More on 'renewables plus hydrogen'

In the last piece on this website I argued that the most effective means of completely decarbonising electricity supply in the UK and elsewhere is to hugely expand the capacity of wind and solar power. This will mean frequent substantial surpluses of electricity when the unneeded power will be converted to hydrogen via electrolysis. This hydrogen can then be used an energy source for use in combined cycle gas turbine plants during periods of electricity deficit. 

I suggested that the UK needed approximately 4.5 times its existing resources of wind and solar power to carry out this strategy. These resources would provide enough electricity to cover all electricity needs, including in periods of deficit. The assumptions behind this number are overly simply but gave a good indication of how much new wind and solar would be needed. I also said that the country would have needed about 75 GW of electrolysers to ensure that all electricity generated would be used. 

This brief article now looks in a little more detail at the requirements for electrolysers. In particular, I ask the question ‘how much more electricity generating capacity would be needed if we restricted the availability of electrolysers to much lower levels?’. The logic is this: 75 GW would only be needed for a few half hour periods a year so if we had less capacity, we would lose relatively small amounts of hydrogen. We would have to make up this loss by installing more wind and solar but this might be less costly than installing huge amounts of electrolyser plant.

I also made one important change to the spreadsheet. I previously assumed that wind and solar would produce all the the electricity needed in each of the 17,520 half periods of the year to 30th June 2021. This ignored other low carbon sources. So for the exercise covered in this article I included nuclear power, biomass and hydro as low carbon sources. In each period I therefore took the total demand figure and deducted the amounts of power provided by these three types of generator. This reduces the electricity required from wind and solar. 

The change substantially cuts the additional capacity required from these sources of power. Instead of needed 4.5 times as much solar and wind as today, the UK will only need a 3.4 times multiple. As a consequence, the maximum demand for electrolyser capacity falls from 75 GW to around 55 GW. To be clear, a 55 GW need arises because in at least one half hour period in the year under analysis, a 3.4 times multiple of wind and solar capacity would have resulted in 55 GW of unneeded electricity that would have been available for conversion into hydrogen.

But is it worth investing in as much electrolyser plant? If much of the capacity is only used a few hours a year, would it be better to install a smaller capacity for making hydrogen? This would mean that some electricity would be wasted at times of high production. However this could be compensated for by increases in solar and wind capacity that would produce more power in periods of lower surpluses. 

The chart below shows how what multiple of current wind and solar power would be needed to compensate for reduced electrolyser capacity. This exercise shows that partially restricting electrolyser availability has little impact because the number of hours of very substantial electricity surpluses were few in number across the year under study The addition requirements for renewables are very small indeed until electrolyser installations fall to less than half the maximum 55 GW total.

I then compared the costs of installing 55 GW of electrolyser and a 3.4 times multiple of current wind and solar with an alternative of 20 GW electrolyser capacity and 3.59 times these renewables. 

I think the approximate number suggest that the reduction in required electrolyser capacity reduces costs by about twice as much as the increased need for investment in renewables. 

The conclusion seems clear. It would be much better for the UK to go for 20 GW of electrolysers (or perhaps less) and a 3.59 times multiple of wind and solar. In addition, there is further smaller advantage. A 3.59 multiple, rather than 3.4, means that in periods of deficit the requirement for combined cycle gas turbine capacity to turn the hydrogen back into power would be slightly less.

In addition, it is worth pointing out that the total amount of electricity generation necessary to cover the UK’s needs in the year to June 2021 would have been about 1.25 times eventual demand, after taking into account the energy losses from the conversion into hydrogen and back again. Let’s mention one of the implications of this. If new renewables can now be commissioned by commercial developers at prices of £40 or less, the full electricity cost of 1.25 times means an underlying wholesale price of electricity of £50 (before the costs of electrolysers and CCGT). ‘Renewables plus hydrogen’ can work effectively as the key decarbonisation weapon, and the cost is less than any alternative.

‘Renewables plus hydrogen’: a way to push fossil fuels out of electricity supply

What is best route to reduce the UK’s reliance on gas and fossil fuels for electricity generation? 

This note provides an outline of one approach, using real data from the last year.  The analysis shows that all the UK’s current electricity demand could be met by an expansion of onshore wind, offshore wind and solar PV to about 4.5 times current levels. 

Crucially, half hourly matching of supply and demand across the year is carried out by hydrogen. When electricity is in surplus, electrolysers are used to make hydrogen. When in deficit, the hydrogen is burnt in gas turbines to generate electricity. The chart below illustrates this for 25th June this year when wind and sun would have been converted to hydrogen during the day but hydrogen would then have been needed in the night hours.

In this simple model fossil fuels are never needed to supplement supply. The inevitable energy losses in the conversion processes mean that more electricity is needed to cover total needs over the year but the excess production is less than 25% of the total. Complete electricity independence would thus come from having about 50-60 gigawatts of each of solar PV, onshore wind and offshore wind, up from about 11-14 gigawatts each today.

The note only looks at replacing fossil fuels in the current electricity supply. As decarbonisation proceeds, more activities – particularly transport and building heating – will be switched to electricity. This will increase the demand for power but this can also be handled by an expansion in renewables, as long as a storage medium such as hydrogen is used to balance supply and demand.

The analysis

1, The data used in the article was provided by Drax Electric Insights for the 365 days from 1st July 2020 to 30th June 2021. (Thank you particularly to Iain Staffell of Imperial College for giving me access to the database). Electricity demand and supply is logged for each half hour period. Electricity supply is split by type of generator, including fossil fuels, nuclear, renewables, storage and international connections.

2, I have added extra columns to the spreadsheet that allow me to multiply wind and solar output in each line by a multiple that can be varied. Thus if solar output is 5 GW in one half hour period and I use a multiple of 2, the column changes the output to 10 GW. I can use different multipliers for onshore, offshore and solar.

 3, Sometimes the multiplied estimated output exceeds the electricity demand for that half hour. Sometimes, even after applying the multiple on all three sources of electricity, demand still exceeds supply.

 4, In those periods when there is a surplus from renewables, the spreadsheet diverts that surplus into making hydrogen. The conversion efficiency is assumed to be 70%. That is, the energy value of the hydrogen that is generated by the electrolyser is 70% of the electricity input. 10 MWh in to the electrolyser creates 7 MWh of hydrogen (lower heating value). This is slightly higher than standard PEM or alkaline electrolysers today but will almost certainly be achieved within the next two years. The hydrogen is assumed to be stored.

5, In periods of deficit when renewables output doesn’t cover power demand, hydrogen is assumed to be taken from storage and burnt in a combined cycle gas turbine (CCGT), much as natural gas is today. Many of today’s large gas turbines can be converted to burning hydrogen, say the market leaders, GE, Siemens and Mitsubishi. The conversion efficiency is assumed to be 60%, roughly the performance of modern turbines. For every 10 MWh of hydrogen burnt by the gas turbine, 6 MWh of electricity is generated.

6, The process of generating hydrogen is 70% efficient and then turning back into electricity preserves of 60% of the energy value. This means that any period of deficit will require electricity generation that is only 42% efficient (70% times 60%). 10 MWh of electricity turned into hydrogen in a half hour of surplus will at some point be converted back into only 4.2 MWh of power at a time of deficit. 

7, Simple calculations allowed me to work out how much electricity output from renewables needs to be expanded so that all electricity needs over the course of the July 2020 to June 2021 would be met by renewables with hydrogen storage. The UK’s electricity requirements could be met by many different combinations of offshore wind, onshore wind and solar. I found that the most ‘efficient’ mix of sources was to use approximately the same multiples of each of the three existing sources. By ‘efficient’ I mean the combination that requires the least amount of renewable electricity to be converted in hydrogen for storage. This mixture of sources therefore most closely matches the electricity required over the 17,520 half hour periods each year. 

The results

8, A combination of 4.54 times expansion of onshore, offshore and solar produces a total of 678,913,290 MW, for half hour periods, or about 339.5 TWh. The actual demand in the year under study was 276.8 TWh, a lower figure than usual because of the impact of Covid. So the electricity system would have produced about 63 TWh more power than would have been generated in a fossil fuel network. This extra amount is what it takes to make the hydrogen in periods of surplus and use it in deficit half hours.

9, With this mixture of resources, the electricity system would have been in surplus for about 10,300 half hour periods and in deficit for about 7,220. The system would have required electrolyser capacity of about 75 gigawatts if the target were to ensure all electricity generated was used. In reality, if it is only to be used a few hours a year this would never be a sensible electrolyser capacity to install. In this case, just 30 GW of electrolyser capacity would have captured all but about 15 TWh of the surplus, or about 25% of the total surplus generated. It probably would be cheaper to overbuild the renewables rather than increase electrolyser capacity.

10, Other combinations of renewable sources usually require more electricity to be generated to cover the periods of deficit. In other cases, when one renewable is expanded more and another less, the match between demand and supply is less good, requiring more storage in the form of hydrogen to meet periods of deficit. However the differences are not enormous.  For example, a system which multiplied onshore wind by 4, onshore wind by 2 and solar by 13.5 would have covered overall demand at the expense of generating about 352 TWh, rather than 339.5 mentioned in paragraph 8. 

11, The only route of a reliance on fossil fuels is to base the energy system on renewables. The transition will be painful and expensive but will eventually result in lower costs and far greater less exposure to geopolitics. The current crisis of gas supply should oblige us to begin to take the difficult steps towards complete decarbonisation.

Appendix

What does a 4.54 times expansion mean?

 1, Solar would move from 13.1 GW to 59.5 GW capacity

2, Onshore wind from 13.6 GW to 62.1 GW capacity

3, Offshore wind from 10.7 GW to 48.7 GW capacity.

The UK land and sea space is comfortably capable of accommodating this increase.

The issues with the analysis

1, The spreadsheet manipulation is overly simple. It assumes that all electricity supply comes from the three renewable sources. Other non-fossil sources (principally imports, nuclear and biomass) are excluded from the analysis. If they were included, the required multiple for renewables expansion would be lower. 

2, It assumes constant capacity of solar and wind during the period. In fact, renewables capacity rose by just over 1% during the year. I use the figures for the end of the year. This will have marginally increased the multiple of new capacity needed.

3, I don’t take imports and exports into account, not least because shortages and surpluses are likely to be continent wide. When it is windy in the UK, it is very likely indeed to be windy in northern Germany and Denmark, for example.

4, My assumptions are also conservative in assuming that future renewables capacity is no more productive than at present. In fact offshore in wind in particular is improving in its capacity factors as the size and height of turbines increases.

5, I haven’t taken into account any storage costs for hydrogen. Nor have I modelled whether it would be more efficient, for example, to install multiple gigawatt hours of batteries to act as the first reserve in periods of excess or deficit. Hydrogen makes sense when storage is over longer periods but batteries work well as the storage medium for intra-day periods. (Storage losses with batteries are likely to be less than 10%, compared to almost 60% with hydrogen).

Follow on work

1, This programme needs to be costed. Because of the conversion losses from electricity to hydrogen and then back, more electricity needs to be generated than is apparently needed. Does this make the proposed route to self-sufficiency costlier than alternatives? I don’t think so but this topic needs more research. This note suggests that from an energy supply viewpoint it makes good sense to expand solar, offshore and onshore by roughly the same multiple. But does this make sense financially? Might it be better, for example, to focus on adding solar PV because the Levelised Cost of Energy (LCOE) is probably lower than offshore wind at the moment?

2, It would be best to do much more sophisticated modelling of the impact of existing and future nuclear power, hydro and pumped storage, biomass and imports. In addition, it would worth assessing the potential effect of demand shifting during the course of the day. But this could only reduce the total need for new wind and solar. 

3, Critically we should also be assessing the impact of the future expansion of electricity demand due to heat pumps and transport electrification. This is complex; we would need to overlay temperatures to assess the need for electric heating. Much demand for electricity in transport can be deferred for hours, if not days. Modelling this would be very difficult indeed.

4, We also need to accurately model exactly what the capacity factor of new installations is likely to be, and exactly when the output will occur. Much solar PV is on household roofs not facing due south. But a very large percentage of new solar is likely to be in south facing solar fields so the total amount of power generated by 1 gigawatt of PV will be greater, but it will be concentrated in the hours around midday. We should also factor in the growth of large scale battery capacity. 

Chris Goodall

chris@carboncommentary.com

September 23rd 2021

Maersk's methanol fuelled container ships

Why does Maersk’s decision to buy eight new ships matter? After all, the company owns around 700 already. 

The reason is that the world’s largest shipping company is committing substantially more than a billion dollars to a set of new ships that may dramatically change the prospects for green methanol production around the world. It has ordered the vessels with engines that can either burn methanol or heavy fuel oil.

The economics editor of the Guardian described the Maersk decision as ‘a drop in the ocean’.[1] He was wrong: this is the clearest sign yet that a swing to decarbonised shipping can conceivably happen within twenty years. Methanol isn’t new as a fuel – and few doubt its feasibility for shipping – but low carbon manufacture of this simple chemical is not well-established. By providing an outlet for zero-carbon methanol production, Maersk will transform its production. And if the methanol doesn’t arrive on time, the company will be able to persist with using fuel oil in the engines. 

A Maersk feeder container ship similar to the one ordered in February of this year with dual fuel (methanol/oil) capacity.

In March of this year a shipping magazine carried a quotation from a shipping analyst on why the major carriers were continuing to buy container ships powered by heavy fuel oil even though decarbonisation targets were inevitable.[2]‘There is no alternative’, he said. ‘Methanol ships are in development. There are trials with ammonia. There are studies of ships with hydrogen. None of these ships are orderable yet’.

 Five months later, Maersk has shown that this conclusion was too pessimistic. It has chosen Hyundai in South Korea to build the dual fuel ships, probably powered by MAN engines. Delivery will start in 2024. This follows a commitment earlier in the month to source renewable methanol from a Danish supplier for the first - and much smaller - dual fuel vessel it ordered earlier this year.

Maersk’s principal gambles are as follows:

·      About 20 dual methanol/oil ships are on the waters today. The earliest – a Stena Line ferry – entered service in 2015. But the existing vessels are far smaller than Maersk’s proposed new ships. The largest today are equivalent to a vessel carrying 2,000 standard containers. Maersk’s order is for ships able to transport 16,000 over long distances. The engine technology will need to be different. MAN says this is possible.

·      Methanol is available as a bunker fuel at many of the world’s largest ports. But if Maersk is to only use green methanol it will have to ensure that this fuel is widely distributed around the world’s major termini.

·      Will green methanol actually be available in sufficient quantities? About 200,000 tonnes a year are produced today, but very little would meet the company’s requirements for ‘zero-carbon’ synthetic fuels or for bio-methanol made from forest or field wastes. 

·      Green methanol is likely to be much more expensive than conventional bunker fuel, which is cheap partly because only ships can burn the least valuable output of oil refineries. Will customers pay the premium?

Dual fuel ships in the context of the Maersk portfolio 

Maersk sails about 700 ships, mostly larger vessels that travel long distances. Its share of container shipping worldwide is about 17%. The new methanol-powered ships will carry a total of 128,000 containers or around 3% of Maersk’s carrying capacity. (The vessels on order are much larger than the typical ship operated by this shipping line). Very roughly, the dual fuel container ships will move around 0.5% of the world’s container freight.

Maersk’s ships use about 10 million tonnes of bunker fuel a year at the moment. That results in almost 30 million tonnes of CO2 emissions, about the same as Denmark, Maersk’s home country. Methanol carries far less energy per unit weight than oil but will probably be more efficient at generating motion in a ship’s engine. The company says it will need about 360,000 tonnes of low carbon methanol and this fuel will save about 1million tonnes of carbon emissions compared to using heavy fuel oil.

Methanol made from fossil fuels is not in short supply. The world makes about 80 million tonnes a year at present, mostly as a precursor to chemicals production. It is a simple alcohol, containing carbon, hydrogen and one atom of oxygen. (CH3OH). About 200,000 tonnes today is manufactured using captured carbon dioxide and hydrogen. This is often called ‘green’ methanol, although the CO2 has usually been derived from a source that uses fossil fuels, usual a flue gas from an industrial process. This is not really ‘green’; the carbon dioxide will eventually end up in the atmosphere when burnt in the ship’s engine. 

Green methanol

Two types of methanol production may meet Maersk’s requirements for truly ‘green’ CH3OH. The first is when the CO2 is captured at a facility that is processing agricultural or biomass wastes. In this case, the gas has been extracted from the atmosphere by photosynthesis and so the methanol made using it will simply return the carbon dioxide to the air when burnt. 

The second type of plant does not exist yet. It will capture CO2 directly from the atmosphere and chemically merge it with hydrogen from electrolysis using renewable electricity. This is technically feasible. The only question is cost. Maersk paid about $300 a tonne of fuel in the last financial quarter and this represented a little over 10% of its revenues. So the price of fuel matters, although not overwhelmingly so, particularly in times of astronomical freight rates, such as at present.

The plans for green methanol plants around the world show how much of a boost to the market Maersk might be giving. The first site where methanol was made without fossil fuels was probably at Carbon Recycling in Iceland. There, CO2 from a geothermal power plant that would otherwise be vented is used with hydrogen made from electrolysis. This technology has worked well for more than a decade. Carbon Recycling is now expanding internationally and is planning a 100,000 tonne factory in Norway and a 110,000 tonne equivalent in China. (Both are reliant on fossil fuel exhaust gases and so are not properly ‘green’).

Liquid Wind in Sweden is a start-up that wants to construct factories making 50,000 tonnes a year. Seven of these would be needed to cover the demand from Maersk alone. REintegrate, the Danish company making the green methanol for the smaller ship Maersk ordered in February, is offering just 10,000 tonnes a year.

The effects of Maersk’s decision

The biggest impact of the Maersk initiative will be to transform the prospects for genuinely green methanol. One beneficiary might be the HIF project in southern Chile which intends to make a petrol/gasoline substitute using a process which has methanol produced in an intermediate step. Its plans are not advanced but would be sufficient to roughly cover Maersk’s entire needs. I expect the project executives have already booked their tickets to visit Maersk’s HQ in Copenhagen. 

What about the final gamble listed above? Will the cost be bearable? At the moment grey methanol trades for about $500 a tonne. And the energy value is little more than half that of fuel oil at $300 a tonne although combustion efficiency might be slightly better. This means that fuel costs would almost triple just by using fossil fuel derived methanol (and twice as much fuel will need to be carried for the same journey, reducing container capacity). 

The average container cost about $3,000 to ship last quarter, according to Maersk’s quarterly report. Current fuel costs might have been around $400, which would rise to over $1,000 if grey methanol were used, adding about 20% to the overall shipping cost. 

Green methanol is going to start by being more expensive, although possibly not significantly so. The two key costs are going to be the cost of hydrogen and captured CO2. CH3OH is 1/8 hydrogen by weight so a tonne of methanol requires 125 kg of green hydrogen. At the target price of $1.50 per kilogramme by 2025[3], the cost of H2 will be around $190. The capture of CO2 from air has a target price of around $100 per tonne and a tonne of methanol will need about 1.6 tonnes, implying a cost of at least $160. It might be less if the CO2 came from biological sources. Thus it is at least conceivable that green methanol might eventually cost no more than today’s fossil variety. But there is still a substantial price premium over the cheap heavy fuel oil used today.

 What will be the effect of the world’s (eventual) carbon tax? Buying 360,000 tonnes of green methanol will save about 1 million tonnes of emissions. At a carbon tax of $100 a tonne, Maersk will therefore save $100 million, or about $280 a tonne of methanol. There’s still a big gap between the fuel cost of methanol and that of heavy fuel oil, even of the desulphurised variety.

 Will Maersk’s clients pay the 20% increment that will be needed to cover the extra costs of green methanol when costs are reduced to today’s grey methanol prices? The company appears confident that it has obtained a sufficiently large base of customers prepared to pay the price. A long list of major global enterprises, ranging from H&M to Amazon and Novo Nordisk, seems to be committed to backing Maersk’s initiative. 

This appears to me to be a sensible gamble from the world’s largest shipping company. And its commanding stature in its industry will encourage others to follow. In pushing for methanol, Maersk is indicating that it is not yet ready to take the bigger risks on low carbon ammonia as a fuel.

[1] https://www.theguardian.com/business/nils-pratley-on-finance/2021/aug/24/sunaks-stamp-duty-holiday-hard-to-square-with-levelling-up-rhetoric (Last part of the article).

[2] https://www.freightwaves.com/news/inside-container-shippings-sudden-newbuild-ordering-spree

[3] This is the figure target by electrolyser company Nel in 2025 in low cost electricity locations.

The delusions of the UK hydrogen strategy

Long in gestation, the UK’s hydrogen strategy[1] gives the strongest possible sense of a country heading rapidly in the wrong direction. Where most countries and regions are pushing the development of hydrogen from green electricity, the UK has committed to a future dominated by the conversion of natural gas with carbon capture. Most strikingly, the UK is projecting costs for hydrogen vastly greater than anywhere else in the world.

Always sceptical about hydrogen made from electrolysis, the government has exceeded its normal standards of myopia. Below, I compare the estimates just provided by the UK government and by the EU in June 2020, 14 months ago.[2]

These figures show jaw-dropping differences between the EU’s and the UK’s estimates of the cost of hydrogen made from renewables in 2020 and 2025 respectively.

Estimates for the cost of hydrogen from electrolysis of renewables  (2025 or 2020)

2025 (UK)        £112/MWh

2020 (EU)        £64-£114/MWh[3]

These figures say that the EU saw the cost of hydrogen in 2020 as lower than the UK forecasts it will be in 2025. In the lowest cost locations, it was little more than half the price. The mid-point of the EU’s range is over 20% cheaper then than the UK forecasts for four years’ time. (It may be worth saying that nobody, but nobody, sees anything but the price of green hydrogen falling sharply in the next few months and years).

The differences widen. The EU estimates for the cost of renewable hydrogen in 2030 are up to 60% below the UK’s costs for 2050, twenty years later. 

Estimates for the cost of hydrogen from electrolysis of renewables (2030 or 2050)

2050 (UK) £71/MWh

2030 (EU) £28-£62/MWH

And it’s is also worth noting that the US is targeting a hydrogen price of $1/kilogramme by the end of this decade. That’s equivalent to a price of just under £22/MWh, or 70% below the UK’s estimate of costs twenty years later. The world’s largest electrolyser manufacturer, Norway’s Nel, aims for $1.50/kilogramme by 2025 (£33/MWh), less than half the UK’s 2050 estimates.

 What is going on? Why is the UK so jaw-droppingly less optimistic about renewable hydrogen than other entities? The suspicion must lie with the country’s devotion to the future of hydrogen from natural gas. It does very much look as though the policy-makers have determined that green hydrogen must remain more expensive than traditional routes of hydrogen manufacture using natural gas. 

Estimates for the cost of hydrogen from different technologies (UK 2050)

Renewable electrolysis          £71/MWh

Steam methane reforming

of natural gas                         £67/MWh

Autothermal reforming           £65/MWh

As an aside, it’s notable that the the UK strategy paper talks of ‘small projects expected to be ready to build in the early 2020s’ using renewable electricity but ‘large scale projects expected from mid 2020s’ for those employing natural gas and carbon capture. In other words, renewable electrolysis is still a toy. Even by 2050, the typical project seems to be expected to use a 10 MW electrolyser, when everybody else is talking of schemes today of one hundred times this scale.

Nowhere else in the world expects hydrogen to be cheaper to make using natural gas with carbon capture than electrolysis by mid-century. The UK government numbers are truly staggering.

 But, of course, there’s no reference that I could find in the UK strategy paper to any data or opinions from abroad.  That’s despite many major economies publishing their own policies over the last year. 

 All one can say is this: if green hydrogen made in the UK does cost £71/MWh in 2050, there’s absolutely no point in trying to build an industry here. It will be vastly cheaper to import the gas from Spain or Portugal by pipeline or Chile by liquid hydrogen carrier. The whole UK strategy will come to nothing, using a lot of taxpayers’ cash in the next four decades.

[1] https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1011283/UK-Hydrogen-Strategy_web.pdf

[2] https://ec.europa.eu/energy/sites/ener/files/hydrogen_strategy.pdf

[3] €2.5-5.5/kg, using the Lower Heating Value and an exchange rate of €1.17/£.

The Hydrogen Revolution by Marco Alverà

The Hydrogen Revolution; a Blueprint for the Future of Clean Energy by Marco Alverà is published by Hodder Studio on 26th August at £20.00

The history of hydrogen’s use as a man-made source of energy is older than we might think. Late in the nineteenth century, the Danish inventor Poul la Cour improved the design of wind turbines. Realising that his machines were often generating excess electricity that needed to be stored for later use when wind speeds were low, he used electrolysis to make hydrogen. Production of up to 1,000 litres an hour was kept in a tank and then burnt to make light at the high school where la Tour taught. From 1895 to 1902 the machinery worked successfully, keeping the lights on at the school every single day. (Although the building’s windows seem to have been very occasionally blown out by minor explosions of hydrogen)

Similar anecdotes fill Marco Alverà’s new book about the vital role of hydrogen in the world’s energy transition. A senior businessperson now running Italy’s Snam, Europe’s largest natural gas distribution grid, Alverà is the perfect individual to give us sense of how hydrogen is going to be used in the zero-carbon future. The book bubbles with his optimistic fervour and mixes technical detail with personal opinions. It doesn’t remotely read like an earnest manifesto from a corporate leader protected by his public relations team from saying anything too specific. Instead it offers an impassioned argument for a rapid transition to a global economy whose entire energy needs are met by renewable electricity and the hydrogen generated from it.

Alvera - and the Snam strategy team that helped with his research - side with the proponents who foresee a world that gets 25% of its energy needs from hydrogen, more than the share held by natural gas today. Other analysts, such as the International Energy Agency and the Energy Transitions Commission, have recently offered projections that suggest figures of about two thirds of this level. 

The book argues that almost every activity that cannot easily be electrified should be converted to hydrogen. So, for example, Alverà suggests that many domestic heating boilers should be switched away from natural gas to hydrogen. He is unusual in thinking this; most analysts recommend the use of electric heat pumps in the large majority of houses. His judgment, perhaps too strongly influenced by the constraints on the Italian electricity grid, is that the infrastructure investment needed to deliver reliable electric power for heating at the coldest times of the year is too great to be envisioned. And, as with the hydrogen at Poul la Cour’s school, hydrogen can be used to provide energy at times when renewable electricity isn’t available.

Marco Alverà sees a much larger role for hydrogen in transportation than most commentators, believing that the longer range of fuel cell cars will help beat off the competition from battery vehicles. The book also enthusiastically promotes hydrogen airplanes, even though they will require a fundamental redesign and may find it difficult to compete with existing aircraft configured to use synthetic zero-carbon fuels. 

Alverà gives us analysis, delivered as usual with flair and enthusiasm, that shows how a programme of investment in electrolysers and renewable electricity could push the cost of hydrogen down to below $2.00 a kilogramme within five years. His models show that this is attainable in large parts of the world after 25 gigawatts of electrolyser capacity have been installed, making about 5 million tonnes of hydrogen, or less than 10% of today’s production of the gas from fossil fuels. In the locations with the cheapest renewable electricity this target will be achieved earlier.

But should we believe the chief executive of a natural gas distribution company about the stellar future of alternative energy sources? Without a large role for hydrogen, which can be transported in refurbished natural gas pipelines, Alverà’s company has very poor prospects in the post-carbon world. An increasing number of voices argue that hydrogen is simply a front for ensuring that the main fossil fuel companies, such as Snam, continue in business.

But the author’s case is strengthened by his analysis showing how cheap it would be to build and operate hydrogen pipelines around Europe and beyond, bringing hydrogen from sunny places to the industrial centres where it is most needed. Gas pipelines are very much cheaper to construct and operate than long-distance electricity networks. Alverà suggests new connections both to North Africa and to parts of the Middle East where solar energy will be particularly cheap. Pipelines also offer large amounts of energy storage, with one kilometre containing a maximum of 12 tonnes of hydrogen, with an energy value equivalent to the daily electricity use of 40,000 homes. Even larger volumes can be stored in underground caverns easily created in the salt strata that exist underneath many countries around the world, including the UK and other countries in northern Europe. 

Marco Alverà is keen to show us how a world of solar, wind and hydrogen can allow the world can continue to live much as it does now. In his view our lifestyles, including our car and air travel and purchasing of clothes, electronics and other goods, will not need to be curtailed. I think this where he moves on to dangerous ground. The climate crisis is just one part of the unfolding ecological disaster that includes the loss of biodiversity, rising pollution from other sources than energy production and the destruction of many natural environments. Although hydrogen has an absolutely central role in averting the worst of our climate problems, it is not a universal panacea.

Hydrogen will be cheaper than today's natural gas prices by 2025

Natural gas prices are high around the world. In the UK, recent prices of above 114 pence per therm (about 3.9 pence/5.4 US cents per kilowatt hour) exceed any figures since the wholesale market became established in the 1990s. Similar records are seen across Europe and around the world. Forward contracts predict that these high prices will remain for many months. 

Part of the reason is geopolitics. Russia is ‘encouraging’ Europe to move ahead with the Nord Stream 2 pipeline by restricting exports on existing routes, forcing prices higher. Another reason is climate change. Gas demand is higher than usual because soaring summer temperatures are prompting high electricity use for air-conditioning. And in places like Brazil long-term drought has sharply reduced hydro-electric generation, forcing the country to ship in more gas from the US.

The price rise ought to make us even more eager to move away from fossil fuels such as natural gas. The effects of the cost inflation will be felt predominantly by the poorest groups. In the UK, the least well off decile of households devote 8% of their spending to paying for gas and electricity, almost three times as much as the richest decile.

At current gas prices in many parts of the world it will soon be cheaper to use hydrogen as a fuel for heating or for making electricity. (Many existing types of gas turbines can use some portion of hydrogen instead and the main suppliers say that 100% hydrogen will be possible soon).

Earlier this year, the large electrolyser supplier Nel published a formal target for the cost of green hydrogen in 2025, just four years away.[1] It looks for a figure of $1.50 per kilogramme, based on expectations for its own electrolyser costs and, most importantly, a figure of $20 per megawatt hour for electricity supply. Translate $1.50 into a cost per kilowatt hour and we arrive at a figure of 4.5 cents. Compare that to the price of wholesale gas in the UK today, which costs around 5.4 cents per kilowatt hour, making hydrogen prospectively almost 17% cheaper. 

The continuing belief that green hydrogen is always ‘too expensive’ to be useful needs to be challenged. We need a robust international supply chain for low carbon hydrogen, probably coming from the lowest cost locations such as Australia and Chile, to help keep heating and electricity prices down. And as reports this week have made clear, it has to be ‘green’ hydrogen because the alternative ‘blue’ product, made from natural gas with CCS almost certainly involves emissions that rule out its widespread use.[2]

[1] https://nelhydrogen.com/wp-content/uploads/2021/05/Nel-ASA-Q1-2021-presentation.pdf

[2] https://www.theguardian.com/environment/2021/aug/12/uk-replace-fossil-gas-blue-hydrogen-backfire-emissions

Hydrogen made at the wind turbine

Both offshore wind and hydrogen generation are increasingly seen as central to global decarbonisation. And over the last year we’ve seen a striking increase in the number of linked proposals that seek to develop offshore wind farms that are at least partly devoted to making hydrogen. Most of these schemes envisage generating electricity at the turbine which is then taken onshore via a high voltage undersea cable. This electric power will then be fed into a large electrolyser complex onshore to make hydrogen for various uses.

An illustration of how a central electrolyser complex on a platform in the middle of the Aquaventus project might look

But the story is changing rapidly; we are seeing a striking increase in the number of schemes that propose to make hydrogen in the wind turbine itself or at a platform in the middle of the wind farm. Instead of electricity, the farm will feed hydrogen onshore via a pipeline and then directly to users or to a repurposed gas grid for wider distribution. Although these new schemes are still at an early stage, it looks probable that a substantial fraction of all offshore wind turbines will eventually make hydrogen rather than transmit electricity.

What is driving this largely unnoticed change in the plans of large offshore developers? 

1, It is usually (much) cheaper to transport hydrogen than it is to move electricity. 

2, Having the electrolyser in the turbine or on a nearby structure enables the electronics in the turbine to be simpler. 

3, If making hydrogen is the ultimate purpose of the electricity made at the wind farm, then it may make sense never to attach the turbine to the grid. The advantages of this include cost – no need for a substation onshore, for example – and flexibility. There is no risk of enforced disconnection if the grid temporarily cannot handle the electricity that the turbine produces.

4, In addition, the hydrogen pipeline to the shore can act as a very efficient storage medium. The pressure can be increased and more hydrogen ‘packed’ into the pipeline.

1, Cheaper to transport hydrogen than electricity

Hydrogen is surprisingly easy to transport via pipeline. It can be compressed to approximately the same level as natural gas in conventional pipelines and flows more easily because of its lower viscosity. (But it does have a lower energy value per cubic metre at comparable pressures). 

The German utility RWE wrote as follows about its proposed AquaSector project in the North Sea that will eventually make hydrogen offshore (see below for more details about this proposal).

Compared to the transport of electricity generated offshore, the hydrogen production at sea and the transport via pipeline could offer clear economic advantages. The pipeline could replace five High Voltage Direct Current (HVDC) transmission systems, which would otherwise have to be built. It is by far the most cost-effective option for transporting large volumes of energy over long distances.[1] 

One of the largest offshore hydrogen schemes is likely to be NortH2 in the Netherlands sector. The developers say this[2]:

As wind turbines are placed further out to sea, hydrogen production close to the source becomes more attractive. After all, the generated energy must also be transported to land. This can be done via heavy electricity cables, but it is cheaper and more efficient to transport hydrogen gas molecules. That is why NortH2 is also looking at possibilities to convert the generated wind power into hydrogen directly at the wind turbines: electrolysis at sea.

Siemens, which makes many of the offshore wind turbines now being installed around the world, seems to be convinced of the operational advantages of putting the electrolysis process either into the turbine itself or close by. One of its recent presentations suggests three reasons for favouring transporting hydrogen rather than electricity including the following comment. [3]

* Capex reduction by replacing high cost HV infrastructure with pipes network

The precise cost of transport to shore will depend on the distance and the complexity of linking to the hydrogen users or to the gas grid. The EU offered a recent estimate of around 5 Euro cents per kilometre per megawatt hour of energy.[4]This implies a cost of about €6/MWh for a 100 km link. The number was based on earlier research by Bloomberg NEF. 

Other experts, including the CEO of the Italian gas distributor Snam, offer much lower figures suggesting that hydrogen transport by pipeline can cost as little as one eighth as much as electricity transfer.[5] (However this largely assumes using existing natural gas pipelines). 

Unlike the transmission of electricity, which will always see losses of power in the transmission process and in the conversion from one voltage to another, hydrogen can be transported in gaseous form almost without loss.

2, Simpler electronics in the turbine itself.

A wind turbine connected to the grid, even via a long undersea cable, requires substantial electronic equipment to condition the power that is generated. Second by second, the varying amounts of electricity being produced have to be converted to a standard voltage and aligned to the frequency of the grid. This means that the power coming from the turbine requires substantial manipulation before it can be connected to the grid. The equipment required is costly.

3, Less equipment onshore and complete independence from the requirements of the electricity grid.

As renewables grow around the world, the percentage of time that wind turbines produce power which cannot be accepted by the national or regional grid is tending to rise. At these times the electricity is wasted. One of the attractions of not connecting turbines to the electricity system and directly making hydrogen instead is that all the power produced will be productively used.

In addition, there will be no need for a substation or substations onshore that connects the power coming in from the wind farm to the main grid. The hydrogen can either be connected to a gas network or used directly by customers such as an oil refinery, a steel plant or a fertiliser manufacturer.

4, The hydrogen pipeline can act as storage.

Natural gas pipeline networks can reduce or increase the pressure in their pipes to provide a buffer between supply and the demand for energy. The same will be true of hydrogen pipelines. When the wind is blowing and the turbine is making hydrogen but customers only need their standard amounts of the gas, it will make good sense to store the temporary surplus in the pipeline. Marco Alverà of Snam says that I kilometre of pipeline can store 12 tonnes of hydrogen, with an energy value of around 400 MWh.[6] Batteries can in theory provide the same service for a turbine that produces electricity but the cost for an storage capacity equivalent to a kilometre of hydrogen pipeline would be fifty million dollars or more. 

The routes to a full coupling of offshore wind and hydrogen.

Let’s now look in a little more detail at some of the main pilot projects to produce hydrogen directly at the turbine or at central node in a wind farm. We will start with early experiments that are precursors to full hydrogen production and then move through to some of the outline plans for gigawatt-scale projects. All the schemes I could find were in Europe.

Denmark: a trial to show that a wind turbine can directly power an electrolyser while unconnected to the grid.

 At Brande in Denmark, close to the its Danish headquarters, Siemens is trialling joint operation of a 3 MW onshore wind turbine and an electrolyser.[7] One of the most important features of the experiment is the attempt to show that the turbine can be ‘islanded’, meaning it can power the electrolyser without any grid connection, thus replicating how an offshore turbine without the means to connect to the electricity network can make hydrogen. The hydrogen from Brande will be used to power Copenhagen’s fleet of fuel cell taxis.

The site for hydrogen production from an islanded onshore turbine at Brande, Denmark

Perhaps more importantly, Siemens’ wind business is also investing heavily in the development of a variant of its largest offshore turbine that that will incorporate an electrolyser in the base of the tower. This work is being supported by the Siemens division that makes electrolysers.

The Netherlands: installation of an electrolyser on an existing natural gas platform.

The PosHYdon project in the Netherlands North Sea will use an existing natural gas platform to host a 1.25 MW NEL electrolyser, making a maximum of about 500 kilogrammes of hydrogen a day from water that has been demineralised.[8]The hydrogen will be added to the natural gas produced at the platform which will then be piped onshore. (Domestic appliances can burn natural gas that contains some hydrogen. The percentages that are allowed vary from country to country). 

This trial will not use electricity from a nearby wind turbine but instead will use power that has been delivered to the platform from onshore. The installation is one of the few fully electrified offshore oil and gas platforms in the world.

An image of how an electrolyser might look on the Dutch offshore gas platform

The experiment will test the durability of a NEL electrolyser in a rugged marine environment and also examine how well the electrolyser copes with sharp variations in the availability of power.

The project is backed by a large number of energy companies and science research funds of the Netherlands government. 

Norway: making hydrogen in times of surplus electricity and storing it on the sea-floor.

A pilot project will use seawater to make hydrogen close to an offshore wind farm in periods when electricity is in excess supply.[9] The hydrogen will be made and stored on the sea floor. Fuel cells will convert the gas back into electricity at the wind farm at times of shortage. In this case hydrogen does not avoid the need for electricity transmission. Instead it uses the gas to help make electricity supply more reliable. 

This scheme is still at an early stage but involves a large number of partners with strong interests in hydrogen, including Finnish utility Vattenfall and Spanish oil company Repsol. It is being led by Technip FMC, a leading supplier of equipment for undersea oil exploration. The €9m project is being part-funded by Innovation Norway.

Underwater electrolyses and fuel cells in the projected Technip FMC scheme

UK: A trial project to make hydrogen on a floating offshore wind turbine base.

One of the potential advantages of using floating turbines for hydrogen production is that the turbine base provides a horizontal surface on which to place the electrolyser and other equipment. It may be easier and more economical to use floaters than fixed foundation turbines. Consulting firm ERM has received funding to develop a trial site in the middle part of this decade that will install a large 10 MW turbine, probably off the Scottish coast, to make hydrogen.

The design of the ERM floating turbine with hydrogen electrolyser

ERM’s technology may be used at a much larger Scottish wind farm.[10] The company recently signed a memorandum of understanding with the developers of a 200 MW project that will be constructed before 2030. The Scottish gas grid operator SGN is also part of the possible scheme to use floating turbines to make hydrogen to be piped onshore.

Italy: making electricity and hydrogen from an offshore wind and solar site.

The engineering company Saipem and its partners intends to make hydrogen at a new 450 MW offshore wind and offshore solar site in the Adriatic Sea off Ravenna.[11] The offshore farms will have an electrical connection to the mainland but also make hydrogen on converted offshore oil and gas platforms that will be decommissioned. The hydrogen will be piped both to the shore, and thus to the local natural gas network, and to marine refuelling platform that will accommodate ships that will transport the hydrogen to other locations.

A illustration of some aspects of the Saipem project, including offshore hydrogen production and hydrogen transport ship.

Netherlands: investigation of the opportunity to directly produce hydrogen at an offshore wind farm.

NortH2, a much larger Dutch project, is examining the options for directly making hydrogen from wind turbines.[12] It envisages as much as 4 GW offshore wind capacity in the Netherlands North Sea by 2030. In the early design, the power will be transported to a port on the Dutch coast but the consortium is backing research that looks at making hydrogen either at the turbines, on a platform shared between many turbines or at a man-made island close to the wind farm. This scheme is backed by the Norwegian oil company Equinor, Shell and several other entities including the innovative Netherlands gas grid operator Gasunie. 

Germany

Aquaventus is the most ambitious of all European projects for making hydrogen offshore.[13] The scheme proposes eventually to use 10 GW of offshore wind to make hydrogen to be transported by pipeline to the German island of Heligoland. The first phase of this enormous scheme involves the installation of about 300 MW of offshore wind, producing about 20,000 tonnes of hydrogen a year by 2028. (Current global demand for hydrogen is about 70 million tonnes, and this is likely to rise sharply). 

The partners behind the Aquaventus project, which include the utility RWE and Shell, regard it as a ‘proof of concept’ for the larger set of wind farms to be built by 2035, all of which will be connected to Heligoland by hydrogen pipeline. The gas will then be piped to mainland Germany. 

An illustration of the 10 GW wind farm feeding hydrogen into north west Germany via Heligoland

In almost all respects this scheme seems similar to existing plans for North Sea wind farms producing electricity with the only difference being the generation of hydrogen. If it comes to fruition it will show that direct production of hydrogen at wind farms may eventually be as financially attractive as the conventional model of producing electricity.

What can we conclude from these diverse experiments and pilot projects?

Although some participants in these pilots are still checking that electrolysis at sea is possible and makes financial sense, there seems to be an increasingly strong view that a large fraction of total hydrogen supply will come from offshore wind turbines. Many of the largest European utilities are heavily involved in the project proposals.

Underlying this view is the sense that the demand for hydrogen will be sufficiently broad to make investment in direct manufacture at renewables sites an attractive proposition. The usual objection to making hydrogen from renewables is the loss in energy value resulting from the electrolysis process. But if the market needs huge quantities it is not a question of whether hydrogen should be manufactured but how best to do this. The number of large companies crowding into the hydrogen from offshore wind business suggests a high confidence that many millions of tonnes of hydrogen will be needed. 

[1] https://www.rwe.com/en/press/rwe-renewables/2021-07-23-aquasector-partnership-on-first-large-scale-offshore-park-for-green-hydrogen-in-germany

[2] https://www.north2.eu/en/blog-en/offshore-electrolysis/

[3] https://www.siemensgamesa.com/en-int/-/media/siemensgamesa/downloads/en/products-and-services/hybrid-power-and-storage/green-hydrogen/210318-siemens-energy-hydrogen-day.pdf page 10. 

[4] https://op.europa.eu/en/publication-detail/-/publication/7e4afa7d-d077-11ea-adf7-01aa75ed71a1/language-en?WT.mc_id=Searchresult&WT.ria_c=37085&WT.ria_f=3608&WT.ria_ev=search

 [5] This information is taken from Marco Alverà’s forthcoming book, The Hydrogen Revolution.

[6] Marco Alverà in The Hydrogen Revolution.

[7] https://www.siemensgamesa.com/en-int/products-and-services/hybrid-and-storage/green-hydrogen

[8] https://poshydon.com/en/home-en/

[9] https://www.energyvoice.com/renewables-energy-transition/hydrogen/289798/technip-fmc-offshore-green-hydrogen/

[10] https://www.offshorewind.biz/2021/08/04/scottish-floating-wind-project-forms-green-hydrogen-tie-up/

[11] https://www.saipem.com/en/media/news/2020-08-25/saipem-protagonist-offshore-wind-will-develop-wind-farm-italy

https://www.agnespower.com/en/progetto-adriatico/

[12] https://www.north2.eu/en/blog-en/offshore-electrolysis/

[13] https://www.rwe.com/en/press/rwe-renewables/2021-07-23-aquasector-partnership-on-first-large-scale-offshore-park-for-green-hydrogen-in-germany

The struggles to make CCS work

The continuing difficulties facing the huge Gorgon carbon capture project in Western Australia must make us concerned about the viability of CCS elsewhere in the world.[1] As an informed Australian commentator said after recent announcements from the gas field, the Gorgon experience implies that CO2 storage will be more ‘expensive, slow and difficult’ than was hoped.[2] Each project will need to be carefully tailored to the precise geologic circumstances of the reinjection site. In his words, the difficulties at Gorgon show that CCS will be only a ‘vital and important, but niche, component’ of the energy transition. 

Part of the offshore infrastructure for the Gorgon project. Source: Chevron

This would also be the conclusion of many of those associated with an earlier large CCS project to reinject carbon dioxide at the In Salah gas field in central Algeria. This experiment ran into similar geological problems and was abandoned after several years because of concerns that the CO2 might escape. 

In both cases, the projects have been run by some of the world’s largest fossil fuel companies, all with huge experience in understanding geology and deep drilling. If these businesses cannot manage to achieve successful CO2 storage in nearly ideal conditions, there must be real doubts about whether carbon dioxide can be effectively stored in oil and gas formations.

Nevertheless, some governments around the world, and many fossil fuel companies, see CCS as a saviour technology that will allow continued large scale use of fossil fuels. The experience at Gorgon, and at almost all other CCS projects, suggests that this unthinking reliance on carbon capture is mistaken. The world will need to store CO2, but it cannot be a central plank of our decarbonisation strategies.  Australia’s community-funded Climate Change Council summarises the history of global carbon storage in a unequivocal fashion - ‘no CCS project has yet been delivered on time, on budget or to agreed performance’. [3]

Gorgon CCS

Gorgon is a series of large offshore gas fields, operated by Chevron with shareholdings also held by Exxon Mobil and Shell as well minor stakes taken by Japanese gas supply companies.  The project is one of the world’s largest sources of natural gas. Most of the production is liquefied to LNG and then transported to Asia. 

The Gorgon gas field off Western Australia, with pipelines going onshore via Barrow Island, where the CO2 separation occurs. Source: Chevron

As with many other gas fields, the Gorgon output naturally contains some carbon dioxide. Percentages range from 1% up to about 15% depending on which of the several separate fields the gas comes from. Even small percentages of CO2 cause particular problems for the liquefaction process. CO2 freezes to a solid at higher temperature than those at which gaseous hydrocarbons turn to liquid. This causes damage to equipment at gas liquefaction plants, such as those that process the Gorgon output. 

So the CO2 has to be separated from the natural gas. This is relatively simple. Some chemicals naturally absorb carbon dioxide and passing extracted natural gas over these chemicals will result in the CO2 being captured. The carbon dioxide can then be released again by simple heating, completely separating it from the hydrocarbons in natural gas. 

In most places around the world where gas liquefaction takes place, the CO2 is released to the atmosphere. Gorgon was meant to be different. The CO2 was intended to be injected back into the sandstone formation from which the natural gas originally came. The developers promised to put back at least 80% of the CO2 that had been separated out. It hasn’t turned out as well as hoped. 

An outline of how the Gorgon CCS scheme operates. Source: Chevron

The Gorgon project was started in 2009 and CO2 capture was intended to begin in 2016. The difficulties faced by the project meant that no carbon dioxide was actually injected until 2019. Since then, the sequestration process appears to never to have been fully operational and the amount stored is a fraction of what was expected. As a result, Chevron and its partners may have to pay fines of up to AUS$100m/$74m. (In the context of the project, this is an insignificant penalty).

What has gone wrong? The first problem was that when mixed with water CO2 forms carbonic acid, a weakly corrosive molecule. After the CO2 is injected into the sandstone formation, which is filled with water, the carbonic acid starts to dissolve the metal equipment in the injection well. 

The injection of carbon dioxide into the sandstone increases the pressure in the formation. Unchecked, this would eventually result in underground rock fracturing and the possibility of the return of the CO2 to the surface. This eventuality has previously been vehemently denied by the CCS industry.  In order to avoid leakage, Chevron created another set of wells to extract water from the formation to reduce the pressure. The wells did not work properly because both sand and water rose to the surface, eventually clogging the pipes. The difficulties resolving this eventually forced the Australian regulator to ask Chevron to reduce the rate at which CO2 was being injected into the formation so that the pressure did not rise too fast.

This problem seems to be persisting, reducing the rate at which the carbon dioxide is stored. Industry estimates suggest that only 2.5m tonnes a year are being sequestered rather than the 4m tonnes which was promised at the beginning of the project. Thus far, the CCS portion of the Gorgon project is said to have cost about AUS$3bn ($2.2bn) and has injected a total of about 5 million tonnes. If the current collection rates continue, the total amount sequestered is likely to be around 50 million tonnes during the lifetime of the field, about half of what was initially promised.

 The CO2 capture and storage will be much more expensive than first forecast. Assuming the $2.2bn figure applies to the full 50 million tonnes collected, the capital alone will imply a cost of around $45 a tonne of CO2. The full price, including operating costs, will be much higher.

The experience at Gorgon mirrors the most signifcant earlier attempt by the oil and gas industry to sequester the CO2 originally mixed into natural gas.

The In Salah experience 

BP and Equinor (formerly Statoil) are shareholders in the In Salah field in central Algeria. The operator is state-owned Sonatrach, the largest African oil and gas company.

 The In Salah field first began producing gas in 2004. It is expected to continue in operation until 2027. As in the Gorgon fields, the Algerian gas contains too much CO2 and the excess has to be removed. The target was to capture about 1 million tonnes a year and reinject it back in to the sandstone formation from which the gas has been extracted.

The In Salah gas field. Source: Sonatrach

The project was never fully successful. By 2011, when the CCS project was abandoned, about 4 million tonnes had actually been injected back into the gas-bearing sandstone formation.

What went wrong? In this case, there appears to have been no attempt to reduce the pressure in the CO2 storage areas by extracting water. CO2 was injected directly into the sandstone formation and caused the pressure to rise to levels sufficiently high to fracture the rocks above, raising the possibility of a leak.

The following paragraph is taken from an academic paper written by engineers from BP, Equinor (then Statoil) and Sonatrach after the project was abandoned.[4]

 ‘Following  the  2010  QRA (Quantified Risk Assessment),  the  decision  was  made  to  reduce  CO2  injection  pressures  in  June  2010.  Subsequent analysis of the reservoir, seismic and geomechanical data led to the decision to suspend CO2 injection in June 2011. The future injection strategy is currently under review and the comprehensive site monitoring  programme  continues.  Concerns  about  possible  vertical  leakage  into  the  caprock  led  to  an  intensified  R&D  programme  to  understand  the  geomechanical  response  to  CO2  injection  at  this  site’.

The diagram below shows where the engineers suggest fracturing may have already occurred by the time the project was abandoned. (See, for example, the near vertical line in the centre of the graphic). 

Visualisation of some of the problems at one of the CO2 injection wells at In Salah. Source: https://www.sciencedirect.com/science/article/pii/S1876610213007947

Although the risk of excess CO2 pressure producing or enhancing rock fractures was considered before the project began, it was not initially regarded as likely. The engineers had carefully selected the reservoir for injection, saying that it had ‘big storage capacity with a good insulation’ of rock over the top.[5] This turned out not to be the case.

BP engineers on the project had earlier described the storage geology at In Salah as ‘very similar to that of the North Sea’, where the company also hopes to develop large CCS projects.[6] We have long been told by specialists in CCS that injection of CO2 into depleted fossil fuel formations held no risks because the geology had already proved itself by retaining the gas or oil for hundreds of millions of years. The experience at In Salah and at Gorgon suggests that this does not provide sufficient security, perhaps because the volumes of CO2 stored result in pressures that are higher than projected by the geologists.

It is possibly a trivial finding but one other feature of In Salah needs mentioning, if only because the oil company engineers themselves discuss it in some detail. Parts of the land above the CO2 injection wells have risen very slightly (by up to 20mm) in response to the carbon dioxide stored at pressure over two kilometres below the ground. The direct significance of this is small, but it does indicate that large volumes of injection even into very deep formations can have unexpected effects on geology.

What does this mean for the future of CCS?

The world needs carbon capture and storage if it is to get to net zero. There may always be activities, such as the making of cement, that cannot be carried out without CO2 emissions and these must be safely stored. However the evidence from Gorgon and In Salah is that successful storage in oil and gas formations is almost certainly;

a)    More difficult and expensive than expected.

b)    Very dependent on geology. An approach to CCS that might work in one location might fail in another. 

c)     So rolling out CCS rapidly and at gigatonne scale in many hundreds of places around the world is not easy to envisage. We are still in the stage of CCS experimentation, and are well before a standardisable and inexpensive approach can be widely used.

d)    Areas, such as the North Sea, which are touted as perfectly suited to geologic storage, may well be more difficult to use than currently expected by government and by the oil and gas industry. 

e)    Of particular concern is the development of a ‘blue hydrogen’ industry around NW Europe, which will probably rely entirely on finding CO2 storage sites in the North Sea. However, as our knowledge stands today, the injection of carbon dioxide is likely to be more costly and much more limited in tonnage stored than is being currently modelled.

[1] The two cases discussed in this note both involve injecting CO2 into the geologic formation that contains gas but at a location away from the gas field itself. We cannot conclude that all types of CCS, including injection into working oil fields, will experience similar problems. However very large scale storage (hundreds of millions of tonnes) does now look more difficult than we believed.

[2] https://www.abc.net.au/radionational/programs/sundayextra/chevron-gorgon-ccs/13467950 Interview with Peter Milne. Absolutely fascinating and highly recommended.

[3] https://www.climatecouncil.org.au/resources/what-is-carbon-capture-and-storage/

[4] https://reader.elsevier.com/reader/sd/pii/S1876610213007947?token=CA1B347BA1CD3EFB86A7F2B30B81BE638206DB66453686410CD6A56CC773892ED08E3CD4D2C7EC601DC59A5BE0C679A6&originRegion=eu-west-1&originCreation=20210730104253

[5] https://www.opec.org/opec_web/static_files_project/media/downloads/press_room/HaddadjiSonatrach_Algeria.pdf page 27

[6] https://ec.europa.eu/clima/sites/default/files/lowcarbon/ccs/docs/colloqueco2-2007_session2_3-wright_en.pdf page 10

ArcelorMittal says it will be producing zero carbon steel in 2025

ArcelorMittal’s Gijón steel plant in north west Spain

ArcelorMittal is the second largest steel-maker in the world, trailing only Baowu, the huge Chinese producer. It produces about 80 million tonnes of the metal a year, or about 4% of the global total. Making steel is a process that uses coal and generates large amounts of CO2, meaning the company is alone responsible for about 0.3% of world emissions. So its actions matter. Recent company news suggests a new willingness to invest in the full transformation of its business away from coal and towards hydrogen.[1] The significance of the move appears to have been missed by the world’s media. 

Earlier in July, ArcelorMittal announced a plan to build what will be its first zero-carbon steel-making facility. If the target opening date of 2025 is achieved, the 2.6 million tonne plant at Gijón in north west Spain promises to be the first full scale low carbon steel works in the world. It will beat the current leader, Sweden’s SSAB, by a year. SSAB is already producing trial quantities of metal without using coal but only promises commercial quantities in 2026. 

At Gijón, green hydrogen, made from solar electricity, will be used to reduce iron ores (oxides of the metal) to sponge iron, from which steel can be made. Up until this point ArcelorMittal had begun several experiments of varying size and financial cost that attempt to reduce the greenhouse gas intensity of steel-making. None promised full carbon neutrality. Some involved the reuse of waste gases or their conversion to ethanol.

This month’s announcement is important because it seems to commit ArcelorMittal for the first time to a large scale investment at an existing steel plant that will produce zero-carbon metal. Until now, the company sometimes appeared to be toying with the carbon problem, making unclear promises to ‘eventually’ move to green hydrogen use in some of its German plants or to recycle waste gases containing CO2 in other European steel works. 

The proposed process at Gijón – ‘direct reduction’ or DRI – is already extensively used around the world although it conventionally employs natural gas to create synthesis gas (carbon monoxide and hydrogen, usually called ‘syngas’), rather than using hydrogen directly. DRI plants are less expensive to build than conventional blast furnaces and can be economically operated at a smaller scale. ArcelorMittal, perhaps aided by the US company Midrex that dominates DRI manufacturing technology, appears to be committing to using pure hydrogen at Gijón at a much greater scale than ever before planned in the world steel industry.[2]

Why now?

After dragging its feet during recent years, and making very few specific promises on decarbonisation, the company seems to finally made a full scale plan for greening part of its production. Why now? Probably the most important reasons will have been - 

·      The willingness of the Spanish government to help ArcelorMittal with the capital costs of the new plant, and probably its operating expenditures as well. The ArcelorMittal announcement of the Gijón plan came after the signing of a memorandum of understanding with the Spanish government which indicated that Spain will provide financial help but without being specific as to the amount.

·      As the weeks pass, the chance of the EU imposing carbon taxes on steel are rising. Not only is it increasingly likely that steel makers will have to pay for their ETS allowance but the probability of a carbon price at the borders of the EU within ten years has grown. This will make steel made from coal substantially more expensive. A tonne of steel typically requires about 0.75 tonnes of coal, and is therefore responsible for about 1.9 tonnes of CO2emissions. At an ETS price of around $60 a tonne, carbon taxation might add over $110 to the price of steel made with coal. (Steel usually trades for around $600 a tonne, so the carbon price could make a real difference). 

·      The cost of green hydrogen is falling fast, largely because of the fall in price of renewable electricity. Spanish solar parks could probably now produce electricity for less than $25 per MWH (around €20). I have estimated elsewhere that a tonne of low carbon steel will probably require about 4.25 MWh of electricity, costing therefore about $107. At today’s metallurgical coal prices of around $135 a tonne, steelmaking costs around the same whether using electricity or coal. And this is before taking carbon taxation into account.

·      After a long period of lukewarm interest in solar PV - Spain has less photovoltaic capacity than the UK -  the Spanish government has allowed substantial expansion of production capacity in the past year. The Gijón plant will need very large amounts of electricity to make hydrogen; I calculate it will probably require about 6 gigawatts, or about 50% of current national installed PV capacity. The national administration is making clear that it will encourage the development of the new solar fields in the local area that will be needed to deliver the 4% extra national electricity production that Gijón alone will require. 

 What are the wider implications?

·      It seems to me that the Spanish support for ArcelorMittal must inevitably produce similar offers from governments in the other main steel-producing countries in Europe. If ArcelorMittal goes ahead at Gijón I guess it is likely that no new steel furnaces will be built on mainland Europe that don’t use hydrogen. (Germany’s finance minister has already made a commitment to the local steel industry that promised whatever support is needed for a transition to hydrogen). Many steel furnaces inside the EU are reaching the end of their lives and it makes increasing sense to convert to hydrogen DRI instead of the costly rebuilding of ageing steel furnaces. 

·      We are beginning to get a sense of what the transition to hydrogen in the steel industry will cost. ArcelorMittal has previously said that it thought its transition to zero carbon using hydrogen would require investment of around $40bn for its own plants. The limited financial figures released for the Gijón project are consistent with this estimate. Grossed up to the global industry, we can expect an investment of around $1trn, or slightly more than 1% of global GDP. The benefit will be a reduction of about 8% in world CO2 emissions.  The will be spread over perhaps 25 years, implying annual investment requirements of less than 2% of world steel industry turnover. Even in an industry that goes through frequent financial crises, this is manageable.

ArcelorMittal invested about $3.5bn in new fixed assets in 2019. (The unusual 2020 figure was much lower than this.) The new Spanish DRI plant is therefore a large fraction of the company’s typical annual capital expenditure. But the output of the new Gijón plant represents over 3% of ArcelorMittal’s total steel production, meaning that a full conversion to DRI over the thirty years to 2050 should be fully financeable within the company’s existing capital budget

·      The investment world may come to recognise that steel making will almost inevitably shift to areas of the lowest electricity prices. Spanish PV can compete but it is less certain that German offshore wind can provide the cost-competitive electricity prices that the local industry needs. Australia, with good supplies of accessible iron ore and ultra-low potential renewable energy prices is very strongly positioned to regenerate its steel-making industry, possibly in the Pilbara region in the north west of the country. 

·      It is far too early to be certain but other steel makers that have been experimenting with partial use of hydrogen in existing coal furnaces, such as VoestAlpine in Austria, may soon conclude that it is better to shift to 100% low carbon rather than take intermediate steps that might result in perhaps half the CO2 saving. This is analogous to the car industry; why continue to invest in designing and making hybrids when the world is swinging so fast to fully electric autos?

After five years of small experimentation and promises to spend tens millions of dollars on carbon reduction, ArcelorMittal now says it will invest in a 2.6m tonne DRI plant costing a billion Euros, with the help of the Spanish government. This has worldwide significance.

[1] https://corporate.arcelormittal.com/media/press-releases/arcelormittal-signs-mou-with-the-spanish-government-supporting-1-billion-investment-in-decarbonisation-technologies

[2] I say ‘appears to be committed’ because Arcelor Mittal’s corporate material is usually particularly cleverly worded to avoid any absolute promise to take any particular route.

Can Scottish renewables replace oil and gas production in the economy?

The online news site Tortoise asked me for some numbers about the importance of renewable electricity to Scotland, particularly in comparison to the revenues it derives from offshore oil. Will active development of wind and solar on the way to net zero bring as much money into the economy as today’s fossil fuel activities?

Some rough answers to this question follow. In summary, the maximum development of offshore wind is likely to result in about as much financial contribution as offshore oil does today. Much of the electricity from wind will need to converted into hydrogen because Scotland’s own energy needs will be easily met. This hydrogen excess will be exported, probably principally by pipeline to the Netherlands and beyond. At the right price, Germany will be a ready market for Scottish hydrogen. 

Exploited to their fullest extent, renewables can wholly replace the role of fossil fuels in the Scottish economy but the challenge is a tough one. As well as pushing offshore development to close to its likely maximum size, Scotland will need to increase onshore wind substantially and invest in solar. If it becomes cost competitive, tidal power, which Scotland has in abundance, will add to the portfolio.

Scotland’s current energy needs

1, The total energy demand for Scotland is about 160 terawatt hours (TWh) per year.[1]

 2, Out of this total, electricity demand is approximately 34 TWh. The rest is largely oil and gas used for heating and transport.

3, Renewable electricity generation is about 32 TWh. In other words, Scotland is already close to meeting its total electricity needs from locally generated renewables.[2]

4, In addition, low-carbon (but not electricity) sources of heat provide about 5 TWh of energy. This is about 6.5% of total heat demand.[3] Overall, low carbon sources therefore provide just under a quarter of Scotland’s energy, not just electricity needs.

 Scotland’s current energy production 

5, The value of oil and gas production in Scottish waters was approximately £22 billion in 2019.[4] (This value is of course affected by variations in the price of fossil fuels). 

6, Scottish GDP is about £167bn.[5] This means that the sales of oil and gas is equivalent to about 13% of the national economy. The actual value added in Scotland by the industry is less, of course, at around £9bn or just over 5% of GDP.[6]

7, The oil and gas industry in Scotland produced total taxation of about £700m in 2019. (This figure will change substantially from year to year in line with fuel prices).[7]

The scale of the potential for renewable electricity

8, Less than 1 GW of the UK’s 11 GW offshore wind capacity is in Scottish waters. Most of Scotland’s renewable electricity comes from onshore turbines.

9, Scotland plans to increase its offshore wind capacity to 11 GW by 2030.[8] Assuming a capacity factor of 50%, which is probably slightly conservative, this will add about 44 Terawatt hours (TWh) to Scottish energy provision, or slightly more than a quarter of its current total energy consumption of around 160 TWh. Scotland will then be in a position of having large electricity surpluses while covering almost one half of its entire energy need. This power will be largely transmitted to England.

10, At today’s approximate value of £45 (UK pounds) for a megawatt hour of wind electricity, 11 GW of offshore capacity will be worth about £2bn, or around a tenth of today’s Scottish oil and gas industry size. So the 2030 plans do not remotely cover the loss of the oil and gas industry.

11, But Scotland indicates that it will not stop at that point. A recent investigation of the possibility to use excess renewable electricity to make green hydrogen set an ‘ambitious’ target of 60 GW by 2045, which is the country’s target for its net zero date.[9] This would produce about 262 TWh of electric power, or over 100 TWh greater than Scotland’s total energy need. At a value of £45 per MWh, the extra wind electricity would have a gross value of £11.8bn, or somewhat over half the size of the current oil and gas industry. 

 12, But, once operational, wind farms require relatively little expenditure. It may be that the net benefit to Scotland is actually  great as the £9bn produced in value added by the fossil fuel industry. 

13, Perhaps as importantly, Scotland is not restricted to 60 GW of offshore wind. A 2010 research project backed by the Scottish government and others assessed the potential as 169 GW, including large amounts of floating wind.[10] If exploited, much of the electricity produced would have to be exported in the form of hydrogen. (169 GW would provide at least 3 times as much power as is currently used in the entire UK, meaning most would be wasted if it could not be converted into a storage medium).

14, Hydrogen may have a lower price than electricity, expressed in terms of cost per MWh. Additionally, there will be losses in the conversion process from electricity. The value of the hydrogen produced may be as low as $45 (US dollars) per megawatt hour, which is equivalent to $1.50 per kilogramme.[11] At an electrolysis conversion efficiency of 75%, 169 GW of new offshore wind would be worth about $25bn, or about £18bn. Adding in today’s existing renewables and the total rises to just under £20bn, or roughly equivalent to the value of Scottish oil and gas today. This would leave Scotland with an energy economy equivalent to 12% of its GDP, a higher figure by world standards. 

15, This shows the scale of the challenge. Scotland can replace fossil fuels with offshore wind but it may also aim also to exploit onshore wind resources, with which it is also well-endowed, as well as other renewable sources. Shortages of electricity transmission capacity into Europe means that it will almost inevitably have to use hydrogen as the energy carrier.

[1] https://scotland.shinyapps.io/Energy/?Section=WholeSystem&Chart=EnConsumption

[2] https://scotland.shinyapps.io/Energy/?Section=RenLowCarbon&Subsection=RenElec&Chart=RenElecTarget

[3] https://scotland.shinyapps.io/Energy/?Section=RenLowCarbon&Subsection=RenHeat&Chart=RenHeat

[4] https://www.gov.scot/news/oil-and-gas-production-statistics-for-2019-1/

[5] https://www.scottish-enterprise.com/learning-zone/research-and-publications/components-folder/research-and-publications-listings/scottish-economic-statistics

[6] https://www.energyvoice.com/renewables-energy-transition/286963/scottish-government-energy-statement/

[7] https://www.energyvoice.com/oilandgas/north-sea/260923/north-sea-gers-figures-scotland/

[8] https://www.gov.scot/news/increased-offshore-wind-ambition-by-2030/

[9] https://www.gov.scot/publications/scottish-offshore-wind-green-hydrogen-opportunity-assessment/

[10] https://publicinterest.org.uk/offshore/

[11] This value is normally assumed as the global price at which green hydrogen will be as cheap as the grey version. In actual fact, the prevailing price in Europe is likely to be higher. 

Some rules of thumb of the hydrogen economy

Most analysis of the role of hydrogen in the global economy uses numbers that are not immediately translatable into conventional measurements. The purpose of this article is to offer some simple rules of thumb that help place hydrogen alongside other parts of the energy system.

 1, A kilogramme of hydrogen - the unit most often used – has an energy value of about 33.3 kWh.[1] So a tonne of hydrogen delivers about 33 MWh and a million tonnes about 33 terawatt hours (TWh). To provide a sense of scale, the UK uses about 300 TWh of electricity a year. 

2, Estimates vary, but about 70 million tonnes of pure hydrogen is made today, mostly for the fertiliser and oil refinery industries. This has an energy value of about 2,300 TWh, or roughly the same amount as the EU’s electricity consumption (excluding the UK, of course). 

3, Many estimates of the eventual demand for hydrogen centre around a figure of about 500 million tonnes.[2] This will have an energy value of about 16,500 TWh, or about 40% of the world’s current consumption of natural gas.

4, How much electrical energy does it take to make a kilogramme of hydrogen in an electrolyser? A survey of the major manufacturers suggests a figure of about 50 kWh at present for both Alkaline and PEM electrolysers. Put an energy value of 50 kWh of electricity in and get hydrogen out with an energy value of 33.3 kWh, or 67% efficiency. Alkaline and PEM electrolysers offer performance of this level but Solid Oxide electrolysers already offer 80% conversion of electricity to hydrogen. But they need substantial sources of external heat.

5, Will the efficiency of electrolysers rise? Yes. The assumption in the industry is that Alkaline and PEM electrolysers will rise to an efficiency of about 75% (44 kWh in, 33.3 kWh out) within five years.

6, Many observers say that green hydrogen made from the electrolysis of water will be fully cost competitive with fossil hydrogen when it costs less than $1.50 per kilogramme.[3] This is equivalent to 4.5 US cents per kWh of energy value, or $45 per MWh. As at today’s date (June 11th 2021), unrefined crude oil costs about the same amount per kWh.

7, What will it take to get H2 to $1.50 per kilogramme. Low electricity prices are, of course, utterly critical, followed by falling electrolyser prices. Hydrogen is little more than transformed electricity. NEL, the world’s largest electrolyser manufacturer, says that it believes $1.50 is achievable in 2025, based on $20 per megawatt hour electricity. It is coy about the prices it expects for its own products, but I guess that it projects about $500 per kilowatt of capacity by mid-decade.[4]

8, How much renewable electricity will need to be generated to satisfy the demand for hydrogen? At the current efficiency level of about 67%, the world will need about 50 terawatt hours for each million tonnes of green hydrogen. 

9, At the prospective efficiency level of about 75%, this number falls to about 44 TWh. A world that requires 500 million tonnes of hydrogen will therefore need to produce 22,000 TWh of green electricity a year just for this purpose. Today’s global production from all wind and solar farms is a little more than 10% of this figure. To meet the need for hydrogen we need a sharp acceleration in renewable installations to several terawatts a year.

10, 22,000 TWh is roughly equivalent to 15% of total world primary energy demand.

 11, How large a wind farm is needed to make a million tonnes of hydrogen? If we assume a capacity factor of 50% for a well-sited North Sea wind farm, each gigawatt of capacity will provide about 4,400 GWh a year, or 4.4 TWh. At the future efficiency level of about 75%, this will produce about 100,000 tonnes of hydrogen. Therefore most of the UK’s current North Sea wind output from 13 GW of wind would be needed to make one million tonnes of H2. 

12, The amount of electrolysis capacity required to make 500 million tonnes of hydrogen a year depends on how many hours a year that the electrolysers work. If we assume the average is 5,000 hours a year, or about 60% of the time, then the world will need around 4,500 gigawatts of electrolysis capacity - about five hundred times what is currently in place - at the prospective 75% efficiency level. This is an important conclusion because it points to the necessity of creating a massive new industry. My figures suggest the investment in electrolysers may exceed the cost of building the renewables necessary to provide the electricity for making hydrogen. Those of us who look at the stock market valuations of the existing electrolyser manufacturers and recoil in disbelief may not being sufficiently imaginative. 

[1] Lower Heating Value (LHV)

[2] E.g. Energy Transitions Commission (680 million tonnes) and the International Energy Agency (320 million tonnes), Chris Goodall work for CLSA in Hong Kong (562 million tonnes)

[3] Whether this is true or not strongly depends on the region of the world in which the comparison is being made.

[4] https://nelhydrogen.com/wp-content/uploads/2021/05/Nel-ASA-Q1-2021-presentation.pdf See page 15.

The size of the hydrogen opportunity

Two recent reports from respected organisations have looked at the future of hydrogen. The Energy Transitions Commission (ETC) envisages the possibility of hydrogen providing up to 20% of total world energy need by 2050 through the manufacture of up to 800 million tonnes of the gas. The International Energy Agency (IEA) is somewhat more cautious, estimating a figure of about 13%. 

In addition, a report I wrote in March for the Hong Kong financial institution CLSA suggested that hydrogen might provide at least a fifth of global energy, a figure similar to the ETC estimate.[1] In all three cases, the authors look forward to a future energy landscape dominated by renewable electricity and hydrogen. (However the IEA assumes that over a third of all hydrogen will still be made using natural gas in 2050).

In this note I briefly compare the projections of the three analyses. The purpose is to show that although many of the detailed conclusions about the growth of the hydrogen economy vary significantly, the main projections have strong similarities. As an aside, almost all other recent research shares the central themes. Hydrogen, which is still not taking seriously by many analysts, is going to become a central part of the drive to full decarbonisation.  

Although there is no consensus about the required scale of the industry, energy analysts are converging on a projection of an eventual market size of between 500 and 1,000 million tonnes of hydrogen a year. The energy required to make this is greater than the world’s total electricity production today. Hydrogen changes everything.

The sectors which will drive the growth of hydrogen.

1, Shipping. These reports envisage ammonia, a derivative of hydrogen, becoming the main fuel for long-distance shipping. Ships, such as island ferries, that cover shorter distances will typically use batteries. The ETC sees ammonia for shipping as being the single most important use of hydrogen by 2050 using about 145 million tonnes, twice today’s global production for all purposes.

 2, Steel manufacture will also be an important market. I project that this will be the largest use of hydrogen. Other industries that need high temperature heat, including cement manufacture, glass-making and some chemicals, will provide large opportunities for the gas.

3, Aviation will decarbonise using synthetic fuels, made from hydrogen combined with CO2 probably derived from direct air capture. Aircraft, according to these three reports, will not use hydrogen directly in any significant quantities.

4, Personal cars will not move to hydrogen as the predominant energy source. Batteries will dominate. But some long-distance commercial vehicles that do not return to the same point each night may move to hydrogen fuel cells. Surface transport will therefore not be a major user of hydrogen, although I say that railways may move to the use of fuel cells.

5, Although much low temperature space heating will move to electricity, and away from natural gas, there is a significant role for hydrogen in this market. 

6, Lastly, but probably most importantly, hydrogen will perform a vital role balancing the electricity market. When power supplies are abundant, hydrogen will be made and then converted back to electricity in conventional combined cycle gas turbines when there is an energy shortage. All three reports see this as a large-scale use of hydrogen. The IEA sees this function as demanding almost 100 million tonnes, almost 20% of its total projection of the global need for the gas. My figure is similar.

Other conclusions shared between the reports.

 7, Hydrogen will be transported across regions largely by pipeline. Repurposed natural gas pipelines will play an important role.

8, Storage will be concentrated in newly constructed salt caverns, where this is possible. Large parts of the world, including much of Africa and Asia may not have adequate capacity but Europe, the Middle East and North America are well supplied with geological salt.

9, Transport from energy-surplus areas, such as NW Australia and Chile, will use ammonia as the carrier for the hydrogen.

10, The cost of green hydrogen will be dominated by the price of renewable energy. At prices of $20 per megawatt hour or below, hydrogen made from electrolysis would already be competitive with the ‘grey’ product in higher cost natural gas markets.

 11, The relatively low figure for hydrogen production from the IEA arise because the Agency assumes that a large amount of decarbonisation will take place through the use of biomass. This, for example, explains the limited use of hydrogen for aviation. Instead, aviation fuel will be made from biological materials. Many will question whether the emphasis on sustainable biomass is remotely plausible. The ETC and I assume that almost all energy use will employ electricity or hydrogen made from electricity.

 The central numbers

The table below gives some of the forecasts for hydrogen from the three reports. I should stress that some of these numbers may not be directly comparable because the authors use different definitions. In addition, the IEA report includes figures that vary between different sections of the document. This report also omits some critical estimates, such as the amount of hydrogen needed for methanol - an important precursor for many important chemicals - and fertiliser manufacturing.

How much 2050 H2 is from electrolysis?

 ETC - About 680 million tonnes. (about 85% of total hydrogen production)

IEA - About 320 million tonnes (about 60% of total hydrogen production).

CLSA,Goodall - About 562 million tonnes (all prepared by electrolysis)

These differences are driven by the assumption about how much of the hydrogen is made from electrolysis of water and how much from steam reforming of natural gas with CCS.

Electrolysis capacity

ETC - 7800 gigawatts

IEA - 3600 gigawatts

CLSA, Goodall - 4800 gigawatts

These figures are approximately consistent with the forecast hydrogen production.

Share of final energy demand

ETC - 15-20%

IEA - 13%

CLSA, Goodall - 20%

The key differences derive from the assumption about how much remaining fossil fuel is used. A forecast with high gas use (with CCS) requires more primary energy production because of the inefficiencies of conversion into useful energy.

Eventual electricity generation 2050 excluding for the production of hydrogen

ETC - 93,000 TWh

IEA - 60,000 TWh

CLSA, Goodall - 120,000 TWh

I project that almost all energy-using activities are switched to hydrogen or electricity by 2050. The other forecasts are for a slower transition.

Cost of electrolysers, 2050

ETC - $100/ kW

IEA - $200-390/ kW

The figures by sector

The ETC report helpfully breaks down the use of hydrogen into industries. The IEA’s and my work partially replicates this approach, although I backed away from estimating the tonnage of hydrogen used to space heating and the IEA omits several important sectors from its analysis. 

[1] Hard copies of the CLSA report are available. Please drop me a line at chris@carboncommentary.com if you would like me to send you a copy.

WHICH TECHNOLOGY TRANSITIONS WILL CREATE THE LARGEST EMISSIONS REDUCTIONS?

In a recent presentation I was asked a question I found impossible to answer. And after some hours of work, I’m still far from certain my response is correct. But I thought I’d share the analysis even though the answer - get rid of coal in power generation - is probably obvious.

The issue raised is crucially important: of the various transitions in technology we are trying to engineer, which will reduce emissions the most for every unit of extra renewable electricity generation? The world is trying to ‘electrify everything’ but which applications should be given the first priority when we add extra wind and solar?

The alternatives are numerous. Should the world use new renewables to reduce the amount of electricity generated by coal or gas? Or would it better to speed up the growth of EVs to use the extra renewables? How does using the electricity to generate hydrogen for decarbonising steelmaking compare? Or making ammonia as a fuel for ships’ engines? What about the impact of increasing the use of electricity for domestic heating? Or producing hydrogen for fuel cell use in heavy transport? Or manufacturing synthetic fuels using electricity for use in aviation? 

Of course we eventually need to stop using fossil fuels across all the energy system and transfer to renewable electricity. But the rate of decline towards eventual net zero also matters. If we decarbonise the most polluting activities first the amount of CO2 eventually in the atmosphere will be lower than if extra electricity replaces fossil fuels in sectors with low emissions per unit of energy. The purpose of this analysis is therefore to suggest which sectors the world should be pushing towards renewable electricity into first, whether in the form of electrons, hydrogen, ammonia or synthetic fuels.

I have tried below to calculate the emissions reduction that arises from applying one incremental megawatt hour of zero-carbon electricity to each of the main alternative uses.

The numbers are approximate; they will also vary somewhat across the world as well from operator to operator. For example, if the extra electricity was used to make hydrogen enabling an inefficient old steel furnace to be closed, it would reduce emissions more than if the manufacturing site was more recently built. Or to use an alternative illustration, a heat pump for a domestic house will save far more emissions if it replaces oil fired central heating than a natural gas boiler. 

Here is my league table, suggesting an order of priority for investment in carbon-saving technologies.

Sources specified in Appendix below

The implications of this table seem to be clear. In general, we should be focused first on using the growing amount of renewables in world electricity systems to decarbonise activities which are themselves inefficient users of fossil fuels. So, for example, our extra unit of clean electricity can be used to provide the power for a new EV. A new petrol car will only convert about a quarter of the energy in the fuel into useful motion but an electric car is more efficient. The new renewable electricity therefore offers real leverage in reducing emissions. 

The same is true for a heat pump: a central heating boiler offers good transfer of the energy in gas into heat but a heat pump can actually use a unit of electricity to transfer several times as much heat into a house. (I’ve used a typical UK figure of a 2.8 times multiple). A coal-fired power station only works at about 40% efficiency, the energy value of the coal compared to the electricity output. That is why it comes out top of the table.

These top three uses all offer CO2 savings of between 600 and 900 kilogrammes per megawatt hour of electricity produced.

We then move to applications will employ the new electricity to create hydrogen for use in other processes. Hydrogen in steel making replaces the use of coal. Making hydrogen from electricity sees substantial energy loss but the gas is somewhat more efficient than coal in reducing iron ore to liquid iron. So this application is relatively productive. Similarly, there are advantages and disadvantages in using electricity to make hydrogen for use in a fuel cell in a heavy vehicle. These activities offer carbon savings of around 400 kg per megawatt hour of electricity.

 At the bottom end of the range are those uses which involve the conversion of electricity into hydrogen and then through a second conversion into ammonia or synthetic fuel. Here, the savings can be as little as just over 100 kg per megawatt hour. The emissions reduction value is therefore about an eighth of the gain if the new electricity is employed to reduce coal-fired electricity output. 

The key lesson is that there are real differences in CO2 reductions from different uses for new renewable power. Hydrogen comes lower in the list of priorities than getting coal off the grid. This conclusion must be qualified; when an electricity system has genuine surpluses of supply, an increasingly common phenomenon, making hydrogen is far better than simply disconnecting the generation capacity.

(Thanks to Tim Elliott of Regal Funds Management of Australia for the question and for his patience later discussing these results. Errors are all mine).

Appendix: The key inputs into each calculation

1, Reducing coal use in power generation.

1 MWh of new renewable electricity replaces 1 MWh of coal fired power.

In typical power station, 1 MWh produces 900 kg of CO2

2, Using the power for EVs.

A new EV takes in about 0.85 MWh of electricity (accounting for battery losses) from 1 MWh of new renewables production.

A new EV will typically travel about 6 km for each kWh of battery power used. So 1 MWh of new electricity production will enable a journey of 6*850 km, or about 5,100 km.

A new ICE car would typically emit about 130g per km. 

So the saving would be 130g multiplied by 5,100 or 663 kg.

 3, Electrifying heating using heat pumps.

1 MWh of electricity delivers 2.8 MWh heat into a building using a heat pump (approximate UK average).

This typically would reduce the consumption of gas by about 3.2 MWh. (The boiler is not 100% efficient).

This would have produced about 650 kg of CO2.

4, Making hydrogen for steel manufacturing.

A tonne of new steel made today typically results in emissions of about 1.85 tonnes 

Steel made using hydrogen will probably require about 3 MWh of energy in the form of CO2.  

At electrolyser efficiency of 67%, about 4.5 MWh of electricity is needed to make the H2 for a tonne of steel.

So 1 MWh of electricity would save about 1.85 tonnes divided by 4.5, or about 411 kg of CO2.

5, Making hydrogen for a fuel cell in heavy vehicles.

1 MWh of electricity makes hydrogen with an energy value of about 670 kWh, assuming an electrolyser operating at 67% efficiency.

The conversion back to electricity from a hydrogen fuel cell to power the battery in the truck is about 60% efficient. The electricity available for travel is therefore about 402 kWh for each 1 MWh of electricity initially produced.

A truck is assumed to be 25% efficient at converting the energy in diesel into power available for travel. Therefore to be equivalent to the travel power delivered by electricity, the truck would use 1608 kWh of diesel.

At 10.6 kWh per litre of diesel, the truck would need 152.3 litres of fuel. 

Each litre of fuel produces about 2.5 kg of CO2. This means that the switch to fuel cell truck from a diesel truck would save 381 kg of emissions for each 1 MWh of electricity used to generate hydrogen.

6, Reducing gas use in power generation.

1 MWh replaces 1 MWh gas fired power.

In typical gas power station, 1 MWh produces about 330 kg of CO2.

This excludes fugitive methane losses at point of production or in transport.

7, Making synthetic fuel for aviation rather than kerosene

About 20 kWh of electricity is needed to make 1 litre of fuel. (Plus about 12 kWh of heat, which is assumed to be free). The source for this estimate is Norsk eFuel.

So 1 MWh of electricity will produce 50 litres of eFuel.

 2.5 kg of CO2 arise from each litre of aviation kerosene.

So 125 kg of CO2 is saved for each of I MWh of electricity devoted to making synthetic aviation fuel.

8, Using ammonia instead of heavy fuel oil in shipping.

Each tonne of ammonia requires energy of 9.15 MWh. 1 MWh of electricity will therefore make about 109.3 kg of ammonia. 

The energy content of ammonia is about 5.2 MWh per tonne. 1 MWh of electricity will therefore make ammonia with an energy value of 565 kWh.

565 kilowatt hours has the energy equivalent of about 45 kg of Heavy Fuel Oil (HFO). (Key assumption that ammonia engines and HFO engines are equally energy efficient)

A litre of HFO produces about 2.5 litres of CO2. The replacement of HFO by the ammonia produced using 1 MWh of renewable electricity therefore saves about 113 kg of emissions. 

Wind farms need more people than coal mines

It is still common to hear that one of the disadvantages of renewables is that they do not create good new jobs. ‘Old’ industries, such as coal mining or power station operation, are portrayed as better for employment than solar or wind.

 We saw one example yesterday. Sarah O’Connor of the Financial Times wrote an article (paywall) suggesting that jobs would be lost in the energy transition. She wrote

 ‘Wind farms, once up and running, do not require as much labour as digging-up coal’. 

But is this right? Or are we all stuck with memories of photographs from the 1950s of huge numbers of blackened miners pouring out of collieries at the end of a shift?

 The application to develop a new metallurgical coal mine in the north of England gives us some useful data. The proposed mine in Cumbria is said to offer a maximum of 500 permanent jobs. So I estimated whether the energy produced per employee would be more or less than that typically produced by the people running, repairing and maintaining wind farms. The evidence is that employees working at operational wind farms are responsible for less energy production per person. In other words, Ms O’Connor’s assertion is not correct; wind farms will actually need far more labour than modern coal mining to give us the energy we need. 

Cumbria mine

Employees                                                      500 employees

Projected coal output per year                 3.1 million tonnes

Coal output per employee                         6,200 tonnes

Energy value of metallurgical coal           8.3 MWh per tonne

Energy value per employee year              51,460 MWh

Wind farm operations and maintenance (NOT construction)

Estimate average number of employees per MW of capacity[1]        0.29

Typical annual output per megawatt of capacity[2]                              3,504 MWh

Typical output per person employed                                                   12,083 MWh

To deliver all the energy an economy uses will therefore require more employment in wind farms than in mines. In fact, over four times as many people are needed to run wind farms than to operate a new coal mine in the UK. 

[1] Source Page 17 of Wind Power and Job Creation, L. Aldieri, 2020.

[2] At a 40% capacity factor

Crowd-funding to convert natural gas pipes into hydrogen-ready equivalents

In one of the latest offerings from Abundance, the crowd-funding platform, Northern Gas Networks (NGN) is seeking to raise £1m from individual investors to help fund a very small part of its programme of making the pipeline network ready for a transition away from natural gas to hydrogen. NGN says that this fund-raising is part of its programme to involve the UK public in its plans for moving towards zero carbon emissions. 

Why is hydrogen so important?

Green hydrogen will provide a boost to decarbonisation efforts. It has two principal roles

1.    To allow countries around the world to switch to 100% renewable sources for their electricity. The key issue facing wind and solar power is the intermittency and unreliability of electricity generation. We won’t always have power when we need it.

Green hydrogen made from water electrolysis solves this problem. When electricity supply is over-abundant, the surplus is used for making hydrogen, which is then stored. And when power is in short supply, hydrogen can be extracted from storage and then burnt in conventional gas power stations to provide an immediate boost to electricity generation. In this way, it is a near-perfect complement to ever-cheapening renewables.

2.    Separately, hydrogen can also replace fossil fuels in those activities that cannot be switched to electricity. For example, steel-making currently uses about 20% of world coal and is responsible for perhaps 8% of world greenhouse gases. Coal can be entirely replaced by hydrogen. And green hydrogen stored in the form of ammonia will provide the fuel for long-distance shipping. Some heating needs may shift from natural gas to hydrogen, including those of domestic homes.

These two areas of use will allow green hydrogen to grow rapidly over the next decades. It will become a central pillar of our move to ‘net zero’. 

How will green hydrogen be transported?

Some hydrogen will be used close to where it is produced. For example, the Spanish utility Iberdrola is developing a large PV farm next to a fertiliser factory.[1] The solar electricity will be used to make hydrogen, a critical ingredient for fertiliser production. Another big scheme in Germany envisages hydrogen made from offshore wind used in a new steel plant near the port of Wilhelmshaven.[2]

Alongside local use of hydrogen, developers are also planning huge pipeline networks. One proposed scheme sees a total of 40,000 km of pipeline criss-crossing Europe by 2040.[3] About two thirds of this grid will use existing natural gas pipelines, repurposed to carry hydrogen. This will provide much of the capacity to move the gas from where it is made to the place of utilisation. So, for example, hydrogen will be made at offshore wind farms, at the base of the turbines or on dedicated platforms, and then carried by pipe to large industrial centres where the gas will be used.

This shouldn’t surprise us: it is far cheaper to transport hydrogen over long distances than it is to shift electricity. One estimate is that the cost could be as low as about 0.3 Euro cents per kilowatt hour for a 1000 km link.[4] That’s roughly the distance from Penzance to Aberdeen. The cost of building a new pylon link to move electricity over this distance would be much greater. And it would be almost impossible to get the political support to allow a new above-ground electricity link, as policy-makers in countries such as Germany have found when they have proposed new north-south power networks. 

But is it safe to move hydrogen around in pipelines? Doesn’t the gas corrode the pipes, resulting in eventual leakage? No, hydrogen can probably be moved with greater safety than methane, or natural gas. Pipelines cannot be made from iron or steel which is embrittled by hydrogen, but thick plastics are effective and safe. The world already has several large pipeline systems for hydrogen, including at least 1,600 miles of pipe in the US, without any serious reported problems.[5]

At normal pressure, hydrogen is a much less dense substance than methane, the primary ingredient in natural gas. So it will be need to be transported at higher pressure. This means that pipelines being converted from natural gas to hydrogen will need to add compressors along the trunks and branches of the networks. 

How will the hydrogen be stored?

Of course we will also need substantial storage to enable hydrogen to match the supply and demand for energy. The UK is lucky in that large parts of the country have thick layers of salt well underneath the surface. Hydrogen can be stored by dissolving some of this salt in water and then extracting the brine. This creates what are called salt caverns, which usually have the approximate shape of a wine bottle, sometimes hundreds of metres in height. The remaining salt is almost totally impermeable to hydrogen. In fact, three salt caverns have been used for hydrogen storage in the UK for several decades and more can be found in the US. Salt caverns also already provide large storage capacity for natural gas in various parts of the world, including China.

To summarise; a switch to an energy economy that combines renewable and green hydrogen is the most likely route to net zero, in the UK and elsewhere. Large fractions of our solar and wind farms will need to be devoted to making hydrogen, at least part of the time. And this hydrogen will need to be transported to the end-user. This looks both technically possible and highly economical. Many of the users will be large industrial companies. 

Hydrogen in the home

Many UK homes will switch to heating with electricity, principally using what are known as ‘heat pumps’. But hydrogen can also be used a fuel for heating buildings and in many circumstances this may be cheaper for the homeowner and equally compatible with the UK’s zero carbon objectives. This will replace natural gas, which creates CO2 when burnt. On the other hand, hydrogen just turns into water vapour. We’ll need new central heating boilers but these are likely to be no more expensive than today’s natural gas equivalents. And much, but not all, of the UK’s gas pipeline network still needs to be modified to carry hydrogen to homes, schools, offices and other buildings.

This is where the Abundance debenture issue for Northern Gas Networks (NGN) comes in. NGN wants to have pipelines, small and large, that can safely and effectively accommodate a possible switch to hydrogen from natural gas. This is a costly programme, but we cannot continue to burn fossil fuels in homes and other buildings and hydrogen is the obvious replacement for some of our homes and other buildings.

[1] https://www.iberdrola.com/press-room/news/detail/iberdrola-fertiberia-launch-largest-plant-producing-green-hydrogen-industrial-europe

[2] https://www.uniper.energy/news/uniper-plans-to-make-wilhelmshaven-a-hub-for-climate-friendly-hydrogen

[3] https://gasforclimate2050.eu/news-item/european-hydrogen-backbone-grows-to-40000-km/

[4] https://gasforclimate2050.eu/news-item/european-hydrogen-backbone-grows-to-40000-km/

[5] https://www.energy.gov/eere/fuelcells/hydrogen-pipelines

Even removing environmental levies won't bring electric heat pumps to cost parity with gas boilers

(The rise in energy prices in the UK on April 1st 2022 affected gas more than electricity. The ratio between the two prices has changed. Using the COP assumptions in this article, removing all environmental levies from electricity and placing them on the price of gas would now mean that a heat pump would currently reduce the overall bill if a heat pump is installed).

Even after deducting all environmental levies, heat pumps remain more expensive than gas.

Some comments about a previous post on the costs of heat pumps focused on the effect of high levies imposed on electricity in the UK. The purpose of this short piece is to suggest that even after moving all environmental and social charges from electricity to general taxation, air source heat pumps will still have higher energy costs than gas boilers.  

This is a fundamental obstacle to the government’s plans for a huge growth in air source heat pump use.

In the previous article I used the prices for electricity and gas provided by British Gas, the UK’s largest supplier, for a household in Oxford. 

These were over 17.7 pence per kilowatt hour for electricity and 3.3 pence for gas.

The ratio between these numbers is about 5.33 times. This implies that unless a heat pump is very much more efficient, the household’s energy costs will rise substantially when one is installed. This is what is usually experienced by families around the UK, if my email inbox is any guide.

Heat pumps can be very efficient, putting up to 4 units of heat into a house for each unit of electricity consumed. But typically in the UK air source heat pumps do not deliver efficiency gains of anything like this number. Academic research for the UK government suggests that the real ‘Seasonal Performance Factor’ is probably below 2.8.[1]

Even after taking into account the efficiency loss of a gas boiler, arising from the small percentage of the energy value of gas not being delivered into hot water, heat pumps will therefore be very much more expensive. 

Calculating the impact of ‘Environmental and Social Obligation Costs’ on the economics of heat pumps.

I looked at British Gas’s most recent ‘Consolidated Segmental Statement’ for 2019.[2]This allowed me to deduct the financial charges loaded onto electricity prices. (These arise from costs such as Feed-in Tariff payments). 

If we removed all these costs entirely for 2019, the price of electricity would decline by about 23%, bringing it down to about 13.4 pence per kilowatt hour or just over 4 times the price of gas. At this ratio, and assuming 85% efficiency for a gas boiler, switching to a heat pump will still add about 22% to a household’s bill for home heating. 

The government could take one further obvious step. It could transfer all the current Environmental and Social Obligation Costs from electricity to gas. This action would approximately equalise the cost of running an air source heat pump and operating a gas boiler in the average UK household. 

If the UK wants to push heat pumps – and I can certainly see the logic of this ambition, even with all the reservations expressed in my previous post – it will have to radically shift relative gas and electricity prices. It needs to cut electricity prices by a quarter and add a quarter to gas. I wonder whether there is any impetus to achieve this?

[1]https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/606829/DECC_RHPP_160428_On_performance_variations_v20.pdf

[2] https://www.centrica.com/media/4011/centrica-2019-ofgem-statement.pdf

Hydrogen versus heat pumps for decarbonising heat

Chris Goodall 

DRAFT, for comment

SUMMARY

Many times a year I am contacted by people who have had electric heat pumps installed at their house. Almost all complain that their utility bills have sharply risen and also that their home is no longer as warm as it was. Sometimes the reason is that the householder has not been properly trained on how to operate the heat pump but mostly the causes seem to be a mixture of poor installation and inappropriate choice of equipment.

Despite increasing evidence of underperformance and high costs, the UK continues to push to increase the rate of installation, targeting 600,000 new heat pumps a year by 2028. I use this note to identify six reasons why this surge may be a mistake and why it might be better to replace natural gas central heating with hydrogen boilers to achieve our decarbonisation objectives.

* Electricity in the UK is over five times more expensive than natural gas. Although heat pumps are about three times more efficient that gas boilers, this isn’t enough to compensate for the vastly higher price of electricity.

* Heat pumps are far more expensive to install than gas boilers, whether running on hydrogen or natural gas.

* Heat pumps often don’t work effectively. (This may be a consequence of poor installation or, more likely, the low insulation standards of typical UK houses).

* Heat pumps use a lot of electricity. As a result, the distribution network, currently responsible for 22% of domestic bills, will need very expensive upgrading to deal with the increased electricity demand.

* Hydrogen can be stored in large volume whereas electricity cannot be. This means that on cold days, when heat demand might be ten times today’s electricity requirements, hydrogen will be much better at dealing with peak demand

 * Similarly, hydrogen will be more able to cope with high rates of increase in energy demand as the cold weather arrives. 

These arguments are dealt with in detail below. My conclusion is that hydrogen needs to considered as the primary means of decarbonising domestic heat, the creator of about 20% of UK emissions.

I start by looking briefly at why heat pumps are generally thought to be better than hydrogen at servicing domestic needs before going on look at the weaknesses in the case for any form of electric heating compared to the use of hydrogen.

The arguments against hydrogen in heating.

 1, Electricity can be decarbonised relatively easily. The current wisdom is that we should therefore shift as many energy-using activities to electricity as we can. This includes domestic heating, which is currently responsible for about 20% of UK emissions.

2, The most energy efficient way of delivering electric heating is through the use of heat pumps, say the proponents. Therefore we should try to expand the use of heat pumps as fast as possible. Why are heat pumps relatively efficient? A heat pump will normally deliver more heat into a building that it actually consumes in electricity. It is transferring heat from one place to another, not generating it. This is the crucial reason why researchers and policy-makers are emphasising the virtues of rapid expansion of heat pump installations.

The reasons why hydrogen will be a better alternative than heat pumps for at least a large fraction of UK heating.

I suggest that there are six reasons why hydrogen should nevertheless be extensively deployed for domestic heating in the UK. (These are not arguments that there should be no heat pump installations but rather that hydrogen will be better at serving the bulk of demand. New housing developments with well-insulated properties should certainly be furnished with ground source heat pumps, for example).

1.    The relative price of gas and electricity

Proponents say that heat pumps save householders money. This is very unlikely to be true. The reason is the ratio between the price of gas and that of electricity in the UK.

In early April 2021 the prices offered to me by the largest UK utility, British Gas, were as follows[1]:

Electricity     17.753 pence per kilowatt hour

Gas                3.331 pence per kilowatt hour

In other words, electricity is well over five times as expensive as gas per unit of energy.[2] A quick look at tariffs from other suppliers confirm that the British Gas ratio is broadly representative. A customer switching to electricity from gas will therefore pay far more unless the new heating system is very much more efficient.[3]

Heat pumps are indeed more efficient. In the best installations, where a ground source pump is feeding a well-designed underfloor network in the home, it may be possible to get 4 units of heat for each unit of electricity supplied over the course of the year. But typically an air source heat pump feeding domestic radiators will only achieve about 2.7 units of heat with one unit of electric power.

Gas boilers aren’t 100% effective at turning gas into heat in the radiators. The rated efficiency of a new boiler can be as high as over 92%. However even the best modern units are sometimes badly installed or the home heating network is not ideally set up to achieve the best heating from the gas consumed. It might be better to assume a figure of 85% for a new boiler.

Let’s compare the costs of a home using 12,000 kilowatt hours of gas and a residence delivering the same amount of heat using a heat pump.

Gas – 12,000 kWh of gas costs £399.72 (plus the standing charge). This delivers 85% of 12,000 kWh as heat into the house, or 10,200 kWh.

 Electricity – 10,200 KWh provided from heat pump at an efficiency ratio of 2.7 = 3,777 kWh of electricity consumed. This costs £670.68 at current prices, or £271 more than gas.

The conclusion is clear. Switching to electric heat pumps from gas central heating will cost most UK householders substantial amounts of cash, probably increasing typical bills by more than 50%.

Would the use of hydrogen be any better? It depends on the price of hydrogen of course. And we cannot forecast that accurately. (Even though people like me try to do this all the time). 

Let’s use two different numbers. First, $1.50 per kilogramme of hydrogen. This price is often used as an estimate of what price hydrogen will achieve by the end of the decade. But this depends on the rate of fall of renewable electricity costs. These dominate the cost of making hydrogen.

At $1.50 a kilogramme, hydrogen costs 4.5 US cents per kilowatt hour. This is equivalent to 3.26 UK pence per kilowatt hour. Gas is currently priced at around 1.6 pence per kilowatt hour on the UK wholesale market. So hydrogen will be about 1.66 pence per kilowatt hour more expensive than gas at wholesale, or around double the cost.

We can estimate the price of hydrogen delivered to the home by adding this amount to the price of today’s gas, plus a small addition to reflect the slightly higher cost of shipping hydrogen through today’s natural gas pipelines.[4] 

If we add a total of, say, 1.8 UK pence to today’s price of gas we arrive at 5.131 pence per kilowatt hour for a domestic user. A gas usage of 12,000 kilowatt hours will cost the householder £615.72. This is an annual increase of over £200 but is still cheaper than the heat pump alternative at £670.68.

The second number I want to use is the price that would equalise the cost of the energy typically used for a heat pump and that of hydrogen. This could either be achieved by lower electricity prices or higher hydrogen prices. Very roughly, we achieve equality of heat pump and hydrogen prices either by raising the hydrogen price to about $1.72 per kilogramme, up from the target of $1.50, or cutting the price of electricity to about 16.2 pence per kilowatt hour, down about 9% from today’s rates. 

A hydrogen price of $1.72 per kilogramme is possible in low-cost locations by 2030. These places may include the UK as the price of offshore wind and solar continue to decline. A recent report from Bloomberg New Energy Finance said[5]

Our analysis suggests that a delivered cost of green hydrogen of around $2/kg ($15/MMBtu) in 2030 and $1/kg ($7.4/MMBtu) in 2050 in China, India and Western Europe is achievable. Costs could be 20-25% lower in countries with the best renewable and hydrogen storage resources, such as the U.S., Brazil, Australia, Scandinavia and the Middle East.

The key conclusion is this. A push into heat pumps will significantly raise the heating costs of UK homes. (Partly, of course, this is because they are so badly insulated by European standards). At possible 2030 hydrogen prices, it may be cheaper to switch to hydrogen for most homes, unless government reduces the costs imposed on electricity suppliers.

2.    The cost of installing heat pumps versus replacement hydrogen central heating boilers

Heat pumps are expensive to buy and to install. It depends on the size and complexity of the installation but a figure of £4-5,000 for a typical UK house (semi-detached, 160 square metres) is probably reasonable for an air-to-water unit. If the radiators in a house need replacement, which is likely in many installations, the cost will be even higher, possibly doubling the eventual bill.

We cannot yet know the cost of a hydrogen boiler for the home. But Worcester Bosch, the largest provider of gas boilers in the UK, says that it expects them to cost about the same as today’s models. It has units on trial. So the average house should see a cost of around £2-2,500, including installation. This is half the cost of a heat pump. Very, very roughly, the annual depreciation of a heat pump is likely to be at least £100 more than a hydrogen boiler. So even if cheap finance is available, the heat pump is going to add substantially to the full costs of heating a home.

3.    The reliability and performance of heat pumps versus standard boilers

The UK heat pump installation industry is still small and installation standards have yet to reach uniformly high levels. Many owners are unhappy with the performance of their heat pumps, saying that they feel that the units do not deliver reliable heat. Partly this may be as a result of householders trying to restrict the use of the pumps because of the high bills that are being received for increased electricity use. But it is undoubtedly true that many homeowners with heat pumps are not able to heat their house consistently to a comfortable level. Bills are also far higher than expected across the country.

4.    The extra infrastructure required across the country

The demand for heat for houses varies hugely throughout the year. At peak, domestic heating probably requires about 170 gigawatts during half hour periods on very cold days.[6] This can be compared to levels peaking at around 50 gigawatts for today’s electricity consumption at similar times. 

 If the average heat pump delivers 2.7 units of heat for each 1 unit of electricity consumed, the figure of 170 gigawatts is lowered to around 60-65 gigawatts if all housing is converted. This is equivalent to adding 120% to total electricity demand. Actually, the numbers will be far worse than this because air source heat pumps work less efficiently at lower outside temperatures when heating needs are greatest. The actual increment to UK electricity demand is likely to be more than 100 gigawatts from a full conversion, tripling maximum electricity demand.

Two problems result from this. First, it will require large amounts of new network infrastructure, ranging from transmission lines to local transformers. I cannot estimate the cost but it will almost certainly add very substantially to electricity bills, further raising the running cost of heat pumps.[7] In addition, many of the required upgrades will be intensely politically controversial. Large-scale transmission lines are already extremely difficult to impose on communities, as both the UK and other countries such as Germany have found. 

The second problem is the availability of renewable electricity supply to meet the increased peak demand levels. To provide reliable power at 150 gigawatts in deep winter, when wind speeds are likely to be low because of the anticyclonic conditions, is an almost impossible challenge. 

The four reasons for deep reservations about the viability of air source heat pumps above are complemented by two reasons why hydrogen will be a more appropriate choice for much domestic heating.

5, Hydrogen can be stored cheaply and shipped around without major investment in new infrastructure.

Within a few years, the UK will frequently have too much electricity as offshore wind booms. The government has a target of 40 gigawatts offshore by 2030, up from just over 10 gigawatts today. This will meet total demand on its own over long periods even before considering onshore wind and solar PV. Solar PV is also likely to double by 2030, based on current indications of future build-out. 

When renewables supply exceeds demand, hydrogen is the only viable long-term storage medium. The UK is well supplied with potential salt caverns in which hundreds of terawatt hours can be stored. The hydrogen can then be used for domestic heating at some future point, as well as for other applications such as ammonia manufacture, steel-making, chemicals manufacture and for use in electricity generation at times when renewables supply is limited.[8]

Hydrogen can use existing pipelines and domestic supply networks. They can be switched relatively easily from the distribution of natural gas and the UK gas operators are heavily engaged in planning for this. (As are most European networks) More compressors will be required on the distribution lines but the cost of this is likely to be insignificant compared to the extra electricity distribution costs required by a large scale switch to heat pumps. 

6, Hydrogen is far better than electricity at dealing with sharp peaks in demand

It is not simply that hydrogen is easy to store and transport. It is also that it is better able to cope with rapid changes in the level of demand. The ‘ramp rate’ is the amount of change in energy use as demand rises, for example when householders return from work. At the moment, the electricity ramp rate peaks at less than 5 gigawatts an hour. But the ramp rate for heating is probably more than 10 times this level.[9]

This number would fall if heat pumps were providing 100% of domestic heat because they should be operated constantly, even when householders are out of the house. But, nevertheless, a full transition to heat pumps will significantly increase the variability of electricity demand, posing problems for suppliers and distribution network operators. Gases, including hydrogen, are far better at handling this variability, partly because the gas in the pipelines themselves represent substantial stores of energy which can meet sharp changes in demand.

 To summarise: domestic heating uses more energy (about 300 terawatt hours a year in natural gas alone) as all electricity requirements combined. And usage is highly variable, peaking on cold days at almost six times electric power employed for all purposes. Running an energy system to service such a large and unstable demand using electricity is unlikely to work. It is far better to employ a more easily storable energy vector such as hydrogen, which can be easily made and stored at times of excess power generation and then distributed when needed.

Hydrogen is currently substantially more expensive than natural gas. But the gap between the two commodities is highly likely to narrow sharply in the next decade and may then disappear in energy-rich countries such as the UK. The current focus on heat pumps as the principal route for decarbonisation of heating therefore makes little sense.

April 8th 2021

Chris Goodall

chris@carboncommentary.com

+44 7767 386696

[1] Direct Online Only tariff Version 7 for a house in Oxford.

[2] Part of the reason for this large difference is that the costs of decarbonisation have been largely loaded onto electricity rather than gas. 

[3] It is helpful to note that the ratio between gas and electricity prices is particularly wide in the UK. EU Commission data suggests that the average ratio in the EU is about 3.3, not the 5.3 recorded in the current British Gas tariff. Seehttps://ec.europa.eu/eurostat/statistics-explained/index.php/Electricity_price_statistics and https://ec.europa.eu/eurostat/statistics-explained/index.php/Natural_gas_price_statistics

[4] Hydrogen is less dense and although it can probably be transported at higher pressure than natural gas it still requires more compressor stations to ship through the network.

[5] https://assets.bbhub.io/professional/sites/24/BNEF-Hydrogen-Economy-Outlook-Key-Messages-30-Mar-2020.pdf

[6] https://www.sciencedirect.com/science/article/pii/S0301421518307249

[7] Currently distribution charges make up 22% of the average domestic electricity bill. It doesn’t seem unreasonable to suggest that this number could double if the UK had to install the infrastructure to handle peak electricity flows of 3 times current levels.

[8] Hydrogen power stations, such as adapted gas turbines, are now being planned in Europe and elsewhere. 

[9] https://www.sciencedirect.com/science/article/pii/S0301421518307249

The UK would require 100 GW of offshore wind for domestic heating, not the 300 GW the CCC claims

The Chief Executive of the UK’s Climate Change Committee is reported as saying that the UK would need to multiply its offshore wind capacity 30 fold in order to produce enough hydrogen to fuel domestic boilers. He appears to say that this therefore makes hydrogen impractical as a substitute for natural gas. I don’t think his number is remotely correct.

The CCC has always been a little sceptical about hydrogen for the obvious reasons that it is currently expensive and a switch to using it for domestic heating is a difficult and highly ambitious step.

In this case, its scepticism is overdone. To make enough hydrogen to completely cover the energy needs of all UK domestic homes currently using natural gas for space and water heating would require about 101 gigawatts of extra offshore wind, not the 300 gigawatts the CCC claims. (There is about 10 GW of offshore wind at the moment).

This is an important difference. The UK government is promising 30 gigawatts of new offshore wind in the next ten years so 101 extra gigawatts is easily conceivable. 300 is much more difficult. 

By the way, we hydrogen fan-boys don’t argue for exclusive use of hydrogen in domestic heating. if we can electrify space heating using heat pumps we should do so. But heat pumps will not work effectively in many circumstances and hydrogen will therefore probably be necessary for some homes. It is well within the capacity of the UK offshore wind sector to provide the electricity necessary, despite the CCC’s statements.

Assumptions

Here are the assumptions behind my calculation.

1, Offshore wind capacity factor – 50%. (Probably a bit low for future wind farms but a bit higher than is currently achieved).

2, Electricity to hydrogen conversion factor – 70%. (Achievable today with a PEM electrolyser).

3, Requirement for total terawatt hours for domestic gas use – about 310 TWh. (Source: DUKES Energy for 2020)

4, Total offshore wind capacity required to provide 310 TWh of hydrogen – About 101 GW.

5, I have not added in the small amount of relatively extra energy needed to pump hydrogen through a network of pipes compared to natural gas.

BP and synthetic fuels at the Lingen refinery

BP has talked for several years of generating green hydrogen at its refinery in Lingen in north western Germany. In 2016, the utility Uniper announced that it was cooperating with the oil company to build an electrolysis plant that would supply H2 to the site. Nothing seems to have happened.

 This week BP made a similar announcement. This time it has paired with Orsted to develop a plan to build a 50 MW electrolysis plant, using electricity sourced from offshore wind in the North Sea. The scale of the scheme has increased from 25 MW, and several other features make this plan more likely to go ahead. Indeed BP talks of eventually extending the size of the plant to 500 MW, ten times the initial capacity.

The Lingen refinery uses about 45,000 tonnes of hydrogen to make some the hydrocarbons it produces from oil. To put this number into context, global production of pure hydrogen is about 70 million tonnes and the refinery processes about 0.1% of world oil. 

 According to BP and Orsted, the 50 MW electrolyser will produce about 9,000 tonnes a year of hydrogen, 20% of the refinery’s needs. If we assume that the electrolyser works 8000 hours a year, the wind energy used will be about 400 GWh. 9,000 tonnes of hydrogen has a lower heating value (LHV) of around 75% of this, or around 300 GWh.

According to BP, the CO2 emissions from the refinery will fall by about 80,000 tonnes as a result of using electrolysis. That’s approximately 9 tonnes of CO2 for each tonne of hydrogen. At today’s price of €26 per tonne, the carbon tax reduction from producing a tonne green hydrogen is around €235, or 23.5 Euro cents per kilogramme, equivalent to 31 US cents per kilogramme. 

Hydrogen made from wind in the North Sea will probably cost around €2.25-2.50 a kilo, perhaps a bit more ($2.66-$2.95+). This compares to a raw cost of hydrogen made from natural gas in Germany of probably no more than about $1.60. So green hydrogen will be more expensive, even after taking carbon taxes into account. But it is worth noting that pulling the CO2 price up to $50 a tonne would probably come reasonably close to equalising the cost of green and grey hydrogen. 

Perhaps the most interesting part of the BP/Orsted announcement is the future possibility of expanding the electrolyser capacity ten times. As the press release makes clear, this would take the amount of hydrogen produced to well over the refinery’s current need. The surplus will be used, the partners say, to perhaps begin the process of making synthetic fuels. (By ‘synthetic’ in this particular case, I imagine that BP envisages making petrol or diesel replacements using hydrogen and captured CO2 from the refinery’s other operations). 

This is, I think, the first time that BP has publicly announced an intention to make replacements for fossil fuels. (No commentators or journalists have made this point, so please treat this assertion as tentative). Of course this is a long way off; BP says that the smaller electrolyser won’t begin operation until 2024, even if it can rapidly agree a subsidy scheme with the German government. 

Nevertheless this announcement seems very important. It is a curious fact that oil refineries, which symbolise the fossil fuel economy, may become the first industrial sector to shift towards to 100% green hydrogen for their own operations. How much wind capacity will be needed to fully decarbonise hydrogen production for refineries? Based on this example, full replacement of methane for making hydrogen will require at least 500 GW of electrolysers and probably well over 1 TW of offshore wind, 50% more than current worldwide wind capacity.

How much hydrogen will be needed to replace coal in making steel?

About 7-9% of the world’s emissions arise from the manufacturing of steel. It is the world’s most polluting industry. Hydrogen could entirely replace the massive use of coal, although the transition will be expensive. However it is probably the only realistic way that steel can get to net zero, a conclusion that seems increasingly shared within the industry.

This note looks at the likely costs of making steel without significant emissions. It assumes that hydrogen is made using renewable electricity and briefly assesses how much new wind or solar capacity will be required to allow the industry to get to ‘net zero’. Making hydrogen from steel only takes place today in tiny quantities so the figures in this article cannot be definitive but I thought it would be helpful to give a sense of scale. Corrections are very welcome.

The basic numbers

The world makes about 1.8 billion tonnes of steel a year. This number is expected to rise to possibly double this level by 2050, although there is a very wide range of forecasts. 

Steel use in developed countries will not rise substantially, if at all. A modern economy typically requires a stock of about 12 tonnes of steel per person to provide the buildings, cars and other infrastructure required. Most OECD countries are already at this level. A decade of rapid building has given China a large fraction of the circa 12 tonnes per person required. 

But total steel sales of about 1.8 billion tonnes a year only provides about a quarter of a tonne per person globally. Although we will probably see improvements in the efficiency of steel use, replacing some metal with wood or carbon fibre, the world is very far from sating its needs.

‘New’ steel versus recycled metal. 

About three quarters of all steel made today comes from the processing of iron ore. Coal is burnt in a blast furnace to ‘reduce’ the ore, that is extract its oxygen leaving metallic iron. The remainder is almost all made from the recycling of existing steel in electric arc furnaces. 

 ‘New’ steel                 1.35 billion tonnes

Recycled steel             0.45 billion tonnes

Total                            1.80 billion tonnes

 Some processes in the manufacture of ‘new’ steel can be improved. New plants use less coal than ones that are fifty years old. But the processes employed today will always need very large amounts of coal.[1]

 Each tonne of ‘new’ steel typically requires about 0.77 tonnes of coal, meaning that the industry as a whole uses just over 1 billion tonnes a year.

The energy value of the type of coal used for steelmaking is about 8 megawatt hours (MWh) per tonne. So each tonne of ‘new’ steel has typically required about 6 MWh in the process of getting from iron ore to a finished steel product, such as coil used for making the exteriors of cars. 

The coal energy needed for steel-making is therefore

1.35 billion tonnes of steel times 6 MWh = about 8,000 Terawatt hours (TWh) = as a comparison, about one third of global electricity consumption

 By contrast, recycled steel uses much less energy per tonne. One source suggests about 0.67 MWh per tonne of finished product. 

Using hydrogen instead

A small quantity of steel is made today using what is called the ‘direct reduction’ process and the technology is mature. A synthesis gas (hydrogen and carbon monoxide) made from methane (natural gas) is burnt in a large chamber to extract or ‘reduce’ the iron ore to metal.

The first experiments in large scale direct reduction using pure hydrogen are now being carried out at the SSAB steel works in Sweden. These experiments will give us more accurate data on the amount of hydrogen needed. 

Direct reduction using hydrogen will almost certainly be more energy efficient than using coal. From reading around the subject, I guess that a tonne of finished ‘new’ steel will require about 3 MWh of hydrogen, considerable less than the 6 needed for coal-based processes. However the process of making the hydrogen will incur some additional energy losses in the electrolyser, taking the amount of electrical energy required up to between 4 and 4.5 MWh per tonne of steel. Let’s assume the figure is about 4.25 MWh.

 Amount of electricity required to create the hydrogen to make all the world’s ‘new’ steel at today’s production levels = 1,350 million tonnes times 4.25 MWh = 5,700 Terawatt hours or about one quarter of world electricity production.

If the hydrogen is all made from renewable electricity, how much extra wind or solar capacity will be required?

 If the average new wind turbine has a capacity factor of 40% (low for offshore, probably about right for onshore) then the world would need about 1600-1650 gigawatts of extra turbines. This is well over two and a half times the currently installed amount of wind power globally. The figure for solar PV would be roughly twice this level.

What weight of hydrogen will be required?

 Figures for the world’s current hydrogen production vary between sources but most indicate that about 70-80 million tonnes of the gas are made each year. None is currently used for making steel.

A tonne of ‘new’ steel will need about 90 kilogrammes of H2 (with an energy value of about 3 MWh). 

 1,350 million tonnes of steel, each requiring 90 kg will use about 122 million tonnes of hydrogen, or about 50% more than current world production.

What about the capacity of electrolysers?

If we assume that the electrolysers work every hour of the year, then we will need about 650 gigawatts of capacity. This compares to less than 1 gigawatt installed globally at present. 

Conclusion

A swing to hydrogen as the fuel and reducing agent for steel production will involve a major transition. Very large amounts of new renewable capacity will be required if ‘green’ hydrogen is used. The electrolyser manufacturing industry will need to expand by several orders of magnitude. And, of course, the steel industry will have to invest billions in the new plants required. Most sources suggest that for the main steel firms to make the transition voluntarily that they will have to see a mixture of low power prices (say below $40 a MWh) and a reasonable carbon tax (at around $50 a tonne). These figures seems entirely attainable to me.

[1] Today’s plants use a blast furnace (BF) in which coal is used to reduce ore to liquid iron. The iron is then turned into steel in a basic oxygen furnace (BOF). The BF-BOF process is now used to make a very large fraction of all ‘new’ steel.