Category Archives: renewables

Additional actions in EUETS sectors can reduce cumulative emissions

It is often claimed that additional actions to reduce greenhouse gas emissions in sectors covered by the EUETS are ineffective because total emissions are set by the level of the cap.  However this claim is not valid in the current circumstances of the EUETS, and is unlikely to be so even in future.  Additional emissions reduction measures in covered sectors can be effective in further permanently reducing emissions.

This post is longer than usual as it deals with a very important but relatively technical policy issue.

The argument about the effectiveness of additional actions to reduce emissions …

Many additional actions are being taken to reduce greenhouse gas emissions in sectors covered by the EUETS.  These include energy efficiency programmes, deployment of renewables, replacing coal plants with less carbon intensive generation, and national carbon pricing.

It is often argued that such additional actions do not reduce total emissions because the maximum quantity of emissions is set by the EUETS cap, so emissions may remain at the fixed level of the cap, irrespective of what other action is taken (see the end of this post for instances of this argument being used publicly).

However, this argument does not stand up to examination.

Assessment of the argument needs to take account of the current circumstances of the EUETS.  Emissions covered by the EUETS were some 200 million tonnes (about 10%) below the cap in 2015.  This year emissions are likely to be 13% below the cap.  The EUETS currently has a cumulative surplus of almost three billion allowances, including backloaded allowances currently destined for the Market Stability Reserve (MSR), and the surplus is set to grow as emissions continue to be less than the cap.

In these circumstances emissions reductions from additional actions will mainly increase the surplus of allowances, with almost all of these allowances ending up in the (MSR).  These allowances will stay there for decades under current rules, and so not be available to enable emissions during this time.

Indeed, in practice these allowances are unlikely ever to enable additional emissions.  The argument that they will assumes that the supply of allowances is fixed into the long term.  In practice this is not the case.  Long term supply of allowances is determined by policy, which can and does respond to circumstances.  Additional surpluses and lower prices are likely to lead to tighter caps than would otherwise be the case, or cancellation of allowances from the MSR or elsewhere.

The remainder of this post looks at these issues in more detail, including why the erroneous view that additional actions don’t reduce cumulative emissions has arisen.

Why current circumstances make such a difference

The argument that additional actions to reduce emissions will be ineffective reflects how the EUETS was expected to operate when it was introduced. It was assumed that demand for allowances would adjust so that the quantity of allowances used would always equal to the cap, which was assumed to be fixed.

This is illustrated in stylised form in the diagram below.  The supply curve is vertical – perfectly inelastic supply.  Demand for allowances without additional actions leads to prices at an initial level.  Additional actions reduce demand for allowances at any given price, effectively shifting the demand curve to the left by the amount by which additional actions reduce emissions.  This leads price to fall until the lower price creates sufficient additional demand for allowances, so that total demand for allowances is again equal to the supply set by the cap.  Because the supply curve is fixed (vertical) the equilibrium quantity of emissions is unchanged, remaining equal to the cap[1].

Chart 1: A price response to the change in demand for allowances can lead to emissions re-equilibrating at the cap when allowances are scarce …


However, at present, large increases in emissions (such that emissions rise to the cap) due to falling prices are clearly not occurring, and they seem unlikely to do so over the next few years.  As noted above, the market remains in surplus both cumulatively and on an annual basis.  The price would be close to zero in the absence of banking of allowances into subsequent phases, because there would be a cumulative surplus over Phase 3 of the EUETS, and so no scarcity[2].

If demand were further reduced in the absence of banking there would be no price fall, because prices would already be already close to zero.  Correspondingly, there would be no increase in demand for allowances to offset the reduced emissions from additional actions.  The emissions reductions from additional actions would be retained in full. This is again illustrated in stylised form in the diagram below. 

Chart 2: With a surplus of allowances and price close to zero (assuming no banking) any reduction in demand for allowances will be retained in full …


In practice the potential to bank allowances and the future operation of the MSR supports the present price.  It is expected that in future as the cap continues to fall allowances will become scarce.  There is thus a value to allowances set by the cost of future abatement.

Additional actions now to reduce emissions increase the surplus, and so postpone the expected date at which the market returns to balance.  This reduces current prices.  This will in turn lead to some increase in emissions.  However, this increase will be small – much smaller than if the market were short of allowances now.

Quantifying this effect 

Modelling indicates that if additional actions are taken over the next 10-15 years, then the increase in demand for allowances due to falling price will be less than 10% of the size of the reduction in emissions[3].  Correspondingly more than 90% of the emissions reductions due to additional actions are retained, adding to the surplus of allowances which, which end up in the MSR.  Modelling parameters would need to be in error by about an order of magnitude to substantially affect this conclusion.

This effect arises in part because of the low level of prices at present.  This means that even a large percentage change in price leads to a small absolute change, and thus a small effect on demand for allowances.  Even a 50% price fall would be less than €3/t at current price levels.  It also reflects that the shape of the Marginal Abatement Cost curve, with price falls only increasing abatement by a small amount.  This means that even if prices are higher than current levels the effect of price falls on demand for allowances is still relatively small.

The relatively small response to price changes is consistent with the current market, where there is a lack of sufficient increase in demand to absorb the current yearly surplus (or even to come close to doing so).

The 90%-plus of the allowances freed up by additional actions are added to the surplus end up over time in the MSR.  They then stay there for several decades.  This is because even without additional actions, and even with some reform of the current proposals for Phase 4 (which covers 2021 to 2030), the MSR is likely contain at least three billion allowances by 2030, and perhaps as much as five billion.  This will take until 2060 to return to the market, and perhaps until the 2080s, at the maximum rate written into the legislation of 100 million per annum.

Any additional surplus will only return after this.  Even if the return rate of the MSR were doubled the return time for additional surplus would still be reckoned in decades from now.

This will be even more the case if proposals for the EUETS Phase 4 are not reformed, and the surplus of allowances being generated anyway is correspondingly greater.

The implications of the very long delay in the return of allowances

It seems unlikely that allowances kept out of the market for so long would ever lead to additional emissions.  It would require policy makers to allow the allowances to return and enable additional emissions.  This would be at a time when emission limits would be much tighter than they are now, and indeed with a commitment under the Paris Agreement to work towards net zero emissions in the second half of this century.

There are several policy mechanisms that could prevent the additional surplus allowances enabling emissions.  Subsequent caps tighter as unused allowances reduce the perceived risk of tighter caps, and additional actions now set the economy on a lower carbon pathway.  Furthermore, with a very large number of allowances in the MSR over several phases of the scheme, allowances may well be cancelled.  Indeed, over such long periods the ETS itself may even be abolished or fundamentally reformed, with allowances not carried over in full.  Or a surplus under the EUETS may persist indefinitely as additional actions succeed in reducing emissions.

As the market tightens towards 2030 it is likely that a higher proportion of any additional emissions reductions will be absorbed by the market via a price effect, but it still seems unlikely to be as much as 100% given the long term trend to lower emissions and the lack of additional sources of demand, especially in the event of large scale additional actions[4].  Some of the policy responses described would still be expected to reduce the supply of allowances.


The argument that emissions will always rise to the level of the cap manifestly does not hold at present, when emissions are well below the cap. and there is a huge cumulative surplus of allowances.

In future, it seems likely that more than 90% of reductions in emissions from additional actions will simply add to the surplus, and eventually end up in the MSR.  They at least stay there for several decades, because of the very large volume that will anyway be in the MSR.

While there is in principle a possibility that they will eventually return to the market and allow additional emissions this appears most unlikely in practice.  Policy decisions will be affected by circumstances and this can readily prevent additional emissions, through some combination of tightening of the cap and cancellation of allowances.

Even when the market returns to scarcity these policy responses are likely to hold to a large extent, for example with lower prices enabling more stringent caps.  The hypothesis of no net reductions in emissions from additional actions thus seems unlikely ever to hold true.

Spurious arguments about a lack of net emissions reductions should not be used as a pretext for failing to take additional actions to reduce emissions now.

Adam Whitmore – 21st October 2016


Note:  A more detailed review of the issues raised in this post, and the accompanying modelling can be found in this report.


Examples of statements invoking the idea of fixed total emissions

For example, in 2015 RWE used such arguments in objecting to the closure of coal plant:

“The proposals [to reduce lignite generation] would not lead to a CO2 reduction in absolute terms.   [The number of] certificates in the ETS would remain unchanged and as a result emissions would simply be shifted abroad.” [5]

Similarly, in 2012 the then Chairman of the UK’s Parliament’s Energy and Climate Change Select Committee, opposed the UK’s carbon price support mechanism for the power sector arguing that:

“Unless the price of carbon is increased at an EU-wide level, taking action on our own will have no overall effect on emissions”[6]

Neutral, well-informed observers of energy markets have also made this case.  For example, Professor Steven Sorrel of Sussex University recently argued that:

“Any additional abatement in the UK simply ‘frees up’ EU allowances that can be either sold or banked, and hence used for compliance elsewhere within the EU ETS[7]



[1] This is analogous to the well-established rebound effect for energy efficiency measures.  Improved domestic insulation lowers the effective price of energy, so consumers take some of the benefits as increased warmth, and some as reduced consumption.  The argument here is that in effect there is a 100% rebound effect for emissions reductions under the EUETS.

[2] Such a situation occurred towards the end of Phase 1 of the EUETS (2005-7), which did not allow banking into Phase 2.  Towards the end of the Phase there was a surplus of allowances and the price fell to close to zero.

[3] The price change is modelled by assuming the price is set by discounting future abatement costs, with a later date for the market returning to balance leading to greater discounting and so a lower price.  The increase in demand for allowances is modelled based on a marginal abatement cost curve and consideration of sources of additional demand.  See report referenced at the end of this post for further details of the modelling.

[4] There are likely to be path dependency and hysteresis effects in the market which prevent a full rebound.

[5] See RWE statement, “Proposals of Federal Ministry for Economic Affairs and Energy endanger the future survival of lignite”, 20 March 2015.



The constrained role of biomass

The role of biomass in the world energy system looks likely to be constrained, so there will be a need to focus on high value applications where there are few low-carbon alternatives.

This is the second of two posts looking at the role of biomass.  Here I focus on potential resource constraints.

A wide range of possibilities

The amount of biomass available to provide energy depends a lot on the amount of land available to grow energy crops, and how much that land can yield.   Different assumptions on these variables produce quite different estimates of the total resource, and numerous studies over the years have produced a wide range of results.    The amount of waste biomass available also matters, but potential availability from this source is smaller.

A comprehensive review of estimates of the biomass resource was carried out two years ago by researchers at Imperial College[i] (see chart).  It showed a variation in estimates of a factor of around 40, from of the order of 30 EJ to over 1000 EJ (1EJ =1018 J, or a billion GJ, or 278 TWh).  This compares with total world primary energy demand of just under 600 EJ, transport demand of around 100 EJ, and at least 250 EJ to produce present levels of electricity, assuming biomass combustion to remain relatively inefficient[ii].

Estimates of available biomass resource

biomass chart processed

Source: Slade et. al. (2014)

The authors examine reasons for differences in estimates, which I’ve summarised in the table below.  The differences are largely assumption driven, because the small scale of commercial bioenergy at present provides little empirical evidence about the potential for very large scale bioenergy, and future developments in food demand and other factors are inevitably uncertain.

Reasons for variation in estimates of total biomass supply

Range Typical assumptions
Up to 100EJ Limited land available for energy crops, high demand for food, limited productivity gains in food production, and existing trends for meat consumption.  Some degraded or abandoned land is available.
100-300 EJ Increasing crop yields keep pace with population growth and food demand, some good quality agricultural land is made available for energy crop production, along with 100-500Mha of grassland, marginal, degraded and deforested land
300-600EJ Optimistic assumptions on energy crop availability, agricultural productivity outpaces demand, and vegetarian diet
600 EJ + Regarded as extreme scenarios to test limits of theoretical availability


Reasons for caution

In practice there seem to me to be grounds for caution about the scale of the available resource, although all of these propositions require testing, including through implementation of early projects.

Land Availability

  • There will rightly be emphasis on protection of primary forest on both carbon management and biodiversity grounds, with some reforestation and rewilding.
  • There is little evidence of a shift away from meat consumption. With the exception of India, less than 10% of people in  most countries are vegetarian despite many years of campaigning on various grounds[iii].   In China meat consumption is associated with rising living standards.
  • Demand for land for solar PV will be significant, although a good deal of this will be on rooftops and in deserts


  • The nitrogen cycle is already beyond its limit, constraining the role of fertiliser, and water stress is a serious issue in many places (agriculture accounts for 70% of current fresh water use). The UN Food and Agriculture Organisation has projected fairly modest increases in future yields.

Policy support

  • Difficulties in limiting lifecycle emissions from biofuels are likely to lead to caution about widespread deployment.
  • Concerns about food security may limit growth of biofuels.

Small scale to date, despite many years of interest

  • There has been little progress to date compared with other low carbon technologies. Though traditional biofuels remain widely used, modern biofuels account for a very small proportion of demand at present.  World biofuels consumption currently accounts for only 0.2% of world oil consumption[iv] .  Many biofuels programmes have had subsidies cut and there is still limited private sector investment.

In this context some estimates of the potential for biomass to contribute to energy supply seem optimistic.  For example, Shell’s long-term scenarios (Oceans and Mountains) show biomass of 74 EJ and 87 EJ respectively for commercial biomass, 97-133 EJ including traditional biomass by 2060[v].  These totals are towards or above the more cautious estimates for the resource that might ultimately be available (see table above).  A recent review article[vi]  suggested that by 2100 up to 3.3 GtCp.a. (around 12 billion tonnes of CO2) could be being removed, and producing around 170EJ of energy.  However the land requirements for this are very large at about 10% of current agricultural land.  The authors suggest instead a mean value for biomass potential of about a third of that, or 60EJ.

On balance it seems that biomass is likely to account for at most less than 10% of commercial global energy (likely to be around 800-900EJ by mid-century), and potentially much less if land availability and difficulties with lifecycle emissions prove intractable.

It thus seems likely that biomass energy will be relatively scarce, and so potentially of high value.  This in turn suggests it is likely to be mainly used in applications where other low carbon alternatives are unavailable.  These are not likely to be the same everywhere, but they are likely often to include transport applications, especially aviation and likely heavy trucking, and perhaps to meet seasonal heat demand in northern latitudes.  For example, according to Shell’s scenarios aviation (passengers + freight) is expected to account for perhaps 20-25EJ by 2050, and biomass could likely make a useful contribution to decarbonisation in this sector.

None of this implies that biomass is unimportant, or has no role to play.  It does imply that policies focussing on deploying other renewable energy sources at large scale, including production of low carbon electricity for transport, will be essential to meeting decarbonisation targets.  And the optimum use of biomass will require careful monitoring and management.

Adam Whitmore  – 11th April 2016


[i] Slade, Global Bioenergy Resources, Nature Climate Change February 2014

[ii] Data on final consumption and electricity production from Shell and IEA data.  35% efficiency for biomass in electricity is assumed, which is likely to be somewhat optimistic, especially if CCS is employed.


[iv] BP Statistical Review of World Energy

[v]  These totals include biofuels, gasified biomass and biomass waste solids, and traditional biomass.

[vi] Smith et. al., Biophysical and economic limits to negative CO2 emissions, Nature Climate Change, January 2016.  The paper estimates land requirement for 170 EJ of 380-700 Mha, around 10% of total agricultural land area in 2000 of 4960Mha.

Grains of rice, Japanese swords and solar panels

Even Greenpeace has underestimated the growth of renewables.  In particular, solar has been growing exponentially, and may continue to be so for a while, though likely at a slower percentage rate.

Greenpeace did much better than many at projecting the growth of renewable energy sources in the 2000s.  Their projections were very close to outturn for wind – the 1999 projections were a little below outturn, the 2002 projections a little above.  However even Greenpeace underestimated the growth of solar.  The projections were nevertheless startlingly better than those of the IEA, who have, as I’ve previously noted, consistently underestimated the growth of renewables by a huge margin.  Growth of solar has been exponential, as has that of wind (at least until recently).  Greenpeace appears to have done well by following the logic of exponential growth.

Greenpeace’s projections for wind growth in the 2000s were close to outturn, but they underestimated the growth of solar …


Exponential growth is so powerful that it can confound intuition about how large numbers can become.  The counterintuitive power of exponential growth is illustrated by the process of making a traditional Japanese steel sword.  The supreme combination of strength and flexibility of such a weapon is said to derive from the way an exponential process layers the metal.  As the metal is beaten out and folded repeatedly to forge the sword the number of layers in the metal doubles up each time.  Following this simple process 15 times creates 215 layers, well over 30,000.  This would be impossible in any other way with traditional methods, and the number of layers created would be hard to comprehend without doing the formal calculation.  This property of producing very large numbers from simple repeated doublings may have contributed to previous projections for renewables seeming implausible, because they were so much greater than the then installed base.  This may have contributed to even Greenpeace being a little cautious in its projections for solar.

Nevertheless exponential growth inevitably runs into limits as some stage.  This is captured by the classic fable of grains of rice on a chessboard, where one grain is put on the first square, two on the second, four on the third, eight on the fourth and so on, doubling with each square.  Half way through the chessboard the pile of grains, though very large, is manageable – around 50 tonnes for the 32nd square.  However amounts then quickly begin to go beyond all reasonable physical constraints.  The pile on the final square would contain 263 grains of rice, which is about 230 billion tonnes.  This is about 300 times annual global production, and enough to cover not just a square of the chessboard but the entire land surface of the earth (to a depth of about a millimetre or two).

Extrapolating growth rates for solar PV from the period 2000 to 2013, when cumulative installed capacity doubled every two years, runs into similar limits.  At this growth rate the entire surface of the earth would be covered with solar panels before 2050.  This would provide far more energy than human civilisation would need, if there were room for any people, which there would not be because of all the solar panels.   So are there constraints that imply that renewables are now in second half of the chessboard – or, if you prefer a more conventional model, the linear part of an s-curve for technology adoption?

Looking at solar in particular, as I’ve previously commented, it needs a lot of land, but this is unlikely to be a fundamental constraint.  Some have previously suggested a limit as technologies reach scale, defined as about 1% of world energy supply, after which growth becomes more linear.  However solar manufacture and installation are highly scalable, so there are fewer obstacles to rapid growth than with traditional energy technologies.

Costs are rapidly falling, so that solar is becoming competitive without subsidy, both compared to other low carbon technologies and, increasingly, with high carbon technologies, especially if the cost of emissions is taken into account.  There is no obvious limit to how low the costs of solar cells can go that is likely to bind in the foreseeable future, although the ancillaries may show slower cost falls.  The costs of lithium ion batteries are also falling rapidly, having approximately halved in the last five years and continuing to fall at a similar rate.  As a result daily storage is becoming much more economic, reducing the problem of the peakiness of solar output and easing its integration into the grid, although seasonal storage remains a daunting challenge.

Solar still accounts for only around 1% of world electricity generation so globally there are plenty of opportunities globally in new electricity demand and from scheduled retirement of existing generating plant.  The vexed issues around grid charges, electricity market structures and role of incumbents may slow growth for a while, at least in some jurisdictions, but seem unlikely to form a fundamental barrier globally as long as costs continue to fall.

In short there seem few barriers to solar continuing to grow exponentially for a while, although likely at a slower percentage rate than in the past – each doubling is likely to take longer than two years given the current scale of the industry.  Solar can still continue moving quite a long way up the chessboard before it hits its limits.  How large the industry will become will need to await a future post, but provisionally there does not seem any reason why solar PV should not become a 300-600 GW p.a. or more industry.

Policy has played an important role in the development of solar to date mainly by providing financial incentives.  It will continue to play an important role, but this will be increasingly around removing barriers rather than providing a financial stimulus.

Of course I cannot know if this fairly optimistic view is right.  But it does at least to avoid some issues that might bias projections downwards.  First, it recognises the potential validity of counter-intuitive results.  In a sector such as energy which usually changes quite slowly the numbers resulting from exponential growth can seem implausible.  This can lead to rejection of perfectly sound forecasts, as the intuition of experienced professionals, which is based on long experience of incremental change, works against them.  Second it avoids assuming that all energy technologies have similar characteristics.  Finally, it takes into account a wide range of possibilities and views and considers the drivers towards them, helping to avoid the cognitive glitch of overconfidence in narrow limits to future outcomes.

The rate of growth of renewables is intrinsically uncertain.  But the biases in forecasts are often more towards underestimation than overestimation.  If you’ve been in the energy industries a while it’s quite likely that your intuition is working against you in some ways.  Don’t be afraid to make a projection that doesn’t feel quite right if that’s where the logic takes you.

Adam Whitmore – 25th November 2014


In the calculations of the results from exponential growth I have, for simplicity, assumed very rough and ready rounded values of 40,000 grains of rice = 1litre = 1 kg.  I’ve assumed 10m2/kW (including ancillaries) for the area of solar panels. The land surface of the earth is 1.5 x108 km2.  Solar capacity doubled around every 2 years from 2000 to 2013, growing from 1.25GW in 2000 to 140 GW in 2013 (source:  BP statistical review), reaching a land area of around 1400km2.  217 times its current area takes it past the land surface of the earth, so it would take to 2047 (34 years from 2013) with doubling of installed capacity every 2 years to reach this point.  The source of the story about sword-making is from the 1970s TV documentary The Ascent of Man and accompanying book.

For data on Greenpeace’s historical projections see: See pages 69 and 71


Tranmission links to enable wind power

The availability of long distance transmission systems can help smooth out variations in availability of wind power, but helps solar less.  Policy needs to enable long-distance links to allow continuing increases in wind generation.

One of the challenges of moving to an electricity system running with a large proportion of wind and solar is that electricity output from these sources is variable, because the wind does not always blow and the sun does not always shine at any particular location.  With small proportions of these sources on the system this is not much of a problem.  However as a system becomes more dependent on these variable renewables, production is potentially curtailed in periods of high output, while there is a shortage of power at other times.  I’ll refer in this post to wind and solar photovoltaic (PV) power, which is by far the predominant form of solar electricity.  The issues with concentrated solar thermal power are different because there is some potential for storage in the power plant.

Difficulties with balancing supply and demand typically begin to become more severe as each type of variable renewable power, for example wind, begins to supply more than (very roughly) around 15% of annual electricity.  In practice the extent of the challenge of integration depends on a range of factors.  One influence is the amount of inflexible generating capacity such as nuclear on the system.  Another influence is the correlation between variable supply and demand.  For example, there is some seasonal correlation between electricity demand and wind output in Europe (in winter demand is higher and it’s windier), and there is some daily correlation between electricity demand and solar PV output in Australia (the demand peak is in the daytime).  Nevertheless, in any case there will be challenges in reliably meeting demand while accommodating very large amounts of variable supply.

To address this problem variable supply can be moved to different times, using storage, and to different places via transmission capacityDemand management can help, especially for a demand peaks, and some thermal back-up capacity is likely to be needed anyway in most cases.

The extent to which transmission links can help system balancing depends on the extent to which generation in different places is correlated.  If distant power sources tend to produce power at different times then transmission can greatly help smooth out variations in production, because when output is low in one location electricity can be moved there from another.  But if distant sources tend to produce power at the same time the advantages of long distance transmission will be reduced, because if output is low in one place there will be little electricity in the other place to move to fill the gap.  This is especially so if patterns of demand are also similar in the different places

Typically, correlations of output across regions for solar PV are much higher than for wind, especially as distances increase (see chart).  This is because solar output tends to depend strongly on time of day and season, which is quite similar even across an area as large as Western Europe, whereas wind varies with weather systems, which are less strongly related over distance of the order of 1000 miles or so.  Looking at the correlations between hourly output in different countries in Western Europe shows that the correlation between solar output in Germany and France is 88%, much greater than for wind at 44%.  Moving further away, the correlation between output in Germany and Spain is close to zero for wind, but still as high as 84% for solar.  The match of solar output is is actually greater than these figures imply due to the large number of times when solar output is zero for both countries.

Correlations of hourly output between different Western European countries are much greater for solar than for wind …

Correlations chart

These factors mean that increasing interconnection will tend to enable higher proportions of wind more than it will enable higher proportions of solar.  (This is assuming transmission is for load balancing.  Interconnection to transport power from sunnier to less sunny regions may well be valuable.  Also, this conclusion would change if intercontinental of transmission of large amounts of power were possible, but this remains a distant prospect.)

Incidentally, the correlation between solar and wind output is negative (when it’s windy it tends to be less sunny and vice versa), so having some of each on the system tends to increase the combined total that can be accommodated, compared with a system only having either one or the other.

A recent study of the USA by the National Oceanic and Atmospheric Administration (NOAA) confirmed very large benefits from High Voltage Direct Current (HVDC) long distance transmission for systems with large amounts of variable renewables.   The study used very detailed weather and load data, and data on existing power plants.  It concluded that with optimistic projections of wind and solar costs it is possible to reduce CO2 emissions by 82% with somewhat lower electricity costs, provided sufficient transmission capacity is in place.  The study emphasised the importance of the transmission network encompassing a large geographical area, such as the 48 contiguous US states, due to the large geographical scales over which weather is variable.

However, interconnectors are not always quick, cheap or easy to build.  They often link or cross different jurisdictions – US States, Chinese provinces or European countries – and will often link different types of electricity trading arrangement.  This can impose substantial barriers around permitting, and also around operation.  Policy can help the growth of wind by reducing these barriers and recognising the growing role of internconnection, although the precise policy measures necessary will be quite locally specific.  Enabling increased transmission is likely to be an important step in enabling the continuing growth of wind power in particular, and is likely to become increasingly urgent as growth continues.

Adam Whitmore – 16th September 2014


Thanks to Mathieu Ecoifier for providing the correlation coefficients between wind and solar in Europe.  Correlation coefficients are a rough and ready indicator of independence.  Actual effects on system operation will depend on many factors.

For analysis of the inverse correlation of wind and solar see for example Correlations Between Large-Scale Solar and Wind Power in a Future Scenario for Sweden, Joakim Widén, IEEE Transactions on Sustainable Energy, Vol. 2, No. 2, April 2011

The US study mentioned is Alexander MacDonald et. al., NOAA Earth System Research Laboratory, Low Cost and Low Carbon Energy Systems Feasible with Large Geographical Size (2014) – Presentation at Imperial College London 27th May 2014

The EU’s recent proposal for a 2030 EUETS target does not look very ambitious

The EU’s recently announced greenhouse gas emissions target for 2030 looks like just enough to keep the 2050 target credible, but seems unlikely to be perceived as highly ambitious by other jurisdictions.  

The European Commission has recently proposed a target of reducing EU greenhouse gas emissions to 40% below 1990 levels by 2030.  Sectors covered by the EUETS (power generation and large industry) will be required to reduce emissions to 42% below 1990 levels.  This post takes a look, using some rough-and-ready analysis, at how onerous the EUETS target would be if implemented.   The Commission also announced a proposal to establish a “market stability reserve” for the EUETS.  I will return to this proposal in a future post, but for now the analysis excludes its effect.  The analysis also excludes the temporary delay of allowances sales over the next few years (backloading), which does not affect cumulative totals to 2030 in the absence of the stability reserve.

A target of a 40% reduction by 2030 is on a straight line track from the 20% mandated by 2020 towards the least stringent end of the 2050 target, which is an 80-95% reduction from 1990 levels.  This appears to be the minimum reduction likely to retain the credibility of the 2050 target, especially given the current surplus of allowances in the EUETS.  A smaller reduction by 2030, requiring deeper cuts to be achieved more rapidly towards 2050, would likely have increased the perceived probability that the 2050 targets would not be adhered to.

There is currently a surplus of EU allowances of around 2.2 billion tonnes, equivalent to about one full year of emissions covered by the scheme.   This scale of surplus has arisen mainly due to the severity of the recession in Europe.  Emissions currently remain below the cap, and even as the cap tightens it will take more than a decade for the surplus to disappear.

This is illustrated in the chart below.  The cumulative cap on emissions between now and 2030 (green line) starts at level of the current surplus.  It then increases, but less rapidly each year as the annual cap comes down.  This is compared with the illustrative case of annual emissions are constant at 2012 levels (solid blue line), so cumulative emissions grow linearly.  In this case, with no reduction in annual emissions, the surplus disappears in around 2026.  However in practice power sector emissions are expected to fall over the period (see below), reducing cumulative emissions (dashed blue line).  This leads to the surplus disappearing only in 2029, and reduces the cumulative shortfall by 2030 to quite low levels, assuming emissions from industry are constant.  Aviation is excluded from these totals.  Although internal flights remain covered by the EUETS, the associated cap remains unclear.

Cumulative emissions (excluding aviation) and the cumulative cap (including current surplus) show a deficit emerging only in the late 2020s …

 Cumulative surplus

The power sector is the largest source of emissions covered by the EUETS, so is crucial to demand for allowances.  There may be some increase in electricity demand over the period, and hence in demand for allowances.  The increase may be smaller with strong efficiency measures, or larger if there is very rapid uptake of electric vehicles, and will also vary more generally with GDP growth over the period.  There is also likely to be a decrease in nuclear generation to 2030 as older plant comes to the end of its working life and is not replaced by an equal amount of new plant.

However the growth in demand and fall in nuclear output seem likely to be more than offset by continuing growth in generation from renewables.  This implies a net decrease in the need for fossil generation, leading to lower emissions in the absence of changes to the fossil fuel mix.  However there may be some increase in emissions from internal EU  aviation, although any increase is likely to be much smaller in absolute terms than the decrease from the power sector.  Trends in emissions from industry, assumed to stay constant here, will also affect the total.

Together these trends might lead to a cumulative excess of expected emissions over the cap of around a billion tonnes by 2030 (about 3% of the total), including some growth in emissions from domestic aviation.   Projections of emissions over more than a decade and a half are obviously uncertain, and the cumulative total could easily vary by a billion tonnes or more from this total.  Nevertheless, it seems likely that the shortfall in allowances cumulatively over the period will be somewhere in the low- to mid- single figures percent of the total over the period, with the market remaining in surplus until the late 2020s.   The additional abatement required to eliminate the shortfall in this case could be achieved by a moderate amount of fuel switching.  And scenarios where a surplus of allowances persists through to 2030 are not hard to construct.  (The shortfall is somewhat increased if you take the view that there is a permanent stock of allowances needed to enable hedging in the market,  Some estimates indicate that this is around a billion tonnes, which would increase the shortfall to around 6% in the scenario above.  However it is by no means clear that this is needed through the 2020s, and anyway it remains easily accommodated by fuel switching,  Conversely around an extra 800 million allowances unused from the New Entrant Reserve  may come into the market at the end of Phase 3 in 2020, further reducing any shortfall )

Any substantial scarcity that does emerge seems likely to be as a result of banking of allowances into the period after 2030, either as a result of private sector banking or the operation of the market stability reserve, which effectively mandates a certain amount of banking of any large surplus.

The EU’s apparent intention to (just about) keep on a track towards its 2050 targets is surely welcome.  However the proposed 2030 target for the EUETS thus does not seem very demanding.  It seems unlikely that such a cap will be to be taken by other countries as a sign of strong EU leadership on emissions reduction.  It also seems unlikely that the EUETS alone will become effective at stimulating large scale investment in low carbon technologies over the next decade and a half.  This risks endangering progress to reduce emissions after 2030.  Additional policy instruments will likely be needed if the EU is to succeed in building the low carbon infrastructure needed to put itself on a path to largely decarbonising its economy by the middle of the century.

Adam Whitmore  –  14th February 2014

Notes on data and assumptions  

The 40% target requires a 20% point reduction by 2030 from the already mandated 20% cut due by 2020.  If this were followed by 40% points (40% down to 80%) over the subsequent two decades an 80% cut would be achieved by 2050.   20% of 1990 levels per decade thus takes the cap towards the top end of the 2050 target range of an 80-95% cut by 2050.

2012 emissions include the industrial emissions additionally covered in Phase 3.  Emissions from large industry are assumed to remain constant over the period.  The linear reduction factor is assumed to increase from 1.74% p.a. to 2.2% p.a. in 2021.

The estimates of power sector trends are based on the IEA 2013 World Energy Outlook New Policies Scenario.  This scenario shows demand growth in EU power generation of 0.4% p.a. over the period, leading to an additional 260TWh of generation by 2030 compared with 2011.  It also shows a decline of 10% in nuclear, but his may include optimistic assumptions about new build.  A decrease in nuclear generation of 20% (180 TWh p.a.) seems plausible, and I’ve used this estimate.  This leads to potential additional demand from fossil generation of 440TWh (260TWh + 180TWh).  The IEA estimates that generation from renewables, including hydro, will approximately double between 2011 and 2030, increasing by 730TWh p.a..  This leads to a net reduction in demand for fossil generation of around 290TWh (730TWh – 440TWh) by 2030.  The estimate of the saving takes account of the profile of these trends, for example the more rapid fall-off in nuclear in the 2020s.  Additional TWh of low carbon power are assumed to reduce emissions by 0.4t/MWh, equivalent to displacing mainly gas. 

The electricity sector projections take their base year as 2011 while the emissions data base year is 2012, but this is taken account of in the calculations. 

Internal aviation emissions are currently around 84 mtpa, but the position of aviation within the EU post-2020 is currently unclear.  The calculations assume that international aviation is dealt with under a separate agreement through ICAO, or not at all. 

The calculations exclude any additional reductions if other jurisdictions take action.  Any reductions in the cap due to international action may in any case be accompanied by increased use of offsets within the EU.

The UK needs to take a more serious look at importing renewable electricity

Imported solar electricity looks likely to be cheaper than nuclear in the UK by the early 2020s when new nuclear is due to come on line.  Solar and other imported renewables deserve a closer look as one means to decarbonising the UK power sector.

The recently agreed Contract for Difference (CfD) for new nuclear power at Hinkley Point in the UK fixes the price of electricity at £92.5/MWh ($149/MWh) for 35 years, indexed to inflation.  This is expensive compared with the average market electricity price in 2012 of £45/MWh ($73/MWh) (see the end of post for notes on data and calculations).  It is also expensive abatement, at around £136/tCO2 ($217/tCO2) against a gas plant at current market electricity prices.  This compares with the UK carbon price planned for 2020 (including the UK’s own carbon price support levy) of £30/tCO2 ($47/tCO2).

The price for new nuclear compares more favourably with the prices for alternative sources of low carbon power in the UK at the moment.  It is cheaper than the current going rates for offshore wind, solar and onshore wind in the UK (£155/MWh, 125/MWh and 100/MWh respectively).  It is also lower than the cost of Carbon Capture and Storage (CCS), which is estimated at around £160/MWh at the moment (with an abatement cost of about £400-600/tCO2 avoided after taking account of the residual emission from power plants with CCS).

However, solar electricity in Germany and Italy can be produced for around £90-95/MWh, close to the price of electricity from Hinkley, based on the Feed In Tariffs in the first half of this year for ground-mounted systems.  (The Feed In Tariff in Germany has since been reduced to £83/MWh but it is not yet clear how much capacity will be built at this price).

A number of adjustments need to be made to obtain a like-for-like comparison between the prices solar and nuclear.  (The calculations of these adjustments are indicative, but precise numbers are anyway impossible to derive given the long timescales and uncertainties involved.)

First, the cost of back-up capacity and system balancing increases the cost of solar compared with nuclear.  There is some increase in system balancing costs.  Together these are estimated to add £13/MWh to the cost of solar.  Any offsetting adjustment for the system capacity effects of nuclear is excluded from this number (see notes).

Second, nuclear and solar have very different patterns of output with correspondingly different values.   Solar runs only in the daytime, with output higher in summer.  Nuclear output is largely constant, typically running at full output almost all of the time.  With present wholesale market price patterns in the UK the additional value of daytime power for solar outweighs the additional value for nuclear from supplying winter evenings when prices are highest, leading to a premium for the value of the solar production pattern on average over the year of 6/MWh.  (This includes crediting the full value of winter peak hours to nuclear, which may to some extent double count the value of capacity if the above capacity premium is also included in the comparison.)  However, price patterns may change in future for many reasons, for example because large amounts of solar generation may reduce daytime prices.  Summer daytime prices in Germany already show some weakening due to the amount of solar on the system, although they remain generally above overnight prices.

Finally the length of the contracts also differs.  The solar Feed In Tariff in Germany runs for 20 years whereas the Hinkley contract is for 35 years, inflation indexed in both cases, making the Hinkley contract more valuable.  The additional value is estimated as £7/MWh or more (this is the additional price that might be needed if the Hinkley contract were to run for only 20 years).

The adjustments thus offset each other (with, coincidentally, no net effect) leaving the costs of UK nuclear appearing very similar to the present costs of solar in Italy and Germany.  In addition of course transmission costs to the UK would need to be paid for imports of solar from continental Europe.

But it is more appropriate to compare the price of the nuclear contract with the price that solar – which can be installed very quickly – will require when the nuclear plant comes on line a decade from now (assuming it is completed on schedule).  Solar costs look almost certain to fall over this period.  Prices for solar in Germany are roughly a quarter of what they were a decade ago and are expected to fall significantly again over the next decade.  Imports to the UK from sunnier regions in southern Europe, such as Italy or (especially) southern Spain could be cheaper still.  It is impossible to be certain how far costs will fall, but a mid-range estimate (based on long term historical trends) is that prices of perhaps as low as £50-60/MWh or less could be attained for imported solar delivered to the UK by the time Hinkley comes on line, even allowing for the costs of transmission.  Solar would then have a clear cost advantage over nuclear.   Even new solar in the UK appears likely to be available at below the cost of power from Hinkley by then.

Solar alone will not be a complete solution to decarbonising the UK power sector.  But there are also other options for importing renewable power to the UK, including onshore wind from Ireland and Scandinavian hydro, which can provide considerable flexibility.  While they may lack some of the employment and industrial policy attractions of building capacity within the UK, imports can allow access to a scale of renewable electricity supply that the UK, with its poor solar resource and (at least in England) exceptionally high population density, may otherwise struggle to reach.

There are also other advantages to importing renewables.  A diversity of locations, with varying demand and production patterns linked by adequate transmission capacity, can help balance the system, and ensure that power is available at lowest cost.

Policy has an important role to play in making such imports of power viable.  Policy can enable and incentivise the construction of transmission capacity, more flexible system design and operation, and appropriate commercial arrangements.

The Hinkley nuclear deal signals that the UK Government is serious about meeting the need for new low carbon power.  The CfD mechanism provides a new way to finance new nuclear power, and it makes the costs of the project transparent.  And the UK may turn out to need new nuclear plant if it is going to meet its ambitious decarbonisation objectives (although likely of a different desgin).

But options for importing renewable power do not as yet appear to have received the same degree of policy focus as new nuclear.  Imports of renewables may have a significant role to play in diversifying supply and limiting the total costs of providing low carbon power.  They deserve much more serious and ambitious attention than they have yet received.

Adam Whitmore  – 13th November 2013

Notes on calculations 

Price of the Hinkley C announcement is taken from the DECC announcement The quoted price excludes the reduction of £3/MWh if another similar plant is built.  Other UK prices for low carbon power are draft prices for CfDs.

No adjustment is made for any of the other features of the contract.  In particular no adjustment is made for the value of the loan guarantees for which the project is reported to qualify.

The price for CCS is taken from the report of the UK’s CCS cost reduction task force.  There is an aspiration to reduce costs of CCS to around £100/MWh by the 2020s, but it is not clear whether such a large reduction can be achieved given the slow progress in developing CCS in the power sector globally.  There are similar aspirations to reduce the cost of offshore wind.

Calculations of abatement cost are based on a comparison with emissions from a CCGT of 0.35 tonnes/MWh, using the current market price of electricity, with emissions from plant with CCS at 0.07 – 0.15 tonnes/MWh depending on fuel type and capture rates.

The cost of solar in Germany used is the 2013 feed-in tariff for ground mounted systems less than 10MW of 11.02€c/kWh in April 2013.  The feed-in tariff in Italy was at a similar level. 

The estimated cost of back-up capacity is based on a study from the solar parity project.  The calculation ignores the cost of system capacity associated with nuclear that arises because the proportion of total capacity it accounts for is lower than its proportion of energy it accounts for.  This leads to an additional capacity cost associated with nuclear which to some extent offsets the additional capacity cost of solar, so the capacity cost of solar should in reality be estimated as the difference between the capacity costs of nuclear and solar rather than the full value quoted here, which would decrease the relative cost of solar. 

The price premium for solar is based on 2012 price patterns.  The wholesale electricity spot price in Great Britain is weighted by solar output in Germany over 12 representative days (one per month), allowing for the one hour time difference between Germany and the UK to get the output pattern for notional imports (data was Italy or Spain would yield slightly different results, but the general pattern would be the same).  This is compared with the time-weighted average over the year, which is assumed to be the price received by nuclear power. 

Peak prices during winter evenings contain an element of payment for capacity.  This is added to the value of nuclear relative to solar in this calculation.  However an element of capacity value has already been included as a separate item in the adjustment (see above).  As noted in the main text, there is potentially an element of double counting here, with the value of capacity for nuclear being available at the peak included both in this and the capacity adjustment itself.  This calculation combined with the capacity cost above may thus understate the present premium value of the solar output pattern, and so the assumption is somewhat favourable for nuclear.

Adjustment for contract duration is based on comparison of cash flows from a 20 year and 35 year contract.  The calculation assumes the 2012 baseload market prices prevail in real terms in years 21-35 of the contract (approximately 2044 – 2058), but adjusted to allow for a carbon price of £30/tCO2, based on the government’s stated price target for 2020.  There is a stated goal of increasing the carbon price beyond this level, but the achievability of such a high carbon price remains unclear, and is not regarded as a base case for the purposes of this calculation.  The calculation assumes 8% real terms discount rate (real, pre-tax).  A further adjustment could be made to take account of the lower risk of the revenue stream from the fixed price contract, which would further increase the value of the longer term nuclear contract. 

Another study by the Solar Parity Project estimates a likely reduction in the cost of solar by 2023 of around 40%.  Costs of solar power from southern Europe in 2013 can readily be estimated as anywhere between around £35-65/MWh or depending on rates of deployment, technology learning rates, how much of present low cost of panels is due to cyclically low prices, whether installation costs can match German levels, and what load factor is achievable.  Corresponding costs for UK solar seem unlikely to be greater than around £80/MWh, although the UK government’s own estimate for 2020 is much higher, at around £100/MWh, for reasons which are unclear (see solar roadmap document

If solar gets cheap enough it is possible that the UK’s poor solar resource would be less of a problem considering cost only – the extra output in southern Europe might be offset by the extra transmission costs at very low cost levels.  However this seems a distant prospect, and anyway land availability and the high population density in England would continue to favour imports.

Exchange rates used are $1.61/£ and €1.19/£. 

Why have the IEA’s projections of renewables growth been so much lower than the out-turn?

The IEA has greatly underestimated the growth of renewables for some years now.  This illustrates how important it is to allow for unexpected outcomes if policy design is to be robust, as even well informed projections can be very different from the subsequent out-turn.

(For an update on the IEA’s projections of renewables see also this post.)

The International Energy Agency’s (IEA’s) annual World Energy Outlook (WEO) is a thorough and well researched analysis of the outlook for the world’s energy systems[1].  Over the years it has become the standard view of the world’s energy use now and in the coming decades.  However it has had an extraordinarily poor track record in projecting the growth of solar and wind power in recent years.  The charts below compare the IEA’s projections over the last few years with the out-turn for both wind and solar.  Projections have been revised upwards each year.  But they have still been consistently too low, by a very large amount in most instances, with the pattern persisting over many years for two different groups of technologies, wind and solar PV.   As recently as 2006 it was expected to take until the 2020s to reach current levels of wind capacity, and until the 2030s to reach current levels of solar capacity, with current solar PV capacity almost an order of magnitude greater than expected in just seven years ago.

The IEA’s projections have consistently increased over the years, but still fallen short of actual deployment ….

wind and solar past projections

It would, of course, be wrong to suggest that because past projections have been underestimates the current projections will also be too low.  However the most recent projections continue to show rates of deployment that appear very cautious.  The graphs below show the IEA’s projected rate of installation in the most recent WEO (for 2012) under its central New Policies scenario compared with past and current growth rates.  For both wind and solar projected installation rates start below 2012 levels and remain roughly constant or fall over time.

IEA’s projection show declining rates of deployment for both wind and solar …

wind and solar current projections

Decreases in installation rates are of course possible.  Wind installation seems likely to be lower this year than last, although the rate of solar deployment continues to grow.  However, projecting flat or slowly declining installation rates over the next couple of decades suggests either that current rates are a spike, or that installation is moving towards saturation.  Neither of these possibilities seems likely.  Costs are continuing to fall, especially for solar, renewables still account for a very small share of total generation, and drivers towards deployment of low carbon technologies seem likely to strengthen rather than weaken over the period.  One does not need to be an advocate of renewables to expect that these industries are more likely to grow than shrink over the next couple of decades, even if growth of annual deployment may be much slower than in the past.  It would seem more plausible if a central case scenario were projecting some continuing growth in annual installation, with decreases very much a low case.   It will be interesting to see how these projections are adjusted in the next edition of the WEO due out in a few weeks.

So what has led to this persistent underestimation of growth?  There may have been a reliance on individual jurisdictions’ plans, with more caution than seems with hindsight to have been warranted about the rate at which policy might move.  This seems to have led to linear extrapolation of capacities when technologies were in a phase of exponential growth.  Projections for wind have improved in recently years as growth appears to have become more linear (at least temporarily), and following a large upward revision in the projected rate of addition between the 2009 and 2010 editions of the WEO.  It may also be that there is some inherent caution about new technologies.  However the IEA – along with many others – has tended, if anything, to be somewhat optimistic about CCS, so this cannot be a complete explanation.  There are also specific circumstances that have played a role, notably being somewhat slow to recognise the falling costs of solar PV, with even the costs from the 2012 edition being well above actual values[2].

There may also be a deeper explanation rooted in institutional conservatism.  Taking a conservative view of future prospects in the energy sector can be necessary to avoid being swayed by the latest fad.  A conservative view recognises the realities of the long time horizons and vast scale of the world’s energy systems.  However it can carry the risk of missing the role of genuinely transformative technologies, as appears to be the case here.  The IEA’s current caution may still prove justified.  But  Eurelectric, the European power industry association, noted in a recent report that the European power sector is already undergoing one of the largest transformations in its history[3].  Such changes seem likely to be a global phenomenon.  Wind and (especially) solar PV seem likely to form part of the largest transformation of the energy sector at least since the growth of oil consumption in the middle decades of the 20th century, and perhaps since the invention of the steam engine.  The IEA seems to be slow to recognise this.

Whichever way the future turns out, the IEA’s past projections show how different actual out-turns can be from even well-informed projections.  This provides and important reminder that none of us can be sure about future changes to the energy sector, and policy design must always be robust against things turning out to be different from expectations.

Adam Whitmore – 8th October 2013