Thames Water will end up as a publicly-owned company

Thames Water

I spoke yesterday (Wednesday April 3rd) to Ruth Williams of Utility Week about the probable outcomes of the current debacle at Thames Water. I hypothesised that the financial challenges facing the company were so severe that it would inevitably end up in public ownership. The resulting article is here.

I’ll attempt to provide the detailed numbers in this note to justify this view. But first I’ll try to give some background.

The context.

Yesterday’s Utility Week conversation follows an interview last year when Ruth talked to me about the first attempt by private equity to gain control of a UK water company. This was in 2001/2 and involved Southern Water. I was then an independent member of the UK’s Competition Commission, now part of the Competition and Markets Authority. The Competition Commission was charged with examining water industry takeovers to ensure that Ofwat’s ability to regulate the industry was not impacted.

The Commission’s view was that the transaction should be permitted. I strongly disagreed. I was obliged by the Commission to focus my statement of dissent on technical matters that revolved around the loss of a separate water company as a result of the proposed deal.

If the transaction took place, Ofwat would then have a slightly reduced ability to compare the relative performances of the 22 water suppliers in the UK when setting prices. The regulatory framework obliged Ofwat to penalise relatively poorly performing companies by obliging them to reduce their prices in relation to those water businesses doing well on measures such as leakage rates, investment levels and water quality. This is the focus of the first pages of my dissent.

But my material on the loss of an independent competitor was a façade. My real concern, expressed forcefully but completely ineffectually within the Commission, was that the highly leveraged financial structure of the proposed takeover would make regulation impossible. I was allowed to mention this concern but only in an appendix to my dissent. Twenty years ago, the Commission had a view that the methods of financing of takeovers would have no impact on the acceptability of a merger.

This appendix was then redacted for 20 years before FOI requests obliged the Competition and Markets Authority to make the full version available here:

The Appendix can be found at page 11 to 18 of the full note.

 It is not a particularly clear summary of my thinking but paragraph 6 makes the core point: regulators cannot regulate highly leveraged businesses if price controls would force them into bankruptcy.

Put simply, my question is this: how can the regulator use price reductions to force companies to generate efficiency gains if by so doing he makes these companies unable to finance the operation of their business? As I say below, a highly geared and sophisticated capital structure is likely to reward shareholders handsomely if the business does well. If it does badly, the most likely outcome is a renegotiation of the price regime. English and Welsh water businesses will need new capital for decades to come. If the regulator does not revise his price caps, capital investment programmes will suffer. In my opinion, he therefore has little choice but to give in to the demands of water businesses that need to deliver high levels of regular financial return to outside investors, banks and bond holders.

This is exactly what we are seeing today. Highly indebted Thames Water teeters on the edge and demands price rises of 40% in real terms (said to be 56% in nominal money) before 2030. Faced with this request, the options facing Ofwat are all deeply unattractive.

The current position

First of all, I need to say that I have rounded all the following numbers to aid comprehensibility. I don’t think there’s any detriment to the arguments. Most of these figures come from Thames’ latest half year report, multiplied to cover a full year. This report is available here.

1, Water companies, as with all ‘grid’ operators such as gas and electricity transmission companies and communications networks, have very high ratios of capital stock to yearly revenues.

o   Thames Water has annual revenues of about £2.5bn a year. The capital employed in the business is around £19bn, or almost eight times as much.

2, Some water companies have financed their capital stock using money borrowed from outside lenders.

o   Thames has borrowings of around £16.4bn. (It states it has a gearing ratio of under 80% (page 5) which is slightly inconsistent with this number and my assertion quoted in the previous paragraph that it has £19bn of capital employed).

3, Although water companies make good margins on sales, the free cash flow after paying interest on debt may be small compared to the continuing investment needs of the business.

o   Thames Water is currently investing about £2.1bn a year. This compares to free cash flow of around £1.2bn a year. (page 5) So, even before considering the debt that is coming to maturity this year and for increasing capital investment needs, Thames has a requirement for nearly £1bn of extra outside money.

4, Water companies have large stocks of invested capital, now often financed with external debt. This debt all eventually comes due for repayment.

o   Over the next four and a half years, about £5.4bn of Thames Water debt will come due. (page 10). This will average about £1.2bn a year. Maturing debt is therefore eats up approximately all free cash flow at current customer prices. And this is before any capital investment.

o   Total fundraising needs will include both cover maturing debt (£1.2bn a year) as well as the £0.9bn difference between continuing capital investment (£2.1bn) and the free cash flow available to finance this investment (£1.2bn).

5, Under-investment in the past decades will imply a sharp rise in the capital spending over the next few years in many water company regions.

o   Thames Water is proposing new investment at a much higher level than currently. It suggests a figure of around £18.7bn over the next five year regulatory period (2025-2030) to begin dealing with the enormous problems of waste water processing. This is equivalent to £3.7bn a year or nearly 50% more than total annual revenue. To repeat: Thames wants to invest 150% of its total income, before considering the costs of running its business.

o   Add maturing debt and total fund raising will therefore need to be about £4.9bn a year, or about 4 times current annual free cash flow.

6, Interest payments on water company debt will rise from the low levels of a few years ago to reflect higher interest rates.

 o   Thames Water interest payments have been running at about £360m a year. (I have estimated this figure by doubling the half year number on p9). This seems to exclude what is called the ‘accretion’ of liabilities due on index-linked debt. This would substantially increase the £360m cost but I am unable to estimate by how much.

o   New debt raised at fixed rates, rather than the index-linked instruments that provide about 60% of Thames’s current indebtedness, would cost substantially more. Government 10 year debt currently trades at a yield of around 4%, and I guess Thames would have to pay around 6.5% for a similar maturity. I estimate total fundraising needs will be £1.2bn (maturing debt in point 4) and new investment £3.7bn (point 5) less free cash flow of £1.2bn (point 4). £1.2bn plus £3.7bn less £1.2bn equals £3.7bn. At 6.5% this would cost extra £240m per year less the cost of perhaps £80m no longer payable on the matured debt. This yields a net figures of an extra £160m a year on top of the current £360m.

o   The implication of this is that each year that passes will add £160m to Thames’ interest bill (or index linked equivalent). This alone would absorb about 60% of free cash flow by 2030.

 7, We can assume Thames will be allowed to raise its prices, which will help produce more free cash flow to increase its investment. It is asking for 40% in real terms before 2030.  In the highly unlikely event that this increase flowed directly into cash, it would increase the amount available for new investment by around a billion a year. This does not come close to covering the incremental cash needs specified in point 5.

8, The stream of numbers in this note can be compressed into two assertions:

o   Without very substantial external fundraising Thames Water cannot meet its investment requirements, even if it is allowed to charge very much higher prices.

o   The lack of any sign that Thames will be net cash positive in the next decade makes any form debt financing extremely difficult. Raising new shareholder equity is vanishingly unlikely. So there is virtually no chance of private money continuing to fund even the continuing operations of the company, much less its enhanced investment proposals.

This means that, possibly disguised in some form of ‘special administration’, Thames will inevitably end up in the hands of a state entity. This will cut the interest rates it will pay but it will still require large injections of new cash if it is to improve its dire record in river pollution.

Chris Goodall

chris@carboncommentary.com

+44 (0) 7767 386696

4th April 2024.

Please copy any part of this note if it would be helpful. I’d be grateful for attribution.

Waste oils will not provide substantial volumes of Sustainable Aviation Fuel, despite what Mr Sunak says.

This week the UK government welcomed the first transatlantic flight by a commercial airliner using 100% Sustainable Aviation Fuel (SAF). Prime Minister Sunak said ‘SAF is primarily made of waste oils and fats. … SAF will be key to decarbonizing aviation.   .. It could create a UK industry with an annual turnover of almost £2.5 billion, which could support over 5000 UK jobs’.[1]

Unfortunately, this isn’t correct. Aviation fuel made from waste oil and fats is not zero carbon. Perhaps more importantly, the quantities available for use in the UK and elsewhere are not sufficient to ‘decarbonize aviation’. And published official reports show that the government knows this. The actual share of aviation needs that can be met by these two sources is almost certainly less than 2%, even if these raw materials are entirely used for this purpose, rather than existing uses. Mr Sunak estimates the potential industry value at £2.5 billion but even if all the UK’s waste oil was used for aviation, the size would be about a tenth of this number.

How much waste cooking oil is potentially available in the UK?

In 2013, consultants Ecofys produced a report, then published by the Department for Transport, that estimated that the total volume of used cooking oil (usually called UCO) produced in the UK was about 250 million litres.[2] This figure was taken from estimates produced by the UK Sustainable Biofuels Association and submitted to the House of Commons.[3]

Most of this UCO, then and now, is used to make biodiesel for road use. And not all is collected for reuse. But let’s assume that all the 250 million litres would be available for aviation. Put through the most efficient process, this would turn into about 160,000 tonnes of aviation fuel.

The total current demand at UK airports runs at about 12.2 million tonnes. So UK-sourced UCO could produce about 1.3% of the country’s needs. But, to stress the point, this is assuming that every litre produced was efficiently turned into aviation fuel with no losses. Every single takeaway in the country, every restaurant and catering establishment would have to devote all its UCO to one particular use. Biodiesel and other uses have no access to the UCO even though at the moment, for example, McDonalds uses its own waste oil for biodiesel for its distribution fleet.

What do other government reports say about the maximum availability of UCO?

In 2017, the government’s business and energy department, then called BEIS, asked Ricardo to estimate the real availability of all forms of waste biomass in 2030.[4] (UCO is included as waste biomass because cooking oil is made from oil seeds such as rapeseed).

The consultants reported that the energy value of all UCO available for use was 7 Petajoules (PJ). This was described as ‘the accessible resource in 2030, if no barriers to supply are overcome’. If all these barriers were surmounted, the number rises to 9 PJ.

In an efficient process, 90% of the energy value of UCO can be converted to aviation fuel. That means that the maximum energy available would be 8.1 PJ, equivalent to 2.25 terawatt hours (TWh). The energy value of all the aviation fuel used in the UK is about 145 TWh, implying that UCO could provide about 1.45% of the total requirement if all is devoted to aviation fuel. That’s slightly more than the Ecofys figure of about 1.3%.

What might be the actual amount that the aviation industry could use?

In a consultation document published earlier this year, the Department for Transport made its own estimates of the volume of UCO that could be available for aviation purposes in 2030.[5] It used further work by Ricardo and a body entitled the Aviation Impact Accelerator, a team based at Cambridge University. Most of the external team members of this second body are part of the aviation industry, including Boeing, Rolls Royce and Heathrow Airport. It won’t be a surprise to learn that the Accelerator produces some estimates for availability which are an order of magnitude greater than the figures from the specialised consultants.

The 2023 forecasts developed by Ricardo assume that the UK can devote 3% of all available domestically produced UCO for aviation fuels and also purchase 1% of all internationally produced used oil. These assumptions therefore result in much lower assumed availability. Rather than estimating a total energy value of 2.25 Terawatt hours, it suggests a figure of less than a tenth of this level.[6] This figure is then assumed to fall as the availability of internationally sourced UCO declines. Other countries will need that oil for their own fuels.

 These Ricardo figures, published by the government as the lower bound of its forecasts, would allow only about 0.1% of all aviation needs to be fulfilled by UCO (from the UK and elsewhere) in 2030.

The estimates from the Aviation Impact Accelerator are far more optimistic, largely because it assumes that the volumes of used cooking oil available in the UK will grow. (There is no justification presented for this opinion). This industry body uses the Ricardo UK figures from 2017 for total availability (2.25 TWh for the energy value of UCO produced in the UK) and then almost doubles this figure by 2040. But even under these unrealistic assumptions, the total percentage of all aviation fuel produced in 2030 is no more than around 2% of current needs.[7]

To summarise, if ALL the UK’s UCO was used to make aviation fuel, meaning that other major uses, such as biodiesel were stripped of their share, government data suggests that no more than 1.45% of energy needs could be met. Even adding in substantial growth (which is highly implausible) and some imports only increases that figure to around 2% in the Aviation Impact Accelerator figures.

Would the use of other waste oils change this position?

The UK Prime Minister also mentioned waste oils in his statement. The principal source for aviation fuel today is animal fats derived from slaughterhouses. This is sometimes called ‘tallow’. The volumes are far smaller than for UCO. As importantly, tallow loses more energy in the conversion process to aviation kerosene than does UCO.

The Ricardo 2017 analysis suggests that the total availability of all tallow in the UK is equivalent to about 4 PJ, or 1.1 TWh. After conversion to jet fuel, the energy value might be around 0.4 TWh, or around a quarter percent of the UK’s needs. For reasons which are not explained, the industry-led Aviation Impact Accelerator sees the amount of tallow rising over 50% between 2025 and 2030, even though the amount of meat being eaten in the UK is stable or even falling. The more pessimistic assumptions by Ricardo in its 2023 projections suggest that considerably less than 0.1% of aviation demand can be met by tallow.

What are the implications of this analysis?

For aviation to be fully decarbonised the world will need a mixture of battery aircraft for short trips, some use of hydrogen in medium-sized aircraft and a very large scale replacement for aviation kerosene for long distance travel. Although using UCO is appealing because of the ease of conversion to fuel, the volumes are tiny in the context of the global need. We will need alternatives that offer orders of magnitude more output for full decarbonisation of aviation, even though they are far more complex and costly than UCO. SAF from waste oils is a dead-end.

What are the realistic options for the future? Government reports in the UK focus on forestry residues and municipal solid waste. In the case of wood products, the concern is the risk of deforestation, the lack of available supply and the technological complexity of turning lignocellulosic materials into kerosene. No-one is doing it at scale yet. Municipal waste suffers in addition from a small supply that is likely to decline as recycling plastics becomes more common.

So the answer has to be synthetic fuels, made from hydrogen and direct air captured CO2. This is an early stage industry but is the only conceivable way of meeting aviation’s needs with a low carbon impact. Follow Infinium and Norsk e-Fuel as good examples.

Appendix

The International Energy Agency’s views

It isn’t just the UK which doesn’t have enough waste oils. Here’s what the IEA wrote in December of last year.

Used cooking oil and animal fats are unlikely to provide relief (to biofuel producers), as they are in even higher demand because they offer lower GHG emissions intensity and meet EU feedstock requirements. In fact, the use of used cooking oil and animal fats nearly exhausts 100% of estimated supplies over the forecast period. Even when a broader range of wastes (such as palm oil mill effluent, tall oil and other agribusiness waste oils) is considered, demand still swells to nearly 65% of global supply. 

(From ‘Is the biofuel industry approaching a feedstock crunch’, IEA December 2022.)

And we almost certainly need to fly a lot less. Not least because even the best SAF still releases water vapour when burnt, adding to the global heating caused by contrails.

[1] https://www.livemint.com/news/world/sustainability-landmark-virgin-airlines-takes-off-first-saf-based-flight-rishi-sunak-calls-it-very-exciting-11701242225845.html

[2] https://assets.publishing.service.gov.uk/media/5a74ebade5274a3cb286840c/ecofys-trends-in-the-uco-market-v1.2.pdf

[3] https://publications.parliament.uk/pa/cm201012/cmselect/cmenvaud/1025/1025vw08.htm

[4]https://assets.publishing.service.gov.uk/media/5a7f9007e5274a2e87db69a8/Biomass_feedstock_availability_final_report_for_publication.pdf

[5] https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1147351/uk-sustainable-aviation-fuel-mandate-consultation-stage-cost-benefit-analysis.pdf

[6] The exact figures are not given in the report and I have estimated this number from Figure 5.

[7] Once again, I should stress that the government report does not provide the precise figures and I am estimating the percentage from Figure 5.

The increase in capital investment required for the energy transition

Almost every week a new report quantifies the investment needs for part of British infrastructure. Without unfailingly consistency, the researchers specify requirements for large numbers of billions of pounds to modernise energy, transport, water supply or similar sectors. Strikingly, these figures are never put into context. We are not told whether the additional capital investment represents a large or a tiny fraction of GNP, nor how they compare to other countries. It’s time to change this.

This article is an attempt to pull together some of the estimates contained in the recent analysis from the UK’s National Infrastructure Commission and compares these figures with the total investment volumes in the British economy, with international averages and with comparable figures, particularly as regards energy, that have been produced by other sources. It concludes by suggesting that, if carried through, new capital going into energy will require allocation of at least 1.5% of GDP. But other sectors will also need major injections and the rebuilding of the British economy will absorb at least 5% of national income over the next decades. This is a major - and unremarked - shift in the structure of the economy but the growing evidence of inadequate capital spending across the UK makes the investment increasingly urgent.

The data

The UK currently puts about 18.4% of its national income into capital investment across the economy.[1] This includes such things as the purchase of machine tools or robots for a factory, the construction of new houses or transmission masts for mobile phones.

18.4% is low compared to most countries. The average in the EU is 21.6%, about 17% higher than the UK.

UK GDP was around £2,500 billion in 2022.[2] Investment therefore ran at about £460 billion in that year.

Most of that money was spent by the private sector. Government investment was approximately 2.8% of GDP in 2019. If this share has remained the same, it represents be around £70 billion in 2022. The OECD average for public investment as a percentage of GDP averages around 3.2%.[3]

·      The estimates of how much extra investment the UK needs for infrastructure: National Infrastructure Commission (NIC) study, October 2023[4]

This study suggests the following requirements for the UK energy system on its trajectory to full decarbonisation by 2050. (A summary table is below).

o   £20-£35 billion a year of private investment between 2025 and 2050 for decarbonisation and increased electricity supply. This seems to cover power generation, transmission and distribution as well as a carbon capture network and hydrogen production, storage and transmission.[5]

o   £5.1 billion of public funding between 2024 and 2030 (7 years) on the Social Housing Decarbonisation Fund to improve insulation standards. This equivalent to about £0.7bn a year.

o   £8.8 billion of private investment, although mandated by government, to install insulation improvements in low income households between 2024 and 2035 (12 years). This amounts to about £0.7bn per year.

o   £28.9 billion of public investment in improving the energy efficiency of public buildings, spread over the 2024 – 2050 period, but with 75% (£21.6bn) spent prior to 2035 (12 years). Between 2024 and 2035, this is £1.8 billion a year.

o   £33.8 billion of public funding between 2024 and 2050 to deliver low carbon heat for social housing of which 35% is spent before 2035 (12 years). This amount would provide about £1.0 billion a year.

o   £41.7 billion of public investment to help subsidise lower income households decarbonise their heat supply, principally by installing heat pumps. 35% should be provided by 2035, implying expenditure of about £1.2 billion a year.

o   Public subsidy of £7,000 per new heat pump installed between 2024 and 2035. The National Infrastructure Commission targets 7 million installations before the end of the period, implying a total subsidy of about £4.1 billion a year.

o   The NIC also recommends a scheme offering the buyers of heat pumps a zero interest loan. The cost of this is not calculated in the report so I use the following assumptions: 5% cost of interest subsidy, an average debt of £3,500, 7 million installations by 2035. This costs the government about £1.2bn a year.

o   To get to 300,000 public EV chargers by 2030, the UK will need about 35,000 new chargers a year. Making the crude assumption that 20% will need to be rapid chargers (50 kW or more at £30,000 installed cost) and the rest slower (7 kW+, averaging £8,000), very approximately the cost will be £0.45 billion a year.

The table below summarises these cost estimates.

Source; analysis and estimation partly using NIC data

Combining both public and private investment, the NIC is suggesting a figure of around £38 billion a year between now and 2035 to transform the energy system. This is approximately 1.5% of national GDP. If achieved, the UK would still sit well below the average investment ratio of EU economies. Public investment, now running at around £70 billion, would rise about 13%, or approximately to the same level as the average for the OECD.

·      Other assessments of how much will be needed in investments in the energy system

 Are the NIC assessments reasonable and well-supported? The data in the report is extremely sparse, particularly on the estimates of £20-£35 billion a year for the transformation of energy supply and storage. For example, there’s absolutely no analysis of the amount of battery storage required or its price. Important questions like the direction of the cost of offshore wind are ignored. So we have considerable reason to be doubtful of the quality of the numbers provided.

One potential check is to make estimates of the money required just for the construction of electricity generation and the improvement of electricity networks. The government targets 50 gigawatts of offshore wind by 2030 and 70 gigawatts of solar by 2035. (Each of these two types of generation have about 14 gigawatts of UK capacity today).

o   The cost of offshore wind. About 5 gigawatts a year are targeted between now and 2030. The cost of offshore wind is about £3m a megawatt at present, implying a total cost of around £15 billion a year. Any onshore wind would be additional.

o   Solar will need to rise by about 3 gigawatts a year. It costs about £700,000 a megawatt in late 2023 if installed on open land. That is about £2 billion a year.

o   National Grid estimates that the amount of capital investment required to connect the new wind farms to the high voltage network will be about $21.7 billion before 2030, or £3bn a year.

These three items add up to £20 billion a year. In addition, there will need to be extensive battery farms, hydrogen production, new distribution infrastructure on the lower voltage grid and many other improvements. These will almost certainly take investment needs up to £35 billion or beyond. So the NIC estimates are probably too low.

·      The other sectors covered by the NIC

Transport and environmental resiliency are the other main sectors covered by the NIC 2023. It estimates that transport improvements will demand £28 billion a year between now and 2050. Much of this cash will need to be spent on the obviously necessary improvements to public transport, particularly in cities.

Environmental resilience, particularly against flood and drought will require £8-12 billion a year from the private sector and another £1-1.5 billion from public funds.

In total, the NIC’s report suggests a need for around £39 billion of private investment each year and approximately the same amount from government. In total, this is over 3% of national income and, if carried through, would take the UK up to around the EU average for investment as a share of GDP.  This looks possible. However inside this total the NIC is proposing an increase in public investment of more than 50% in the next few years, which seems a more challenging task.  

·      Capital needs not covered by the NIC

In addition, we know that several other sectors, such as water supply and treatment, that are not covered by the NIC will also need major additional tranches of new capital. For example, the water companies have bid for the right to invest £96bn over the five year period of 2025-2030, almost double what they are currently investing.[6] The request is therefore for an investment of £19 billion a year, or almost 0.8% of GDP.

Add in other sectors requiring more capital, such health care provision, and the percentage of UK GDP devoted to investment will probably need to rise by at least an additional 5%, adding nearly a quarter to total capital spending. This will be an unprecedented change in the economy, temporarily reducing the amount of money available for immediate personal consumption.  

[1] Source: World Bank, https://databank.worldbank.org/source/world-development-indicators/Series/NE.GDI.TOTL.ZS

[2] Source: House of Commons Library, https://commonslibrary.parliament.uk/research-briefings/sn02783/#:~:text=In%20the%20latest%20calendar%20quarter,£2%2C506%20billion%20in%202022.

[3] Office for Budgetary Responsibility; https://obr.uk/box/international-comparisons-of-government-investment/

[4] https://nic.org.uk/app/uploads/Final-NIA-2-Full-Document.pdf

[5] Data is from page 16 of the report.

[6] https://www.water.org.uk/news-views-publications/news/water-companies-propose-largest-ever-investment

How much money might the UK save by installing more wind power?

Wholesale electricity prices are lower when the wind is blowing hard. This is true across the year. If the UK installs more turbines, there will be more wind power at all times, tending to further pull down the cost of electricity for all.  

How much might electricity consumers benefit if the country added more wind capacity? I looked at the data for the last 12 months and found that just by adding the turbines that are already planned the UK might save over £3bn a year in electricity costs. This calculation is based on the assumption that the relationship over the last year between wind output and wholesale prices persists into the future. Increasing wind capacity still further could add to these savings.

Put another way, the UK government’s net zero rollback, and its reluctance to liberate onshore wind, will cost people money.

The analysis

Across the year, the correlation between wind speeds and power prices is reasonably robust. Why is this the case? If wind power is abundant only the most efficient gas power plants need to operate and they bid into the hourly power auctions at a lower price than the older and less efficient stations. And windy conditions in the UK usually mean that it’s windy elsewhere in Europe, which also helps reduce the prices of electricity coming into the country through undersea connectors.

To give one example, the average price on the Nordpool ‘day ahead’ exchange was £81.6 per megawatt hour on December 30 2022 when wind provided the largest percentage of UK electricity of any day in the last year.[1]  One day later and the price was £130.6 as a result of wind cutting its contribution to little more than half the level of the previous 24 hours.

Wind provided about 26.8% of all UK electricity in 2022.[2] The new turbines already planned would increase that by about 24%.[3] If the wind farms match the productivity of existing turbines, that means the amount of electricity generated will be about 24% higher than today. This will push prices down. My analysis suggests that if the last year’s patterns were repeated the average price of the electricity sold on the wholesale market might fall by 10.5% when these wind farms are complete. Further increases in wind capacity would proportionately increase this saving.

Much of the UK’s electricity consumption is bought and sold on the wholesale market. My analysis uses data from the Nordpool ‘day ahead’ exchange. But large amounts of power are bought and sold via other mechanisms, such as direct power purchase agreements or longer term contracts. Of course the wholesale price of power does not directly affect these agreements. But in the course of time lower ‘day ahead’ wholesale prices will change the price in all contractual agreements.

If all electricity prices fell by the 10.5% estimated in the previous paragraph as the consequence of the planned wind expansion, the eventual reduction could cut the total cost of electricity by about £3.3bn a year. Of course we cannot be sure that the correlation between wind availability and power prices will continue to hold but it is a plausible possibility.

My purpose in calculating these numbers was to quantify the possible beneficial impact from increasing the amount of wind power available on the UK grid. This is a social and a shared value resulting from the private investment in new wind turbines. In addition, there is a gain from the reduction in carbon emissions.

We should put these possible savings in context. The 6.7 gigawatt already-planned expansion in UK wind power will cost private capital about £10 billion, assuming a 50:50 mixture of £1m per megawatt for onshore and £2m for offshore wind. The £3.3 bn saving in wholesale prices as a result of this investment is a profoundly attractive social return (in addition to the private profit return arising from the £10bn spent on expanding wind availability.

Apppendix

These are outline details of the method I used.

 ·      For each day in the year to the end of September 2023, I noted down the average daily price of electricity on the Nordpool ‘day ahead’ wholesale market, expressed in £ per megawatt hour. (To avoid any accusations that I broke Nordpool’s rules by using automatic copying of its data, I took down each number manually).

·      For each of these days, I also noted the percentage of the UK’s electricity that was generated by wind. I used the numbers from the Gridwatch web site, copying each figure from the charts on its main page. (These numbers exclude the electricity generated by smaller wind farms not connected to the high voltage National Grid network).

·      I then divided the year into months because electricity consumption and production patterns vary through the year. And, particularly in the last year, rapidly varying gas costs have strongly affected the price at which CCGT suppliers are willing to supply power into the UK at different times.

·      For each month in the year, I constructed a chart that plots the percentage of power output provided by wind and the average price for each day on an x-y chart. The wind percentage sets the position on the x axis, the average price on the y axis.

·      I then asked Excel to calculate the line of the trend for each month.[4] The equation for the trend line predicts the value of y (the price) dependent on the percentage of electricity provided by wind and a base number that estimates the price if there had been no wind during that day. For example, the equation for January 2023 is y = -£1.6802x + £187.36. This indicates that if there had been no wind on a day during that month the price would have been expected to be £187.36 per megawatt hour. Each one percentage point increase in the percentage of power provided by wind typically reduced the wholesale price by £1.6802.

·      The January 2023 chart is shown again below.

• The value called R2 on this chart is a measure of the closeness of the correlation between the two variables. A perfect correlation, in which y values are 100% determined by changes in the x number produces an R2 figure of 1. A complete absence of correlation results in an R2 of 0. The actual figure of 0.69 for January suggests a moderately strong but not complete link. The average across all months was lower at 0.47, implying that factors other than wind also had substantial effects on the electricity price.

• I then took the average wind percentage for each month (it was 33% in January) and increased this figure by 24%. Why 24%? Because current total wind capacity is about 26.9 gigawatts and an additional 6.7 gigawatts are now planned to be installed, or 24% of today’s total.

• I used the trend line for each month to estimate how much of a reduction in the wholesale price would be obtained by increasing the percentage of electricity that is delivered by wind by 24%. This pushes up January 2023 from 33% to just under 41% of total supply. Using this trend line, the average wholesale price would fall from about £131.9 to about £118.6, a saving of approximately 10%.

• The implication of this number is that the total cost of the electricity supplied in the specific month of January 2023 would have been 10% lower if all the planned extra 6.7 gigawatts had already been installed. The percentage across all the twelve months ranged from 1.1% in May 2023 to 22.2% in the extraordinary month of December 2022 when gas prices reached historic highs. The average across all 12 months was similar to January’s figure at around 10.5%.

• I continued this exercise by calculating how much might have been saved in terms of £ across the year if the extra wind capacity had already been in place. National Grid provides each month a figure for the amount of electricity that flows across its network.[5] We can use this estimate as a way of calculating the savings from having more wind power in the UK by multiplying the amount of electricity used by the prospective savings in £ per megawatt hour. January’s figures would have resulted in a total saving of over £100 million.

• The total cost reductions from having 24% more wind across the 12 month period might have amounted to over £3.3billion, or about £50 per head of UK population. However this figure would have been concentrated in the months of October 2022 to January 2023. The savings in May 2023 could have been as low as £18m, compared to the £billion plus in December 2022. This a reflection of the very low correlation of wind power and wholesale prices in May 2023 compared to the other months.

• The May 2023 (lowest R2) and December 2022 (highest R2) charts are shown below. May was a period of relatively low gas prices by recent standards while December’s were astronomically high. It looks as though wind power has more effect on the wholesale price of electricity when gas prices are elevated. This may mean that if gas prices revert to historical averages the deflationary impact of wind will be reduced.

Next steps and issues with the analysis

• Solar power should be added to the analysis because it also tends to push down the wholesale price of power, particularly on sunny summer afternoons.

• It would be better to split each month into weekdays and weekends to ensure that the different demand patterns are properly reflected in the analysis.

• I should normalise the data to take out the effects of changing gas prices on the wholesale price of power.

• The core hypothesis in this analysis is that wind power, which has no measurable cost to produce, deflates the overall market price when it floods on to the networks. This is highly plausible, but we cannot be sure that further increases in wind power will continue to deflate wholesale prices.

• At some points during very windy weather the UK already has enough renewable electricity to need no fossil fuel power. Gas is still being consumed in order to have a dispatchable power source that can be quickly varied. If we add a lot of new wind power, some of this electricity will have to be curtailed implying it will have no effect on wholesale prices.

  • It could be that the deflationary impact of high winds arises largely because the continental European price of power is being driven at the same time, flooding the UK interconnectors with cheap electricity. If the UK increases its wind capacity this will leave European prices unaffected. In other words, the increase in UK turbines may have less effect on power prices than I am calculating.

  • On the other hand, the most obvious downward effect of high winds on the UK power market occurs when wind supplies more than 45% of electricity needs. Any increase in wind capacity will make those events more frequent and so tend to exaggerate the impact on wholesale prices.

[1] The day ahead contract is the price agreed between buyers and sellers for the delivery of electricity in one hour periods on the following day. This market operates for seven days a week.

[2] Source: National Grid, https://www.nationalgrideso.com/electricity-explained/electricity-and-me/great-britains-monthly-electricity-stats

[3] I’m not sure whether or not this figure includes the wind farms that are currently on hold because the developers are unsure whether to proceed after facing much higher costs. I’m assuming that the wind farms waiting to be built are equally productive as the existing stock of onshore and offshore turbines. This is probably a pessimistic assumption since turbines are becoming larger and generate more electricity.

[4] Using linear regression.

[5] This is not a perfect proxy for the actual amount of electricity produced. Some electricity, such as that delivered by solar farms and small wind farms, does not travel on the National Grid high voltage network but stays on the local lower voltage distribution systems.

Building the infrastructure for low carbon steel

Most of the largest European steelmakers are planning for the conversion to the use of hydrogen rather than coal. This article looks at the efforts of Salzgitter, the second largest German manufacturer, to decarbonise its production capacity. The rapidly developing plans involve the construction of ‘direct reduction’ furnaces, electric arc furnaces, the supply of hydrogen and the purchase of higher quality iron ore from Canada.

By 2025 Salzgitter intends to have an output of 1.9 million tonnes of steel made using hydrogen. Its total production at the moment is about 7 million tonnes. (World production of steel, mostly in China is just under 2 billion tonnes). Salzgitter’s full conversion to hydrogen and electric arc furnaces is planned by the mid 2030s.

Direct reduction using hydrogen

Most new steel (‘primary’ steel, not scrap metal recycled in an electric arc furnace) is made in blast furnaces in which iron ore is mixed with coking coal. The coal both heats the ore and strips it off the oxygen in the ore, leaving raw iron. About two tonne of CO2 emissions result from each tonne of new iron produced, meaning that steel contributes about 8% of total global emissions.  

Hydrogen can replace coal, dramatically reducing CO2 output from steel production. The process is called ‘direct reduction’ of iron or DRI. We know DRI is highly likely to work because a very similar process is used in some parts of the world, including India and Iran, that uses syngas (H2 and carbon monoxide) made from natural gas. Almost 40 projects in Europe are now planning to shift to pure hydrogen DRI, which will emit only water. (By the way, there’s been very little progress in the UK compared to the rest of Europe). A DRI plant produces a form of iron, which is then converted to steel in an electric arc furnace.

Salzgitter

Salzgitter makes steel in the town of the same name in Lower Saxony in central Germany, close to Hanover. The business is sited there because of the existence of a local iron ore seam that is no longer mined. The huge furnaces on the site are responsible for about 1% of Germany’s total emissions.

The steel producer began work on low carbon steel making in 2015, testing out hydrogen production made with local renewable electricity. One critical step it took in mid 2022 was to commit over €700 million to the first phase of its full decarbonisation. This commitment was made on the basis that German governmental support would also be forthcoming.  The company’s contribution was eventually upped to over €1 billion.

Recent events

The last few weeks and months have seen an extraordinary flurry of announcements from Salzgitter covering funding, electricity and hydrogen supply and iron ore provision. The planning and preparation for the conversion to DRI have taken sudden leaps forward.

·      Funding. The German government and the state government of Lower Saxony promised around a billion Euros for the first phase of the project on 18th April 2023. The intention is to convert about 1.9 million tonnes of production capacity to hydrogen DRI by the end of 2025. The total cost for this part of the decarbonisation is expected to be almost 2 billion Euros, or about a billion Euros per million tonnes of yearly steel output. (This is roughly equivalent to the expected investment cost per tonne of steel at H2 Green Steel, the new company using hydrogen in northern Sweden). For this money, the owners will get two direct reduction and three new electric arc furnaces.

·      On 20th April Salzgitter and Iberdrola Deutschland announced that the steel company would take the output of 114 MW of Iberdrola’s new offshore wind farm ‘Baltic Eagle’ that is schedule to go online at the end of 2024. The output from these turbines will provide approximately half a terawatt hour of output, which is probably about 7% of the Salzgitter’s first phase needs.

·      Salzgitter and gas distribution company VNG said on 17th April that they were jointly investigating the connection of Salzgitter into the planned European hydrogen grid that will allow production in low cost locations to be brought in a pipeline to the DRI plant.

·      In February, the steel company and Canadian iron ore producer Baffinland announced plans to work together to deliver iron ore to the DRI plant. DRI requires ore with higher concentrations of iron than are typically currently used in most world steel making. Baffinland, partly owned by competitor steel company ArcelorMittal,  has ore that reaches over 66% iron content. The announcement of the cooperation with Baffinland comes after an investigation with the world’s largest ore producer, Rio Tinto, in 2022 that perhaps has concluded that most of its output does not meet the quality required for DRI.

·      In early 2022, Salzgitter and German utility company Uniper agreed to supply hydrogen from a proposed new hub at the port of Wilhelmshaven. This will both use electrolysers to make H2 from offshore wind but also convert ammonia shipped into Germany back into hydrogen. Uniper is also planning a hydrogen-making plant in the port of Rotterdam district using offshore wind electricity that will connect into the European gas grid to supply Salzgitter.

The last few weeks have seen much commentary on the withering of ‘hydrogen hype’ as the difficult realities of conversion become clearer across multiple industries. Salzgitter’s growing commitment to full decarbonisation and the development of a full supply chain for iron ore and hydrogen suggests that at least the steel industry is moving ahead rapidly, probably made more confident by the EU’s Carbon Border Adjustment Mechanism.

Steel is likely to be most important single user of H2, with a probable demand of at least 150 million tonnes a year after full decarbonisation. (Most forecasts see a total need for hydrogen of around 500 million tonnes in 2050, although the total amount used for electricity ‘storage’ is still very unclear).

One concern must persist. Salzgitter is not in the best location for either iron ore or cheap hydrogen. My guess is that, as H2 Green Steel In Sweden says, it will be far better to be in an area with either very cheap renewable electricity – which Germany is not – and close to high quality ore. Once again, German locations fall short. Salzgitter’s inland location creates a further disadvantage.

In any event, government support for the transition is probably vital. The German state and Lower Saxony are putting up about 50% of the required capital investment and most other steel producing countries look as though they expect to fund similar amounts across Europe. Those of us who live in Britain should be deeply concerned at the apparent block on grants to UK steel producers to ease the transition to hydrogen.

Full electricity decarbonisation is possible but the pace is insufficient

On March 9th, the UK’s Climate Change Committee concluded that the UK could meet its electricity needs in 2035 and 2050 with a mixture of renewables, nuclear and what it calls ‘low-carbon dispatchable generation’, plus a small amount of unabated natural gas.[1] It made its positive assessment by studying typical and extreme weather patterns in the past. It then calculated whether the possible portfolio of wind, solar and nuclear envisaged by government targets would generate sufficient power, if combined with some combination of storage, natural gas with CCS, and hydrogen. The conclusion was that the transition is possible, even alongside a 50% rise in electricity consumption by 2035 and a doubling by 2050. But it also said that the current pace of installation was insufficient to meet the targets for decarbonisation.

I wrote some comments in the note below, including a query as to whether the enormous cost (and difficulty) of electricity transmission upgrades is being fully considered. Extra infrastructure may double the cost of the new electricity generation capacity.

 ***

Many energy commentators reacted with enthusiasm to the CCC’s work. The report was seen as a strong signal to the UK government, and to the many sceptics, that a renewables-based system can - very largely - drive unabated natural gas off the country’s electricity grid. And it is indeed a very impressive piece of analysis; its workings are detailed without being obscure.

For the first time, the CCC sees a potentially large role for hydrogen as the key balancing energy source in the electricity system. When the wind is blowing hard, surplus power will be sent to electrolysers where it will be turned into hydrogen. The hydrogen will be stored in salt caverns beneath the ground and combusted in gas turbines when the wind is still.

The CCC leaves the precise size of the hydrogen contribution unclear, saying that the cost compared to natural gas with CCS is not certain. So it merges abated gas and hydrogen into ‘low carbon dispatchable generation’ without being wholly specific about the share of hydrogen. It is also ambivalent about the role of electrolysis versus autothermal reforming of natural gas to make the product.

Nevertheless, for those of us who have been pushing the importance of hydrogen for storage of electricity for several years, this is an important moment. The language of the document is entirely different from a previous 2018 CCC report on hydrogen which concluded 

‘the low overall efficiency of electrolysis and the relatively high value of using electricity as an input mean that the costs of producing bulk electrolytic hydrogen within the UK are likely to be high.’[2]

That language has now completely changed with an acceptance that the role of hydrogen is to take electricity at times when power prices are very low and store it for periods when prices are high. Table 3.1 in the recent CCC report gives a figure of just £22 per megawatt hour for hydrogen production for 2035 (but in 2012 prices).

The world’s most respected climate agency has given the argument for ‘renewables plus hydrogen’ a good chance to break through into the policy mainstream.

Let’s briefly look at the key aspects of the work. This is not to question the main thrust of the conclusions but to examine their implications.

1, The report essentially uses government targets for renewables installations as the basis of its figures. The figures for new capacity are not independently generated.

 By 2030, the UK plan is to have more than 50 GW of offshore wind, compared to about 15 GW today. That means an installation rate of about 7 GW a year, a demanding target. But the CCC appears to use the 50 GW 2030 target as its estimate of 2035 capacity.

For onshore wind, the CCC is much less bullish, assuming 28 GW in 2035, up from about 13 GW today. The implied installation rate is less than 2 GW a year. Even this is probably unlikely unless the UK government reverses its effective ban on onshore wind in England and Wales. Scottish development isn’t sufficiently fast. Solar rises by about 55 GW before 2035, up from about 15 GW today. The estimates for 2050 requirements are 115 GW offshore, 31 GW onshore and 105 GW of solar. 

2, Because this is the stated government view, the critical assumption that the CCC has had to run with is that new nuclear will become an important part of the UK’s portfolio. By 2050, the estimate used is for 24 GW of operational nuclear, which will cover about a third of the UK’s total electricity need. 10 GW is assumed to be available in 2035.

Is this likely? No, it is not. Sizewell B will probably decommission that year, the last existing nuclear plant in the UK. Hinkley Point C, possibly to be completed mid-decade, has a capacity of 3.2 GW. So two more new nuclear plants will needed in the next twelve years. One has to be a blind optimist to believe that this is possible. And, of course, the price will probably be more than twice than that for wind or solar.

The likelihood is that the UK will construct no more than a couple of new nuclear plants. The key implication is therefore that we will need more wind and more solar than the CCC says. Very roughly, the likelihood is that instead of 115 GW of offshore wind, about 150 GW will be needed. The key effect on the CCC’s arguments is that because wind is variable, the amount of hydrogen capacity needed for storage will be much more than they predict.

3, The CCC does not extensively deal with the interaction between the EU energy markets and those of Great Britain. This is important, but is unfortunately typical of most official documents across energy and other policy areas. Yes, there is mention of electricity interconnectors but it seems to be assumed that EU countries will accept a large portion of GB surpluses. This is unlikely because at times of UK high winds, most of northern Europe will be similarly harvesting overwhelming yields of electricity. As I write this on Monday 13th February, the UK’s wind is providing over 20 GW of power, while in Denmark turbines are currently giving more to the Danish grid than the entire national electricity consumption.

The modelling behind the CCC work appears not consider this problem, perhaps because of an assumption that other countries will not invest as extensively in new wind capacity. But, for example, the Netherlands government has a target of 70 GW of offshore wind by 2050, a figure that would provide almost three times the current Dutch power needs over the course of the year. Netherlands producers will be wanted to export at exactly the same time as UK wind farms. As far as I could see, there was no mention of this in the entire CCC report. Other northern European countries also have major (and well-documented) strategies to expand offshore wind.

4, There are similar problems with the discussion of hydrogen interconnectivity. Although there is mention of pipelines in the CCC report, there seems to be an absence of consideration of the effect of the development of a full European hydrogen network. Moving energy around in pipelines, even over several thousand kilometres, is very much cheaper than using electricity networks. (There is a good reason why UK domestic electricity bills have a charge of transmission and distribution that is four times the fee for gas per kilowatt hour!). If we need more hydrogen, the cheapest way to get it will probably be through the proposed EU pipeline system, probably partly fed from northern European wind and hydro and north African solar. The UK energy system – both electricity and hydrogen – will almost certainly be very much more tightly integrated with Europe than the CCC suggests. Once again, one presumes this is because wider UK government policy does not want to acknowledge the utterly central role of links to the mainland (and Ireland) in our energy policy.

5, The CCC mentions extensively, but does not fully quantify, the striking requirements that the UK has to improve its electricity transmission and distribution systems in order to make the ‘renewables plus hydrogen’ transition possible. This issue needs urgently to be bought to the forefront of our discussions. As with many other European countries, the development of new electricity resources, and the electrification of heating and transport, is being impeded by the lack of capacity in both high voltage and low voltage segments. The unrecognised reality is that upgrading our infrastructure may cost as much as the whole of the extra renewables installations in the period to 2050. And, unfortunately, much of the required investment will have to be made well before the new capacity comes on line. Which will mean businesses and families paying for the full transition soon, and before the majority of the benefits show. By the way, this problem affects most other advanced countries as well.

The tables below show some indication of the scale of the challenge facing supporting infrastructure by comparing the cost of new renewables to the cost of new electricity transmission and distribution. I have had to use estimates for many of these calculations but I think they are broadly correct. My logic is in the appendix below.

 The cost of new renewables to 2050

 a)    Offshore wind at £1.5billion a gigawatt = £150bn

b)    Onshore wind at £1 billion a gigawatt    = £18bn

c)     Solar at £0.5 billion a gigawatt               = £45bn 

Total                                                                     = £213bn

The cost of supporting infrastructure

 a)    Distribution networks (i.e. DNO spend) = £60-180bn (source page 66 CCC report)

b)    Transmission network (i.e. ESO spend)  =

·      Offshore wind at £0.6 billion per gigawatt = £60 bn

·      Onshore wind at £0.3 billion per gigawatt = £5.4bn

·      Solar at £0.2 billion per gigawatt                 = £18bn

Total                                                                       = £143.4 - £263.1bn

Under some projections, the cost of infrastructure upgrades to allow full use of renewables will therefore exceed the cost of the installations themselves. The unfortunate implication is that the Levelised Cost of Renewables infrastructure may approximately double the cost of the electricity produced by these installations. That is a very tough conclusion for those of us who want a rapid transition.

 Appendix.

The cost of renewables is taken from recent figures published about very large scale projects, slightly reduced to take into account likely cost cuts over the next decade.

The cost of distribution (essentially the low voltage networks that take power to buildings) is taken from the CCC report.

The cost of transmission infrastructure is calculated from a recent Ofgem estimate that the cost onshore of putting 50 GW offshore in place by 2030 is about £21bn. See the summary by lawyers CMS at https://cms-lawnow.com/en/ealerts/2023/01/accelerating-onshore-electricity-transmission-investment-a-step-forward-for-low-carbon-generation.

 Onshore wind and solar will require less investment in transmission per gigawatt. Many schemes will actually connect to the distribution system, not the National Grid. I have roughly estimated a figure of £0.3bn per gigawatt for wind and £0.2 per gigawatt for solar based on the offshore numbers.

[1] https://www.theccc.org.uk/2023/03/09/a-reliable-secure-and-decarbonised-power-system-by-2035-is-possible-but-not-at-this-pace-of-delivery/

[2] https://www.theccc.org.uk/publication/hydrogen-in-a-low-carbon-economy/

Copying the Danish scheme for paying householders after a new turbine or PV farm is installed locally

People in Denmark living close to a new wind turbine or solar farm receive a yearly payment. In most cases, the amount corresponds to the value of the output of 6.5 kilowatts from the new renewable generator. I think the UK should consider a similar scheme here, but probably more generous - to increase local support for wind and solar power. We need to rapidly unlock the exploitation of the country’s fabulous coastal (and some inland) wind resources.

Details of the Danish scheme (full text at bottom of page)

·      Any household living within 8 times the height of a wind turbine or 200 metres from the nearest solar panel is eligible. The average new onshore turbine (measured to the highest tip) is likely to be around 100 metres, implying a qualifying distance of up to 800 metres.

·      Each household is awarded the value of the output of 6.5 kilowatts both for solar and wind.

·      The maximum proportion of the output of the wind or solar site that can be paid to local householders is 1.5% of the total. In the event that 6.5 kilowatts multiplied by the number of eligible homes would exceed 1.5%, the value of the payment is cut proportionately so that the total does not go over this limit.

• Householders have to apply for the payment.

What would be the implications of this scheme if used in the UK?

·      6.5 kilowatts of wind power is likely to produce about 19 megawatt hours a year on a reasonable site close to a coast. (33% capacity factor assumed). At a value of £60 per megawatt hour, the payment would be about £1,100 per year.

·      6.5 kilowatts of solar power should achieve slightly more than 6 megawatt hours a year on the coasts or in the southern part of England. (11% capacity factor assumed). This would generate a payment of about £375.

Of course, the numbers in March 2023 would be much larger because of the unusually high prices for wholesale electricity. They might be double these levels.

Would the cap of 1.5% of output typically come into play?

·      A new onshore turbine installed in 2023 might have an maximum output of 4 megawatts. Therefore the 1.5% maximum would be 60 kilowatts, meaning only 9 households could benefit before the annual payment was scaled back.

·      A solar farm typically could have a capacity of 10 megawatts. This would allow 23 households to benefit before proportional cuts were made.

What changes might make this work for the UK?

We know there is broad support for wind and solar, even if it is developed in the immediate proximity. The UK government has just published its latest opinion survey on the topic.[1] This shows that only 12% would be unhappy about a wind farm in their local area and 7% similarly opposed to solar. (However these figures may be slightly inaccurate because some respondents said that a solar or wind farm would be impossible in their area and therefore didn’t say whether they opposed them or not). For comparison, only 4% of people are generally unhappy with solar, wherever it is sited, and 11% oppose wind.

My guess  - and of course it is only a guess - is that the payments might need to rise to a maximum of 3% of the revenue of the renewable site and payments be made corresponding to up to 10 kW of capacity. This could extend up to 1km from a turbine and 300 metres from a solar farm.

This would mean that a home in a wind turbine’s area might get £1,700 a year at a ‘normal’ wholesale electricity price of £60. That would be greater than the typical electricity bill. Solar would provide a fee of just under £600.

Perhaps these bonuses would help bring local communities behind new renewables developments. And allow elected politicians to actively support them, rather than almost universally oppose them for fear of the consequences at the next polling date. It might unlock the London’s government’s almost total ban on new English wind.

Most importantly, it would give local people a sense of de facto ownership of the asset. In my experience, nothing promotes wind or solar better than the feeling that every time the sun comes from behind the clouds, or the turbine spins once, a small amount of money has been earned.

[1]https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1140685/BEIS_PAT_Winter_2022_Energy_Infrastructure_and_Energy_Sources.pdf

I am very grateful to my daughter Ursula Brewer, operations manager at solar developer Better Energy in Copenhagen, for informing me about the Danish scheme.

Building a zero carbon aviation industry

Decarbonising aviation is perhaps the most difficult challenge facing ‘net zero’. Earlier this week the UK’s Royal Society, its premier scientific research institution, produced a very useful summary of just how demanding the transition away from Jet A fuel is going to be. I thought a precis might be helpful, along with some comments about what I see as potential errors in the report.

The Royal Society looked at five leading options

·      The use of biofuels, which resemble jet fuel but are made from organic wastes or foodstuffs

·      Using hydrogen as the source of energy for aircraft engines

·      Employing ammonia as the fuel, which requires hydrogen

·      Making synthetic fuels from hydrogen and captured CO2.

·      Continuing to use fossil fuels but mandating sufficient carbon capture from air to balance the emissions.

Perhaps surprisingly, the report dismisses battery-powered aviation on the basis that ‘battery technologies are unlikely to have been developed to give the energy density required for most commercial flights in the timescale available to reach net zero by 2050’. Given the potential speed of improvement in the ratio of battery power to weight, this looks just a little too pessimistic.

The central conclusion of the Royal Society’s work is that all the prospective alternatives will demand either a very large share of the UK’s land area or a multiple of today’s production of renewable electricity. If hydrogen is involved, large amounts of electricity are demanded, if biofuels are used, impossibly large amounts of land are needed.

This is uncontroversial. The UK has – I think – the highest percentage of aviation fuel use to total energy need of any large country. The Royal Society tells us that fuel for flying supplied in the UK has an energy content of 145 TWh, which is almost 8% of total energy use of around 1650 TWh for the country as a whole. This is partly because Britons fly more than almost any other nationality but also because some of the UK airports act as hubs for passengers flying from one country to another.

The context of the report is important. Most energy-using activities such as heating or transport will cause reductions in total energy demand in the UK. For example, a heat pump typically uses much less energy (in the form of electricity) than a boiler burning gas. An electric car is roughly 80% efficient at using energy, or over three times as effective as a petrol vehicle.

Aviation is different. Total energy demand to carry a person a thousand kilometres will certainly rise under all of the Royal Society’s options. In the case of synthetic alternatives to aviation fuel, this is because of the energy losses converting electricity to hydrogen, capturing CO2 and then converting the mixture into a chemically identical replacement for aviation fuel. By the way, the same will be true of long-distance shipping, as with any other energy using activity that transfers from a fossil fuel to a gaseous or liquid alternative.

So as decarbonisation proceeds, total energy demand for heating purpose and surface transport will fall but air and sea energy requirements will sharply rise. That is, of course, assuming that the world and its trade continues to move around as much via aircraft and ship. It is possible to imagine a scenario in which air and sea transport might use a half or more of all energy demand in the UK.

This helps us scale the Royal Society’s numbers. At first sight, their figures for the eventual energy demand from aviation look shockingly high. It suggests a maximum of 660 TWh if all fuel is made synthetically, or over four times the current energy demand. For further comparison, this figure is well over twice today’s total UK electricity consumption or around 300 TWh. But if almost all other demands are falling, the requirements for energy look slightly less intimidatingly large.

Energy requirements (mostly electricity) to make alternative fuels

Total energy required

Current aviation fuels Circa 145 TWh

Hydrogen 207-290 TWh

Ammonia 217-332 TWh

Synthetic fuel 468-660 TWh

Jet A plus equivalent DAC 61-148 TWh

In the case of hydrogen, for example, the Royal Society is suggesting that the amount of electricity required to make sufficient quantities of the gas will be between 207 and 290 TWh, or up to double the energy quantity in the fuels of today. This is because the report assumes that electrolysers to make hydrogen may only offer 50% efficiency. One unit of electricity into the electrolyser will only make half a unit of hydrogen expressed in its energy value.

Other alternative fuels would have even lower efficiency, meaning that the amount of energy inputted would have to be even higher. The exception is the interesting alternative of simply collecting CO2 on the ground using direct air capture to balance the emissions in the atmosphere. According to the Royal Society, this has the lowest additional energy requirement.

Of course many will want to know exactly how this balancing is checked and enforced. However in theory all that would have to happen is that each airlines would report its use of fuel bought in the UK and then buy an equivalent amount of CO2. (Each tonne of aviation fuel results in about 2.5 tonnes of CO2 in the atmosphere).

In addition the analysis looks at how much land would be required to meet aviation needs from a variety of different crops and waste materials. In the case, for example, of rapeseeds, the Royal Society estimates that about 68% of all the UK’s agricultural land would be required to produce sufficient to manufacture 12 million tonnes of jet fuel. Other waste materials could supplement the rapeseed but the conclusion has to be that large parts of the entire country would be needed to satisfy fuel demand.

The Royal Society also compares the potential energy requirements for each of the five options to the current (2020) level of renewables output. Excluding biofuels such as biomass burning at Drax and other power stations and electric generation at anaerobic digestion plants, the report says that the UK generated 86 TWh of renewable electricity in 2020. If the country moved entirely to using hydrogen as the fuel for aircraft propulsion, this number would have to approximately quadruple just to meet airline and existing needs.

The implication which we are supposed to draw is that it will prove extremely difficult to replace fossil aviation fuel with either substitutes based on electricity and hydrogen or on biological materials, or both in combination.

Some queries about the numbers and the analysis used.

I certainly don’t want to question the main conclusion of the Royal Society report. Creating an industry which cost-effectively produces a zero carbon alternative to aviation fuel is clearly difficult.

Nevertheless, many of the numbers and analyses in the document do need to be questioned. In general, I believe the Royal Society has chosen numbers that make the transition seem more demanding than it actually is. I also want politely to suggest that the report is cavalier in using unsourced or incorrect figures.

1, Some of the core data is incorrect. For example, the document asserts that the UK’s total production of renewable electricity in 2020 was 123 TWh. The actual number, according to DUKES Energy, the central source for government estimates, was just under 135 TWh.[1] (Please see table 6.2). The Royal Society also suggests throughout its document that the amount of electricity generated by sources not using biomass was 86 TWh. DUKES Energy says that the number was 95.4 GWh.

2, Of much greater importance are the key assumptions about the efficiency of hydrogen electrolysis. The Royal Society uses a range from 50% now to 70% in 2050, giving a government reference for these figures.[2] Unfortunately I could not find these numbers in the government document. However these numbers are far too low. The current estimate of NEL, probably the world’s largest electrolyser manufacturer is over 78% for its most efficient unit.[3] Of course this is a manufacturer’s claim, and needs to be checked, but the percentage is far greater than today’s estimate by the Royal Society. At the lower bound of the report’s estimates, the electricity needed to produce aviation fuel replacements is overstated by at least one third. This affects all the Royal Society’s calculations. And electrolysis can be even more efficient than this if a reliable source of heat is available so that Solid Oxide Electrolysis (SOEC) can be used. In the case of synthetic fuels, using Fischer Tropsch in the manufacturing process produces a high level of waste heat that could be used to give energy to a SOEC.

3, The problem is reversed with green ammonia. Here the Royal Society assumes a manufacturing energy efficiency of greater than hydrogen (71%). But since ammonia is made from hydrogen this is inconsistent with its assumptions about electrolyser efficiency.

4, The report gives figures for the expected energy requirements for making synthetic fuels but it gives no source or other rationale for these numbers. I think the estimates they have used are substantially too pessimistic but one of the tens of companies now in the synthetic fuels industry could have provided robust estimates. LanzaTech, for example, is referred to other places in the document and their figures would have provided some rationale for the low efficiency estimates provided.

In my view there are several other problems with the text and its sources. They range from typos, such as calling the world’s pre-eminent catalyst company Topside instead of Topsøe, through to unsupported assertions, such as saying electrolysers are costly in terms of GHG emissions (they are not).

However the central point is true. The UK, with its high needs for aviation fuel and small land area, is going to struggle to make its own substitutes for Jet A. (Of course, it may be much cheaper to make the hydrogen elsewhere and then import it). But the projected expansion to over 50 GW of offshore wind by 2030 will probably on its own provide almost 200 TWh of extra power. Other energy requirements will also have claims on this new electricity but there is no reason why the UK’s ample wind and solar resources could not provide the energy for fossil fuel substitutes for aviation fuel.

It would be even better if aviation demand fell, not least because the non-CO2 global heating impacts of aircraft are probably as great as the direct effect of burning fuel. We cannot get rid of these problems by substituting hydrogen for Jet A.

[1] https://www.gov.uk/government/statistics/renewable-sources-of-energy-chapter-6-digest-of-united-kingdom-energy-statistics-dukes. Please see table 6.2

[2] https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1024173/Options_ for_a_UK_low_carbon_hydrogen_standard_report.pdf (accessed 31 August 2022).

[3] https://nelhydrogen.com/product/atmospheric-alkaline-electrolyser-a-series/ and https://www.idealhy.eu/index.php?page=lh2_outline for the energy value of a m3 of H2

Will cheap CCS on gas power stations be the best way of providing low carbon electricity when renewables aren't available?

Developing inexpensive capture of CO2 from power stations and other sources is a high priority. So far, progress has been slow at pushing down the cost and increasing the percentage of CO2 that is captured.

A recent US study offered a more optimistic future for CCS.[1]  Researchers at Pacific Northwest National Laboratory developed a new technique and then did detailed modelling of how much a large scale plant attached to a power station would cost per tonne captured.. Their estimate – around $40 a tonne of CO2 for a coal-fired power station – is probably the lowest figure offered by scientists working in this critical field. Other forecasts have generally been more than $70 a tonne for gas-fired plants and slightly lower for coal.[2]

This note looks at the possible implications of the proposed approach for the future of carbon capture. It suggests that even at these very low carbon capture prices it may still be cheaper to use hydrogen rather than natural gas for making electricity.

This is a complicated piece of analysis, meaning that there are probably mistakes in the workings but, very roughly, hydrogen costs of $1.55 per kg in the US will compete with natural gas and this form of cheap CCS at 2021 prices. In the UK, the higher gas price implies that hydrogen is competitive at around $2.60 per kg. These prices are attainable within a few years and US support may mean that hydrogen is already competitive with natural gas if CCS and carbon pricing is included.

Low cost CCS

PNNL has been working on solvent development for more than a decade and proposes what appears to be a new class of CO2 absorbing chemicals. These solvents, CO2 binding organic liquids or CO2BOLs, require much smaller amounts of water to capture the gas.

The benefit of this is that far smaller amounts of energy are required to ‘boil off’ the CO2 after it has been captured. It can then be permanently stored, perhaps in a geologic formation. Other techniques may require as much as a third of the energy of a power plant to be devoted to separating out the carbon dioxide from the solvent once it has been captured.

The approach which PNNL has modelled in detail (but which has not yet been built at commercial scale), calls for the creation of a very large metal box. The CO2BOL is dropped in streams from the roof, at a rate of up to 4 million litres an hour or about 4,000 cubic metres. The flue gas enters the chamber at the bottom and rises, encountering the falling liquid which absorbs a very large fraction of the CO2. The liquid is then extracted and heated to remove the carbon dioxide.

The PNNL researchers say that their work suggests a need for a plant costing about $750m to capture the emissions of a substantial coal-fired station, which might be several million tonnes of CO2 a year. They claim potential capture rates of 90%,

In addition, the carbon dioxide must be transferred by pipeline to a point at which the gas is then piped into permanent storage. US government research estimates that the storage cost across much of the country is as low as $10 a tonne. (This seems to exclude the pipeline transmission cost, which will not be large in most circumstances).

The total costs of the full CCS process will be about $39 for the capture, $10 for the final storage and perhaps $3 for the transport to the well per tonne of CO2. This adds up to $52 a tonne. The capture cost is for a coal-fired power station; gas would be higher because the CO2 concentrations are much lower in the exhaust stream. Let’s assume the total price for capture of 90% of flue gas from a gas CCGT plant of about $60 a tonne.

What do these figures mean?

The purpose of this short section is to estimate how much carbon capture will add to the price of a megawatt hour of gas-produced electricity. It includes estimated figures for the cost of the greenhouse gases not successfully captured by the proposed new process, assuming that some form of carbon taxation applies. I copy figures from the IPCC for some of these costs.[3]

I use the following process to estimate the impact of fully accounting for the CO2 and methane emissions.

·      First I use the IPCC figures to estimate what the emissions are from the drilling and transportation of natural gas to the typical power station (‘fugitive emissions’). The numbers include methane losses at the well but they are much lower than are currently being seen in many gas producing areas, such as the shale formations of the US. The IPPC says that typically the upstream emissions of methane from natural gas production and transportation process are about 120 kg per megawatt hour of electricity produced at a CCGT.

·      Next, I use an estimate for the average CO2 output from the gas-fired power station. This will vary substantially depending on the age of the plant and the quality of its turbines and will vary slightly depending on how many hours a week the plant operates. The figure is 370 kg per megawatt hour.

·      I assume the new CCS plant will collect and store 90% of all CO2 produced by the combustion  of natural gas. The PNNL researchers say it is possible the percentage may be higher but experience suggests that getting over 90% capture is extremely difficult.

·      The price of carbon emissions is forecast at $100 per megawatt hour in my analysis. The EU ETS price is currently about €88, equivalent to about $95.

·      I have guessed that the extra gas required for the carbon capture processes is approximately 15%. (I could not find the projected figure in the paper itself). This figure is important because it means that the total CO2 produced to make electricity is assumed to be 15% higher than an unabated plant. This increases the fugitive emissions, the uncaptured CO2 and the tonnage of CO2 that is captured in the process of making a megawatt hour of electricity.

What is the price of this pattern of emissions? Some of the emissions will result in carbon charges, which will (or should be) be imposed by future emissions trading schemes in Europe and elsewhere. The other cost is the $40 a tonne for the carbon capture.

Uncaptured emissions

            Fugitive emissions – 120 kg per MWh – inflated by 15% = 138 kg per MWH

            @ $100 a tonne = $13.8 per MWH 

            Uncaptured emissions – 37 kg per MWH – inflated by 15% = 42.6 kg per MWh

            @ $100 a tonne = $4.26 per MWh

Captured emissions

            Captured emissions – 333 kg per MWh – inflate by 15% = 383 kg per MWh

@$40 a tonne = $15.32 per MWh

Storage costs

            383 kg per MWh of CO2 to be stored at $13 a tonne = $4.98 per MWh

If these estimates are accurate, the total costs of carbon capture and possible carbon taxation at a gas fired power station is about $38.36 per megawatt hour of electricity produced.

This is the burden imposed by using CCS. The figure is actually unlikely to be as low as this. Initial estimates tend to be overly optimistic but nevertheless I’ll use this number.

How do the costs of gas with CCS and hydrogen power stations compare?

In the US in 2021, the average natural gas price to power stations was $5.15 per million Btu.[4]  This is equivalent to about $17.57 per megawatt hour. If a power plant is 60% efficient, it will require $29.28 of natural gas to make a MWh of electricity.

For comparison in the UK, which is usually a low cost location in Europe, the current (February 2023) wholesale price of natural gas is about £47 a megawatt hour, meaning a megawatt hour of electricity will take about £78 ($93.65) of natural gas to make.

A working natural gas power station in the US using CCS and paying for remaining emissions would face costs of

·      About $29.28 for natural gas

·      About $38.36 for CCS and possible carbon tax

·      The total is $77.64 per megawatt hour of electricity.

How do we compare this to hydrogen? The direct comparison is between $77.64 and the cost of hydrogen needed to make a MWh in a combined cycle power plant. We don’t need to compare the running costs of the two plants because they will be essentially the same. And hydrogen will also offer about 60% efficiency in a power plant.

 Let’s look at a range of green hydrogen costs

 ·      $1 per kg

·      $1.50 per kg

·      $2.00 per kg

·      $2.50 per kg

To make a megawatt hour of electricity in a CCGT using hydrogen will take about 50 kg of the gas. The full cost needed to compare with natural gas with CCS at $77.64 per megawatt hour will be as follows.

At $1 per kg                = $50 per MWh

At $1.50 per kg           = $75 per MWh

At $2.00 per kg           = $100 per MWh

At $2.50 per kg           =$125 per MWh

What this says is that hydrogen has to be below around $1.55 per kg to compete with natural gas with CCS in the US. This is a tough target, although electrolyser manufacturer NEL has often said it is attainable by 2025 in good locations. The official US Earthshot target is $1 per kg by 2031.[5] The support offered by the Inflation Reduction Act would certainly get the cost down to approximately this level already.

What about the UK, where natural gas prices are currently very much higher? Including CCS costs at US prices (for want of good figures in the UK) suggests that the full price of making electricity with gas in the UK is now around $132 ($93.65 gas costs plus $38.36 CCS costs) a MWh. At this cost, hydrogen below about $2.60 per kg would be competitive with natural gas. This is clearly also possible within a few years.

There are many contestable assumptions in this analysis but I wanted to show that, even with extremely aggressive cost assumptions for CCS, hydrogen is not obviously uncompetitive with natural gas for making electricity.

 [1] I am very grateful to Thad Curtz for pointing out this research. https://www.cnbc.com/2023/01/24/new-technique-from-us-national-lab-to-remove-co2-at-record-low-cost.html covers the topic. The paper is at https://www.sciencedirect.com/science/article/abs/pii/S0959652622052702. The paper says $40 a tonne, the CNBC piece $39 a tonne.

[2] This doesn’t make coal ‘better’ because over twice as much CO2 is produced for each megawatt hour of electricity produced compared to gas.

[3] IPCC Annex III, Technology Specific Cost and Performance Parameters, S. Schlömer et al. https://www.ipcc.ch/site/assets/uploads/2018/02/ipcc_wg3_ar5_annex-iii.pdf

[4] https://www.eia.gov/todayinenergy/detail.php?id=55519

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

Decarbonising steel: hydrogen or metal oxide electrolysis?

The major steel companies in Europe now have advanced plans for switching away from coal to hydrogen. The first large scale plant is likely to open in 2026 in Boden, northern Sweden as the first site of H2 Green Steel. H2 Green Steel promises to manufacture 5 million tonnes a year of near zero carbon metal by 2030. Many other steel-makers have made ambitious promises, and have gathered substantial subsidies in most large European countries (not Britain) to make the transition.

The sense of an almost inevitable switch towards hydrogen was punctured last week by a new fund-raising for a company focused on an entirely different route to decarbonisation. Boston Metal took in $120m to develop steel-making using electrolysis. Investors included ArcelorMittal, the largest steel-maker outside China. ArcelorMittal is also backing hydrogen and has invested in carbon capture on its Belgium plant using Lanzatech technology.

Boston Metal says that if iron ore can be heated to 1600 degrees using electricity in a liquid solution, it will separate into iron and oxygen. This is called Metal Oxide Electrolysis (MOE) and is similar to the standard process for making aluminium from bauxite, although at a substantially higher temperature. One of Boston Metal’s core innovations is a type of anode that can tolerate the temperatures inside the furnace.

Let’s look quickly at the advantages and disadvantages of the Boston Metal approach compared to the prospective hydrogen equivalent.

The advantages

1.     Boston Metal takes iron ore and puts it through its electrolysis furnace and produces liquid steel. If the technology works as promised, this is remarkably simple compared to steel-making using coal, and seems very straightforward even compared to hydrogen. Direct Reduced Iron (DRI) using hydrogen takes iron ore, turns it into pellets, then puts it into a furnace to make iron. The iron is then made into steel in an electric arc furnace.

2.     The technology is modular. Boston Metal’s basic product is the size of large bus and an indefinite number of modules can be placed next to each other. By contrast, a DRI plant will have to be large to gain maximum efficiency.

3.     Financial details aren’t available but the capital costs may eventually be lower per unit of steel-making capacity than a hydrogen DRI plant, but only a very large scale.

4.     Importantly, the process can use iron ore of any grade. DRI probably requires ore at the top end of the iron-containing spectrum in order to avoid having to put the molten metal through a basic oxygen furnace, a further step in the steel production process

The disadvantages

1.     The technology requires a continuous and stable supply of electricity. It will need huge quantities with near 100% reliability, so many places in the world will be unsuitable. By contrast, the hydrogen for steel making can be made anywhere and then transported to the steel site. And unlike the Boston Metal route which needs electricity all the time, a DRI plant can use hydrogen that has been stored for months.

2.     The total energy needed for DRI production is probably lower than for Boston Metal. These numbers aren’t reliable but I think DRI production using hydrogen needs about 3.2 MWh per tonne of steel whereas the MOE process is said to require about 4 MWh.[1] Details are in the Appendix below. The difference may not seem much but, assuming a price of $40 per MWh of electricity, the cost premium is about $32. In the context of steel prices of around $600 a tonne (highly variable), this difference is significant.[2] For comparison, conventional steel making uses about 5.2 MWh of energy in the form of coal per tonne.

3.     A large DRI plant constructed today might make 5-10 million tonnes of steel a year. But at the moment the Boston Metal technology is at the scale of about 1 tonne a week from each module.[3] By 2026, the output is forecast to rise to about 1,200 tonnes a year and then eventually to more than one million tonnes. The scaling up of the MOE process so that capital costs are minimised may take decades and the DRI approach is more ready for very large scale operation. (DRI using syngas made from natural gas rather than pure hydrogen has been operating for several decades and now produces over 100 million tonnes of iron).

4.     If I understand it correctly, the ‘Inflation Reduction Act’ in the US seems likely, at least in the short term, to give huge impetus to the manufacture of green hydrogen, offering a subsidy of up to $3 per kilogramme. Potentially, this brings the net cost down to cents per kilogramme within a few years. It isn’t clear to me that just using renewable electricity as in an MOE process would benefit from similar generosity. Please tell me if I am wrong.

Boston Metal’s success or failure has very wide significance for the hydrogen industry of decades to come. Steel-making is likely to be the single largest end-use for H2, absorbing up to 100 million tonnes out of total hydrogen production of about 500 million tonnes by 2050. But BP’s recent Energy Outlook forecasts about 50 million tonnes of H2 used in steel making so my predictions may be somewhat too aggressive.[4]

At current (January 2023) coking coal prices of about $190 a tonne, both hydrogen and MOE production routes will be probably become cheaper than the conventional blast furnace approach within a few years. (I’m assuming $40 a MWh for renewable electricity for use in either alternative process). Moreover, a carbon tax/border adjustment of $100/€100 a tonne will make coal-based steel entirely uneconomic against both hydrogen and MOE.

On balance, I think that hydrogen will still capture a large fraction of the world’s steel making by 2040. But I’ll be watching Boston Metal’s future steps with great interes

 Appendix

The energy needs for making steel using hydrogen are approximately as follows.

Kilowatt hours per tonne

* Pelletizing the iron ore                    -           220 kWh

* Generating the hydrogen                -           2500 kWh

* The electric arc furnace                   -           450 kWh

 Total                                                    -           3,170 kWh per tonn

[1] Source: Boston Metal

[2] Source: Trading Economics

[3] https://www.thechemicalengineer.com/features/electrochemistry-for-greener-steel/

[4] https://www.bp.com/en/global/corporate/energy-economics/energy-outlook/hydrogen.html?sectionSlug=eo23-page8-section1

The proposal for Europe’s largest solar farm

The Botley West solar farm will consist of three large areas of photovoltaic panels immediately to the west and north west of Oxford in central England. In total, the proposal envisages a plant of 840 megawatt capacity, making it larger than any solar farm currently operating in Europe.[1] Botley West now has to pass through a complicated and drawn-out approvals process, with a final decision by the UK government not due before 2025.

Fields proposed to be used for solar PV in the central part of the development, just south of Blenheim Palace, north-west of Oxford. From the north to the south of this portion of the solar farm is about 5 km.

The farm will connect directly into the very high voltage transmission network (‘the National Grid’) at a newly built substation just west of Oxford. I think this will be one of the first times any solar development has fed directly into the National Grid, rather than into the lower voltage networks of the local electricity distribution companies.

This is a huge proposal, covering 1,400 hectares (14 sq km, 5.4 sq miles) of mostly agricultural land in Oxford’s ‘Green Belt’ a ring around the city intended to be kept free of new buildings and other developments. A farm of 840 megawatts represents more than 5% of the total installations of solar PV in the UK today and it will generate about one third of one percent of the whole country’s current electricity use. It therefore will cover all the electricity needs of Oxfordshire homes.

The obstacles to the project.

The proposal has elicited strong reactions, mostly unfavourable. The main criticisms include

1.     Resistance to the construction of such an overwhelmingly large project. It will require between 2 and 3 percent of Oxford’s Green Belt, and about half a percent of Oxfordshire’s total land area.[2]

2.     Why does it have to be where it is planned to be?

3.     It is seen as having a negative impact on biodiversity.

4.     And will reduce the amount of land dedicated to arable agriculture.

5.     For local residents, it will affect the appearance of the countryside.

6.     The park will be ultimately owned by a German company. Some people object to the flow of income from the farm flowing to non-UK financiers.

I will look at these points in turn and conclude by suggesting some routes that might help the project secure more support.[3] I should also state that on balance I believe this solar farm would be a very useful part of the UK’s decarbonisation plan.

1.     Why does the project have to be so large?

A large number of smaller farms are being planned, both in Oxfordshire and elsewhere. The recent period of high electricity prices has made solar a relatively cheap way of generating power.

 But almost all of these farms will have to wait many years for connection into the local distribution network operated by Scottish and Southern Networks (SSEN). In many other parts of the country as well as in Oxfordshire, congested lower voltage networks are unable to accept the exports of power from new solar farms. The portion of the electricity distribution infrastructure that brings power to homes and businesses is severely overstretched across much of the UK. Large amounts of new capital, and considerable time, will be needed to upgrade these networks.

Botley West isn’t blocked by this problem. It is sufficiently large to justify the creation of an entirely new high voltage National Grid connection to the main pylon line that runs between the Oxford substation westwards to the Bristol area. The solar farm has to be as large as is planned because only a generator this large can justify the cost of a hugely expensive new substation to tap into this long-distance line.

2.     But why does it have to be in west Oxfordshire, and not somewhere else?

National Grid recently upgraded the Oxford substation at Cowley on the eastern edge of the city, giving substantial extra capacity. This makes possible the Botley West connection a few kilometres away.

I am told by the developers of the Botley West project that National Grid is not able to connect new large scale PV farms elsewhere in the country because the required high voltage capacity is not available. In other parts of the UK, any very large new solar farm will struggle to get a connection before 2031.

Of course this has very serious implications for the pace of the UK’s decarbonisation and the speed of growth of electricity demand as the country seeks to switch heating and transport away from fossil fuels. The lack of any serious policy for achieving the required growth in electricity transmission and distribution capacity will make decarbonisation more difficult than assumed. It’ll block the rapid growth of heat pumps and the development widespread car charging. This issue gets no attention.

Put simply, the Botley West developers have located one of the few areas in the southern half of the UK where a large solar farm can be installed.

3.      Will it have a negative impact on biodiversity?

Intensely farmed agricultural land has truly awful levels of biodiversity. Large, over-cultivated fields with few hedgerows are always terrible for nature. Unfortunately, much of the land that Botley West will use has been farmed excessively and will benefit from a switch to hosting solar panels; ploughing will stop as will the use of fertilisers and pesticides.

The design for the PV farm is not yet complete. So we cannot know exactly what the other benefits of the transition will be. But merely converting ploughed fields to solar helps rebuild some aspects of natural life, particularly if plant life is encouraged around the panels. In addition, the developer promises wide buffer spaces around the individual fields, some woodland planting and biodiversity corridors. Properly done, nature can thrive around solar farms in a way that it is not possible in intensive arable landscapes.  The experience from around the UK and elsewhere is that solar PV can provide a major lift to the quality of the local natural world.

4.     What about the impact of the loss of land for agriculture?

Botley West will extend over about 1,400 hectares. Not all of this land is currently used for agriculture. But let’s assume that it is. If all this area produced wheat, and the land was as productive as the UK average, farmers would get approximately 12,000 tonnes of wheat off this area, with a value of about £2.8m at today’s prices. The value of electricity produced, which will reduce the need to import gas and oil, is approximately 16 times as much.

Perhaps as importantly, average quality agricultural land – such as the area reserved for Botley West – does not produce wheat every year.  It is more likely that the fields would only produce wheat once every three years and, of course, that this crop would generally be used to feed cows, not humans. Botley West is not going to make bread more expensive.

Nevertheless, the loss of agricultural land is still a concern. Imagine for a second that UK decided to use large amounts of field solar, perhaps taking the national capacity up to 200 gigawatts. (It is about 14 gigawatts at the moment).  This would probably generate about 210 terawatt hours, or over two thirds of the UK’s current consumption of electricity. It would require approximately 2% of the UK’s agricultural land to build the solar farms to do this.

Where we can, the country should clearly allocate solar farms to less productive land, particularly outside cereal growing districts. But we should also recognise that some solar will need to be placed in areas of reasonable quality farmland because of the need to secure connections into either the high or low voltage distribution networks.

5.     Affecting the appearance of the countryside

The areas to be devoted to solar panels in the Botley West development are predominantly flat. The panels and the associated infrastructure will be 2.5m high at most. Properly shielded by trees and other vegetation, the solar fields will be largely invisible to local people and to those passing through the area.

Many of the opponents to the Botley West scheme are sceptical about this point. However there are already 25 solar farms in Oxfordshire, and most of them are close to invisible after surrounding trees have grown up. They don’t have significant effects on the views of people in the area.

6.     The proposed park will be owned by a German company

The company that constructs and owns Botley West will be the UK subsidiary of a German company that has constructed solar farms elsewhere in Europe and in Japan. It will pay tax, including business rates, in the UK in exactly the same way as a business owned by a British firm.

Given the scale of the proposed solar farm, probably costing nearly £500m, the German business will also need to raise large amounts of third party capital. Much of this will probably come from UK banks and investors, thus keeping the eventual returns in the country. In the current circumstances perhaps we Britons should be grateful that a German business sees opportunities to help the UK decarbonise in this way.

What should Botley West do to secure local support for the proposal?

The decision whether or not to allow Botley West to be built will be taken by central government, not by local planning officers or district councillors. However favourable local opinions are likely to improve the chances of the project being approved.

The current opposition is widespread and diverse. Local MPs, both Conservative and LibDem, are either explicitly opposed or have expressed deep reservations. Groups such as the Council for the Protection of Rural England (CPRE) have also voiced strong concerns.

CPRE opposes the scheme because, in their eyes, it does not achieve any of the following objectives:

▪ Prioritise the use of brownfield land.
▪ Benefit the local economy.
▪ Be supported and/or owned by local communities.
▪ Bring net benefits to wildlife.
▪ Avoid/minimise loss of productive agricultural land.
▪ Avoid use of designated land such as Areas of Outstanding Natural Beauty and Green Belt, and elsewhere avoid/minimise impact on landscape, tranquillity and cultural Heritage.

This note has tried to contest most of these points, but it is true that the project does not introduce any form of local ownership. So my first suggestion is

·      Allow local people in Oxfordshire to invest in the scheme. Oxford has a very effective group that owns local renewable assets; Low Carbon Hub has built solar farms and hydro-electric power sites in the area and is well placed to act as the platform by which Oxfordshire residents buy shares, or debt instruments, issued by Botley West. In other places, community ownership has transformed attitudes towards renewable schemes that might otherwise have been strongly opposed.

An alternative proposal might be to make yearly dividend payments to all households within 3 km of the farm. This payment could be dependent on the measured output of the farm, giving local people a return based on how much energy is produced.

My second proposal is that the buffer areas around each of the many fields within the development be used to provide other benefits.

·      Create spaces for local agriculture, including allotments and commercial market gardens in the areas around the panels. Local fresh food is in increasing demand and also many people want to become horticulturalists but cannot find land on which they can work. The Botley West development could also provide allotments for all who want to rent space. Of the 1,400 hectares, perhaps 20 hectares could be allocated to community agriculture of one form or another, probably with no loss of output at the solar farm 

A third idea might be to subsidise local residential PV.

·      The developer could develop a package of low cost PV installations that would be offered to all homes within a certain area, allowing local households to benefit directly from PV. A well promoted and designed package offering perhaps 3 kilowatts of solar panels to all homeowners at a highly competitive price might make a big difference to local attitudes towards the development.

Botley West is an enormously ambitious proposal that I believe would help re-start the UK’s stalled decarbonisation process. It is completely understandable that the scheme is creating concern but the country needs schemes like this to provide the green electricity to feed the growing number of electric cars and heat pumps. It would be an extraordinary example of how solar PV could produce cheap electricity on a very large scale with no carbon emissions.

[1] The Francisco Pizarro farm in western Spain opened last year with a capacity of 590 MW. This is currently the biggest PV development in Europe.

[2] Oxfordshire is a county in southern England, of which Oxford is the major city. Oxfordshire has about 600,000 residents in about 270,000 households.

[3] Much of the land that is proposed to be used is owned by a single proprietor. This is the Blenheim estate, the area surrounding Blenheim Palace to the north west of Oxford. I have informal connections with the estate management team and was grateful to them for buying copies of my last book for all their employees. I have no current financial connection with the estate (although I am in grateful receipt of a free annual pass to the grounds!). Nor do I have any connection to the German developer of the site. I am grateful for their response to my questions.

Why hydrogen may be the principal media for energy storage

Over the course of the last week (December 12th – December 19th), South Australia produced more renewable power than its entire needs for electricity.[1] The state proudly claims that this is the first time that a large electricity market has met all its requirements from wind and solar. It also suggests that by March of next year, aggregate needs may be met for over a month. This is a striking picture of how renewables will look at many places around the world within a few years.

The state is connected into Australia’s National Energy Market (NEM) which can buffer periods of over-supply or shortages. In addition, South Australia has some gas generation used to make electricity when wind and solar outputs are insufficient. But high wind speeds over the last weeks have meant that electricity generation from turbines has been able to meet almost all instantaneous demand. The previous week saw gas only provide about 9% of all electricity produced in the state, with wind generating almost ten times as much.

This is the context for two important decisions announced this week.

·      A plan by the state of South Australia to invest in one of the world’s first power-to-gas-to-power (P2G2P) plants reached the stage of requesting tenders from suppliers.[2]

·      The national government of Australia proposed to build a set of large batteries, partly funded by its renewable energy agency (ARENA).[3]

Both of these schemes are a response to the growing need to productively store electricity surpluses to meet demand when wind and solar outputs are not sufficient.

The P2G2P plant

South Australia intends to build a 250 MW electrolyser to generate hydrogen, combined with a 200 MW hydrogen gas turbine power plant. I think this is by far the largest P2G2P proposal in the world. The intention seems to be to use 100% hydrogen from the opening in late 2025, unlike other plants, such as Intermountain in Utah, which are intending to gradually phase in increasing percentages of H2

When electricity is abundant, the electrolyser will make hydrogen, storing it until it is needed. The power plant will then use the gas to generate power. The proposed storage facility will hold 3,600 tonnes of hydrogen, which will have an energy value of about 120 gigawatt hours. This is approximately equal to 1% of South Australia’s annual electricity use.

South Australia says it has budgeted AU$593 (US$400) million for this proposal. The state itself will own and operate the facility. At today’s approximate figures of US$600 per kilowatt, the electrolyser will cost about US$150 million. The storage facility will probably be the next largest element.

We cannot know yet whether this plant can be built for US$400 million but the government seems optimistic. At least 60 external companies have registered interest in bidding for elements of the project.

The plan is to use land near the city of Whyalla, one of the centres of South Australia’s steel making industry. Steel will need huge quantities of hydrogen and may also be a customer from the hydrogen.

Large batteries for the grid

Australia’s ARENA announced eight locations for grid storage batteries, including one in South Australia. These will be constructed so that they can respond nearly instantly to the need for power and will assist in maintaining the correct frequency and voltage of the AC grid. (Apparently this is called ‘grid-forming’ capacity).

ARENA expects battery suppliers to quote costs of around US$1.8bn for these installations. They which will provide about 2.0 gigawatts of power and a total energy storage capacity of 4.2 gigawatt hours. the biggest will be 900 MWh, making it prospectively one of the largest batteries in the world. ARENA offered grants of around US$120 million towards the cost of putting these 8 systems in place.

Some of the implications of these projects

One thing immediately stands out comparing these two sets of projects. The single P2G2G installation will offer about 118 GWh of storage compared to about 4.2 GWh for the eight batteries. But the cost of the whole P2G2P project should be around US400m, compared to US$1,800 for the batteries. If these numbers are right, storing energy in the form of hydrogen is therefore less than one hundredth of the cost of the same energy value of electricity in a battery.

This is why I think hydrogen will be the means by which renewable-dominated grids are balanced. P2G2G systems are widely criticised for being ‘inefficient’ because the energy losses from making hydrogen and then converting it back to electricity are at least 50%. (I assume 75% efficiency in the electrolyser and 60% of energy going into a turbine being converted to electricity). But the capital cost of a large storage system for hydrogen is absolutely tiny compared to a battery, which might achieve 90% round-trip energy efficiency.

We will need batteries for very rapid response to changes in grid conditions. But the large bulk of energy storage needs will be provided by hydrogen systems such as the Whyalla power station.

If we assume that the Australian battery systems last 18 years (optimistic), charge and discharge 400 times a year (very optimistic indeed) and that the cycle goes from 100% charged to 0% charges (an impossible assumption), the capital cost per megawatt hour of charging is just under $60, without including any interest burden.

The same calculation for hydrogen storage produces a figure of about 50 US cents for each megawatt hour. If these Australian figures are realistic and typical, in normal conditions a hydrogen storage system is vastly cheaper to own and operate. Batteries will only be better than hydrogen in financial terms if the electricity to be stored is very expensive and therefore the P2G2G efficiency losses are costly.

This is unlikely. In a system dominated by renewables, periods of surplus electricity will see very low prices, and curtailment of wind and solar production. So the efficiency losses do not make hydrogen systems inherently uncompetitive. Put simply, the high capital cost of operating batteries will be greater than the cost of the losing energy via the hydrogen storage process.

Of course, prices may change. Batteries may get cheaper and hydrogen may prove more expensive to create and store than South Australia believes. But at the moment it looks as if large scale storage to deal with the growing number of hours and days of surplus electricity, such as South Australia is already seeing, will be accommodated using electrolysers and hydrogen turbines. Europe should sponsor a similar P2G2P plant now.

[1] https://reneweconomy.com.au/south-australias-incredible-week-104-1-per-cent-wind-and-solar-over-seven-days/

[2] https://www.whyalla.sa.gov.au/our-city/news-and-events/latest-news/hydrogen-power-plant-progresses-to-next-milestone

[3] https://arena.gov.au/blog/arena-backs-eight-big-batteries-to-bolster-grid/

The UK government’s support for new coal mining: ‘Chasing the next thing that is going to die.’ (Copy)

On 7th December 2022, Stéphane Tondo, the head of government affairs and climate change at Arcelor Mittal, one of the world’s largest steel-makers, gave a presentation that included the following statement: ‘By 2030, most of EU’s steel production will be decarbonized’.[1]

Tondo also asserted that over half of the 90 million tonnes a year of European steel made in blast furnaces today would switch to a process using hydrogen and electric arc furnaces by that date. This will reduce the demand for metallurgical (coking) coal by a similar percentage.

On the same day, the UK government gave permission for a new coking coal mine in north west England. Its principal justification was that Europe’s steel sector would continue to need large amounts of this type of coal for many decades to come. The government’s 400 page decision further said that decarbonisation of the industry, if it occurs at all, will be made possible by the use of carbon capture and storage. Hydrogen steel-making is not, and will not be, a financially viable way of making steel, said London.

The conflict between these two views of the industry could hardly be sharper. Who is right?
I try to answer this question in three ways.

First, I look at the published intentions of the owners of each of the 27 operating blast furnace sites in the European Union and the UK. I show that all but four of these sites have stated a strategy of switching away from using coal to using hydrogen or increasing the use of electric arc furnaces.

We cannot know how long the transition will take but many of the operators have stated a plan to stop using coal by 2030. We shouldn’t be surprised; the world steel industry is responsible for almost 8% of global CO2 emissions and the main participants know that they face extinction if they do not make aggressive moves to decarbonise their businesses this decade. They are being heavily supported by national governments in funding the transition.

Second, I add up the expected capacity of the direct reduction plants in the cases where the company has provided an estimate of expected size. I do this to compare the operators’ plans with the UK government’s estimate that, at most, the European steel industry will have switched 10 million tonnes of output from coal to hydrogen by 2030. I show that the government’s figure is a gross underestimate.

Third, I list the published decarbonisation commitments of the main European steel makers. Typically, they have promised to reduce their emissions footprint by 30% by 2030.

The stated plans for the 27 EU and UK blast furnace sites

Almost all the blast furnace operators in Europe have publicly indicated how they expect to move away from coal. The only exceptions I could find are the two sites in the UK, a Polish operator and the Hungarian steel manufacturer. (The owner of the Port Talbot site in the UK has said that it has asked for government support to switch to electric arc furnaces but as far as I can see has not said that it intends to shift to this route to making steel).

Blast furnace sites and capacity information from Eurofer.eu. DRI and EAF intentions from published documents

Of these 27 sites, 15 have indicated an intention to build direct reduction furnaces using hydrogen and 15 have said they will invest in electric arc furnaces. Seven are indicating they will have both types of steel-making at these locations. This is logical; a direct reduction plant using hydrogen needs to an electric arc furnace to turn the iron into steel.

So, despite what the UK government said in its coal mine decision, the European steel industry has firmly suggested the routes it intends to take away from coal. Few companies are ignoring the imperative to move to low carbon manufacturing. However we don’t know how fast the industry will move.

To the list in the table above should be added the entirely new site of H2 Green Steel, a Swedish start-up funded by over €3.5bn of debt and equity. This company will use hydrogen, and not coal, from the start of its business. Despite its high profile in the European steel industry, the decision documents did not mention this company once in more than four hundred pages. (There is virtual no mention of any European or other steel-makers in the entire document).

H2 Green Steel’s enthusiasm for a transition to hydrogen is being bolstered by the evidence of an increasing preference of customers for low carbon steel and also by findings that steel made without coal is typically of a better quality than its conventional equivalent. Major car companies are helping to fund H2 Green Steel and are committing to buying hydrogen steel from the company and other hydrogen steel manufacturers. The car industry is the second most important user of steel after the construction of buildings.

It may also be worth noting that only one of these 27 sites has started to invest in any form of carbon capture. Arcelor Mittal’s site at Gent/Ghent in Belgium is experimenting with converting flue gas to ethanol using the Lanzatech process. Arcelor Mittal tells us that the maximum saving of emissions from the ethanol production is about 125,000 tonnes a year, which represents between one and two percent of the site’s total emissions. The UK government’s faith in large-scale CCS for the steel sector is at variance with almost all opinion within the industry.

How much direct reduction capacity does the European industry expect to install before 2030?

The UK government’s inspector asserted that ‘even if all the announcements made by the industry come to fruition this only amounts to 10 million tonnes per annum of hydrogen based steel production in Europe by 2030 which is less than 7% of overall current production of around 160 million tonnes per annum’.

There are two problems with this statement. First, it doesn’t reflect reality. The table below lists all the planned introductions of DRI that are accompanied by a figure for expected capacity in million tonnes per year.

Proposed capacity of installations at major steelworks that have committed to DRI with hydrogen (Million tonnes annual capacity)

Ghent                         2.5

Dunkerque                 2.5

Bremen                       3.5

Dillingen                     2.5

Duisburg                     2.5

Gelati                          1.5

Gijon                           2.3

Lulea                           2.7

+ H2 Green Steel           5.0

 Total                            25.0

This table, collected from publicly available information, tells us that the UK government’s estimate of 10 million tonnes of maximum DRI capacity by 2030 is a large underestimate of promised installations. Simple research would have shown the error of the inspector’s conclusion.  

The second point is that the inspector suggests that the total amount of steel produced in the EU and the UK is 160 million tonnes a year. While this figure is broadly correct – it was 153 million tonnes in 2021 – this number includes output from electric arc furnaces, which use electricity and not coal.

Steel production from blast furnaces in 2021 was 86 million tonnes in the EU + UK. This is the part of the steel industry that can be decarbonised using DRI. Electric arc furnaces are decarbonised by using renewable electricity.

So the planned installations of DRI, mostly due to be installed by 2030, actually represent about 29% of the possible total. To make the point in a different way, almost a third of the EU and the UK’s steel production using coal may be switched to hydrogen by 2030 if current plans are fulfilled, not the maximum of 7% claimed by the UK government.

 Planned overall rates of decarbonisation

According to steel industry analysts at Kallanish, seven of the major EU manufacturers have made promises about their rate of decarbonisation.[2] With one exception, the companies commit to cutting their emissions by a specified percentage by about 2030. (Kallanish doesn’t specify the date from which the percentage is calculated in these seven cases)

Promised rates of decarbonisation

  Arcelor Mittal                        35% by 2030

Thyssenkrupp                          >35% by 2030

                                Tata                                       >30% by 2030

  SSAB                                     .>50% by 2030

Voestalpine                             35% by 2032

Salzgitter                                50% by 2030

                     Saarstahl                                 ‘significant savings by 2035’.

 Decarbonisation on this scale can only occur by reducing coal use by switching to DRI and/or moving to producing more steel using electric arc furnaces and scrap steel. 

Conclusion

The UK government has allowed the construction of the mine in the north west because it believes that the European steel industry will not decarbonise rapidly and, if it does, it will use carbon capture and storage (CCS). It asserts that hydrogen DRI is an immature technology that is unlikely to be rapidly employed.

Publicly available information that the government’s inspector should have used shows that this assertion is highly inaccurate. Almost all large EU steelmakers have released plans for moving to hydrogen DRI, either partly or in entirety. DRI is a well-understood technology that is widely used already, usually for making steel in smaller quantities. Currently DRI furnaces use natural gas, not hydrogen, but companies and their investors are confident that the fuel can be switched with no adverse consequences.

Only Arcelor Mittal is even experimenting with CCS on coal-fired blast furnaces and its support seems to be rapidly shifting away and towards hydrogen. CCS technology is far less well established than DRI. CO2 capture at blast furnaces is widely seen in the industry to be difficult and costly.

As is frequently the case, the UK government and its agencies has taken a decision without any research into trends in the rest of Europe. The lack of any substantial reference in the 400 page government document to the opinions of the EU steel industry is almost incomprehensible. Or perhaps not.

In the research for this article I came across a similar decision by the province of Alberta in Canada which recently approved metallurgical coal mining but then rapidly reversed the policy when faced with widespread protest. Blake Shaffer, assistant professor of economics at the University of Calgary, told The Narwhal newsletter in February 2021 that the expansion of metallurgical-coal mining in Alberta is an example of the province ‘chasing the next thing that’s going to die.’ [3]

That seems a strikingly accurate way of also describing the UK’s decision.

[1] https://media.kallanish.com/filer_public/cb/43/cb43922b-24d5-47b0-ad24-ad08eec3bdf1/h4s_kpm_webinar_dec_22_final_all.pdf

[2] https://media.kallanish.com/filer_public/cb/43/cb43922b-24d5-47b0-ad24-ad08eec3bdf1/h4s_kpm_webinar_dec_22_final_all.pdf

[3] https://thenarwhal.ca/alberta-rockies-ucp-coal-mine-policy-reinstated/

30% of social housing will not be heated adequately in the coldest weeks of this winter

Conclusion

The very warm weather over the last few weeks has disguised the problems of fuel poverty in the UK. Using data on house internal temperatures from Switchee, I forecast that In the coldest weeks of this winter almost 30% of social tenants in the UK will keep their homes below 18 degrees every hour of the day. This implies that well over 1m social homes will be too cold. Two years ago, this number was about 10%, or little more than a third of the numbers expected this year. The rise in the price of energy will cause a substantial rise in illnesses brought on by cold housing. The low internal temperatures will also bring about an increase in important problems such as interior mould.

The method used to predict excessively cold homes

The detailed information to support my conclusion is provided by Switchee, the  UK’s leading ‘Internet of things’ platform for social housing. Switchee’s thermostats provide data to the landlord which shares it (suitably anonymised) with Switchee. It is then aggregated.

The database is richly informative. It can be used to identify the number of households that hold the temperature of the house below any particular temperature. As might be expected, as the outside temperature falls, the number of homes not ever heated to an adequate 18 degrees rises sharply. As the later charts in this article show there is a clear linear relationship between the external temperature and the percentage of homes that are kept cold. We can use this robust relationship to forecast what we can expect for the 2022/23 heating season.

What previous years have shown us

The chart below shows the percentage of homes never reaching an internal temperature of 18 degrees during rolling 7 day periods in the last four years.[1] These houses were cold every minute of an entire week. As would be expected, the share of cold homes peaks in winter, although homes were also cold during the snaps of chilly weather in April 2022, a time when gas prices had just been increased.

When external temperatures are low, the gas consumption necessary to keep the home above 18 degrees will be higher than at warmer winter temperatures. As prices rise, it is therefore inevitable that budget conscious customers will tend to reduce gas use, and home temperatures will fall as a result.

Chart 1

The percentage of homes never reaching 18 degrees over seven day rolling periods in the last four years

Source: Switchee

It is evident from the chart that higher gas prices in 2021/22 had begun to increase the percentage of homes unwilling to ever let the internal temperature rise above 18 degrees. Has the increase in ‘fuel poverty’ continued into the 2022/23 heating season? It may be too early to tell although the final day of 2022 data on this chart (for November 8th) shows that over 10% of homes had ceased to keep their temperature above 18 degrees over the whole of the previous 7 day period. So although the temperatures were relatively warm outside, more people were living in a cold home than at any point - even deep winter – in 2019/20.

A closer examination of the data for October and early November 2022, and a comparison with the same days in 2021, allows us to show some of the impact of the recent price rises.

Chart 2

Percentage of homes not reaching 18 degrees at any point during a single day: Comparison of September-early November 2021 and 2022

Source: Switchee

 The blue columns in Chart 2 show the percentage of homes never reaching a temperature of 18 degrees each day in September, October and early November 2022. This chart does not use rolling seven day averages but measures single days. So, for example, on 27th September 2022 just over 15% of homes did not hit 18 degrees at any point in the day.

The red line marks the figure for each of the equivalent days in 2021. As we’d expect, the numbers are much lower in 2021. On 27th September 2021, the percentage not reaching 18 degrees was barely above zero.

On some days in this two month comparison, the 2021 red line rises above the blue column, particularly in late October. Unsurprisingly, the reason is probably that external temperatures were typically much lower in 2021. For example, the average for the last week of October 2021 was just 11.77 degrees, compared to 14.78 in 2022.[2]

So although it looks as though fuel price pressure may have added to the numbers of householders choosing not to heat their home. But this conclusion is muddied by the variations in temperatures between years.

The best way of assessing the impact of higher utility prices is to plot the relationship between the weekly average temperatures and the percentage of homeowners holding temperatures below 18 degrees. This analysis shows the very close link between lower temperatures and high percentages of unheated (or under-heated) homes. And, as must be expected, the position this year is far worse than in previous periods.

The Switchee database runs from September 2019 to today. The first chart shows the relationship between the average external temperature of each rolling week from September 2019 to June 2020 on the x axis and the percentage of homes not reaching 18 degrees at any stage in that seven day period. When the average temperature rises above 15 degrees, the number of homes not reaching 18 falls to about zero and these weeks are omitted from the chart (and all succeeding ones).

Chart 3

Source: Switchee

This chart shows the close relation between external temperatures and the percentage of homes never reaching 18 during the rolling 7 day period . The trend llne calculated shows that if the average external temperature was 10 degrees the percentage of homes never reaching 18 degrees in that week was about 3.6%.

July 2020 to June 2021 shows a very similar pattern. This year had some far colder 7 day periods, including some periods below zero for the 7 day rolling window.

Chart 4

Source: Switchee

As can be seen from the trendline on the chart, external temperatures below zero are associated with over 11% of homes consistently staying below 18 degrees in this one year period.

The pattern begins to change during the following year (July 2021 to June 2022). Gas prices began to increase in September 2021 but the effect was small until the end of March 2022, when the domestic price increased again, this time sharply.

Chart 4 shows that a 10 degree average external temperature in the July 2021 to March 2022 period was associated with approximately 4% of households keeping their temperature below 18 degrees. This is very little different to the previous years in the Switchee database.

Chart 5

Source: Switchee

In this period, a 7 day average external temperature of 10 degrees is associated with about 4 percent of homes never exceeding 18 degrees internal temperature. An average temperature of 0 degrees (which was not reached in this period) is predicted to cause about 11.5% of homes never heating the house to 18 degrees.

As chart 6 shows, the period from the end of March to the last days of June 2022 showed a sharp increase in householders keeping their homes cold.

Chart 6

Source: Switchee

 In this short period, the percentage of homes consistently not being heated to 18 degrees when the external temperature averages 10 degrees was between seven and eight percent, almost double the figure in the first nine months of the year. The trend line on the chart suggests that were the temperature to fall to zero the percentage of cold homes would be over 21%, once again almost double the figure for the previous period.

Not unexpectedly, the continued rise in prices in the second half of 2022 has pushed even more homes into keeping the internal temperature below 18 degrees.

Chart 7

Source: Switchee

 Temperatures in this last period have generally been warm. So we cannot directly see what percentage of homes will be under-heated in the coming winter. But we can predict what the likely levels will be. In previous years, the trend line has been straight and there is little reason to believe winter 2022 will be different. As temperatures fall, the number of tenants never heating their house to more than 18 degrees rises proportionately.

The figures for summer and early autumn 2022 suggest that the share of social homes kept below 18 degrees internally when the external temperature is 10 degrees will be just below 10 percent, up from 7- 8 percent in the April to June season of 2022 and no more than 3-4 percent in previous years. If the temperatures fall to an average of zero for a seven day period - which doesn’t happen every year - the trend line suggests that about 29% of all social housing tenants will be keeping their homes below 18 degrees. This figure is almost three times the level of less than two years ago.

To repeat an earlier point; keeping the house below 18 degrees is both bad for human health and also causes deterioration of the property. Mould is probable, and other damage very possible. The UK has about 4.5 million social housing homes and this analysis suggests that well over 1 million of them will be insufficiently warm in the months to come. Of course, many privately-owned homes will also be kept cold to save money. The consequences for many of the occupants will be severe.

 Disclosure: I own shares in Switchee

[1] A ‘rolling seven day period’ is covers the day under study and the six preceding days. The chart therefore has 365 records per year.

[2] This figure is an average calculated across the 24 hour day and representative of the UK as a whole.

Which is better: a hectare of solar or wheat?

What happens when a hectare of UK land is transferred from agriculture to producing electricity from solar panels? This note looks at the impact on energy production, the UK’s trade balance and the productivity of the economy. The numbers show the huge advantage of using land for solar electricity. At current prices the electricity from a solar field is worth at least 20 times the value of wheat produced on the same land.

The analysis is prompted by persistent reports that the British government is intending to block the use of all but low quality land for solar farms.

Map of the south of the UK, with colours reflecting the quality or availability of the agricultural land

A map of the southern UK. The colours reflect the quality of the agricultural land. Under the government’s possible new rules, only yellow and light brown areas could be used for solar. Most of these parts of the country are in national parks, river valleys, uplands or inaccessible moors and are thus unsuitable for solar.

First of all, some numbers on the current state of the UK solar industry.

·      Including rooftops, solar capacity is currently about 14 gigawatts.

·      This uses about 0.1% of UK land and generates about 4% of all electricity.

·      Current plans suggest an active pipeline of around 30 gigawatts or more awaiting permission or construction.

·      At current wholesale prices, or indeed at the maximum price caps for renewables recently floated by the UK government of around £50 per megawatt hour, solar appears to be profitable to build across most of the country.

·      However the recent rise in interest rates, which will directly affect the costs of solar developers, may reduce the financial attractiveness of solar expansion.

1, Energy productivity

 One the roles of agriculture is to convert solar energy into food. When we talk of ‘calories’ we are referring to a measure of energy. So, for example, we can very simply convert the number of tonnes of grain produced on a hectare of land (about 2.5 acres) to megawatt hours.

 Let’s use some average UK figures to compare the energy produced by a solar farm and a wheat crop. This will be approximate, of course. Yields vary for both grain and PV in each year and in different parts of the country.

 Energy yield - wheat

Typical UK wheat yield                                               About 8 tonnes per hectare

Energy content of wheat                                            About 4 megawatt hours per tonne

Typical energy value of one hectare of wheat           About 32 megawatt hours per hectare

Energy yield – solar PV

Typical solar field capacity                                         About 0.5 megawatt per hectare

Capacity factor for a field in southern England         About 11%

Total energy produced per year                                 About 480 megawatt hours per hectare.

The energy yield from solar, using these rough approximations, is fifteen times the energy from wheat. Even that number is too favourable to wheat. Fields have to be rotated between crops each year and except in the very best locations need to be rested. So grain is not produced every growing season. Second, I have used the average figure for wheat across the UK. Most planned solar fields are in the less agriculturally productive regions of the country, implying that a conversion to solar results in a lower loss of wheat production.

‘But we can’t eat electricity’ will say the supporters of the proposed new policy. But neither can we power our houses with wheat. 

2, The impact on the UK’s trade balance

The UK is a significant net importer of cereals. In the last year for which figures are available, the UK imported over 2 million tonnes were imported while exports were about a quarter of this figure. If a hectare of wheat field is converted to solar, UK imports of wheat will typically rise but energy imports will fall.

Of course wheat prices vary from year to year. The Ukraine war has introduced new instability because the country is a major exporter of grain. I use a figure of £300 a tonne for wheat, approximately the October 2022 level.

Increased cost of importing wheat

 Typical UK wheat yield                                             About 8 tonnes per hectare

Price                                                                            About £300 a tonne

 Value of extra imports if field is converted to PV     About £2,400 a hectare. 

Decreased cost of importing gas

Typical electricity production of solar field                About 480 megawatt hours per hectare

Average efficiency of gas power station                   About 60%

Energy value of gas to make 480 MWh electricity    About 800 megawatt hours

Cost of gas      (Normal times)                                   About £16 a megawatt hour

                        (October 2022)                                   About £100 a megawatt hour

 Amount of gas imports saved by a 1 hectare solar field                                                        

(Normal times)                                   About £12,800 a year

                        (October 2022)                                   About £80,000 a year

 Usually, the saving on imported gas from converting a wheat field to solar PV is about 5 times the cost of importing the grain from that field. At the moment, the multiple is 33 times; every hectare converted would improve the UK’s balance of payments by £77,600.

3, Impact on production.

A farmer growing wheat has to prepare the ground, by the seed, sow it, fertilise and protect the crops, harvest the crop and then dry the grain. A solar farm costs a large sum to install but then very little to maintain each year for the thirty five years or so of its potential existence.

The UK government has recently suggested it may cap the price at which wind and solar farms can sell their output. At the moment, before any restriction, contracts between solar farms and their direct customers are being agreed at prices well above £100 per megawatt hour. But in the analysis below, I have used a figure of £100 for current rates and I assume that any price cap on solar might be around £50 a megawatt hour.

Value of wheat output

Typical UK wheat yield                                               About 8 tonnes per hectare

 Price                                                                            About £300 a tonne

Value of extra imports if field is converted to PV     About £2,400 a hectare. 

Value of solar output

Total electricity production                                        About 480 megawatt hours per hectare

Value of production

(At £50 a megawatt hour)                 About £24,000   

(At £100 a megawatt hour) About £48,000                                             

Depending on the price assumed, the value of the output of a solar field is therefore between 10 and 20 times the value of the wheat produced.

If economic ‘growth’ is vitally important, as the government asserts, there is no question that solar is far better than wheat for the UK.

What is the focus of European climate tech?

The Net Zero Insights database and its associated tools track over 20,000 climate tech companies in Europe. Additional data is also available for the US. The information stored includes material on such matters as fundraising, products, technology and personnel.

 This source gives us information on where new climate tech is most active and which sectors are developing the fastest.

Raising new external sources of finance

The businesses in the Net Zero Insights package can be divided into climate challenge areas. (A small number of the companies operate in more than one sector and are therefore recorded twice). The numbers below record how many companies in each area raised money in the eighteen months from January 2021. 

Table 1

Source: Net Zero Insights

As we might expect, there are more new entities raising money in ‘energy’ than any other sector. But the number of companies taking in new cash in the field of the ‘circular economy’ is surprisingly close to the figure for ‘energy’ businesses. Next comes ‘food and agriculture’, with a big gap before ‘transport and mobility’.

The percentage of businesses raising new money varies substantially between the sectors

Table 2

Source: Net Zero Insights

The percentages vary between the lowest (water) at 7% to the highest (Emissions control, reporting and offsetting) at 21%. The smaller sectors tend to have had greater numbers of new financings.

 Areas of high interest

We looked particularly at four climate tech investment areas that need large numbers of new companies to take technology forward.

·      Cement

·      Steel

·      Direct air capture

·      Hydrogen

 The database shows 621 entities in these four sectors, just under 3% of the total. Hydrogen is by far the most important, with 419 companies on the list. By contrast, Europe has only 20 ventures in direct air capture.

However the small direct air capture sector shows the most financing dynamism. Of the 20 companies, 12 raised money in the January 2021 to June 2022 period. In the hydrogen sector only 17% of the much larger number of business attained new sources of funding, though this figure is much larger than the 12% average across all sectors. Despite the importance of climate tech in steel, only a relatively small number of ventures - just 9 of the 94 businesses in the sector – raised new cash. 14 cement companies took in more money in the period.

 The hydrogen sector raised almost €3bn in the eighteen month period under study. This is more than 4% of the new money invested into all climate tech ventures of around €67bn. Although a relatively small number of hydrogen businesses took in new money - 79 out of a European total of 2,544 fund raisings – the average amount invested was very large. The hydrogen investments (or fund raisings from sources such as government grants), averaged over €37 million per deal.

 Green steel raised just over €0.5bn in the 18 month period and low carbon cement €260m. In the case of both industries, over half of this cash was taken in in the last quarter from April to June 2022. But despite the vital importance of decarbonisation of these two sectors, in aggregate they raised only just over one percent of the total money invested in climate tech in the period. This rate of financing needs to increase rapidly.

Climate tech is concentrated in the Nordics and Estonia

The Nordic countries and Estonia have the most active climate technology sectors, expressed in terms of population size.

·      Large countries such as Germany and the UK have the most ‘climatetech’ companies. But when expressed per head of population the numbers are far higher in northern Europe. When calculated in this way, Denmark has the most businesses, followed by Iceland.

·      Similarly, the list of new fund-raisings in the last eighteen months is dominated by companies in the bigger states but Estonia and Iceland have the most number of new fundings per inhabitant.

·      Businesses in Estonia and Sweden raised most money per head of population. New funding was equivalent to over €1,000 per head of population in Estonia in the period from the beginning of 2021 until mid 2022. France and Germany were less than a tenth of this figure.

 The data.

Europe’s most complete database of young ‘climate tech’ companies produced by Net Zero Insights shows a total of almost 23,000 ventures across the continent.[1],[2] The data covers companies from Iceland in the west to Turkey in the east, covering all the EU and states such as Ukraine and Russia.

These businesses contained in the database are in sectors as diverse as greenhouse gas capture and the built environment.

The table below shows the number of climate tech companies in each sector.[3]

 Table 1

Source: Net Zero Insights

Number of companies in each country

 In which countries do the companies operate? As we might expect, bigger countries have a high share. Taken together, the UK, Germany, France and the Netherlands have over half the near-23,000 start-ups.

 The top 15 countries out of the 46 states in the database account for 90% of the companies. Portugal, the last of the top 15, contributes about 1.5% to the European total.

Table 2

Source: Net Zero Insights

 Companies per inhabitant

The pattern changes if we examine the number of climatetech companies per head of population. Smaller countries rise to the top, with Denmark being the location of 136 companies per million people.[4] Not far behind are Iceland and Estonia. 6 out of the top 10 countries are in the Baltics or the Nordic region.

The Netherlands in fourth position is the only large country near the top of the list. Ireland has slightly more companies per head than its neighbour, the UK, which doesn’t quite make the first ten. Germany is at number 15 but France, Spain and Italy don’t make the cut.

 Table 3

Source: Net Zero Insights

Companies raising money in the eighteen months from January 2021.

Over 2000 businesses in the database raised outside equity in the period from January 2021 to June 2022. That’s just under 10% of the list of companies. The UK had almost a quarter of this total, with Germany and France next on the list.

Table 4

Source: Net Zero Insights

Numbers of companies raising money, expressed per inhabitant

 But once again it was the Baltic States and the Nordics that came top of the list when the figures are expressed per head of population. Six out of the top 10 countries were from this region, with Estonia at the head of the list followed by Iceland.

 Germany was in thirteenth position, with only about a sixth of the new fundraisings per head seen in Estonia. Denmark was at position 7 for fundings even though it is top of the list of climate tech companies per head in Chart 3

 Table 5

Source: Net Zero Insights

Money raised.

 A total of over €40 bn flowed into the 2,000+ companies raising money in the January 2021 to June 2022 period. UK climate tech companies raised the most money, accounting for more than a quarter of the total funds raised in Europe. Germany came second. The UK and Germany combined accounted for almost one half of all money raised and the top five countries were almost three quarters of the total.

Table 6

 Source: Net Zero Insights

Money raised for climate tech per head of population

Estonia and Sweden are far ahead of Norway, their nearest competitor, when we look at the money raised per person. Estonia raised more than €1000 per head of population in the eighteen month period while Norway’s equivalent figure was about €330. The numbers for the rest of the top 10 concentrate around €160 a head. The UK saw more funding per head than any other large country. 4 out of the top 10 countries were in the Nordic or Baltic regions.

 Table 7

 Source Net Zero Insights

In the next few days I’ll write about the destination of the money raised. Which sectors did it go into? Which are the areas of the hottest interest to companies and their investors?

Footnotes

[1] By Europe, we mean all EU27 states and countries from Turkey to Iceland.

[2] The data in this article comes from NetZero Insights, a firm based in Lisbon. (I am a small shareholder in this company).

[3] Some companies have been allocated to more than one sector.

[4] I have excluded countries with less than 10 climate tech companies in the database. This excludes Monaco and Liechtenstein with 6 and 5 businesses respectively but tiny populations. If included, Monaco would have more climate tech companies per head than Denmark and Liechtenstein only slightly fewer.

Some important recent stories on the moves to net zero

A summary of this newsletter was published on the MegaOnline web site of Pictet, the international fund manager.

1, Electric heavy trucks. Two of the world’s most important logistics companies made further commitments to the electrification of heavy transport. Maersk announced two orders in the US for heavy ‘Class 8’ trucks. It bought 300 vehicles from the Swedish start-up Einride for delivery in 2023-25 and a smaller order from Volvo of about 110 trucks planned to arrive in 2023 for short-haul journeys. Maersk North America said its ‘long-term goal is to move toward a fully electric trucking fleet’.  Amazon said that it will have 9 DAF electric trucks in use in the UK by the end of this year. They will be charged by 360 kilowatt chargers at the company’s distribution depots, providing one of the fastest charging rates in the country. Amazon reiterated its commitment to achieving at least 50% decarbonisation of its UK transport by 2030. These orders, and others like them, strongly suggests that the logistics industry sees the future in pure battery vehicles, not fuel cell trucks.

2, Direct Air Capture (DAC). Much more money became available to develop the DAC industry. Although it admitted that its pioneering $15m Iceland plant had had reliability problems in the cold winter, Zurich-based Climeworks raised about $650m to invest in much larger carbon dioxide capture facilities. A consortium of US businesses led by payments company Stripe promised that $925m would be available to purchase carbon dioxide removal from DAC providers. The intention is to assure funders of DAC plants that customers will be available for the CO2. Also in the US, the Oxy venture 1PointFive, which is expected to build a 1 million tonne DAC plant in the next two years, sealed a deal with wood products company Weyerhaeuser to utilise CO2 storage space in geologic pores beneath a 12,000 hectare forest in Louisiana.

3, Circular electronics. German company Grover took in new investment of $300m to expand its electronics leasing business by buying more stock. Customers rent from a choice of over 3,000 items such as cameras, phones and computers for a monthly fee and are able to return the device at no cost at any point after the minimum rental period. When the goods return to Grover they are refurbished and then rented out again. At the end of life, the items are then fully recycled. Sales are growing strongly in the markets in which it operates around the world helped, the company says, by the tightening economic conditions in many countries. This ‘unicorn’ is probably the largest single circular business in the world today, operating in a sector in which only about 20% of goods have any form of second life.

4, Vertical agriculture. A disappointing moment for the fast-growing vertical agriculture industry as Paris-based Agricool ran out of money and was put into administration. Agricool grows strawberries and herbs in adapted shipping containers with LED lighting. It sold the products in local supermarkets. Container-based indoor farming can deliver very high quality products with low environmental impact but at costs much greater than conventional farming techniques. However other businesses around the world that operate urban vertical farms continue to grow. In London, for example, Crate to Plate continues to develop new urban indoor farms, aiming to grow salads and herbs within 15 minutes of everybody in the city. It announced a new venture to put a 2,500 square metre farm in the east of London and a smaller one to the south.

5, Methanol for shipping. The debate continues between those who favour synthetic methanol as the fuel for shipping and those backing ammonia. Methanol has edged ahead in recent weeks. In an important, but largely symbolic announcement, the port of Gothenburg, the largest in Scandinavia, said that it had obtained approval to store the liquid for use in vessels in the port. This will assist the port in attracting shipping able to use the fuel. Approvals for ammonia storage and use will be much more difficult to obtain because of the far greater risks. An Egyptian company promised to construct a factory that will produce 100,000 tonnes of synthetic methanol at the entrances to the Suez Canal using locally-made green hydrogen. It targets the site being operational by 2026. That should enable the business to provide methanol to the new Maersk dual-fuel container ships to be completed by that date.

6, Enhanced rock weathering (ERW). ERW is potential means of reducing atmospheric CO2. Silicate-based rocks, such as basalt, gradually react with carbon dioxide, permanently storing it in a stable form. Grinding the rocks finely and creating a much greater surface area increases the speed of the chemical reaction. Soil fertility is improved if the fine dust is spread on fields. Scientists have been pressing policy-makers to fund more research on how best to use ERW for carbon capture and fertility improvement purposes. An article/www.eurekalert.org/news-releases/950523 in Nature Geoscience by scientists at the University of Sheffield in the UK strengthened the case of ERW calculating that up to 10% of the country’s emissions could be offset by applying basalt dust to agricultural soils. A secondary advantage would be a reduction in the need for artificial fertilisers.

7, Sustainable aviation fuel. Cemex, the Mexican cement producer, will build a refinery to make synthetic kerosene at one of its plants in Germany. The process will collect CO2 from cement making and combine it with green hydrogen in the standard Fischer Tropsch reaction. Cemex is partnering with Sasol, the South African specialist in synthetic fuel and with Enertrag, a German renewables developer.

8, Power to gas. Companies on the Iberian peninsula are among the leaders in commercialising the large scale use of renewable electricity to make hydrogen and other zero carbon products such as ammonia. One recent new project at Sines on the coast of Portugal  announced last month will make 50,000 tonnes of hydrogen and 500,000 tonne of ammonia from locally solar and wind power in a €1bn project. This is one of the many examples around the world of ‘hydrogen hubs’ at ports; hydrogen will be made centrally, some will be used locally and most exported in the form of ammonia. These hubs are not just being planned for Europe; a local renewable energy supplier and a Belgian electrolyser manufacturer plan a 2 gigawatt plant on the east coast of India, partly to replace natural gas imports.

9, The costs of carbon capture (CCS). Two of the oil majors said that they expected the market for carbon capture to be around $4 trillion by mid-century. Exxon Mobil upped its estimate of the CCS market to $4 trillion from half that level a year ago. Occidental put the figure at $3-5 trillion. These estimates are about 4% of current world GDP. Expenditure of this money would allow them to continue extracting fossil fuels much as at present. No other companies or institutions think this route will be lowest cost way of obtaining the world’s energy and getting to net zero.

10, Biochar. Net Zero, a French startup developing biochar production factories for tropical countries, won $1m from the X Prize, a competition funded by Elon Musk. Agricultural wastes are heated to very high temperatures in the absence of oxygen, leaving almost pure carbon. The carbon is stable for hundreds of years in soil. Two other biochar startups were also among the 15 winners, one in Kenya and one in the US. Biochar is identified as one of the most promising techniques for permanent carbon removal from the atmosphere and has the advantage of also improving acidic soils and reducing the need for fertilisation. The  carbon content of biochar can be measured relatively accurately and easily, making it very suitable for carbon offsetting schemes.

Getting 5 million tonnes of hydrogen from Australia to Germany

The MOU (memorandum of understanding) between the huge German utility E.ON and Australia’s Fortescue Future Industries (FFI) promises ‘up to 5 million tonnes per annum’ of green hydrogen delivered to Europe by 2030. This will provide the energy to replace about one third of Germany’s energy imports from Russia. Andrew Forrest, FFI’s leader, continues to take by far the largest role in pushing for a hydrogen future around the world.

If the ambition is realised – and the details are sufficiently sparse in the press release to suggest that the project is not yet fully thought out  – the implications for the growth of hydrogen are very striking.

·      If the green hydrogen is produced by water electrolysis using solar electricity, this single project will require about 150-180 gigawatts of new PV capacity. That is about 5 times the UK’s entire renewable generation fleet, principally solar and wind[1]. Total global solar installations are running at just over 200 gigawatts this year so the FFI requirements are equivalent to about 10 months of world PV additions.

·      The amount of electricity required will be just over half the UK’s current electricity supply or approximately half of one per cent of world power generation.

·      The FFI production sites will probably install large scale battery capacity and I make a guess that this will mean that the electrolysers can run 50% of the hours in the year. This implies that the FFI sites will need about 80 gigawatts of electrolyser capacity. There’s probably less than 1 gigawatt of water electrolysers working in the world today. The EU has an ambition for 40 GW by 2030 or about half the FFI target.

·      The electrolyser demand for this project alone would use up all the manufacturing capacity of the industry in 2029, at least according to a simple spreadsheet I use. 

·      The total hydrogen produced today in North West Europe is about 3.5 million tonnes, meaning that the E.ON/FFI project will more than double local availability.

·      There is, I think, only one vessel operating today that is capable of shipping liquid hydrogen. The Suiso Frontier is newly commissioned and was built to travel between Australia and Japan. It carries about 75 tonnes when fully loaded. Assuming a five week journey time, the project would need at least six thousand ships of this size. Of course the actual vessel size will increase enormously between 2022 and 2030 but the need for investment now in building hydrogen-compatible shipping is clear. One thing we should be clear about: hydrogen carriers will be highly specialised ships that require very careful engineering.

·      One estimate is that transporting liquid hydrogen by ship will add about $1 per kilogramme to its cost. This means that the end user will need to pay about 3 US cents per kilowatt hour of energy, just for transportation. That alone is more than 50% more than the typical price of natural gas in Europe before the current crisis. The transition to hydrogen isn’t going to be cheap and, incidentally, it would be much cheaper to create the hydrogen in North Africa and then transport it by pipeline to Germany.

·      There are currently no Liquified Natural Gas (LNG) terminals in Germany although construction of one is now planned. Germany has therefore no experience in bringing in liquid gas for distribution into the natural gas grid. 

·      In all probability, much of the hydrogen will arrive into Rotterdam. Rotterdam and Antwerp have done more than any other European ports to prepare for the growth of hydrogen. But the scale of import for the FFI project will be challenging to manage. The port says it will be able to take hydrogen off carriers and put into a pipeline network that will take it to North Rhine Westphalia, but only in 2030. FFI will have to get Rotterdam to speed up its hydrogen investment. 

·      Once in Germany, natural gas pipelines will need to be refitted to carry hydrogen. This is possible and widely discussed among the main gas networks in Europe. But it will require major investment and a clear decision to quickly phase out natural gas that would otherwise occupy these pipelines. The amount of energy to be produced by FFI for E.ON would require about two standard ’48 inch’ pipelines for the 5 million tonnes of hydrogen to be transmitted to users in Germany. It seems possible, but will require billions of Euros of investment.

The world’s future is now dependent to a striking degree on FFI’s ability to push forward its many hydrogen projects forward around the globe, of which the E.ON scheme is just a small part. Andrew Forrest’s commitments to decarbonisation are clear but the scale of his ambitions may exceed the company’s ability to finance his projects. He needs to work with the large oil and gas companies to take his work forward as fast as possible.

[1] I have assumed that H2 is transported in liquid form and made an allowance for the high energy costs for liquefaction. Hydrogen, or its derivative ammonia, will also probably be used to power the ships that transport the energy.

Newsletter summary for January and February

I wrote a summary for Pictet Asset Management of what I thought were the most interesting stories from my newsletter over the past couple of months. The text is below and on the Pictet web site

From introducing a new breed of trees to the UK to help absorb carbon to powering planes with hydrogen, here is a round-up of some of the most interesting climate change-related stories from the past month.

1. Synthetic fuels for aviation. Several ventures have announced the location for their first synthetic fuel plants, principally making aviation kerosene. These will all need CO2 and green hydrogen. In Norway, Norsk eFuels and direct air capture specialist Climeworks said they would build a refinery in the north of the country where electricity is abundant, allowing green hydrogen to be created and CO2 to be captured inexpensively. The Dunkerque plant of ArcelorMittal will host a factory for Engie and the US start-up Infinium to make fuels from hydrogen and steelworks CO2. Near Porto, Veolia and its partners will build a plant using carbon dioxide from municipal waste. Sasol and Engie joined with German pioneer Ineratec to make fuels in Frankfurt using the CO2 in agricultural biogas.

2. Carbon sequestration in trees. A crowdfunding site in the UK is raising the money for the conversion of a 200 hectare portion of a large arable estate with deteriorating soil quality into woodland growing paulownia, a fast-growing Asian hardwood. This will be the first such plantation in the country. The German plant nursery supplying the sterile and non-invasive young trees says that paulownia will sequester carbon in many soils at ten times the rate of native oaks. The timber can be employed in a wide variety of non-structural uses such as furniture. The UK is the least forested large country in Europe and has struggled to increase the rate of tree planting. Paulownia hardwood may make the task of converting degraded arable land into productive forest much easier.

3. ‘Dispatchable’ green electricity. Solar and wind are intermittent. The first renewable sites are planned which will use hydrogen generated from surplus electricity to provide power when wind and sun are not available. Two are being developed by consortia linked to Hydrogène de France. One is in the French territory of Guiana and the other on the island of Barbados. In both places, night-time power will be provided by a fuel cell that uses hydrogen made from electricity from the previous day.

4. Heat pump sales. Decarbonisation of high latitude countries, in Northern Europe for example, depends on finding alternatives to natural gas for domestic and commercial heating. Heat pumps will provide a large part of the answer, converting low carbon electricity into over three times as much heat for buildings. Across Europe, sales have begun to increase very sharply in recent years. In 2021, volumes rose by a quarter and now account for over 25 per cent of all heating installations. Individual markets saw much faster growth. For example, numbers in France and Poland rose by 52 per cent and 66 per cent, respectively.

5. Steel made using hydrogen. One of the world’s largest steel producers, ArcelorMittal, started the long process of switching to hydrogen as a replacement for coal. Within the last few months it has obtained major subsidies in France, Spain and Canada to speed up the transition away from blast furnaces and towards hydrogen direct reduction. (France alone provides about 14 per cent of ArcelorMittal’s global steel output.) Recent moves by major European steelmakers - and Asian manufacturers such as Posco - towards the use of direct reduction have been encouraged by growing evidence of strong demand for green steel from major customers, such as car companies. BMW, for example, recently said that it wanted 40 per cent of its steel to come from low carbon sources by 2030. 

6. Chemical recycling. The small percentage of plastic that is recycled is almost invariably treated mechanically, for example by cutting it into small pieces. The resulting product can usually only be used in lower value applications. But chemical recycling breaks down the polymers in plastic, recreating the original monomers. The plastic can then be remade with no loss of quality and can be used to make the original products. Two large projects were announced in France. One, led by the US chemical recycling leader Eastman, will recycle polyester in what will be the world’s largest plastics reprocessing plant. The second will use technology developed by French pioneer Carbios to use enzymes to break down PET. These are early but important steps towards building a fully circular plastics economy. The long-term implications for the oil refining business, which sees plastics as its biggest source of future growth, have not yet been fully calculated.

7. Taking responsibility for supply chain emissions. Large corporations are putting increasing pressure on their suppliers to reduce emissions. These businesses are aware that getting to zero carbon in their own operations (‘Scope 1’ and ‘Scope 2’) means nothing if large greenhouse gas emissions result from their supply chain or from customer use (‘Scope 3’). International brewer Guinness started a programme that will result in more carbon being retained in the soils of barley suppliers in Ireland. My rough estimate is that this programme of ‘regenerative agriculture’ might offset one sixth of its total supply chain emissions. Drug company AstraZeneca says that its Scope 3 emissions are 20 times those caused by its own operations. A surprisingly large part of AstraZeneca’s wider carbon footprint arises from the propellant gases used in inhalers for asthma and lung diseases. AstraZeneca finally announced a near-zero carbon replacement.

8. Fossil fuels out of favour. I picked up three very different decisions to cease working with high carbon companies. Danish bank Nordea said it would stop lending to offshore oil. COWI, an international engineering consultancy, said it will take on no more projects for fossil fuel companies. And Eastern Pacific Shipping, a large operator of vessels transporting bulk commodities, promised it would no longer ship coal. Software billionaire Mike Cannon-Brookes took the opposite line, bidding with a Canadian investment fund to buy AGL, a large Australian utility. His purpose is to increase the speed of AGL’s move away from using coal for power generation while raising the growth rate of renewable capacity.

9. Metals shortages. The respected energy commentator David Roberts addressed whether inflation in ‘green materials’ was likely to continue. He concluded that concerns over long-run availability of metals and other raw materials for the energy transition were not warranted. Prices should eventually stabilise. Nevertheless David Roberts also stressed that most minerals are mined and processed in a small number of countries, making future supply chain problems highly likely.

10. The growth of hydrogen. Leading electrolyser manufacturer NEL produced its results for the final quarter of 2021. Among the many interesting numbers it said that its sales pipeline had doubled to 22 gigawatts during the course of that single 3 month period. The total installed volume of electrolysers for making clean hydrogen in the world today is probably less than 1 gigawatt. The growing interest in hydrogen is often still dismissed as ‘hype’. Not so; NEL and other manufacturers are showing that hydrogen will have a large role in world energy.