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.

Nine steps towards Net Zero. (published in the Guardian Tuesday 6.10.2020).

Net zero. It’s a simple enough concept to understand – the notion that we reduce carbon emissions to a level such that we are no longer adding to the stock in the atmosphere. More and more companies and countries are taking the pledge, promising to hit ‘net zero’ by 2050, 2030 or even sooner.

But it’s easier said than done. Industrial processes remain carbon intensive, agriculture and aviation too. Even the sudden economic halt brought about by Covid 19 this year will result in a mere downward blip in greenhouse gas emissions.

The sharp decline in energy use at the beginning of the pandemic has not persisted. Government stimulus programmes have done little to prioritise green projects - barely 1% of the funds made available around the world will target climate change mitigation (LINK). Hopes that the virus would push us into radical action to reduce emissions have proved illusory.

This may make us pessimistic about the future – but that would be mistaken. The last six months have seen a growing realisation around the world that fully decarbonising our societies is technically possible, relatively cheap and potentially of major benefit to society, particularly its less prosperous families.

A sensible portfolio of actions can reduce emissions, provide jobs and improve living standards in forgotten parts of the UK. It won’t be completely painless but this nine-step plan can beneficially transform much of the British economy.

1. Energy

Successful action will start with electricity generation. Britain has made surprisingly good progress in recent years, cutting CO2 from power plants by 60% in the last decade, largely as a result of the replacement of coal generation by wind and solar power. We should go much further because we’ll need to generate far more electricity to meet demand from electric cars and from heat pumps for home heating. If we increase generation by about 20 times from today’s levels. (CAN YOU describe here what that would look like: x new mega wind farms? Solar panels on every house? Are we on track for this kind of expansion - increasing anything 20fold seems an enormous task?) this will give us sufficient electricity almost all the time, significantly reducing the problems arising from the unpredictability and intermittency of most renewable sources. Is such as massive expansion actually possible? I have calculated (LINK) that the UK would achieve this target by devoting about 5% of its maritime zone to offshore wind, 2% of the land area to solar panels and about 12% to onshore wind. These are large numbers, but far from impossible. BP, a recent convert to the importance of the expansion of global renewables, makes a similar estimate that wind and solar should also be expanded 20 times around the world to achieve net zero emissions by 2050. (LINK)

2. Batteries and hydrogen

Under the scenario described above, we will have far too much electricity almost all the time. Batteries can cope with some of this surplus but most of the power should be converted to hydrogen. Today, hydrogen is created from fossil fuels but it can be easily made from water using the electrolysis process. The gas can be stored for later use to make electricity on the rare occasions when renewable power is insufficient. Hydrogen is hugely versatile; it can also be deployed to power vehicles, to provide the energy for steel-making and other industrial processes and to act as the critical raw material for the chemicals industry. Although ‘green’ hydrogen made from renewable electricity is currently much more expensive than natural gas, the consistently rapid fall in renewable energy prices is pushing down costs every month. This means that for those buildings that cannot be heated by electric heat pumps, hydrogen boilers may even become a viable alternative to gas central heating. 

In the last few months, major European countries have shifted strongly towards this plan. France (LINK) and Germany (LINK) have promised a total of €16bn to help build a hydrogen sector. Companies in Norway (LINK) and Denmark (LINK) have announced plans to create chemical plants to build zero-carbon liquid fuels made from hydrogen and using carbon dioxide captured directly from industrial processes. Italy’s dominant gas distributor has begun mixing hydrogen into its pipelines (LINK) while Spain’s largest utility will build a facility to make the gas from solar electricity(LINK) and use it to provide all the needs of a large fertiliser plant. Shell will take surplus electricity from North Sea wind farms to provide hydrogen for an oil refinery in the Netherlands (LINK). A Finnish partnership has suggested using the CO2 from paper mills to combine with green hydrogen to make substitutes for petrol and diesel (LINK) while a French mill will be using it to make electricity when power prices are high (LINK). All this has happened in the last year and the number of announcements is speeding up across the continent.

3. Utilities

As a supplement to decarbonising energy supply, we also need to wrest control over the energy networks back from their current owners, often non-UK businesses owned by private equity funds. Many other countries, such as the US, have publicly controlled energy companies that can act to meet local needs and minimise the cost of gas and electricity. We should follow the example of Germany and offer the chance to local governments to run all the utility networks in their areas. So far, municipal energy companies have not been successful in the UK but they have never actually been able to own the pipes and wires within their towns and cities. This should change.

4. Efficiency

We need to complement the decarbonisation of energy supply with measures to improve energy efficiency. In the UK the crucial target is the poor insulation standards of almost all our housing. Policy has been lamentably weak in this area over the last decades. We have seen minor improvements but now require programmes of deep refurbishment, working street-by-street across the country. This may seem an expensive and difficult programme but nothing else can provide an adequate boost to jobs and incomes in our most deprived areas. The refitting of our substandard homes is the best way of avoiding the worst consequences of the otherwise inevitable rise in unemployment over the next months and years. France is devoting a large fraction of its economic expansion plan to improving the energy efficiency of its homes and public buildings such as schools and prisons. We can also follow this example.

5. Motoring

The obvious other target is car use. Many European cities have pedestrianised large areas of the centre, introduced better cycling provision and improved public transport. As far as I know, none has reversed these changes. Taking cars out of cities is the single best way of reviving centres, reducing pollution levels and getting more people on bikes. Let’s particularly embrace electric bikes, which use a hundred times less energy than a car. Detailed analysis in the Netherlands city of Utrecht (LINK) showed that the spending on cycle lanes was more than repaid by lower health costs as a result of the population embracing active means of getting around the urban centre.

6. Farming

Energy use represents around two thirds of carbon emissions. Easily the next most important source of greenhouse gases is farming. Cows and sheep emit methane and fertiliser use creates nitrous oxide, both powerful greenhouse gases. Moving towards a diet dominated by plants is a vital part of the fight against climate change. We’ll probably never get a stable climate until meat has almost disappeared.

However it is increasingly clear that we can make fully vegan foods that resemble meats for those who would miss the taste and texture of the real thing. Meat production dominates farming around the world and reducing animal numbers will give us space to introduce properly climate-friendly agriculture. That means farming that is less intensive and less dependent on herbicides, pesticides and fertilisers. It will also employ more people.

7. Reforestation.

We need a massive programme of reforestation. The UK woodland cover is little more than a third of the extent of other large European countries and the planting of mixed trees will help capture CO2, bring jobs back to the periphery of the British Isles, help control flooding and improve air quality, as well as providing greater opportunities for leisure.

8. Flying and shipping.

In the long term, we can probably replace the fossil fuels we use for flying with low carbon alternatives made from captured CO2 and hydrogen. Today, we should cut our flying, either taking the train or avoiding long distance travel. This is costly and difficult for some people but the ‘Flight Shame’ movement originating from Sweden has helped push down passenger numbers, particularly in Germany. Flying really matters to your personal carbon footprint; a return journey from London to New York will typically produce more CO2 than your share of the emissions from driving a car for a year.

9. Carbon tax

Lastly, we should try to bring the reluctant oil and gas industries onto our side by instituting a tax on the production of anything which results in carbon emissions. Rarely in the past have businesses asked to be more heavily taxed. But today almost all large fossil companies are pleading for a carbon levy that provides the necessary incentive for them to wean themselves off extracting oil and gas.

Fighting the causes and consequences of climate change is neither particularly difficult or expensive. The net impact on jobs and living standards will be strongly positive. The programme will require direction from central government, and probably an effective carbon tax, alongside a willingness to hand over some powers to local authorities.

Perhaps this is the most contentious part of the programme I propose - the idea that Whitehall should recognise both that the free market needs some assistance when it comes to climate change, and that devolution of real power to towns and cities could be beneficial to everybody.

Chris Goodall is an author and environmentalist whose latest book, What We Need To Do Now, assesses the steps needed to build a low-carbon world and was shortlisted for the Wainwright Prize. He writes a weekly newsletter on low carbon progress around the world, available at www.carboncommentary.com

Business is now the dominant force pushing the speed of decarbonisation

Most of us assume that governments and international organisations will take the crucial roles in the fight against climate change. But over the past year more and more commercial companies have chosen to become the leaders in the battle to reduce emissions. While countries have prevaricated and blustered about their response to the environmental emergency, businesses have quietly taken action to align their activities to the ‘net zero’ objective.[1]

These steps may not pay off immediately. In fact, it is likely that many decisions by corporations will end up by costing them money. Nevertheless, the number, complexity and size of projects announced by major businesses in the last few months have shown a striking commitment to taking important steps to develop low-carbon technologies, even without an obvious monetary incentive.

Here are six examples of very recent path-breaking steps by businesses - many currently involved in activities that produce large volumes of CO2 - in advance of any obligation to take action to decarbonise. Some of these projects have been financially assisted by governments or the EU but all have been partly funded by private companies taking a risk on their investment of money and management time.

 1.    Norsk e-Fuel will make aviation fuel from renewable hydrogen and CO2 captured from a cement plant.[2]Eventually, the company will incorporate CO2 that has been directly captured from the air. It intends to make 100 million litres of fuel by 2026, enough to cover a large fraction of Norway’s needs for domestic routes. The company is a joint venture between technology providers and two industrial companies seeking to build a business that pioneers low carbon fuel for airplanes. The backers of this ambitious venture know that the price of the synthetic fuel may well be twice the cost of today’s fossil oils. Nevertheless, they have pushed ahead knowing that the long-distance aviation will only be possible if this, or other similar technologies, have begun producing low carbon fuel.

 2.    Hydrogen made by electricity from a solar power station will provide the crucial ingredient for a fertiliser factory in southern Spain. Spanish utility Iberdrola has said it will take the power from a new 100 MW solar farm and convert it into hydrogen for use in a large fertiliser factory nearby.[3] The company will use advanced electrolysis techniques to make the hydrogen and will store it as a liquid combined with other chemicals. This highly innovative project will require subsidy from Iberdrola in the form of reduced hydrogen and electricity prices but it says that it is willing to bear these costs in order to speed up the development of new technologies.

3.    Cement producer Lafarge and the Austrian oil and gas company OMV announced that they would cooperate to design and build a plant to capture 700,000 tonnes of CO2 coming from a cement works and turn it into ‘renewable’ hydrocarbons.[4] The other two partners, the largest Austrian utility and a specialty chemicals company, will respectively provide the hydrogen and turn the hydrocarbons into fully recyclable plastics. The plan will take the rest of the decade to come to fruition but nevertheless this is a highly significant project: four different companies embedded in the fossil fuel economy have become participants in a venture which will develop wholly green alternatives to conventional hydrocarbons. 

4.    Steelmaking represents about 7% of world emissions, largely because coal is consumed to reduce iron ore to molten metal. Speciality Swedish steel producer SSAB was the first to take substantial action to move away from this fuel.[5] It is constructing a new steel works that will use hydrogen instead of coal. This will be a new process which several other major steelmakers are also beginning to experiment with. SSAB’s initiative is costly, with a total bill of around €200m to the end of the pilot phase, and the steel produced will be perhaps 25-30% more expensive than metal made using coal. Nevertheless, the company and its partners are confident that the switch away from coal is necessary and its new process will, in time, be the most economical way of producing steel.

5.    In France, a large paper works owned by Smurfit Kappa has decided to employ hydrogen in a different way.[6] It will replace a natural gas turbine that makes a combination of heat and power with one that uses hydrogen. When the energy market is in surplus, the company will convert electricity into hydrogen, and then burn it to make heat and electricity at times of short supply. This pioneering project may be the first time that a commercial company has built its energy strategy around the conversion of power into hydrogen for later use in a gas turbine. It is highly unlikely that the choice makes financial sense today but successful firms are good at taking decisions that reflect what is likely to happen in the future. 

6.    Lastly, I wanted to note a very different sort of project. The US payments processing company Stripe recently asked for bids for a pot of $1m of money that it had set aside to pay other companies to collect and permanently store CO2.[7] Winners included a Swiss company that captures CO2 from the air and then injects it into basalt rock. The rock is chemically altered by this action, permanently sequestering the gas. Stripe is doing what we all need to do, thinking about ways in which it can counterbalance remaining emissions once it has taken all the actions it feasibly can to reduce its carbon footprint.

The first five of these examples share a similar characteristic. The companies are intending to use renewable electricity to provide the energy to break water into oxygen and hydrogen in the process called electrolysis. This hydrogen will be made in times when electricity is in surplus. The gas can be turned into other products or transformed back into electricity when renewable sources are not freely available. 

 This pattern is no accident; we are all becoming increasingly aware that full decarbonisation will require us to invest trillions of Euros in renewables ever year for the next few decades. And because the supply of wind and solar electricity can never be fully guaranteed, we require a storage medium such as hydrogen. Batteries will never provide enough capacity to store surplus power for months on end. The second crucial value of H2 is that it can be transformed relatively easily into close substitutes for fossil fuels. Renewable electricity and hydrogen provides the clearest route to net zero, a view probably shared by all the companies covered in this article.

 These six short case histories illustrate the second phase of the long journey towards decarbonisation. The first was the rapidly growth in investments in wind and solar across the world, increasing the production of green electricity. ENEL Green Power was one of the most important actors in this global movement, accompanied on the journey by the many companies that decided that their electricity purchases came from exclusively zero-carbon sources. The business world now needs to ensure that the momentum is maintained, showing governments and the rest of civil society that decarbonisation is both technically and financially feasible.

Chris Goodall July 2020

[1] We use the expression ‘net zero’ when describing a company or a country that has reduced its responsibility for overall emissions down to zero, possibly by employing techniques that capture CO2 to counteract any remaining greenhouse gases which it creates.

[2] https://www.norsk-e-fuel.com/en/

[3] https://www.europapress.es/castilla-lamancha/noticia-iberdrola-entra-negocio-hidrogeno-inversion-150-millones-proyecto-puertollano-20200312140251.html

[4] https://www.omv.com/en/news/200624_lafarge-omv-verbund-and-borealis-join-hands-to-capture-and-utilize-co2-on-an-industrial-scale

[5] https://www.ssab.com/company/sustainability/sustainable-operations/hybrit

[6] https://www.paperfirst.info/smurfit-kappa-saillat-france-will-produce-paper-with-the-worlds-first-industrial-scale-hydrogen-turbine/

[7] https://stripe.com/blog/first-negative-emissions-purchases

COVID and the energy transition

 Chris Goodall 29 July 2020.

(This article was published by Roca Gallery, part of the Spanish ceramics company and a business I have had the privilege of working with before. URL is http://www.rocagallery.com/covid-and-the-energy-transition)

Many of us hoped that the profound shock delivered to the world by the pandemic would speed up action on climate change. COVID gave us what the English call ‘a teachable moment’, an event that can be employed to communicate a wider truth. The infection arose because mankind’s chronic abuse of nature has allowed more diseases to cross from animals into humans. It ought to be obvious, say climate activists everywhere, that the use of the atmosphere as a dumping ground for carbon dioxide and other greenhouse gases is creating a similar disaster just waiting to happen. Climate change is both more dangerous than COVID and more difficult to control. There may eventually be effective vaccines to the disease but there is no drug that can make us immune to increasing temperatures, fiercer storms and rising waters. 

Nevertheless, I think we will be disappointed by the response to the pandemic. I guess that we will eventually return to the lives we lived before the storm arose. We’ll travel, work in offices and buy too many unnecessary things, just as in the past. At the global peak of the pandemic, greenhouse gas emissions were down about 17% from the equivalent period in 2019. But in China, the world’s biggest carbon polluter, emissions were back to pre-COVID levels by May 2020. The rest of the world will probably follow quickly.

Is this sufficient reason to be pessimistic about the long-term climate effects of the pandemic? Not necessarily. The impact on greenhouse gases will be principally felt through indirect repercussions to the world’s economies, not through the changes directly caused by the disease itself. 

The first such repercussion of the disease is the crushing rise in unemployment, particularly amongst the younger and less-skilled members of society. Governments have begun to react to this, usually by stepping up investment programmes in order to provide jobs. In many countries, such as Germany, new capital has been carefully directed towards the green sectors of the economy. For example, €9 billion has been promised to develop hydrogen made from renewable electricity which helps store the energy generated on windy days. In France, the activist group WWF and consultants Ernst & Young combined to argue that a green restart to the economy might result in one million new jobs. Most of these will be concentrated in building renovation work and in renewables. 

 It makes good sense for governments to push their money into these sectors. A recent report highlighted the greater impact on jobs of investment in the green economy. It estimated that every $1m of support from public funds would add almost eight new jobs in green industries, such as housing refurbishment, compared to less than three in the rest of the economy.

The second indirect repercussion of the disease will be a wish to dismantle complex international supply chains and move business back to individual countries. Local self-reliance, whether in food, energy or medical drugs will probably reduce emissions. Not only will the carbon costs of shipping and aviation be reduced but - more importantly - the CO2 arising from local manufacture will be more carefully monitored and controlled. 

A further consequence of the virus will be increased confidence about the feasibility, and desirability, of a rapid energy transition. During the worst days of the pandemic, electricity demand was down more than 25% in some nations. Countries in which a large percentage of supply arises from intermittent renewables, principally solar and wind, were understandably concerned about the stability of the grid as fossil fuels were pushed out of the electricity market. But electricity supply remained stable and resilient almost everywhere. This has improved our confidence that renewables will be able to provide larger and larger portions of energy requirements. Moreover, many large companies, such as Iberdrola in Spain, have noted the resilience of the grid and accelerated their plans for investment in wind and solar.

At the beginning of this article I suggested that the disease will have little direct effect on the energy transition. I think there is one exception to this conclusion. A consequence of the restrictions on travel was a striking improvement in inner city air quality. City mayors want to avoid going back to the levels of pollution prior to the pandemic. Particularly in Britain, they also seek to encourage walking and cycling to reduce obesity, which has had a profound effect on the severity of the illnesses experienced by COVID victims. My guess is that only significant policy change arising from the pandemic will be a rapid growth in car-free areas, reclaiming our urban centres for pedestrians and cyclists. 

Human beings focus on highly visible events, such as the emptying of the airports after COVID, and wrongly assume that they are illustrations of wider trends. Single battles, even those as profound as the struggle against the pandemic, are as nothing compared to the longer war against climate breakdown. In a year’s time my guess is that we will find it difficult to quantify the direct impact of COVID on emissions. Nevertheless we are gradually beginning to flatten the curve of greenhouse gas growth as renewables become ever cheaper and companies around the world finally begin to take full responsibility for their impact on the atmosphere.

Key figures from the winning Hollandse Kust (Noord) offshore wind farm bid

1, The Nederlandse Kust (Noord) offshore wind site sits 18.5 km off the northern Netherlands coast. It is split into two parts.

2, In total, it covers 125 km2.

3, Kust (Noord) will contain 69 turbines with a capacity of 759 MW. (Some sources say 769 MW). The Siemens Gamesa turbines are 11 MW in size.

4, Power output is expected to be at least 3.3 TWh per year. (Some reports omit the words ‘at least’ or say ‘about’). 

5, It is expected to be operational in 2023. The winning bid was announced on 28th July 2020.

6, It will deliver part of its electricity to a hydrogen unit in the port of Rotterdam. The electrolyser is said to be sized at 200 MW.

7, No subsidies are payable. The winning bidder was selected on the basis of qualitative factors. (‘A beauty contest’ in English jargon). I suspect that the government authority that awarded the Shell/Eneco consortium with rights to develop the area may have been swayed by the commitment to use part of the output to make hydrogen.

8, The Netherlands plans to produce 16% of its electricity from offshore wind energy by 2023 and increase this to 40% by 2030. Total current electricity consumption is about 115 TWh a year. 

Resulting numbers

a)    MW capacity per km2 = 759/125                                            = 6.07 MW/km2

b)    Hectares per MW = (125*100)/759                                        = 165 Ha/MW

c)     Annual output per MW = 3.3*1000/759                               = 4.35 GWh/MW

d)    Annual output per km2 = 3.3*1000/125                                = 26.4 GWh/km2

e)    Watts of output per m2 = Convert 3.3 TWh to Watt hours and then divide by the number of hours in the year and the number of sq metres in 125 sq km = 3.01 watts/m2

f)     Capacity factor = 3.3 TWh/759 MW divided by numbers of hours in a year. = 49.0 %

g)    Share of total national electricity use = 3.3TWh/115 TWh  = 2.9%

Sources: 

https://windeurope.org/newsroom/press-releases/combined-offshore-wind-hydrogen-project-wins-dutch-hollandse-kust-noord-tender/ (press release)

https://www.offshorewind.biz/2020/05/07/shell-and-eneco-jointly-submit-hollandse-kust-noord-bid/

How much space will a 100% renewables UK require?

An energy future dominated by renewable energy will require large areas of land to be devoted to solar and wind farms, both onshore and offshore. Some people, such as the late David MacKay, think that this poses substantial challenges. A recent article in the Financial Times also quoted an estimate that 23,000 sq km of land (almost 10% of the UK’s land area) would be needed just to provide the energy to replace oil.[1]

This article provides an estimate of land and sea areas of the UK needed to provide all the country’s energy needs, not just electricity. Much of the electricity will be directly used but large percentages will be devoted to making hydrogen, both to be used directly but also to be converted into synthetic hydrocarbons, such as aviation fuel. 

It assumes the electricity is provided by these extra capacities[2]:

Offshore wind             -           250 gigawatts ( in addition to about 10 GW in August 2020)

Onshore wind             -           120 gigawatts ( +about 14 GW in August 2020)

Solar                            -           250 gigawatts (+ about 13 GW in August 2020)

This renewables fleet would require approximately these areas

Offshore wind             -           41,000 sq km

Onshore wind             -           30,000 sq km

Solar                            -             5,000 sq km

These figures represent the following percentages of the maximum available area

Offshore wind             -           5.3% of the UK’s EEZ[3]

Onshore wind             -           12.5% of the UK’s land area

Solar                            -           2.1% of the UK’s land area.

The calculation 

 The UK currently uses about 1873 terawatt hours (TWh) of energy each year.[4]

Oil                                 -           756 TWh

Natural Gas                 -           872 TWh[5]

Coal                              -           59 TWh

Electricity from non-carbon     -           186 TWh (renewables, nuclear, hydro, imports)

 Full decarbonisation requires us either to continue using fossil fuels but to capture all the resulting CO2 or to move all our energy needs to renewables. I believe that this second strategy is cheaper and easier to achieve. The rest of this article analyses this route and estimates the capacity of renewables that we will need and how much land and sea area that this will entail.

How do we move to using renewables as our complete energy source?

Many activities that use oil and gas can be easily transferred to electricity. Personal cars, for example, can shift to batteries while much domestic and other space heating can be carried out by electric heat pumps. Other energy uses, such as aviation, cannot be switched to using electricity, despite what the airlines sometimes tell us. In these cases electricity will need to be used to make hydrogen using electrolysis. This hydrogen will either be employed directly, to make steel for example, or will be used to provide the critical component in the manufacture of synthetic hydrocarbons.[6]

 To summarise: we can use electricity as the raw material for all energy needs

·      As electricity itself, usually to power an electric motor

·      As the energy source for making hydrogen, either to be used directly as the energy source;

·      Or as the critical ingredient in the manufacture of synthetic fuels.

Renewables in combination with hydrogen can do almost everything fossil fuels can do. An energy strategy based on huge amounts of renewables, combined with turning excess electricity production into hydrogen is therefore possible.

Calculating how much electricity we will need to replace fossil fuels.

The UK uses three principal fossil fuels: coal, oil and gas. The government data on the consumption of each fuel gives figures for how each is used. In the case of oil, it is employed to make vehicle fuels, aviation fuels and plastics, among other uses.

In the case of each specific use for each category of fuel I have taken the figures from official statistics to estimate the electricity equivalent. 

·      Domestic cars, for example, required about 22 million tonnes of oil in 2019. The energy value of that oil was equivalent to approximately 256 terawatt hours. However a car is a very inefficient converter of the energy in oil into motion. Over three quarters is wasted as heat. So my calculation (which probably needs refinement) is that domestic cars might only use 67 terawatt hours of electricity to charge and drive. This is an example of a direct switch from a fossil fuel to electricity.

·      Many commercial vehicles will also use batteries but expert opinion suggests that some bigger trucks will need to use fuel cells as the power source. In this case, they will use hydrogen, made from electricity, which the fuel cell will convert back into electricity to drive electric motors. Because of the substantial conversion losses, this will require us to generate much more original electric power. This is an example of the second category of switch: movement from fossil fuel to hydrogen

·      The third category of switch is the replacement of a fossil fuel with a low-carbon synthetic equivalent. Aviation fuel will be made using electricity to make hydrogen which will then be combined with carbon molecules in relatively simple reactions to make long chain hydrocarbons that chemically identical to conventional fuels.

In each of 23 separate energy uses, I estimate how much renewable electricity will be needed to power the activity. In each case I first make an assessment of what percentage of each category of energy use will move to using direct electricity or hydrogen or synthetic fuels. I then estimate the conversion efficiency of all the processes needed to create the fossil fuel substitute, enabling me to calculate how much renewable electricity will be needed to completely substitute for existing sources.

Adding up all these 23 figures gives me an estimate of the amount of electricity that will be needed to replace all fossil fuel use. It amounts to 1,710 TWh, or just over 90% of existing total energy use. (For comparison, total electricity production today is just over 300 TWh). I was surprised this number was so high. I expected that the efficiency gains of moving to electric cars and electric heat pump heating would significantly reduce total primary energy demand. I had forgotten that other energy uses, such as making synthetic aviation fuel, will be considerably less energy efficient.[7]

Will 1,710 TWh of new renewable electricity be sufficient to cover all the UK’s needs? Not quite. We will still have to ensure that we have enough electric power at all times to provide for all the needs for reliable electricity. Let me explain this a bit more. At the moment, we get about 60% of electricity from low carbon sources. When the wind and the sun aren’t performing, the UK is able to revert to gas generation. Under the route proposed in this article, this will have to stop. 

But we will be needing to expand renewables capacity by approximately 17 fold to get all the power we require. This means that even on relatively dark and still days, we will get enough electricity to cover all the ‘undelayable’ needs for power.[8] During periods of high wind and sun we can convert all the surplus power to hydrogen. Current electricity demand peaks at around 50 gigawatts. But in my estimates we will need over 600 gigawatts of additional renewables capacity so it would have to be a very poor day not to provide today’s levels of power need.[9]

In the hours that renewables do not provide enough ‘undelayable’ electricity, we should plan for it to be provided by gas turbine power stations powered by hydrogen. This is inefficient because it requires us to store surplus electricity in the form of hydrogen (80% efficiency) and then converted back to electricity at times of urgent need in a gas turbine (60% efficiency). I have budgeted just over 100 Terawatt hours of extra electricity from renewables to pay for this inefficiency.

How much space will be needed?

In my simple model we will need a total of just over 1800 Terawatt hours of extra renewable electricity. (This is approximately the same as our total requirement today). We can provide this by a mixture of onshore and offshore wind plus solar power. Each of these power sources has its own space requirement. 

My calculations suggest the following approximate electricity production estimates for these three technologies:[10

·      Offshore wind             -           3.4 watts per square metre

·      Onshore wind             -           1.4 watts per square metre

·      Solar                             -           5.5 watts per square metre [11]

(As background, today’s energy consumption for the UK, in terms of watts per square metre of land area is just under 1. Therefore we would be able to provide all the energy needs of the country by putting just less than 20% of the UK under solar panels.[12] Of course we will probably choose not to do this. 

I guess that the most likely approximate outcome will be as follows

·      Offshore wind             -           250 gigawatts 

·      Onshore wind             -           120 gigawatts

·      Solar                             -           250 gigawatts.

We could decide to use a different balance but this combination gives us the overall amount of electricity we need. As I said in the introduction these figures represent the following percentages of the maximum available area:

·      Offshore wind             -           5.3% of the UK’s EEZ[13]

·      Onshore wind             -           12.5% of the UK’s land area

·      Solar                            -           2.1% of the UK’s land area.

Is this plausible?

·      Offshore wind - David MacKay estimated that the total UK sea area with a water depth of less than 50 metres was about 120,000 sq. km. (50 metres is used as an approximate figure for the deepest water in which fixed foundation offshore wind can be installed). My estimates are that the requirement is about one third of this space. However the demand is actually less than this because some power, possibly huge amounts, can be provided by ‘floating’ offshore wind turbines. There is only one large such commercial installation in the UK today but it is proving productive. The floating wind variant may become cheaper than fixed foundation turbines.[14]

·      Onshore wind – 12.5% of the UK’s land area is probably the most demanding of the three targets. But onshore wind can co-exist with solar and, of course, with conventional farming. It will need to be concentrated in areas close to the coast all around the country, but the results will be best if the focus is on the northern half of the country and the south west of England. It may be that solar and onshore wind should take a larger share of the target to avoid over-crowding.

·      Solar. 2.1% (about one fiftieth) of the UK seems quite easy, but the capacity should probably be concentrated on the south coast and, of course, on all buildings with roofs facing between east and west. (An east facing roof produces maximum power at a different time to one facing west, which is an important advantage of diversity in how solar is oriented). Solar can, of course, be combined with the grazing of some animals. 

The cost

Before counting in the cost of electrolysers, new pipelines and electricity transmission grids, the capital cost of a 100% renewables plus hydrogen economy will be as much as £700-800 billion, or around 40% of 2019 UK GDP. Carried out over 20 years, this means devoting 2% of national income to investment in renewables, or around £40 billion a year. But at the end of the process the UK will have effective self-sufficiency in energy at a reliable and steady cost. Hundreds of thousands, perhaps millions, of jobs will have been created and emissions driven to near zero. Now is precisely the time to do this.

Conclusion[15]

Full decarbonisation is possible using renewables that occupy a manageable fraction of UK land and sea areas. And which provide reliable, dispatchable power.

[1] https://www.ft.com/content/763b96c3-438f-4f5b-b6cb-f94f4dbfbaf2 (Paywall)

[2] Other proportions could be used.

[3] Exclusive Economic Zone

[4] I used the figures from the quarterly Energy Trends for 2019, published as provisional figures in March 2020. https://www.gov.uk/government/statistics/energy-trends-march-2020

[5] Much of the gas is used to make electricity.

[6] I define a synthetic hydrocarbon in this context as a replacement for a fossil fuel. Using hydrogen and a source of carbon (either captured from the air or from the exhaust gases of processes such as cement manufacture), relatively simple chemical engineering can be used to generate products that can function as near-perfect substitutes for oil and gas derivatives, such as petrol or aviation kerosene.

[7] Aviation fuel will be made from electricity which is converted to hydrogen (80% efficiency) and then to hydrocarbons (50% efficiency). So making chemically similar fuel will require input energy of two and a half times the energy value of the aviation fuel used today.

[8] My need for electricity for the lights in the house is ‘undelayable’. On the other hand, charging the car can usually wait for a few hours, or indeed a few days. So we don’t have to have power immediately available to meet all our electricity needs.

[9] Nevertheless, we do need to take into account the need for ‘undelayable’ heating, which is heavily concentrated into colder days in mid-winter. This will significantly raise peak electricity demand.

[10] For information, these are the estimates in David MacKay’s Sustainable Energy – without the hot air. Solar, 10 watts/m2, onshore wind 2 watts/m2, offshore wind 3 watts/m2.

[11] Future advances, such as     the use of perovskite tandem panels may push this up to more than 7 watts). 

[12] This sounds impossible, or at least very difficult. I don’t think it would be. Over 20% of the UK’s land area is given over to unproductive grazing of animals on rough pasture. This is concentrated in Scotland. However the total amount of all grazing land just in England would be almost sufficient to provide the total space required for the UK.

[13] Exclusive Economic Zone

[14] One of the reasons for this is that the North Sea is relatively unusual in having large amounts of space with less than 50 metres water depth. Other parts of the world will largely have to use floating turbines to achieve significant offshore wind capacity. This emphasis will help push costs down. 

[15] The Excel worksheets which provide the backup calculations for this article are available from me. I will try to post them in a freely accessible place as soon as I have tidied them up to make them legible. Many of the calculations are necessarily approximate but I believe the figures in this article are broadly accurate.

BP’s strategy change will leave it producing almost as much useful energy as today

BP announcements this week included a stated intention to reduce its oil production by almost 40% by 2030 at the same time as ramping up to 50 gigawatts of renewables capacity. 

Initially I thought this would mean a significant fall in the amount of useful energy produced by the company. Cutting oil output from 2.6m to 1.5m barrels a day will reduce the world total by slightly more than 1%. And in the little spreadsheets below I show that 47.5 GW of extra renewables will probably only produce about 0.5% of world electricity. Given that oil is globally a more important source of energy than electricity today, I assumed that BP was going to see shrinkage its share of the overall world market.

This may well not be true. Less than 20% of the initial energy value in a barrel of oil typically gets translated into useful actions, such as moving a car. Electricity is much more efficient and up to 90% of the energy value is available via an electric motor. As a result, $50bn of investment in renewables will produce almost as much useful energy in 2030 as is lost by BP letting its oil output decline. 128 terawatt hours of useful energy from oil will be lost by the strategy change while 113 hours of renewable electricity is gained. 

·      The critical assumption in this calculation is the expected capacity factor of the renewables. In a good solar region, PV would produce approximately 25% of the absolute maximum output if the sun shone 24 hours a day 365 days a year. Onshore wind might average 40% in a windy area while offshore wind will go over 50%. BP says it will invest $50bn to achieve an extra 47.5 GW of capacity. This isn’t currently enough to pay for that much offshore wind, so I assume a 50:50 mixture of solar and onshore wind. This would be fundable by an investment of $50bn and an average capacity factor of 32.5%.

This analysis suggests that BP’s output of useful energy will be down by about 7% to around 113 terawatt hours. 113 TWh is about 0.07% of the world’s total current need for energy, or about 1/1500 of the total. In other words, BP will continue to have to invest billions a year to make a truly significant contribution. However we should remember that the vast majority of current needs are provided by burning fossil fuels which captures only a relatively small fraction of the combustion energy. 113 TWh is about 0.4% of world electricity requirements.

What about the value of the output as recorded on the company’s profit and loss statement? 

Crude oil trades for about $46 today; let’s call that $50. (BP’s long term assumption for the oil price is $55). BP refines about ¾ of its output which probably adds about $20 to the value of the product although some of the energy content of the original oil is lost. The cash value of the output it is losing by letting oil production drift down by 1.1 million barrels a day is about $24bn. 

The equivalent number for the electricity output gained is just under $7bn, so the strategy switch will cut BP’s turnover by about $17bn, or around 7% of its annual total. However a billion pounds of renewable electricity is produced with very low operating costs. A PV farm doesn’t need anybody working on it while an offshore oil rig is expensive to service and operate. So the impact on immediate profitability will be much less, provided the price of electricity stays at around $50 per megawatt hour. 

The UK’s flight addiction is paused. The only safe recovery is a synthetic jet fuel revolution

(This article was published in Business Green on June 24th 2020. Many thanks to Ned Molloy for all his help).

The Coronavirus lockdown, including the shutdown of most air travel, cut global carbon emissions a whopping 17% at the peak of the confinement in April, compared to a year earlier.

This pause is a good time to reflect on our “flight privilege”. Astonishingly, more British people took flights abroad pre-crisis than from any other country in the world. If you feel it’s unfair you can’t fly abroad this year, just remember that you’re now, temporarily, in the normal situation for 80% of humanity that has never stepped foot on a plane in their life.

And yes, that’s the 80% that’s probably going to be hit hardest by Coronavirus, and climate change.

So if we are going to start flying at pre-crisis levels at some point, we’ve got to have a real plan for how to do so without adding carbon into our dangerously saturated atmosphere.

Coronavirus has reminded us it’s a good idea to listen to the science. To maintain a safe climate for human habitation, scientists say the world must have abandoned the use of fossil fuels by 2050 or before. Some parts of this transition to low carbon energy have an obvious route. For example, we know how to get to zero emissions from electricity production and road transport. 

But what about flying? This month the largest yet electric plane made a successful half-hour flight - but it was still tiny, with room for nine passengers only.  Longer flights, carrying hundreds of people, will need to be powered by energy-dense liquid fuels for decades to come. 

Investment in zero-carbon aviation fuels then, is the most important measure of much airlines care about climate change, and on that measure, during the last 10 profitable years for the airline sector, the answer is - almost zero. Now that airlines are in crisis, and receiving huge sums of public money, it’s time to fundamentally rethink the business model. Building a new industrial sector around zero-carbon aviation fuels is an obvious target for a green stimulus.

The development of climate-safe aviation fuel is undoubtedly a challenge. Nevertheless, it is technically feasible and well within the competence of the UK’s universities, our innovative young companies and chemical engineering industries.

Research work at the moment focuses on making fuel from wastes such as plastics or wood chippings. This route is a dead end, because thevolumes of aviation fuel required around the world (around 7 million barrels per day, pre-crisis) dwarf any available source of waste. 

A different route is necessary, making carbon-neutral fuel in a anindustrial process that does not require use of scarce materials. Is this even possible? Surprisingly, yes, it’s been done already. We can make chemically equivalent versions of jet fuel by combining hydrogen produced from water via a process called electrolysis, and carbon dioxide captured from the air or from industrial processes such as cement making. If the hydrogen is made using renewable electricity, and the CO2 is sucked from the atmosphere, this synthetic aviation fuel adds no carbon to the atmosphere, and is compatible with the UK’s ‘net zero’ target.

This is not speculative science on a blackboard. The reaction of hydrogen and carbon atoms to make complex hydrocarbons occurs in a process called “Fischer-Tropsch”, that was invented in Germany almost a hundred years ago. We are able to employ well understood rules of chemicals production to make hydrocarbons that are almost exactly the same as those made from fossil oil.  In fact, they will be better because they contain no sulphur or any of the other unwanted materials contained in fossil fuels, and will cause far less pollution from ultra-fine particles.

So we’re not “waiting for a breakthrough” - we face a large engineering project. Decarbonising aviation requires mass manufacturing of hydrogen using electricity generated from renewable sources, the capture of carbon dioxide at the lowest cost, and the building of large Fischer-Tropsch refineries that can produce millions of tonnes of fuels a year. Although small groups of companies in Germany, the Netherlands and elsewhere have begun to develop integrated plants that can make this carbon-neutral synthetic aviation fuel, the field is still wide open for the UK to dominate.

At present, synthetic fuels are more expensive that fossil equivalents. One estimate is that the cost is equivalent to oil at $100 a barrel, even in regions where cheap hydrogen can be made.[1] However the only way to bring these costs down sharply is to scale up production. The UK’s task is to establish a synthetic fuels industry to capitalise on what will become a multi-billion dollar global industry. ITM Power, a Sheffield company, is already a world-leader in making hydrogen from renewable electricity. Several UK businesses, such as C Capture in Leeds, have expertise in CO2 collection. 

What policies do we need to push the development of carbon-neutral aviation fuels? I suggest four: tax, regulation, subsidy of the first commercial plants and new research. Firstly, fossil jet fuel is currently free of any tax and the first change should be a levy that pushes its cost per litre at least up to the level of petrol. (There are barriers in international treaties but the global interest in imposing fair taxation on aviation is probably at an all-time high). Secondly, regulation to mandate the airlines use a small but growing percentage of zero carbon fuel, copying Sweden and Norway.. The immediate boost to the UK synthetic fuel industry would be enormous. 

Thirdly on subsidies, use some of the revenue from taxing fossil jet fuel to run competitions to develop commercial-scale Fischer-Tropsch refineries that use zero-carbon hydrogen and captured CO2. The industrial infrastructure is there to build these refineries today, and sufficient government support will rapidly bring low-carbon aviation fuel to market. Importantly, the scale of the eventual market for low carbon fuels would mean that the oil majors would pitch for these funds. It gives them a route away from fossil fuels. Lastly, it makes sense to direct research funding towards this sector, particularly because it fits the UK’s existing skills in chemical engineering.

It’s not going to be easy. But the world has no alternative to synthetic fuels if we want to continue to be able to fly. The UK’s green stimulus should include all four of the above measures, to speed up the development of this potentially vast new industry. 

Chris Goodall’s new book is called What We Need To Now – For a Zero Carbon Future

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