When will electric cars cause oil demand to start falling?

The volume of fuel needed to power cars and other light vehicles will start falling in early 2026. This is the prediction of a simple model I have built to forecast how the electrification of transport will curtail oil use. I think the model is the first systematic attempt to calculate the year-by-year impact of EVs.

By 2030, petrol and diesel use for light vehicles will be declining over 1% a year and the fall will accelerate rapidly thereafter. In that year, electrification will have pushed oil use 4 million barrels a day below what it otherwise would be. This equates to about 4% of today’s global production. But oil demand for fuelling cars and light vehicles will nevertheless be higher in 2030 than today because of the increasing overall volumes of cars sold.

I have built this model because the oil companies are now producing their own estimates of the impact of battery cars on oil use. These figures seem too informal and contain many unrealistic assumptions. I thought it might be helpful if I carried out a fuller piece of work. I want to stress that my spreadsheet is also uncomplicated but I think it represents a real advance on other ways of estimating this utterly crucial figure for the world economy, and our climate change ambitions.

The key input to the spreadsheet is, of course, the rate of growth of electric cars. In order to provide maximum credibility, I have used figures provided last month by Continental AG, (‘Conti’) one of the top five global car component manufacturers.[1] The company carried out a major review of the likely evolution of the car market, including conversations with other suppliers and customers.[2] Continental sees pure electric vehicles representing just under 20% of the global market by 2030. Hybrid electric cars will also have grown by that date, meaning that ‘close to 60% of the market will be electrified in the company’s words.[3] (This figure includes substantial volumes of what are called ‘mild’ hybrids, a type of vehicle that almost entirely relies on internal combustion engines). I think Conti's numbers are too conservative but I have used them because of the investment the company has made understanding its marketplace.

The start of the date at which oil demand for transport begins to fall is critical to the future of the oil industry. Large amounts of crude, particularly in high cost locations, will be stranded if EVs start cutting oil use soon. In common with other oil majors, BP has said that it expects oil demand for cars and light vehicles to continue to rising at least until 2035. Continental envisages both lower overall vehicle sales of all types in 2030 but also a much larger percentage of fully electrified battery-only vehicles than BP. Investors in both types of company – oil and automotive – should be interested in which of the future is correct. My model shows that if Continental is right, BP’s optimism is very mistaken.

Model outputs

My model gives the following result for daily oil demand. The two lines below show a world of no further electric vehicle sales and one which follows Continental’s suggested trajectory. The gap between the two lines is just over 4 million barrels of oil a day in 2030. This compares with BP’s estimate of a gross saving of around 1.2 million barrels a day from electric cars in 2035 before taking increased vehicle numbers into account. (I do not know whether BP includes ‘mild’ hybrids in its calculations).

Source: Spreadsheet projections and Continental AG

Source: Spreadsheet projections and Continental AG

In addition, I thought it might be useful if I included another estimate that see pure electric cars grow at a faster rate. Continental sees 22 million new battery-only cars sold in 2030. What happens if this number is actually 40 million? (I also assume a faster rise across all years from today). This is a challenging figure, implying that about 35% of new cars and light vehicles are fully electric in 2030. However it is clearly possible, given that many of the manufacturers are now openly talking about 25% EV sales in 2025. My projection is below. As you might expect, the reduction in oil use starts earlier, falling from late 2024,and by 2030 demand is 6 million barrels a day below the ‘no electrification’ scenario. However, it is only by this date that oil demand finally falls below the 2016 level. The future challenge remains immense.

Source: Spreadsheet projections

Source: Spreadsheet projections

Appendix

Method

The purpose of the model is to show how much petrol and diesel is used by cars and other light vehicles in each year to 2030. The fuel use is a function of the number of vehicles, the distance each travels and the average fuel economy (litres per 100 km travelled or miles per gallon, either US or UK).

The key inputs to the spreadsheet are

a)    Historic and forecast car and light vehicle sales, both electric and conventional.

b)    Estimates of the length of life of cars and other vehicles. How many vehicles made in each previous year are still being driven? (Evidence from the UK is that very few vehicles more than 25 years old are used on the roads. Those that are still in service will generally drive very small numbers of miles).

c)     Estimates of how many miles/kilometres vehicles drive per year. If the UK is any guide, the distance travelled falls sharply as the car ages. The model assumes no change in future in average vehicle miles for each age of car.

d)    Fuel economy estimates. The spreadsheet estimates how much fuel is consumed per kilometre travelled based on average fuel economy for each year. The fuel economy of a car made in a particular year is assumed not to change as the car ages.

e)    Estimates of how much fuel is saved for each class of electrified car or other light vehicle. Continental splits its forecasts into different classes of electrification and the model suggests a fuel saving for each type.

A simple example. To build up an estimate of the number of barrels of oil needed to fuel cars and light vehicles in 2016 I needed to calculate the number of vehicles produced in 2003, for example, that were still on the road, the average mileage travelled and their fuel economy. I want to stress that all of these numbers are uncertain and therefore there will be errors in my inputs. However my estimate of the total amount of fuel used globally is consistent with estimates produced by the US Energy Information Administration.[4]

More detail follows on these inputs.

a)    Vehicle sales. The yearly sales of all type of vehicle were about 94 million in 2016. This includes heavy freight vehicles totalling about 3 million. I have assumed that these will not be electrified in the near future. (Although Elon Musk as has recently talked about a planned articulated or ‘semi’ truck in recent weeks). So I use a 91 million estimate. I increase this number in line with Continental’s forecasts, reaching 111 million in 2030.

b)    Age of cars on the road. The UK publishes statistics on the age distribution of its cars. This enabled me to work out the mortality rates of vehicles. If, for example, we see 1.5 million of the 2006 registrations were still around in 2015 but only 1.4 million in 2016, we can estimate the age distribution of vehicles leaving active use. We can show that, on average, 15% of vehicles are removed from the road in their fourteenth year, the peak year for mortality. Care is needed here; the average life of vehicles has increased substantially in the last twenty five years but this effect appears to have slowed down or stopped, at least in the UK. I use the pattern of UK car mortality as the basis of my estimate for the world.

c)     In the UK, the use of car declines as it gets older. This seems to be largely an effect derived from heavy car users buying new vehicles and then selling them to lighter drivers as the car ages. There is also a minor impact from people driving less as they grow older. If I buy a car when I am aged 50 and keep it for 15 years I am likely to use it much less when I am 65. I use the UK’s figures for the miles/kilometres driven for each year of a car’s age.

d)    Fuel economy estimates. We have good data on the average claimed fuel economy figures for the major economies for passenger cars. ‘Real world’ fuel consumption is known to be substantially higher. And, of course, the fuel use of heavier vehicles such as buses and delivery vans is greater than domestic cars. I have created an estimate of the average fuel use (litres per 100 kilometres) for the world. This is not as brave as it sounds. The fuel economy of a Ford Focus will be very much the same whether it is sold in Ecuador or Germany.

e)    Fuel savings by type of car. Continental sees four classes of electrically assisted vehicle. At the top of the tree is the pure battery car. (We will also see pure electric vans, of course, and increasingly battery-only buses). This saves 100% of its liquid fuel consumption. Then comes the plug-in hybrid. I assume this reduces oil demand by 50% below the standard car of the same age. So-called ‘full’ hybrids, which cannot be plugged in but save some fuel because of regenerative braking, a need for a smaller engine and other features save 25%, I estimate. ‘Mild’ hybrids, which use a battery to store energy from braking and use it to improve acceleration, save 12%. The latter three figures are my own estimates based on reading motor industry statements. If others can suggest better figures, please do get in touch.

The work I have described so far involves a number of careful guesses. I don’t want to pretend my model is particularly accurate. However the key point is that when I work out the fuel consumed by each yearly cohort of cars and add it up to get an estimate of the number of barrels of oil needed each year to make gasoline/petrol and diesel, my figures are very similar to the US government estimates. In other words, I may have wrongly individually estimated the global car stock, the fuel economy and the miles travelled but the final result is reasonably accurate.

The major problems with my model

a)    I have extrapolated the rate of mortality of cars and light vehicles from UK statistics on cars alone.

b)    Similarly, I have estimated how the mileage of cars changes with the vehicle’s age from UK data. This information is also self-reported by respondents to questionnaires and may suffer as a result.

c)     I have had to generate assumptions of how much fuel the various types of hybrid save. (I have not included ‘range extender’ cars, assuming that this category will fade as battery size increases).

d)    I do not know how fast underlying fuel economy will improve from now on. My assumption is that this will be quite slow, apart from the improvements induced by electrification. I have used a rate that gradually decreases. The underlying reason is not technological. Rather, it is that as the electric car market grows the R&D effort in large OEMs and component manufacturers will swing away from internal combustion engines.

e)    I have assumed that electric car buyers are broadly typical of all buyers. In other words, the cars they buy or would have bought (e.g. large versus small, petrol versus diesel) mirror the market as a whole. To be clear, if electric car purchasers are would actually have otherwise bought very small cars, the savings in total global fuel consumption would be less than if they were otherwise to buy a large car. My spreadsheet sees the electric car sales pattern as similar to internal combustion engine deliveries. The same assumption is made with respect to the distance travelled, and how this changes as the car gets older, and the age at which the car is scrapped.

f) I have not included any impact from the arrival of autonomous cars, nor car-sharing. By 2030 these factors may be reducing the number of new cars sold, although the total mileage driven may not change much. 

[1] Page 14 of this presentation gives the key numbers: http://www.continental-corporation.com/www/download/portal_com_en/themes/ir/events/20170425_strategy_powertrain_uv.pdf

[2] Continental provided estimates for 2016, 2020, 2025 and 2030. I have interpolated between these figures for the intervening years.

[3] In Continental’s terminology, a car is ‘electrified’ if it can be plugged into the electricity supply but also if employs any form of hybridisation, including what is termed ‘mild’ electrification using a small battery to assist acceleration and recover energy from braking.

[4] Figures available at www.eia.gov/outlooks/ieo/transportation.cfm

A progressive carbon tax could be the low-cost way to decarbonise

The idea of a universal carbon tax is gaining popularity around the world. Instead of complex subsidies and regulations, we might be able to get decarbonisation more cheaply and simply if the use of fossil fuels was taxed at a rate proportional to the amount of CO2 emitted. As has been shown in the UK over the past couple of years, quite modest taxes on coal use have almost removed this fuel from the power generation mix. Carbon taxes raise the price of fossil fuels, disportionately penalising coal, the most polluting source of energy.

The voices in favour of a carbon tax now include Exxon, former US Secretaries of State and the Chinese government.  The idea is appealing to the political right because it minimises the distortion to energy markets and, at least in theory, captures the full cost of carbon pollution, encouraging the quicker growth of renewables. Instead of expensively subsidising low carbon energy, with all the difficulties that this involves, perhaps it is better to simply make fossil fuels relatively more expensive? But those on the left have been less impressed because it will tend to increase the price of goods, such as natural gas for heating, that tend to absorb a much large fraction of the budget in lower income households.

Is there scope for compromise? Can we keep the right happy with a carbon tax and also appease the left’s concerns? Several countries are exploring – or have already introduced – a carbon tax whose proceeds are completely recycled to individuals and households. In the Canadian Province of Alberta, for example, fossil fuel use is penalised by a tax of C$20 per tonne of CO2 emitted. This has tended to increase the price of energy and items made locally using fossil fuels. But 100% of the tax raised is then paid out as an allowance to Albertans in the bottom half of the income distribution. This year a single adult will receive C$200 and a couple C$300. The net effect of the carbon tax and the rebate combined is to redistribute income from richer groups to the less well-off. This is because poorer people typically use less electricity and other fuels and buy fewer items with indirect or direct fossil fuel content.

How could this work in the UK? The country has CO2 emissions of about 390 million tonnes a year. (I’m excluding methane and other global warming gases in this illustration). About 65 million people live in the UK, so the average person is responsible for about 6 tonnes of CO2. If all fossil fuel use was taxed at, say, £50 a tonne the typical individual would see price rises of around £300 a year. (Calculating the CO2 embodied in imported goods would increase this figure).

Some of this would directly be via electricity and gas bills and increased petrol and diesel costs. Another portion would be less invisible because it would be wrapped into bills for other things. Restaurant meals, for example, might go up slightly because the costs of power had risen and ingredients had gone up slightly in price because of higher transport charges.                             


Let’s assume everybody in the UK was credited with £300 each year. As in Alberta, poorer folk would tend to benefit because they consume less energy, or things that embody energy, than the average. So their extra bills would not outweigh the £300 that they got annually from the government. In a sense, this £300 would be the beginnings of a ‘basic income’, the increasingly popular idea of a benefit that is paid to everybody, regardless of need or entitlement.

As an illustration of how a carbon tax merged with a rebate, or ‘basic income’, might operate, I looked at how much money UK households (not individuals) spend on electricity, gas and other domestic fuels, including petrol for the car. This analysis does not cover all the energy that is embedded in the goods and services we buy or are provided with using our taxation payments. But it does cover the direct expenditure on motor fuels and home energy. This is therefore a very simple and incomplete analysis but demonstrates how a carbon tax might help reduce income equality.

I used standard sources for this work.[1] The government produces an annual survey that splits homes into tenths (‘deciles’), ranging from those who have the least amount of money to spend to those who have the most. A household sitting at the top of lowest decile spends a total of about £194 a week, according to the latest data. A household in the top spends more than £1211 a week or over six times a much.

These totals are split into various categories. The survey records the average expenditure on fuel to heat the home and on petrol or diesel for a car. These weekly figures are in the table below. As you can see, households in the bottom decile spend more than £22 a week on home energy and fuel for a car. This is considerably more than 10% of total expenditure on all items. Domestic energy alone is about £17 a week, and this is likely to have risen as a result of recent price increases. People in the top decile spend eight times as much on motor fuels but less than twice as much on home energy. This means that overall they spend little more than half as much as the poorest tenth as a proportion of their income. 

This is the core of the problem. If a country such as the UK puts a carbon tax on energy it will disproportionately affect the least well-off. It will be what is termed ‘regressive’. This makes a tax politically impossible. So I went on to look at the impact of recycling the whole tax back to UK households. (Of course, as in Alberta, it could be just given back to a less-well-off portion of the population).

To do this exercise I had to make assumptions about the quantities of electricity, gas and motor fuels bought by each decile. And then I needed to calculate the amount of CO2 resulting from the use of these energy source. The analysis shows that a household in the bottom expenditure decile is responsible for less than 4 tonnes of CO2 (domestic energy and motor fuels only) while a home in the highest spending tenth accounts for over ten tonnes. The average is about 6.6 tonnes. (Note that these figures are for homes, which contain on average 2.4 individuals).

The next step is to calculate the extra cost that households in each decile would bear as a result of a £50 carbon tax. The lowest decile will see bills rise by just under £180 while the highest will pay an increase of about £530. (For the lowest spending households this would be a cost increase that took away about 2% of their total spending power and is thus very unlikely to be implemented without some form of monetary compensation.

The final analysis is to assess what would happen if the entire tax were recycled as lump sum payment to each household. Each home would receive about £330, representing 6.6 tonnes times £50 per tonne. The net impact – tax cost versus lump sum rebate – is shown in the following chart. The numbers indicate that the least well-off homes would gain £150 a year and the wealthiest would lose £200. On average, payments would equal the tax.

When implemented in this naively simple way, a carbon tax can be made ‘progressive’ (helping the poorest and taxing the richest). The political right can approve, because the tax is an efficient and market-based way of taxing pollution while left can support it because the impact increases the net household income of poorer homes.

Of course a carbon tax should be made universal if it is implemented at all. It should cover all uses of fossil fuels including those employed to manufacture imported goods and services. Otherwise it will disadvantage home producers against foreign suppliers. The encouraging thing is that it looks more possible to get an international agreement on a standard carbon tax now than it ever has been in the past. (That's not to suggest it will be easy).

In the UK renewable subsidies are often blamed – usually inaccurately – for putting up energy prices by large amounts. It is becoming politically more challenging to get society to agree to continue to support low carbon energy (including electric transport). I sense it would be easier to get continued decarbonisation using a carbon tax, combined with a rebate, than continuing with subsidy schemes. And, perhaps foolishly, my training in economics gives me an almost religious faith in the price mechanism as a way of directing an economy.

[1] The Living Costs and Food Survey, ONS. https://www.ons.gov.uk/peoplepopulationandcommunity/personalandhouseholdfinances/expenditure/bulletins/familyspendingintheuk/financialyearendingmarch2016

Power-to-gas: the remaining critical ingredient in the energy transition

A windy week in Germany produced the expected result. Wholesale electricity prices from 19th to 26th February 2017 dipped below zero four times and much of the weekend saw figures below €25 a megawatt hour. This pattern is increasingly frequent across many electricity markets. As the Economist pointed out last week, the arrival of large scale renewables with zero operating cost is eating away at the businesses of those companies reliant on selling on the open market. €25 does not pay for the cost of the gas to generate a megawatt hour in a power station.

German electricity production

(Prices are the wavy lines at the bottom of the chart. Electricity production from wind is the light green area)

Source: Energy-charts.de. (Best site in the world for full public information about a power market!)

Source: Energy-charts.de. (Best site in the world for full public information about a power market!)

In the US, NRG, which is the largest independent producer of power, summed up the problem by saying its business model was now ‘obsolete’. Lower and lower prices are making it impossible to produce electricity from gas or coal in markets increasingly captured by solar and wind. Equally, no-one can raise the finance to build new power stations, even in those countries with ageing fleets, such as the UK, because of low prices and fewer and fewer hours of operation. This problem will get worse.

Whether you are an enthusiast for a fast transition to a renewables-based energy system or are sceptical about the pace of change, the destruction of the traditional utility by the eating away of wholesale prices is not good news. It increases the possibility that the increasingly rapid switch to renewables around the world will be brought to a shuddering halt by governments worried about the security of energy supply because of the intermittency of wind and solar. Although we can make huge progress in adjusting electricity use to varying supply, ‘demand response’ will never be enough to deal with weeks of low wind speed and little sun in northern countries.

I want to put forward the view that there is only one way to deal with this problem. When power is in surplus, it needs to be turned into natural gas. This will reduce the amount of excess electricity and provide renewable gas for burning in power stations when renewables are in short supply. ‘Power-to-gas’ is the critical remaining ingredient of the energy transition. Can I put this as strongly as I can? Without a rapid and whole-hearted commitment to this technology, the renewables revolution may ultimately fail.

Power to gas

Electricity can be used to split water into hydrogen and oxygen in the reaction known as electrolysis. The hydrogen is then combined with carbon dioxide, either using biological techniques or through the conventional Sabatier process. This generates methane, the main part of natural gas. If the CO2 used in the reaction is derived from organic sources, such from anaerobic digestion, it is ‘renewable’.

What is the net impact of this transformation of electricity to natural gas? First, the surplus of electricity is reduced. Second, the energy in the electricity is largely transferred to the energy in methane. This methane can be indefinitely kept in natural gas networks, which generally have a capacity for storage vastly greater than the batteries are ever likely to possess. Although Britain has relatively little gas storage, other countries often have months of capacity. They can make gas when electricity is abundant and then use that gas to generate power when the wind and sun are not available.

The energy economics of power to hydrogen

Large amounts of hydrogen are generated today around the world. The gas is almost entirely created through a process known as ‘steam reforming’ which takes methane and water creating hydrogen and carbon dioxide. The CO2 is vented to the atmosphere, thus adding to global emissions. Very approximately, hydrogen made from methane costs about twice the cost of natural gas per unit of energy carried. So if natural gas (mostly methane) costs 1.6 pence (2.0 US cents) per kilowatt hour, which is approximately the current wholesale rate in the UK, then producing a kilowatt hour of hydrogen will cost about 3.2 pence (4.0 cents).

The alternative way to produce hydrogen is through water electrolysis. This uses electricity and until recently the conversion process has been less than 70% efficient. And, generally speaking, electricity has been several times expensive than natural gas per kilowatt hour. A commercial customer might have bought electricity at 8 pence a kilowatt hour or more, meaning that at 70% efficiency hydrogen costs about 12 pence per kilowatt hour (14.6 cents) or almost four times as much as gas produced from methane. Clearly, no-one produces hydrogen using electrolysis unless they are remote from steam reforming plants.

Electrolysers are getting much cheaper and more efficient. We will see electrolysis costs fall to around $400/kilowatt and efficiencies rise above 80%. However making hydrogen from power will still be usually more expensive than from steam reforming of natural gas.

But look again at the chart of German prices above. Anybody owning an electrolyser that could work when electricity prices are low would have been able to make hydrogen for much less than from methane for much of last week. Very roughly, at any time the German power price was below €25, an electrolyser could make hydrogen more cheaply from electricity than from gas. That is, if the electrolyser owner could get access to inexpensive wholesale power, it could absorb cheap electricity. I reckon – but do not have the numbers to prove this – that German prices were below €25 per megawatt hour for at least 30% of last week.

This is a complicated area so please let me labour this point. The evolution of power markets is pushing the typical short-term wholesale price of electricity down to historically unprecedented levels. At the same time, the commercial and household price of power is rising as subsidy and electricity network costs rise as the renewables revolution takes hold. The low wholesale price of power at times of wind or of strong sun means that making hydrogen from electrolysis is often cheaper than using natural gas. And as wind and solar capacity rises, this reversal of usual pricing differences is going to happen far more frequently.

Of course most business do not buy power through a wholesale market, and almost everybody has to pay grid distribution charges. So the logical place to put these electrolysers is next to wind farms or solar parks which can use power at no direct cost. When these entities are expecting to get very low power prices they will swing over to making hydrogen instead.

Hydrogen to methane

Hydrogen is useful and will grow in importance. But moving it around is complicated and expensive. So I think it will be used predominantly at the point of production, either for chemical products, fuelling fuel cell cars or making methane. In my view, it is making methane that offers by far the most important opportunity because it can be stored and transported so much more efficiently than hydrogen.

Methane (CH4) can be made from hydrogen and CO2 in one of two main ways. The traditional Sabatier process offers a simple route, albeit with substantial energy loss. That is, one kilowatt hour of hydrogen (you’d get this by burning about 25 grams of the gas) turns into about 0.75 kilowatt hours of methane. The rest is lost as heat. The second is biological. Some microbes in the class called Archaea can absorb hydrogen and CO2 and exude methane as a waste product. Their efficiency is about the same, or slightly better, turning up to 80% of the energy in hydrogen into methane. They can make the transformation quickly and in relatively low cost production systems. As I say in The Switch, the leading contender is a German company called Electrochaea which operates its first 1 megawatt plant near Copenhagen getting its CO2 from a stream of biogas out of a wastewater treatment plant. The CO2 is free. In fact it should have a negative cost since it allows the whole stream of biogas to be feed into the natural gas grid rather than inefficiently burnt in gas turbines on site.

Think of methane as identical to natural gas, although the gas in pipelines also contains varying amounts of longer molecules. If we use surplus electricity to make hydrogen and then combine it with CO2 to make methane, then we are losing energy at two different stages: electrolysis and methanation. Very roughly, the best we can hope for is to obtain 65% of the energy in electricity out of the process in the form of methane.

Natural gas trades at about 1.6 pence (2.0 US cents) per kilowatt hour at the central trading point in the UK. How cheap does electricity have to be to make it financially attractive to use it to make ‘renewable’ methane? Very roughly, and before the operating costs of the machines, it has to be 1.6 pence times 65% or just over 1 pence per kilowatt hour (1.25 US cents).

The German market operated at less than this price for about 35 hours last week, or one fifth of the time. In all those periods, an electrolyser could have been profitably making hydrogen to be converted back into methane. The methane – which has very low greenhouse gas emissions because it has been made from renewable electricity and the CO2 from organic waste – can be pumped into the gas grid. It can then be used to make power in a gas turbine when electricity is in short supply.

Conclusion

To most people in the utility industry, the idea that it can possibly make sense to use valuable electricity to make cheap natural gas still seems absurd. They aren’t looking at the charts, I say. As wind and solar electricity grows in importance, the cost of power will inevitably drift towards zero. (First year economics tells us that prices always edge towards the marginal cost of production). Electricity will become cheaper than gas. On a windy weekend night in the North Sea offshore turbines will produce more electricity than northern Europe needs at some date in the not-to-distant future. Negative wholesale electricity prices will become increasingly prevalent.

We really need this to happen. First, it means we can happily heat buildings with low carbon electricity, even without the advantages of heat pumps. More important, it means that instead of using fossil natural gas for power and heat generation, we can use renewable natural gas instead, particularly when power is costly because of lack of wind and sun.

The central argument of this article is thus that the right way to ‘fix the broken utility model’ that the Economist talks about is to link the gas and electricity markets through large-scale application of power-to-gas technologies. Big utilities talk about understanding the need for decentralisation but the reality is that they will be terrible at moving away from centralised production plants. What they would be good at is running large scale electrolysis and methanation operations that allow them to continue to run CCGT power plants when electricity is scarce. We will not need capacity payments or other complex subsidies and incentive schemes. By creating a continuing role for CCGT we will have found a way to keep our energy supply secure without threatening decarbonisation objectives. 

 

 

 

1.     With many thanks indeed to Vyas Adhikari for his help understanding some of the questions of chemistry and energy transformations involved. Errors are all mine.

2.     The material in the piece above is highly compressed. I’m happy to provide more analysis and back-up if anyone is interested.

 

 

 

 

 

 

 

 

Is there an alternative to the Westinghouse AP1000 nuclear plant?

Toshiba is struggling to avoid bankruptcy because of the cost overruns at the two US sites constructing its subsidiary Westinghouse’s AP 1000 nuclear reactors. Latest estimates suggest that these new plants will absorb almost as much cash as Hinkley Point C per kilowatt of generating capacity.

The cost of electricity delivered by a nuclear power station is very largely determined by the amount of capital expended during its construction. This suggests that the AP1000 design will need a contract price for its power generation similar to the £92.50 plus inflation agreed for EdF’s Hinkley Point proposal. This number is now probably higher than the cost of offshore wind and substantially larger than the costs of solar or onshore turbines.

The Financial Times reports that the government wants to cut the rate paid to future nuclear stations by 20% or more. If neither the EPR design for Hinkley Point nor the AP1000 proposed for Moorside in Cumbria can achieve this, are other contenders available that might offer better cost control? The best example to look at is probably the four reactor project in the United Arab Emirates. Constructed by Kepco, South Korea’s dominant electricity supplier, this 5.6 gigawatt scheme is on track to start up the first reactor at some stage in 2017 and complete the final plant in 2020. So far, the evidence is that the design will probably cost about half the EPR and AP1000 per unit of generating capacity. My approximate calculations suggest that the Korean competitor can probably provide power to the UK at around £56 per megawatt hour, slightly lower than onshore wind today.

Nuclear construction prices have two key constituents. One is called the ‘overnight’ element. This is the notional cost of building the plant using the assumption that it is entirely constructed ‘overnight’. In reality, of course, nuclear power stations can take decades to complete. The money spent in the first year by the owner has an interest cost attached to it which will not be recouped until plant starts getting paid for generation. This is the full cost of construction.

In the table below, I’ve written down what I think is the approximate overnight cost of each of the three reactor designs, at least as far as we can see today. In the second row, I have put the full cost, including the assumed interest cost. In both cases, I have had to use publicly available information. (This information is often confusing and I may have made errors). 

Main points.

1)    The Hinkley Point EPR is usually stated to have a projected ‘overnight’ cost of £18bn. I assume an exchange rate of £1 to $1.25. The full cost, including the interest burden during construction, is often written as £25bn, or about $31.25.

2)    The two AP1000s being constructed at the Plant Vogtle site in Georgia, USA, are being constructed by Westinghouse and a subsidiary under a contract with four future owners, of which the most important is Georgia Power. Georgia Power is already charging its customers for the AP1000 construction costs and therefore the underlying ‘overnight’ and full costs are far from clear. Second, the contract sees most of the overrun being borne by Westinghouse and most sources seem to suggest that this number is currently about $3bn. However a quick look below at a photograph from January 2017 suggests that construction is still very incomplete and overruns may increase sharply both because underlying costs increase and because completion is delayed, thus increasing interest charges.

A January 2017 photograph of Plant Vogtle construction (copyright Georgia Power)

A January 2017 photograph of Plant Vogtle construction (copyright Georgia Power)

3)    The detail available on the UAE Kepco contract is not great. It seems that the initial contract between Kepco and the state entity was for $20bn. I have taken this as the overnight cost. In late 2016, a re-financing was arranged for $24.4bn and I have assumed that this is the full cost including interest until the completion of the first reactor.

4)    The table below shows that a) the Kepco APR1400 project is much bigger than the UK and US sites and b) it will be completed, as things stand today, much more rapidly than the AP1000 and the hoped-for 10 year cycle for the EPR at Hinkley. It also has a construction cost per kilowatt of about half the alternates.

An estimated assessment of the economics of construction and likely construction time

An estimated assessment of the economics of construction and likely construction time

5)    I’m going to employ a rule of thumb that the fuel cost of a nuclear power station is about $5 a megawatt hour and the operating expenses are around $14, including decommissioning. (Please note: although decommissioning costs are high, they are 60 years into the future. Therefore their ‘present value’, in the language of economists, is small. Anybody studying the costs of cleaning up the UK's early nuclear sites today is entitled to laugh at this idea).

My calculations suggest that if the interest cost required is about 9%, the Kepco APR1400 could be financed at a guaranteed UK electricity price of about $70, or approximately £56 per megawatt hour. This is just over half the inflation adjusted price being paid to the EPR’s owners at Hinkley Point.

Whether Hinkley Point is constructed or not depends on the ability of EdF to raise money in the capital markets. (It has just started a new fundraising that will help). But we know for certain it will be last EPR ever constructed since EdF has stated it will use a new design in future locations. By contrast, the international evidence is that the Korean approach to nuclear construction, focusing on ensuring that the design is standardised and experience gained at one location is transferred to the next site, appears to be working. Although the full details of the UAE project are not public, the project appears to be on time. The first of the four Berakah reactors will be probably completed within five years, an achievement that contrasts with the disastrous experiences with the EPRs in Finland and Normandy, France.

Should the UK invite Kepco to come in and develop a crash programme of nuclear construction? The design approval process will take 4 years, we are told. So the earliest the new capacity would be ready would be about 2028. By that time, offshore wind will probably be cheaper than the APR1000 costs and onshore wind and solar will certainly be. Whether energy storage has progressed fast enough for wind and solar to be sufficient is unclear.

The crucial point seems to me that if the UK wants nuclear – and people will have very different opinions on this - it needs to transfer its attention away from the increasingly complex business of getting Toshiba and its partners to construct Moorside and look instead to the world’s most successful nuclear power station constructors. Kepco stands out. I guess it could achieve the UK government's current objectives for electricity generation costs. So might the Russians and the Chinese, but their offerings are politically highly problematic, to put it mildly.

2017 BP Energy Outlook

BP’s Annual Energy Outlook forecasts how much energy the world will use until 2035. It breaks this down by fuel source and region. It also estimates the likely change in carbon emissions. The 2017 edition has just been published and I compared some key numbers to those published last year. My core conclusion is that BP is still reluctant to recognise how sharply falling costs will inevitably increase the growth rates of renewable electricity and electric cars.

Total energy demand.

The chart below shows what BP expects to happen. World energy demand is now forecast to rise at 1.3% a year until 2035, down from 1.4% this time last year. Oil and gas growth rates are cut but, despite the impression in the text, coal demand is still expected to rise slightly.

The pattern of changes in renewables.
Every year since 2011, BP has increased its estimates for the total output of renewables in the next couple of decades. This year, the increase is as big as ever. In fact, the yearly revisions are tending to grow in size. We are still only looking at 10% of world primary energy demand by 2035, but at least this is trending in the right direction.

Source: BP Energy Outlook, 2016 and 2017

Source: BP Energy Outlook, 2016 and 2017

Why is BP getting more optimistic about renewables?

Last year, BP produced estimates of the cost of wind and solar that were massively out of line with analyst calculations of the cost of electricity produced. For example, BP said that solar PV costs in the US would average about $110 a megawatt hour in 2020.

All the estimates have come down in 2017. But they are still detached from reality. Reading off the chart, BP seems to be saying that PV in the US will cost, on average, about $58 a megawatt hour in 2035 - a cut of 30% on its 2016 estimates - although it might be as low at $35 in some locations. The finance house Lazard said the US is now at around $50-$55 for solar PV today in good locations. Rather surprisingly, BP sees no cut whatsoever in solar costs in the US between 2025 and 2035, a view that will be shared by almost nobody, either in the renewables industry or outside.

BP is also more bullish about onshore wind in the US and in China. In BP’s eyes, wind will be unambiguously the cheapest source of power in both places by the latter part of the next decade. By 2035, wind is shown as less than half the cost of either gas or coal in China.

This is where credulity is stretched very thin indeed. Even though BP shows renewables as by far the cheapest source of power in China, it assumes that they will represent only about 19% of power generation in 2035, up from about 7% today. There’s no explanation for this. Indeed, the only thing BP does say is that renewables integration into electricity grids will be relatively painless. So the reason for the slow growth is unclear, particularly in view of the Chinese government’s published expectations for renewables investments and its wish to retire much of its coal-fired capacity.

Electric cars

BP now acknowledges that electric cars exist, and will have some effect on oil demand. (In the past it said that natural gas would be a more important transport fuel than electricity). It projects 100m electric cars out of a total fleet of about 1.8 billion by 2035. EVs cut oil consumption by about 1% below the level it would otherwise have been. Electric cars only capture about 10% of the total growth in the number of cars on the world’s roads.

The company sees that battery costs are falling, and that eventually this will make EV’s directly cost-competitive – perhaps within ten years. But BP doesn’t say whether this on the basis of a purchase cost comparison or the easier target of being cheaper over the entire life of the car. Nor does it say why, if EVs are cost competitive, that only a tenth of incremental sales are electric over the next couple of decades.

It says that battery packs currently cost around $220 a kilowatt hour and sees this number falling to around $140 by 2035, while acknowledging the high degree of uncertainty about even the current numbers. Some will suggest that BP’s 2035 figures are already close to being achieved today. (GM was paying $145 a kilowatt hour for battery cells nearly eighteen months ago).

As with renewable electricity, I suspect we will see BP increasing its forecasts for EV sales as each new annual outlook appears. Nothing too dramatic each year but enough of an increase not to seem completely out of touch. But nothing in this year's Energy Outlook suggests that BP understands how the rapidly rising competitiveness of new energy sources will have self-reinforcing effects and increase the speed of the transition away from gas and, particularly, oil.

15 things to do to improve your climate impact

(This piece was commissioned by the Guardian to run during its 24 hour climate change blitz on 19th January 2017).

1, Air travel is usually the largest component of the carbon footprint of frequent flyers. After including the complicated effects on the high atmosphere, a single return flight from London to New York contributes almost a quarter of the average person’s annual emissions. Going by train or simply not taking as many flights is the easiest way of making a big difference.

2, Eating less meat, with particular emphasis on minimising meals containing beef and lamb, is the second most important change. Cow and sheep emit large quantities of methane, a powerful global warming gas, as well as contributing to climate change in several other ways. A fully vegan diet might make as much as a 20% difference to your overall carbon impact but simply cutting out beef will deliver a significant benefit on its own.

3, Home heating is next. Poorly insulated housing requires large quantities of energy to heat. Now that many people in colder countries have properly insulated their lofts and many have filled the cavity wall, the most important action you can take is to properly draft-proof the house, something you can do yourself. Those with solid brick or stone walls will also benefit from adding insulation, but the financial benefits are unlikely to cover the costs of doing the work.

4, Old gas and oil boilers can be massively wasteful.  Even if your current boiler is working well it’s worth thinking about a replacement if it is more than fifteen years old. Your fuel use may fall by a third or more, repaying the cost in lower fuel bills. 

5, The distance you drive matters. Reducing the mileage of the average new car from 15,000 to 10,000 miles a year will save over a tonne of CO2, about 15% of the average person’s footprint. Or, if car travel is vital, think about leasing an electric vehicle when your existing car comes to the end of its life. Taking into account the lower fuel costs, a battery car will save you money, particularly if you drive tens of thousands of miles a year. Even though the electricity to charge your car will be partly generated in a gas or coal power station, electric vehicles are so much more efficient that total CO2 emissions fall.  

6, But also bear in mind that the manufacture of the car may produce more emissions than it ever produces in its lifetime. Rather than buying a new electric vehicle, it may be better to keep your old car on the road for a bit longer by maintaining it properly and using it sparingly. The same is true for many other desirable items; the energy needed to make a new computer or phone is many times the amount used to power it over its lifetime. Apple says 80% of the carbon footprint of a new laptop comes from manufacturing and distribution, not use in the home.

7, LEDs. Within the last couple of years, a new type of light bulb called an LED (light emitting diode) has become cheap and effective. If you have any energy-guzzling halogen lights in your house - and many people have them in kitchens and bathrooms today – it makes good financial and carbon sense to replace as many as possible with their LED equivalents. All the main DIY outlets now have excellent ranges. And they should last at least 10 years, meaning you avoid the hassle of buying new halogen bulbs every few months. Not will your CO2 footprint fall, but because LEDs are so efficient you will also help reduce the need for national grids to turn on the most expensive and polluting power stations at the times of peak demand on winter evenings.

8, Home appliances. Want to really make a difference to your electricity consumption? Frequent use of a tumble dryer will be adding to your bills to an extent that may surprise you. But when buying a new appliance, don’t always assume that you will benefit financially from buying the one with the lowest level of energy consumption. There’s often a surprising premium to really efficient fridges or washing machines. 

9, Simply buying less stuff is a good route to lower emissions. A new woollen man’s suit may have a carbon impact equivalent to your home’s electricity use for a month. Even a single T-shirt may have caused emissions equal to two or three days’ typical power consumption. Buying fewer and better things has an important role to play.

10, The CO2 impact of goods and services is often strikingly different from what you’d expect. Mike Berners-Lee’s book ‘How Bad are Bananas’ takes an entertaining and well-informed look at what really matters. Bananas, for example, are fine because they are shipped by sea. But organic asparagus flown in from Peru is much more of a problem.

 

11, Invest in your own sources of renewable energy. Putting solar panels on the roof still usually makes financial sense, even after most countries have ceased to subsidise installation. Or buy shares in new cooperatively-owned wind, solar or hydro-electric plants that are looking for finance. The financial returns won’t be huge – perhaps 5% a year in the UK, for example - but the income is far better than leaving your money in a bank. 

12, Buy from companies supporting the switch to a low-carbon future. An increasing number of businesses are committed to 100% renewable energy. Unilever, the global consumer goods business, says its operations will be better than carbon-neutral by 2030. One its main competitors, Procter and Gamble, has much less specific plans and at the time of writing its UK web site has taken down its policy statement on climate change. Those of us concerned about climate change should direct our purchases towards the businesses acting most aggressively to reduce their climate impact. 

13, For a decade, investors ignored the movement that advocated the divestment of holdings in fossil fuel companies. The large fuel companies and electricity generation businesses were able to raise the many billions of new finance they needed. Now, by contrast, money managers are increasingly wary of backing the investment plans of oil companies and switching to renewable projects. And universities and activist investors around the world are selling their holdings in fossil fuels, making it more difficult for these companies to raise new money. Vocal support for those backing out of oil, gas and coal helps keep up the pressure. 

14, Politicians tend to do what their electorates want. The last major UK government survey showed that 82% of people supported the use of solar power, with only 4% opposed. A similar survey in the US showed an even larger percentage in favour. The levels of support for onshore wind aren’t much lower, either in the US or the UK. We need to actively communicate these high levels of approval to our representatives and point out that fossil fuel use is far less politically popular.

15, Buy gas and electricity from retailers who sell renewable power. This helps grow their businesses and improves their ability to provide cost-competitive fuels to us. Renewable natural gas is just coming on to the market in reasonable quantities in many countries and fossil-free electricity is widely available. Think about switching to a supplier that is working to provide 100% clean energy.

 

The first 'time of use' tariff in the UK. Will it save users money?

Any economist will tell you that prices will eventually align with underlying costs of a product or service. This is as true for electricity as it is for cars or nursing home care. But for domestic consumers today in most countries of the world, electricity is priced at levels removed from the underlying cost to provide it.

The most obvious example is the failure of domestic tariffs to rise in periods of peak demand. In an economically rational world, power prices should be highest in cold, dark countries in the early evening in winter. In hot places, by contrast, they might be highest at the same time in summer as air-conditioning is working its hardest. But electricity prices generally stay the same across the day.

Very gradually, new technologies such as smart meters are making it possible for electricity retailers to introduce ‘time of use’ (ToU) pricing for homes and small businesses, helping to bring prices closer to costs. (ToU often exists already for big users, albeit in a somewhat opaque form). In places such as Hawai’i and California time of use charges are well established. The UK’s first nationwide offer was launched last week, giving customers a 5p (6 US cents) per kWh tariff for seven overnight hours and a 25p (30 US cents) figure for 16.00 to 19.00 on weekdays. Intermediate times are priced at 12p.

For the average user, the new Green Energy UK pricing structure will probably save a little money compared to the cheapest tariffs from large electricity providers, even before the household adjusts its power consumption to move it out of peak use.[1] I worked this conclusion out using the invaluable data from Cambridge Architectural Research on hourly patterns of electricity use in British homes.

CAR’s data comes from live observations of real houses several years ago. Power use, particularly for lighting, has fallen since but I have nevertheless used their numbers without any decrease. This means that my calculations are about now about right for a house that uses about 20% more electricity than average.

Average UK household electricity consumption over the course of a day

Source: Cambridge Architectural Research, published at https://www.gov.uk/government/collections/household-electricity-survey, 2014

Source: Cambridge Architectural Research, published at https://www.gov.uk/government/collections/household-electricity-survey, 2014

Very roughly, a typical household taking the new Green Energy package will pay about £570 for electricity compared to about £580 for the Scottish Power tariff, the cheapest mainstream supplier at the moment. The difference is therefore small but the gap is widened if the household takes deliberate action to move its energy use out of the penal 3 hour weekday tariff between 16.00 and 19.00.

The CAR research suggests that the average home is using about 670 watts during peak time across the year. Cooking is the largest single element across the week at 121 watts, with audiovisual kit next at 92 watts.  Cold appliance and washing and drying machines follow at between 60 and 70 watt each. These power uses could clearly be pushed into adjoining time periods. Fridges, for example, can be automatically turned off for three hours with no impact on food quality. It should be easy to reduce typical demand by 150 watts in the peak period and this would increase the saving to around £25, making the Green Energy tariff probably the cheapest in the UK at the moment.

But, you may say, does it really make sense to save a little money in return for the hassle of having to manage the timing of electricity use? Probably not. But, in the longer term, ToU tariffs will also appeal to two categories of domestic households.

First, electric car owners are being offered a chance to do all their charging at just 5p a kilowatt hour at night. This compares to about 6p for other suppliers offering ‘Economy 7’ tariffs which offer low prices at night but higher prices at other times of day. Electric car users will almost certainly be better off using the new Green Energy rate.

The low night rate may also encourage the installation of domestic battery systems although payback times are still very long indeed. Power will be imported at night and then used during the day, including at peak time. This will save up to £300 a year for the typical medium-to-high user and more for a large house. To fully avoid daytime charges (either the standard rate or the peak fee), the battery system will need to store at least 12 kWh. This about matches the capacity of the Tesla Powerwall 2 (nominal 14 kWh, actual about 13 kWh) which has installed costs, including a separate inverter, of around £5,500-£6,000. It will be twenty years – longer than the likely life of the battery – before this cost is recouped.

A much smaller battery, sized simply to avoid all Green Energy’s peak charges between 16.00 and 19.00 on weekdays, is probably only a little better. A 2 kWh battery, such as the Maslow or an Aquion, might cost around £3,000 installed with an inverter and with timers to charge it during the night and discharge it at peak. The maximum saving here might be around £200 a year, implying a 15 year payback. As battery prices come down, the economics will improve.

What about the impact of a ToU tariff on households with solar panels? Perhaps 90% of the output of an array is likely to be in the period of intermediate prices in the Green Energy tariff. So the money saved by having PV is unlikely to be substantially greater than for households without solar.

Lastly, there is one thing that the wily customer should definitely do. Subscribe to the new Green Energy tariff for the summer months (when household peak usage is lower than in winter and therefore the impact of the penal 16.00 to 19.00 rates is less) and then switch back to conventional suppliers for the October to March period when peak needs are higher. Unfortunately, if too many people do this, the supplier will struggle to be profitable with its current prices. Let’s hope this doesn’t happen because in the long term it is in society’s interest that all electricity prices are tied to time of use. (To make the obvious point the reason for this is that ToU tariffs will help minimise the early evening peak in electricity demand and thus reduce the need for expensive and high carbon ‘peaker’ electricity generating plants).

[1] I compared the Green Energy tariffs with the lowest tariff I could find on a price comparison web site from a big supplier. This was Scottish Power’s March 2018 price.

BP – electric cars are coming but won’t impact our business.

BP’s chief economist, Spencer Dale, gave a speech earlier this month about the impact of electric cars on the demand for oil.[1] He suggested that BP’s forecasts for EV sales to 2035 implied that the demand for petrol will be largely unaffected. Very roughly, today’s passenger cars use about 19 million barrels a day of oil. This will rise sharply, says BP, on the back of increasing world car sales. The number of EVs on the road by 2035 will only cut the need for oil by 0.7 million barrels daily, or less than 4% of current demand. The impact of electric cars will be dwarfed by the increasing numbers of petrol and diesel cars.

As usual with Mr Dale, the logic is clear and persuasively stated. But look beneath the surface of BP’s bullishness about the resilience of oil demand, and some of its strange assumptions about EV become clearer. The internal inconsistencies and omissions should make us concerned that BP simply isn’t facing up to a somewhat uncomfortable reality.

Two immediate examples from the article that follows below: BP forecasts EV sales volumes rising to 6.2 million a year between 2025 and 2030 but then falling to less than half this level - 2.8m per annum - between 2030 and 2035. This may be what BP hopes will happen, but what can possible be the logic behind this collapse in EV sales over a five year period? We are left in the dark as to why BP thinks this is a reasonable view.

Briefly, a second point. Spencer Dale’s speech omits any mention of China whatsoever.[2] But this year China is responsible for half the world’s sales of EVs as the government starts to try to deal with its awful air pollution. Any proper forecast would include at least a view on the car market that is now easily the world’s largest. Not a word in his speech.

BP's forecasts for electric car sales

Let’s dissect a little of what Spencer says in more detail.

1.     BP says that the total number of EVs on the road today is about 1.2m. Actually, that number was reached at the end of last year. This year’s sales will be about 800,000, taking the total to around 2.0m (+- 0.1m).[3] As of today, therefore, Spencer underestimates the stock of global EVs by 40%. Frankly, this is not a good start for a forecast by a major international company.

2.     Sales in 2016 around the world are running at about 50-55% above 2015 figures after about 40-45% growth in 2015. Nowhere in Mr Dale’s speech does he mention this, or any other numbers suggesting the strong buoyancy – to say the least – of current production growth.

3.     BP forecasts 7 million electric cars on the road by 2020. That’s consistent with a 19% annual growth in sales volume over the next four years, a substantial fall from recent rates. Nowhere is this discussed. An impartial observer might query why sales growth will diminish sharply just as manufacturers reduce EV costs to around petrol equivalents.[4]

4.     It gets stranger. Between 2020 and 2025, sales growth speeds up again. It rises to 21% annually. And then it falls to 18% growth a year in the next five year period.

5.     And then the market starts to shrink. Having been over 6m cars a year, it falls to less than half, or 2.8 m units. No explanation, no comment, no analysis. Mr Dale needs to go back to his forecasting team and ask why a maturing product, with purchase costs probably below the equivalent petrol car, should see sales more than halve over a five year period. To put this in context, electric car sales in the BP world will capture about 1.5% of car sales in 2030-35, up from around 1% today. Really? What is the logic here?

Source; BP

Source; BP

Source: BP (There is a small inaccuracy here on my part.  Most of the cars sold in the next few years will disappear from the fleet by 2035. So this figure slightly underestimates sale because it excludes replacements).

Source: BP

(There is a small inaccuracy here on my part.  Most of the cars sold in the next few years will disappear from the fleet by 2035. So this figure slightly underestimates sale because it excludes replacements).

What doesn’t he say?

‘Economists don’t do cool’, says Spencer Dale as he admits that he cannot predict how consumer tastes will evolve over the next twenty years. This is a defensive statement, attempting to deflect some of the critical attention his speech will generate. I agree: economists are terrible at predicting how markets with a substantial cultural, technological or fashion element will evolve. (I partly know this because of my own early training in the dismal science). But this is no excuse for not at least mentioning some of the vital trends that are apparent even to us blinkered economists.

1.     Spencer Dale’s speech makes no mention whatsoever of the legislative plans around the world to block the sale of new internal combustion engine cars. Some of these plans may well not come to fruition. But Norway (2025), the Netherlands (also 2025), Germany (2030) are three examples of countries that state that they will ban non-electric car sales. Immeasurably more importantly, India is also contemplating a sales block, possibly as early as 2030 or before.[5] China may make a similar decision, not least because its manufacturers are now clearly the lowest cost producers and a large domestic market will provide a springboard for export sales.

2.     BP completely ignores the growing evidence of rapid EV development in light vans and buses. Spencer Dale says that only cars can be easily electrified at the moment. But, to give the most obvious example, La Poste in France and Deutsche Post in Germany are both making a transition to near-100% electric fleets for local deliveries. This is logical. Post vans have relatively short daily runs and usually return to a depot. The same argument holds for urban taxis and delivery vehicles. Buses are also moving to battery power as urban pollution becomes a central political issue. London is a good example as it moves to buy more electric buses. Purchase costs are sharply down and will cross diesel vehicle prices within a few years. Fuel costs are, of course, much lower and this is a more substantial element of bus running costs than a car.

3.     Mr Dale does admit that urban pollution issues may cause increased sales of EVs. But he then ducks any estimate of what the impact might be, saying that he will stick with the narrow focus on carbon emissions. London? Delhi? Shanghai? Are these cities really not going to do as much as they can to reduce mortality-inducing particulate pollution?

4.     EVs are particularly important because their battery capacity will be increasingly used to provide back-up power in a world of intermittent renewables. ‘Vehicle to grid’ charging – only just being rolled out by Nissan and others – is likely to become a crucial part of the grid stability armoury. A million 200 mile range cars (3% of the UK vehicle total) will provide about 7% of total daily demand in the UK if necessary. Of course we don’t know when this will happen, but there is strong economic logic to V2G and it deserves mention. Nothing at all from Mr Dale on the value of batteries.

5.     Nothing also about the likely evolution of electric car costs and battery prices. No excuse here, Mr Dale. Even geeky economists like us can do forecasts of what is likely to happen to vehicle costs as learning curve effects drive down prices. In a 20 page speech there really ought to be something about how costs are going to change. How can an international company like BP make a forecast for electric car sales without at least a superficial attempt to estimate how prices are going to change in relation to petrol vehicles?

6.     Spencer Dale admits that car sharing and autonomous vehicles may increase the speed of the transition to electric vehicles. But he ducks any estimate of the impact, essentially saying this is beyond his capacity. Instead, he uses the International Energy Agency high growth scenario for cars and posits this as the highest possible estimate for EV sales. Actually, those of us following the growth of renewables over the years know that the IEA is almost as slow as the oil companies in adjusting to the evolving reality. You only have to look at its consistent underestimate of the growth of solar PV to see this. (I cannot be sure but I also think there is an arithmetic mistake in how the impact on oil demand is calculated by BP).

7.     Even more obviously, what about battery costs? When battery costs fall to $150 / kWh (probably less than three years away, I guess) the initial costs of buying an EV will be less than a petrol car for a 200 mile range machine. At the point, therefore, not only only the sticker price will be lower, but maintenance costs will be better, insurance costs will be cheaper and, of course, fuel will be less.[6] Why would any sensible person not buy an electric car by this point? Mr Dale seems to recognise that EVs will eventually dominate, but refuses to examine the forces that will drive an increasing speed to any transition.


If you work in an oil company, you will usually be surrounded by people saying that the low carbon revolution will indeed happen, but not quite yet. Your forecasts therefore show an eventual takeover off fossil fuel markets by electricity in a couple of generations. But the slope of the downwards curve for fossil demand is slight, putting far into the future any real need to address the need to adjust your own company’s portfolio of activities.

As Mark Carney and Michael Bloomberg have said today in London, this may convince investors and lenders today but at some near point in the future these illusions will be sharply stripped away. Mr Dale’s speech is a perfect example of how BP and others are avoiding facing up to the risks of rapid and destructive change in their business. 

[1] http://www.bp.com/content/dam/bp/pdf/speeches/2016/back-to-the-future-electric-vehicles-and-oil-demand.pdf

[2] Except in one footnote like this.

[3] I believe that Jose Pontes, whose work is also widely published on cleantech websites such as CleanTechnica, is one of the best analysts of EV sales. http://www.ev-volumes.com/country/total-world-plug-in-vehicle-volumes/.

[4] VW is reported today as saying that its long range electric cars will be price competitive with diesel by 2020. https://chargedevs.com/newswire/volkswagen-says-it-will-offer-a-373-mile-ev-in-2020-at-the-price-of-a-diesel-golf/

[5] http://www.financialexpress.com/auto/news/govt-aims-to-make-india-a-100-electric-vehicle-nation-by-2030-heres-how/273629/

[6] In the spirit of curiosity, rather than a crude lusting after a desirable object, I visited the local BMW garage yesterday. I asked the EV salesperson about comparative costs. He gave me hard figures for annual servicing which were a fraction of petrol car servicing prices. And said that insurance costs are far lower because insurers recognise that EV drivers moderate their acceleration in order to maintain charge, thus reducing risks. He told me he had sold 120 cars this year, up from 60 EVs in 2015. He had only ever heard one complaint, and that was by a customer who bought a car with a defective battery in early 2015. Whatever the opposite is of a 'lemon', the BMW i3 appears to it. Mr Dale might also visit a BMW dealership to good effect. 6% of BMW's current US sales are electric. 

 

Solar panels now pay back the energy used to make them in little more than a year

How much electricity do we get back from the large amounts of energy invested in making solar panels? An impressively detailed paper from researchers at the University of Utrecht provides some answers to this crucial question. In short, conventional PV modules made next year will achieve ‘energy payback’ in not much more than a year.

Some of the press commentary on the new article in Nature Communications focuses on this benign impact of solar and the scope for continuing improvements in energy use. Other writers took a very different tack. Instead of focusing on the rapid payback on the energy invested in the manufacturing processes of today, the journalists chose to concentrate on the much higher inputs in the past. This makes solar look less good. The headline on Ben Webster’s article in the London Times was ‘Solar panels less green than you think, say experts’. An anti-renewables US website’s headline was ‘Solar power actually made global warming worse, says new study’.

One of the aims of the Utrecht paper was to give us an estimate of when the annual global expenditure of energy on making panels fell below the amount of electricity produced by all the solar PV ever previously made. This calculation showed that the extremely rapid growth rate of solar, combined with the previously huge energy costs of making PV, meant that it wasn’t until about 2011 that solar PV ceased to be in overall yearly energy and carbon debt. The Times article got very confused about this point, implying that this meant that an individual panel made early than this date didn’t typically generate enough electricity to pay back the energy invested in making it. No, the Utrecht conclusion was that in any individual year until about 2011 the manufacturing energy use of the whole PV industry was greater than the electricity output of panels already on roofs and in fields. This is a very different point.

 The ‘energy return on energy invested’ debate for PV continues to rage. Those, like me, who believe solar will become the dominant world energy source at some not-to-distant point tend to believe panels to pay back their energy reasonably quickly. If, at the other extreme, you are deeply sceptical of renewables and want fossil fuels such as coal to provide most power, then proving solar PV is energy efficient assumes great importance. UK journalists such as Matt Ridley sit firmly in the camp of fossil fuel advocacy and voice the view that panels installed in the UK, for example, never pay back their embodied energy.

Mr Ridley can call on just one recent academic paper to support his view. This particular piece of research suggested a very long payback time indeed for panels installed in high latitudes. One of the reasons that the Utrecht work is so important is that it summarises all the research on energy payback, including 40 separate assessments of the energy payback on solar manufacturing. 39 of these assessments show very different figures indeed to those supported by Matt Ridley.

Q+A

More generally, I wanted to get the some of the many additional Utrecht conclusions into the public arena. So I wrote to the lead authors Atse Louwen and Professor Wilfried van Sark to ask five specific questions on issues not directly reported in the study but which can inferred from their work.

The full Q+A follows. It is unamended by me (except to add a brief explanation of some technical terms). Many thanks indeed to Atse and Wilfried for the extraordinarily rapid and full response. (By the way, I think they are being very cautious in their assessment of how much electricity that the average solar panel generates in the course of year. This makes their assessment conservative.  Payback is probably faster than they say). 

1.       Please would you tell me approximately how much energy it typically takes to make 1 megawatt (peak) of solar modules today? And roughly how much did it take 5 and 10 years ago? 

Today, according to the experience curve we used, it would take for production of 1 megawatt-peak of average (~40% mono, ~60% poly) solar PV systems (so modules and inverters, installation, mounting structure) roughly 18.4 TJ of primary energy. Considering the locations of this installed capacity the average yield of 1 MW globally would be conservatively estimated to be 1200 kWh/kWp. This would correspond to an energy payback time of ~1.4 years. 5 years ago the figures would have been 25.9 TJ/MW (EPBT of ~2.0 years).10 years ago this would have been 36.9 TJ/MW (EPBT of ~2.8 years)

(My note: EPBPT is ‘energy payback time’, TJ is ‘terajoule’. 1 TJ is equal to about 278 megawatt hours).

2.       How long will it typically take a polycrystalline panel made on 1st January 2017 (and installed on the same date) to generate enough electricity to repay the energy used in its manufacture?

A complete PV system based on polycrystalline panels, made in 2017, would need 15.8 MJ of primary energy per watt-peak. This corresponds to an EPBT of roughly 1.2 years (for global average yield)

3, Solar PV production has historically grown at 45% a year over the last decades, according to your estimates. If growth were to continue at this rate, and the reductions in the energy required in manufacture of silicon panels also falls at the same pace as they have done historically, when would a panel made on 1st January 2020 reach ‘energy payback’? Perhaps 45% is too high a figure to use for future growth rates; when would the energy payback be on a panel made on 1st January 2020 be if future growth runs at just 20% a year?

Indeed over the period 1975-2015 the average annual growth rate (or CAGR, compound annual growth rate) was indeed 45%, but the last years this figure has already been a little bit lower, slightly below 30%. Forecasts are again a bit lower, we guess 20% would be a decent estimate. In our study we use projections for future development of capacity that are around 20% (slightly lower). With this in mind, an average PV system in 2020, in our model, would have an energy demand of 16.7 MJ per watt-peak, corresponding to an EPBT of about 1.3 years. Note this is higher than for a poly panel in 2017, as the share of mono systems is increasing and these have a slightly higher energy demand for production.

 4.       In their comments on your research, some journalists have focused on one aspect of your work. They quote your conclusion that in the ‘Increasing PR (performance ratio) scenario, (energy) debt was likely already repaid in 2011 for both CED (energy) and GHG emissions’ In other words, they say, until 2011 solar panels had a net adverse effect on carbon in the atmosphere. Your conclusion seems to arise because solar PV has been growing so rapidly that in any single year energy use in module manufacturing would have exceeded the total electricity generation of all previously produced modules. Are you able to confirm that if, say, PV had only grown at 20% per annum, then net energy debt would have been repaid earlier than 2011? In other words that it is precisely the very high rate of growth in PV that means energy debt increased until 2011?

This probably true indeed, but if solar growth would have been lower, then the reduction in EPBT would also have been lower, as it is a result of experience during production and as such is a function of the cumulative production of PV capacity. However, generally speaking, net energy is consumed when growth rates are larger than (1/PBT). As growth rates were in the past on average 45%, sometimes higher, and EPBT has dropped below (1/0.45 = 2.2 years) only recently, it is likely that if growth rates were constrained to 20% the break-even point would have occurred sooner. 

However, in terms of experience curves, the investments you need to make (in this case in terms of energy and GHG emissions) to bring the technology down to a certain environmental “cost” level, are always more or less the same, whether you take 20 or 40 years to make these investments. So the faster growth and temporary adverse effects now result in a faster increase of the positive effect, so to say. 

5.       Lastly, on the basis of the literature search you carried out during the research for your article, what do think is the current ‘Energy Return on Energy Invested’ (ERoEI) of a polycrystalline panel?

The ERoEI of a global average polycrystalline based system would according to our figures be about 19.8. For NW Europe, taking our home town Utrecht as an example with an estimated annual yield of 875 kWh/kWp (which is an average, actual yield for the Netherlands that my colleagues measured using data from thousands of PV systems), this would be 15.2. 

This ERoEI has been debated, also recently, even to the point were critics state that the ERoEI of systems in N Europe is smaller than 1.0. According to everything we have seen in literature and in our own research, this is just not true. A recent example of a study that states this ERoEI to be smaller than 1 is that by Ferroni and Hopkirk in Energy Policy  but upon review of this study we, and many researchers in the field, found that the authors severely overestimate the energy required to produce PV systems, and underestimate their electricity yield, among other issues with this paper. A rebuttal paper written by a large number of colleagues (not us) in the field has already been submitted to the journal, which we hope will be published soon. 

(My note: The Ferroni and Hopkirk paper is the one always cited by anti-renewables commentators).

Several readers have pointed out that the Utrecht paper uses estimates of production energy that suggest a much longer energy payback than the authors propose. My reasoning as to why I think the Utrecht paper is nevertheless correct is appended as responses to these comments below. Thank you to the commenters for raising this issue, which I should have spotted myself.

The time needed for Energy Transitions

Summary

The standard view is that the switch to an energy system based on renewables will take at least half a century.

This opinion is largely derived from Professor Vaclav Smil's work on previous transitions from one fuel to another. We have all gone on to assume that the future will be like the past.

In contrast, I argue that the growth of solar PV, in particular, will not be restrained by the forces that held back new fuels in the past. Of course, nobody actually knows how rapid the growth of renewables will be but my purpose in this note is to suggest that Smil's view may be incomplete and that solar and wind will continue to grow at far faster rates than he suggests are possible.

The time needed for energy transitions

Energy transitions from one fuel to another are thought to be inevitably slow. As a result, everybody - but particularly those in the fossil fuel industry - says that the move to near-100% renewables is going to take at least a couple of generations. If true, the world is heading for more than 4 degrees of warming.

Can we make the transition happen faster? In this paper I try to make the case that the conventional wisdom may be wrong and the switch could take place far faster than the previous moves from wood to coal, coal to oil or oil to gas.

Readers of my book, The Switchhave written expressing surprise at my optimism. This long note is attempt to respond to these criticisms. I apologise for the length.

The widespread view that the transfer between one fuel and another takes over 50 years is almost exclusively derived from the one work of one man: Vaclav Smil, now a retired university professor from Manitoba, Canada. Smil is the doyen of energy historians, a very small group of people who have looked carefully at how the source of our fuels has changed over the centuries.

Professor Vaclav Smil, www.vaclavsmil.org

Professor Vaclav Smil, www.vaclavsmil.org

 

His well-researched and simple charts show how coal replaced wood, then oil pushed out coal and finally gas rises to importance. These graphs merge data from all the countries around the world to show how global shifts took a very long time. [1]

Smil’s work - academically rigorous and highly researched – is very rarely challenged. His view has become almost untouchable, perhaps partly because Bill Gates refers to it frequently and with obvious reverence. And over the years Smil's work has been aided by his attacks on some very easy targets: the renewables enthusiasts who have hailed the dawn of a fully low carbon era some decades too soon. Their premature announcements of the end of the fossil fuel era have made Smil's scepticism seem very sensible. I suspect another reason may also be that many powerful companies and institutions need Smil to be correct about the time taken for transitions. As the eventual inevitability of a 100% low carbon world becomes more and more obvious, those with an interest in prolonging the fossil fuel era hold on to the Smil hypothesis, much as a toddler keeps a comfort blanket by his side.

Today, even oil companies admit that the future will eventually be dominated by solar (for example, Ben van Beurden, the CEO of Shell during autumn 2015) but also say that the transition will take many decades.[2] Fund managers heavily reliant on the dividend stream from fossil fuel businesses similarly secretly wish for a slow shift. Indeed, many of us have a tendency to reject the possibility that the transition to renewables will be quicker, more disruptive and painful than the smooth and continuous - but nevertheless slow - growth shown in Smil’s unthreatening charts. Smil himself is openly sceptical about the rate of future growth of renewables and his many followers often quote his words.[3]

…’even a greatly accelerated shift towards renewables would not be able to relegate fossil fuels to minority contributors to the global energy supply anytime soon, certainly not by 2050’

Put at its simplest, the Smil view is that the maximum rate of global growth over the longer term of a newly arrived energy source is about 9% a year. In the world of the 20th century - in which energy demand was rising an average of 3% annually - this takes a fuel’s share from 5% to 40% in fifty years. The conventional wisdom is that solar, wind and other renewables are inevitably bound by the same rule. Growth is capped at 9% per year by the same forces that held down coal, oil and gas increases.

In the past half century, the growth rate of solar PV has averaged about 40% per year. If yearly increases stay at the same rate, PV alone would take its share of global energy supply from about 0.3% today to 50% in about 16 years. This is the wonderful effect of rapid compound interest. Wind has also grown rapidly, and together with PV possesses the capacity to push global energy to be predominantly renewable in little more than a decade.

Very few people believe this will happen. And the majority opinion may well be right about the need for at least a half century to pass for a new energy source to become dominant. Nevertheless, I want to test the case; is the evidence against the possibility of a more rapid renewables transition quite as clear as Smil and his followers suggest?

We have three main lines of attack against the prevailing pessimism.

1)    Smil’s numbers refer to the world as a whole. He tracks, for example, oil’s share of global fuel use and says that it rose from 5% in 1915 to about 23% in 1965. But fossil fuels are unequally geographically distributed and supply took time to diffuse across the globe. If we look at changes in individual countries, the pattern is very different. Growth in the use of particular fuels has often been strikingly fast and far quicker than Smil asserts is possible. The growth of renewables can be far more geographically coordinated because both PV and wind are available in far more countries than oil, coal or gas. In fact they are almost universal. No other fuel is.

2)    In the past, energy switches happened slowly because industries had to build new infrastructures and invest in large amounts of extra capital equipment to enable the new energy source to be useful. The rapid growth of oil, for example, only happened when mankind had developed the internal combustion engine and set up businesses as diverse as car assembly and tyre production. The requirement to change the whole system in order to exploit a new source of energy inevitably slows the transition down. Will the world need to invest similarly in huge and expensive supporting infrastructure to exploit renewables?

3)    The growth of fossil energy sources may have been held back because of high costs. Renewables have certainly been more expensive in most parts of the world until the last few years. Will the continued downward shift in solar and wind costs enhance the rate of transition, simply because renewables are cheaper than the alternatives, either now or imminently?

Line of attack against lethargic transitions 1.

Might the growth of energy technologies be quicker than the conventional view says is possible?

Coal was the dominant source of energy in the UK as early as 1700.[4] That is, even before the beginning of the industrial revolution it produced more kilowatt hours of energy than wood, wind, draught animals and human food taken together. Put at its simplest, it was picked off the beaches near Newcastle (north-east England), shipped to cities such as London for heating homes and, soon after, to Cornwall to feed the steam engines used to pump water from mines. Most other places around the world didn’t have abundant near-surface coal and were far more reliant on wood. It took the development of underground mines, canals and railways to spread the use of coal as an energy source around the world.

As the Smil charts show above, it wasn’t until 1840 that coal was 5% of global energy supply (and a large fraction of that 5% was actually consumed in the UK, then the only fully industrial country in the world).  By that time, coal was already just under 90% of total energy supply in the UK, and its scope for further growth in its share was inevitably minimal. Simply as a matter of arithmetic, this slowed down the measured rate of increase in coal’s global penetration. So it is unsurprising that Smil’s global coal transition came much less rapidly than it actually occurred in individual countries.

A similar process can be seen in the case of oil. The chart below shows the share of oil in the energy mix of the US and the UK between 1950 and 1980.[5] The US percentage barely changes in the period at around 40-45%. Oil was produced in large volumes in the US and it was already relatively cheap. In 1950 the UK was short of foreign exchange and only about 10% of its energy need came from imported oil.

As the economic circumstances improved, the share of oil rose very rapidly, reaching a higher share than the US by 1970, only twenty years later. (North Sea oil was not discovered until 1969). The UK’s transition to oil was far faster than suggested by the Smil hypothesis and it pushed coal from 85% of the energy mix down to less than 50% by 1970. What Smil says took 60 years globally (5-40% in the case of oil) took 20 years (11-45%) in the UK.

To make the point in a slightly different way, the transitions to both coal and to oil occurred in one or two large countries much earlier than the rest of the world. The share of oil or coal in these markets was already high by the time the wider upsurge in fuel use began, largely because these countries were endowed with easily extractable oil and gas. That means that the share was already so high that it couldn’t rise much further. This – purely as a result of arithmetic – will always depress the apparent global rate of growth.

Let’s briefly look at another example of the distorting impact of looking at the world as a whole rather than studying individual countries or regions. World coal use rose about 2.5% a year between 1980 and 2012, approximately the same as global GDP growth. Coal’s share of world energy use remained roughly constant. However that stability disguised a divergence between a virtually static market for coal in OECD countries and 4% annual growth in non-OECD economies. More specifically, China’s coal use almost tripled between 2000 and 2013, growing almost 10% a year. The country now burns half the tonnage mined worldwide and almost two thirds of its primary energy comes from coal.[7]

Natural gas provides more examples. Before large scale liquefied gas transport started in the 1990’s, international trade was limited. Some pipelines ran from Russia to European and to near-Eastern countries but most natural gas was consumed in the country where it was produced. Those places without gas tended to see a small proportion of their energy needs met by this fuel. This is a large part of the reason why gas took 40 years to move from 5% of global energy supply in 1930 to 20% in 1970.

But the pattern in individual countries that did have easy access to natural gas is often very different. The chart below is extracted from a book about the growth of natural gas in the Netherlands. In 1959, the Dutch discovered a huge gas field in the north of the country, near Groningen.[8] It produced large volumes of gas at a low cost. Use of the fuel was limited until about 1965 but within 10 years gas was responsible for over 50% of the total Netherlands energy supply.

                                   Composition of Netherlands energy supply 1960 to 2000

In the UK, the arrival of North Sea gas in the late 1960’s also produced a rapid rise in the share taken by this fuel. From 1% of total energy use in 1969, the UK moved to 18% derived from gas only 10 years later. This wasn’t a full ‘energy transition’ but it was far faster than the conventional view says is possible.

Those figures are energy as a whole, covering the decade of the 1970s. Gas saw another burst of growth two decades later as power generation was swiftly switched from coal in what was known as ‘the dash for gas’. This took the fuel’s share of electricity production from nothing in 1991 to 38% ten years later and, coincidentally, meant that gas also provided 38% of all energy use by the turn of the millennium. This was the full transition – gas moved from insignificance in 1970 to well over a third of all fuel use thirty years later. The UK is a large country and shifted far more rapidly to a new source of energy than now seems to be thought possible.

France saw a similarly rapid switch as it brought nuclear power into play around 1980. Less than fifteen years later, nuclear electricity represented over 35% of total national energy demand.[9] This had, of course, required huge capital investment in building reactors around France.

Line of attack against lethargic transitions 2

The clean energy transition will not be held back by the need to build new infrastructure

I am going to assert two things. First, that previous energy transitions were slow in part because each fuel only became fully valuable after a network of infrastructure and machines was developed to exploit the energy it contained. Second, by contrast, the clean energy revolution does not require much additional complementary investment. Solar PV and wind supply electricity, and the capital investment to use this energy source is already in place in the form of transmission and distribution line. Similarly, batteries can be simply plugged in to the electricity system. Long-term storage - which will be needed in huge amounts in high latitude countries - can be provided by ‘green’ natural gas and liquid fuels, which will be created using renewable energy. This energy can be stored in the existing gas and oil infrastructures.

How did the unavailability of complementary infrastructure slow previous transitions? Countries, continents and the world swing from one fuel to another because the rising energy source is either cheaper or more convenient, or both. But the switch isn’t instantaneous because the new fuel usually requires huge investment in finding and extraction. Then a further prolonged burst of capital spending is required to provide the machines to use the new source of power and build the support infrastructure, such as pipelines and storage tanks, to use that energy.

The best known early example, of course, is the transportation of coal in the United Kingdom. Before the advent of canals, the price of coal in cities was pushed up by high transport costs. In the classic anecdote of the Industrial Revolution, the opening of the Bridgewater canal in 1764 halved the price of coal in Manchester within months (although I have to admit that my attempts to find hard information to support this story have failed). Without transport links, energy transportation of fuels is expensive and this has delayed the growth of all alternative energy sources since the beginning of the coal transition.

It is also important that machines are available to productively utilise the new fuel. For coal to be useful to industry, engineers also had to develop machines which turned energy into motion. Newcomen’s steam engines of the 1720s began the process but it wasn’t until the work of James Watt sixty years later that coal began to be turned into useful power with reasonable efficiency.

Similarly, oil needed to be refined before it could be used as a transport fuel, which eventually replaced kerosene for lamps and heat as its dominant end use. It also required vehicles to use the gasoline produced. The internal combustion engine can be said to have been developed (in France) about the same time as the first wells were drilled in the US in the early 1870s. But in 1900, forty years later, there were said to be only about 8,000 cars in the US, and more of these were battery-powered than used internal combustion engines.[10] The relatively slow diffusion of cars held up the transition to oil. They were expensive and unreliable. Mrs Ford continued to drive her favourite electric car even after her husband had started producing the Model T in 1908. In the decade from 1900, car sales grew sharply and by 1910, there were about half a million on US roads. Four years later there were 1.7 million.[11] Unsurprisingly, US oil production quadrupled in the period.

So even in the US, blessed in the early years by easy-to-extract crude oil, took time to fully use the resource because the machines to combust the fuel took time to develop. In fact it wasn’t until 1950 that oil overtook coal as the single most important fuel source in the US, eighty years after the first well was drilled.[12]

Oil’s rise around the world was held back by the need to invest in refineries to produce motor fuel, large farms of oil tanks to store the petrol and diesel, garages to sell cars and retail the fuels and, of course, cars to use the fuel. It is no wonder that the transition took decades across the globe.

Countries which discovered big gas fields sometimes exploited the new source very rapidly. The Groningen field mentioned above enabled The Netherlands to get natural gas out to the bulk of the population remarkably quickly. Even still, this was not a simple process. Most urban areas had a gas works that made ‘town gas’ from coal and pipes that carried the fuel to homes. So it might be thought that all the suppliers had to do was to switch from the coal gas, made in town gas works, to the new source. In actual fact, a new long distance grid had to be built and every single cooking stove, hot water boiler and heating appliance was adjusted or replaced. (I am not quite sure of the reason for this but I suspect it was to do with the low calorific value of Groningen gas, which contained large amounts of nitrogen).

The photograph below shows the conversion workshop at the Feijenoord Municipal Gas plant. Fitters are replacing components of domestic cooking stoves. This was not a simple transition but it still occurred remarkably quickly.

                                          Fitters at a gas plant in the Netherlands in about 1960

The economic benefit of natural gas in the Netherlands was substantial and the resource was exploited very rapidly indeed, providing 50% of the country’s energy within 10 years. This was achieved even though the transition was complex and involved real costs and dislocations. For example, people lost their kitchen cooker for a few days while the burners were replaced. No similar obstruction stops solar and wind energy replacing coal and gas as the source of electricity.

Smil himself notes the extraordinarily fast transition to natural gas in the Netherlands. However also he wrote that ‘only small economies endowed with suitable resources can undergo very rapid resource transitions’.[13] He appears to be admitting that the Groningen field was so large that it made possible a switch for the entire economy. It’s worth mentioning that the sun is delivering 6000 times as much free energy at this moment as the world needs. Everywhere with decent sunshine – and that means at the very least 80% of the world’s population - has the ‘suitable resources’ that Smil says are the precondition for a fast transition.

Even Professor Smil would not argue that the UK is a ‘small economy’. In the latter part of the 20th century, it was responsible for between two and three percent of the world economy. But the rise of North Sea gas in the decade after 1969 from 1% to 18% of total energy use occurred despite the large changes to infrastructure that were needed. As in the Netherlands, the discovery of accessible fields brought about the rapid development of a long distance pipeline network and a similar adjustment to each and every gas appliance in the country, in this case carried out gas fitters employed by the nationalised gas supplier in the home. (One of my earliest memories is standing in the doorway of my grandfather’s kitchen watching a couple of rather oil-stained individuals remove parts of his cooker, replacing them carefully a few minutes later).

The point is this: past transitions were made complicated by the need to develop distribution systems and invest billions in the machines and appliances that used the fuel. This isn’t the case with solar and wind. They tap into an existing architecture of distribution and the purchasers of electricity need no new appliances to cope with solar-generated power. This makes a faster global transition far easier to accomplish than the rise of coal, oil or gas.

Of course solar and wind electricity do have different characteristics to electricity from gas. As sources of energy they are unreliable and highly variable. The electricity system therefore needs to put capital into devices that help us deal with the intermittency of renewable power. This both means storage batteries and, as importantly, computer-based technology that manages energy demand so that it aligns with available supply (usually now called ‘demand response’). But the investment required is a fraction of what the UK and the Netherlands needed to bring gas to the bulk of the population within a few years.

Although most transport and domestic heat supply will be fully electrified, the UK and other high-latitude countries also need to provide renewable gas and oil. These ‘green’ fuels will be manufactured by upgrading carbon dioxide to gases and liquid fuels using large amounts of energy, almost certainly in the form of renewable electricity. We will need chemical industry infrastructure to carry out the transformations from simple to more complex and energy-rich molecules but the cost of this will be a small fraction of the capital requirements for generating the electricity in the first place.

Line of attack against lethargic transitions 3

The price of low carbon energy

The UK – with poor sun but good wind – has just published estimates of the current cost of renewables compared with electricity generated by natural gas. Perhaps surprisingly, the government thinks that the costs are broadly comparable, even at the currently low wholesale price of gas. (However, the gas costs do include a figure for the price of carbon).

For projects completing in 2020, electricity generated by gas is seen by the UK as costing £66 per megawatt hour. (This includes £19 of carbon costs but also assumes an extremely optimistic 93% utilisation rate. The real utilisation rate is unlikely to be more than 80% for mid-ranking plants). Large scale PV is put at £67 and wind at £63.  At a 3.5% real interest rate (probably about today’s actual cost of capital), the figure falls to £53 for PV and £49 for onshore wind.

The UK is a relatively cheap place to generate electricity from gas and expensive for solar, because of poor insolation levels. It ought to be inexpensive to construct and operate wind turbines here but restrictions on size, planning constraints and grid connection costs have raised the price to well above other countries.

Nevertheless, UK renewables are now no longer more expensive than gas-powered electricity for projects now in early planning.

In other countries, usually with more expensive gas (with the exception of the US) and better solar radiation, PV is often already significantly cheaper. Some recent auction prices have seen PV at less than 3 US cents per kilowatt hour, or $30 per megawatt hour. These prices are lower than the fuel cost alone for the gas burnt in a combined cycle gas turbine (CCGT). Solar PV is already the low-cost way of generating electricity in large parts of the world, both in the form of large fields of panels and in tiny installations in towns and villages without electricity.

PV continues to fall in price, with no end in sight. Benefiting from a steep learning curve, PV will the lowest cost way of generating electricity almost everywhere around the world within a decade. Wind is also getting cheaper by the month, although the rate of decline is not as great as solar.

The argument that the energy transition to non-fossil fuel sources will inevitably be a half century long because there is no financial benefit to the use of renewables is wrong.

Conclusion

The conventional wisdom remains that the next energy transition will take as long as previous shifts. Even though many countries have committed to deep and rapid decarbonisation, no-one quite believes their plans. The comfortable view that PV (and wind) will copy the slow rate of growth of gas and oil continues to be dominant.

I’ve tried to suggest that the standard view of the slow transition may be flawed. Switches in individual countries have been far faster in the past than the simple global numbers would suggest. These rapid transitions have often been fuelled by low cost local sources of energy. Solar energy is global and so provides the raw fuel for a swift move to a new dominant energy source.

Solar, wind and other renewables require no new infrastructure. They simply supply into the existing electricity network. However, the need for storage, or ‘dispatchable’ alternatives to wind and PV, does increase capital requirements for the transition.

Wind and, particularly, solar are now as cheap, or cheaper, than the fossil alternatives. There is therefore a strong financial incentive to roll out more PV in many parts of the world. This incentive will not reduce at any point in the future. Wind and PV are getting cheaper month by month while fossil fuels are tending to get more expensive to extract.

No-one knows how the changes to the energy system will unfold. But the notion that transitions from one fuel to another inevitably take a half century or so is likely to be wrong. As Paul Dodds, an academic at University College, London, says [14]

Technological revolutions can be implemented very quickly when there is a clear business case and benefit – publically and privately. Transitions are very slow when there isn’t.

Even in as tiny an academic discipline as energy history, there are people who dispute Smil’s confident but pessimistic assertions. Paul Warde, a Cambridge historian, is a younger upstart questioning the prevailing view that transitions have a predictable and almost mechanically determined path. In a recent oral presentation on Vimeo he goes on to suggest that the dead hand of conventional wisdom on changes in energy supply may be reinforced by the reluctance of people in the energy industry to change their public positions on the future of supply and demand. [15]

Did people get things right? Unfortunately, the fact is that most of the long-term energy predictions that we have ever made are wrong, and frequently they’re quite badly wrong.

…Either as people or institutions, people tend to get wedded to a particular model of prediction…There are big career implications from abandoning a position that you have strongly taken.

It may be time to start more actively questioning the prevailing wisdom on energy supply and, as Warde suggests, allow a little more intellectual flexibility into our thinking. The growth of all new products, energy or otherwise, is faster than a century ago as diffusion becomes easier and cheaper.

How long did it take to get the mobile phone to almost universality in the world? In 2000, there were about 740 million phones in the world, or one for every nine people.[16] Now there are more than 10 times as many. Global internet penetration grew from 6% to 43% in the same period. And these are not insignificant industries. The mobile phone market is now almost as big as the world’s energy business at over 4% of the global economy.

As the analyst Kingsmill Bond has shown in a recent paper, renewable sources have been growing several times as fast as other fuels at the same stage in their development cycle. 

                            Growth after a fuel reached 10 mtoe (million tonnes of oil equivalent) 

Perhaps we need to ask whether the fossil fuel industries are telling us that the transition will be slow simply because they want to stay longer in their current business, rather than facing the pain of building a new strategy in a world of zero carbon fuels.

 

 

 

 

 

 

 

[1] JP Morgan Asset Management, The Arc of History, using data from Vaclav Smil, Scientific American 2014: https://www.scientificamerican.com/article/a-global-transition-to-renewable-energy-will-take-many-decades/

[2] http://www.bbc.co.uk/news/business-34274352

[3] Vaclav Smil quoted in Daniel Yergin’s short paper from IHS Do Investments in Oil and Gas constitute systematic risk?’, October 2016

 

[4] The information on the early dominance of coal in the UK is taken from Dr Paul Warde’s masterly analysis of British energy history in his long paper entitled Energy Consumption in England and Wales 1560-2000 (Naples: CNR, 2007).

[5] http://www.eia.gov/totalenergy/data/monthly/pdf/sec1_7.pdf. The data on the UK’s use of oil is taken from Warde op. cit.

[6]

[7] https://www.ief.org/_resources/files/snippets/chinese-academy-of-social-sciences-cass/world-energy-china-outlook-interim-report.pdf

[8] Natural Gas in the Netherlands: From Cooperation to Competition, Aad Correljé et al, Orange-Nassau Group, Amsterdam, 2003

[9] http://euanmearns.com/energiewende-germany-uk-france-and-spain/ Figure 11

[10] http://news.thomasnet.com/imt/2003/01/17/how_oil_refinin

[11] http://www.carhistory4u.com/the-last-100-years/car-production

[12] http://www.eia.gov/todayinenergy/detail.php?id=10

[13] http://www.vaclavsmil.com/wp-content/uploads/WEF_EN_IndustryVision-12.pdf?emailid=5655d14ccb56e60fc6447e23&segmentId=7e94968a-a618-c46d-4d8b-6e2655e68320

[14] https://www.bartlett.ucl.ac.uk/energy/docs/dodds-presentation-slides

[15] . (https://vimeo.com/185466482) I may have mistranscribed some individual words

[16] https://www.itu.int/en/ITU-D/Statistics/Documents/facts/ICTFactsFigures2015.pdf

[17] http://www.gsma.com/mobileeconomy/

Wind and PV comparable in cost to gas generation in the UK

The government says that onshore wind is already the cheapest electricity generation technology in the UK. Towards the end of a long and impressively transparent report on the costs of generating power, BEIS says that wind came in at £62 per megawatt hour in 2015 compared to £66 for gas-fired generation. Solar wasn’t much higher at around £80.

The commercial viability of renewables will get improve while the cost of fossil fuel electricity will tend to rise, says BEIS. By 2020, large scale solar will be at £67 per MWh, almost the same as gas. Onshore wind (very surprisingly) is said to cost slightly more than 2015 at £63 per MWh. In 2025, a new gas plant will produce power at £82 a MWh, including a substantial carbon charge, while PV and wind have fallen to little more than £60. Even ignoring the cost ascribed to CO2 emissions in the calculations, gas and its two low-carbon competitors are almost evenly matched by 2025. Even in straight cash terms, solar and wind on particularly good sites will beat gas within a few years.

Perhaps as importantly as the figures for utility scale solar farms exporting into the grid, BEIS shows that large rooftop installations on warehouses and factories produce power by 2020 at £73/MWh, much less than most businesses are paying for grid electricity today. This is, I think, the first statement that PV will soon reach ‘grid parity’ for large arrays on commercial buildings, and may be at this point already.

The reasons for BEIS’s conversion to the fundamentally attractive economics of UK renewables are two-fold. First, the Department has moved to more reasonable assessments of the underlying capital costs of PV and wind. It should be complimented on the openness with which it discusses past failures to keep up with the decline in the PV prices. Every single government and supra-national body around the world has made the same mistake but BEIS has now been more transparent than all its peers.

The second point is that BEIS is at long last acknowledging one of the key advantages of PV and wind: they require far lower rates of return than other technologies. Investors are happy with the low risk of generating assets that cost nothing to operate and the returns they now demand reflect this preference for wind and solar over gas and other plants.

Nevertheless, it can still be very strongly argued that BEIS’s assumptions are biased against wind and, particularly, solar.

·      Commercial large scale PV sites in the UK do not have 11% capacity factors. These farms are generally capable of generating at least 10% more than this. (A colleague sent me data today suggesting his portfolio of Cornish solar farms actually manage more than 13%). A 10% underestimate of yield means a 10% overestimate of the cost of producing power from solar.

·      BEIS assumes that solar farms in 2020 will be paying capital costs of £1,000 per kilowatt. This is a mistake. The actual cost today is no more than about £800 in most locations. It will be less by 2020. Because a solar farm is, in effect, cost free to operate, the implicit price for generating electricity is entirely geared to capital costs. We can make another near-£20 reduction here.

·      The final unfavourable assumption is the cost of capital for PV developments. BEIS says this is 6.5% before inflation for PV, the lowest of all generation technologies and 8.5% after assumed inflation of 2%. This seems slightly high. A large farm built by a solid developer will be able to attract debt finance at little more than 3% real and I doubt that the returns to shareholders need to be more than 7% nominal. Weighting these two suggests a figure of about 5-5.5% real is a perfectly reasonable assumption today. Once again this change would significantly reduce PV’s implicit costs.

·      On the other side, the costs of CCGT generation are understated. A plant built in 2020 will not work 93% of the hours in the year (excluding outages). On a sunny, and windy summer day in 2020 even a new CCGT that is cheapest to operate will not be working.  Turbines, nuclear and PV will provide all the power that is needed. A better estimate might 75% or so. (Older and less efficient plants will work far less than this). This means that the capital cost and the running expenditures of the power station will need to be spread over a lower level of output, raising the implicit cost of production.

 

All new substantial generating capacity now needs some form of subsidy or price support to operate. Today’s wholesale prices come nowhere close to covering the underlying costs of new generating capacity. These figures from BEIS make an unshakeable case that a fair and balanced subsidy scheme should mean that large amounts of new onshore wind and PV are encouraged onto the UK grid. Even if a GW of gas turbines have to be build to support each GW of renewables, low-carbon sources are now close to, or at, grid parity.

 

 

 

 

Matt Ridley on solar and batteries (2)

Matt Ridley responded via Twitter to the last article on this web site in which I tried to correct some of the errors in his Times (London) piece of 24th October. His rebuttal is appended below.

I won’t ask why he used 2014 - rather than 2016 - battery prices when he himself has said costs are declining very rapidly. Nor why he chose to illustrate his points about the Musk Gigafactory by quoting the capacity that will be available when its first phase is finished rather than when the project is complete.

He also suggests that typical 35 year lives for solar panels are very unlikely. He may not know that the world’s biggest manufacturer, Trina, now offers an insurance-based 30 year warranty.

A couple of further things are worth noting. First, the yearly output of the Gigafactory would actually supply about 5 hours of UK electricity on a typical day, not the 60 minutes he suggests. His figure is wrong by a factor of five.

Solar EROEI

Very much more importantly, I think the pernicious nonsense that solar PV does not pay back the energy used in making modules needs to be rebutted.

The academic paper to which Matt Ridley refers is one of many that have been written on the ‘energy return on energy invested’ for solar PV. The researchers are - I think - alone in now thinking that more energy goes in than ever comes out. The dozens of other people working in this field have produced results wholly in conflict with the result he chooses to pick. As with many other things Mr Ridley writes about climate matters, it would be good to see a properly academic approach to the use of external data.

I’m going to do a bit of arithmetic to try to show why Mr Ridley is vanishingly unlikely to be right that the EROEI of PV is negative. I am going to use the example of the UK. Of course in sunnier regions the numbers would be even clearer.

1, Most solar panels are made in China. Indian wholesale prices for PV are the cheapest in the world at just under 40 US cents a watt. (A watt refers to the peak output of the cell when in full sun). Let’s assume that this is the full underlying cost of the panel. No margin for the manufacturer, or the wholesaler, no transport costs or import duties.

2, A large industrial user in China, such as an integrated PV manufacturer, pays about 6 US cents per kilowatt hour for electricity. Perhaps there are some further hidden subsidies so let’s take that number down to 5 US cents. (That’s about half today’s industrial electricity price in the UK).

3, Let’s make another assumption that the entire cost of a solar panel is used to pay for electricity. This is obviously an almost absurdly conservative assumption. If each kilowatt hour costs 5 US cents, then the sales price of the panel equates to 8 kilowatt hours of electricity. (40 cents divided by 5 cents). That is the ‘energy invested’ the EROEI calculation.

4, In a reasonably good location in the UK a watt of PV produces about 1 kilowatt hour of electricity a year. If the panel last 30 years (the length of the Trina guarantee), it will produce 30 kWhs per watt of capacity. That is the ‘energy return’ of the calculation.

5, Making a series of assumptions that are clearly as favourable as possible to the case Ridley wishes to make, even in the UK the EROEI for PV is 3.75 (30 kWh/8 kWh). He is wrong to suggest PV does not make sense in energy terms.

6, And scientific progress is a wonderful thing, as Mr Ridley so eloquently shows in his writing on all non-climate matters. The energy efficiency of making PV is rising rapidly because less silicon is wasted, the cell is thinner, new materials for photon collection (such as perovskites and oligomers) are arriving and electricity efficiency is rising because of advances such as solar tracking. 

 

Matt Ridley's response on Twitter (28th October 2016)

 

 

 

 

 

 

 

Another depressingly inaccurate article from Matt Ridley

Matt Ridley wrote an article in The Times (London) on 24th October, suggesting that using batteries for long-term energy storage is both expensive and impractical. Several people wrote to me about this, asking about its accuracy. The Times never publishes factual corrections so I thought I would quickly write down some of the mistakes in the piece.

a)    Batteries don’t currently cost $410 per kilowatt hour. When GM announced its Chevy Bolt electric car in autumn of 2015 it said that the battery cells it would employ were costing $145 a kilowatt hour. This is about a third of the number Matt Ridley used, although the GM figures excludes the cost of combining the cells into full battery packs. However the cost of batteries is continuing to fall sharply and the largest suppliers are suggesting that a figure of $100 a kilowatt hour is within sight, perhaps within a couple of years. Mr Ridley is several years out of date.

b)    Matt Ridley says that batteries are more expensive than 'pumped storage' for storing electricity. (He also writes that 'piles of coal' would be better). The most developed proposed new scheme in the UK is at Glyn Rhonwy in Snowdonia. The latest costing for this 500 MWh site is £160m, or about £310 a kilowatt hour. This is about twice the price of electric vehicle batteries today. Matt Ridley also writes that pumped storage ‘wastes’ less than batteries. I presume he means that the energy losses are smaller when charging and discharging. But Glyn Rhonwy will have a net energy conversion of ‘more than 75%’.[1] The batteries in a Tesla Powerwall have 92.5% efficiency. Mr Ridley is therefore wrong.[2]

c)     Matt Ridley refers to Professor David MacKay’s estimates of the UK’s need for storage to cope with wind variability. He suggests that the country would need to spend £130 billion to cope with the erratic power produced by turbines. What MacKay said was actually ‘There is thus a beautiful match between wind power and electric vehicles. If we ramp up electric vehicles at the same time as ramping up windpower, roughly 3000 new vehicles for every 3 MW wind turbine, and if we ensure that the charging systems for the vehicles are smart, this synergy would go a long way to solving the problem of wind fluctuations’.[3] The key point is that a large number of electric vehicles will help us stabilize the grid without any need for dedicated batteries. (And even if we did need batteries, the cost would be far lower than Ridley says because the cost has come down so much in recent months and years).

d)    Energy return on energy invested. Ridley makes the point that renewable electricity sources such as wind turbines and solar panels require energy to make. If this energy cost is greater than the energy they generate, there is no point in building them. We are all agreed on this. But he then goes on to assert that solar panels never pay back the energy used in manufacture. This particular story resurfaces depressingly often and is complete nonsense. The typical solar panel, even if it spends its 35 year life in dull old UK, creates far more electricity than is used to make it. Energy payback times for PV are falling all the time but even conservative estimates suggest a 10 times payback.[4] As silicon gets thinner and more efficient this number is rising rapidly.

e)    Elon Musk’s Gigafactory. Matt Ridley mentions Musk’s new battery factory in Nevada. This will make more batteries in 2020 in a single location than were made in the entire world in 2013. Ridley’s figure for the output of the factory is wrong by a factor of 3. By 2020, the Gigafactory will be producing 150 gigawatt hours a year of batteries for cars and for energy storage, not the 50 gigawatt hours he claims. I won’t comment on his suggestion that Elon Musk is operating some sort of pyramid scheme to draw subsidy out of the US government. If the world had more entrepreneurs like Musk the problems of climate change would be a lot more manageable.

f)     Ridley says that the cost of electric cars is ‘huge’, although he agrees they are quiet and non-polluting. The current price of EVs is indeed higher than equivalent petrol cars, but the difference is far less than the annual difference in fuel costs over the typical 15 year life of a vehicle. The BMW i3 offers nearly 200 miles of range for less than £28,000. Compared to petrol models, this price cannot be called ‘huge’.

g)    He also slams electric cars for taking a long time to charge. However the BMW referred to in f) will fill from empty to full in less than 40 minutes at a fast charging point in the UK.

h)    And, lastly, he tries to suggest that an electric car is likely to set itself on fire if it charges quickly. (He uses the recent history of new Samsung phones as justification for this assertion about electric cars). While it is true that a small number of Tesla vehicles have had fires, the chance is almost certainly less than for petrol cars.  Yes, batteries can malfunction but petrol is a far more dangerous fuel than electricity.

As far as I know, no-one other than Mr Ridley has ever actually suggested that batteries will be used to meet the need for long-term storage in high latitude countries such as the UK. The role of batteries here will be to help match supply and demand in the electricity system and to provide some overnight electricity. Britain will manage seasonal storage need in different ways, such as converting surplus electricity into methane in summer and at times of high winds.

Addendum 27th October. In another slighting remark about Elon Musk, Matt Ridley states that some analysts believe Tesla is 'burning through $1bn a quarter'. The company has today released its latest quarterly report. In q3 2016, showing a net positive free cash flow of $176m. Only about $1.2bn out Mr Ridley..

(This article was corrected at 11am on 26.10.16. I changed kilowatt to kilowatt hour when describing the cost of the Bolt's batteries).

(Further correction, 12 noon on 26.06.16. I changed 'smaller than' to 'greater than' in describing the energy return on energy invested calculation.)

 

 

 

 

 

 

 

 

 

[1] http://www.quarrybatterycompany.com/docs/QB_FACTSHEETS_ENGLISH.pdf

[2] https://www.tesla.com/powerwall

[3] Page 195 of the online edition of Sustainability – Without the Hot Air

[4] http://rameznaam.com/2015/06/04/whats-the-eroi-of-solar/

 

 

Why does age so clearly predict attitudes towards renewables (and Brexit)?

A person’s age is the best predictor of whether he or she thinks renewable sources of energy are a good idea. In a recent YouGov survey for Bulb, a new UK utility, pollsters looked at whether households would switch to low carbon sources if the price was the same as fossil fuels. 65% of 18-24 year olds would use a renewable source of supply but only 44% of those over 55 would do the same. (In other words a majority of 55+ householders would prefer to stick with fossil fuels even if there was no financial penalty to switching). 

Similarly, 74% of 18-24 year olds thought that ‘Renewable energy is something we should all buy’. This falls to 48% among those over 55. (Why are these numbers higher than those in the previous paragraph? Because people are more likely to offer general support than commit themselves to actually do something). 

Look at the poll’s numbers and another recent survey of opinions comes to mind. The UK’s June referendum showed a very similar pattern. Support for renewables and for Remaining falls sharply across the age ranges. The two charts below show how attitudes shift in step as people age.

Source: Bulb YouGov survey and Lord Ashcroft poll on Brexit voting and social attitudes

Source: Bulb YouGov survey and Lord Ashcroft poll on Brexit voting and social attitudes

Source: Bulb YouGov survey and Lord Ashcroft poll on Brexit voting and social attitudes

Source: Bulb YouGov survey and Lord Ashcroft poll on Brexit voting and social attitudes

In the Referendum, social class had a profound impact on the likelihood of voting to leave.[1] 54% of ABC1s wanted to stay in but only 36% of the C2DE group. But the attitude towards renewables doesn’t vary much across classes; 59% of ABC1s say that ‘renewable energy is something we should all buy’ and this number only falls to 54% for C2DEs. Willingness to buy renewables at the same price as fossil energy is 53% among the wealthier group, with a similar figure of 49% among the C2DEs. Other demographic indices also don't help predict attitudes towards renewables.

Why is age so important a crucial predictor of attitude towards low-carbon energy? Is it the same reason that drove the young to vote differently to their parents on Europe? 

The wonderful post-referendum Ashcroft poll gives a possible clue. As well as garnering information about how people voted, it surveyed social attitudes and looked at how well they predicted attitudes to Brexit. The poll showed that the young are very much more inclined to think that trends such as multiculturalism and feminism are ‘forces for good’. Similarly, belief in the positive impact of ‘The Green movement’ is far more common among the young. Crucially, if you felt that these social movements are broadly good you were very much more likely to vote to stay in the EU.  By contrast, social class had a very limited correlation with what might be called ‘progressive’ attitudes, as well as being a poor predictor of voting patterns.

Put simply, my hypothesis is therefore this. Attitudes towards renewable energy are closely correlated with views on Brexit because the move to low carbon sources is seen as a force for good among younger people, similar to feminism and social liberalism. Older voters see it as another ‘progressive’ movement which they want absolutely nothing to do with. Broadening democratic support for the energy switch therefore depends partly on ensuring it is no longer grouped with the progressive causes it is at the moment. 

In Energy Democracy, a book recently published by two of the foremost specialists on the German Energiewende (roughly ‘Energy Transition’), the authors make one crucial point throughout their book.(2) Renewables have never been seen as a particularly liberal or progressive cause in German and local generation of electricity has long been something that political conservatives have strongly supported. Community-owned wind farms, viewed as almost Marxist in the UK, are fully accepted by the mainstream voter in Germany. Money stays within the local community, and reliance on faceless utilities is reduced, says the typical 60 year old town dweller. Finding a way to transfer these attitudes to England and Wales - Scotland seems to get the point already - is one of the main challenges facing those of us who believe a fast switch to a low-carbon energy system is vital and also beneficial. 

 

[1] Lord Ashcroft’s poll is at http://lordashcroftpolls.com/wp-content/uploads/2016/06/How-the-UK-voted-Full-tables-1.pdf

[2] Energy Democracy; Germany's Energiewende to Renewables, Craig Morris and Arne Jungjohann, Palgrave Macmillan, 2016

[3] The YouGov survey for Bulb was kindly given to me by Hayden Wood, co-founder. 

Solar PV data for the UK. Misleading and systematically inaccurate

The PV industry reacted with disappointment as the latest monthly estimates of the deployment of solar were published by BEIS a couple of days ago. Solar Power Portal said the numbers ‘revealed August to be the slowest deployment month yet under the new regime’.

There’s a big problem here. The statisticians at BEIS and its regulator, the UK Statistics Authority (UKSA), know that the numbers Solar Power Portal is quoting are systematically wrong. Both government bodies understand very well that the official figures are constructed in a such way that they will never accurately report the actual level of solar installation in any one month. For the last year I have working pro bono with the department and its regulator to try to get some improvement – or at least an open admission of the issues – in the way these numbers are presented. We've seen some progress - including far greater openness about the way retrospective revisions are made to the data - but serious unresolved problems persist.

This week I admitted failure in my attempt to get these issues addressed. For several months, BEIS and UKSA have been promising a final meeting at which the crucial amendments to the way the numbers are presented would be discussed. At first I was told the session would be held in September, then it was fixed for October 3, which was moved to the 27th, and then other dates were offered and finally on Monday I was informed that the earliest possible date at which the officials would be free was mid-November. That takes it up to almost a year since I first wrote to UKSA to make a formal complaint and I’ve now given up. BEIS seems unable to publicly acknowledge that many of its statistical practices – across the solar deployment statistics and other series - are seriously and deliberately misleading. 

I’m writing this piece with sadness. I grew up with National Statistics, including a period briefly teaching economic statistics at university, and trusted government to produce honest and reliable figures because its statisticians are meant to be independent. The BEIS series which I have tried to help improve over the past year carry the National Statistics guarantee of quality. But despite the obvious flaws being now recognized by the department and the regulator, the reports are still allowed to carry this imprimatur today.

They shouldn’t be, and the failure of UKSA to insist on the quality mark being removed, makes me very concerned about all government data. If important figures are being produced that the statisticians know are wrong but they refuse to acknowledge the problems for fear of public or political criticism, we cannot be sure about any numbers coming out of government. This has serious implications for policy-making and for public trust.

The issues are complex, and I stress that I completely understand why BEIS finds it difficult to collect and present the data accurately. However its failure to acknowledge the problems is destructive to the PV industry and is misleading investors, the electricity market and policy makers. BEIS needs to openly admit the problem and, if necessary, stop producing the monthly document.

At heart, the cause of the statistical failure is this: PV installation data is poor and incomplete and arrives at BEIS very late. But the statisticians are obliged to bring out the figures every month. So what they do – understandably – is each month report what they know for certain has been installed in the previous month. But during the period since they last reported, previous month’s figures have been increased by data dribbling in about installations done before the previous month.

The effect is to make it seem as though each individual month has very low installation levels when they are first reported. But as time passes, the actual level is shown to be much larger, sometimes very much higher.

This year’s data is shown below. I find this information immensely confusing but I hope you understand it. The column is the month to which the data refers. The rows are the date of the report. So, for example, in the report for January (row) the amount of installed capacity for January (column) is recorded as 8,949 megawatts. In February, as more information has come in, the estimate of January capacity has risen to 9,202 megawatts. And the rise continues. By August, January’s total installed PV was estimate at 9,774 megawatts, over 800 megawatts higher than it initially said it was.

BEIS data.jpg

Why does the consistent rise – every month for every month - cause a problem? Because it obliges BEIS to underestimate the rate of monthly deployment. For the February report, it has only received confirmation of 11 megawatts of deployment in that month and it publishes that figure. So its statistical summary indicates it was a very poor month for PV. But look down at the bottom of the table; this shows that by August February is shown to be 87 megawatts higher than January.

This is closer to the real figure. But it is probably still an underestimate because BEIS continuously revises the numbers upwards for several years. It is still increasing its figures for PV from the months of 2014.

This point is even more apparent when we look at the figures for March. The first estimate of installations was 196 megawatts (9519 megawatts less 9323 megawatts). By August the estimate has risen five fold for the deployment in the month to 1018 megawatts.

Another way of looking it this is to compare how much PV BEIS has said in total has been installed each month with the figure for the absolute rise in PV now indicated. Add the together each month’s estimate of new deployment and you’d think the UK had put 376 megawatts of solar down so far this year. Then compute the difference between what BEIS said was the installed level in January (8,949 megawatts) and what it says now (11,034). This suggests a rise of at least five times as much. In time, the increase will be recorded as even greater because a lot of August data hasn’t arrived yet.

The underlying reason for this mess is that BEIS does not have access to decent data. But this doesn’t excuse the failure to acknowledge the problem. Last year, I initially complained to UKSA about the lack of any acknowledgement of the revisions. In fact, they were actively disguised by completely removing the data from public view.

As a result of my letters, UKSA forced BEIS to amend its policies on this issue and in several other important respects. The presentation of the data has become more transparent and honest. Nevertheless, the central problem remains. BEIS is presenting data each month under the National Statistics quality mark that is knows with absolute, unqualified certainty is wrong, and sufficiently wrong that it might affect both policy making and government expenditure by a noticeable amount.

This isn’t an isolated incident. A month ago, I complained that another series of BEIS data was in breach of National Statistics rules. Old statistical series were being wiped from the record to stop nosy people like me examining how BEIS had retrospectively changed its figures. Although I been initially told by a BEIS statistician that all the data had been ‘overwritten’, and therefore expunged, the Department did put back the old numbers on its web site two hours after I had submitted another formal complaint. You won’t be surprised to know that, once again, retrospective changes aren’t marked and anybody looking at the data will not be able to compute underlying growth and decline rates.

I think all this is very serious indeed. But I spend my life working with numbers and I’m probably not being objective.

Addendum,

Wookey (see the comments) asks for a chart that shows how one month's estimates are revised each month. 

This is the chart he wants for January 2016. The numbers have risen by over 800 MW (0.8GW) since the first statistical report. This increment is, for example, enough to provide 3% of UK electricity demand on a sunny weekend day in June. The revision is hugely significant. 

The X axis is the month of the revised report. So, for example, the deployment report for May says that January's total capacity was about 9,500 MW, up by about 100 MW from the previous month's estimate. 

The X axis is the month of the revised report. So, for example, the deployment report for May says that January's total capacity was about 9,500 MW, up by about 100 MW from the previous month's estimate. 

 

 

 

 

 

 

 

 

 

 

 

 



‘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

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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).