Posts by: Dave Elliott

Water, Energy and other resources

By Dave Elliott

Energy resources aren’t the only thing we are running short of. Water resources could be the next big issue. And conventional energy systems have a big impact on that and will be affected by water scarcity. All thermal/steam raising energy systems need cooling, and maintaining access to water is likely to become a major problem for fossil and nuclear plants as climate change impacts: (more…)

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Land use and energy

By Dave Elliott

By their nature, renewable energy flows are diffuse and the technology for capturing energy from the flows has to cover relatively large areas. It is instructive, and sobering, to revisit Professor David MacKay’s calculations about the areas required to match the energy needed per person from renewable sources:

However, as I noted in an earlier post (on his comparisons between wind/solar and shale gas), some of his analysis is a little limited, and the general conclusions have to be put in perspective. (more…)

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Green energy transformations

By Dave Elliott

The International Energy Agency (IEA) has released a new report “the Power of Transformation”, which concludes that the integration of large amounts of renewable energy can be achieved by any country at only a small increase on whole system costs, compared with the current fossil-fuel-heavy electricity systems. The IEA used present-day costs for solar PV and wind, which are likely to continue to fall, with wind and PV being set to provide the bulk of the generating capacity in transformed electricity systems. (more…)

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PV solar – is that all we need?

By Dave Elliott

PV solar is booming, as I noted in my last post, with over 130 GW in place globally and some see it as overtaking all other renewables, with prices falling dramatically. Indeed a new study “The Economics of Grid Defection” by the US Rocky Mountain Institute (RMI) says that PV solar and new cheap battery technology will soon mean that we won’t need power grids. (more…)

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PV solar versus wind

By Dave Elliott

With costs falling rapidly, PV solar is moving ahead fast and some see it as likely to become a major renewable source in the future, if not the dominant one. The World Energy Council notes that in its new Symphony global energy scenario, “by 2050, globally, almost as much electricity is produced from solar PV as from coal,” and Shell’s recent “Oceans” scenario saw solar as being the largest single energy source globally by 2060. (more…)

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Water source and gas fired heat pumps

By Dave Elliott

Heat pumps are seen as a clever way to get an energy upgrade, with the input energy driving a compression cycle, pumping heat collected from outside a building into radiators inside, like a fridge working in reverse. Most systems use heat from the air or from the ground, but there are also some water-source systems. For example there are large water-source heat pump schemes in Scandinavia, feeding heat to district heating networks. About 60% of the total energy input for Stockholm’s Central Network is provided by a district heating plant with six large heat pumps using the sea as a heat source. Warm surface water is taken during summer, while in winter, the water inlet is in 15m depth where the temperature is at constant +3°C. Helsinki in Finland also has large heat pump plant producing district heating with capacity of 90 MW, as well as cooling, with capacity of 60 MW, using heat from the sea and from wastewater led into the sea from a central wastewater treatment plant.

These are large projects, but a medium-scale system is being developed in the UK, using Mitsubishi’s Ecodan pump, which was voted the best new product or technology at the 2014 Climate Week Awards. It’s the first application of a system of its kind in the UK, and is backed Mike Spenser-Morris, a local developer and director of the Zero Carbon Partnership. The heat pump will use the Thames to provide hot water for radiators, showers and taps in nearly 150 homes and a 140-room hotel and conference centre at Kingston Heights in Richmond Park, cutting heating bills, it’s claimed, by up to 20%. It’s based on using water drawn from two metres below the surface of the Thames, where the ambient temperature, sustained by ambient heat from the sun, stays at around 8C to 10C all year round. A system of heat exchangers, pumps and condensers boost that to 45C. The electricity used to power the system is supplied by Ecotricity, which makes it zero carbon. According to a report in the Independent on Sunday, the system is thought to have cost about £2.5m, though this is for a ‘first of a kind’ project. The cost of future systems should be lower, and the Renewable Heat Incentive can offset supply costs.

Energy Secretary Ed Davey told the Independent on Sunday: ‘This is at a really early stage, but it is showing what is possible. You never have to buy any gas- there are upfront costs but relatively low running costs. I think this exemplifies that there are technological answers which will mean our reliance on gas in future decades can be reduced. Here you have over 100 homes, you have a hotel with nearly 200 bedrooms and a conference centre that won’t be using gas. It will be using renewable heat from the nearby River Thames. This is a fantastic development. My department is exploring the potential for this sort of water-source heat pump across the UK, so we’re going to map the whole of the UK for the potential’:

As the Independent noted, in theory, any body of water, including tidal rivers as well as standing water such as reservoirs and lakes, can be used as long as they are in the open and heated by the sun. The Government has a target of 4.5 million heat pumps across the UK, though most will be using heat from air or ground and will be small domestic units. Prof. David MacKay, until recently DECC’s chief scientific adviser, has described a combination of heat pumps and low carbon electricity as the future of building heating. However, as I’ve noted before, there are limits to the viability of small domestic systems: they make most sense in off gas-grid areas. Larger units, feeding district heating networks, are more efficient, and make more sense in urban areas, where there are large heat loads. Operation at the larger scale also make it easier to provide an effective maintenance regime, important for heat pumps, which need careful adjustment and servicing to maintain optimal performance. Otherwise the coefficient of performance (CoP), usually expected to be around 3, can fall dramatically. For example, in winter in damp cold countries like the UK, the external heat absorption pipes of air source heat pumps can develop a film of frost, reducing the heat flow. Without regular de-icing, the pump then has to work harder, potentially, in the extreme, reducing the CoP to perhaps 1 or less- making it less efficient than a simple one bar electric fire.

Moreover, large or small, the current type of heat pump run on electricity, and it’s been argued that the idea of shifting to heat pumps instead of gas for home heating on a national scale may be suboptimal, since using heat pumps run on mains electricity generated in large gas fired-plants, may be no more efficient than using gas direct in a domestic scale condensing boiler. It’s also argued that the wide-scale use of electric heat pumps is impractical, since the electricity network could not supply the large amount of power needed – the gas grid carries 4 time more energy than the power grid. It’s perhaps worth noting in this context that in the 1950’s, Southbank’s Festival Hall was heated by a large 7.5MW gas fired heat pump using the Thames as a heat source, although it seems it was taken out mainly as it produced too much heat: it was oversized

There is now renewed interest in gas-fired absorption cycle heat pumps. They are less efficient than the electric motor driven compression-cycle variant, but gas is cheaper/kWh than electricity, much of which, after all, is made inefficiently by burning gas (and coal), so a 50% net fuel saving is claimed. At the World Renewable Energy Congress in London in August, Prof. Bob Critoph from the University of Warwick noted that there were now three domestic gas-fired systems on or very near to market (Robur, Vaillant, and Viessmann) with others under development. He proposed a mixed heating solution with both gas-fired and electric heat pumps, and also the use of hybrid electric heat pump-gas boiler systems, e.g. for older properties. He felt that the proposed mix, whilst not being the minimal emission route, was an affordable and pragmatic solution to domestic heating. There are of course other novel ideas, for example solar thermal fired absorption cycle heat pumps, which may have relevance even in the UK, with the combined air source/solar Solaris system claimed to be 25% more efficient than standard air-source electricity-powered units depending on location: and

Whatever the heat and power source, are heat pumps the way ahead? Some say that large community scaled gas-fired combined heat and power (CHP) plants, with CoP equivalents of up to 20, are better in energy efficiency and carbon emission terms than heat pumps of any scale or type. That may be true at present, but, longer term, if electric heat pumps use green electricity, or gas fired heat pumps use green gas (biogas or stored gas produced using surplus wind/solar-derived power), then net emissions would be near zero. Although the same would be true for green gas fired CHP.

In the final analysis, given its high CoP, CHP seems to have the edge for the moment, but, in economic terms, the optimal systems choice may depend on the location and the size of the load. One of the largest gas-fired heat pump systems so far is the 140kW unit at Open University:;Ener-G_teams_up_boreholes_with_absorption_heat_pumps_.html

In some locations, large water sourced units may make sense, but large gas-fired units might have even wider applications. But then so may CHP, linked to district heating networks. However, to complicate matters further, it may not be a straight choice between CHP and heat pumps: e.g. a heat pump can be run using electricity from a CHP plant, while using the heat from the CHP plant as its heat source, thereby upgrading the heat output. Plenty of room for innovation!

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Renewables vs shale gas

By Dave Elliott
As a parting shot, after standing down as DECC’s Chief Scientific Advisor at the end of July, Prof David MacKay produced a comparison of renewables (wind and solar) and shale gas:

The headline figure (as picked up by the Telegraph: was that wind farms cover around 700 times more land area /kWh of energy produced at the site than shale gas wells. However, as usual with renditions of MacKay’s approach to land-use comparisons, this simple statistic is arguably a little misleading. As he admits, the actual area covered by wind turbine bases and access roads is very much less that the area covered by the wind farm, most of which can be farmed as usual. So, using his figures, the wind turbine /gas well land use ratio falls from 700:1 to 18:1

There are also other aspects that need to be considered in the comparison, some of which he covers in side notes. The energy content of the shale gas emerging from the well isn’t the same thing as the electricity output of a wind farm (or solar farm)- the gas has to be burnt in a power plant to generate energy (at 50% efficiency at best) and that also takes up room. This might reduce the wind turbine /gas land use ratio from 18:1 to perhaps 9:1 or less. And unless we condone the release from the gas-fired power plant of CO2 to the air, there will also have to be a carbon capture plant and a CO2 gas storage system- taking up a large area somewhere, and reducing the efficiency of the gas plant. That might add another factor of 2 or more, so maybe we are down to a ratio of 4:1 or less.

Hydraulic fracking also uses very large amount of water– that has to come from somewhere. It also creates large amounts of contaminated water, which has to be stored and/or treated, presumably somewhere else. It’s hard to know how to take these factors into account in land use terms. Another factor of 2? In the final analysis, overall, there might not be that much in it, if the land-use comparison is done fairly, at least for on-land wind, depending on location. And of course the whole land-use comparison collapses if we are talking about offshore wind. Or for that matter, offshore shale wells.

MacKay also looks at ground-mounted solar farms. Certainly solar farms (as opposed to roof-mounted PV arrays) do take up land space, on MacKay’s figures, around 8.5 times more than for wind turbines/kWh, although less than the total equivalent wind farm area. But, rebalancing the comparison, the Solar Trade Association has pointed out that much of this land can be grazed and most (perhaps 95%) of it can be used for wild flower growth, aiding biodiversity:

MacKay also looks at the truck movements associated with each option. His figures for solar and wind (nearly all during construction) seem high, those for shale gas low: he assumes all water is piped to and from the shale gas well site, but surely some water, and certainly fracking chemical fluids, would have to be tanked in throughout the operation, while some wastes would have to be tanked out. As for visual intrusion, his choice, for comparisons sake, of 10 temporary shale gas-drilling towers, may well be perceived as uglier but less invasive overall than his choice of 87 much taller 2MW wind turbines, though it will surely depend on the location. Some people positively like the look of wind turbines, seeing them as elegant symbols of low-impact energy extraction. It’s hard to see drilling rigs like that, although we have yet to have major shale gas projects in the UK to test that out. If, as it has been suggested, the UK may have 1000 wells started each year, attitudes may harden, as projects attempt to go ahead and impacts become apparent. My favorite unknown is whether excess gases will have to be flared off. That would make for quite a spectacle in rural areas…

At it stands, DECC’s most recent public opinion survey found that 79% of those asked backed renewables like wind and solar (82% backing solar, 67% on-land wind) while only 24% supported shale gas extraction:

There are also wider strategic issues: an emphasis on shale gas could undermine the development of renewable energy and efforts to respond to climate change. Scientists for Global Responsibility (SGR) and the Chartered Institute of Environmental Health (CIEH) have produced a report reviewing current evidence associated with shale gas extraction. SGR Director and report co-author, Dr Stuart Parkinson, said: ‘The evidence we have gathered shows that exploiting yet another new source of fossil fuels such as UK shale gas is likely to further undermine efforts to tackle climate change. We need to focus on low carbon energy sources, especially renewables, together with concerted efforts to save energy.’ The report calls for rethink, arguing not only that impacts may be high and regulatory oversight insufficient, but also that on-land wind power may be cheaper than shale gas.

The governments current decarbonisation policy envisions fossil gas being replaced as a heating option by green electricity from wind and solar and by nuclear electricity, used to power heat pumps. See my next post. That could make for a huge saving in gas – and emissions. And it would reduce the need to import increasingly expensive gas as north sea reserves dwindle. There will still of course be a need for gas to run electricity generating gas turbines, with some of those being used at times to balance variable renewables like wind and solar. However, although some new more flexible gas plants may be needed as old ones retire and renewables expand, the extra gas required for balancing, over and above what is used by the gas CCGT units at present, will be relatively small. And, as the Pugwash 2050 scenario explored, using the DECC calculator, if UK renewables expanded to 70% and alternative supply and demand side balancing options were developed, the need for gas for power generation would fall, so that, with proper commitment to energy saving, by 2050 well under 10GWof gas fired capacity would be needed. And increasingly it could use green gas- from biomass/waste AD and also possibly via surplus wind/PV to gas conversion, some of this also being use at high efficiency in CHP plants feeding district heating networks. There are disagreements about how much biomass could be available and used, but the Tyndall Centre says that by 2050, 44% of the UK’s energy requirements could be met by the increased utilisation of biomass, including household waste, agricultural residues and home-grown energy crops i.e. with no imports:

It is possible than gas could find a new market in transport, assuming the governments plan to see that electrified via a shift to electric vehicles is not successful. Certainly SNG/CNG could play a helpful role in fuelling trucks and large vans. But, as the Tyndall report suggests, much of this could be green gas. So why exactly do we want all this shale gas? Perhaps, with, tragically, renewable expansion already being constrained by government policies, it’s to compensate for that and also in case the nuclear expansion programme fails to materialize.

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Biomass burning impacts: the debate continues

By Dave Elliott
The seemingly endless debate on the impacts of burning biomass continues. At one extreme there are those who see almost all use of biomass as suspect. More specifically there are objections to using whole trees or stem wood, especially if imported so that the source is less sure. One claim is that this can produce more carbon emissions net than would be produced from burning coal, and depletes biogenic carbon stores.

It’s actually a complex issue, since forests are managed for a variety of purposes. As a new EU report on ‘Biogenic Carbon and Forest Bioenergy’ from Forest Research notes:
‘Typically, forest bioenergy is produced as a complementary co-product of wood material/fibre products. It is unusual for forest bioenergy to be the sole product from harvested wood’. However it says EU forest bioenergy is likely to increase significantly, so that ‘it will be necessary to intensify management of EU forests in order to increase removals of primary wood and/or import more wood into the EU and/or mobilise the availability of sources of other woody biomass.’ But it claims ‘A requirement to produce forest bioenergy seems unlikely to become the principal driver of forest management unless demand for forest bioenergy becomes very intense’. In particular is suggest that ‘demand for forest bioenergy seems likely to be met through increased extraction of harvest residues including poor-quality stemwood and trees, the use of sawmill co-products and recovered waste wood. Some small roundwood may be used as a source of bioenergy. It is less likely that forest bioenergy will involve consumption of wood suitable for high value applications, such as sawlogs typically used for the manufacture of sawn timber’.

Having set the scene it notes that, given this complex and changing pattern of sourcing, ‘Biogenic carbon can make a very variable contribution to the GHG emissions associated with forest bioenergy. Consequent GHG emissions can vary from negligible levels to very significant levels (similar to or greater than GHG emissions of fossil energy sources)’, although ‘in some specific cases, forest bioenergy use may be associated with net carbon sequestration’ e.g. when the replanting or rotation rate is high.

Nevertheless ‘There is widespread recognition in the research literature that increasing the levels of wood harvesting in existing forest areas will, in most cases, lead to reductions in the overall levels of forest carbon stocks compared with the carbon stocks in the forests under previous levels of harvesting. Where the additional harvesting is used to supply bioenergy as the sole product, then such forest bioenergy will typically involve high associated GHG emissions (i.e. compared with fossil energy sources) for many decades.’

It is this that groups like Friends of the Earth (FoE) and Biofuelwatch focus on, claiming that this is now what is happening- to feed giant biomass combustion plants like Drax with wood pellets from North America, some of which are allegedly made from stemwood. Even so that doesn’t necessarily mean they are against the use of all biomass. For example FoE’s new report ‘Felled for Fuel’ focuses on, and objects to, ‘burning trees for electricity’. Instead it wants the government to ‘refocus support for bioenergy on the use of feedstocks such as agricultural and forestry wastes and biogas from sewage, food waste and other organic wastes’ and also to limit the use of the available sustainable biomass ‘to modern combined heat and power (CHP) plants which would ensure the most efficient use of these limited feedstocks, making use of the energy for heat as well as generating electricity’.

FoE does see overall biomass use as being constrained though by more careful assessment of sources and their bio-impacts. It calls for ‘the government’s ambitions for bioenergy to be scaled down and capped at a level that ensures supplies can be
sourced sustainably and domestically’. That raises many issues. Some see bio-conversion of big old coal plants as a useful stop gap, but if that’s not on, then others look to specially grown energy crops as a viable new source, in addition to wastes. And to the use of wood for heat production at the local level. It’s a broad ranging debate.

DECC’s new, long awaited, Bio-carbon Calculator may help clear the air a bit in relation to large scale biomass conversion plants. DECC uses it to assess a range of scenarios for the net carbon balance that would be associated with North American biomass used in the UK, with different land use changes assumed. It concludes that ‘in 2020 it may be possible to meet the UK’s demand for solid biomass for electricity using biomass feedstocks from North America that result in electricity with GHG intensities lower than 200 kg CO2e/MWh, when fully accounting for changes in land carbon stock changes. However, there are other bioenergy scenarios that could lead to high GHG intensities (e.g. greater than electricity from coal, when analysed over 40 or 100 years) but would be found to have GHG intensities less than 200 kg CO2e/MWh by the Renewable Energy Directive LCA methodology’.

So it can produce more emissions than coal, but also, done right, with proper choice and regulation of sources, it can be fine. The Renewable Energy Association agreed: ‘Anyone using biomass in accordance with the guidelines set out by the UK government would be lower-carbon than other fuels.’

However DECC says the energy input requirement of biomass electricity generated from North American wood used by the UK could be significantly greater than other electricity generating technologies, such as coal, natural gas, nuclear and wind. That may limit its use. But DECC says Energy Input Requirements can be cut e.g. by reducing transport distances and the moisture content of the biomass. So overall it sees some projects as viable.

Will that end the debate? Unlikely! FoE said it was vital to have tougher regulation and clearly it’s not convinced that stem wood isn’t being used. But at least the various stakeholders are almost now on the same analytical page, or ought to be, in relation to biomass conversion! How they then decide to respond in terms of strategic development priorities is another matter. Interestingly, DECC won an appeal against a Judicial Review ruling that required it to reinstate a large DRAX biomass conversion project which it had turned down. So it won’t now happen. And DECC has also said, in its allocation statement for future CfD rounds (limiting them to £205m p.a.), that it was‘ not at present intending to release a further budget for biomass conversion’, i.e. after the current ‘early’ CfD round. Clearly biomass conversion is something of a hot potato!

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Wind and PV fight for limited pot of money

By Dave Elliott
PV solar is doing well in the UK with, on some reckonings, nearly 3 GW installed so far and much more planned, perhaps 10GW by 2020 being likely and possibly even near 20GW. On-land wind is also doing quite well, with 7.3GW in place, and despite planning conflicts and local opposition, a total of 13 GW likely by 2020, based on projects already built, under construction or permitted. Offshore wind is doing well too, with 3.7 GW in place and near 1GW likely to be added this year, including Gwynt y Môr (576MW) and West of Duddon Sands (389MW). All being well, similar amounts are expected in 2015 and 2016, taking the total to maybe 8GW by 2016/17, on the way to 10-11GW by 2020, maybe much more.

However that all depends on new projects getting support under the new contract for a difference (CfD) system, and, although five offshore wind projects have got CfDs under the interim ‘early’ round, the government has announced a £205m p.a. cap on future rounds- and that’s to be shared across all the renewables.

The cash allocation cap is set up under two categories- ‘Pot 1’ with, from 2019, £, for well established options, like on-land wind and large PV solar, with costs falling and support needs reducing, and ‘Pot 2’ with £155m p.a, for less established options like off-shore wind, geothermal, AD biomass, wave and tidal stream projects, which still need more support to get prices down- some more than others. Offshore wind is amongst the cheapest of the Pot 2 group, with the CfD strike price set at £155/MWh for 2014-2017, falling to £140 thereafter, and costs seem likely to fall to around £100/MWh after 2020. By contrast, the strike price for wave and tidal stream is set £305/MWh over the whole period up to 2019. So who will get the money? A 100MW tranche has been set aside for wave and tidal stream, so there will be less room (and cash) for the others. Gordon Edge, director of policy at Renewable UK, noted that even if offshore wind got the full £155m pa allocated to ‘Pot 2’ that would fund just one typical 500MW offshore wind farm ‘which is significantly less than we need’. Given for example the recent planning go-ahead for E.ONs 700MW Rampion project off Sussex and the many others in the pipeline, that’s quite an understatement!

It’s even tighter in Pot 1, where there are to be competitive contract auctions. With only £50m available p.a. for hydro, energy from waste, onshore wind, landfill gas, sewage gas and large-scale solar, the Solar Trade Association (STA) complained that, ‘even if all of this went to solar – which it won’t – this is only enough for 1GW of solar in this round, a considerable reduction on the current market’. The STA was particularly incensed by the government’s proposal to exclude large solar power projects (over 5MW) from support under the Renewables Obligation (RO) system from April next year, given that all the other technologies were not excluded, with the RO system still planned to be available up to 2017 for new projects and existing contracts under it running beyond that.

Large solar could seek support under the CfD, but the STA said that solar, with relatively small projects promoted by small business, was not well suited to it, and was ‘being exposed to this new Contracts for Difference system without having the back-up of the old scheme’. The CfD strike price offered was £120/MWh for 2014-16, falling in stages to £100 by 2018, but it would be in competition with on-land wind, with a strike price of £95/MWh falling to £90 by 2019, and with land fill and sewage gas at ever lower strike prices (£55 and 75/MWh respectively). Small PV can continue to get support under the microgen/domestic Feed In Tariff (FiT) and it’s still booming despite a cut in the FiT level, but otherwise, solar growth looks likely to be seriously limited. The STA said the cap could cut large-scale solar installations by about 65% to 80% next year.

What’s behind this? It would perhaps have been reasonable to expect solar to compete within the CfD system if it had the RO in the interim, so why exclude it? Well firstly, with solar farms booming around the UK (several hundred are in place or planned) visual intrusion concerns were rising, and local objections were emerging. And secondly, the rapid expansion was costing too much. DECC’s impact assessment says closing the RO to solar above 5MW from April 2015 will save up to £200m a year, from 2017, from its Levy Control Framework clean energy subsidy budget. That’s the extra it says it might cost if large solar farms were left to expand, perhaps reaching 6.3GW by 2020, under the RO, getting 1.4 ROCs/MWh this year, 1.2 ROCs in 2016. They said this money could be better spent.

Well, we will see. The first full CfD auctions start this October, and then happen annually after that. Will large solar get squeezed out by on-land wind? That’s surely not what the Conservatives want. They have talked of constraining on-land wind, reflecting pressure from their (anti-wind farm) political base in the shires. Well maybe, actually, the £50m pa cap for Pot 1 will do that. Even if on land wind got it all (so killing off large solar), the rate of growth of on-land wind would also be cut: it’s been suggested that it might be halved:

Will offshore wind also get squeezed? That too would be perverse. Although more expensive, it was meant to be one of the main alternatives to on-land wind! Or will the overall cap be raised? It’s set under the Levy Control Framework (LCF) to limit low carbon support (i.e. the RO, FiT and the CfD) and consequent pass through to consumer bills. That has imposed an overall limit for 2014/15 of £3.5bn, rising in stages to £7.6 billion in 2020/21.

There have been calls for a rethink on the LCF cap. Certainly when and if the Hinkley nuclear plant project goes ahead, with its guaranteed £92.5/MWh CfD strike price, the overall cap will have to be raised. As the Daily Telegraph noted: ‘The budget post-2020 is yet to be set but at a minimum will have to expand to accommodate new nuclear plants, the first of which could start generating power – and therefore using up susbidies – from around 2024.’

The Hinkley project CfD allocation was not subject to a price cap or to the competitive contract auction process that now faces new renewable projects – Edf was the only player and also won a promise of a £10bn loan guarantee. It’s not clear what will happen with regard to next lot of major nuclear projects that the governments want us to support- 16GW initially, maybe more later. If a competitive CfD framework does emerge across the board, we can expect further head to head collisions as rival options seek funding. However with wind and PV solar likely to be cheaper than Hinkley by the time it starts up, any similar new nuclear projects will face stiff competition.

Meanwhile, what should the priorities be? Well, keeping consumer costs down is obviously important, but we are only talking small amounts -the RO has only added around 2% to bills, the FiT 1%, while the competitive CfD is expected to drive prices down, although DECC’s most recent impact assessment carefully noted that its estimates didn’t yet cover nuclear costs. We shall see! But if it was left to the public, the most recent poll indicated that 79% backed renewables (67% liked on land wind, 72% offshore wind, and 82% solar) and only 36% backed nuclear:

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DECC Reviews Renewables

By Dave Elliott

In its 2014 review of renewable energy policy, part of its Electricity Market Reform deployment exercise, the UK Department of Energy and Climate Change outlined how it saw each key option developing:
There have certainly been some changes since its 2011 Renewable Roadmap, which selected eight technologies as likely to be key to meeting the UK’s 2020 renewables targets.
PV solar was not amongst the selected eight. But now it’s a front runner. In its new report DECC says, ‘We consider solar PV now to be an established technology in the UK,’ and with 2.7GW or more in place that’s clearly true. And they add ‘Solar is anticipated to be the first large-scale renewable technology to be able to deploy without financial support at some point in the mid-to-late 2020s’. Didn’t it do well! Despite the cuts in Feed In Tariffs. DECCs main concern now seem to be that PV, especially solar farms, will expand too fast! They note that ‘Solar PV is a technology which can be deployed quickly even at large scale’. But they are worried about the costs and eco-impacts of large ground mounted projects and would prefer Building Integrated schemes, large and small. On costs, they accept that these are falling (which is why take-up has grown) and will continue to fall (in part due to the take-up), but they say ‘because the UK is a small part of the global market, it is likely that these cost reductions will largely occur independently of what the UK does’. And they have sought to limit the cost pass-through to consumers, most notably by entirely cutting Renewables Obligation (RO) support for large projects. Otherwise they say they might reach 5GW by 2020! Nevertheless they still talk of an overall possible 10GW of PV by 2020 and perhaps even 20 GW.

Wind power did feature strongly in the 2011 DECC review, offshore especially. Now, despite being the cheapest of the main new renewables, on land-wind has fallen out of favour in some circles (e.g.due to vociferous campaigning and some local opposition), although, as DECC says, ‘current installed capacity in the UK is 7.3GW, with a further 1.5GW under construction’ and ‘there is also a large potential pipeline of UK projects with 5.4 GW having received planning consent and a further 6.5GW currently in the planning system. This means we are well on our way to reaching our ambition for 11-13GW of onshore wind by 2020’. But by contrast offshore wind is seen the biggie: ‘Offshore wind is the most scalable of the renewable technologies, and it is the renewable technology that has the most potential to make a significant contribution to decarbonisation goals, if required. There is significant long-term potential for cost reduction and it is at an early stage of deployment – DECC’s central estimate is a 25-30% reduction in central costs by 2030, which could be higher depending on the level of deployment between now and then. The UK is the market leader for offshore wind, with the biggest pipeline to 2020, and deployment in the UK is therefore a key driver of cost reduction to 2020’. DECC had earlier said up to 39GW was possible by 2030. But that depended on the market.

Wave and tidal stream also featured in DECC’s 2011 Renewable Energy Roadmap, which suggested that there could be 200-300 MW of marine capacity by 2020. That was much less than the 1-2 GW forecast in the Government’s Marine Energy Action Plan 2010, or even the 1.3GW by 2020 UK figure in the EU Renewable Energy Action Plan. And although the UK is still in the lead in this area, the new DECC Review reduces its expectations further: ‘Wave and tidal stream technologies are still at the demonstration stage and are not currently competing in the mainstream market. There are currently around c.10MW of wave and tidal stream capacity deployed in sea trial around the UK – more than the rest of the world combined. We anticipate that by 2020, wave and tidal stream could reach 100-150MW in the UK alone. This deployment could then increase quickly beyond 2020 to reach GW-levels in the late 2020s-early 2030s’.

Unlike heat pumps (still strongly backed), geothermal wasn’t in DECCs 2011 key options list, but a 2012 SKM study claimed that it could supply 20% of UK electricity from around 9.5GW of capacity. The new DECC review however relies on a 2013 Atkins report on deep geothermal power which suggested a possible best case potential of up to 3-4% of current average UK electricity demand. So it’s still seen as something of an outsider option, although worth backing.

By contrast, DECC is still very enamored of biomass, including EfW combustion, advanced gasification/pyrolysis, biomass CHP and AD from farm and other wastes. There are limits though, mainly related to land use constraints and concerns about the sustainability of importing biomass pellets for large biomass conversion plants. I’ll be looking at that in my next but one post.

The new DECC renewables review is just about electricity supplies, so it doesn’t look at solar or biomass heat (both being pushed quite hard by the Renewable Heat Incentive), or biofuels (on which progress is less spectacular). But arguably it does add up to a package might help the UK meet it 2020 15% renewable energy target. However, with the various cuts and uncertainties about the effects of the new Contracts for a Difference support system, that is not certain: DECC has just imposed a £205m p.a. cap on renewable CfD allocations up to 2020 which may constrain new offshore wind and large PV solar projects seriously. I will be looking at that in my next post. And beyond 2020 there are no renewables targets, with, under current policies, the continued expansion of renewables likely to be constrained by the commitment to nuclear and maybe shale gas CCS. But policies can change and with renewables costs falling, they may break through further and accelerate more, so there is still all to play for.

If so, what about grid balancing? DECC has confirmed that it will be seeking 53GW of contracted capacity for the new ‘capacity market’ for 2018/19, to help deal with supply shortfalls due to demand peaks, variable renewable inputs and plant or grid failures. For the moment much of this will involve existing gas plants that might otherwise be closed, given the increased output from renewables, but will be needed occasionally when that output is low. However any facility that can provide grid balancing services can apply to the capacity auction process in December, including storage and demand management. Contracted capacity will get a cash incentive for being available. DECC says it will add £2p to average annual consumer bills over the period 2014-30.

So what next? Given its excellent renewable resources, clearly in principle the UK could, if it wanted to, at least match the German ambition of getting 80% of electricity from renewables by 2050. Assuming that is Scotland, which has most of the resources, is still part of the UK! noted that about 15 GW of 2020 renewables will be in Scotland or in Scottish waters. Only about 18 GW will be in England and Wales. So it said Independence would mean around 40% of total UK renewables capacity would disappear, but only 10% of UK electricity consumption.

DECC sees it differently, arguing that Scotland’s small population would not be able to sustain the cost of its large renewables capacity without the RO income from the rest of the UK – or a £189 p.a increase on Scottish consumer’s bills. But in reality wouldn’t the UK have to buy in, and continue to support, Scottish green power to meet it renewable targets? DECC also sees the nuclear issue differently, and, with the European Commission currently looking at the UK’s proposals for funding the EdF Hinkley project, Westminster has evidently warned the (anti nuclear) Scottish government that any negative representation it made to Brussels on this would be viewed as a ‘hostile act’.
Clearly the independence referendum is going to be a lively affair!

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