Tuesday, 21 October 2014

A Forgotten Issue?

By Kirsten Jenkins and Darren McCauley, University of St Andrews.  This article first appeared in the summer 2014 edition of the RSGS's magazine, The Geographer.

Two issues continue to dominate the political and legal landscape of an energy-independent Scotland: renewables, and oil and gas. Geography and geology unite to produce an irresistible combination, or flatter to deceive depending on your viewpoint. Yet, whilst analysts mull over claim and counter-claim, one issue of geopolitical importance remains for Scotland – the nuclear question. Often tied up with demilitarisation and Trident, domestic electricity generation from nuclear power is perceived to be a fait accompli in the independence debate. Surely ‘Yes Scotland’ and ‘Better Together’ have united in saying ‘no’ to domestic nuclear-generated electricity? We ask here what ‘no’ actually means, and whether it is indeed possible.

Scotland is no stranger to nuclear-generated electricity provision. Since the late 1950s, nuclear has played an important role in Scotland’s energy mix, with a total of six reactors providing consistent baseload electricity, which, even now, provide around 34% of our electricity produced. From Chapelcross, Hunterston A and B, Torness, East Kilbride and Dounreay, nuclear has played a fundamental role in keeping Scotland’s lights on. But nuclear’s card is marked. Under the current Scottish Government, nuclear has fallen firmly out of favour, as they state in no uncertain terms that there’s to be no further nuclear electricity generation development. This, despite increasing support for nuclear over the border, with plans for a new reactor at Hinkley Point C. Instead, the Scottish Government, which controls its own planning and infrastructure, holds ambitious targets to supply the equivalent of 100% of domestic electricity consumption in Scotland from renewable energy by 2020. For current reactor facilities this signals the end of an era, as all Scottish reactors face increasingly frequent maintenance outages and the threat of imminent decommissioning. Without renewal, all of Scotland’s nuclear capacity is set to ‘dry up’ by 2035. The challenge of renewing Scotland’s energy mix, therefore, has never been more pressing. In the midst of these challenges, and with some disquiet surrounding the achievability of Scotland’s renewable aims, the role of nuclear is increasingly called into question.

The main challenge is that a devolved power, for example Scotland, has no legislative competence over nuclear energy installations, yet it has full legislative competence in respect to environmental matters and planning. The Scottish Government has rejected the idea of deep geological disposal facility (GDF) and new nuclear build. However, this does not answer the question of what happens to radioactive waste at Scottish nuclear sites and the legacy waste Scotland currently stores at Sellafield in Cumbria. This issue, whilst it has long been acknowledged, has been further intensified by the Scottish independence campaign and, as David Cameron stated in December 2013, “there is therefore a mesh of vertical and horizontal lines of authority that will impact upon policy implementation”.

If Scotland gains independence from the UK, the waste must return to Scotland, where there are neither facilities nor legal framework in place to deal with the problem. Further, will it be necessary to develop a new legal framework in which Scottish taxpayers are liable for their share of the cost of keeping the waste in England? Considering that the UK has not yet enacted any legislation directly concerning nuclear waste, the problems created by Scottish independence – or, in what seems to be the likely minimum outcome, near complete devolution – are a real dilemma.

The UK is advancing its own policy in the area, but the Scottish Government has yet to fully engage with this issue in the debate on independence. An independent Scotland would need its own independent nuclear waste storage facility and, in having a reduced number of nuclear energy plants, would not benefit from economies of scale. Moreover, the timescales in question mean that the existing Scottish nuclear power sites will be decommissioned before any robust interim storage facility or GDF would be built. This inevitably has the potential to become a real challenge for Scotland in the near future.

There is need, therefore, to more thoroughly and openly tackle the true role of nuclear electricity generation in an independent Scotland, and to acknowledge its often-sidelined implications. The knowledge that Scotland is simultaneously dependent on nuclear, wary of nuclear, and ill-equipped to deal with nuclear waste independently, signals real trouble ahead. Nuclear is an issue that we best not forget.

Saturday, 18 October 2014

Flooding in Oxfordshire, February 2014.  Photo: Julia Lawrence.
Potential influences on the United Kingdom's floods of winter 2013-14
Dr Chris Huntingford, Centre for Ecology & Hydrology

Last winter, severe flooding affected large parts of the UK.  In a paper published in Nature Climate Change, scientists at the Centre for Ecology & Hydrology, working with colleagues from the Met Office and a number of universities, looked at the possible drivers behind the floods.  Chris Huntingford, a climate modeller based at the Centre for Ecology & Hydrology in Wallingford, Oxfordshire, was the lead author of the paper.

None of the individual rainfall events in the UK in recent months was unprecedented, but the weather patterns behind them persisted for three months causing a near-continuous succession of westerly storms.  This had the cumulative effect that for much of the southern UK, the total winter rainfall was record-breaking.  Preliminary analysis suggests that particularly warm ocean conditions and heavy rainfall in and around Indonesia triggered wind patterns across the Pacific that travelled northwards before ultimately drawing cold air down across the USA.  This in turn forced a particularly strong and persistent jet stream across the Atlantic and towards the UK.  The Met Office is now studying this sequence of events in significantly more detail.

Questions arise as to whether fossil fuel burning could have a role.  We have reviewed existing research literature for Earth system factors that may be both changing through global warming, and additionally are identified as influences on storm features for the UK.  As expected, this confirms how complex and interconnected the climate system is.  Multiple possible UK rainfall drivers are identified that link to the state of the oceans, the atmosphere and sea-ice extent.  Interestingly the recent rapid decrease in Arctic sea-ice that is widely attributed to global warming, for the UK at least is often portrayed as likely to bring more easterly winds and colder conditions.  The previous three winters had these features for some of the time, in marked contrast to winter 2013-14.  Although the precise details of linkages between changing large-scale features of the climate system and UK rainfall intensity are still not fully understood, we hope our review article is a complete list of such connections.  To apply that frequently used expression, we trust there are no ‘unknown unknowns’ lurking out there we have yet to consider.

Assuming that we do have a pretty good idea of all drivers expected to affect rainfall, and that require on-going computer modelling, three challenges are noted in how to proceed.  These are: (1) the need for continued enhancement of physical process representation via ever better parameterized differential equations of the oceans, atmosphere and ice-sheets; (2) increase further the numerical grid resolution of climate models, on which these equations are calculated; and (3) undertake significantly higher numbers of simulations, all with slightly different initial conditions, creating a large ensemble of projections.  The call for better resolution is because some characteristics of storms occur on fine spatial detail, thus needing small spacings between grid-points on which calculations are updated.  The request for large ensembles is because extremes, by definition, are rare events, and so we need to ensure that all heavy rainfall ‘return times’ are fully sampled.  This is both for pre-industrial and for raised levels of atmospheric greenhouse gases.

During the major flood events affecting much of southern England from December 2013 to February 2014, it was inevitable that questions would be asked as to whether fossil burning could have a role.  It is always (and correctly) stated that no single observed extreme event can be formally attributed to human-induced changes to atmospheric composition.  But a statistic can be derived that assesses any changing probability of a particular extreme event occurring, a quantity sometimes referred to as ‘Fractional Attributable Risk’.  By satisfying the three challenges we listed above, we will get near to stating if humans are increasing, decreasing or leaving invariant the chances of rainfall events of the type witnessed.  However, even now limitations remain on computer speed and resource, and expenditure on climate research can only ever be finite.  Hence an especially lively debate will now occur as to what constitutes the optimal balance between pursuing these three challenges, in order to get us most quickly towards the required answers.

Anyone studying meteorological systems, or the full Earth system, soon realizes of course how tightly coupled all features are of the climate system.  In this review, by trying to collate in to a single paper the main factors affecting UK rainfall, this did though provide a timely reminder of such comprehensive interconnections.  Understanding these further suggests a very interesting time lies ahead for climate change research.

Thursday, 16 October 2014

Unconventional gas

By Lin Bunten, Head of Operations – Energy, Scottish Environment Protection Agency. This article first appeared in the summer 2014 edition of the RSGS's magazine, The Geographer.

While evidence has shown that the extraction of unconventional gas can present a number of risks to the environment, and some of the technologies being used in this area are new to environmental regulators, many of the processes (such as borehole construction) are not new, and neither is the job of regulating those practices to ensure that they do not harm the environment.

In Scotland, the main type of unconventional gas currently undergoing exploration is coal bed methane (CBM). Unlike shale gas, CBM extraction does not necessarily require fracking, as the seams already naturally contain fractures or fracture easily. In Scotland, as in the rest of Europe, the industry is relatively new and operations are still in the exploration stage.

There are currently three active exploration sites in Scotland: Airth, Falkirk; Deerdykes, North Lanarkshire; and Canonbie, Dumfries & Galloway. These sites have been granted planning permission by local authorities, and licences by SEPA and other regulatory bodies, to carry out exploration drilling. Planning permission is currently being sought for CBM production at Airth.

Regulation - SEPA is just one of a number of organisations involved in regulating unconventional gas extraction in Scotland, along with the Department of Energy and Climate Change (DECC), local authorities, the Health and Safety Executive, and The Coal Authority. We are committed to ensuring that there is a high level of protection for the environment, and we believe that, along with other regulatory bodies, we have a wide range of regulatory tools that can be used effectively to control and mitigate the environmental impacts that may be caused by unconventional gas activities.

We believe these regulatory tools already provide a high level of protection to the environment, but if further evidence demonstrates that more protection is required, we will support the Scottish Government in bringing forward further measures.

Environmental Issues - Potential environmental impacts can include effects on groundwater and surface water from drilling and fracturing, and increased greenhouse gas emissions and health impacts from fugitive gas releases.

Effects on groundwater and surface water -SEPA is responsible for protecting and improving the environment of Scotland, and we do this by enforcing a number of regulations designed to protect the air, land and water environment. For example, the Water Environment (Controlled Activities) (Scotland) Regulations (commonly known as CAR) control:

• potential risks of cross-contamination of aquifers due to poor borehole construction;

• pollution from an unexpected release of gas or fracturing fluid into other parts of the water environment;

• pollution from the uncontrolled disposal of liquid or solid waste;

• the abstraction of uncontrolled quantities of water.

Increased greenhouse gas emissions and health impacts - Emissions of methane and other volatile organic compounds are regulated by local authorities under the Management of Extractive Waste (Scotland) Regulations 2010, and by SEPA through the Pollution Prevention and Control (Scotland) Regulations 2012 (PPC). The PPC regulations are designed to control emissions to the environment from certain specified activities. The initial exploration for gas, drilling etc does not require a PPC permit. However, the extraction process cannot begin unless all required environmental licences are in place.

As well as contributing to climate change, fugitive emissions have the potential to impact on human health and the environment. SEPA and the local authority will ensure that operators make full use of technologies that reduce fugitive emissions to air and undertake comprehensive monitoring during production to assess health risks, which will help inform regulation.

The Scottish Government has set ambitious targets for reducing greenhouse gas emissions, and the impact of unconventional gas extraction on these targets has not yet been fully assessed. ClimateXChange is currently commissioning a research project to estimate greenhouse gas emissions associated with the exploration and extraction of onshore unconventional gas in Scotland, and how these compare to other energy sources

Tuesday, 14 October 2014

The untold story of CSG expansion in Australia

Dr Mariann Lloyd-Smith PhD (Law), Senior Policy Advisor, IPEN – International POPs Elimination Network, and Senior Advisor, National Toxics Network Inc. This article first appeared in the summer 2014 edition of the RSGS's magazine, The Geographer.

Exploration and production of natural gas from unconventional sources such as coal seams and shale are rapidly expanding in Australia, with a predicted 40,000 coal seam gas (CSG) wells to be developed in Queensland alone. Community concerns over the contamination of groundwater, surface water and air are escalating, bringing together an unlikely alliance of farming communities and environmentalists united in their opposition to further development of unconventional gas fields. Recent New South Wales legislation introducing a 2km buffer zone around urban areas and certain agricultural infrastructure has seen some Australian CSG companies leave Australia to pursue opportunities in the UK, Ireland and Europe where such restrictions do not exist.

Opposition to CSG and shale gas has grown in Australia as more evidence of pollution and the environmental and social impacts on rural communities has come to light. The limited publicly-available data on chemical use and releases in the drilling and production stages has increased concerns around the potential for water pollution and the public costs of managing the wastes.

‘Fracking’ (hydraulic fracturing) involves injecting wells at high pressure with water, proppants, radioactive tracers and chemical additives, to fracture the formation and produce new cracks and pathways to help extract the gas. While industry claims that chemical additives are minimal, consisting of less than 2% of the fracking fluid, a risk assessment provided to the Queensland Government identified c18,500kg of chemical additive used per well, with up to 40% not recovered. These quantities, although extraordinary, were consistent with the 2011 European Parliament report which estimated 16,000kg of acutely toxic substances were used to frack tight gas in Lower Saxony, Germany. Wells may also be fracked a number of times.

The chemicals listed in the risk assessments included surfactants, lubricants, acids, scale and corrosion inhibitors, and biocides. Some chemical ingredients could not be identified in the Material Safety Data Sheet (MSDS) due to commercial confidentiality, but of those identified, many had acute or chronic toxicity warnings. The majority had only limited data on environmental fate and ecotoxicology.

Waste Water - CSG activities generate large quantities of ‘produced’ water, reported by Australian industry to be 0.1-0.8 megalitres per day. Produced water may be contaminated with heavy metals, naturally-occurring radioactive substances, fracking or drilling chemicals, high quantities of salt, BTEX (benzene, toluene, ethylbenzene, xylene), and naturally-formed halogenated chemicals. Currently, produced water in Australia is managed by ‘storage’ in large holding ponds, used for dust suppression on roads, ‘treated’ and released into waterways, or sold on for use in irrigation.

Water Contamination - In 2011, bromine was detected in treated and released CSG water at six times background levels. Methane, not detected in the upstream control sample, was detected at 68 micrograms per litre. In Australia, there has been little comprehensive testing of groundwater, despite the fact that industry has reported BTEX chemicals in five out of 14 monitoring wells in Queensland.

Proppants and Silicosis - The extensive use of proppants is also causing concern. Proppants consist of either sand/silica or manufactured ceramic polymer spheres based on alumino-silicates, which are injected as part of the fracturing fluid mixture and intended to hold open the fractures once the pressure is released. Breathing silica can cause silicosis, is a known cause of lung cancer, and is suspected of contributing to autoimmune diseases, chronic obstructive pulmonary disease, chronic kidney disease.

Methane and Climate - Impacts Unconventional gas is promoted as a ‘cleaner fossil fuel’ compared to coal, but ongoing concern over the climate impacts of the lifecycle of gas from shale and coal seams has resulted in Australian research on the industry’s fugitive emissions. Researchers have suggested that CSG activities change the geological structure and enhance diffuse soil gas exchange processes, helping gases to seep through the soil to be released to the atmosphere.

Air Pollutants - While there are few publicly- available reports of formal air monitoring data related to CSG activities in Australia, limited government and community sampling of ambient air around CSG activities has detected many VOCs. Residents report symptoms of severe headaches, nausea, vomiting, nose bleeds, eye and throat irritations, severe skin irritations and paraesthesia in children. A preliminary health investigation by the Queensland Health Department concluded there was “some evidence that might associate some of the residents’ symptoms to exposures to airborne contaminants arising from CSG activities”.

Conclusion - With no baseline data collected prior to the CSG and shale activities, it is impossible to clearly establish cause and effect relationships. However, there can be no doubt that both community and environmental health has deteriorated in certain regions since the unconventional gas industry was established. If a proper cost-benefit analysis had been done prior to granting approvals for these projects, regulators and governments may have concluded that this industry was simply not worth the risks to community and environmental health.

Saturday, 11 October 2014

Biomess? – fuel for thought

By Dr Dan van der Horst, University of Edinburgh. This article first appeared in the summer 2014 edition of the RSGS's magazine, The Geographer.

Making and controlling fire was perhaps the single most important invention that allowed humans to conquer the planet; keeping us warm and safe, improving our food, and transforming our landscapes. Even today, biomass energy is the most important source of energy in many developing countries. But the production of liquid biofuels, a policy pursued by the EU and the US, is highly controversial with environmental, social and conservation NGOs, even if most people in Scotland have no idea it is in their fuel tanks. In this short piece I will not revisit the extensive debate of how biofuels impact on food production and biodiversity, and what it would take to reduce or control these effects. Instead, I focus on a few home truths about biofuels that have received less attention to date.

The economic problem of biofuels is that they are, under most conditions, a relatively expensive way to reduce carbon emissions, so public money could be better spent on other low-carbon interventions. Whilst other renewables may experience technological breakthroughs or significant price reductions due to mass production, this is far less likely to happen for biofuels as they are based on a feedstock that has to be grown on land, which comes with an opportunity cost.

First generation biofuels (ethanol made from starchy or sugary crops, or biodiesel made from plant oil) are only a good value product in a market where food prices are low and petrol and diesel prices are high. Unless food production is subsidised and fossil fuels are taxed, these are rare conditions. In the absence of subsidies, we can perhaps envisage such conditions in a very remote corner of Africa where people can produce a surplus of food but cannot export it due to very poor transport links, which in turn also make the import of diesel and petrol very expensive.

Biofuels could have a useful role to play in an oil-importing developing country that is selfsufficient in food production but is struggling to sell its agricultural exports on the world market, for example because of logistical bottlenecks or import tariffs. Under these conditions, biofuel production could be a useful way to enhance the trade balance (spend less hard currency on importing oil) and boost the rural economy instead. This is how Brazil came to adopt their sugar-to-ethanol programme.

The carbon problem of second generation biofuels (made from inedible, woody biomass) is that there are better uses of the feedstock: using biomass as building material will store carbon for decades or longer. And when the time comes to dispose of these materials, they can still be burned for energy recovery. If there is a suitable place for biofuels in an industrial country, then it is first and foremost in integrated waste management. In the first decade of the 21st century, the UK was producing more renewable energy from biomass than from wind. This was not because we have big agricultural or forestry sectors, but because we were implementing the EU waste directive, which told us to cap landfill sites and capture the methane that emerges from them. Some of the largest anaerobic digestion plants in Europe are now found in the West Midlands; modern centralised facilities for treating sewer sludge and food waste. It could even be argued that we would have no need for a separate energy policy, if our other policy domains, such as foreign policy, environmental policy and economic policy, were more coherent and integrated.

At the end of the day, there is one very simple fundamental problem for biofuels. If you want to extract the highest possible value from a product, that product has to be very cheap and plentiful to ensure that putting it on fire is the best option. Smoking (whatever...) is just the exception that proves the rule.

Thursday, 9 October 2014

Affording Coal

By Mike Robinson, RSGS Chief Executive. This article first appeared in the summer 2014 edition of the RSGS's magazine, The Geographer.

Global energy is changing. Energy usage has trebled in the last 50 years, importing nations are becoming exporters, and whilst oil remains the largest source of primary energy in the world, its persistently high price has opened up the viability of a range of alternative energy types.

However, fossil fuels still dominate the global energy mix, providing more than 85% of global energy, and of these it is coal that has seen the fastest-growing demand of all. In a recent global review, the International Energy Agency (IEA) stated that there was the equivalent of 142 years of proven reserves of coal at current consumption rates (compared with 61 years of proven reserves of natural gas and only 54 years of oil). The World Coal Association, an industry representative group, further claims that the remaining recoverable resources of coal are more than 20 times larger. Of course, these estimates are based on current usage, and only a small increase in annual demand could cut the number of years significantly. For example, if coal saw even a 5% per annum growth, reserves would fall from 142 years to c45 years.

So, coal is the fastest-growing energy source. It is effective. There’s still a lot of it. And it is also relatively cheap. Sounds great. But coal has a problem. It is not called ‘dirty coal’ for nothing and, along with its immediate health and environmental impacts, coal has the highest carbon content (and therefore the highest carbon emissions) of any fossil fuel. In 2011, coal produced about 30% of global energy use, but accounted for around 44% of global carbon dioxide emissions; and historically it is responsible for more global emissions than any other fuel source.

As IEA Executive Director Maria van der Houven stated recently, “Irrespective of its economic benefits for the countries, the environmental impact of coal use, especially that coming from carbon dioxide emissions, should not be overlooked.”

Being the most available fossil fuel, and the cheapest, it is unlikely that people, companies and nations are going to be successfully persuaded to give it up, even though many of its damaging costs are ‘externalised’. Poland, for example, which hosted a recent round of IPCC climate negotiations (and simultaneously ran a major coal conference in the nextdoor stadium), uses coal almost exclusively (85% of electricity production) and is not going to give up its own energy security just for the climate without a very significant incentive.

The Obama administration unveiled historic environmental rules in June to cut carbon pollution from power plants by 30% – the first time any president has moved to regulate this carbon pollution – in large part by targeting reductions in coal use. The only hope for the climate in relation to coal, other than simply cutting our use of coal dramatically, is to find a way to capture some of the fossil fuel emissions from burning coal and store them somewhere where they can’t ‘leak’ or seep out into the atmosphere. This process of carbon capture and storage (CCS) is yet to be tested at any significant scale, and will cost significant money and energy to implement.

However, whilst CCS is only a partial solution (potentially reducing coal’s carbon emissions to those of natural gas), it feels increasingly more necessary. Even in the UK, where no new coal-fired power stations have been built for years, 39% of our electricity comes from coal-fired plants. So despite CCS remaining an uncertain technology, domestically and globally we probably need to see CCS developed successfully if we are going to keep burning coal and want to maximise our chances of avoiding dangerous climate change.

However, whether CCS works or not, we need to try to limit our use of coal. Several of the proposed key steps to reducing global carbon emissions include replacing coal with gas power, replacing coal with wind, or replacing coal with nuclear power. All of these would make major inroads to global emissions. Coal is fairly evidently a fossil fuel that we cannot ultimately afford, except in moderation.

This is, in part, what drives the development of renewable energy sources. The IEA reported last year that “global subsidies to renewables reached $101 billion in 2012, up 11% on 2011, and need to expand to $220 billion in 2035”. However, it is worth noting that the same body estimated that fossil fuel subsidies increased to $544 billion in 2012.

If we are going to solve the conundrum of how to achieve energy security, environmental sustainability, and economic prosperity simultaneously, we need to see some of this fossil fuel subsidy directed towards renewables and perhaps the development of CCS. However, CCS is a costly technology and if coal has to start paying for its environmental damage and other externalities like the cost of CCS, it no longer looks so economically attractive, which is why many commentators believe the fossil fuel subsidies would be better spent purely on renewable alternatives.

Tuesday, 7 October 2014

Scotland’s renewable energy transition: quo vadis?

By Professor Paul L Younger FREngg, Rankine Chair of Engineering and Professor of Energy Engineering, University of Glasgow. This article first appeared in the summer 2014 edition of the RSGS's magazine, The Geographer.

The Scottish First Minister memorably remarked in 2011 that Scotland could come to be seen as “the Saudi Arabia of renewable energy”. Three years later, with the Scottish independence referendum looming, it seems a good time to ask whether this is feasible. The Scottish Government has set ambitious targets to position Scotland in the premier league of renewably-powered nations. In summary, by 2020 the Scottish Government plans to have 30% of total Scottish energy use met by renewable sources. As energy includes heat (55% of Scottish energy use in 2011), transport (24%) and electricity (21%), separate targets for each of these modes have been set.

The electricity target always grabs the limelight: an equivalent of 100% renewable by 2020. This does not mean that all energy consumed in Scotland at that time will be renewable; rather, it effectively means that over a year (say) Scotland will export enough renewably-generated electricity to match the non-renewable element of its domestic consumption. Logically, if we really want to reduce Scotland’s contribution to climate change, we would be prioritising development of renewable heat. However, the 2020 target for renewable heat (11%) is even more modest than that of the UK Government (12%). At present, mainstream suggestions for decarbonising heat invoke electrification, on the assumption that electricity will soon be decarbonised. This would imply increasing the total amount of electricity generated by a factor of 2.5. But will Scotland’s renewable electricity generation be up to the job?

Renewable electricity supply in Scotland has a distinguished pedigree, dating back to the commissioning of the Galloway Hydros scheme in 1935. Many large hydropower systems were constructed in the Highlands during the 1950s, but development then slowed to a trickle, with only one sizeable new hydropower station being built since 1963 (the 100 MW Glendoe system commissioned in 2009). The current total installed hydropower capacity in Scotland is around 1.5 GW.

Estimates from Heriot-Watt University indicate that, given the imperative of conserving scenic glens, this could only be expanded by about 50%, mainly through small schemes. This is frustrating, as hydro is less variable in output than other renewables, albeit it is notably vulnerable to inter-annual variations in rainfall. In 2013, Scotland’s hydropower stock produced around 15.5 petajoules (PJ) of electricity, which amounts to 10.3 PJ per GW installed. This is significantly better than wind, which produced 8.9 PJ per GW installed. Yet even if all of Scotland’s remaining hydropower potential were to be developed over the next few years (which it will not be, given the lead times involved), it could not contribute more than 10% of the additional renewable electricity capacity needed by 2020.

Given Scotland’s weak solar resources (amongst the weakest in sub-polar Europe), and given that wave and tidal technologies remain nascent and exorbitant, wind is the only option for meeting the 2020 renewable electricity target. What does this mean in terms of further expansion of installed wind capacity? Scotland currently uses around 132 PJ of electricity per annum, and given the ambitions for economic growth and expansion of electricity use for heat and transport, we can assume that the 2020 figure will be some way north of this. In 2013, Scotland generated a record amount of electricity from renewable sources: 61.2 PJ, or 46% of Scottish electricity demand.

Given the proven annual productivity of Scottish wind farms, this means that a further 70.8 PJ will have to be generated by wind in 2020, which equates to 9 GW extra installed capacity. This is a realistic prospect: around 4 GW of onshore wind already has consent with a similar amount in planning; 5 GW of offshore wind is also in planning, though the recent cancellation (or ‘postponement for at least a decade’) of the 1.8 GW Argyll Array offshore from Tiree casts some doubt on the degree to which this will be deployed by 2020. Nevertheless, it seems likely that renewable electricity generation in Scotland can indeed meet the 2020 target.

This is where things get interesting though. Due to natural variability of wind speeds, onshore wind in mainland Scotland struggles to exceed a capacity factor of around 30% (ie, the proportion of the time it is actually producing significant amounts of electricity). This means that, even with 100% equivalent renewable capacity installed, some other source of electricity will always be required for more than two-thirds of the time. Thus, ensuring a 24/7 power supply will always need a combination of baseload (ie, constantly-available) and dispatchable (ie, available on demand) electricity sources. (Electricity storage also has a role to play, but it is sufficiently costly that it is difficult to see this expanding beyond the niche application of marginal load balancing). The problem is that most baseload and dispatchable sources of power cannot be switched on or off within the timescales over which wind output fluctuates.

Much of Scotland’s baseload is provided by its two remaining nuclear power stations, Hunterston B and Torness, which between them produced 34.5% of Scotland’s electrical output in 2012. Some baseload, and virtually all of the dispatchable output, was provided by just two power stations: Longannet (coal-fired, 25%) and Peterhead (gas-fired, 8%). Although the outputs of these fossil-fired power stations can be tweaked over a timescale of hours, they cannot be adjusted instantaneously as wind speeds wax and wane. Thus when we say Scotland produced 46% of all its electricity renewably in 2013, we need to be clear that much of this had to be exported to England. Indeed, Scotland’s 100% renewable electricity target is absolutely dependent on it continuing to export to England.

The net export in 2012 was 26.1%; yet there are early signs of changing fortunes for Scotland’s electricity export business. The four remaining non-renewable power stations in Scotland were until recently five: Cockenzie (coal-fired) closed in 2013 and will shortly be demolished. Since Cockenzie was taken off-line, Scotland has begun to experience periods in which it is reliant on electricity transfers from England. This happened on about ten days in 2013.

The Scotland-England interconnectors have hitherto always flowed N-S. This change in polarity represents the increasingly tight margins of baseload and dispatchable capacity in Scotland. At present, no new power stations with such capability are under construction in Scotland. Moreover, under current plans Scotland will lose its two nuclear power stations in 2023 – and with them a third of its electricity output, and the core of its baseload. Meanwhile, Longannet is ageing (it was originally commissioned in 1973), and notwithstanding recent upgrades, it is not currently expected to remain in service beyond 2025. Scottish Government policy precludes any replacement nuclear or coal-fired power stations, so in little more than a decade almost all of Scotland’s baseload and dispatchable generation capacity will have gone. That already leaves us barely enough time to design, obtain consent for, and construct alternatives. The only alternative of sufficient scale deployable to such a deadline is gas-fired generation.

Unless unconventional gas developments are permitted and succeed, Scotland will continue to be poorly endowed with natural gas resources. The majority of the North Sea gas fields are offshore England. Gas separated from Scotland’s oil fields is currently burned for power generation at only one site. Yet Peterhead has seen steady decline in capacity, from 2.2 GW in the early 2000s, to 1.1 GW in 2010; by April 2014 it was just 0.4 GW. These reductions have been ascribed to uncertainty over future prices for fossil-fired generation, coupled with transmission cost penalties for power stations in remote locations.  Neither of these factors auger well for construction of replacement, non-coal, non-nuclear, baseload or dispatchable capacity in Scotland within the next decade.

But does this matter? Can’t England provide these services to Scotland, while Scotland virtuously sticks to renewable generation alone? The current connector capacity is nominally 4.4 GW, though in practice this is limited to 3.3 GW due to thermal stability problems. A new 2.2 GW connector from Hunterston to North Wales is currently under construction.

We can therefore rely on an England-Scotland connector capacity of around 5.5 GW: this amounts to just 40% of Scottish peak demand, and closely approximates the amount of power output currently coming from Scotland’s nuclear and fossil-fired power stations (5.4 GW). There is no room for manoeuvre, and no guarantee that England (which has similar problems of its own) will have the spare capacity to feed power north when Scotland stands in need. We live in interesting times.