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Energy Subsidies and External Costs

(Updated September 2014)

  • Substantial amounts have been invested in energy R&D over the last 50 years. Much of this has been directed at developing nuclear energy – which now supplies 12% of world electricity.
  • Today, apart from Japan and France, there is about twice as much R&D investment in renewables than nuclear, but with rather less to show for it and with less potential for electricity supply.
  • Nowhere in the world is nuclear power subsidised per unit of production. In some countries however it is taxed because production costs are so low.
  • Renewables have received heavy direct subsidies in the market by various means, but these are being scaled back or abandoned in some places due to the high cost to consumers.
  • Fossil fuels receive indirect subsidies in their waste disposal as well as some direct subsidies.
  • Nuclear energy fully accounts for its waste disposal and decommissioning costs in financial evaluations.

There are three main areas where, broadly speaking, subsidies or other support for energy may apply: government R&D for particular technologies, subsidies for power generation per unit of production (or conceivably per unit of capacity), including costs imposed on disincentivised alternatives, and the allowance of external costs which are either paid by the community at large or picked up later by governments.

Energy R&D

There has been a lot of government-financed energy research and development (R&D) in most developed countries. This has been driven by concern about energy security, as well as by the need to address environmental problems and social concerns. Reliable and affordable energy supplies are vital to any economy, while energy shortages or the threat of such have political and economic consequences. Therefore as concerns have evolved from oil shocks to climate change, each country's energy provision and infrastructure needs restructuring accordingly.

Government R&D expenditure on energy tends to be focused on long-term development of new technologies, with the aim of bringing them to commercialisation, while private R&D is mostly on the further development of existing and operational technologies. While there are notable exceptions both ways, there is a strong disincentive for industry working in a highly competitive market and needing to justify a return on capital to shareholders to undertake long-term, high risk R&D. This is because after all their investment they will still be selling kilowatt hours of electricity or another essentially undifferentiated product in a competitive and very price-sensitive marketplace.

In recent years, some controversy has surrounded the question of the relative levels of R&D expenditure on nuclear energy and on new renewables (essentially technologies to harness wind and solar energy). Unfortunately, IEA data available for the first edition of this paper is no longer available, hence some of the following is dated.

Serbia published new FITs early in 2013, which will be valid for 12 years from project commissioning and will be corrected annually every February in line with the level of inflation in the Eurozone. They include EUR 9.2 c/kWh for wind and 16.25 c/kWh for solar, but with low caps on the capacity covered.

Year 1975 1980 1985 1990 1995 2000 2005
Conservation
333
955
725
510
1240
1497
1075
Fossil Fuels
587
2564
1510
1793
1050
612
1007
Renewables
208
1914
843
563
809
773
1113
Nuclear Fission
4808
6794
6575
4199
3616
3406
3168
Nuclear Fusion
597
1221
1470
1055
1120
893
715
Other
893
1160
787
916
 
 
 
Total Energy R&D
7563
15034
12186
9394
9483
9070
9586
Total: Japan
1508
3438
3738
3452
3672
3721
3905
Total: excluding Japan
6055
11596
8448
5842
5811
5349
5681
Table 1. Expenditure by IEA countries on energy R&D.

Energy R&D

The above table and graph are from the OECD International Energy Agency's database (IEA, 2001 & 2006) regarding government expenditure in the 26 IEA member countries. The database does not include information about private companies' expenditure, nor funds spent by non-IEA countries, such as China, Russia or India.

The total amount of energy R&D expenditure by governments of IEA countries rose in response to the oil price shocks of the early 1970s and then fell away as associated concerns abated, with the conspicuous exception of Japan. Private R&D investment has apparently followed the same pattern outside Japan.

Nuclear energy R&D vs Renewables and other sources

Throughout the period, the expenditure on nuclear fission dominated the overall figures, though falling from 64 per cent of the total in 1975 to 33 per cent in 2005. However, Table 2 shows that in most IEA countries (apart from Japan), government R&D expenditure on nuclear fission fell significantly through the 1990s, to trivial levels - in fact below that spent on renewables, which has averaged about US$ 700 million per year for the last two decades but is now rising.

IEA R and D

Table 2. Expenditure by IEA Countries on Fission R&D.
(2005 US$ millions)
  UK France Japan USA Other IEA countries All IEA countries
1975
929
0
763
2164
952
4808
1980
741
0
2098
2410
1160
6794
1985
638
895
2259
1241
1542
6575
1990
253
555
2298
737
356
4199
1995
17
599
2455
103
442
3616
2000
0
666
2393
39
308
3406
2005
4
?
2398
171
?
3168

IEA data shows R&D on nuclear fission peaking around 1980 and after 1985 declining steadily to less than half that level. Since 1990 Japan alone has been responsible for some two thirds of IEA R&D expenditure on nuclear fission, with France accounting for most of the remainder. If the French and Japanese figures are excluded, fission R&D expenditure in the rest of the IEA countries totalled US$ 308 million in 2000.

The extent of expenditure on renewables significantly outweighing that on nuclear fission everywhere except France and Japan would be unremarkable if the potential contribution from each were similar. In fact the potential scope for renewables contributing to electricity supply is very much less because the sources, particularly solar and wind, are diffuse, intermittent and unreliable. Their diffuse nature is simply a technical problem. But for intermittent and essentially opportunistic supply of wind- or solar-generated electricity to a grid system, the maximum potential appears to be about 20% of the total, and normally less, whereas that from nuclear energy is around 90%.

Partly as a result of the R&D expenditure, nuclear power now provides 14% of world electricity (more in those countries foremost in the R&D) - 2600 billion kWh per year, compared with a fraction of that for non-hydro renewables. Furthermore the scope for increasing the renewable contribution is not considered by the power producers to be very great.

The Japan Atomic Energy Agency (JAEA) is Japan's major integrated nuclear R&D organization, with 4400 employees at ten facilities and annual budget of 161 billion yen (US$ 1.7 billion).

A 2008 study by Management Information Services Inc looked at US energy more widely than just electricity, and took in all federal incentives, not simply R&D, from 1950 to 2006. Some $726 billion was identified (2006 dollars). Its conclusions included:

  • The largest incentive category was tax concessions, especially for oil but also wind. No tax concession was for nuclear in this period.
  • Total support for nuclear power over the 56 years was $65 billion, 9% of the total incentives. This compared with $50 billion (7%) for non-hydro renewables (wind and solar) plus geothermal.
  • The main support was for oil and gas - $436 billion, 60% of total, with coal at $93 billion (13%).
  • Most of the support for nuclear power was in R&D.
  • Today nuclear power in the USA pays more than it receives due to contributions to the federal nuclear waste fund, which so far exceed disbursements from it by $14 billion. (There is no corresponding payment from other energy sources.)

Focusing on R&D:

  • R&D comprised 19% of the total incentives, and half of this ($67 billion of $135 billion) was for nuclear, 16.5% for renewables plus geothermal, and 23% for coal. (Nuclear fusion was not included)
  • Of the nuclear R&D, about $39 billion was spent before 1975 to explore a range of reactor concepts.
  • Nuclear R&D peaked at $2.8 billion in 1978 and declined sharply to about $550 million in 1987, then steadily to a low of $75 million in 2001.
  • Research on breeder reactors took 35% ($23.7 billion) of the nuclear R&D, though funding for this ceased in 1988. From 1976 to 1988, the breeder program accounted for a high proportion of expenditure.
  • Light water reactor technology accounted for only 8% ($5.3 billion) of the nuclear R&D though it now provides almost 20% of US electricity.
  • Other reactor types received $38 billion in R&D.
  • Since 1988, spending on nuclear R&D has been less that for coal, and since 1994 it has been less than that for renewables as well.

US Department of Energy figures show the renewables total in the US R&D budget as $505 million in FY2007 and energy efficiency $676 million, compared with nuclear power at $300 million (double the 2003 level) and fossil fuels at $397 million. Nuclear fusion is additional at $319 million.

Other US DOE R&D data is as follows ($ million)

Years

currency Renewables Coal Nuclear End use

1988-2007

2007 $

6271

7593

13,500

5737

FY 2007

2010 $

717

582

1017

509

FY 2010 2010 $ 1409 663 1169 832

EIA 2008 & 2011

In FY 2007, relating the support to actual energy produced, the figures are: wind 2.34 c/kWh, "clean coal" 2.98 c/kWh, gas, coal 0.044 c/kWh, nuclear 0.16 c/kWh.

Outside the IEA, Russia, India and China have substantial nuclear fission programs and as the European Union also funds an amount of fission R&D, the worldwide totals for fission will be rather higher than the figure above. Nonetheless, given that the bulk of government-sponsored R&D into nuclear fission focuses on waste management and other fuel cycle back-end processes, it is clear that little is being spent at present by governments on new reactor designs.

Subsidies for particular energy sources and disincentives on alternatives

A simple definition of subsidy is difficult to find. The IEA points out that there is enormous confusion about what is meant by the term. The narrowest and perhaps most commonly used definition is a direct cash payment by a government to an energy producer or consumer. But this is just one way in which governments can stimulate the production or use of a particular fuel or form of energy. 

Broader definitions attempt to capture other types of government interventions that affect prices or costs, either directly or indirectly. For example, an OECD study defined a subsidy as any measure that keeps prices for consumers below market levels, or for producers above market levels, or that reduces costs for consumers and producers. In a similar way, the IEA defines energy subsidies as any government action that concerns primarily the energy sector that lowers the cost of energy production, raises the price received by energy producers or lowers the price paid by energy consumers. What matters in practice is the overall impact of all subsidies and taxes on the absolute level of prices and costs and the competitiveness of each fuel or technology.

In addition to front-end R&D expenditure there are ongoing operational subsidies for various forms and sources of energy. With government-controlled utilities, or regulated markets such as in the USA until the mid 1990s, utility costs could simply be passed on to the consumers, who effectively supplied a subsidy relative to cheaper alternatives. With deregulated and competitive markets this had to change.

In an open market, government policies to support particular generation options such as renewables normally give rise to explicit direct subsidies along with other instruments such as feed-in tariffs, quota obligations and energy tax exemptions. To provide disincentive on alternatives there can be targeted taxes including carbon taxes, or emission trading schemes for carbon. (see later section)

US figures for electricity production 2010

Fiscal year 2010 electricity production subsidies and support
(EIA Table ES4 & ES5, million 2010 dollars)

Beneficiary Direct Exp Tax Exp R&D Federal Elect Support Loan G'tee Total Share of total subsidies & support Share of electricity generation in 2010
Coal 37 486 575 91 0 1,189 10.0% 44.9%
Natural Gas and petroleum liquids 1 583 15 56 0 654 5.5% 25%
Nuclear 0 908 1,169 157 265 2,499 21.0% 19.6%
Renewables 4,178 1,347 632 133 269 6,560 55.3% 10.3%
Biomass 6 54 55 0 0 114 1.0% 1.4%
Geothermal 115 1 72 0 12 200 1.7% 0.4%
Hydropower 17 17 51 130 0 215 1.8% 6.2%
Solar 409 99 287 0 173 968 8.2% 0%
Wind 3,556 1,178 166 1 85 4,986 42.0% 2.3%
Unallocated Renewables 75 0 0 0 0 75 0.6% 0
Transmission & distribution 461 58 222 211 20 971 8.2% NA
Total 4,677 3,382 2,613 648 555 11,873 100% 100%

Subsidies for renewable energy supplying electricity

The IEA's World Energy Outlook 2011 estimates that the total cost of subsidies for renewable energy will rise from $66 billion in 2010 to $250 billion in 2035. However, several countries are cutting back support for renewables due both to the high cost impacting electricity prices and also the costs and difficulties of integrating them into the transmission networks. Germany and Spain are cutting about $2.5 billion and $3.5 billion per year respectively from subsidies for renewables.

A feed-in tariff (FIT) obliges energy retailers to buy any electricity produced from specified, eg renewable, sources at a fixed price, usually over a fixed period of some years (eg 20 years in Germany), the price being significantly greater than that paid for power from mainstream sources. The rates usually vary for different sources, eg being greater for solar or offshore wind. In this case they may be called Advanced Renewable Tariffs (ART), differentiating by technology and perhaps project size. There is usually no amount or proportion specified, though a cap or quota on how much needs to be bought overall or from particular sources may be applied. With renewables, any supply offered must be taken by the grid operator, regardless of merit order considerations (normally applying, so that lowest marginal cost supplies are preferred). In Germany for instance, the grid operators buy the renewable kWh at the specified FIT rate and then sell them on the open market. The difference between the sales proceeds and the FIT they have paid to various suppliers is compensated by the end consumer through an 'EEG-surcharge' being applied to bills. Electricity-intense industry has this surcharge limited.

Feed-in tariffs (FIT) are now common in Europe, Canada, China and Israel and imminent in several Australian states, total at least 41 countries or provinces. They generally mean that the consumer pays the subsidy for power from the legislated sources, the cost being spread across all power purchases unless there is a special deal to buy renewable power at a premium. In Germany the additional cost of the FIT above normal wholesale market is recovered by a ‘renewable energy surcharge’ being added to retail electricity bills (with exemptions for industry).  However, in some countries FITs have become unaffordable, and are being replaced with other mechanisms.

A variation on FIT is the contract for difference (CFD), which means that if the market price is lower that the agreed strike price, the government pays that difference per kWh, if the market is above the strike price, the generator pays the government. The key factor then is setting the strike price far enough ahead to enable investment. Another variation – short of a full FIT – is a bonus payment on market price.

A problem showing up in several countries, especially regarding FITs, is that they become increasingly costly to consumers as the take-up increases. In Germany, the cost of subsidies for solar power is expected to reach EUR 46 billion by 2030. In Spain the take-up was so high that the government had to renege on its subsidy commitments after investments had been made. France cut back subsidies in 2010. The UK in 2011 wound back the FIT levels for new plants. Slovakia in 2011-12 slashed FITs for solar from EUR 38 c/kWh to 11.9 c/kWh for small solar (up to 100 kW) in order to keep electricity prices down.

When governments change the FIT levels to adjust the incentive, the changes generally apply only to new sources.

Europe

In the EU, feed-in tariffs are widespread (in 18 of 25 EU countries as of 2007). European Environment Agency figures in 2004 gave indicative estimates of total energy subsidies in the EU-15 for 2001: solid fuel (coal) EUR 13.0, oil & gas EUR 8.7, nuclear EUR 2.2, renewables EUR 5.3 billion.

In the UK, a February 2010 report from Ofgem showed that subsidies for renewables, notably the Renewables Obligation, had risen from £7 in 2007 to £13.50 per year on the average household electricity bill, and in 2008-09 totalled £1.04 billion.

The UK Renewables Obligation (RO) requires retailers each to buy a certain proportion of the electricity they supply from renewable sources with certificates at whatever price they can, or to pay a penalty. In the UK proportion was 9.1% and the default buy-out price (or "fine") was 3.576 p/kWh in 2008-09. It had reached 11% at the end of 2010 and will be 15% by 2016 (ie suppliers needed to present to Ofgem 0.11 certificates per MWh sold in 2010-11). The buy-out price for 2010-11 was 3.7 p/kWh (£37 per MWh certificate) and in 2013 auction prices ranged £41.50 to £44/MWh. The price of the electricity from renewable sources is left to the market. The amount required to be bought can be adjusted annually, as in UK towards 15.4% by 2015 (2006-07 level was 6.7%, 2007-08 was 7.9%).

In 2006-07 in England and Wales 12.87 billion kWh of renewable electricity was supplied and £218 million in fines was paid, representing a shortfall of 6.55 billion kWh. (The actual UK system is more complex than outlined, because Ofgem issues to generators certificates which can be traded, and the price of these reflects the fact that fines are distributed to retailers or others in proportion to certificates they submitted. In 2010-11 this was £14.32 per certificate, so the value of a certificate to the generator was about £51. This compares with the wholesale electricity price of about £52/MWh.)

Due to the Renewables Obligation the UK subsidy on onshore wind generation is the highest in the EU. Under the Energy Act 2008 the UK system was modified from 2009 to provide greater incentive to use offshore wind, biomass and emerging technologies. This is done by issuing one certificate (or 0.9 certificate) per MWh for onshore wind, 2 (or 1.9) per MWh for offshore wind, etc. and adjusting from time to time. Technologies such as wave and tidal power which are hopelessly uneconomic and likely to remain so, even if they are more useful, will get up to 5 certificates per MWh. 

The Renewables Obligation provided about £1.4 billion support for renewables in 2010, at a cost of 3% on consumer bills, or about £20 per household, half of which is due to wind. DECC said it added £30 to an average household bill for 2013. By 2017 it is expected to be £50. A November 2011 estimate from DECC said every household in the UK had paid £320 on average so far to subsidise renewables, a total of £7 billion, bringing average household energy bills to £1300 pa. Ofgem estimates that in the course of achieving 30% of supply from renewables the amended Renewables Obligation for large-scale projects is predicted to cost consumers £6 billion per year by 2020, and the new feed-in tariff (FIT) for schemes up to 5 MWe will cost them £7.9 billion per year by 2030, on the basis of 5.2 pence/kWh for RO and 9.3 p/kWh for FIT*. Meanwhile it is seen by the Renewable Energy Foundation to be "both counterproductive and very poor value for money". The new government elected in 2010 is moving to replace the Renewables Obligation with a 'contract for difference' for new projects, effectively a long-term power price, which took shape in the draft energy bill released in May 2012.

* From April 2010 householders and communities who install low carbon electricity technology such as solar photovoltaic (PV) panels and wind turbines up to 5 megawatts are paid for the electricity they generate, even if they use it themselves. The level of payment depends on the technology and is linked to inflation. Electricity from small wind turbines was paid at 34 p/kWh, that from solar PV 41 p/kWh. They got a further payment of 3 p/kWh for any electricity exported to the grid. These figures were reviewed in 2011 with a view to reductions applying from April 2012. The solar PV rate for FIT then dropped to 21 p/kWh, and to 16p in August 2012 with further decrease thereafter to average 3.5% every three months. But the export tariff goes up from 3.2 to 4.5 p/kWh.

Three units of the Drax coal-fired power plant are being converted to run on biomass, mostly imported wood pellets, for a guaranteed power price of £105/MWh. However, in April 2014 the second unit converted to biomass was denied similar Investment Contract support, leaving it to recoup costs from Renewables Obligation Certificates (at 0.9 ROC/MWh, the average ROC price in May 2014 was about £41.70) plus the wholesale power price – about £50/MWh. A court appeal failed. However, the government has offered an Investment Contract with price guarantee for the third Drax unit.

The Renewables Obligation is to be replaced in 2014 for new projects with a FIT effected through contracts for difference (CfD) which can be capped regarding quantity. Draft strike prices (FIT) for renewables include £155/MWh for offshore wind (declining to £135 in 2018), £100/MWh for onshore wind (declining to £95 in 2018), and £125/MWh for large solar PV (declining to £110 in 2018).

The UK also has a Climate Change Levy of 0.43 p/kWh on non-renewable sources (at present including nuclear energy, despite its lack of greenhouse gas emissions), which corresponds to a further subsidy of renewables.

The UK government legislated to establish a carbon price floor from April 2013, to underpin the move to a low-carbon energy future. Per tonne of CO2, this rises from £4.94 to £9.55 for 2014-15, £18.08 for 2015-16, and £18 to 2018. 

In Germany the Renewable Energy Sources Act (EEG) of 2000, revised in 2004 and 2007, governs subsidies. Germany applies a mixture of incentives for renewables, but principally relies on wholesale feed-in tariffs which are guaranteed for up to 20 years.

The average feed-in tariff (FIT) apart from solar PV was EUR 8.5 c/kWh, or 16.4 cents including solar PV in 2006 (solar PV being up to 49 cents). Wind provides nearly half of the renewable input and feed-in tariffs for new plants are 8.9 c/kWh on land and 15 c offshore, but dropping to 4.9c after five or twelve years respectively. Solar PV gets 12-18 c/kWh depending on size, for 20 years. The combined subsidy from consumers and government totals about EUR 20 billion per year – for some 25% of its electricity from wind and solar. Early in 2010 Germany announced a 15% cut in the solar feed-in tariff for new installations, after adding nearly 3000 MWe solar in 2009, and reportedly paying over $15 billion for solar power. Energy consumers will pay €100 billion over the next 20 years to subsidize domestic PV installed before the end of 2011. The first several months of 2012 added at least €5 billion to that amount. A public backlash is reported due to much of the economic benefit going to foreign solar module manufacturers. In mid 2012 parliament agreed to cap solar FITs at 52 GW (about double the present level) and apply a new solar FIT of 18.5 cents/kWh for rooftop plants of 10-40 kW and 16.5 c/kWh for 40-1000 kW systems. For larger plants, none over 10 MW would be eligible for FITs.

The four major German utilities and the Federal Network Agency and grid authority raised the surcharge that customers pay on their utility bills to fund renewable energy by a steep 47% in 2013, from 3.592 c/kWh in 2012 (yielding EUR 20.4 billion) to 5.277 c/kWh. Then in October 2013 they announced a further 18% rise to 6.24 c/kWh in 2014, taking the annual surcharge on consumers to about EUR 23.6 billion. This is to cover the increasing proportion from renewables and the fact that the utilities are obliged to pay for each renewable kWh much more than they can sell it for (eg 18 c/kWh for solar, sold for 4.5 c/kWh on wholesale market). Utilities charge most customers the EEG surcharge or Umlage to cover the difference. Some energy-intensive industries are exempt from this. Overall, the 2013 forecast EEG feed-in tariffs amount to about €18.5 billion, compared with projected revenues on the electricity market of about €2.6 billion. The difference between projected feed-in tariffs and marketing revenues forms the essential part of the EEG surcharge. However, the government is putting a cap on the surcharge until the end of 2014 and then allowing only 2.5% per annum increases. It also plans to tighten industry exemptions and possibly cut FITs for wind and biomass plants, calling into question investment security.

The federal Economy Ministry calculates that electricity prices will increase by 3 to 5 c/kWh by mid-2013 from the early 2012 level of 3.59 cents in order to finance renewable energy subsidies and grid expansion, though other estimates put the figure at over 5 cents.

France cut subsidies for solar PV input to the grid by 25% early in 2010, from $0.80 set in 2006 to $0.61 c/kWh.

Denmark has a wide range of incentives for renewables and particularly wind energy. In 2000 it produced 4 TWh (out of 36 TWh gross total, about 11%) thus, and is aiming at 15%. Its utility buy-back rates for privately-generated wind electricity in 1999 averaged DKr 0.60/kWh, including a DKr 0.27/kWh subsidy funded by carbon tax (now US$ 6.8 cents & 3.2 cents respectively). However, there is a further economic cost borne by power utilities and customers. When there is a drop in wind, back-up power is bought from the Nordic power pool at the going rate. Similarly, any surplus (subsidised) wind power is sold to the pool. The net effect of this is growing losses as wind capacity expands. Official estimates put the expected losses at DKr 1.5 billion per year, others reckon more than double this.

Early in 2009, Nord Pool announced that from October the spot floor price for surplus power would drop from zero to minus 20 Euro cents/kWh. In other words, wind generators producing power in periods of low demand will have to pay the network to take it. Nord Pool stated: "A negative price floor has been in demand for some time – especially from participants trading Elspot in the Danish bidding areas. In situations with high wind feed in Denmark there have been incidents where sales bids have been curtailed at price €0. Curtailment of sales may give an imbalance cost for the affected seller and thus creates a willingness to pay in order to deliver power in the market." This has increased the negative effect on the economics of wind power in Denmark, since a significant amount of its wind power production is affected.

Sweden subsidises renewables (principally large-scale hydro) by a tax on nuclear capacity, which (late in 2001) works out at EUR 0.32 cents/kWh. It also has a quota and certificate scheme which gives a price of 6.85 c/kWh on renewables apart from solar PV.

Italy had a quota (Renewable Portfolio Standard) and tradable and certificate scheme with average price 12.53 c/kWh for renewables apart from solar PV, 17.27 cents including solar PV, in 2006. This was replaced by FiTs, but due to the proliferation of solar PV capacity, its €6.7 billion cap on subsidies for 2013 was reached in mid-year. FiTs then were 10.6 to 18.2 c/kWh depending on size and location. Innovative plants got 21.7 to 24.2 c/kWh. Concentrating solar PV got 17.4 to 21.5 c/kWh. The FiTs are for 20 years. The government decided on a FiT reduction of 17-25% in 2014.

In Norway the government subsidises wind energy with a 25% investment grant and then production support per kWh, the total coming to NOK 0.12/kWh, against a spot price of around NOK 0.18/kWh (US$ 1.3 cents & 2 cents respectively).

Spain has a feed-in tariff of EUR 7.32 c/kWh for wind energy, 27 c/kWh for solar thermal, and 31-34 c/kWh for solar PV. In 2010 cuts of 25% for roof-mounted solar systems and 45% for larger ones were announced. In February 2013 subsidies were cut further and indexed to an inflation estimate that strips out the effects of energy, food commodities, and tax changes. In 2000, the government had promised more than 20 years of large subsidies, and investment had proceeded on this basis.

At the end of 2012 Spain brought in higher taxes on power generation to address an EUR 24 billion energy tariff deficit after more than a decade of selling electricity at regulated rates which did not cover costs, with some EUR 7 billion per year subsidies on renewables. The cost of subsidies was not passed on to consumers, since this would have made power unaffordable. However, foreign investors put a lot of money into wind and solar projects due to the high FITs - some EUR 13 billion. But this power generation tax plus subsidy reductions in 2010 and further major cuts in February 2013 meant that the government had reneged on the terms of that investment, and legal action under the international Energy Charter Treaty was planned.

In July 2013 the Ministry of Industry, Energy and Tourism introduced further ‘definitive reforms’ to reduce the deficit by €4.5 billion per year. These measures remove the FIT system and substitute a new Regulated Asset Value-based system and will cut the payments for renewables by €1.3 to 1.4 billion per year. Overall they will cost utilities €2.7 billion per year. Solar companies are expected to be worst affected, due to debt load estimated at €30 billion, and widespread financial distress is predicted by solar and wind industry groups. In May 2013 renewables received an average subsidy of EUR 100/MWh.

Greece has a feed-in tariff of 6.1-7.5 c/kWh, whereas the Netherlands relies on exemption from energy taxes to encourage renewables.

Turkey, under its Dec 2010 Renewable Energy law, has a basic feed-in tariff of 7.3 c/kWh, slightly below market prices late in 2010. This can then be increased by up to 3.7c for wind, up to 9.2c for concentrating solar thermal, and up to 6.7c for solar PV, depending on the equipment used and its local content. Prior to this, the FIT was EUR 5.5 cents/kWh.

The Czech Republic had a mandated feed-in tariff for solar power of CZK 12($0.63) per kWh, about ten times the cost of power generated by CEZ. This was threatening grid stability and was reduced to CZK 5.5 for new PV projects over 100 kW and CZK 7.5 for smaller ones after the end of 2010. However, the impact of some 1600 MWe constructed by then was expected to lead to an increase in electricity prices of 13% for residential and 18% for industry consumers in 2011, and a 25-28% retroactive tax on solar electricity from installations over 30 kW was introduced, but was challenged. The International Photovoltaic Investors Club (IPVIC) had an arbitration complaint being lodged in the first quarter of 2013 with findings expected in 2014. The investors group is reportedly seeking up to CZK 2.5 billion in damages.

From January 2014 the Czech government will end all support for new renewables capacity coming on line from then, and set a CZK 495/MWh (€19/MWh) cap on payments by consumers for renewable power - a 15% drop from 2013. The level of direct government payments to cover the costs of feed-in tariffs and green bonus scheme payments for electricity from renewables will rise to an estimated CZK 15.7 billion (€600 million) in 2014. Total Czech support for renewables is estimated at CZK 44.4 billion (€1.7 billion) in 2013. The 26% tax on new solar installations will drop to 10% in 2014. 

Slovakia has drastically cut back on subsidies for solar power, after a boom in response to generous feed-in tariffs pushed the household price of electricity up by 5%. Only roof-mounted PV panels under 100 kW will now be eligible. The subsidy cost jumped from EUR 10 million in 2010 to EUR 117 million in 2011 (to 30 June). The planned 8 MWe of new solar capacity to the end of 2010 ended up with 145 MWe total, and 115 MWe more was expected by the end of June 2011 cut-off.

Latvia has feed-in tariffs of EUR 9.6 to 18.2 c/kWh for wind, depending on size of generator, and 42.7 c/kWh for solar PV. Lithuania's feed-in tariff for wind is 8.7 c/kWh.

Elsewhere in EU, small-scale photovoltaic (PV) input is encouraged by high feed-in tariffs, eg 50 c/kWh in Portugal.

North America

The US government spent $24 billion on energy subsidies in 2011, $16 billion of this for renewables including $6 billion for ethanol tax credits, according to the Congressional Budget Office. The production tax credit for wind cost $1.6 billion. Fossil fuels got $2.5 billion in tax breaks.

In the USA a direct subsidy or Production Tax Credit (PTC, now about 2.2 c/kWh for wind) is available to generators of renewable power over the first ten years of a project's operation so they can sell it that much below actual cost. The subsidy is granted as credit on taxes, though following the American Recovery & Reinvestment Act (ARRA) in mid 2009, an investment tax credit of 30% may be claimed instead for wind plant placed in service before 2013 if construction begins before the end of 2013. A total of $16.8 billion had been provided in direct grants for energy efficiency and renewable energy projects under ARRA. This credit can be converted to a grant from the government. In the USA a Renewable Portfolio Standard is proposed, mandating a specified amount of renewable power from suppliers, and applying already in California and other states. The PTC is indexed to inflation, and has been extended each year.

Several US states and municipalities are looking at FITs. Vermont enacted one in 2009 and Gainesville, Florida has one in 26-32 c/kWh range.

In Ontario, Canada, under a 2009 Green Energy Act, feed-in tariffs were introduced, ranging from 11 c/kWh for landfill gas and 13 c/kWh for wind to 80.2 c/kWh for solar PV.

East Asia

In Japan, since 2009 a feed-in tariff required utilities to buy surplus solar power produced domestically at up to JPY 48/kWh. This was extended to hydro, wind and geothermal power at JPY 17-20/kWh, compared with JPY 5-7 for base-load power. In mid 2012 the general FIT was increased to JPY 42 /kWh for solar-generated electricity, double the tariff offered in Germany and more than three times that paid in China. The level is to be reduced in April 2014 to JPY 37/kWh residential and JPY 32/kWh for systems over 10 kW. Wind power FIT will be JPY 23.1 /kWh for units above 20 kW and JPY 57.75 for smaller units.

In China, the Global Wind Energy Council acknowledges "the fact that wind is heavily subsidised". This is under a variety of complex measures focused on capacity rather than output, and correlates with a low average capacity factor of 16% over 2006-07, partly due to grid constraints. China's 2006 Renewable Energy Law sets out a subsidized electricity tariff structure (though no feed-in tariff), a compulsory grid connection mandate for renewable energy projects, and a rule that requires utilities to purchase all the renewable electricity produced in their service area. In addition, carbon credits awarded under the UN Clean Development Mechanism (CDM) enable foreign investors in Chinese wind projects to sell carbon credits outside the country, this being essential to project viability.

Solar power has enjoyed substantial incentives in China since 2009, and in 2011 the national feed-in tariff was RMB 1.15 per kWh (18 cents), but in 2012 this was reduced to RMB 0.55 (8.7 cents). Late in 2012 subsidies for solar power were boosted by CNY 7 billion ($1.1 billion) to a total of CNY 13 billion. The subsidies are to allow support of 5.2 GWe of domestic solar energy production.

Australia

Australia's Mandatory Renewable Energy Target (RET or MRET) has since 2001 required retailers each to buy a certain proportion of the electricity they supply from non-hydro renewable sources at whatever price they can, or incur a penalty by paying a shortfall charge, currently 4.2 c/kWh ($A). The original 10% target or 9500 GWh by 2010 was increased in 2009 to 20%, or about 45,000 GWh in 2020, representing a major increase from non-hydro sources. The shortfall charge goes up fro 4 cents to 6.5 c/kWh. The obligation is tradeable. Subsidies for renewables total an estimated $12 billion in the decade to 2011, which works out to about 0.6 c/kWh. Origin Energy estimates that the small-scale renewable scheme part of MRET will cost customers $3.2 billion over the current two years to 2012. Government-commissioned modelling suggests that the net overall power cost to consumers will be 0.5 c/kWh to 2015 and then 0.77 c/kWh to 2020. A 2011 study by Carbon Market Economics found that each tonne of CO2 emissions eliminated through the use of renewable energy plants commissioned by the end of 2010 cost $76 in subsidies, more than three times the proposed carbon price of $23 a tonne.

Feed-in tariffs are on a state basis. Victorian and NSW householders with solar PV sell power to the grid at 60 c/kWh, compared with about 8 c/kWh for coal-fired power delivered to the city.

Subsidies for coal (and other fossil fuels)

The OECD IEA estimates that globally, fossil fuel subsidies amounted to $409 billion in 2010, compared with about $300 billion in 2009. Its detailed inventory covers over 250 mechanisms that support fossil fuel production and use. Some 54% of the fossil fuel support went to the petroleum sector.

In the EU, coal is heavily subsidised by governments, particularly in Germany's Ruhrgebiet region, northwest Spain, and Romania's Jiu Valley. There have been proposals to phase out coal subsidies by 2022, reducing them by one quarter every three years, but some 100,00 jobs are involved. In 2010, some EUR 3.2 billion in coal subsidies were handed out in six EU countries: Germany, Hungary, Poland, Romania, Slovakia and Spain.

In July 2010 the European Commission unanimously approved a proposal to close uncompetitive hard coal mines in the EU that rely on subsidies by October 2014, and to phase out coal subsidies by 2018. The mines that rely on operating subsidies are located mostly in the Ruhr region in Germany, in northwest Spain and in the Jiu Valley in Romania. More than 40% of electricity in Germany is produced from coal, about half of which is hard coal and half lignite. In Romania, coal-produced electricity is also around 40%, most of which hard coal. In Spain the share is around 25%, also mostly hard coal. Under the approved rules, interim operating aid would only be allowed for coal mines with a closure plan in place, otherwise state aid will stop.

According to the EC in mid 2010, total aid to the hard coal sector has been halved from €6.4 billion in 2003 to €2.9 billion in 2008. The amount of aid going towards actual production has fallen by 62% to €1.3 billion in the same period.

Germany has provided producer subsidies to its coal industry amounting to EUR 68 per tonne for 34 Mt coal in 2000 - total EUR 2.3 billion. Since the late 1980s the domestic hard coal production price has been at least EUR 100/t above the imported cost, and subsidies reached a high of EUR 7.9 billion in 1989. By 2002 production had declined to about 25 Mt/yr and the subsidy was down to EUR 3.5 billion and a later figure quoted EUR 2.5 billion, with EUR 130 billion over previous four decades.

Energy taxes, and subsidies for nuclear power

Corresponding to subsidies in the other direction are taxes on particular energy sources, justified by climate change or related policies, and with low production costs providing opportunity. For instance Sweden taxes nuclear power at about EUR 0.67 cents/kWh, which makes up about one third of the operating costs for nuclear plants. Belgium is introducing a tax of 0.5 cents/kWh on nuclear. The UK has a Climate Change Levy which is a tax on energy used by business. The rate was 0.43 p/kWh but from 2006 has been indexed. Electricity from designated renewable sources is exempt from the levy, nuclear power is subject to it.

Germany in 2010 legislated for a tax of €145 per gram of uranium or plutonium fuel for six years, yielding €2.3 billion per year (about 1.6 c/kWh), a levy on nuclear generators of €300 million per year in 2011 and 2012, and €200 million 2013-16, to subsidise renewables, and a tax of €0.9 c/kWh for the same purpose after 2016.

Finland has been planning to introduce a tax on nuclear fuel to raise about €170 million per year from 2013, and countering the windfall profits from nuclear generators selling CO2 emission allowances. The Ministry of Employment and Economy in 2011 said that these so-called ‘windfall’ profits would be taxed at 43% to 45% of the market price of CO2 emission rights, depending on the model adopted, and at least €0.2 cents/kWh. In the "minimum tax model", at €15 per tonne CO2 the tax would generate at least €67 million per year, and at €30 per tonne, the tax would be € 0.67 cents per kWh, generating some €223 million. In the "flexible tax model", the uranium tax would be €0.17 cents per kWh, plus 30% of the windfall profit. An emission allowance price of €15 per tonne of CO2 would generate some €57 million, and a price of €30 per tonne would generate €207 million. Under this model, if the emissions trading price fell to less than €9.3 per tonne of CO2, there would be a 'negative' tax which could be credited against subsequent years of 'positive' uranium taxes. The proposal has drawn criticism, as it counteracts a key goal of the EU's carbon market - to reward low-carbon production compared with high-CO2 sources.

There is also occasionally a tax on excess wind production at times of low demand in Denmark and northern Germany. Nordpool requires generators to pay up to EUR 20 c/kWh for users to take excess electricity when demand is low, and in Germany the price has hit 50 c/kWh (at 5am on an October day in 2008). A similar situation arises locally in western Texas.

The USA is the only country which has offered any subsidy to nuclear power: a production tax credit of 1.9 c/kWh from the first 6000 MWe of new-generation nuclear plants in their first 8 years of operation (same as for wind power on unlimited basis). (In 2007 the USA subsidised renewables by $724 million and recorded $199 billion subsidy for nuclear power. The latter was entirely due to a change in tax rules related to decommissioning, under the 2005 Energy Policy Act.)

Escalating subsidies for renewables

A Eurelectric report in January 2004 looked at direct support levels for renewable electricity supply in 2001 and projections for 2010, assuming that present support mechanisms remained unchanged and that developments were in line with EU targets. The EUR 3.3 billion subsidy in 2001 was projected to grow to about EUR 11.5 billion in 2010, including EUR 7.4 billion for feed-in tariffs. The unit subsidy would then range from 0.4 c/kWh in Finland to 6.6 c/kWh in Germany, with a weighted average of 3.7 c/kWh in EU-15 countries (4.2 c/kWh in those with feed-in tariffs).

Table 3. Direct support for Renewable Electricity Supply
Country Subsidy
EUR million per yr
Subsidy
EUR cents/kWh
  2001 2010 2001 2010
Austria*
122
702
2.49
4.11
Belgium
27
55
2.7
2.70
Denmark*
273
499
4.19
3.87
France*
112
814
3.13
3.13
Germany*
1047
3326
6.21
6.58
Italy
1067
2493
6.31
5.88
Netherlands
59
679
1.98
5.69
Spain*
323
1537
2.78
2.65
Sweden
100
220
1.89
1.28
UK
96
547
1.73
1.45

* using feed-in tariff

 

Carbon taxes and emission trading schemes for carbon

Despite much rhetoric and considerable experience with the European Emission Trading Scheme (ETS) for carbon applying to certain sectors, no country imposes an economy-wide tax on greenhouse gases or has in place an economy-wide ETS. The EU's cap-and-trade ETS, in its first six years of operation, raised a little more than $2.5 billion.

Much of the justification for subsidising renewables is the avoidance of carbon dioxide emissions, due to the need for European countries to meet Kyoto targets. The 2004 Eurelectric report thus identifies cost of carbon emissions avoided. These in 2001 ranged from EUR 7/t of avoided CO2 in Finland to EUR 64/t in Denmark, EUR 74/t in Germany and EUR 100/t in Italy. Projections for 2010 have much higher costs: EUR 55/t for Denmark, EUR 109/t for Germany and Italy, EUR 148/t for France, and EUR 155/t for Netherlands. The weighted average is EUR 88/t and that for countries with feed-in tariffs EUR 103/t.

In 2011 an Australian Productivity Commission report surveyed much of the world scene. The report calculates the subsidy equivalent, abatement achieved and implicit abatement subsidy for policies and aggregated by sector in each country. Those for electricity generation are addressed here, and the following is largely from that source.

Estimates of abatement relative to counterfactual emissions in the electricity generation sector showed Germany significantly ahead, followed by the UK, then Australia, the USA and China. The estimated cost per unit of abatement achieved varied widely, both across programs within each country and in aggregate across countries. Emissions trading schemes (ETS) were found to be relatively cost-effective when not crowded out by other policies, while policies encouraging small-scale renewable generation and biofuels produced little abatement for substantially higher cost. What all schemes have in common is that they involve a cost, which someone must pay. These costs can be expressed in subsidy equivalent or resource cost terms, and can be considered as the ‘price’ of abatement achieved by particular policies.

International comparisons for electricity generation, 2010

  Abatement %
of emissions
Total electricity sector
emissions, t CO2
Implicit abatement subsidy
$/t CO2
Electricity price
uplift %
China 1-2 3370 35-37 1
USA 3 2270 43-50 -
Australia 3-5 196 44-99 1-2
UK 8-15 151 75-198 17
Germany 18-20 299 137-175 12-14
Japan 1 396 156-287 1
S.Korea <1 191 225-401 -

 

The most widely applied emissions-reduction policies in the electricity sector are mandatory renewable energy targets (most with tradeable permits), feed-in tariffs, and capital subsidies (often in conjunction with feed-in tariffs). Mandatory renewable energy targets apply at the national level in Australia, Germany and the UK (under an EU mandate), Japan, and South Korea (committed for 2012). Although the USA does not have a national level mandatory renewable energy target, over 41 states have renewable targets of one form or another, most mandatory. Feed-in tariffs apply at a national level in Japan, the UK, South Korea and Germany, and at a state level in Australia. China and India operate national and state/province-based schemes. Feed-in tariffs also exist in some US states, where they operate mainly as commercial arrangements between utilities and small-scale generators that the utilities use to meet their renewable energy targets. Capital subsidies are common, and provided for widely varying purposes.

External costs

However, the implicit subsidies where the waste products of energy use are allowed to be dumped into the biosphere are greater than these direct subsidies. The largest of them are given to fossil fuel producers. Nuclear energy has always had to cost in its own waste management and disposal (equivalent to about 5% of generation cost, with a further similar sum for decommisioning)*. Renewables only give rise to wastes in manufacturing, and while these are sometimes unpleasant they are dealt with in the same way as other manufacturing wastes.

* In the UK this has been patchy due to changing government policies, and major expenditure is now required to deal with legacy wastes arising from early nuclear power generation - effectively an external cost, albeit a historical one.

Consideration, and if possible quantification, of external costs aids life cycle analysis and technology comparison as well as cost-benefit analysis generally.

The report of ExternE, a major European study of the external costs of various fuel cycles, focusing on coal and nuclear, was released in 2001 and further figures have emerged since. The European Commission launched the project in 1991 in collaboration with the US Dept of Energy (which subsequently dropped out), and it was the first research project of its kind "to put plausible financial figures against damage resulting from different forms of electricity production for the entire EU".

The external costs are defined as those actually incurred in relation to health and the environment and quantifiable but not built into the cost of the electricity to the consumer and therefore which are borne by society at large. They include particularly the effects of air pollution on human health, crop yields and buildings, as well as occupational disease and accidents. The 2001 data excluded effects on ecosystems and the impact of global warming, but these are now included despite the high range of uncertainty in adequately quantifying and evaluating them economically.

The methodology measures emissions, their dispersion pathways and ultimate impact. Exposure-response models lead to evaluating the physical impacts in monetary terms. With nuclear energy the (low) risk of accidents is factored in along with high estimates of radiological impacts from mine tailings (since shown to be exaggerated) and carbon-14 emissions from reprocessing (waste management and decommissioning being already within the cost to the consumer).

The report shows that in clear cash terms nuclear energy incurs about one tenth of the costs of coal. Nuclear energy averages under 0.4 euro cents/kWh (0.2-0.7), less than hydro, coal is over 4.0 cents (2-10 cent averages in different countries), gas ranges 1-4 cents and only wind shows up better than nuclear, at 0.05-0.25 cents/kWh average.

The EU cost of electricity generation without these external costs averages about 4 cents/kWh. If these external costs were in fact included, the EU price of electricity from coal would double and that from gas would increase around 30%. A summary plus access to more recent work is on ExternE web site.

The report proposes two ways of incorporating external costs: taxing the costs or subsidising alternatives. Due to the difficulty of taxing in an EU context, subsidy is favoured. EC guidelines published in February 2001 encourage members states to subsidise "new plants producing renewable energy ... on the basis of external costs avoided", up to 5 c/kWh. However, this provision does not extend to nuclear power, despite the comparable external costs avoided. EU member countries have pledged to have renewables (including hydro) provide 12% of total energy and 22% of electricity by 2010, a target which appears unlikely to be met. The case for extending the subsidy to nuclear energy is obvious, particularly if climate change is to be taken seriously.

In that connection it is interesting to note the significant state subsidies to the coal industry in the EU, reported to total EUR 6874 million or EUR 190 per tonne in 2000. This includes operating aid, 'aid for reduction of activity', and other. In Germany alone, politically committed to phasing out nuclear energy and meanwhile finding new ways to tax it, EUR 4598 million was spent in subsidies to coal in 2000! Considerable effort was being given to finding ways to extend these subsidies beyond mid 2002.

Another European treatment of production and external costs, specifically of power generation in Switzerland (the GaBE Project), has been done by the Paul Scherrer Institut and shows that the damage costs from fossil fuels are 10 to 350% of the production costs, while those for nuclear are very small. A summary is accessible on the web, and the figure below is from it:

Switzerland Electricity

The twin bars represent the range of values for plants operating in Switzerland (Rp = cents SFR)

An earlier European study (Krewitt et al, 1999) quantified environmental damage costs from fossil fuel electricity generation in the EU for 1990 as US$ 70 billion, about 1% of GDP. This included impacts on human health, building materials and crop production, but not global warming.

The EC is undertaking a follow-on study to ExternE called NewExt to examine particular environmental costs and risks, mostly associated with fossil fuels.

In October 2009 a US National Research Council report commissioned by Congress quantified and analysed a total of $120 billion in "hidden" external costs of energy production in the USA in 2005. The figures reflect mainly health damage and exclude the effects of climate change. Electricity generation accounted for more than half, practically all being from coal.

The external cost of damages, primarily caused from sulfur dioxide, nitrogen oxide and particulate matter emissions from burning coal, were $62 billion, or 3.2 cents per kWh of electricity produced from it. The report expects damages from coal to fall to 1.7 c/kWh by 2030. Electricity produced from natural gas produced $0.74 billion in damages (0.16 c/kWh) in 2005, primarily from air pollution. For nuclear the figure was about 0.02 c/kWh. Motor vehicles produced $56 billion in health and other non-climate damages, considering the full life cycle of vehicles - only one third was from their operation. Electric and plug-in hybrid vehicles resulted in higher non-climate damages than other technologies, due to reliance on fossil fuels for the electricity. Energy used to create the batteries and electric motors adds 20% of the manufacturing portion of life-cycle damages.

Public health

Consideration of external costs leads to the conclusion that the public health benefits associated with reducing greenhouse gas emissions from fossil fuel burning could be the strongest reason for pursuing them. Considering four cities - New York, Mexico, Santiago and Sao Paulo - with total 45 million people, a paper in Science presents calculations showing that some 64,000 deaths would be avoided in the two decades to 2020 by reducing fossil fuel combustion in line with greenhouse abatement targets. This is consistent with a 1995 WHO estimate of 460,000 avoidable deaths annually from suspended particulates, largely due to outdoor urban exposure.

The World Health Organisation in 1997 presented two estimates, of 2.7 or 3 million deaths occurring each year as a result of air pollution. In the latter estimate: 2.8 million deaths were due to indoor exposures and 200,000 to outdoor exposure. The lower estimate comprised 1.85 million deaths from rural indoor pollution, 363,000 from urban indoor pollution and 511,000 from urban ambient pollution. The WHO report points out that these totals are about 6% of all deaths, and the uncertainty of the estimates means that the range should be taken as 1.4 to 6 million deaths annually attributable to air pollution.

Life cycle CO2 emissions

Turning to carbon dioxide, if all energy inputs are assumed to be from coal-fired plants, at about one kilogram of carbon dioxide per kWh, it is possible to derive a greenhouse contribution from the energy input percentage of output. However, For Sweden's Forsmark as many energy inputs are not fossil fuel, its life cycle analysis (2002 data) give it the very low CO2 emission figure of 3.1 g/kWh.

In France, despite energy-inefficient enrichment plants which are run by nuclear power, the greenhouse contribution from any nuclear reactor using French-enriched uranium is similar to a reactor elsewhere using centrifuge-enriched uranium -- less than 20 g/kWh overall.

Figures published in 2006 for Japan show 13 g/kWh, with prospects of this halving in future.

Older figures published from Japan's Central Research Institute of the Electric Power Industry give life cycle carbon dioxide emission figures for various generation technologies. Swedish utility Vattenfall (1999) published a popular account of life cycle studies based on the previous few years experience and its certified Environmental Product Declarations (EPDs) for Forsmark and Ringhals nuclear power stations, and a similar exercise was undertaken in Finland by Kivisto et al. The sets of data compare as follows:

g/kWh CO2 Japan Sweden Finland
coal
975
980
894
gas thermal
608
1170 (peak, reserve)
-
gas combined cycle
519
450
472
solar photovoltaic
53
50
95
wind
29
5.5
14
nuclear
22
6
10-26
hydro
11
3
-

The Japanese gas figures include shipping LNG from overseas, and the nuclear figure is for boiling water reactors, with enrichment 70% in USA, 30% France & Japan, and one third of the fuel to be MOX. The Finnish nuclear figures are for centrifuge and diffusion enrichment respectively.

Energy-related accidents

A November 1998 study from the Paul Scherrer Institut in Switzerland, more recently available in English, examines other aspects of external costs. The 400-page report was commissioned by the Swiss Federal Office of Energy, and draws on data from 4290 energy-related accidents, 1943 of them classified as severe, and compares different energy sources. It considers over 15,000 fatalities related to oil, over 8000 related to coal and 5000 from hydro - in total, about seven World Trade Centres. It points out that Full Cost Accounting, including both internal and external costs, is increasingly used for electric utility planning, though not on any standard basis, and not without considerable practical difficulty in assigning costs. Also it is notable that for any specific energy chain, different parts are often in different countries.

Considering only deaths and comparing them per Terawatt-year, coal has 342, hydro 883, gas 85 and nuclear power only 8 (/TWe.yr). (Nuclear power delivers some 2500 TWh per year, hence these 8 deaths would be spread over 3.5 years in the course of providing 14% of the world's electricity, whereas coal's 342 deaths can be expected every 19 months for slightly more than twice the amount of electricity.) In terms of number of immediate deaths per event from 1969 to 1996, hydro stands out with about 550 compared with coal at about 40.

Deaths per TWyr

In the period from 1975, typically about 30 energy-related accidents with at least five fatalities occurred every year, including 1-5 with over 100 fatalities.

The new report updates and confirms an earlier study covering 1970-92.

A further OECD report in 2010 yields the following figures:

Summary of severe* accidents in energy chains for electricity 1969-2000

  OECD Non-OECD
Energy Chain fatalities fatalities/TWy fatalities fatalities/TWh
coal 2259 157 18,000 597
natural gas 1043 85 1000 111
hydro 14 3 30,000 10,285
nuclear 0 0 31 48

Data from Paul Scherrer Institut, in OECD/NEA 2010 Comparing Nuclear Accident Risks with those from other energy sources.

* severe = more than 5 fatalities

The adoption of any policies or conventions to take account of external costs of generating electricity will have a very beneficial effect on the prospects for any strong resurgence in the role of nuclear energy.

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