The UK rightly deprioritises early CCU

The UK government has decided that CCU projects should not be eligible for early rounds of industrial CCS projects support contracts.  This looks like the right decision.

Carbon capture and use (CCU) is an appealing concept in some respects.  Carbon capture and storage (CCS) adds the costs of transport and geological storage to the costs of capture. In contrast, CCU is intended to make captured CO2 a valuable product, replacing costs with a revenue stream.  The main use of captured CO2 to date has been for enhanced oil recovery (EOR) in North America.  In the UK, including there is a range of potential applications including making building materials, lime, food and drink and e-fuels.  CCU may be particularly attractive for capture sites away from large industrial clusters that have limited access to transport and storage.

Some CCU projects, for example, aggregates manufacture, result in the permanent abatement of CO2, where the carbon is permanently stored in the product and not subsequently released.  However many CCU projects, including food and drink and e-fuels, lead to only the temporary abatement of CO2, as the carbon is ultimately emitted to the atmosphere.  The latter are not compatible with reaching net zero emissions.  EOR also leads to new emissions.  The CO2 injected into the reservoir to drive out additional oil stays there, or can be almost completely recovered and reinjected. However the additional oil recovered will typically be burnt without capture, creating additional emissions (although this may only displace other oil).  

CCS and CCU are intended to play a role in the UK reaching net zero.  In this context, the UK government has envisaged supporting CCU when it results in the permanent abatement of CO2 emissions, excluding use where CO2 eventually returned to the atmosphere.   

However further work has led the government to conclude that, although some forms of funding may be available to CCU, only CCS projects will be eligible for support under the industrial carbon capture business model, which provides support contracts for projects[i].

 They give three reasons for this.

The need to gather more evidence

They suggest that further evidence is needed on the market potential and costs of CCU to understand what barriers the market faces, the detailed technical application of CCU, the technological and commercial readiness, and the economic potential of CCU. They note that until these issues are understood, there will be uncertainty over what form of government support is the most suitable for CCU projects.

Additional commercial and technical complexity

The application of CCU could involve additional commercial and technical complexities to the business model that would need to be worked through in detail before support is provided. For example, the business model would need to take into account a number of considerations specific to CCU projects, including the revenues gained if the CO2 captured is sold, and monitoring the end-use of CO2 to ensure the captured carbon is permanently abated.

Prioritising support for the deployment of CCS

There is a focus on incentivising large-scale abatement of CO2 and the establishment of transport and storage infrastructure essential for net zero. CCU resulting in the permanent abatement of CO2 potentially represents only a very small abatement potential when compared to CCS.

Essentially the overall view is an argument that:

  1. Only CCU projects that result in CO2 being kept permanently out of the atmosphere should be eligible for support
  2. These are too small as a proportion of total emissions to merit the additional effort and complexity they would lead to at the moment.

Both these arguments seem sound.  The first point will always apply.  On the second, those CCU projects which include permanent abatement may be worthwhile at a later date.  But for now the focus should be on getting large scale CCS projects built.

Adam Whitmore – 23rd November 2021


[i] https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1023095/icc-business-model-october-2021.pdf

Defining low carbon electrolytic hydrogen

Hydrogen made by electrolysis is only low carbon if made when there is surplus low carbon generation on the system.  This will likely become much more common in future. Deployment of electrolysers in the meantime should focus on developing capacity for future deployment, for example by developing electrolysers capable of running flexibly.   

The UK government recently consulted on defining a standard for low carbon hydrogen[i].  Similar discussions are taking place elsewhere, including in the EU.  However these discussions have generally failed to deal adequately with the problems associated with diverting scarce renewable electricity to make hydrogen.

Using renewable electricity to displace fossil generation achieves much greater emissions savings than making hydrogen by electrolysis, and is much cheaper.  Using renewables to displace gas in power generation leads to around two and a half too three times the emissions savings from making hydrogen to displace natural gas in industry, either in boilers or direct combustion (see my previous post for more comparisons of this type). This because of:

  • The energy losses in making hydrogen.
  • The lower efficiency with which gas is used in power generation (and thus the greater gains from displacing it).

This is shown in simplified form in the chart below.

Charts 1:  Comparison of emissions avoided by displacing electricity from natural gas in CCGT and in heat for industry

Abatement using hydrogen to reduce emissions is also much more expensive per tonne of emissions reduction.  This is both because of the cost of making the larger amount of renewable energy required per tonne of savings, and the cost of the electrolysis.  These comparisons will not change fundamentally as technology improves.  For example, electrolysis will always be an additional cost.

This implies that diverting renewable electricity to make hydrogen increases both emissions and costs.  

In practice, renewables will be diverted as long as there is fossil generation on the system.  This is almost always the case at present.  Low carbon electricity (nuclear and renewables) is low marginal cost, so will almost always run at full capacity ahead of higher marginal cost gas plant.  Consequently, when an electrolyser is switched on, the additional demand leads to additional natural gas generation, because there is no unused low carbon generation available to run.  Correspondingly, when an electrolyser is switched off natural gas generation is reduced.  The emissions from the electricity used in hydrogen production are therefore those from a natural gas plant.

The relevant consideration is thus the marginal plant on the system – the additional plant that runs when electrolyser is switched on.  One implication is that reducing grid average carbon intensity at any point in time does not change the emissions from hydrogen production while natural gas plant is at the margin.  For example, whether the system is running at 50% or 75% low carbon power, additional emissions will still be caused by switching on electrolysers. This is illustrated in the chart, which shows additional demand from electrolysers must be met by additional high carbon power, when there is no surplus of renewables.

Chart: Running electrolyses increases generation from high carbon power

Calling renewables for hydrogen additional, signing PPAs, looking to guaranties of origin, and similar measures do not change this physical reality.  Renewables are still diverted from displacing fossil generation.  For example, it is sometimes specified that renewables for hydrogen production must be “additional” for hydrogen to be low carbon.  However “additional” renewables for hydrogen manufacture still suffer the same problems, because even if labelled “additional” renewables still diverted from other potential uses. The electrolyser can be switched off and the renewables used to displace fossil generation on the grid. 

Even when there is a grid constraint or lack of grid connection it will usually be much cheaper, and yield much greater emissions savings, to rectify this than to make hydrogen. These circumstances will be rare in any case. Most new renewable electricty in the UK will be offshore wind, so will have good connections to the onshore grid.  Furthermore, electrolysers are unlikely to be situated far from the, grid as they will need to be close to centres of hydrogen demand, for example powering fuel cell buses or industry.  Indeed creating standards based on lack of grid connection risks creating perverse incentives to disconnect from the grid.

Provision of a PPA does not materially change the situation.  The PPA is financed from the support contract with funds from the government.  Financial support for hydrogen could instead be used to build extra offshore wind capacity directed to decarbonising the grid. (This would not apply in the same way if hydrogen production were unsubsidised, and in that case a genuinely additional supply of renewables may be created.) And funds freed up from avoiding the other costs of producing hydrogen can be used to fund yet more renewable capacity, further increasing the benefits. 

There are several ways in which additional renewables could be sold into wholesale markets.  For example:

  • Funds could be spent on developing new renewables to serve wholesale markets rather than electrolysers – recognising the greater value this has for abatement.
  • Selling power from the electrolyser PPA into the grid.  It may be possible to prevent this by terms in the contract, but this would not be justified on emissions savings or cost grounds.

When there is surplus low carbon electricity, for example because there is a large amount of generation from wind when demand is low, there will be little no natural gas generation on the system.  In this case switching of electrolysers will absorb this surplus without leading to additional natural gas generation.  The hydrogen is then genuinely being made using low carbon power.  This situation is currently rare but expected to be much more common over the next decade or so.

The reality is that making hydrogen from electricity is only low carbon when there are surplus renewables on the system.  At all other times there will be additional natural gas-fuelled generation as a result of the hydrogen being made.  This point was made in a recent report by respected consultants Element Energy:

“To be truly using renewable electricity, the electrolysers must not be diverting existing renewable electricity production from other sources of demand. Electrolysis performed using curtailed renewable generation is zero carbon.[ii]

 A low carbon standard should recognise this.

Furthermore, policy choices should be made in the light of this reality. They should focus on enabling deployment at scale in the 2030s (and perhaps late 2020s) when there will likely be significant amounts of surplus renewable electricity.  Any investment in electrolysis in the meantime should recognise that electrolysers currently increase emissions, and are justified only as part of a pathway to future use.  For example, there will likely be a large scale demand for electrolysers that can run flexibly enough to take advantage of periods of surplus renewable electricity.

The priority for both reducing costs and increasing emissions savings must always be to use renewables to displace fossil fuels in power generation.  Renewable electricity should not be diverted to making hydrogen.  The only exception to this now should be deployment of electrolysis to develop technologies and infrastructure necessary to enable future deployment at scale.  This recognises that the hydrogen produced is high carbon, but regards this as a necessary investment to serve future needs.

Adam Whitmore – 27th October 2021 


[i] https://www.gov.uk/government/consultations/designing-a-uk-low-carbon-hydrogen-standard

[ii] http://www.element-energy.co.uk/wordpress/wp-content/uploads/2021/08/Zemo-Low-Carbon-Hydrogen-WTT-Pathways-full-report.pdf

Prioritising use of renewables

Using renewables in different ways produces very different emissions reductions. 

Use of renewables will be central to decarbonising most parts of the energy system.   But the amount by which each MWh of renewables reduces emissions varies greatly across sectors and applications.

This is illustrated in the chart below.  It shows the number of tonnes of emissions reduction from using 1MWh of renewables in various ways. The Climate Change Committee (CCC) has produced similar estimates (see end of this post), although for a slightly narrower range of uses. 

There is clearly significant variation around each of these values.  Estimates depend, for example, on efficiency of a fossil fuelled power plant, or the emissions from the petrol or diesel car that is being displaced by an EV.  And there may be changes over time as technologies improve, although some of these technologies are limited by the fundamentals of their processes.  Nevertheless, the broad picture is likely to remain similar. 

Chart:  Emissions savings from using 1MWh of renewables for various applications

Note:   The use of renewables will usually focus on electricity but in some cases may include a component of renewable heat. 

The chart shows that directly replacing fossil fuels (coal and gas) in power generation is highly effective in reducing emissions. Coal will be eliminated from power generation in the UK by 2025, but some UK renewables may displace coal plant elsewhere if exported, so coal in power generation is included on the chart.  Highly efficient end use applications, such as heat pumps and electric vehicles, also deliver large reductions per MWh. Carbon Capture and Storage (CCS) is an especially effective use of energy, because the energy is dedicated to capturing and permanently storing CO2 from flue gases, although there are of course other costs. 

Other applications of renewables are less effective.  Replacing natural gas with electricity for industrial heat, making “green” hydrogen by electrolysis for use in boilers, and Direct Air Carbon Capture and Storage (DACCS) all achieve smaller amounts of emissions reduction per MWh of renewables.  Least effective of any of these approaches is the manufacture of e-fuels, where green hydrogen is combined with CO2 to make liquid hydrocarbons using renewable electricity.   Making e-fuels results in up to thirteen times less emissions reduction per MWh compared with the other options. 

Implementing options producing less abatement per MWh risks diverting renewables away from those that produce more abatement, hampering overall emissions reductions efforts.  This risk applies for as long as availability of renewables is limited, which seems likely to be the next couple of decades at least given the vast scale up of renewables deployment that is needed (see previous post).

Those options to the right of the chart will require very abundant, and preferably very cheap, renewable energy if they are to make a significant contribution to total emissions reduction.  This is still many years away, and most likely to be where there is a good solar resource, though economic e-fuels production still seems likely to be some decades away at best.  Among other things there are limits to efficiency gains in e-fuels manufacture – making hydrogen then combining it with carbon dioxide to make fuel is intrinsically energy intensive.

A complementary perspective to Marginal Abatement Costs

This perspective is a useful complement to looking at cost per tonne of abatement, usually summarised in a marginal abatement cost (MAC) curve.  A MAC curve is a valuable guide to where there are low cost opportunities available, although policy needs to focus much more widely than on the cheapest abatement.  However, technological progress can lead to abatement costs falling over time, as for example they have spectacularly in the case of solar PV over the last ten years.  Furthermore, interactions across the system may change feasibility, costs and practical scale of available options. A variety of perspectives can help understanding the possible effects of changes, and so can contribute to mapping out more robust pathways and identifying the likely contributions of different options.

The perspectives anyway often indicate similar conclusions.  A high renewables requirement is reflected in high abatement costs.  Estimates of abatement costs are typically £550-1200/tCO2[i]or more for e-fuels, an order of magnitude more than CCS, at around £60-100/tCO2[ii]

Specifying “additional” renewables does not remedy the problem of high renewables use

In apparent recognition of this problem of diverting renewables from more productive abatement, it is sometimes specified that renewables for some applications must be “additional”.  However “additional” renewables still face the same issues, because they still divert renewables from other potential uses. Any funds used to build renewables for less effective abatement could instead be used to build renewables for more effective abatement.

What about surplus renewables? 

There may increasingly be times when electricity demand is met entirely from nuclear and renewables, and there is surplus low carbon power on the grid.  This may imply that all available sources of demand for renewable electricity have been fulfilled.  The surplus low carbon electricity could be applied in various ways.  However there will still be choices to  be made, because there will be alternative uses for the (limited) surplus on the system.

Can’t this all be left to the (carbon) market to sort out?

Many of these issues can be addressed to some extent letting by carbon markets do their job of finding least cost abatement.  However at present many technologies are at an early stage, and subsidies for early deployment are in place or planned.  In the UK these include contracts for industrial CCS, contracts for low carbon hydrogen, contracts for renewable electricity, a mandate for renewable fuels in surface transport and a mandate for sustainable aviation fuels.  Such measures have a strong rationale in principle, because carbon markets alone will not produce adequate deployment of new technologies.  However deciding which technologies to support and by how much inevitably means choices need to be made, and the sort of analysis presented here can be useful in helping form such judgements.

Carbon markets have a crucial role to play.  But early stage deployment requires a range of factors to be addressed in deciding where support for new technologies is best directed.  This should include the quantity of emissions reduction using renewables.

Adam Whitmore – 27th September 2021

Analysis by the CCC

The UK’s Climate Change Committee (CCC) has produced similar estimates to those presented here, though covering a somewhat smaller range of options[iii].  The relative performance of the options and the approximate savings are similar in the two pieces of analysis.  However the analysis in this post indicates somewhat less abatement per MWh in many of the cases, which appears to reflect more cautious assumptions.  

Notes


[i] Costs are currently highly uncertain due to the variety and early stage of development of the technologies.  Early stage estimates for other technologies have often been subject to appraisal optimism, understating the costs of early projects.  A recent article in Nature Climate Change included estimates of €800–1200/tCO2 at present.  https://www.nature.com/articles/s41558-021-01032-7?proof=t Other cost estimates show a range of e-fuel costs of £2000-4000/tonne, which is approximately £550-1100/tonne CO2 reduction. https://www.transportenvironment.org/sites/te/files/publications/2017_11_Cerulogy_study_What_role_electrofuels_final_0.pdf   ICCT estimates e-fuels costs of at least €3-4/litre by 2030 (approx. €3750-5000/t).  The potential for cost reduction is strongly dependent on the costs of the renewable energy needed for manufacture. 

[ii] CCS costs vary significantly because projects differ greatly, for example in the concentration of the CO2 being captured and the distance that the captured CO2 needs to be transported.  There are also few industrial capture projects yet operating, implying uncertainty in addition to the variety of costs.  The CCS cost estimates shown  are based on a range of sources, including recent IEA assessment, https://ieaghg.org/ccs-resources/blog/new-ieaghg-technical-review-towards-improved-guidelines-for-cost-evaluation-of-carbon-capture-and-storage, and estimates from GCCSI https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.  The upper end of the range for capture costs is provided by the Longship project, which is likely to be expensive due to project specific factors (transport and storage costs are assumed to be lower than for Longship).

[iii] https://www.theccc.org.uk/wp-content/uploads/2020/12/Sector-summary-Electricity-generation.pdf  See figure M5.4.

Transforming the world’s energy system with solar and wind

Recent analysis confirms the very large increases in solar and wind generation required to decarbonise the energy system by 2050.  Achieving this growth will require large scale investment in grid infrastructure and system balancing.  This is turn will require the right policy support.

An order of magnitude increase in build rates of solar and wind power is needed between now and 2050 …

All informed analysis of decarbonising the world’s energy system shows solar and wind power playing a central role.  For example, recent modelling published by the Energy Transition Commission (ETC)[i] shows electricity meeting around 85% of global energy demand by 2050.  This includes direct electrification and also “indirect electrification”, using hydrogen made by electrolysis, with some of the hydrogen used as ammonia.   Electricity is expected to be mainly from renewables, with nuclear having only a limited role due to high costs and lack of acceptance.  The remainder of the energy mix is expected to be mainly biomass with some use of fossil fuels with CCS.

The analysis emphasises the need for rapid scale up of deployment of renewables, mainly solar and wind (see chart).  In the 2020s the rate of installation of solar and wind must be more than double 2019 levels.  Further increases are required thereafter, reaching more than ten times 2019 rates of installation in the 2040s. The implied compound average growth rate of cumulative installed capacity is approximately 11% p.a. for wind and 13-14% p.a. for solar.  (Note: I published similar analysis in December last year, with largely consistent conclusions.  A comparison is included at the end of this post.)

Chart:  Increase in installation rates for wind and solar

Source:  Energy Transition Commission

Extensive supporting investment will be required to achieve this growth …

This growth in generation appears achievable, although to strong policy drivers will continue to be needed.  However increasing rates of deployment of generation, while essential, are not enough.  A large amount of investment in different types of infrastructure will be needed to make sure that the system balances and electricity is available when required. This includes the following.

  • A mix of renewables – wind, solar and hydro, which have different patterns of production.
  • Increased interconnection to help deal with variation in output from renewables.  For wind, variations within a continent can be large, so links across moderate distances help.  However, with solar, greater resilience may require interconnection over multiple time zones using HVDC (High Voltage Direct Current) transmission lines.  This is because solar output is strongly dependent on time of day, with similar longitudes having correlated output (night is at about the same time). 
  • Dispatchable plant, for example using natural gas with CCS may play some role on systems, although residual and lifecycle emissions will be an issue in many cases.
  • Oversizing the generation relative to peak demand, gives a greater probability of meeting peaks even if output is not at maximum.  This is made easier by falling costs and the availability of storage for surpluses.
  • Demand side flexibility, especially reductions in demand from industry.

However even with these measures in place there will be a substantial need for daily, weekly and seasonal storage.

  • Falling costs of batteries will allow them to play a major role in daily balancing, though likely not over much longer timescales.  There may be a role for batteries in electric vehicles to support grid, but their role remains unclear.
  • Pumped hydro will also help daily and weekly balancing.  Compressed air storage may also play a role.
  • Other hydro will become a very valuable balancing source, for example week to week.
  • Hydrogen generated by electrolysis and then converted back to electricity may have an important role to play both weekly and seasonally.  The ETC analysis shows it as the most cost effective approach for week to week balancing.  It is inefficient due to the losses in conversion of electricity to hydrogen and back again, with a cycle efficiency of only around 35%.  However, this is similar to the efficiency considered normal for coal-fuelled electricity for decades, and should be sustainable if the electricity is cheap enough.  The balance between this and power generation from natural gas with CCS remains unclear, but the relative importance of hydrogen is likely to increase strongly over time.

All this will require large investments.   However with the costs of renewable electricity continuing to fall, renewables should remain cheaper than fossil generation, even allowing for these wider costs. (This excludes the costs of electrifying end use – for example the installation of heat pumps for residential heating will require large capital investments.)

With policy needed to make investment happen …

Making these investments happen will require farsighted regulatory and policy measures to be put in place.  This is partly about removing barriers to infrastructure, such as grids and storage.  In particular building transmission grids at scale is essential, but has too often in the past been a very lengthy processes due in large part to permitting issues.  The inability to build sufficient electricity transmission capacity in Germany has hampered its decarbonisation, for example. But it is also about new commercial arrangements, including electricity pricing and trading arrangements appropriate for a system with a large amount of variable, zero marginal cost capacity. 

What exactly these measures should be I will return to in future posts.  But it is clear that without further measures it will be difficult or impossible for renewable generation can grow at the required rates.  The urgency and scale of action required should not be underestimated 

Adam Whitmore – 15th June 2021

Comparison of modelling

The ETC analysis quoted here has similar assumptions and reaches very similar conclusions to that which I published in a post on this blog late last year, although the two sets of analysis were carried out entirely independently.  A summary comparison is provided in the table below.  Both pieces of modelling envisage somewhat greater electrification than assumed in scenarios by IRENA and BNEF.

AssumptionsThis blog (December 2020)[ii]ETC analysis reported in this post
Total final energy demand in 2050  (000 TWh)102 (sensitivity  127)99 – 137
Percentage electricity of final energy80% (range 70 – 85%)85%*
Electricity consumption in 2050 vs. 2019 (factor higher)3 – 43.5 – 5
Percentage wind and solar of electricity80% (range 70 – 90 %)75 – 90%
Annual installation rate of wind and solar 2020-2050 as a factor of 2019 rates for net zero by 20507 (range 5 – 11)2 to approximately 14, growing over time
Compound annual growth rate of wind and solar installed capacity 2020-205011-12%11% wind, 13-14% solar

* The ETC analysis shows electrification comprising 68% direct electrification, 15% electrolytic hydrogen and about 2% ammonia. My analysis did not separate out direct electrification, hydrogen from electrolysis, and ammonia from hydrogen. 


[i] https://www.energy-transitions.org/publications/making-clean-electricity-possible/

[ii] https://onclimatechangepolicydotorg.wordpress.com/2020/12/14/a-further-huge-scale-up-of-solar-and-wind-power-is-needed/

The errors of e-fuels

Synthetic hydrocarbon fuels made using captured CO2 are likely to be worse for the climate than conventional oil products, because the renewable energy used for their manufacture would be better used reducing emissions. 

This post looks at synthetic hydrocarbon fuels made from combining hydrogen and CO2 – either fossil CO2 captured from an industrial process or CO2 captured directly from the air.   (It excludes fuels made from biomass or other biogenic feedstock, which raise different issues.) These fuels (usually called e-fuels) are very similar to conventional oil products such as diesel, so they can be used in a very similar way. 

However in practice e-fuels offer few if any climate benefits over using conventional oil products.  Indeed they are worse for the climate, because their manufacture requires vast amounts of renewable electricity that would be better used elsewhere to reduce emissions. 

Burning e-fuels has similar emissions to burning conventional oil products – by design they are very similar products.  If e-fuels are made from fossil carbon captured from an industrial process they end up putting that fossil carbon into the atmosphere when they are burnt.  This is not compatible with a net-zero economy[i]

In practice using e- fuels is even worse than this simple comparison implies.  Their manufacture uses huge amounts of renewable electricity[ii].  All this energy is used in just recreating a product already found in nature.  The renewable electricity could be put to much better use reducing emissions elsewhere – renewable electricity will be scarce for the foreseeable future because of the huge scale-up needed to displace existing fossil fuel use. 

This makes e-fuels worse for the climate than conventional oil products: they have similar emissions, but making e-fuels diverts large amount renewable electricity from reducing emissions elsewhere. 

Instead of using fossil CO2 that has been captured from an industrial process, some proponents of e-fuels make their case based on use of CO2 captured directly from the air (Direct Air Capture – DAC)[iii],[iv].  However, again this makes no sense.

Making e-fuels with CO2 captured from the air is roughly carbon neutral, but so is burning conventional fuels and removing CO2 from the atmosphere using DAC with permanent storage (usually referred to as DACCS).  Capturing a tonne from the air then emitting a tonne from e-fuels is simply equivalent to emitting a tonne from conventional oil products, then capturing that tonne and permanently storing it (see Figure below). It achieves this same result – approximate carbon neutrality – using either e-fuels or conventional hydrocarbon fuels. In both cases it’s the DAC that makes the cycle carbon neutral.  But, again, much greater amounts of renewable electricity are required in the case of e-fuels, with no compensating climate benefits over conventional oil products.  It would be better to use the additional renewables elsewhere, including additional DAC if necessary, which although expensive would at least take more carbon out of the atmosphere.

Much better is DACCS without any use of hydrocarbon fuels.  This is carbon negative, with net removal of CO2 from the atmosphere – likely to be a crucial long term need.

Figure: Comparison of various uses of Direct Air Capture

Furthermore, DAC is itself very expensive and energy intensive, requiring yet more renewable electricity.  It likely to remain so due to the low concentration of CO2 in the air – about a factor of 100 less than in a typical exhaust gas at a factory or power plant.  This is likely to make any approach using DAC difficult and expensive over at least the next two or three decades.

A comparison with enhanced oil recovery (EOR) illustrates the problems with e-fuels. A tonne of CO2 captured from the air can be used to make e-fuels, or to produce conventional oil by injecting the captured CO2 into an oil reservoir to recover more of the oil. These approaches make similar products, and therefore have similar emissions, but the EOR route uses much less renewable energy. The energy can instead by used for reducing emissions or additional DAC. (To be clear, I am not advocating EOR, simply suggesting in had advantages over e-fuels.)

E-fuels are simply not a good way to reach net-zero.  We need to focus on real solutions, including using renewable electricity wisely.

Adam Whitmore – 18th May 2021


[i] A recent article in Nature Climate Change made this point, but did not go on to make the comparison with continued burning of fossil fuels. 

https://www.nature.com/articles/s41558-021-01032-7.epdf?sharing_token=WNMrraktjyxydmZ37t5XrtRgN0jAjWel9jnR3ZoTv0NvvcjgkZX46JlO7Nfw7zfyvoADBvTOq9WIfhdmgV2dg_Zm-ooRIvDUajySVOgslfK-wkOrhQeaskxdoHd9CQkDKrEyWaG7Nek-etV6-wjBn0LukVZpsV7ZIbuxiMdSO6Q%3D

[ii] The huge demand for renewable electricity will remain even if technology improves.  This is because manufacture of e-fuels is intrinsically energy intensive, as CO2 is such a stable molecule.  Conventional oil refining also uses energy, but much less than making e-fuels. 

[iii] https://www.bosch.com/stories/synthetic-fuels/

[iv] https://www.rolls-royce.com/media/our-stories/discover/2021/e-fuels-powering-climate-neutral-future.aspx

Progress on carbon border adjustments in Europe

The recent vote in the European parliament shows it to be strongly in favour of introducing carbon border adjustment mechanisms (CBAMs) for sectors covered by the EUETS.

On 10th March the European Parliament passed a resolution on the design of a WTO-compatible EU carbon border adjustment mechanism (CBAM)[i].  The vote was non-binding.  However it shows where the debate has reached. 

Perhaps the most striking thing about the vote was the size of the support for the introduction of CBAMs.  The Parliament voted 444 to 70 in favour.  This stands in contrast to the position as recently as 2017, when a majority in the Parliament voted against such measures.  (An initial amendment on possibility of including imports in the EU ETS was passed in 2008, the start of Phase II of EU ETS, but nothing has ever been implemented.)

The vote recommends implementing CBAMs by setting up a separate pool of allowances, mirroring the ETS price[ii].  This places no restriction on the volume of emissions embodied in imports, but ensures that it pays the same carbon price as EU producers.  A further provision states that importers should not to be charged twice for the carbon content of their products, implying an adjustment or rebate for any carbon price already paid.

The proposed sectoral coverage includes all imports of products and commodities covered by the EUETS.  As a starting point it recommends covering at least power generation, steel, cement, aluminium, oil refining, paper, glass, chemicals and fertilizers, which would already lead to 94% of industrial emissions under the EUETS being covered.

Wording on the need for a rapid phase out of free allowances was removed by a narrow vote on an amendment.  However the resolution as passed notes the incompatibility of CBAMs with free allocation for the same tonne of emissions, and some sort of phase-out of free allocation seems clearly envisaged.

There is mention of special treatment for Least Developed Countries, but there is no explanation of what this means.  Possibilities range from the benign, for example using revenue raised from CBAMs to assist in achieving low carbon development pathways, to the highly undesirable, for example giving exemptions that incentivise polluting industry to move there to avoid CBAMs.

The resolution indicates that the ultimate goal is for CBAMs to disappear as the world adopts similarly robust pricing schemes.  However this seems a distant prospect.  The likelihood of CBAMs needing to be retained seems to be implied by a recommendation that an independent observatory body be established to monitor implementation.

The next major step will be when the Commission publishes its proposals in the summer. It remains unclear what those proposals will be and what will eventually be passed.  Indeed it remains possible that eventually no CBAM proposals will be passed into law, or that they may be introduced to a quite limited extent.  But as things stand their introduction looks likely, and it will be one of the most significant changes to the EUETS since its introduction.

Adam Whitmore – 12th April 2021


[i] The text is here https://www.europarl.europa.eu/doceo/document/TA-9-2021-0071_EN.pdf

[ii] For a review of this and other design issues, see my report from late 2019, here: https://sandbag.be/index.php/project/the-abc-of-bcas/

Are we seeing the start of much higher carbon prices?

For many years carbon prices have been too low to effectively incentivise enough of the actions needed to meet climate targets.  There are now signs that this is changing. 

Carbon pricing is widely seen as crucial for securing cost-effective emissions reductions.  However for many years carbon prices have mainly been too low to bring on the changes required to limit climate change[i].  Prices of $50-100/tCO2 or more are likely to be needed[ii].  However, even in 2020, the World Bank’s annual report on the State and Trends of Carbon Pricing showed that almost half of emissions covered by carbon pricing were seeing a price of less than $10/tCO2, and around 85% were seeing a price of less than $30/tCO2.  At the time this included emissions under the EUETS[iii].  

However there are now signs that this is changing.  The price under the EU ETS, the world’s largest carbon market, was below €10/ tCO2 for much of the period from 2012 to 2017 (see chart).  However, prices have risen strongly over the last few years,  as a result of reforms to the system, and of the prospect of tighter caps in future as the EU moves towards greater emissions reduction.  Prices are now around €40/tCO2.  This is much closer to what’s needed.

Chart: Prices for allowances in the EUETS (€tCO2)

Note: Dates on axis correspond to start of the year.  Source: Ember. 

Looking ahead, there is an emerging trend towards much higher prices in some places.  Several jurisdictions have set intended levels for prices in 2030 that are around two to five times current prices under the EUETS. Prices under the carbon tax for industry in the Netherlands are due to rise to €125/tCO2 by 2030 (see previous post). Norway has now proposed an even more ambitious carbon tax, reaching a price of €200/tCO2 by 2030[iv]. (Like the Dutch tax it will be a top-up tax, adding to the EUA price to reach the target level in the covered sectors.)   Canada intends that prices will reach C$170/tCO2 [v],while Ireland has set a target level for its carbon tax of €80/tCO2[vi], again both in 2030 (see table).

Target carbon prices for 2030  

JurisdictionTarget carbon price per tonne for 2030
Norway€200 (NOK2000)
CanadaC$170
Netherlands€125 for industry €32 for power generation
Ireland€80

At the moment such examples are too few and volumes covered are too small for this to be regarded as a global trend. However, such price levels have the potential to reframe expectations of carbon price levels, and so help enable similar prices elsewhere.

As carbon prices rise it will be essential to make sure that increases are politically acceptable (see an earlier post for some ways this can be achieved). And although higher carbon prices have the potential to accelerate decarbonisation, to be fully effective they need to be accompanied by appropriate supply side measures, such reinforcement of grids and support for new technologies

Nevertheless, the higher prices we are now beginning to see offer hope of much more effective carbon pricing over the next few years.

Adam Whitmore – 17th March 2021 


[i] I previously noted the problem of carbon prices being too low in a post back in 2015. https://onclimatechangepolicydotorg.wordpress.com/2015/06/02/carbon-prices-around-the-world-are-consistently-too-low/

[ii] For example, in 2017 the International High Level Commission on Carbon Pricing stated that the explicit carbon-price levels consistent with the Paris temperature target were at least US$40–80/tCO2 by 2020 and US$50–100/tCO2 by 2030.  See https://static1.squarespace.com/static/54ff9c5ce4b0a53decccfb4c/t/59244eed17bffc0ac256cf16/1495551740633/CarbonPricing_Final_May29.pdf

[iii] https://openknowledge.worldbank.org/handle/10986/33809.  See figure 2.4. 

[iv] https://bellona.org/news/ccs/2021-02-norway-proposes-e200-per-ton-co2-tax-by-2030#:~:text=Norway%20will%20seek%20to%20more,the%20country’s%20climate%20action%20plan.

[v] https://www.icis.com/explore/resources/news/2020/12/15/10586316/canada-to-hike-carbon-tax-to-c-170-tonne-in-bid-to-reach-paris-target

[vi] https://www.rte.ie/news/budget-2020/2019/1008/1081870-carbon-tax-to-be-increased-by-6-per-tonne/#:~:text=Minister%20for%20Finance%20Paschal%20Donohoe,80%20a%20tonne%20by%202030.

Avoiding incentives for CCS projects to make more CO2

Paying CCS projects per tonne of CO2 captured tends to create incentives to make more CO2.  Basing payments on emissions savings, with actual emissions compared with what they would be without CCS, provides much better incentives.

There is a story that a city was over-run by snakes (or rats in some versions of the story).  The authorities put a bounty on snakes, with a reward for every dead snake presented.  This worked for a while. But when many of the snakes had been killed, the people began to miss the income.  So they started breeding snakes to earn the bounty.  When the bounty was removed people released the snakes they had been breeding, and the town was over-run again.  I don’t know if this story is true, but apparently there is real example of something very similar from Georgia in the USA in 2007 with a bounty on wild pigs[i].

This story illustrates how perverse outcomes can arise if you target something that looks like what you want to achieve (fewer live snakes) but is actually something different (more dead snakes).

Payments for tonnes of CO2 captured by a CCS project can lead to exactly this sort of problem.  The atmosphere is over-run with CO2 and you want to reduce emissions.  But if you put a “bounty” on CO2, in the form of a contract payment for each tonne of CO2 captured, you provide incentives to make more CO2, just as there was an incentive to breed more snakes.

The current proposals by the UK Government run into exactly this problem, because CCS support contracts include payments based on the number of tonnes of CO2 captured[ii].  This makes captured CO2 a valuable product, and thus creates incentives for more production of CO2 (a CO2 factory), while disincentivising energy efficiency.  It could also potentially make less efficient projects appear cheaper than others on a cost per tCO2 basis, because they will be producing more CO2 for the same manufacturing output, and so may benefit from economies of scale in capture, and thus reduced costs per tonne. 

The incentive to produce more CO2 is seen in its clearest form when energy is cheap. This may be, for example, due to a fall in market energy prices, or access to low costs energy, for example at a refinery.  If a factory reduces output of its main product, it may continue to burn fuel and run it through the capture process anyway, because the capture payments make this profitable.  It will essentially get into the CO2 production and capture business.

A less extreme form of this type of distortion is the reduction in incentives for energy efficiency, either in the factory or the capture unit.  An energy efficiency project may be profitable without the capture incentives, but the loss of contract payments for tonnes captured may make this uneconomic. 

Illustrative worked examples of both these issues are included at the end of this post.

Improved incentives by estimating tonnes avoided

A better choice is to base payments on the amount by which emissions are reduced by the operation of the CCS plant.  This represents the actual environmental benefit of the project.  It gives better incentives and a better basis for comparing projects. 

The emissions reduction is the difference between:

  • what would have been efficiently emitted without the capture plant operating; and
  • what is actually emitted with the plant operating.

That is:

Emissions without capture (tonnes) – emission with capture (tonnes)

This calculation approximates the environmental benefit of the capture project (though is not on a full lifecycle analysis in this form). 

It is not dependent directly on tonnes captured, so gives no incentive for additional CO2 to be produced.  However, it still does give incentives for increased capture rates of other changes that reduce residual emissions (the 5% or so not captured).  

This incentive extends to choosing the appropriate size of capture unit and efficiently operating the plant, including optimising the capture rate. 

This approach requires the emissions that would have happened without the capture plant to be estimated (the counterfactual).  This can, for example, be based on the following.

  • Benchmark emissions per tonne of product.  This may be based on those under the ETS, which already exist for most producers at risk of carbon leakage.
  • Historical emissions per tonne of product from that particular plant.
  • Some other metric fixed in advance.

Something like this is already envisaged for power projects, with payments based on  MWh produced. 

Under this approach there is no incentive to burn energy to generate capture revenue, because the payment does not vary with tonnes captured. It is only affected by the benchmark and residual emissions.  However, the costs are still incurred in making extra CO2, so it becomes highly unprofitable.

Similarly, no net revenue is lost by an energy efficiency project.  Indeed some may be gained due to reductions in residual emissions.  Incentives are thus maintained or strengthened.  The incentive to reduce residual emissions is created by the carbon price, and possibly by additional contractual payments (see note at the end of this post). 

There are some challenges to implementing this approach, but it is broadly in line with the benchmarking approach for free allocation of allowances under an ETS.  As such, it should prove entirely practical, although, like free allocation, not entirely uncontentious.

Payments based on reductions in emissions are a much better approach than payments based on tonnes captured, and need to be implemented for forthcoming capture projects.

 Adam Whitmore – 17th February 2021

Example: Incentives to make extra CO2.

The table shows and illustration of how this might arise.  The numbers are illustrative, but broadly realistic.  Natural gas costs around £10/MWh, so it costs just under £60 to make a tonne of CO2 for capture. (Historic natural gas wholesale prices have mainly in the range 9-26/MWh[iii]over the past decade, although they fell below this range in 2020.)   If incentive payment for capture are £80/tCO2 (excluding transport and storage), then making CO2 for capture is profitable, even allowing for some non-fuel operating costs for the capture process. This does not happen if payments are based on emissions savings.

Tonnes of CO2/MWh fuel (GCV)0.184
Fuel to produce 1 tonne CO2 (MWh)1/0.184 = 5.43
Fuel used per tonne CO2 captured assuming 95% capture efficiency (MWh)5.43/0.95 = 5.72 
Fuel cost (£/MWh GCV)10
Cost of fuel per tonne CO2 captured (£/tCO2)5.72*10 = 57.2
Non fuel opex per tonne captured (£/tCO2)12
Cost of uncaptured emissions at 95% capture and £40/tCO2 (£/tCO2)2
Total costs per tonne captured (£/tCO2)57.2 + 10 + 2 = 69.2
Revenue per tonne captured (£/tCO2)80  THIS REVENUE DOES NOT EXIST WITH ALTERNATIVE APPROACHES, SO COSTS ARE NOT RECOVERED
Profit per tonne captured (£/tCO2)10.8

 Assumptions:  Natural gas cost £10.00 per MWh. No additional costs from producing energy to run the capture process, as equipment is already in place and the energy from the additional fuel burn here is sufficient.  However there may be some additional electricity purchases costs is electricity to run compressors is bought from the grid. There are some incremental non-energy operating costs in running the capture unit.  These are £10/tonne.  The 5% not captured pays a carbon price of £40/tonne. Carbon captured receives a payment of £80 per tonne captured. 

Example: an energy efficiency project.

In the illustrative example shown below, improved energy efficiency is economic based on fuel cost savings alone, by £4/MWh. However there is a loss of revenue from incentive payments due to smaller volumes of CO2 being captured, which is only partly offset by savings in capture plant operating costs.  This loss of revenue leads to a financial loss on the efficiency project of £5/MWh. This makes the project uneconomic.  Again, this does not happen if payments are based on emissions saved.

Cost of energy efficiency per MWh saved (£/MWh)6
Fuel cost saving (£/MWh)10
Profit per MWh saved4
Reduction in tonnes captured per MWh saved0.175 
Loss of incentive payment at £80/tCO2  (£/t)14.0 NO PAYMENTS ARE LOST UNDER ALTERNATIVE APPROACHES SO ENERGY EFFICIENTY REMAINS PROFITABLE
Savings in capture plant operating costs5.0
Profit per MWh saved4 – 14 + 5 = -5 (now makes a loss)

What is the effective carbon price when payments are based on emissions reductions?

There is the risk off double penalty for additional emissions if payments under a contract are reduced and a carbon price is also payable on residual emissions. This can be addressed simply by paying only the difference between the carbon price and the strike price on the residual emissions.  Payment would be:

Benchmark emissions * strike price

– residual emissions * (strike price – carbon price) 

– residual emissions * carbon price     this is the payment under carbon pricing system

This would effectively charge a higher carbon price for residual emissions.  This would give stronger incentives, which may be appropriate for early demonstration projects.  An alternative would be to price any residual emissions at the carbon price only.  Payment would be:

Benchmark emissions * strike price

– residual emissions * carbon price   this is the payment under carbon pricing system


[i] This story is recounted in this podcast, which relates it to similar issues with other incentives.  https://www.bbc.co.uk/sounds/play/m000rln5

[ii] https://www.gov.uk/government/publications/carbon-capture-usage-and-storage-ccus-business-models

[iii] Approximately 25-75 p/th. See https://www.ofgem.gov.uk/data-portal/all-charts/policy-area/gas-wholesale-markets.

The Dutch carbon tax on industrial emissions complements the EUETS

The Dutch Carbon Tax illustrates how taxes and emissions trading can be combined.  It acts as a top-up to the EUA price, in effect putting a floor on the carbon price.  It also has exemptions from the tax which work very like the allocation of free allowances in an ETS.   

On the 1st of January 2021 the Netherlands introduced a new carbon tax for industry.  The tax mainly applies to emitters covered by the EUETS, but also extends to waste incinerators, which are currently outside the EUETS. The design is similar to the tax in power generation, introduced a year previously. 

The tax in effect tops-up the EUA price.  If the EUA price is less than the tax, the amount of tax paid is the difference between the tax and the annual average EUA price for the year. For example, if the carbon price is set at €125/tCO2 in 2030, and the annual average EUA price in 2030 is €50/tCO2 a tax of €75/tCO2 is payable.  The tax is payable after the year end.  If the EUA price is above the level of the tax then no tax is paid.  Waste incinerators pay the tax in full.

In this way the tax sets a minimum level for the carbon price (a floor price), but does not prevent the carbon price from going higher if EUA prices are high. 

The level of the taxes has been set out from now to 2030 (see chart). For industry the price rises linearly from €30/tCO2 in 2021 to €125/tCO2 in 2030. The taxes are intended to be consistent with the Netherlands’ decarbonisation targets, and their level is subject to review and revision over time to ensure consistency with the targets. 

Chart: Carbon taxes in the Netherlands

To give time for industry to achieve emissions reductions there are exemptions from the tax, called dispensation rights. These dispensation rights mean no tax is payable on some proportion of a benchmarked quantity of efficient emissions.

The effect of these dispensation rights broadly resembles free allocation of EUAs according to a benchmark in the EUETS.  Both remove carbon costs for a benchmark level of emissions. Unused dispensation rights can be sold to other emitters covered by the tax, but not to intermediaries. 

The proportion of benchmark emissions qualifying for dispensation rights, called the reduction factor, falls over time. The reduction factor decreases annually, from 1.2 for 2021 to 0.69 by 2030. Over 30% of efficient emissions will thus be subject to the full carbon price by 2030.

This approach in effect creates a hybrid between an ETS and a carbon tax. In particular it puts a floor on the carbon price, and provides exemptions similar to those achieved with free allocation of allowances, but as part of a a tax mechanism.  It illustrates the way in which design of carbon pricing can incorporate similar features in both a tax and an ETS. Debate should focus on features and effectiveness, not on abstract debates about emissions trading vs. taxes.

Adam Whitmore – 22nd January 2021

Thanks to my colleague Christiaan Gevers Deynoot for helpful insights into this tax.

A further huge scale-up of solar and wind power is needed

The rate of installation of solar and wind electricity generation needs to increase by a factor of more than five to reach net-zero emissions globally by 2060.

Electricity generation from solar and wind will be the central feature of a zero-carbon global energy system.   Solar and wind generation have already reached large scale, with increasing rates of installation and falling costs. In 2019 solar and wind accounted for over 8% of global electricity generation[i]. However, much more is needed.  The market for electricity will grow enormously as low carbon electricity replaces fossil fuels in many applications, and solar and wind will take a greatly increased share of this larger market. 

So how much will solar and wind need to grow if the world is to reach net zero emissions by 2060?[ii]

I’ve estimated this by looking at three factors:

  1. Total final energy consumption (end use).  This is assumed to be similar to 2019 levels of around 100,000 TWh p.a. (350 EJ p.a.) in the central case, with a sensitivity of 25% total growth.
  2. The proportion of energy consumptions that is met by electricity (including by hydrogen produced by electrolysis).  This is assumed to be 80% in the central case, with a range 70-85%
  3. The proportion of electricity from solar and wind.  This is also assumed to be 80% with a range 70-90%.

The basis for these assumptions is outlined at the end of this post.

The analysis implies that solar and wind will meet around two thirds of world energy demand by 2060.  This is approximately 30 times the current total generation from these sources (see chart). 

Chart: Composition of Global Energy Consumption

To reach this total, about 1,600 TWh p.a.  of electricity generation from wind and solar needs to be added every year on average between now and 2060, more than five times the 2019 rate of growth of 300TWh[iii].  To reach this total by 2050 would require around seven times the current rate. 

The multiple of current rates of installation needed for net-zero is shown in the table below, with the range corresponding to the range of assumptions noted above.

Table: Multiple of current installation rate for solar and wind necessary to reach net zero global emissions

  Central Case Range
Net zero by 2060 5 4 – 8
Net zero by 2050 7 5 – 11

Most individual assumptions make little difference to these estimates, with estimates continuing to lie within the ranges shown.  The most significant differences arise from variations in assumptions about the amount of biofuels, the amount of hydrogen made from natural gas with CCS, rather than by electrolysis, and to some extent amounts of nuclear and CCS in power generation, including the retrofit of CCS to existing power plants.   Explicitly accounting for efficiency losses in making hydrogen from electrolysis would increase the need for wind and solar still further.

The main conclusion appears robust:  a very large scale up of solar and wind, 4-11 times the current rate of installation, is required to enable of the huge switch away from fossil fuels necessary to eliminate emissions by around mid-century.  This is broadly consistent with estimates by the International Renewable Energy Agency (IRENA) [iv].

Although the scale-up is very large, there do not appear to be any fundamental constraints preventing it.  For example, the amount of land used for solar by 2060 would be enormous – about 0.4% of the earth’s land surface[v]. However this does not seem an insuperable barrier – for example it is much less than now used for agriculture. Other challenges include storage.  Batteries and increasing interconnection are likely to reduce difficulties caused by variation in renewable output.  It also seems likely that, as I’ve assumed, hydrogen will play a significant role as a storage medium to complement variable renewable electricity, especially for storage over weeks or months.

Meanwhile, continued increases in the scale of solar and wind generation, and consequent learning, will continue to reduce costs significantly.  This will in turn greatly reduce the cost of the transition to net zero. 

The need for such large growth implies continuing focus on policies to support the deployment of wind and solar electricity generation, including greatly expanded and enhanced electricity transmission grids.  Other technologies will also be essential, but they all need to be developed in the context of the predominant role of wind and solar electricity generation.

Adam Whitmore – 14th December 2020

Assumptions 

Total energy consumption in 2060

 This refers to energy end use (final consumption), not primary energy, which includes among other things, large losses from using fossil fuels in power generation.  I have here included electrolysis to make hydrogen as part of final consumption.  If the efficiency losses from this process were added to final consumption as shown here the demand for wind and solar would be even greater.

The International Renewable Energy Agency (IRENA) has developed a scenario in which improvements in energy efficiency lead to demand being approximately constant or slightly falling over the period from now to 2050.  There is potential for major efficiency gains, for example in replacing oil with electricity in the transport sector, increased use of heat pumps, and continuing energy efficiency gains in buildings.  In contrast, as noted, there are losses in the production of hydrogen by electrolysis.

With such large opportunities for improved efficiency available, and with widespread international action to reduce emissions, I have assumed that something close to the scenario from IRENA is achievable, and that energy consumption in in 2060 will be around 102,000 terawatt hours per annum (370 EJ), a similar level to 2019. 

Other data projections show consumption increasing by about 25%, and a sensitivity of 25% of additional consumption is also included for the upper end of the ranges shown.[vi]

Electricity as a proportion of energy.

Electricity consumption is assumed to increase by a factor of about three to four.  Some of this electricity is used to make hydrogen, which acts as a form of energy transport and storage.  The remaining energy use is concentrated in aviation and shipping, and some industrial processes.  This is expected to be met from other sources, for example hydrogen made from fossil fuels with CCS (sometimes called blue hydrogen).  Bio fuels will likely play an important role, but are likely to be limited among other things by the scale of available supply[vii]. They may well make their most valuable contribution in bio energy with CCS (BECCS), providing negative emissions. 

I have excluded losses from transmission and distribution, which would increase further the amount of solar and wind required.

Wind and solar as a proportion of electricity.

I have then assumed that around 80% of electricity comes from wind and solar, with a range of 70%-90%.  Other low carbon electricity sources account for the remaining 10-30%.  This includes nuclear, which currently accounts for 10% of total electricity production, with output having fallen over the last decade[viii].  Hydro, which currently accounts for 16% of electricity generation, has grown over the last decade.  I have assumed it cannot grow faster than this due to resource limitations.  There may also significant amounts power generation from fossil fuels with post-combustion CCS.  Other renewables such as geothermal are likely to account for only a small proportion of the total.

Nuclear may play a larger role than I’ve have assumed.  However, it has very long lead times, is much more expensive than renewables and faces political obstacles in many jurisdictions. It seems unlikely to grow to dominate electricity production as it did in France in the 1980s and 1990s. CCS remains in the early stages of its deployment, but may play a significant role, for example in system balancing.  There may also be substantial retrofit of existing plants, especially in Asia.  


[i] https://ember-climate.org/data/global-electricity/

[ii] I have assumed net zero emissions could be achieved by 2060.  This is the target date set by China, by far the world’s largest emitter.  Some countries have committed to 2050, and this is examined as a sensitivity, but net zero seems less likely to be achieved by this date globally, especially as many countries have not yet committed to reaching net zero.   See https://onclimatechangepolicydotorg.wordpress.com/2020/11/10/momentum-towards-net-zero-emissions-is-growing/ 

[iii] Source: BP Statistical Review of World Energy

[iv] This is broadly consistent with analysis by IRENA.  This suggests a factor of six scale-up in renewables deployment is needed. However assumption differ.  For example,  IRENA in its analysis assumed 65% of energy will be supplied by renewable energy in 2050, but with a great proportion of renewables other than electricity. See: https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2018/Apr/IRENA_Report_GET_2018.pdf and  https://www.irena.org/publications/2019/Apr/Global-energy-transformation-A-roadmap-to-2050-2019Edition

[v] https://onclimatechangepolicydotorg.wordpress.com/2013/09/25/solar-deployment-are-there-limits-as-costs-come-down/  I’ve assumed 70kWh/m2 (a conservative assumption because it is based on data from older less efficient cells and much capacity will be based on newer more efficient technologies). This includes total site area (i.e. not only the panels). Generating 40,000TWh on this basis would require an area of around 570,000km2, about 0.4% of the world’s land surface of 149 million square km. This is a huge area – more than double the size of the United Kingdom of 242,000 km2 – although as noted probably an overestimate – and the true figure taking account of efficiency gains might be indicatively 30% less that this. It is in any case far less than the land devoted to agriculture, which uses solar energy to grow food.  And solar power can often make use of spaces – such as rooftops and deserts – that have few alternative uses.

[vi] See https://eneroutlook.enerdata.net/forecast-world-final-energy-consumption.html

[vii] https://onclimatechangepolicydotorg.wordpress.com/2016/04/11/the-constrained-role-of-biomass/ 

[viii] Source: BP Statistical Review of World Energy