‘Solar Annuities’

‘Pre-accredited’ solar farms offer inflation-protected and secure returns and are viable alternatives to conventional annuities.

1, The government has fiercely cut support for large-scale PV farms, taking prospective returns to well below the levels required by financial investors.

2, However a small number of locations with ‘pre-accredited’ allocations of renewable obligation certificates (‘ROCs’) are still possibly financeable. These farms will receive 1.2 ROCs per megawatt hour produced, worth over £50, as well as the price for the power produced. Crucially, the value of ROCs inflates with retail price inflation, or RPI.

3, The 1.2 ROC regime for pre-accredited sites ends in March 2017. To benefit from the scheme, money will need to be committed by end-November 2016.

4, Working with Jonathan Thompson, the CEO of PV developer Green Nation, we have calculated that the remaining pre-accredited sites will typically produce a stream of cash that is twice the amount that would be returned to a person buying a conventional financial annuity, even under very cautious assumptions about costs and incomes.

5, A PV farm with ROC income for 20 years therefore presents an attractive investment opportunity for an annuity-seeking individual wishing to obtain protection against inflation.

Annuities

6, Annuity rates are unprecedentedly low. In fact, for a person aged 65 buying an annuity with the payout linked to RPI, the amount paid out will not return the initial investment for an individual with a life expectancy of someone living in the UK’s longest-lived local government area.

7, Today’s RPI-linked annuity rates produce about £2,570 per year for each £100,000 invested for a 65 year old, with a 5 year guarantee and paid only until the death of the individual. (If inflation is zero, the total amount paid out will only exceed the amount invested if the individual lives 39 years). See http://www.ft.com/personal-finance/annuity-table?ft_site=falcon&desktop=true .

8, The average life expectancy of a 65 year old man in England and Wales is 18.8 years. For a woman, it is 21.2 years.

9, The typical person buying a conventional annuity is likely to live longer (partly because they are more prosperous than the average). For men in the longest-lived area (Kensington and Chelsea) life expectancy at age 65 is 21.6 years and for women 24.6 years (Camden).

10, For a man with 21.6 years more life, the total return in real terms from a £100,000 invested in annuities is just £55,600.

11, The reason that this number is so low is that annuity providers are obliged to buy index-linked government bonds (‘gilts’) to fund future payments. 20 year indexed bonds currently trade at a real interest rate of about minus 1.82%. All gilt yields are very low but index linked bonds cost substantial amounts of money to hold. Protecting future income against the effects of inflation is very, very expensive indeed. https://www.fixedincomeinvestor.co.uk/x/bondtable.html?groupid=3530

12, A saver can also buy an annuity that does not rise with inflation but instead stays constant. The FT’s annuity table suggests that such purchase returns about £4,528 each year for each £100,000 invested. Even if inflation is zero, the person of average life expectancy also does not receive his (or her) investment back during their lives.

Investment in solar farms as an alternative to annuities

13, The underlying reason why solar farms paid through the ROC system are competitors to annuities is that the subsidy payment is linked to RPI inflation. An investor buying a share in a solar farm is purchasing a right to income that will rise at the same rate as retail prices.

14, A stand-alone solar farm receives both ROCs and also sells the electricity that it generates in the wholesale markets. In the simple model we have prepared, based upon Green Nation’s solar farm evaluation spreadsheet, the price of electricity falls by 2% a year against the average price in the economy. (Therefore if RPI is rising at 3%, wholesale electricity will only increase 1% per year). Almost all forecasters see electricity prices rising faster than general inflation so this assumption will be seen as extremely cautious.

15, Based on a recent offer from one of the largest second-tier electricity retailers, Green Nation believes wholesale electricity is currently worth about £46 per megawatt hour for a two year fixed period deal. We believe this price is higher than can be sustained. So not only do we deflate electricity prices each year but we also switch to price below £40 for year 3 of the model. Again, this is a highly conservative choice.

16, Other assumptions in the model are the same as Green Nation conventionally uses. We calculate the free cash flow for each year of operation.

17, The yearly payments to the annuity investor are as seen in the chart below. (The figures assume 2% RPI inflation). The cash continues for 21 years, the average length of ROC payments are only made for 20 years, hence the sharp fall in payments from the solar farm in the final period.

 

18, The total payments to investors under different RPI assumptions are given in the table below for the whole 21 year average life and an initial investment of £100,000. At all inflation rates between 0% and 4%, the PV farm returns more than twice an RPI-linked annuity.

 

     RPI inflation                             0%                    2%                   4%

PV farm 'annuity'                   £128,430             £160,746        £202,764

RPI linked annuity                  £54,054               £66,366         £82,289

Flat annuity                             £95,088               £95,088         £95,088

 

19, What are the prospective difficulties for an investor? First, the PV farm is of a pre-determined duration. It will return cash for 21 years (or until its planning permission expires, probably after 25 years). So a very long lived investor will not gain as much. But even an investor living to 100 will generally be better off overall with a holding in a PV farm. Second, the cash return is partly dependent on the wholesale price of electricity. However if the wholesale price falls to 50% of current levels in 2019, and continues to decline at RPI-2% after that, the PV farm returns far more cash than an RPI-linked conventional annuity. Third, the investor also faces a small degree of operational risk because the farm may not work as well as expected. (Though most UK solar farms have actually outperformed their initial plans). This last risk can be mitigated by using a mixture of two or more farms to provide the annuity

20, Next steps. Although other groups have tried to make ‘solar annuities’ work, the returns have been limited by large intermediary fees. We seek discussions with financial institutions interested in exploring ways of developing the idea contained in this short paper. We should say that there is limited scope for earning high returns for either organising or retailing this scheme. The bulk of the cash will need to be provided to annuity holders.

Chris Goodall

chris@carboncommentary.com

07767 386696

Better average outputs will mean UK wind will frequently meet entire national electricity needs

A new analysis shows that Britain’s wind farms are expected to get much more efficient. In recent years, the typical wind farm has produced about 32.4% of the maximum output. This is projected to rise to 39.4% in the next twenty years, a rise of over 20%. The increase comes from taller towers, bigger turbines and, most importantly, an increased number of offshore wind farms, which benefit from much higher average winds.

The recent paper by Iain Staffell at Imperial College and Stefan Pfenninger at ETH in Zurich uses a new method of forecasting turbine outputs called Reanalysis. This technique utilises historical atmospheric pressure data from NASA and other sources to estimate wind speeds at high resolution. Based on estimates of past wind speeds, the authors then forecast how much electricity the wind farms planned to be build around Europe will generate. The results have been checked by comparing them to the actual output achieved by existing wind farms.

The improvement in UK wind farm outputs are matched by increases in other countries. Most importantly, Germany is expected to see an increase from 19.5% efficiency now to over 29% in 2035. This huge rise comes from the rapid shift of new wind farm construction into the Baltic and North Seas. The average efficiency (often called the ‘capacity factor’) across Europe is projected to grow by nearly a third from 24.2% to 31.3%.

Staffell and Pfenninger’s paper provides a similar, but slightly higher, figure to the recent report from the ECIU think tank, which projected that average UK wind farms would achieve a capacity factor of 33% onshore and 40% offshore by 2030, thus averaging perhaps 37%.

The supporting data and software tools will be extraordinarily valuable to those groups, such as grid operators, looking at the likely impact of growing amounts of wind power.

In the main body of this article I use the research results to roughly predict how often wind power will cover all the UK’s needs by 2035, displacing all other forms of generation, including nuclear. This is an amateur example of how the Staffell and Pfenninger tools can be used.

What do the results mean for the UK?

Staffell and Pfenninger have counted the capacity of new wind farms now under construction or at some point in the UK planning process. They indicate that within twenty years the country could have up to 42.3 gigawatts (GW) of turbines. (The figure today is about 13 GW, including those not connected to the main transmission grid).

42.3 GW working at a capacity factor of 39.4% will provide about 146 Terawatt hours (TWh) of electricity. This is about 40% of the UK’s total need at present. National demand has been generally falling in recent years as a result of energy efficiency. This may continue, particularly as LED lighting replaces halogens and other types of bulbs. But new demands for power for charging cars and heating homes using heat pumps may stabilise the downward trend and will, in all probability, cause power needs to start to rise by the middle of the next decade. But 146 TWh will still provide a large fraction of total national requirements.

More specifically, what does greater wind output imply for other sources of electricity generation in the UK?

The electricity generated varies from almost nothing up to a maximum of about 90% of the rated capacity of wind farms. To some extent, the swings are predictable. We know that atmospheric conditions can mean one storm after another charging in from the Atlantic separated by four or five days. We also recognise that winter wind speeds are higher than those in July. Late autumn is surprisingly good. However conditions still vary dramatically from week to week, a fact that opponents of wind turbines focus upon.

Staffell and Pfenninger’s paper provides some extremely valuable new data on the daily and monthly variability of wind in the UK and other countries. It shows, for example, that typical wind speeds are roughly the same across all 24 hours in winter but that summer months see a peak in late afternoon.  (All their research is now freely available online, along with their modelling tools. I cannot stress enough how useful this will be to researchers and policy planners).

In the work below. I use their estimates of the capacity factor achieved by UK wind farms during the windiest 5% of the time. At the moment, this figure is 68% of maximum capacity. (Put another way, for five percent of the time each year, UK wind farms are producing at least 68% of their rated maximum output).

I have used, of course, different figures for each season for capacity factors because it is windier in winter and autumn. Winter is assumed in my rough analysis to see a capacity factor of 80% for the windiest 5% of the time in 2035, autumn is 75%, spring is 60% and summer 50%. These numbers are guesses but based on the averages in the Staffell/Pfenninger paper. They are unlikely to be significantly wrong. (Seasons are Months 12,1,2, Months 3,4,5, Months 6,7,8 and Months 9, 10 and 11).

In the remainder of this article I use their figures to make a rough estimate of how much of the time wind power in 2035 would fully cover today’s needs. I have had to make some guesses in my analysis, but a researcher devoting time and using the online resources would be able to make a clear estimate of the number of hours that wind will completely meet all UK requirements.

My result shows that in autumn and winter wind power is likely to be greater than national need on a substantial number of occasions. Every night in October 2015, for example, had total UK demand less than would have been provided by 42.3 GW of wind power on the windiest 5% of autumn 24 hour periods. Summer will see some half hours when wind exceeds demand however spring will see a surplus very infrequently indeed.

Why am I writing this article now? Because Staffell and Pfenninger’s work shows that some of the time the UK will have excess power and therefore needs to work harder to develop long-term energy storage able to take weeks of surplus electricity. Long term or ‘seasonal’ storage must move to the front of the research agenda.

And, second, if storage capability is not developed, Hinkley Point C will simply not be needed for substantial amounts of time from November to February. And this is before thinking about solar power (providing about 4% of UK electricity already), hydro, anaerobic digestion and other renewable sources such as the new tidal power farms in Scotland. The growth of intermittent renewables will eventually mean that the UK has too much power at times of high wind and sun to be able to cope with highly inflexible large-scale nuclear.

I have tried to express this as best I can in the following charts with the prospective wind output superimposed over the total UK demand for electricity every half hour from August 2015 to July 2016. (I have added in National Grid estimated figures for wind power not attached to the main grid, as well as estimated solar PV output).

Chart 1. The pattern of GB electricity demand (gigawatts)

Chart shows seasonal rise and fall as well as daily swings and differences between night and day, with summer weekend nights showing the lowest demand.

Chart shows seasonal rise and fall as well as daily swings and differences between night and day, with summer weekend nights showing the lowest demand.

Total demand peaked at around 52 GW in the latter part of January 2016. The lowest figures are reached at weekends during the summer. (These charts are built from spreadsheets containing 17,000 lines and details are sometimes blurred). The lowest recorded electricity use was about 20 GW. The period around Christmas sees reduced demand.

Power use during the day is always higher than at night. In winter, peak demand is in early evening. In summer, demand is flat during the day although is increasingly depressed by solar PV output.  Weekends are always lower than weekdays.

Chart 2. GB national demand compared to estimate maximum wind output in 2035

Chart 2 superimposes the maximum wind output in 2035 and a figure of 90% of this level. The 90% figure is the maximum ever likely to be achieved. The 90% line is, at about 38 GW, greater than maximum demand on all almost all weekend days from April until November.

Chart 3. GB national demand compared to average wind power levels in 2035

 

The average amount of wind power over the year in the Staffell/Pfenninger analysis will be about 17 GW and this is shown as a red line on Chart 3. The minimum UK demand is over 20 GW, so average supply never matches need.

Chart 4. GB national demand compared to approximate seasonal averages of wind power levels in 2035

 

 

The average amount of wind varies through the year. But its variations are approximately the same as electricity demand. In other words, although average wind power is greatest in winter, so is demand (Chart 4). The expected average wind production in each season is a similar proportion of the minimum demand.

Chart 5. GB national demand compared to wind output levels during windiest 5% of the year.

Currently, 5% of the time the capacity factor is at least 68%. The line across Chart 5 shows 68% of the expected 2035 installed wind turbine capacity. On average across the year, the 68% capacity factor will exceed minimum daily demand in all months except the winter.

Chart 6. GB total demand compared to the windiest 5% of the time, adjusted for seasonality in wind speeds

A better way of looking at the relationship between high levels of wind output (the 95th percentile level) and demand is to break the year into the four seasons (Chart 6). Wind variability is greater than seasonal changes in demand. In winter, and autumn particularly, high levels of wind turbine output are more likely to exceed total demand. During almost every day from mid-September to February the 95th percentile wind output is likely to exceed the minimum demand. At weekends and at Christmas, the whole daily demand is sometimes covered by the high wind production.

Very high wind production (at the 95th percentile) would cover 100% of some part of the day’s electricity need over about 200 days a year, mostly in winter and autumn. By contrast, in spring and summer, there will be relatively few days on which wind covers all of the demand at any part of the day because very high winds are much more unusual between April and September.

So what does this mean for the number of days each year on which wind production will exceed today’s need? Very roughly, the analysis in this note shows that about 10-15 nights a year wind will provide all the power that is needed, before even thinking about the remaining nuclear stations, anaerobic digestion, batteries, interconnectors, and hydro. Since Hinkley Point C will probably be paid its full agreed price, even if its electricity is not needed, the additional bills to the electricity consumer should be factored into calculations of the full cost of the proposed new nuclear power station.

Is CCS really the answer?

Ambrose Evans-Pritchard (AEP) has written a series of well-informed and persuasive articles on energy in the UK’s Telegraph newspaper over the summer holidays. His topics included wind power and batteries. He also wrote with enthusiasm about carbon capture and storage, a technology that many people think will be needed at enormous scale if the world is to reduce emissions quickly. 

I’d like to believe him. If we could find a way of adding inexpensive CO2 capture units onto existing power stations we might be able to continue to burn coal and gas into the long-term future. The world would have plentiful wind and solar, ready to be supplemented by fossil fuel power when necessary.

Unfortunately, I don’t think AEP is right. CCS will probably always add more cost to electricity than can be financially justified. I work out some numbers below for a power station in Canada with CCS to try to support my assertion. I'm sorry it takes a large number of paragraphs to do this.

Rather than seeing CCS as a way of complementing intermittent renewables, we are better advised to invest in energy storage to provide the buffers we need. When the sun is shining or the wind blowing, we will siphon off power and put it into batteries or transmute it into storable gases and liquid fuels. This is cheaper, and will become cheaper still every passing year.

The AEP vision

·      Add CCS to all fossil power stations

·      Collect and sequester all the CO2

·      Run these power stations all the time, minimising the huge capital cost of CCS per unit of output.

What I say in The Switch

·      Overbuild wind and, particularly, solar PV

·      Take the surplus electricity and use to provide the energy to make renewable fuels (see the previous post on this web site on Daniel Nocera, for example)

·      Store these fuels for times when the sun isn’t shining nor the wind blowing

The CCS process

At a power plant with CCS - of which there is really only one in the world, at Boundary Dam in Saskatchewan, Canada - a fossil fuel is burnt and the flue gas is passed through a solution containing chemicals that bond the CO2 into bicarbonate. The solution is then heated, the bicarbonate breaks up into CO2 and other molecules and concentrated CO2 is collected. This is a relatively simple, well understood process that has been in use for eighty years. Most – perhaps 90% - of the CO2 is collected, and almost all is then regained and can be stored.

In the UK, we envisage storing the CO2 in old oil and gas reservoirs. Storage of the CO2 in this way will add some cost. In other places, the CO2 actually has value because it can be injected into oilfields that are still producing. It enhances the production of fuels. However, it should be said that some of that carbon dioxide returns to the surface dissolved in the extra oil. Only about 75% of the CO2 sent down into a depleting oilfield stays below ground for ever.

CCS costs

Boundary Dam is an old power station that burns lignite on the border between the US and Canada. It is composed of several separate units. One of these boilers – number 3, usually called BD3 – was coming to the end of its life. Its owners, SaskPower, a public utility, decided to replace this unit with a new generating plant capable of producing about 139 MW of electricity. This is enough to meet about 2% of Saskatchewan’s power needs.

The CCS process uses large amounts of energy. About 29 MW of power is devoted to extracting the CO2 and then regaining it. Very roughly, a power station gets about 20% less usable power from its plant with CCS. There are two separate costs arising from the parasitic effect of carbon capture. First, CCS means less electricity output for each dollar of capital expenditure building the power station. Second, the plant has to spend money on fuel to provide the heat and power to run the CCS process.

The third, and much the largest, cost is the carbon capture plant itself. At Boundary Dam, this equipment cost around CAN $900m, or about US $700m.

Lastly, the plant needs people and materials to run the CCS process. The figures for this are the least visible to the outside world, although SaskPower has provided some estimates. They include the cost of manning the CCS plant and purifying and replacing the solution that absorbs the CO2.

How much do these four elements add to the cost of producing electricity?

First of all, I need to specify some assumptions. I guess that Boundary Dam and other CCS plants will last about 30 years. This is a figure you often see as the length of life of today’s coal fired power stations although many of today’s plants in the industrial world will last longer. I assume that the power station works 8,000 hours a year. I use a figure of 5% for the cost of capital, and assume zero inflation.

The price of lignite, the fuel that Boundary Dam uses, is about US $20 a tonne on the US/Canada border. It has an energy value of about 4,500 kWh per tonne. Boundary Dam delivers about 40% efficiency, meaning that one tonne of lignite provides about 1,800 kWh of electricity.

Very roughly, one megawatt hour (1,000 kWh) produced at Boundary Dam results in one tonne of CO2 being emitted. About 90% of all CO2 produced at BD3 is currently being captured.

We’re now in a position to estimate how much CCS costs per unit of electricity produced. And how much per tonne of CO2 captured.

Cost 1. The extra capital needed to build the electricity generating plant because 20% of its output is needed to power the CCS.

The power station part of the 139 MW Boundary Dam unit cost CAN $562m, or about US $450m. 20% of this is US $90m. At a 5% cost of capital over 30 years, the implied yearly cost is about US $6m. The power station produces about 880,000 MWh a year, and the cost is therefore about US $7 per MWh. This figure appears to be omitted from other estimates of the cost of CCS.

Cost 2. The extra lignite burnt to create the power and heat that is used by the CCS apparatus.

The 29 MW of the electricity initially produced at Boundary Dam is devoted to the CCS process. To make this much electricity at a conversion efficiency of 40% requires 72.5 MW of coal energy. This means that each hour about 16 tonnes of coal are needed to meet the electricity (and heat) requirements for CCS. Over the course of the year, the cost is just over US $2.5m dollars and just under US $3 per MWh. For simplicity, I round this number to $3.

Cost 3. The capital equipment needed for carbon capture.

The kit needed to carry out carbon capture cost over CAN $900m, or about US $700m. Over 30 years, and at implied cost of capital of 5%, this adds about US $52 per MWh. (If the cost of capital was 0%, this figure would still be over US $26).

However this figure is the one that may come down sharply when more CCS plants are constructed. SaskPower says the next unit might be 30% cheaper and 50% reductions are possible in time.
Let’s be generous to CCS and use a figure of US $25 per megawatt when the technology is mature.

By the way, the next retrofitted CCS plant, at Petra Nova in Texas, will cost about the same per MW as Boundary Dam and will probably come on stream in about six months. And don’t even mention the extraordinary new build at Kemper in Mississippi. This power station looks as though it will come in at over US 7bn for a coal gasification plant, combined with CCS, totalling less than 600 MW. That makes it more expensive than Hinkley Point per megawatt of output. As importantly, only 65% of the CO2 will be captured. So the optimistic figure of an extra cost $25 per megawatt hour of electricity produced is a really generous assumption.

Cost 4. The annual cost of operating the CCS plant.

A SaskPower presentation seems to suggest a figure of about CAN $9 a MWh, or US $7. . It may go down a bit in future plants but I have not included any improvement because it is likely to be quite small.

(I have had to make the critical assumption that the y axis marks are each CAN $10 on the relevant chart towards the middle of the presentation. This fits with the rest of the SaskPower presentation).

The total

Add these figures together and we get to US $72 per megawatt hour for the implied extra cost of power at BD3. This may go down to US $35 when the CCS technology is completely mature. This will take several decades.

US $72 is substantially more than the current wholesale price of Canadian electricity, which lies in the high US $30s. The implied cost of electricity at Boundary Dam has therefore been nearly tripled by the addition of CCS. Even after future cost reductions, CCS will add almost 100% to the cost of power.

Source: assumptions in text

Source: assumptions in text

The position is actually even worse for CCS. Boundary Dam has been so expensive that it has added substantially to the power bills of provincial residents. One think tank said

With the cost of electricity at 12-14 cents per kilowatt-hour and rising, the province’s economic competitive position will be weaker. Saskatchewan no longer has affordable electricity and it is likely to get more expensive in future, especially if Boundary Dam 4 CCS is built.

This means that the relative attractiveness of wind and solar are inevitably going to grow. Saskatchewan has been blocking wind power for decades, even though conditions on the northern Great Plains are highly favourable for turbines. A cynical observer might suggest that the presence of lignite and a commitment to using it in power generation has warped the decision-taking of the Province. Other accusation, such as undue influence of the company transporting the CO2 for oil recovery, fly about. But at some point the far lower cost of wind than coal electricity is bound to mean a larger number of wind farms across the Province.

Of course Canada is not the best place for sun. But the average PV panel on a house near Boundary Dam will produce at least 20% more than the best UK locations. At some point, PV electricity will replace the need for coal. When that happens, the implied cost of CCS per megawatt hour will rise as the plant is used less and less and costs need to be spread over a smaller amount of electricity.

Neither Canada, nor any other place in the world, should be investing now in generating capacity that needs to work every hour of the year in order to use its capital productively. What we need are sources of energy that can be available for the relatively small number of hours each year that neither the wind nor the sun are present.

The cost of the CO2 savings

 After very severe teething problems, including over 6,000 maintenance calls, Boundary Dam is now producing almost as much sequestered CO2 as planned. 2017 will probably see about 1,000,000 tonnes pipelined to the oil field for increasing output. Of this, about 700,000 tonnes will stay in the ground for ever.

This has cost almost US $70m, or $100 a tonne, assuming constant operation apart from maintenance intervals. After further development, we might be able to get this to about $60, if future plants are fully used for 8,000 hours or so a year.

The alternatives

The last chapter of The Switch looks briefly at some of the alternatives to CCS that provide a renewables-based energy system with its need for month-long buffers and stores. (Short term storage will be offered by batteries). In summary, I write in the book that conversion of surplus electricity at times of high wind or solar output into gases and liquid fuels looks far cheaper than conventional CCS. Direct capture of CO2 from air will probably become cost competitive to the hugely capital intensive process of putting CCS plants beside coal-fired power stations.

Wind on the Great Plains is now producing power at less than 4 cents a kilowatt hour, or sub $40 a megawatt hour, and solar will be at similar level within five years at the Canadian border. Even if 50% of the energy value is lost in a conversion process to natural gas or gasoline, cheap renewable electricity for storage use will cost far less than today’s US $72 per megawatt hour at Boundary Dam. And we won’t have the 10% of fugitive CO2 emissions being added to the atmosphere all the time.

(NB The arguments about CCS on steel, cement and plastics plants are more complex and I have failed to address them here).

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Artificial photosynthesis and the future of energy

Daniel Nocera, the rock-star of artificial photosynthesis, and his colleagues at Harvard published a paper in June that shows a viable route to long-term energy storage. The Science article demonstrates how surplus power from solar PV can be converted into liquid fuels. The electricity is used to split hydrogen which is then fed to an engineered bacterium (Ralstonia Eutropha) alongside carbon dioxide. The bug ‘eats’ the gases and exudes useful, and highly storable, alcohols such as isobutanol. The conversion efficiency of the energy in electricity to valuable fuels is about 40% in his laboratory. Albeit only at the early experimental level, we now have the potential for an all-natural green refinery for renewable liquid fuels.

Of critical importance, Nocera’s team shows that the bacterium will generate alcohols in the presence of oxygen (which is not the case with most methanogens and acetogens, two other classes of microbes being investigated as the potential workforces in green refineries). Equally vitally, the work seems to indicate that Ralstonia Eutropha is happy to consume CO2 at the very low concentrations found in ambient air. No necessary requirement for expensive carbon capture.

Liquids such as isobutanol are energy dense – perhaps holding twenty-five times as much power per litre as a battery –  and are safe to store and easy to ship. We can use the existing infrastructure of pipelines, tankers and storage tanks. Burn isobutanol in your existing petrol car and you will get motion (although you might have to add 15% conventional gasoline as well). It can also be stored and eventually combusted in a turbine to make electricity at a later date if necessary.

Will generating liquid fuels in green refineries will eventually become cost-competitive with fossil energy sources? Yes. But, based on the numbers in the Nocera paper, it looks at first sight as though this might take some time.

·      What is the current price of liquid fossil fuels (Friday, August 10th 2016?

Barrel of oil

$49

Number of litres per barrel

159

Therefore, cost of crude per litre

$0.295

Approximate cost of processing crude to get to petrol/gasoline

$0.080

Therefore, wholesale cost of petrol/gasoline

About 37.5 US cents per litre

·      What might it cost to get isobutanol using artificial photosynthesis today?

Amount of energy in a litre of isobutanol

About 8 kilowatt hours

Efficiency of conversion of solar electricity into isobutanol in Nocera work

About 40%

Therefore, required solar-produced electricity to generate one litre of isobutanol

20 kilowatt hours

The cost of electricity purchased from solar farms in best locations in 2016*

4 cents a kilowatt hour

Cost of making a litre of isobutanol from solar PV in the best locations

About 80 cents a litre

*This is the approximate price paid by the electricity utility for PV in recent auctions in the Middle East for all the yearly output of a solar farm. However, this number has been as low as just under 3 cents a kilowatt hour in some 2016 auctions.

These two tables show that solar gasoline is apparently over twice as expensive as the fossil equivalent: 80 cents versus 37.5 cents per litre for the average cost of production. (And this is after making the wholly unfair assumption that the green refinery costs nothing to operate). Solar costs will continue to fall sharply around the world, but parity with $49 oil for generating liquid fuels is probably the best part of a decade away.  However the numbers in the boxes do suggest that the world will never see oil prices sustained above $100 again because at that level using electricity to make fuels may be already cheaper today than that level.

At this point we need to ask the question ‘Why would anybody want to convert valuable electricity into less valuable oil? In the UK, wholesale electricity today is usually worth about £40 a megawatt hour while gasoline/petrol sells for the equivalent of £25 a megawatt hour before taxes at today’s oil prices.

The answer is that gasoline can be stored easily and electricity cannot be. So when we have too much electricity, the world needs to convert it into fuel gases and liquids. Otherwise it is wasted. So, even before the further fall in solar PV costs in years to come, Nocera’s technology has a possible use. It will help us cope with otherwise problematic surpluses of power.

Take Sunday 7th August, for example. Strong winds and reasonable sun caused near-havoc in the electricity market, in the UK and also around northern Europe. The average price of power over the course of the day bought and sold by the UK National Grid as it balanced supply and demand was just over £1 per megawatt hour. This isn’t a typo; electricity was essentially worthless last Sunday. During the early afternoon, the price fell to less than negative £60. What precisely does this mean? In those four hours National Grid was offering £60 a megawatt hour to anybody who would either cut their production of electricity or add to their demand. (I think this may have been the day of lowest average very short term electricity prices ever seen in the UK – please correct me if I am wrong).

If your business had taken negative £60/MWh electricity on Sunday and used it to make isobutanol in a Nocera refinery you would have made a turn of almost £100 per megawatt hour. That is why we will see artificial photosynthesis soon.

Last Sunday was atypical. But it will become increasingly common to see very low prices as offshore wind grows (and even solar continues to edge up as companies put unsubsidised panels on their warehouse and factory roofs). On these occasions, the value of converting power to liquids, or indeed power to gas, as Electrochaea is showing so impressively at its commercial trial in Copenhagen using methanogens to make natural gas, is clear-cut. It will stabilise the electricity market as well.

And when solar and wind are in short supply, the liquid fuels made originally from solar PV via artificial photosynthesis can be productively combusted in turbines to make the needed electricity. To make a complete transition to renewable energy sources the world needs energy storage on a truly massive scale. High latitude countries, such as the UK, will need to have perhaps one third of their annual energy demand available in storage buffers. Power to liquids and power to gas are the way forward, providing the responsiveness and flexibility that new nuclear power stations unfortunately lack.

There are about ten early stage technologies around the world for turning seasonal surpluses of power into gas or liquid form. Daniel Nocera’s route is therefore one of many. The sensible industrial strategy for the UK government would to use the country’s skills in bioengineering to build commercial operations using several of these approaches. Government R+D money is vital now.  It is no accident that much of Nocera’s team’s groundbreaking work is funded by US government agencies, including the navy and air force.

·      Several of the other power to gas and power to liquids approaches are covered in the final chapter of The Switch.

·      Thank you to Phil Levermore, Managing Director of the not-for-profit utility Ebico, for his help on last Sunday’s prices in the UK balancing market.

 

 

 

 

 

 

An industrial strategy for energy

(This article was first published on OpenDemocracy). 

In early July, French parliamentarians produced a report on EdF, the largely state-owned electricity company that wants to build a new nuclear power station at Hinkley Point. The legislators concluded that the Hinkley project ‘is probably the last opportunity for EdF to restore the reputation of the French nuclear industry internationally and gain new business in a highly competitive market’. The implication was clear; Hinkley is a central part of the national industrial strategy of France.

The nuclear power station will proceed not because it is good for Britain or its electricity users but because the French state thinks that maintaining the capacity to export nuclear power stations is a paramount objective. And, by the way, France itself is closing down the nuclear plants on its own soil as fast as it can, with no intention of replacing them. Instead it is driving forward with solar and wind.

A few days after the French parliamentary report, the UK’s National Audit Office brought out its own report on nuclear power. Among its conclusions was a calculation that Hinkley will receive subsidies of about £30bn in the first thirty five years of its life. This figure is the difference between the open-market price of electricity and the much higher figure paid to EdF for the electricity produced by the proposed new power station. Directly and indirectly through higher prices of goods and services, the average UK household will pay about £32 a year for more than three decades for the privilege of supporting the French industrial strategy.

In fact, the NAO figures are probably too optimistic. It assumed wholesale electricity prices of around £60 per megawatt hour. Based on today’s trades, the electricity market thinks differently. Wholesale prices for 2018 - the best guide we have to the future - are around £41, or less than 70% of the NAO’s figure. If the cost of wholesale electricity remains at this level, Hinkley won’t cost UK households £30bn but the rather larger figure of £47bn.

Estimates for the underlying price of putting nuclear power on the grid continue to rise sharply. Nuclear power stations being built around the world today are almost all very much more costly than predicted and are taking several years longer to build than promised. The most troublesome new plant - at Olkiluoto in Finland - is now slated to start generating in late 2018, about eight years late. The cost overruns have near-bankrupted the developer, which is now fighting legal battles over $5bn of claims and counter-claims in international arbitration. Olkiluoto is built to the same design as Hinkley, suggesting that the French unions and EdF middle managers that are so opposed to the UK power station have considerable logic behind them.

The NAO acknowledges the cost inflation of nuclear power around the world and also notes that solar and wind require lower subsidies. One chart in its report shows this point clearly. By 2025, the earliest conceivable date by which Hinkley could be providing electricity, the NAO sees solar costing £60 a megawatt hour (about 65% of nuclear’s cost) with onshore wind at a similar figure. In other words, the subsidy needed by solar is expected to be little more than a third of that required by EdF.

What’s also clear is that while nuclear power is tending to get more expensive, wind and solar get cheaper and cheaper every year. Even experts find it difficult to keep up with the speed of the change. In 2010, the government’s energy department said that solar would cost £180 a megawatt hour in 2025. The most recent estimates, less than six years later, are no more than a third of this level. And, by the way, this failure to predict the steepness of decline in the costs of solar power is characteristic of all governmental and research institute forecasts around the world. The likelihood is that by 2025 solar will actually need no subsidies at all, even in the gloomier parts of the UK.

Nobody really disputes any of this. Even the NAO acknowledges that the only remaining argument in favour of the ‘cathedral within a cathedral’ at Hinkley is that nuclear gives the UK what is known as baseload power.[1] This comment mirrors an assessment by the new UK Chancellor, Philip Hammond, who described security of energy supply as an ‘absolute prerequisite’ in a BBC interview on July 14th, although he did also admit he hadn’t seen the new cost figures from the NAO. A well-functioning nuclear power station will provide a stable and consistent output for every hour of the year. It cannot be turned up and down as power needs vary during the year. Mr Hammond sees this an an advantage but as renewable sources grow in importance, the opposite is likely to be true. Modern economies actually don’t want baseload at all; we need electricity sources that ramp up and down to complement highly variable amounts of wind, solar and other renewables. Inflexible nuclear power is the worst possible fit with increasingly cheap but intermittent – although predictable - sources of low-carbon energy.

By 2025 the UK will probably have at least 18 gigawatts of offshore wind and perhaps 12 gigawatts of onshore wind. My guess is that we might see at least 25 gigawatts of solar power, and it could be much more if photovoltaic technologies continue to surprise us with rapid declines in price. (We already have about 12 gigawatts, mostly added in the last two years). The scope for continued improvement in the cost and performance of solar is substantial.

Total demand for electricity falls as low as 19 gigawatts in summer compared to the 55 gigawatts of renewables. So there will be many occasions when the UK has too much power and nuclear power will be unnecessary. On other occasions, such as still December evenings, demand will be 50 gigawatts or so and solar and wind will be producing a fraction of the amount required. The 3 gigawatts at Hinkley will be helpful but insufficient.

Here then is the challenge facing Greg Clark, the new minister in charge of both energy and ‘industrial strategy’. How does the UK avoid becoming the testbed for France’s horrendously expensive nuclear technologies and the proving ground for EdF, its national champion? What technologies will come to the fore that allow the world to switch principally to cheap solar power, by far the most abundant source of renewable energy? In what technologies can the UK develop knowledge and skills that both provide us both with the reliable power that Philip Hammond stressed is needed but also give us goods to make and to export?

Batteries aren’t the answer for us. Although the energy storing potential of lithium ion cells is substantial, they will never get northern latitude countries like the UK through the winter. We have little sun and sometimes the wind doesn’t blow for weeks at a time. Batteries won’t hold enough electricity. And, second, the car makers and the Asian industrial companies that make their batteries have that market already cornered.  The UK would be wasting its money on R+D in this area.

The real opportunity is finding ways of storing large amounts of energy for months at a time. This is where the need is greatest, and the possible return most obvious. More precisely, what we require are technologies that take the increasing amounts of surplus power from sun or wind and turn this energy into storable fuels. In The Switch, a book just out from Profile Books, I explore the best ways of converting cheap electricity from renewables into natural gas and into liquid fuels similar to petrol or diesel so provide huge buffers of energy storage.

This sounds like alchemy. It is not. Surplus electricity can be used to split water into hydrogen and oxygen. Carbon dioxide and hydrogen can then be merged by microbes to make more complex molecules, such as methane. Methane is the main constituent of natural gas, so it can be simply stored in the existing gas network. Other microbes take carbon and hydrogen molecules and turn them into liquids that can be kept in the oil storage networks.

Many companies around the world are trying to commercialise zero-carbon gas and green fuels as natural complements to solar and wind. This is where Greg Clark’s new industrial strategy could really make a difference. A few percent of the £30bn+ subsidy for Hinkley devoted to conversion technologies that can take cheap electricity and use it to store energy in gas or liquids could help build British companies that could expand around the world. The UK’s ability in applied biochemistry is acknowledged and the country could become the global research and manufacturing centre. We missed the early opportunity to develop a large onshore wind industry and gave the market to Denmark twenty years ago. Brexit threatens to have the same impact on offshore wind fabrication here. Greg Clark has the chance to support an even larger industry developing chemical transformation technologies for seasonal storage. Let’s not miss this opportunity.

[1] This phrase was used in a public lecture by Cambridge University’s Tony Roulstone, a nuclear engineer who trains postgraduates.

 

Solar on the best UK sites competitive with cheap coal

How much more energy do we get from open cast coal mines compared to solar PV? And how much do the two alternatives cost?

A week ago Northumberland council gave planning permission to a new open-cast coal mine at Druridge on the coastline just north of Newcastle. About 3 million tonnes of coal will be extracted over a five to seven year period from an area of around 350 hectares, including storage space. (350 hectares is about 1.4 square miles)

The environmental objections to the plan are striking. For example, the owners predict about 170 HGV movements a day along local roads during the whole lifetime of the project. The landscape impact is also severe although the developers say they will ensure that the local sandy beaches are unaffected. But what about the benefits of the energy produced? How do they compare to using the land to generate electricity from PV?

The answer is surprising. Burnt in a coal-fired power station, the coal extracted from the mine will deliver only about twice as much electricity as would solar panels installed on the same site over their lives. The UK could get the same energy from the sun on only twice as much land as the coal mine, with very low emissions and limited environmental impact.

Comparison of energy production: the coal mine

1, The total output of the mine is going to be at least 3 million tonnes of coal. (Higher figures are sometimes quoted but these seem to relate to the original mine, now with planning permission, plus several extensions that are not in the current plan).

2, Coal of the type produced at the mine will yield about 8,000 kWh per tonne. (This number is approximate).

3, So the total energy value of the development will be about 24,000 million kWh, or about 24 terawatt hours. (A terawatt hour is a thousand million kWh).

4, Burnt in Drax power station in Yorkshire, the energy value of the coal will be converted to electricity at an efficiency of just less than 40%. The total coal output of the open-cast mine will therefore produce between 9 and 10 terawatt hours of power, or about 3% of one year’s UK electricity output. Let’s call this 10 TWh.

5, The operation of the mine and the shipment of the coal by heavy good vehicle and rail will subtract from the net energy value of the coal produced. But the percentage impact will be quite small - perhaps no more than 5% - so I have ignored it.

A PV farm on the same site

6, The open cast site consists of an area of about 250 hectares of mined land and approximately 100 further hectares that will be used for storage and shipment. The total is about 350 hectares.

7, A tightly packed solar farm of around 170 megawatts capacity could be accommodated on this area. It would last about 35 years. (Future improvements in panel efficiency would increase the amount of power available per unit area. I have not included this).

8, A solar array of one kilowatt facing due south in the Newcastle area will typically produce just over 900 kWh per year. Allowing for losses in the system, the figure may fall to around 850 kWh per year.

9, The total annual output of a huge solar farm on the open-cast site would be about 0.144 terawatt hours a year. Over the life of the farm, just under 5 terawatt hours would be produced, assuming a slow rate of degradation of panel performance.

 

The coal from the site will therefore produce about twice the energy from PV on the same area. Put another way, the same amount of electrical energy would be produced on a 700 hectare site as from the 350 hectare mine.

Other considerations

a) Vehicle movements

10, The vehicle movements at the coal mine will be about 170 HGV lorries a day over the five to seven years of active mining. The total number of deliveries of PV panels will be 2,000 lorries, or less than 2 weeks of coal movements. For the remainder of the 35 year life, a PV farm would need virtually no large lorries. At the coal mine, there will be one vehicle movement every four minutes for seven years during a 12 hour working day.

Costs

11, A 170 MW solar farm would cost about £140m today. The total projected local expenditure by the mine owner is said to be £70m. This figure includes permanent employees and the chain of local suppliers. But the costs involved in converting the coal to electricity are not covered. These missing numbers include the money needed to run the power station at which the coal is burnt. This would probably add at least another £30m (or circa £10 a tonne of coal produced).

12, Electricity suppliers have to pay a tax on their output. The carbon support price imposes a £18 levy per tonne of CO2 emitted when power is produced. This tax is meant to penalise the fossil fuel producers to compensate for the damage CO2 is doing to the global environment, although it is widely regarded as being substantially lower than the true cost of coal. Burning a tonne of standard coal produces about 2.3 tonnes of CO2. The damage caused by the mine in terms of global warming is therefore judged by the UK government to be over £120m (3 million tonnes of coal times 2.3 CO2 multiplier times £18).

13, The total cost to generate the 10 TWh of electricity from the coal will therefore be around £220m. A solar farm on the same site would cost £140m to generate half as much power or £280m to equal the coal power output.

14, Solar power is therefore currently just over a quarter more expensive than the coal from Druridge mine. Druridge has good quality coal close to the surface and near to railway connections. It is therefore perhaps the cheapest fossil fuel available in the UK. If instead of using land in northern England, the country invested in an equivalently sized solar farm on the south coast where yields might be 25% higher in the very best locations, solar power in the UK would now offer electricity at the same cost as cheap coal. 

The impact of the referendum decision on energy

The large devaluation of the last few days will have significant effects on UK energy, from electricity to motor fuels. Other changes are also likely to slow decarbonisation of the economy.

Nuclear

Hinkley Point C is even less likely to be built.  As at the point of writing, the pound is down about 16% against both the dollar and the Euro compared to twelve months ago. That means that all the components for the power station purchased outside the UK will be 16% more expensive.

EdF has indicated in the past that ‘up to 57%’ of the cost of Hinkley will be spent on UK goods and services. Let’s be a little sceptical and say that only half the cost of the new nuclear plant will be incurred in the UK. The last estimate we saw was that constructing Hinkley was going to absorb £18bn. If half of that cost is derived from imported components and other charges the exchange rate decline over the last year has added over £1.4bn to the bill. Much of that has been in the last few days.

The electricity that Hinkley generates will be no more valuable to EdF than before. The strike price of £92.50 a megawatt hour does not rise in the event of a UK devaluation. So the prospective financial return to EdF and the Chinese shareholders has fallen sharply. Perhaps as importantly, the position may get worse if the decline in the value of the pound continues but nobody can know this in advance, nor can it be fully hedged against.

The same argument applies to all other prospective nuclear construction in the UK. Put at its simplest, the components for nuclear power stations will largely be shipped into the UK and then assembled here. The rapid devaluation that is going on has made all future projects more expensive. Nuclear fuel (costing about $5 for a megawatt hour’s worth of uranium) will also become more costly.

There is a counter-argument. If Brexit pushes interest rates in the UK even lower - and the signs are that this is happening – EdF may be prepared to take a lower return on its capital than would previously have been the case. Rumours have suggested that EdF’s financial projections were based on a 9% cost of capital. We could argue that this number is too high; UK utilities generally run on a 6% estimate. However there is no sign yet that either EdF, the French government, or Hinkley’s Chinese backers are prepared to accept a lower return. I

Lastly, as at Monday midday, EdF’s shares have fallen 20% since the Thursday referendum. EdF’s total stock market value is now less than the cost of Hinkley, a position seen earlier in the year but from which the company had been climbing out of. Investors see profoundly bad effects on EdF from Brexit.

Gas

Gas fired power stations are relatively cheap to build and operate. (Perhaps £600-£700m for a gigawatt of capacity, or about a tenth the price of new nuclear). Fuel is the most important part of the costs they face. The price of gas is set in an increasingly international market. Although contracts in the gas market are set in sterling, the underlying global price set in US dollars feeds into the UK’s auctions. Devaluation will therefore add sharply to the cost of buying gas for power generation. This will force up the long-run price of electricity because developers of new power stations will need guarantees of higher prices before they build their plants. My rough calculation is that the wholesale price of electricity will need to be about 10% higher as a result of the events of the last few days. The price that homes pay for gas will be equally adversely affected.

If these increases do directly feed through to household bills, the immediate impact will be about £100 per home. People will also see inflation in the costs of goods and services they buy because their suppliers will also face higher costs of energy.

Those of us over fifty will remember this phenomenon clearly: large devaluations push up prices. The referendum decision will significantly affect the least prosperous because more of their income is spent on heat and electricity than wealthier groups. Fuel poverty will probably rise, possibly sharply. This will tend to affect worst those most likely to have voted to leave.

Oil

The oil price has been gradually recovering after the sub $30 lows seen earlier in the year. Today, the cost of a barrel is bobbing around $50. But a dollar is now 15% more costly to those buying in British pounds than it was a year ago. The price of petrol will therefore also rise although the percentage impact is softened by the fact that more than half the cost of a litre of fuel is composed of duty, VAT and UK denominated costs. Nevertheless, we'll see a visible jump in fuel prices in the next few weeks.

The cost position of the UK North Sea will be improved, making it slightly easier for offshore oil and gas rigs to stay in business.

Will the rise in the price of oil help the sales of electric cars? It depends. In my view, the rise in renewables will in the longer run force down electricity prices all around the world. The economics of buying and operating an electric car will tend to get better as time goes as by, Brexit or not. Short term relative prices changes in petrol and electricity costs have little impact.

Renewables

The impact here is slightly more nuanced. In the case of solar, withdrawal from the EU would mean that the UK could escape from the ‘Minimum Import Price’ facing Chinese companies. The price of solar modules would fall in Euro terms. But because the Euro is now more valuable than it was a week ago, the impact in pounds would be much less. Perhaps the price of Chinese panels will be higher than it would have been without the devaluation and prospective exit from the EU. Other system components, such as inverters, will also rise in price. Because over 80% of the cost of a large solar field is imported (my guess – better estimates welcome), PV will become much more costly, at least temporarily.

In the case of wind, more of the manufacturing value is added in the UK than in the case of solar. Perhaps they now regret it, but some of the large offshore turbine makers have factories and installation operations here. The UK should become an even more important centre for wind turbine construction as a result of devaluation. However this optimism is only justified if we believe that the UK will be able to export to major markets without substantial tariff impediment. As of today, this is no certainty.

A large fraction of the total costs of offshore wind farms are denominated in Euros. The fall in the value of the pound will make developing large wind areas, such as those on Dogger Bank, more expensive. This will reduce the pace of offshore wind development, perhaps substantially.

Energy R&D

Places like Culham and Harwell, the UK’s energy research centres in Oxfordshire, will diminish sharply in size and importance. The nuclear fusion lab at Culham gets £55m a year from the EU, a large fraction of its budget.

As importantly, research into the conversion of surplus electricity into gas and liquid fuels that can be stored for months will be slowed. As PV and batteries becomes ever cheaper globally, this is the last remaining challenge for the clear energy revolution and the UK had been in a commanding position because of its world-leading role in biochemistry. The Brexit vote is a huge setback for research in this area.

More generally, of course, any new Conservative government will be profoundly sceptical about climate change. The part of the human brain that determines whether one is a denialist or a climate alarmist is the same as that which provided the opinion on the EU. So renewable and low-carbon energies of all types will be under threat as a result of the likely rightward shift of the government.

For example, the Vote Leave campaign literature railed about wickedness of the Large Combustion Plant Directive, the EU’s coordinated plan for reducing air pollution by forcing older coal-fired power stations to close. (The LCPD was one of the undoubted successes of the EU energy and environment policy). The implication is that the Leave people will be happy to see coal back as a major contributor to power supplies even though they also threw about the accusation that the EU had ‘tied our hands on decarbonisation’. That last complaint is about as far from the truth as is possible to get.

The primary conclusion I take from the events since the referendum is that energy is going to become more expensive in relation to household incomes, at least for a few years, and that the low-carbon transition in the UK will be slowed, partly by the impact of devaluation and loss of funding but also because of the rise in uncertainty over the future direction of energy policy.

 

Chris Goodall's new book on the global rise of solar PV and energy storage, THE SWITCH, will be published next week.

 

 

 

 

 

 

Global declines in interest rates will increase the growth rates of solar and wind

A PV array has a once-and-for-all capital cost and then delivers power for up to 35 years with minimal other costs. This means that the cost of finance for solar has a startlingly important effect on the cost of electricity generated. As interest rates around the world fall to zero and below, the cost-competitiveness of solar power is improved.

The reason is that the developer of the PV farm doesn’t need to pay much interest. The only substantial cost it faces is paying back the capital over the 35 year life.

If a new large solar farm faces a cost of finance of 7%, a figure typical of a few years ago, today’s underlying cost of electricity is about 7.4 pence per kilowatt hour in a good location in the UK. (Assumptions in the footnote).[1]  But at 4%, the figure is 5.5 pence and at 2% the cost is 4.4 pence per kilowatt hour.

The implications are fairly obvious. Any developer able to finance an installation at 2% annual interest rate can afford to accept a price for the electricity produced of 4.4 pence per kWh, or £44 a megawatt hour. This figure is below the cost of any competing source of power. With this price, solar is already at ‘grid parity’, even in the UK. (Today’s market price for electricity is lower than this level but no new capacity will be built at these prices. The UK government says a new gas-fired power station requires an average price of £65 a megawatt hour to make it possible to finance construction).

Solar will continue to get cheaper and cheaper over the next decades. Today’s report from IRENA suggests that PV will fall in price by a further 59% by 2025. Low interest rates, longer and longer asset lives and cheaper prices for the panels and other equipment needed for solar farms all point in one direction. Solar power is going to become the dominant energy source of the future. But, even if you accept this, 2% finance probably seems inconceivable. However I suspect we are getting closer by the day.

What are the finance costs incurred by developers today in the UK? In my book on PV, to be published in the next few weeks , I interview some of those who were financing solar assets in the UK late last year. Gage Williams, a director of West Country Renewables, which builds medium sized PV installations and wind developments, told me that he was able to borrow from a commercial bank at about 3.5%. This is only part of the financing cost because West Country Renewables also needs to pay dividends on the money invested by its shareholders and this percentage return will typically be somewhat higher. But the overall cost of the mixture of bank borrowing and shareholder funds was probably something about 5% or slightly more.

Since the interviews, interest rates in the wider economy have dipped sharply again. Governments can now borrow at less than 0% interest in many countries, including Germany and much of Europe. In Britain, most government bonds, which set the baseline rate below which no entity can hope to borrow, still have a small positive return. However the figure for a 30 year government bond is now below 2%.

But if the bond also promises to reimburse the owner for the effects of inflation, the interest rate can now be well below 0%. [2] In fact, UK bonds of 35 year duration are now delivering negative 1% returns. One of the most important reasons for this is that many pension plans promise the owner that his or her payments will go up with inflation each year and there is a shortage of assets that providers can buy that can reliably guarantee to honour the link. So the price is bid up and the effective return reduced.

Like index-linked gilts, feed-in tariff payments in the UK are also linked to inflation. Because they are highly secure, they also provide opportunities that are suitable for pension funds, similar to inflation protected government bonds. A developer today with PV prospects that were accredited for tariffs before the sharp recent cut in the rates payable can therefore obtain remarkably cheap finance. Community share offers on the market today make this clear. For example, Low Carbon Hub (LCH) in Oxford is offering investors (but, sensibly, not promising) 3% returns above inflation on PV installations on schools and factories. If inflation jerks upward, investors therefore get higher returns.

Separately, LCH is building PV installations on local factory roofs for companies wanting renewable power. Without giving me specific numbers it says it can offer these businesses PV electricity at a price that is slightly higher than open-market electricity today. It is therefore almost at ‘grid parity’ already.  However if the business agrees to inflation link its power purchase price, then the overall cost over the life of the installation will be lower than suggested by government estimates for future open market electricity prices.

North Star Solar, a business set up by bankers rather than the usual eco-types, goes even further. It is taking money from pension funds to back an extremely imaginative scheme to put PV, batteries and LED lights into homes. The first customer is Stanley town council in County Durham. North Star tells me it is able to obtain its financing for these installations at ‘less than 2%’, although it is cagey about the actual numbers. These funds are used to provide free installation to tenants, with the business making its return via a monthly charge intended to be less than the savings made by the householders.

In other countries, particularly the US, responsible corporations are also helping to reduce the costs of financing renewables by committing to purchase the energy produced. Marks & Spencer has just announced what I think may be the first scheme in the UK that raises external private shareholder money for PV on store roofs, with the retailer buying the electricity produced. The new entity also proposes to pay an inflation-linked return to small investors, who may well also benefit from the government’s new tax policy of allowing people to earn £1,000 of interest before paying any tax.

Once feed in tariffs have completely disappeared in the UK, which is probably only a matter of months, the returns for PV investors will cease to have the automatic inflation link. Shareholders will demand somewhat higher returns as a result. But the underlying rate is unlikely to go up much, as recent history in the US makes clear. In recent weeks, Fannie Mae, the provider of much of the US wholesale mortgage financing, has said it will allow borrowers to get extra finance to cover the cost of installing new PV on home roofs. The cost of this to borrowers will be about 3.5%. SolarCity, the largest US domestic solar installer, has announced a financing deal that offers their customers a chance to buy an array at less than 3% financing.

Solar and wind are costly in terms of initial capital and very cheap to operate so financing charges often determine whether a project is economic or not. The reverse is true for gas power stations. Tumbling interest rates around the world are unambiguously good news for the future of renewables.

 

 

 

 

 

 

 

 

 

[1] £800 a kW for a large solar farm, 35 year life and £10 annual operations cost per kW. 11% capacity factor. Figures calculated on the NREL web site at http://www.nrel.gov/analysis/tech_lcoe.html

[2] When I refer to ‘inflation’ here, I mean Retail Price Inflation or RPI. The RPI overstates actual inflation by 1%, which is why governments should have replaced it with CPI many decades ago. 

Shaving the peak in electricity demand: the urgent need for an LED installation programme.

LED light bulbs are cheap and energy efficient. A crash programme to replace all the lights in the UK with LEDs would save consumers and businesses money and reduce the risk of blackouts in years to come. It would reduce fuel poverty and cut the need for expensive and polluting diesel generators.

At the peak at about 5.30 on a December evening lighting uses about 15 gigawatts out of total UK demand of approximately 52 gigawatts. This is an almost unbelievable 29% of our need for electricity, met at the precise moment that future blackouts are most likely.

Although LEDs are growing in importance, the number installed is still a small fraction of the total stock of lightbulbs. If all lights across the country were switched to LEDs my calculations suggest that the need for electricity to provide improved lighting would fall by about 8 gigawatts, a saving of about 15% of all power consumption.[1] There are very few circumstances in which LEDs would not represent a cost-effective improvement on current lighting systems. They switch on instantly, have an almost indefinite life, contain no mercury and offer better quality light than almost all alternatives.

As part of my work for Greenpeace, I located 100 case histories of switches from other types of lights to LEDs in industry, commerce and public sector. On average, replacing less efficient bulbs saved two thirds of the electricity bill. These studies were usually written up by companies with an interest in selling more LED bulbs, but show a very consistent pattern across factories, shops, schools, sports clubs and offices. In most places, lighting quality was improved substantially. In some locations electricity costs were reduced because LEDs produce less waste heat and therefore cut the need for air conditioning in places such as hotels and large office buildings.

Even a much more restricted national campaign that just focused on domestic houses would have a dramatic impact. If we switched the lights in the parts of the house that are in use in early evening - essentially the kitchen and living areas - we would reduce home demand by more than 50%. Importantly, these rooms are the places where we now often use halogen bulbs, the most inefficient lights currently on the market. We can cut the typical need for electricity to run lights from today’s average of 180 watts to 80 watts by replacing about 21 bulbs in the average home.

The impact of this is to reduce electricity demand by 2.7 gigawatts. This represents 5% of UK peak demand and would be more than enough to protect the country against power cuts in the years to come. The payback period of such a scheme is about 2 years at current LED prices. For an expenditure of around £60, the householder would typically save £30 a year.

What does the £60 buy? The home gets 6 LEDs to replace conventional bulbs (now almost all compact fluorescent lamps, of course) and 15 to switch out halogens. LEDs are now as cheap as £2 each when bought in packs of 5 or more. From my personal experience of buying bulbs at this price, the reliability and light quality is very good.

The total cost of this switch, adding up all homes in the UK, is about £1.6bn. Contrast this with current government plans to pay electricity generators to keep plants open that would otherwise close. The budget for this is about £1bn just for one year and the UK gets very little for this expenditure. By contrast, the replacement of inefficient halogen lights and other bulbs in kitchens and living areas would save Britain money, cut carbon emissions and improved energy security.


Any rational national energy policy should include a push for a very rapid switch to LEDs. The mechanisms that could be used might include sending a voucher to every home, street-by-street visits handing out LED bulbs and grants to volunteer organisations to help the less-advantaged swap out all their old lights. Perhaps more in line with the current government’s thinking, we could temporarily abandon today’s ECO scheme for improving home insulation. The utility companies that are (very reluctantly) obliged to manage and implement ECO would be mandated instead to replace light bulbs in most UK homes within two years. This would be cheaper, easier and save more energy than ECO.

Capacity margins will dwindle to almost nothing over the next two years. A crash programme to switch to LEDs is necessary, and also beneficial to householders and businesses.

[1] This work was carried out for Greenpeace UK. 

 

 

 

 

 

 

 

 

 

 

[1] This work was carried out for Greenpeace UK.

We need demand response not capacity auctions

We were told early last week that the government will pay existing power stations a fee for staying open over the winter of 2017/18. A similar scheme is already in place for later years. Old power stations, which would probably otherwise close, will be paid about a billion pounds as a bribe to remain ready to generate power. This scheme is called the ‘capacity auction’.

The government is convinced this is the right way to ensure that we never - or virtually never - lose electricity supply. I want to suggest three schemes that would have represented much better value for money. In fact, in the longer run they will all save householders substantial amounts of cash, rather than costing us money.

These are

·      Pay people to reduce their electricity demand at home, probably by providing a game with prizes.

·      Hand out LED light bulbs to reduce household electricity use by replacing the increasing numbers of inefficient halogen lamps in kitchens and living areas.

·      (I do realise that this next suggestion is deeply counter-cultural but I make it nevertheless). Tell people when an electricity blackout is likely; ask them voluntarily to reduce their power use at that time. I suspect the results would be far better than anybody thinks is possible.

In this post, I’m going to look at the first of these options. (An article on the unassailable reasons for handing out free LED bulbs will follow. This second post will use analysis I have been done for Greenpeace on the impact of switching to LEDs on peak power demand).

First of all, we need a few numbers to start the discussion on 'games' to reduce power demand.

·      Over the next couple of years, the government thinks that up to 8.5 gigawatts of fossil fuel electricity generating capacity may decide to close.

·      It believes that these closures can be expected to result in electricity demand exceeding supply for 38 hours a year. (Probably this means 1-2 hours on around 25 weekdays in December and January, when demand is highest).

·      During each of these hours, the forecast is that an average of about 2 gigawatts of demand is not met. This is about 4% of typical peak demand. (I suspect that this will usually mean that one area of the country representing about 4% of demand will be disconnected for the period of 1-2 hours). On average, each household will lose power for about 2.25 hours if the forecasts are correct. (1.5 hours of loss 1.5 times a year).

·      Now here’s a number that we should look twice at: the government says that the ‘cost’ to society of this power outage is £17,000 for each megawatt hour of electricity not supplied, or £17 a kilowatt hour. The average household is using about 1.1 kilowatts at the December peak, so the cost of not having electricity is put at about £19 an hour, or about £28 for the typical outage of 1.5 hours for the average home. That’s about 150 times what the lost electricity would have cost, by the way. I don’t believe the real figure is more than a tiny fraction of this but the important thing is that this number represents the assumed cost of TOTAL loss of power. We can agree that a power cut is potentially costly and inconvenient to householders. But, by contrast, having to cut usage in half, perhaps by turning off the washing machine, has a negligible impact on us.

·      By December 2017, I guess there will be 9 million smart meters in UK homes. That means 1 in 3 households will be able to change their rate of consumption of electricity and have this measured independently by a third party.

Some of the implications of these numbers include

·      If we could reduce demand by 2 GW below what it would have been at peak, most outages would not occur in the winter of 2017/18 and, second, the numbers affected by any power cuts would be much reduced.

·      There are about 27 million households in the UK. If we could in some way reduce the average electricity demand in these homes by 100 watts at 5 o’clock on a December evening, we would save 2.7 gigawatts. That’s less than a 10% reduction in typical household power consumption.

·      Or if we cut power use in smart meter homes by 300 watts, we could make a similar saving. On average, that would mean a cut of less than 30% below the average usage level.

·      Either way, we substantially reduce the threat of power outages.

Paying people to reduce their electricity demand.

Around the world utilities are introducing ‘time of use’ pricing for home users. Take power from the grid at times of peak demand and you pay a higher price. This is the market working in its conventional way, choking off usage at times when supplies are tight. It works because it punishes.

It may not be the best way of getting people to use less. Rewarding socially beneficial behaviour could be at least as effective. If a power supplier paid its customers for keeping their usage low, demand will also fall.

And there is lots of money available to offer as a reward. The government’s capacity market is expected to cost £38 a household across the 27 million homes in the UK. That means we have over £100 available for each of the 9 million homes that have smart meters.

One incentive scheme for smart meter homes might use the following format. On the 25 days a year that demand is expected to exceed supply in the early evening, a message is sent to the phones of people in the scheme. Pay people £4 for keeping their household electricity demand below an average of 250 watts over the critical 1-2 hour period. (That’s below a quarter of typical household use). Someone who successfully plays the game 25 times would make £100. If the government wants to encourage smart meter takeup, I can’t think of a better incentive.

Then there’s the social aspect to this. If you are wealthy, £100 may not be worth the inconvenience of switching off the dishwasher, turning most of the lights out and avoiding using the cooker for an hour or so. But for those who are short of cash, this amount of money could make a difference. It’s potentially a highly progressive, rather than regressive, policy.

This all sounds far-fetched, impossible even in today’s connected world. But the young Silicon Valley company Bidgely (‘electricity’ in Hindi) shows how it might work. Bidgely puts an app on your phone that informs you in real-time what your energy usage is. When the power emergency arrives, it tells you when you need to reduce your electricity draw. As importantly, it then gives you instant updates on how your home is performing against the target of 250 watts.

One of Bidgely’s strengths is that it recognises the power use signature of each major appliance in the house. (The heaters in electric dryers cycle on and off in short bursts, for example). So the app can send an alert that warns the householder which appliances are using a lot of power and threatening the attainment of the reward. Bidgely doesn't need to put sensors on each appliance. At the end of the emergency period, a signal is sent to the smartphone saying what the average usage has been and whether or not the prize has been won.

Of course it’s also increasingly easy to imagine times when the National Grid has too much power. We have already seen several instances this year. Instead of rewarding power use reduction, Bidgely could give you cash for turning on appliances instead.

Bidgely’s investors and customers include the German giants E.ON and RWE, still two of the biggest private utilities in the world. Both companies say their business will move from operating giant fossil fuel power stations to providing a variety services to electricity customers. It’s easy to see how Bidgely might provide a key part of this.

That’s the first option of the three listed above. Instead of rewarding fossil fuel generators for promising to stay open, pay individual householders a decent reward for cutting their demand when told to. It would be cheaper, and instead of going to elderly power stations the money would largely arrive in the bank accounts of the less well-off. (Although the other beneficiary group might be the young London professionals who are not home, and therefore not using much electricity, when the power shortage looms).

There’s one thing that continually strikes me about UK energy policy. It’s driven by a view that supply must be continually matched to an inflexible demand. That 20th century ideology needs radical updating. Today’s world offers almost unlimited opportunities to mould demand to the available supply. If we don’t have the generating capacity to meet demand for a few hours each winter, the answer surely does not lie in spending a billion pounds on diesel generators and superannuated coal-fired power stations. Instead we could pay some money, probably largely to less well-off households, to reduce demand until the emergency passes a couple of hours later.

The end of the coal era is here. At least in the UK

(Since this note was written the UK has seen 4 hours of zero coal generation. Between midnight and 4am on Tuesday 10th May, no coal-fired power station was working on the UK grid. As far as I can see, this has never happened before. A highly symbolic event).

At about 15.30 on Sunday afternoon (8th May 2016), the only coal power station working on the UK grid throttled back its operations. The 400 megawatts or so being generated fell to around 280 megawatts for about half an hour. The reason was probably that the system electricity price had declined to about minus £30 a megawatt hour. It made sense not to generate at all but coal-fired power stations take some time to reduce or increase their output.

At coal’s minimum generation, it was producing about 1.2% of all grid-generated UK electricity. If we included in the wind and solar not on the high voltage National Grid, the figure would have probably been below 1%. 1.2% is the lowest figure ever recorded in the UK since the dawn of the electricity age.

The chart below shows how coal has declined dramatically in importance over the past year and a half. From nearly 50% of generation in early 2015, the average figure this spring has been little more than a tenth of this. More wind, more PV and low gas prices are pushing coal out of the generating mix. Whatever else is going wrong, this is very good news indeed.

 

Public opinion warms to renewables

DECC carries out regular surveys of public opinion on energy issues. Round 17 has just been completed. The first was in early 2012.

The most recent poll shows increased support for the main renewables.

·          Onshore wind reached a new high in support. The percentage of net approval (those in favour less those against) rose to 60%. The percentage thinking onshore wind is a good thing rose 3% from the previous survey while those opposing fell by 3%. The number against onshore wind was 9%, a new low. Only 3% of respondents ‘strongly oppose’ turbines on land.

·      Offshore wind also saw a new peak in approval. The net approval rate was 71% with only 5% opposed. The number ‘strongly opposed’ fell to a new low of 1%.

·      Solar PV has a net approval rating of 80% is close to the previous peak. Only 1% ‘strongly oppose’.

Support for nuclear is stable.

·      Net approval numbers have moved around in recent surveys but at 15% the current poll figures are unchanged from the last round.

Smart meters growing

·      20% of respondents have a smart meter. The numbers using the energy use monitor are rising sharply.

Climate change worries people more.

·      Those saying they are ‘concerned’ total 70%, a new high. Those unconcerned fell to 29%, a new low.

·      Those seeing climate change as being caused by man’s activities increased in number. Those who see it as a result of natural processes fell to the lowest number ever.

·      Climate change is one of the top three of a list of political issues for 22% of people. Those putting it top account for 6% of the respondents.

I saw no other obvious trends in the survey results but I may have missed something.

 

 

 

 

Port Talbot closure: the CO2 and energy arguments

There are two main ways of making steel: an electric arc furnace or a blast furnace. The electric arc furnace (EAF) uses scrap steel and puts an electric current through it to heat it to the point at which it melts. The blast furnace (or basic oxygen furnace, BOF) fires coal that melts the iron out of iron ore. In both processes, the molten metal is tapped off and processed into slab.

Both routes, if I understand the position correctly, can produce high quality steel.

Mr Gupta, the potential purchaser of Port Talbot, wants to convert it from BOF to EAF. Instead of using about a tonne of coal to make a tonne of steel in a BOF and about 0.15 MWh of electricity, Gupta wants to use about 0.45 megawatt hour of electricity (and no coal) in an EAF. (These figures are from http://www.steelonthenet.com/cost-eaf.html)

What is the CO2 impact? A tonne of coal burnt in a blast furnace produces mostly carbon monoxide. That gas is usually then combusted in air to make CO2. (Competitor Arcelor Mittal is working with US/NZ company LanzaTech to use the carbon monoxide as a feedstock for bugs that convert it to useful liquid fuels but worldwide conversion is some decades away).

A tonne of hard coal produces about 3.5 tonnes of CO2. At today’s average CO2 intensity, 0.15 MWh of electricity used in a BOF adds another 0.06 tonnes to this. So a BOF adds just over 3.5 tonnes of CO2 to the atmosphere for each tonne of new steel produced.

An EAF adds less than 0.2 tonnes of CO2 to the atmosphere for each tonne of steel produced.

Switching from BOF to EAF will save over 3 tonnes of CO2 for each tonne of steel. The UK has produced an average of about 7 million tonnes of BOF steel over the last few years. A complete change to EAF could reduce UK emissions by up to 20 million tonnes, or just under 5% of the total.

Does the UK have enough scrap to provide for a EAF at Port Talbot? Yes it does; Mr Gupta says that 7m tonnes is exported to EAFs elsewhere each year. His logic is that it makes more sense to process the scrap in the UK than ship to a EAF elsewhere in the world and then import the resulting steel. Whether he is right or not depends on the costs of making EAF steel here, including electricity charges, compared to elsewhere.

Electricity prices

Why, if energy prices are said to be a major barrier to steelmaking in the UK, would Mr Gupta want to triple the amount of electricity he uses per tonne of steel from today’s BOF levels?

Firstly, electricity isn’t a hugely important part of the cost of EAF steel. 0.4 MWh of electricity might cost £35 at today’s prices, or even slightly less. The value of a tonne of steel is, if I have researched correctly, about £300. Although power costs are not irrelevant, the cost of the scrap metal is a far more important element than electricity.

More importantly, perhaps, Mr Gupta’s family companies are developing a variety of new renewable sources that might supply Port Talbot. These include, as has been widely mentioned, the tidal lagoon at Swansea, just down the cost. Other new sources of electricity include from biomass from the Uskmouth coal plant near Newport on the Severn Estuary and the various other technologies being planned at the green energy hub next to Uskmouth. These include pyrolysis of waste, fuel cells and solar.

So Port Talbot seems to be part of a big plan to create electricity using renewable technologies and then exploit it in an EAF. This sounds rational at first. But none of the energy technologies being developed by Gupta businesses are yet competitive with today’s wholesale price of power. We know, for example, that the tidal lagoon company is asking for a power price at least as high as Hinkley Point.

Unless the government goes along with Mr Gupta and agrees to subsidise his chosen renewables, the price of power at a Port Talbot EAF will be higher than today. I can see no sign that the Energy Secretary will have any interest in putting in place agreements to give Port Talbot cheap power from renewable sources.

Nevertheless, this is a debate the UK should be having. Does it make sense to try to build leadership in technologies such as lagoons and pyrolysis at the same time as keeping open a lower CO2 EAF in a part of the country that needs the jobs that steel provides? I think the question is far more finely balanced than the market fundamentalists believe.

 

EdF (in the US) shows that wind makes better sense than nuclear

EdF’s travails over Hinkley persist. The FT reported this week that engineers within the company have written a memo asking management to wait to proceed with construction until the other EPRs in Finland and Normandy have been successfully completed. A director has said he will vote against the UK nuclear project. The £18bn project is stalled until internal debates within EdF are resolved. 

Within the same company, they do things very differently on the other side of the Atlantic; there EDF focuses wholeheartedly on wind and has no nuclear under development. It has just proudly announced that it has become the largest developer in North America with a portfolio in 2015 of over 1 gigawatt of newly constructed wind farms.

If it continues at the current rate, it will be generating more electricity from wind by 2025 than would be provided by Hinkley Point C. The numbers are as follows. Hinkley will generate about 25 terawatt hours a year. EdF’s 2015 annual portfolio of new wind projects will provide about 3 terawatt hours a year at average US utilisation factors. If it continues to develop new wind projects at the rate of 1 gigawatt a year, it will be generating well over 30 terawatt hours a year from wind by the end of 2025. 2025 is when EdF says Hinkley will be finished.

What about the capital cost of wind versus nuclear? The latest US estimates suggest a figure of about $1,700 per kilowatt of capacity. That means EdF’s projects completed in 2015 cost about $1.8bn. Over ten years, that rate of installation will mean a total cost of around $18bn or about £13bn. Wind is therefore at least 30% cheaper to construct.

And it is much cheaper to operate. The most important project it completed in 2015, the 250 MW farm at Roosevelt in New Mexico, has sold its electricity for the next 20 years to a utility for $23.39 a megawatt hour, less than 20% of the price agreed for Hinkley of £92.50/MWh. (The Roosevelt price is somewhat subsidised by Federal tax credits but even without this benefit the cost of wind would be less than 40% of the price of UK nuclear). Wind saves consumers money when compared to the nuclear alternative.

EdF finances many of its US wind projects on the back of power purchase agreements with major companies such as Microsoft, Procter and Gamble and Google. They commit to buy the electricity produced at a fixed price, not the inflation adjusted figure that the UK will pay for Hinkley. The EdF press release said ‘Corporate America is increasingly turning to renewable energy to power its business operations, based both on consumer preferences and because renewable energy simply makes economic sense’. (My italics).

We never hear this line from EdF in the UK.

EdF cannot guarantee the wind will blow or the sun shine. Unlike in Britain, its US business is also investing heavily in energy storage. The US company has announced 100 MW of battery systems in the US saying ‘Energy storage is an attractive, cost-effective addition to intermittent energy generation projects’. However there’s no mention of batteries on EdF’s UK web site.

For sensible reasons large international companies often pursue varied market strategies in different countries. EdF in the US has decided to back wind while the UK has gone for nuclear. But even a quick look shows that the energy and financial returns to the US strategy seem far clearer and better for the company, and its customers, than the tactics of the UK business.

 

 

 

 

 

First sighting of California Duck this year

Today was sunny. Most predictions were for at least 5 gigawatts of solar PV arriving into the UK electricity system. This number hasn’t been reached for almost six months. (My website at Solar Forecast was a little more conservative and I think the algorithm was too pessimistic).

The electricity market didn’t predict the abundance of sun. As a result, it was hugely oversupplied in the middle of the day. If you’d been buying, you could have bought electricity for less than £10 a megawatt hour (1p a kilowatt hour) in the early afternoon. In fact, for the entire day so far the system price has been less than £30, a strikingly unusual state of affairs.

Phil Harper wrote to me a few minutes ago pointing out that today was the first obvious sighting of the California Duck in the UK this year. Electricity demand in the middle of the day was seriously dented by the superabundance of PV-generated electricity, an increasingly important feature of the Californian power market from March to September. Last Monday, the UK need for electricity was flat from noon to late afternoon at around 40 gigawatts. Today, it dipped sharply as the sun burnt off the haze. At 14.30, demand for other sources of power was around 35 gigawatts over 5 gigawatts less than a week ago. (I do not know why demand remains somewhat lower even now at around 10pm).

The chart below shows the dent in demand. The pattern will get even clearer over the next six months. Some sources suggest that UK PV installations will top 10 gigawatts by mid year, meaning that early afternoon power needs will dip by at least 8 gigawatts below usual levels on very sunny days.

As usual, DECC is either disguising these numbers in its monthly releases or is still unable to cope with the rate of installation. Despite being warned by National Statistics for fiddling with its estimates, it continues to make huge ad hoc changes in its statistics from month to month without acknowledging its problems in keeping up with solar volumes.

Solar is making a significant difference to the operation of the UK electricity market. 

 

The demise of Hinkley C is near-inevitable. This will save the UK money and help us build a truly flexible energy system.

The amount of capital earmarked for Hinkley C (£18bn) would produce more electricity over the next 25 years if it were invested in onshore wind or PV. Based on the projected economics for the first three lagoons, tidal power would be about 65% as productive but the projects would then last twice as long as nuclear. 

If it operates at 85% of capacity, Hinkley C will produce about 24 terawatt hours of electricity a year, about 7% of the UK’s consumption. At today’s prices, PV on which the same amount was spent would generate 25 terawatt hours annually and onshore wind about 31. The Swansea lagoon and its proposed follow-on sites would produce about 15 terawatt hours.

The economic arguments for using renewables rather than nuclear are therefore increasingly strong.

There is very little uncertainty about the actual costs of wind and PV, or the direction of travel. Both are reducing in cost, with solar declining at about 6-9% per year around the world and wind somewhat more slowly. We do not know what will happen if Swansea and other lagoons are built but it is likely that we will also see substantial cost reductions there. Hinkley C is subject to much more uncertainty. The new nuclear sites in Normandy and Finland are proving hugely problematic and even the constructibility of the EPR is in doubt.

The annual running cost of Hinkley C, including its fuel, will be about £360m. This compares with estimates of £130m for £18bn of PV and £310m for onshore wind of the same cost. The lagoons will cost about £75m. All three alternatives to Hinkley will therefore be cheaper to operate, perhaps by over £200m a year.

£18bn worth of PV would take up about 0.2% of the UK’s land area. This is not an obstacle.

Nuclear power is proving difficult to fund and is subject to many concerns, both technical and financial. The only remaining argument for supporting Hinkley C is that therefore it will produce a constant flow of electricity 24 hours a day, if it is successfully completed.

In some circumstances this is an advantage but as wind and solar increase in importance this benefit will die away. There will be times when the UK would like Hinkley to produce less than its maximum output. Even this coming summer it is conceivable that on a sunny, windy weekend day that the UK will not need its full existing output from nuclear power stations and would prefer that they operated at less than 100% output. This is currently impossible. As the maximum output from PV and wind increases over the coming years, the inflexibility of nuclear will become an even more significant problem for the UK grid, particularly if electricity demand continues to fall. 

A portfolio of tidal lagoons with storage capacity – something that can be engineered in - combined with PV and wind would represent a cheaper way of achieving a fully decarbonised electricity supply. Extensive use of ‘demand response’ and time-of-use tariffs could help shape demand to the expected availability of power.

In addition, battery storage is becoming cheaper by the month. Grid operators around the world are installing banks of containerised batteries to help maintain stability. The latest example in Korea has just seen the installation of a 50 megawatt system to replace older fossil fuel plants that used to provide power for hours of peak demand. This operator expects to save three times its cost over working lives of the batteries. In the UK, batteries can provide short-term storage overnight and could deal with unexpected swings in the availability of power.

An effective 21st century energy supply system will almost inevitably be based around renewables and batteries. The pace of cost reduction of PV makes this almost a foregone conclusion. It is already cheaper than nuclear per unit of capital invested. Automation and control of electricity consumption is making it easier every month to deal with the variability of wind and solar supply.

The only remaining problem is long-term storage. It must be provided by the conversion of surplus electricity in the summer, or in periods of gales, into methane for injection into the gas grid. The technology for turning power into hydrogen through electrolysis is simple and well understood. Several types of microbe can then take the hydrogen and a stream of impure CO2 and turn it into methane quickly and cheaply. The new Electrochaea pilot at a waste water pilot in Copenhagen will show how this can be done. The German company Microbenergy offers a similar route to so-called 'biological methanation'. Turning surplus electricity into stored gas and also into liquid fuels is possible, and probably cost-effective. But techniques are not yet commercially proven at large scale.

UK universities and research institutes have outstanding capabilities in biochemistry. My guess is that the country could built a worldwide lead in the use of living organisms such as archaea and acetogens to convert hydrogen and CO2 into useful renewable fuels. The UK should begin large scale research and development of ‘power to gas’ and ‘power to liquids’ projects to deal with the increasingly likelihood that the Hinkley site will remain empty for ever. The likelihood is that this will enable us to to build a energy system that is cheap, reliable and non-polluting, both here and in other parts of the world.

 

 

 

 

 

 

 

 

'Peak Stuff': households now spend more on services than physical goods

IKEA’s Steve Howard announced the arrival of ‘peak home furnishings’. He seemed to be saying that households were tending to consume fewer of the products his company sells.

In 2011,  I think I wrote the first article on the plateau in the UK’s consumption of material goods. It was entitled “Peak Stuff’ and is available on this website.  I looked at a variety of indicators of falling demand for physical objects, ranging from water to cement or fertiliser. I also suggested that other phenomena, such as the decline in the use of energy and the fall in the number of miles travelled, were also occurring in other developed economies.

Steve Howard’s much quoted comments prompted me to go back to look at the data on materials use. The most obvious fall in growth has occurred in the production of steel and concrete. The sharp slowing in Chinese GDP growth has flattened the output of both of these industries. The country is responsible for about 50% of world use of both commodities. So for the first time in living memory global steel and cement use is down. Aluminium, the next most important metal, is more robust, but only slightly.

Controversial in 2011, it’s now accepted that energy use is also falling across most of the OECD countries and Britain’s requirements continue to fall 1-2% a year, even as the economy continues to perform relatively well. Our aggregate use of materials is continuing to fall, as is also the case in the EU as a whole.

I looked quickly at one other aspect of ‘Peak Stuff’. Using government data, I’ve tried to assess whether British households are indeed spending less on buying physical objects. Is Steve Howard’s downbeat assessment of IKEA’s prospects in the UK justified by recent patterns of domestic purchases?

The answer is ‘yes’. British consumers devoted 26 % of their total household purchasing to physical goods in the early part of the last decade. This fell to about 21 % by 2014, the last year for which good data is available. Spending on all major categories of items fell as a percentage of income. That includes furnishings, clothing, cars and consumer electronics. The fall wasn’t regular but the direction of change is clear.

Source: ONS Family Spending

Source: ONS Family Spending

The uptick in 2014 was driven by increased spending on buying cars. However all sectors of expenditure on physical goods saw a decrease between 2002/3 and 2014.

Source: ONS Family Spending

Source: ONS Family Spending

You would be entitled to respond by saying that rising fuel costs, increasing rents and larger mortgages had drained householders of their purchasing power. Every type of discretionary expenditure might therefore be down over the last decade or so. That actually isn’t the case. Spending on services, such sports admissions or satellite subscriptions, rose from 21% of all household expenditure in 2002/3 to 22% in 2014. It is a small percentage rise but in the last few years we’ve seen the money going to services growing to be larger than the cash spent on all forms of goods.  Holidays have been particularly buoyant. (These figures exclude rent, utilities and mortgage interest payments). 

Source: ONS Family Spending

Source: ONS Family Spending

Services beating physical goods for the household pound is a new phenomenon, here or elsewhere. Steve Howard is right to be anxious. IKEA better start selling us pleasurable and enticing leisure services rather than trying to flog us more strangely named articles of bedroom furniture. We already have enough.

More generally, those who worry about a secular stagnation in the West probably need to look closely at whether Peak Stuff is going to depress economic growth over the next decades.

A quick note on method.

ONS publishes a fascinating yearly survey called Family Spending (and has done for many decades). It records the actual expenditure from thousands of UK households, ranging from funeral plans to bananas. Spending is split into hundreds of categories. I’ve decided whether each category is predominantly a physical good or a service. I excluded food from the ‘goods’ section but kept in clothing, furnishing, books and newspapers and many other lines. I did the same for services.  You could quibble with some of these allocations but I think the general conclusion is robust. There is a swing away from things made of metal, textiles and plastic towards spending on experiences. You can have a copy of my spreadsheet if you would find it useful, but it is a bit messy.

 

 

 

 

 

 

Will the switch to an energy system dominated by solar PV cost the world money?

A research paper by Chris Goodall

Will the switch to an energy system dominated by solar PV cost the world money? (Link to PDF)

Abstract

What follows is a thought experiment. I compare two scenarios to decide which will cost more. In one, fossil fuels continue to provide most of the world’s power and solar photovoltaics do not provide any more electricity than at present. In the second, solar PV grows very rapidly and provides the world with all its energy, not just electricity, by 2041. Each year, the amount of cash spent on fossil fuel energy each year is reduced by this switch. The experiment tries to answer the question ‘which scenario costs more?’.[1] Is decarbonisation costly, or financially beneficial?

For the first scenario, I estimate the total cost of wholesale oil, gas and coal from now until 2041. In the second, I add the total amount of capital invested in solar to the gradually lowering expenditure on fossil fuels, as a result of increased PV, to get an estimate of total expenditures, running and capital, on energy. With these figures I can provide an estimate of whether a fast switch to solar will cut the world’s expenditure on energy or not. As far as I know, no-one else has ever done this calculation.

The comparison shows that if the world makes a sustained push for growth of solar photovoltaics the total global cost of energy between now and 2041, including all the capital spent on PV, will be slightly less than if the globe continues to use fossil fuels. As time passes after 2041, the balance will swing even further in favour of PV because solar panels already installed will continue to provide near-free electricity for many years whereas fossil fuels will, in contrast, cost money.[2]

The critical assumptions going in to this analysis are a) that PV continues to grow at an average of 40% a year and b) that the rate of cost reduction of solar energy remains at 20% for every doubling of accumulated production and, of course, that fossil fuel prices remain at the February 2016 level. Any rise from today’s depressed levels will increase the benefit of the switch.

The experiment also assumes that one terawatt of fossil fuels needs one terawatt of PV power to replace it. This may be unfair to PV because it delivers a high quality energy (electricity) whereas most of the energy value in, say, coal, is lost in the power station in the process of conversion to electricity. Nevertheless, for the reasons given in the paper, I thought it appropriately conservative to assume that the amount of PV electricity needed is the same as the gross energy value of all the fossil fuels used.

The idea that solar PV could replace all use of fossil fuels sometimes seems absurd. What will happen at night or in mid-winter in high latitudes? But, as is increasingly clear, demand response will cut night demand, overnight storage will be provided by batteries and longer term buffers will come through the conversion of solar electricity to renewable gases and liquid fuels.

Reactions to this draft will be most gratefully received.

[1] I use PV as the main competitor to fossil fuels because I believe photovoltaics will become very clearly the cheapest and easiest way to generate electricity within a few years. But the arguments in this paper could also be made for wind energy. Or PV and wind could be combined to create the energy transition.

[2] I am very deeply indebted to Professor Nick Jelley of Oxford University for his mathematical work modelling PV growth and creating the ‘S’ curve. This thought experiment would have been wholly impossible without his help. Errors are mine, of course.

 

What the oil companies think about the divestment movement

A couple of weeks ago, 300 academics from Oxford and Cambridge issued a statement asking their universities to work with the fossil fuel divestment movement. Energy scientists such as Sir David MacKay joined professors from across the full range of subjects to ask for ‘morally sound’ investment policies.

Last Friday, a very senior executive from one of the world’s largest oil companies participated in an open and good humoured discussion with undergraduates at one of our leading universities  in a meeting convened under ‘Chatham House’ rules. I was present. The executive, who I will call Harold Schreiber, said that the divestment movement was ‘anti-industry, emotional and populist’. He said that the role of the ‘energy producers (is) to produce energy’ and that those who worried about climate change should focus their attention on the consumers of energy, not those who extract it. Schreiber said that oil companies will not respond to outside media pressure but that ‘constructive engagement’ might be more effective. He based this opinion on what he saw as the positive effect of those oil companies that remained in South Africa during the apartheid years working to build the country’s energy system and, in Schreiber’s words, ‘helping to avoid violence’.

Whether or not the divestment movement succeeded the world would continue to burn large quantities of fossil fuels for the rest of the century, he continued. About 80% of energy needs are met from carbon-based fuels today and in his assessment that number would still be about 25% by 2100. Oil would have to be extracted and burnt in large amounts, although its role will diminish beyond 2030.

Some of his company’s scenarios for the future suggested that it might be possible to get to ‘net zero’ emissions by the end of the century but these were not necessarily the most likely. Moreover, they would require technologies that extracted CO2 from the atmosphere. He referenced work at MIT that showed that the best the world could expect is a temperature rise of about 3 degrees above pre-industrial levels, well above the figure of less than 2 degrees agreed in the Paris conference. He implied that he regretted this probable failure but that the energy companies are not to blame. Governments and energy users are responsible.

Faster change is hugely difficult, he implied. One example was the UK’s poorly insulated housing. Although it may be possible to reduce heat losses in homes, people would need ‘softening up’ for a long time before they agreed to have contractors in their homes for six months of insulation work. More generally around the world, people need proper energy infrastructure to live decent lives and the anti-fossil fuel activists don’t understand that this cannot be provided by ‘iPhone apps’ or other digital tools.

1.3 billion people have no access to electricity at all and these people require the mainstream energy companies to provide them with the means to obtain a reliable energy supply. A decent standard of living demands steel for buildings and the anti-fossil fuel movement has no idea how this might be provided without coal in blast furnaces. Transport needs liquid fuels and no-one, he said, knew how this would be provided without oil from the ground.

As well as criticising the divestment movement for its anti-commercial and antagonistic attitudes, Mr Schreiber said that politicians were making huge mistakes. The UK’s decision to abandon Carbon Capture and Storage (CCS) was ‘frankly stupid’. Obama was wrong to block the Keystone XL pipeline. Sensible policy-making is ‘paralysed’ at the Federal level. More generally, politicians around the world ‘have to reach beyond grandstanding’ and take decisions that are ‘rational’, not driven by attempts to gather short-term popularity by appeasing climate activists.

When questioned on why the major oil companies operated in countries with poor human rights records, he asked whether the audience would rather the energy extraction in these countries was carried out by small private companies or businesses like his employer’s, which are subject to high levels of scrutiny and requirements for transparency.

In summary Schreiber suggested that companies such as his are the servants of the international economy, not its masters. The role of the international oil company is to organise the efficient deployment of capital for the production of inexpensive energy, not to drive the low-carbon future. He said that ‘we are only in the foothills of the move away from fossil fuels’ and his company would continue to invest heavily in oil and gas exploration rather than renewables.

After listening to Schreiber I went away to look at the latest accounts of some of the major energy companies. They show, of course, reduced profitability in the face of declining energy prices. Nevertheless, the divestment movement has a steep hill to climb. Few, if any, oil majors  have any need for new outside capital in the next few years. It might make sense for the financial health of pension and endowment funds to get out of fossil fuels but selling oil shares to another investor (‘divesting’) will have no direct impact whatsoever on the speed of the energy transition.

I think it may be more important to continue asking oil companies the question ‘is drilling for hydrocarbons the most productive use of your huge resources of available capital’? To suggest an answer, I looked specifically at Shell’s worldwide accounts because these have just been published. Excluding its new acquisition, BG, the company spent about $29bn on its exploration and production activities last year. That money enabled the company to just about stand still in terms of the total amount of energy to which it has access in its proven oil and gas fields. It produced 1.1 billion barrels of oil from reserves that dipped slightly to about 11.7 billion barrels. (This is a complex area; Shell has to write down its reserves estimates to reflect that portion of its portfolio that is no longer economic to operate because of low oil prices).

So, very roughly, $29bn is the amount of money Shell needs to invest in order to continue producing 3 million barrels of oil a day (1.1 billion barrels a year). This money could instead either be returned to shareholders or invested in renewable energy technologies. Mr Schreiber said that at the start of the discussion that the role of the energy producer was to produce energy. In the case of Shell, as one example of this, is the $29bn going to produce more energy if it is invested in oil exploration and production or, for example, in solar PV?

The numbers are relatively easy to calculate. Shell’s yearly production of oil has an energy content of about 1,800 terawatt hours. That is, very approximately, the same as the UK’s total consumption of energy from all sources. How much energy would Shell’s $29bn produce if it were invested in solar PV farms? Assuming a 22% capacity factor (much better than the UK but below the average in the US), an installed cost of $1 a watt and a 35 year panel life, the number comes out just ahead of the energy value of the oil that Shell produces each year. In other words, if Shell really sees its role as producing the energy the world needs, then its $29bn would be better going into exploiting solar energy rather than drilling wells and building pipelines. Rather than trying to destroy Shell, one of the world’s most efficient allocators of energy capital, we need to persuade it to divert its considerable skills towards the renewable economy.

Or take BP. In the UK alone the company spends about £175m on energy R&D. This compares to DECC's boast of putting about £100m into clean energy research as year, of which half is devoted to nuclear. Were a oil major to divert its efforts away from fossil fuels and towards the next generation of energy sources, the skill and knowledge in the private sector could make a dramatic difference to the speed of the switch to low-carbon sources.

I made this point clumsily to Mr Schreiber after the discussion. Wouldn’t his company’s exceptional skills and resources also be better directed towards – for example – using solar energy to make renewable liquid fuels, an endeavour Bill Gates sees as one of the most productive areas for new capital going into energy? Schreiber disagreed, saying that this area involved a lot of difficult science not within his company’s area of current competence.

Nevertheless Harold Schreiber knows there is an energy transition happening. Renewable sources of energy will eventually become very cheap and strand the existing assets of the major oil companies. Even the CEO of Shell said in September last year that solar would be the ‘dominant backbone’ of the energy system.

This may suggest that outsiders, such as Oxbridge academics mentioned in the first paragraph, need to engage with the oil company to show how they should redirect themselves - and their huge resources of capital - towards those energy sources that are going to be cheaper than oil. PV already produces more energy per dollar invested than oil. Shouldn’t Schreiber’s company be moving as fast as it can into exploitation of the sun’s energy? Won’t shareholders’ interests be best served by a rapid redirection of the company toward the most productive new sources of energy, rather than drilling for ever more recalcitrant sources of oil?

 

 

The vital role of time of use electricity pricing in the energy transition

Wadebridge in Cornwall is the centre of the first UK pilot of daytime cheap prices for electricity. This summer, 240 households will be paying a tariff of 5p a kilowatt hour during the 10am to 4pm period. Outside that time slot, the rate rises to 18p, almost four times as much. In winter, the price reverts to 13.4p across the full 24 hours.

This scheme is offered by innovative electricity retailer Tempus with the participation of the very effective Wadebridge community renewables group. The rapid increase in the generation of solar and wind electricity around the world is driving many similar ‘time of use’ tariffs in places such as Hawaii and California. Mostly these are compulsory, not a voluntary decision as in Wadebridge. In Cornwall specifically the electricity network is struggling because of the strict limits placed by the distribution grid on solar power exports to the rest of the UK and time dependent pricing is a highly important innovation.

Oahu, the most populated of the Hawaiian islands, has a peak late afternoon price about three times the price at midday. New rates such as these often reflect increasing surpluses of power in peak sunshine, which is not well aligned to the maximum need for air conditioning around 5pm, after the sun has begun to fall. In Ontario, peak prices are about twice off peak tariffs. California has now mandated time of use tariffs, likely to be about 15 cents a kilowatt hour for off peak and 37 cents for peak early evening times.

The aim of these time of use pricing schemes is to push electricity consumption into the periods of low tariffs and to minimise the amount used at times when supply isn’t bolstered by sun or wind. As solar grows from its current 2% share of world electricity supply, we can expect more and more use of pricing variations to mould power demand to align better with power production.

Time of use pricing has the vital secondary role of encouraging the purchase of domestic battery systems that take in power at cheap rates and provide it when the household needs it later in the day. As batteries become cheaper, we’ll increasing numbers of people use them to enable the purchase of cheap solar or wind electricity.

Do the new Wadebridge prices make sense from a householder’s point of view without a battery? Not unless the home can shift a reasonable amount of its consumption into the six hour low rate time slot.  With average domestic UK electricity usage patterns, the cost of the Wadebridge tariff would be about 109 pence per day during the summer, compared to 104 pence on the standard Tempus tariff. (Unusually, the Tempus ratecard has no fixed daily charge so although its standard tariff looks expensive at 13.4p per kilowatt hour, it is broadly comparable to the Cornish prices of the big electricity retailers, which might include a 25p daily fee).

The  Wadebridge summer tariff will save a customer money if the household switches about one tenth of its total consumption into the off peak period. That would probably be achieved by only running the dishwasher, iron and washing machine in the cheap rate period, something not easy for working families but perfectly possible for people at home all day.

In the future, of course, all the appliances in the home will be controllable from a phone app, meaning that machines could be turned on and off as electricity prices changed. Or all of main appliances could use switches that turn them on and off automatically as electricity availability changes. The French electronic controls giant Schneider is partnering California demand response company OhmConnect to do this. The promise is that households will get paid cash for allowing instant switch on and off.

The OhmConnect proposition isn’t exactly a time of use tariff. It isn’t aimed at systematically shifting demand from one time of the day to another. Instead it is a way of instantly cutting electricity use at times of grid stress, such as when a power station ceases to operate without warning.

One trial in London that raised prices to almost four times average levels for one hour periods of grid emergency (with notification by text message) in return for lower prices at other times enabled most participants to save money. More generally, it will only be politically possible to introduce demand moulding price structures for electricity if most consumers and businesses benefit financially. This should be perfectly possible simply because matching supply and demand will also save the utility companies money and stop needless investment in new generating stations that might work less than a hundred hours a year.

However a UK tariff that cut prices when the sun was shining or wind blowing is not yet likely to make a home battery financially logical, even if the ratecard operated all year, not just in summer as it does in Wadebridge. If the householder bought a 8 kilowatt hour battery, and used it to store electricity bought at 5p a kilowatt hour so as to avoid paying 13.p a kilowatt hour, the value might be almost £250 a year. The cost of the best battery and home control system is likely to be over £10,000 at the moment, bought from market leader Sonnen, a German company rapidly developing into Hawaii and California. That’s a forty year payback on a battery that will last about ten. But battery prices are going to continue falling rapidly for the next few decades. Home battery systems will make financial sense soon.