transport is expensive and requires great energy input at our STP.
With regards to efficiency, it is everything. There is strictly no such thing as sustainable or renewable due to the Laws. The closest thing is the planet, without people, in equilibrium. But again, the sun is the input source, so the example is still weak.
I have seen no real data that convinces me that a widespread non-local hydrogen economy is feasible. This is due to the chemical character of hydrogen itself which I touched upon.
Nuclear hydrolysis could be a good local source of hydrogen for local distribution and use, but alas, politics and other barriers continue to block nuclear, as you know.
Thank you for the excellent nuclear article. I am a proponent of nuclear. As far as references via Google that you request, I am sure you can locate some easily, but I can supply when I get back to my local PC in a day or so.
I am having difficulty reconciling some of your calculations.
Your line D shows storage cost and overbuild wastage/loss is some £54.63/MWh, or £31.1bn p.a. on 570TWh, of which the overbuild is 171TWh at £89.05, or £15.1bn, leaving £16bn for the storage. The annualised charge is 11.5% capital charge at 11% interest plus 1.5% OPEX, or a total of 13% of capital cost, implying 16/0.13 or £123bn or £1bn per TWh, not the £0.4bn/TWh they assumed.
Your Line E adds another £62.46 for electrolysers and generators. AFAICS you are assuming electrolysers cost 7.5 times as much as the RS assumption (£2,500 vs £333/kW), and generators 2.70 times as much (£850 vs £315/kW). The per MWh costs in the RS figures are £4.19/MWh of demand for electrolysers, and £4.42/MWh or demand for generators per their formula I already quoted. Using your costs the total would be £43.37/MWh at 5% discount, so your are using an annual charge factor of (62.46/43.37)x(6.51+1.5)% or 11.5%. Subtracting the 1.5% for OPEX the financing capital charge is 10%, implying an interest rate of 9.3%.
These discrepancies echo through the rest of the calculations. Perhaps you can show where I am wrong, or you may wish to revise your calculations or clarify your assumptions.
Overbuild means you need 741TWh of supply to meet 570TWh of demand which effectively pushes up the cost of renewables by 30%.
Agreed. An extra 171TWh of generation (=30% of 570TWh) at a cost of ~£90/MWh whether you factor it as average current administrative strike prices or by your realistic LCOE for standalone renewables before backup and integration costs.
And if storage costs are rather higher, the economic optimum is less storage and more generation even at high marginal curtailment rates, at least so long as the generation isn't also equally more expensive.
I am not using their formulae. I am using a DCF model. Discount rate 11%. Costs of electrolysers etc as per the images in the post.
If we start with the storage your DCF model presumably shows a year zero investment, and cash outflows for debt interest and OPEX at 11% and 1.5% of the overnight capital cost for the next 30 years, though if we look at Stublach cavern leaching took 9 years, so I suspect the book cost of the assets probably includes capitalised interest during construction, but that is extra sophistication given the cost uncertainty. That can be equally assessed using capital charge methodology, which is just the mortgage amortisation required to pay off the capital cost. It's a very handy way of cross checking.
I suspect your spreadsheet is simply taking the capacity of 123TWh and not multiplying it by the £400/MWh=£0.4bn/TWh cost, because it is otherwise a strange coincidence that back calculation using capital charge methodology shows a capital cost of £1bn/TWh.
As it happens, my model is for 1% of the entire system, assuming the whole thing could be scaled up. As per the Government's Gen Cost report, there's a small amount of pre-development spend over five years, then the main capex over two years. I put the capex for the whole storage system over the same two years in years 6 & 7, spread 50:50. For the base case in line D, I used the costs that RS used £333/kW for electrolysers, £400/MWh for the caverns and £315/kW for the generators. 11% costs of capital. Life 30 years (generous), that starts in year 8. 1.5% opex throughout.
I am quite happy with your line C £89.05/MWh value (if anything I'd guess current evidence might even boost it a little - NYISO just ran an offshore auction at $145.07/MWh though you have to be careful comparing depending on what connection costs are borne by the wind farm), and boosting that by 30% to allow for overbuild, to get to £115.77/MWh levelised cost for the WTG input to the system.
I took your description of line D quite literally, to include WTG input (including uplift) and storage only - and not including electrolysers and generators which you appeared to introduce in line E. If I now include electrolysers and generators, then the simple capital charge methodology for line D works out at £141/MWh, which is close enough for government work.
I think we are back on the same page. I apologise for having queried your calculations, but I hope you do not mind my having done so: it is always worth ensuring that figures that start getting quoted more widely in the public domain are robust, and that room for misunderstanding is removed.
Sorry I should have been clearer. Line D is for the full storage system. Electrolysers, Storage, using their unit numbers. Line E then uses 2018 (or average 2018-2050) numbers for the whole system.
Yes, it's always good to have a challenge.
Thanks so much for doing all these calculations. It seems like every one of these official-looking pro-Green reports are loaded with extremely optimistic assumptions that are not obvious to casual readers. Given that almost all the error is in one direction, it is clearly deliberate.
But it is difficult to prove that the assumptions are heavily biased without a huge amount of research. Thanks for doing the grunge work!
I have been scouring the Supplementary Information and other sources to try to verify and understand what the Royal Society actually did in making their cost assumptions. On p162 I found:
Power ↔ Hydrogen
At 5% discount rate £[(26.7 x electrolyser power in GW + 32.1 x size of the store in
TWhLHV +25.2 x maximum power output in GW)/(Annual Output TWh)]/MWh
At 10% discount rate £[([40.3] x electrolyser power in GW + [48.4] x size of the store in
TWhLHV +[38.1] x maximum power output in GW)/(Annual Output TWh)]/MWh
It is useful to note capital charge factors for 5% and 10% discount rates =-PMT(5%,30,1,0) =6.51% at 5% and 10.61% at 10%. Then we can verify base electrolyser cost as £333(0.0651+0.015) for capital plus OPEX at 5% discount rate on their assumptions - £26.67/kW (or £26.67m/GW), and likewise for the generators. I am still struggling to reproduce their figure for the actual storage: the procedure comes out over 80% more costly at 5%.
At the start of the cost chapter there is a limited discussion of transmission and grid stabilisation costs. The grid stabilisation they have assumed is provided by 15GWh of 1 hour duration batteries. These will need to turn over about twice a day to be economic, generating round trip losses of about 7.5GWh/day, or 2.7TWh/year. Their assumptions about battery life and installed cost seem to be very low. Taking 10 years life and an installed cost of £500/kWh I get to about £1.90/MWh of demand or about £1.1bn: however, this is way below current BSUoS charges of ~£4bn, and even if we subtract curtailment (as this is costed at LCOE) it still remains very substantially higher and growing. Their costing of transmission is something else altogether. Checking up on TNUoS figures I found that for 2018/19 the total cost was £2.67bn, with charging split between generators (£430m) and demand (£2,240m): that would have been just under £10/MWh. For the current year we are looking at £3.5bn - and the costs are growing rapidly, with NG's announced £200bn+ investment in upgrades to be paid for likely to add over £10bn p.a. when complete. Yet the study only includes £3/MWh, forgetting that the cost allocation is not the real basis for a whole grid cost. Moreover, dedicated connection lines for renewables will see low average utilisation rates, so the cost per MWhkm delivered will be substantially higher than grid averages, and the need for STATCOMs, synchronous condensers, etc. will add substantially. Even diluted by the higher 570TWh demand we should expect £23+/MWh. For comparison, IIRC the balance sheet cost of the grid was about £80bn, depreciated to ~£40bn on an 80 year life, with investment running at a little over £1bn p.a. to match depreciation back before renewables became a thing - and the grid carried ~400TWh in its peak year - total TNUoS was £1.35bn in 2008/9.
That of course excludes DUoS costs, a good chunk of which will be incurred in accommodating embedded renewables, as well as completely recabling the streets to provide power for heat pumps and EVs. The division of cost is trickier here.
Now add in the "ambitious" assumptions about wind and solar costs and capacity factors, and take proper account of the flattening of the demand projection by AFRY to remove major peaks and troughs and look at the other cost assumptions and I think we are going to end up with a much more expensive system. Moreover, I suspect that the lowest cost options will include more renewables generation and curtailment, because the hydrogen storage element will prove too costly to be extensive. There will be a slight offset from more economically viable shorter term storage, but it isn;t going to rescue the situation.
The quoted cost for the storage of £727/MWhe are for the electrical equivalent of hydrogen. Factoring in their 55% efficiency of the generators brings the cost down to £400/MWh (LHV) hydrogen.
I hadn't previously looked a their transmission cost estimate. But your numbers seem to indicated they should add at least another £20/MWh to their numbers.
Seeing that explanation reminds me that we have a direct cost comparison with Stublach (I passed a few miles away through the attractive part of Cheshire 10 days ago). That has 400mcm of storage or 4.4TWh as methane, at a cost of £500m. Operating pressures are to some extent governed by the pressure of the overburden or ρgh e.g.~2500x10x500=12.5MPa=125bar. When I researched this previously I found that hydrogen stores operate at lower pressure than methane stores, meaning that instead of taking up 3 times the volume, hydrogen actually takes up more like 5 times the volume. So the base cost is likely somewhat higher per MWh than they assume. It is hard to see the costs of leaching coming down: these are probably dominated by brine disposal which might involve disposal at sea rather than shore discharge when larger quantities are involved.
Perhaps an offset is that a storage cavern should last longer than 30 years. Some have already been operating for over 60 years, which is just as well - if new caverns had to be leached every 30 years we would soon run out of space. The cost of financing will largely depend on the perceived risk to revenues. That is lower if there is no threat of a foreshortened asset life (a big risk with WTGs) and if it is simply granted the right to make a fixed charge to cover its financing costs, as with e.g. TNUoS.
What a nutty idea! There is a lot missing from the cost calculations. One thing is the cost & losses of compressing that H2 for transmission to ~1400psi. And then pump stations to pump that H2 to the salt caverns. And we know H2 is the leakiest gas, very hard to stop leakage, so there will be leakage losses in all stages of the H2 facilities. And that's very inefficient transmission as the energy density of the H2 will be 34% of CNG at the same pressure. And H2 embrittlement of all that hardware means high O&M costs. I don't see anything on those high H2 transmission costs.
As you assumed, dubious the electrolysers will be near the storage area. And you have water pumping stations and pipelines. Then the problem is wind/solar are vary widely in output. So the electrolysers will not be running in baseload mode. Running at a CF probably of ~25%. I doubt they took that into account in their calculation of electrolyser cost. That's 4X the capital cost. Nasty having to pay for all those expensive, H2 high pressure, low energy density pipelines and run them at a CF of 25% also. So you probably would want one days H2 storage on the site of the electrolysers at a considerable added cost.
And then the long distance transmission lines from the solar/wind plants to the electrolysers. You will have high line losses because you get low ROI by adding aluminum to the transmission lines. Since with solar you are running max output for only ~3hrs/day. Not like a baseload plant savings for a full 24hrs/day. Add transmission lines from the H2 generators to the grid.
All that infrastructure will be vulnerable to damage from H2 leaks & explosions. Even for much more valuable, much more localized Rockets, these leaks & explosions have been a constant nightmare, with several massive explosions destroying rockets and launch facilities. With long flight delays and cancellations due to H2 leaks. That's why Elon Musk & Jeff Bezos both chose methane instead of H2 for their rockets in spite of the substantial energy/mass ratio of H2. I see very high insurance costs in all of this.
This whole idea is just crazy. Imagine the EROI for that massive infrastructure, starting with the already abysmal EROI of the wind & solar. I would bet an overall EROI of <1:1. A net energy drain. A physically impossible energy source.
Yes, they have made no allowance for compression and cooling losses. The H21 report has a big section on that. And you're right, they haven't included any costs for some sort of hydrogen transmission system.
I'm working on an article about the EROEI of the system. It's not as bad as you might think, but not something anyone should be advocating.
Nice article.
I did a similar exercise and came to a similar conclusion - that the Royal Society grossly underestimated the true cost of renewables.
https://johnd12343.substack.com/p/we-have-to-stop-kidding-ourselves
One of the sources of the seriously underestimated costs is a document produced by the UK government that has been used in studies, which then purport to show that renewables are cheap, and complete the loop by feeding that same erroneous estimate back to the government to establish policy. A process I named "the cheap wind energy echo chamber"
https://johnd12343.substack.com/p/the-cheap-wind-energy-echo-chamber
Perhaps the biggest problem of all is that after building a massively expensive energy system dependent on wind and solar with massive storage, that energy system will still be unreliable. The massive storage suggested by the Royal Society (and I think the storage number they suggest is in the right ball park) takes ten years to fill but it empties in one year of exceptionally low wind. How will you know, once it is empty that you will have another ten years to fill it again before the next year of exceptionally low wind?
I also think the forecasts of renewables and storage costs for 2050 are just wishful thinking on the part of the renewables proponents. I see no compelling reason why offshore wind, for example, should be half the cost in 2050 versus 2023.
The one technology that has the biggest potential for cost reductions is nuclear.
Not stated, but your Figure A/RS Figure 24 is in 2021 money according to the RS footnote describing the figure. Looking up CPI data at the ONS, the index was at 111.3 in Jun 2021 and 131.5 in Jun 2023, giving an uplift of 18.1%. That somewhat reduces the apparent differential between their base costs and yours. If you use RPI instead, then the difference is 23.8%.