Tag Archives: renewables

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 https://www.gov.uk/government/news/initial-agreement-reached-on-new-nuclear-power-station-at-hinkley 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.   https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/209361/Levy_Control_Framework_and_Draft_CfD_Strike_Prices.pdf

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.   http://www.pvparity.eu/fileadmin/PVPARITY_docs/public/PV_PARITY_D44_Grid_integration_cost_of_PV_-_Final_300913.pdf  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 https://www.gov.uk/government/publications/uk-solar-pv-strategy-part-1-roadmap-to-a-brighter-future).

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

Solar deployment – are there limits as costs come down?

A kWh is a different product depending on when and where it is delivered.  The rapid fall in the costs of solar PV implies that building grids, storage and commercial arrangements able to match supply and demand is much more urgent.  This will require strong policy drivers.

Falling costs are making solar PV increasingly competitive with other forms of electricity generation.  This post looks at what might limit solar PV’s deployment if costs continue to fall and reach levels low enough to allow for additional expenditure on grids, storage and demand-side infrastructure while remaining economically competitive.   I’m not taking a view on if or when this will happen, or how low costs might become – there is still a significant way to go to reach that point on a global basis.  I’m simply looking at what the remaining barriers would be if they did.  I’ll use some rough and ready numbers to look at what it might take for solar to produce around a third of the world’s electricity consumption.  I’ll assume this illustratively to be about 17,000TWh (out of a total of around 50,000TWh) by mid-century[1], which would be around 180 times the 2012 total of around 93TWh[2] of solar PV output.

As has often been noted, the solar resource is easily large enough to provide such large amounts of electricity.  Recent data from the US National Renewable Energy Laboratories (NREL) shows average US output of 70kWh/m2 based on total site area (i.e. not only the panels)[3].   Generating 17,000TWh on this basis (likely a conservative assumption, as panel efficiency is likely to increase over time) would require an area of around 240,000km2, less than 0.2% of the world’s land surface.  This is a huge area – about the size of the United Kingdom – but 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.   Local planning and environmental concerns seem likely to become a more prominent issue as solar deployment grows.  However these concerns seem unlikely to place a fundamental limit on the industry globally.

A solar industry meeting a third of world electricity demand would be very large, but not infeasibly so.  It would require about 300GW of capacity to be added each year on average worldwide, around 10 times the 2012 installation rate, which has grown to its current level in just a few years.

However, matching the location and timing of supply to demand is a huge challenge.  Electricity at a different time and place is a different product and so part of a separate market.  Grids and storage help link these different markets[4] and so minimise load shedding (though some may still be required).

The first problem is geographical proximity.  In some cases (such as California and Mexico) demand is quite close to high quality solar resources.  However in densely populated countries with weak solar resources, such as the UK, the challenge is much greater[5].  Electricity may need to be brought from sunnier regions, especially in winter, requiring large scale transmission infrastructure.  There may be more local issues. For example in Japan, grid reinforcement will be needed to bring power from the north to more populous areas, crossing boundaries between regional utilities[6].  However problems in this respect may not be universal.  One recent study indicated that the German grid is already quite robust[7].

Matching the timing of output and demand is even more problematic.  Solar output is much peakier than system demand, and peak output and demand will often not coincide.  One indication is that load balancing becomes a significant problem when solar begins to account for more than around 10-15% of generation[8].

As solar penetration increases relative prices at different times of day are likely to shift, which may well cause demand to respond.  More sophisticated market arrangements and system operation are likely to become important features of most scenarios with extensive penetration of renewables.

Matching the timing of peaks by moving power from where the sun is shining to where the demand is located could imply  tens or hundreds of GW of power to be moved across continental distances.  This is because the point at which the sun is highest in the sky (around noon), when solar output tends to be at its maximum, moves quite quickly across the surface of the earth.  At the equator it travels at just over 1000miles/hour, implying that to service demand even an hour later in the day power must be moved hundreds of miles from west to east.  The chart below shows how far west you need to go to shift the time of peak one hour later at the latitudes of some of the world’s major cities.  To move the peak a quarter of the day – from a noon production peak to 6pm demand – you need to move power a quarter of the way round the world.  And the direction does not always help.  To meet later demand on the US west coast solar panels would need to be out in the Pacific Ocean rather than Arizona and Texas. ( Putting more west facing panels in California itself helps this.  There is some loss of total output but the match to system peak improves).  China, with its population concentrated on the east coast, is better served in the evening, but would run into problems in the morning.  This implies that load balancing using transmission will be a huge challenge from a technological, regulatory and commercial perspective.

Solar production needs to be hundreds of miles west to meet a demand peak one hour later in the day at the latitude of the world’s major cities…

Chart of distance

Even the most extensive links may not be enough on occasions when the sun is over the oceans.  The map below shows where the sun is shining at midnight GMT on 21st December.  There is an hour or so of setting winter sun still left on the US west coast, and the weak first hour or two of the day’s output from panels in east Asia, with Australia in daylight (and therefore with some intriguing export possibilities if links can be built far enough).  But the whole of Europe, Africa, the Middle East, India, and almost all of Russia and North and South America and a good deal of the rest of Asia are in darkness.

daylight map

Building storage to address this problem is challenging because of the huge scale needed, as well as because of  the cost.  The subject is too large to go into here in detail, although one recent study showed it to be crucial for reaching a third of supply in  North America  [9]. In northern Europe very large amounts of storage are required even to balance load within the day. Seasonal storage (because for example average intensity of sunlight in the UK is nine times higher in summer than in winter) would require enormous capacity[10]Germany’s subsidy for storage as part of new residential PV systems, which was introduced in May, and California’s plan for 1300MW of storage by 2020 are early examples of the type of initiative that is likely to be required.  Among other effects the premium for hydro power for load balancing is likely to increase.  And reductions in load factor due to no storage being available and so surplus remaining unused at peak will be less of a problem the lower the capital costs of solar become.

Building transmission and storage infrastructure, along with the arrangements to manage them, will take decades at the scale required.  And getting the costs of storage down will also be hugely challenging.  This will be accompanied by the need to make significant changes to market mechanisms so that they can more effectively balance supply and demand.  None of this will be achieved easily, and strong policy drivers are likely to be required for this to happen as fast as now looks likely to be required if solar is to play a central role in decarbonising power systems.

Few expected solar to become quite so cost competitive quite so quickly.  This largely unanticipated increase in competitiveness leads to a similarly accelerated programme now being required to build grids and storage able to incorporate increasingly large amounts of solar into the world’s power systems.

Adam Whitmore  –  25th September 2013

[1] This is broadly similar to Shell’s Oceans Scenario, which shows 20,800 TWh of solar generation, 36% of a total of 57,800TWh.  The total consumption considered here is based on an extrapolation to 2050 of the IEA’s New Policies scenario for 2035 to 2050.  This may be higher with increased electrification of end use.  It may be lower with greater efficiency, but in any case only intended to indicate order of magnitude.  See http://s01.static-shell.com/content/dam/shell-new/local/corporate/Scenarios/Downloads/Scenarios_newdoc.pdf

[2] Source BP Statistical Review of world energy, 2013

[3] http://www.nrel.gov/docs/fy13osti/56290.pdf.  I’ve taken the average for large solar of 3.4 acres per GWh.

[4] Consumers cannot readily substitute between consumption in different places and at different times – you need electricity in your living room now, and electricity in someone else’s living room later is not the same product.  A hypothetical monopolist could profitably impose a small but significant non-transitory increase in price, implying that the markets are separate.

[5] David MacKay. Solar energy in the context of energy use, energy transportation ans energy storage.  Philosophical Transactions of the Royal Society Vol 371,number 1996.

[10] See reference 3 above for a discussion of this point.