44.This Chapter examines the Government’s policies for decarbonising the power generated by the UK, covering large-scale renewable power technologies such as onshore and offshore wind farms, small-scale renewable power technologies such as rooftop solar panels, and conventional and emerging nuclear power technologies.
45.Power generation was responsible for around 15% of the UK’s territorial greenhouse gas emissions in 2018. The power generation sector has achieved significant decarbonisation over the course of the last carbon budget period, mostly as coal power generation has been replaced by gas and renewable power generation, and improved efficiencies have reduced demand. Overall, emissions from the power generation sector fell by 59% between 2008 and 2017, and emissions reductions in this sector accounted for 75% of the UK’s total emissions reductions between 2012 and 2017.
46.The Committee on Climate Change has made clear that “further reduction in the emissions intensity of power generation […] remains the lowest-cost path towards economy-wide decarbonisation”. Eliminating the UK’s remaining coal power emissions, as the Government has pledged to do by 2025, would reduce the UK’s total emissions by a maximum of a further 4.5%. This compares to overall reductions of around 13% required to meet the fourth carbon budget. Although the proportion of electricity generated from coal has decreased substantially in the UK, natural gas—another, less carbon-intensive, fossil fuel—supplied 40.4% of the UK’s electricity in 2017. Low-carbon power generation technologies include onshore and offshore wind power, solar power, wave and tidal power, geothermal power and nuclear power (the Intergovernmental Panel on Climate Change has estimated that the full lifecycle emissions associated with nuclear power are comparable to renewable power technologies such as wind power). Together, these provided around 50.1% of the UK’s electricity supply in 2017.
47.The Government has stated its intention to “regulate the closure of unabated coal power generation units by 2025”. Seven of the UK’s eight operating nuclear power stations are also scheduled to close by 2030. Across all power generation technologies, around two-thirds of existing power stations are expected to close by 2030. Against this backdrop of planned power station closures, the demand for electricity is anticipated to grow substantially, in particular as sectors such as transport and heating electrify. In total, the Committee on Climate Change has estimated that the amount of low-carbon electricity generated each year will have to more than double during the 2020s, requiring the generation of 130–145TWh of additional low-carbon energy by 2030 (taking into account the generation capacity expected to close by 2030). Were this to be met using just one low-carbon power generation technology, this would be equivalent to increasing the current generation from onshore wind power by a factor of 5.7, offshore wind power by a factor of 7.6, solar power by a factor of 13.0, or nuclear power by a factor of 3.0. National Grid System Operator, which is responsible for balancing the supply and demand of electricity in Great Britain, has similarly estimated that the UK will need to more than double its low-carbon power generation capacity by 2030, and increase it by a factor of between 3.1 to 3.8 by 2050 to reach its existing emissions targets (corresponding to increases of around 50GW and 100–130GW respectively).
48.The Minister of State for Energy and Clean Growth, Claire Perry MP, indicated to us that the Government expected the main components of this future low-carbon power generation supply to consist of offshore wind power, nuclear power and gas power used in combination with carbon capture and storage. As part of its ‘Industrial Strategy’, the Government agreed sector deals with the nuclear and offshore wind power industries. The nuclear sector deal has four main aims:
The offshore wind sector deal aims to:
The offshore wind sector deal also entails up to £250m investment from industry to build the UK supply chain and up to £557m from the Government to finance new offshore wind capacity. In place of a sector deal, the Government has published a carbon capture, usage and storage ‘action plan’. This committed to “the UK having the option to deploy carbon capture, usage and storage at scale during the 2030s subject to the costs coming down sufficiently”.
49.The Government has estimated that the offshore wind sector deal could lead to the deployment of 30GW of new generation capacity by 2030, corresponding to around 100TWh of low-carbon electricity per year (compared to the 130–145TWh the Committee on Climate Change estimated that the UK would need). The Government did not estimate the new generation capacity that the nuclear sector deal would deliver. However, given the £18bn value of the new 3.3GW (~25TWh/yr) reactor at Hinkley Point C, the Government’s ambition for £2bn of domestic and international contracts to be won by 2030 suggests that the nuclear sector deal will not deliver significant proportions of the UK’s additional power needs. The Minister told us that “nuclear has a part to play in the [future energy] mix” but said that the Government has to “spend taxpayers’ money wisely”. It therefore seemed as though the Government planned to meet the bulk of the UK’s additional power generation needs through the 2020s by installing new offshore wind power. Indeed, Dr Robert Gross, co-Director of the UK Energy Research Centre, told us that “the only really big show in town between now and 2030 is the offshore wind sector deal”.
50.The Offshore Renewable Energy Catapult advised us that the Government’s target for offshore wind was “very achievable, with much of the 30GW in the pipeline in one form or another”. Professor Keith Bell, co-Director of the UK Energy Research Centre, further told us that it was “entirely credible” that the UK could deploy the low-carbon power generation capacity it would need to fulfil its fourth and fifth carbon budgets, and indicated that it was already “well on the way” to achieving this. The Committee on Climate Change, however, has estimated that the announced Government investment in renewable power would provide an additional 60TWh per year by 2030, and that the new nuclear reactor at Hinkley Point, if built, would provide 25TWh per year. This would leave a ‘gap’ of 50–60TWh by 2030. Dr Nina Skorupska, Chief Executive of the Renewable Energy Association, similarly told us that the UK was “not on track” to deploying the low-carbon power generation required for its fourth and fifth carbon budgets.
51.Dr Gross said that the Government’s aims were “perfectly achievable” but said that the focus on offshore wind power meant that the UK was therefore “very largely putting all of [its] eggs in that basket”. The Committee on Climate Change has warned that the Government’s power generation decarbonisation strategy was not “credible” because of the “significant risks associated with it” and the lack of “multiple plausible pathways to achieve the necessary level of decarbonisation”. It therefore recommended that the Government develop “robust contingency plans that allow for additional low-carbon generation to be brought forward in the event of delay or cancellation of planned projects, or imports of electricity below projected levels”. This appears to be warranted, given the recent uncertainty surrounding nuclear power projects.
52.Renewable power generation is generally ‘intermittent’, meaning that its output is variable and uncontrollable. For example, wind turbines only generate power when the wind is blowing. Although this poses challenges to the UK energy system, Duncan Burt, Director of Operations at National Grid System Operator (which is responsible for balancing supply and demand on the electricity transmission system—the core network that transfers high-voltage power between power stations and local distribution networks), told us that “it is very easy to get to very high levels of renewable generation and to 100% zero carbon generation over the next six or seven years for regular periods of operation”. Indeed, National Grid Electricity System Operator has stated its ambition to be able to operate the grid using entirely ‘zero-carbon’ power sources by 2025, subject to sufficient generation (this contrasts to the Government’s statement that “one possible pathway to 2032 […] could be achieved by growing low carbon sources such as renewables and nuclear to over 80% of electricity generation). In fact, Great Britain is already achieving increasing periods of zero-carbon power generation. For example, on 8 May 2019, Great Britain met its electricity demands for over a week without using coal power—for the first time since the Industrial Revolution—and later that month went two weeks without coal power. The UK Energy Research Centre has further reported that, although “the additional costs of adding variable renewable generation to an electricity system can vary quite dramatically […] they are usually modest, with higher costs normally the result of inflexible or sub-optimal systems”.
53.We commend National Grid Electricity System Operator for its ambition to be able to manage a ‘zero carbon’ electricity grid by 2025. This goes significantly beyond the Government’s projections for possible renewable power deployment by 2032, and indicates that any ‘over-delivery’ on the deployment of low-carbon power generation in the 2020s will not be incompatible with the electricity transmission system. We urge distribution network operators to adopt a similar ambition to National Grid System Operator, of operating a zero carbon grid by 2025. Ofgem should work with distribution network operators to ensure that the regulatory framework required to allow this is in place. If sufficient progress is not made we urge the Government to consider strengthening Ofgem’s mandate to require the distribution network operators to speed up the investment and upgrading of the distribution networks required.
54.The Government has indicated that it expects requirements for new power generation capacity to be met through offshore wind power, nuclear power and gas-fired power with carbon capture and storage. There is considerable risk that these technologies may not provide the generation capacity required. The Government must set out in its response to this Report how it intends to monitor and address any potential shortfall in power generation capacity, and ensure that this can be achieved with low emissions and costs.
55.The Government has said that its “main mechanism for supporting low-carbon electricity generation” is through ‘contract for difference’ agreements (see Box 1). These have supported the deployment of 5.5GW of renewable power generation capacity since they started in 2015, and were identified by several witnesses as having been an important factor in the falling costs of renewable power technologies. However, since 2017, contracts for difference have been available only for “less-established” technologies such as offshore wind power or tidal power, and not for “established technologies” including onshore wind power and large-scale solar power (the contract for difference framework refers to established and less-established technologies as ‘Pot 1’ and ‘Pot 2’ technologies respectively). The Government has signalled its intention to continue this policy through the 2020s.
Box 1: Contracts for Difference
Under the contract for difference mechanism, the Government signs contracts with renewable energy project developers (through the Low Carbon Contracts Company (LCCC), a Government-owned company) agreeing that for the duration of the contract, the LCCC will pay the developer the difference between the ‘reference price’ (a measure of the average market price) and the ‘strike price’ (the price negotiated at the beginning of the contract) for any electricity the developer sells into the grid. This guarantees the developer a stable price for the electricity it generates for the duration of the contract, usually 15 years. In the event that the wholesale price rises above the negotiated strike price, the developer instead pays the LCCC. The net cost of all payments made to contracted developers is funded through a levy on licensed electricity suppliers.
Contracts for Difference are awarded through Allocation Rounds in which renewable power developers bid for contracts in a ‘pay as clear’ auction. The Government sets an overall budget cap for each auction as well as a maximum permissible strike price for each technology. Developers then make sealed bids of the capacity they are offering and the lowest strike price they would accept. The project with the lowest strike price is awarded a contract first. Each subsequent project wins a contract if its expected cost, when added to the cost of the previous winning projects in the auction, comes below an overall budget cap. Projects that have already won a contract have their strike price raised to that of the latest project being assessed and the revised overall cost of the auction is reassessed against the budget cap. The auction stops once a project’s cost breaches the budget cap when added to the costs of projects that have already won.
The first Allocation Round in 2015 held separate auctions for different groups (or “pots”) of technologies:
Pot 1—established technologies (such as onshore wind power and solar power); and
Pot 2—less established technologies (such as offshore wind power and wave power).
56.Numerous stakeholders contributing to our inquiry argued for the inclusion of established technologies in future contract for difference auctions. In addition to the stakeholders that contributed to our inquiry, contract for difference auctions open to Pot 1 technologies have been recommended by independent organisations such as the Committee on Climate Change and the National Infrastructure Commission. Alongside their low carbon intensity, the main argument for supporting the market for established renewable power generation technologies was their low cost. In particular, the cost of new wind power generation capacity in Europe has fallen continuously since at least 2015, and the Government estimated in 2016 that onshore wind power would have the lowest deployment cost of any power generation technology—including those using fossil fuels—from 2020 onwards (the analysis included carbon pricing costs but not the wider system costs of different technologies).
57.The Government therefore argued that “onshore wind and solar costs have already fallen significantly, and global market dynamics will continue to drive this, so it is right for us to have scaled back support in those areas”. However, RenewableUK has reported that new onshore wind installations fell by nearly 80% in 2018 to the lowest level since 2011, which it claimed was despite that fact that “there is currently 4,466MW [over seven times what was installed in 2018] of shovel-ready onshore wind that has gone through the local planning process”. The Solar Trade Association similarly reported a 95% drop in deployment of new solar power in 2018 compared to 2015 and highlighted the UK’s last-place ranking for anticipated growth in solar power out of 20 established global markets, as rated by Solar Power Europe. Furthermore, planning permission applications for renewable generation fell in 2016 and 2017, from a total equivalent generation capacity of 2.5GW to 0.9GW. Professor Keith Bell, co-Director of the UK Energy Research Centre, explained that it was not subsidy that Pot 1 technologies required from contracts for difference, but that instead “it is a question of the right contractual framework that allows the cost of capital to be reduced and allows the investment to be unlocked”. Dr Nina Skorupska, Chief Executive of the Renewable Energy Association, added that, with policies to support renewable technologies all ended or ending soon without replacement (other than for offshore wind power), “the general lack of a clear policy and framework beyond 2020 is stifling investment”.
58.Nevertheless, the costs of established renewable technologies are expected to continue falling. BVG Associates, a renewable energy consultancy firm, has estimated that the cost of onshore wind power could fall below the wholesale price of electricity in 2023, and therefore result in lower bills for consumers. It projected that a series of five contract for difference auctions for onshore wind power, held at 18 month intervals between 2019 and 2025, could deliver a net benefit of £1.6bn to energy consumers over the total lifetime of the 15-year contract periods and an overall economic benefit of at least £8–12bn. Modelling commissioned by Citizens Advice in 2015 similarly found that the cost to consumers of excluding onshore wind power from the 2017 contract for difference auction would be £500m. Additionally, a 2018 study from University College London argued that restoring Pot 1 auctions would help to improve the competitivity of UK heavy industry, by reducing its electricity costs to nearer the European average. Lord Deben, Chairman of the Committee on Climate Change, told us that the Government “must either allow [onshore wind power] to be part of the structure […] or tell the public the extra cost that we are paying for our electricity because we do not do it”.
59.Despite these projected cost-savings, the 2017 Conservative manifesto stated that the party did “not believe that more large-scale onshore wind power is right for England”. The Minister for Energy and Clean Growth, Claire Perry MP, further explained that “people find these wind turbines to be very unsightly” and stated that the UK “could be generating all the wind power [it needs] offshore with concomitant industrial benefits”. The Government’s own surveys have revealed, however, that 79% of the public support the use of onshore wind power and that 61% would be happy to have a large scale renewable energy development in their area. Energy UK noted that “robust local planning rules” already ensured that new installations of these technologies would go ahead only where the local community supported them. Indeed, there has been some criticism that changes to planning guidance in 2015 “place an effective moratorium on onshore wind projects without decisive and deliberate action from local councils or communities and increases the risk profile of the planning applications that are submitted”. It has also been argued that the UK’s restrictive planning framework is responsible for the fact that the UK’s new onshore wind farms have some of the smallest turbines in Europe, despite the fact that larger turbines lead to greater power output, improved reliability and therefore cheaper costs.
60.RenewableUK has argued that wind farms can provide job creation, inward investment and the provision of facilities for local communities, and estimated that for each installed megawatt of wind power capacity, around £100,000 stays in the community and surrounding areas during the lifetime of a project. However, the British Academy has reported that “the UK has had a less stable environment” for supporting community energy projects than international leaders such as Denmark and Germany, which have some of the highest rates of onshore wind power use in Europe as a result of “extensive local community ownership of onshore wind turbines”. Research suggests that increasing the public stake in projects by promoting community ownership and profit-sharing, and requiring meaningful public consultations (which provides an opportunity for participation) can build and maintain public support. However, Community Energy England, a not-for-profit organisation representing community energy projects, reported that 2018 was “the toughest year yet for community energy, with new generation capacity falling steeply in comparison to previous years”. It blamed this principally on cuts to the feed-in tariff (see paragraphs 69 to 74) combined with a “restrictive planning environment”. An alliance of over twenty sustainable energy stakeholders, led by the Green Alliance, published a ‘manifesto for community energy’ in 2019, advocating:
61.In contrast to the UK Government’s position, the Scottish Government stated in 2017 that “Scotland will continue to need more onshore wind development and capacity” and called on the UK Government to use its reserved powers and established market mechanisms to support onshore wind power projects. The Welsh Government also called on the UK Government “to enable onshore wind and solar technologies to compete in the Contract for Difference mechanism to reduce overall costs and enable the continued renewable deployment needs to meet the UK’s legally binding decarbonisation goals”. Giving evidence to the Business, Energy and Industrial Strategy Committee in November 2017, the Clean Growth Minister highlighted that “under the current contract for difference rules, it is impossible to bring forward geographically specific wind farms, much as we would like to”.
62.Although onshore wind power and large-scale solar power are low-cost and low-carbon, the deployment of new installations of these technologies has fallen drastically since 2015. Onshore wind power in particular could lower costs to energy consumers as well as contributing to the UK’s decarbonisation, and there is widespread support for increased Government support for such projects across Great Britain. The Government must ensure that there is strong policy support for new onshore wind power and large-scale solar power projects for which there is local support and projected cost-savings for consumers over the long-term. The Government should actively encourage and support local authorities to adopt planning practices that promote local support for such renewable energy projects. The Government must additionally develop mechanisms to promote community ownership and profit-sharing of low-carbon projects, such as joint ventures, split ownership or shared revenue.
63.Offshore wind power is set to be supported by the Offshore Wind Sector Deal as well as the Government’s allocation of up to £557m for Pot 2 contract for difference auctions. However, we heard of other less-established renewable power generation technologies that could also support clean growth in the UK during our inquiry, such as wave power, tidal power and geothermal power. RenewableUK warned us that “as currently set up, the contract for difference [mechanism] is not a mechanism that will support marine renewables—or any new renewable technology—as they seek to secure the early-stage investment in smaller-scale projects” required to move these technologies from technology development to commercialisation. RenewableUK consequently advocated the development of ‘Innovation Power Purchase Agreements’, which was supported by other marine energy stakeholders. These agreements would be made between developers of certain renewable power technologies and large-scale energy consumers, with the Government providing tax rebates to the consumer covering the difference between the “emerging technology price” of the energy supplied by the developer and the market price, so that they would not incur a cost penalty for entering into such agreements. The “emerging technology price” would be determined according to a pre-defined framework set by the Government, starting at an agreed value (proposed to be around £290/MWh) and decreasing as the total capacity deployed increases. Agreements would only be eligible for projects supplying up to 5MW of generation capacity. A cross-sector proposal for Innovation Power Purchase Agreements estimated that the maximum cost to the Government of such a scheme would average £141m per year over twenty years. Marine Energy Wales proposed that future Pot 2 contract for difference auctions additionally include a minimum allocation to be awarded to specific technologies, in order to support them through larger-scale commercialisation.
64.The marine energy sector has come together to propose market support mechanisms to support marine and other less-established renewable power technologies through technology development and commercialisation. The Government should examine the case for supporting ‘Innovation Power Purchase Agreements’ and setting minimum allocations of future contract for difference auctions to specific technologies, to support the development and commercialisation of renewable power technologies that are less-established than offshore wind power.
65.The Committee on Climate Change’s estimate that 130–145TWh of additional low-carbon energy would be required by 2030 was based on the assumption that existing renewable power generation capacity that was scheduled to close during the 2020s would be replaced or have its life extended. The average lifetimes of wind and solar farms—the two most common renewable power technologies in the UK—are around 20–25 years. With the UK’s first commercial renewable power projects installed through the 1990s, these installations are starting to near the end of their expected lifetimes.
66.The number of wind farms projected to reach the end of their lifetimes increases substantially from 2029 onwards. This is notable given that RenewableUK, the trade association for the wind, wave and tidal energy industries, has estimated that it could take up to 10 years to start the planning process required to repower a wind farm. The Government revised the National Planning Policy Framework in 2018 to exclude repowering projects from the stricter planning guidance for new wind farm projects, but RenewableUK has warned that repowering projects are still threatened by a “lack of visibility surrounding the planning process”. It recommended that “UK Government, devolved governments and assemblies, local authorities and other key stakeholders should work in conjunction with the industry to create a supportive planning policy framework”, including:
67.RenewableUK also argued that the Government “should ensure that an appropriate market mechanism is in place to enable repowering”. Professor Keith Bell, co-Director of the UK Energy Research Centre, told us that although the risk attached to re-powering existing wind farms should in principle be lower than for building new farms due to the re-use of existing sites and connections to the power networks, there was a mixed degree of optimism in the wind power community regarding the ability for re-powering projects to go ahead without some form of contractual security. Dr Nina Skorupska, Chief Executive of the Renewable Energy Association, indicated that the ability of existing onshore wind power sites to repower without market support would vary site-by-site.
68.The Government should develop, by the end of 2020, a clear planning permission framework for re-powering existing onshore wind farms, and ensure that national planning policy facilitates re-powering with the most efficient technology and does not block proposals that attract local support. It must also monitor the proportion of onshore wind power sites that apply for permission to repower, and be ready to provide market support (for example through eligibility for contracts for difference) if this is not close to 100%.
69.Small-scale renewable power generation technologies include solar panels, small wind turbines and units that convert waste into biogas. Until recently, these have been supported by a ‘feed-in tariff’ scheme, which paid owners of small-scale generation technologies according to the electricity they generated (the generation tariff) and the amount they provided to the grid instead of using themselves (the export tariff). The market regulator, Ofgem, split the costs of the scheme across energy suppliers, who ultimately passed it on to consumers through their energy bills. However, the scheme was closed to new applications on 1 April 2019. Announcing its decision to close the scheme, the Government argued that “growth in the small-scale low-carbon generation sector must be sustainable; driven by competition and innovation, not direct subsidies”. It also explained that the feed-in tariff scheme’s “fixed and flat rate export tariff does not align with the wider government objectives to move towards market-based solutions, cost reflective pricing and the continued drive to minimise support costs on consumers”.
70.The Government has said that around 80% of the power generation capacity supported by the feed-in tariff was in the form of rooftop solar panels. The Solar Trade Association told us that, due to the “the lack of appropriate regulatory scaffolding and lack of local flexibility markets”, the smart energy market was “threatened” by the closure of the feed-in tariff. It reported that domestic installations of solar panels had fallen each year since 2015, which is when the Government first announced that it would start winding down parts of the feed-in tariff scheme. Following a survey of its members in 2018, the Renewable Energy Association reported that over 40% of UK solar installers were considering leaving the industry in response to the closure of the feed-in tariff and that 78% were considering reducing staffing levels. The Association also noted that previous changes in the feed-in tariff, to reduce the tariff offered, had led to an estimated 9,000 job losses in the solar panel industry. The Solar Trade Association labelled the delay between the closure of the feed-in tariff scheme and details of any successor programme “a damaging policy hiatus”.
71.Since closing the feed-in tariff scheme, the Government has announced that a ‘Smart Export Guarantee’ scheme would be set up in its place, coming into force from the end of December 2019. Under the scheme, large energy suppliers will be required to offer at least one export tariff scheme to small-scale generators, but would be free to set the form (within the accepted framework) and value of the tariff per kWh supplied (subject to it being always greater than zero). The Government’s hope is that such a scheme would foster innovation in the smart energy market, and create the conditions for small-scale generation to be rewarded according to its market value. Notwithstanding its concern with the delay between the closure of the feed-in tariff and the start of the Smart Export Guarantee, the Renewable Energy Association said that it welcomed the new scheme overall as a “positive step towards a more decarbonised, local, and cheaper power system”.
72.Certain details of the announced Smart Export Guarantee scheme have, however, caused industry concern. In response to the consultation on the Smart Export Guarantee scheme, the Solar Trade Association highlighted the vulnerability of households operating small-scale generation or storage systems compared to large-scale operators, as well as the potentially limited number of households with smart meters capable of fulfilling the requirements of the Smart Export Guarantee scheme. It argued that, in order to safeguard the small generation market, the Government should set a “fair minimum export floor price”. Dr Nina Skorupska, Chief Executive of the Renewable Energy Association, similarly told us that her Association was advocating a “framework that makes sense from a market perspective but also makes sense for a consumer or developer”, and indicated that this would require a “minimum index-linked safe tariff”. Professor Keith Bell, co-Director of the UK Energy Research Centre, also told us that “some kind of minimum export price would be extremely useful”, but accepted that “there is a bit of work to do to define what that would be”. In addition to advocating a minimum export price, Dr Skorupska has also said that “minimum contract lengths should be required to give future generators certainty”. The Durham Energy Institute also told us that the new scheme should be “guaranteed over a sufficiently long time frame to ensure that continuity, consistency and clarity releases private investment”.
73.In its confirmation of the Smart Export Guarantee scheme in June 2019, the Government stated that Ofgem would report annually on the uptake and nature of tariffs offered and committed itself to “monitor[ing] whether the market is delivering an effective range of options for small exporters”. It also commented that “since the closure of the feed-in tariff scheme, there have been encouraging early signs that a nascent export market is developing”:
Some suppliers are offering or trialling export tariffs, either in line with the wholesale price or at levels comparable with the feed-in tariff export tariff rate. We believe that these encouraging signals show that suppliers are keen to engage in this market and meaningful and competitive offerings will come through, without government taking the role of price setting.
These are, however, only early signs. The Solar Trade Association is monitoring the emergence of supplier offers for small-scale generators and so far lists just two offers from one supplier, alongside small-scale trials from two other suppliers.
74.The delay between the end of the feed-in tariff scheme and the start of the Smart Export Guarantee scheme has caused unnecessary disruption to the smart energy and small-scale generation market. Nonetheless, the move towards a framework that facilitates greater flexibility and innovation in these markets is welcome, provided it offers a fair and sufficient means of compensation for owners of small-scale renewable generation capacity and a sufficient incentive for people to make the initial investment in such technologies. The Government must ensure that it reviews the functioning of the Smart Export Guarantee scheme by the end of 2020, and should be ready to include a minimum price floor if there is evidence of a lack of market competitivity—for example, if uptake of tariffs is not significantly greater than the current number of tariffs or if the tariffs offered are significantly lower than wholesale electricity prices.
75.The Solar Trade Association additionally told us that its “industry has been further dismayed by the continuation of discriminatory business rate treatment of rooftop solar [power]”. In 2017, the Valuation Office Agency (an executive agency sponsored by HM Revenues and Customs) revised the methodology it applied to determine the rates applied to solar power, because the technology was more established than it had been at the previous valuation. This led to a sharp increase in rates, from between threefold to eightfold, for some solar power generation owners including schools and hospitals. The Solar Trade Association has since negotiated reduced business rates for companies that sell the majority of the solar power they generate, but this reduction does not apply to organisations that consume what they generate themselves (despite the potential for this to be more efficient, since no electricity transmission is required). Consequently, the Association now provides guidance on how companies can establish ‘special purpose vehicles’ so that their panels are legally distinct entities from which they can then ‘buy’ their electricity. A spokesman for the Association has reportedly said that “firms are circumnavigating the rates by doing this, but it is administratively expensive”. Additionally, an exemption from business rates for microgeneration sites (those producing no more than 50kW) ended on 31 March 2017. The Solar Trade Association has called for rooftop solar panels to be classed as “excepted plant and machinery” under the business rate regulations, to match the exception already applied to combined heat and power units.
76.The Government must make sure that business rates incentivise embedded low-carbon generation and do not cause existing embedded generation to be disconnected. The Government should reduce business rates for organisations that consume the majority of the power they generate to match the rates of organisations that sell the majority of their generation—and stop the administrative burden of loopholes that are being used to counter the discrepancy in rates. The Government should also reinstate the microgeneration exemption from business rates for renewable energy installations producing no more than 50kW. In its response to this Report, the Government should set out why combined heat and power units have been classed as excepted plant and machinery under the business rate regulations, but such a provision is not applied to solar panels and energy storage systems.
77.Despite discussion of the closure of the feed-in tariff and the business rate rises, Dr Skorupska, Chief Executive of the Renewable Energy Association, told us that “the biggest challenge to small-scale renewables are the grid reforms”. This refers to Ofgem’s proposals to change how the costs of electricity networks are recovered (see Box 2). This has been prompted by Ofgem’s concern that “the current framework for residual charging may result in inefficient use of the networks”:
As a result of changes in technology and other factors, some network users are increasingly able to adjust the timing and volume of their production and/or consumption of electricity, reducing their exposure to charges. Therefore current residual charges will increasingly fall on those network users who are not able to do this. Those who are less likely to be able to adjust their consumption are likely to include residential and small business consumers in general and more vulnerable consumers in particular.
Ofgem has therefore proposed introducing a fixed charge so that consumers pay only according to their ‘customer segment’ rather than the extent to which they use the network. In addition to protecting vulnerable consumers, Ofgem has argued that this could save consumers £0.5–1.6bn by 2040.
Box 2: Network costs
The costs associated with building, maintaining and operating electricity networks are currently recovered through two main charges levied on electricity consumers (through their bills): ‘forward-looking charges’; and ‘residual charges’.
Forward-looking charges are based on projected use of the network whereas residual charges are applied retrospectively to recover any costs not recovered through forward-looking charges. The overall costs, incorporating both components, are determined through Ofgem’s price controls, which set the total revenue the network companies are allowed to earn.
Ofgem has said that “residual charges are not intended to send signals or provide incentives to use networks in any particular way”, which is instead the role of the forward-looking charges.
78.The Solar Trade Association has warned, however, that “a flat, fixed rate will dampen the price signal sent to consumers to encourage the uptake of technologies, products and behaviours that encourage flexibility”. Following the publication of Ofgem’s proposals, six relevant trade associations, including the Renewable Energy Association and the Association for Decentralised Energy, issued a joint statement arguing that the proposals ran “contradictory to Government’s ambition to decarbonise the energy system and create a market for flexibility”. Ofgem itself has estimated that the average domestic consumer using solar power with energy storage could see network charges increase from £25 per year to £64 per year, while small- to medium-sized enterprises using on-site generation and storage could see charges increase from £204 per year to £1,099 per year.
79.Ofgem must consider the interests of future consumers as well as current consumers in its decisions, including the need for decarbonisation. The projected increases in network costs for consumers and businesses that have installed on-site generation and flexibility technologies, arising from Ofgem’s proposed network charging reforms, will act as a disincentive for further consumers or enterprises to install similar technologies. This is not conducive to the overall goal of decarbonisation. However, Ofgem is right to seek to avoid the costs of network usage falling increasingly on vulnerable consumers. Ofgem must revise its proposed network charging reforms to ensure that they do not disincentivise the deployment of technologies that will contribute to the decarbonisation of the UK’s energy system. The Government must ensure that vulnerable consumers do not pay an increasing proportion of network costs, and that all households have the ability to deploy technologies that will reduce their cost of energy and help to decarbonise the economy.
80.The Intergovernmental Panel on Climate Change has estimated that the full lifecycle emissions associated with nuclear power are significantly lower than coal or gas power, less than solar power and comparable to wind power. In 2017, nuclear power accounted for 21% of the UK’s electricity generation.
81.The UK currently has eight nuclear power plants, of which seven are planned to close by 2030. These seven have a generation capacity of 7.7GW, or 87% of existing nuclear capacity. One new plant, at Hinkley Point in Somerset, is currently under construction, which should provide 3.2GW of capacity by 2025. There are proposals for new plants at Sizewell, in Suffolk, and at Bradwell, in Essex, which would be expected to provide a further 3.2GW and 2.3GW of generation capacity respectively. However, plans for new reactors at Moorside, in Cumbria, Wylfa, in Anglesey, and Oldbury, in Gloucestershire, have reportedly been recently suspended. The Minister for Energy and Clean Growth, Claire Perry MP, explained that:
You have to spend taxpayers’ money wisely. Given the precipitous decline [in costs], particularly in other renewable technologies, it became apparent that some of the financial proposals put forward for Wylfa in particular were just not good value for money, but those negotiations and conversations continue.
The National Infrastructure Commission estimated in 2018 that the “average cost of the electricity system as a whole between 2030 and 2050 is broadly comparable between investing heavily in nuclear power stations or investing heavily in renewables”. However, it noted that whereas cost-reductions for renewable power technologies have had a track record of outperforming expectations, nuclear power costs have displayed “no discernible trend in construction costs over time”. This appears to be substantiated by historic evidence. Dr Robert Gross, co-Director of the UK Energy Research Centre, similarly told us that there was no evidence of cost reductions in nuclear power outside of East Asia. Looking forward, however, the Energy Systems Catapult told us that “UK nuclear new build has very significant cost reduction potential”, provided that the Government could work with stakeholders to provide “schedule and budget certainty”.
82.Tom Greatrex, Chief Executive of the Nuclear Industry Association, told us that “it is the cost of capital that has the biggest single impact” on the cost of nuclear power, and said that the viability of future nuclear projects would be “determined largely by how much progress is made on adopting a more appropriate financing model”. In November 2018, the Secretary of State for Business, Energy and Industrial Strategy, Greg Clark MP, said that the Government was exploring alternative financing models for new nuclear plants. In particular, he mentioned a ‘Regulated Asset Base’ model, which would provide a return to investors determined by an independent regulator (see Box 3). Professor Dieter Helm, of Oxford University, has said that such a model was “second best” behind direct Government procurement, but accepted that since direct procurement was essentially “ruled out by the Treasury imposed constraints”, the Regulated Asset Base model was “both plausible and preferable to the Hinkley model” (the main alternative). In contrast, the National Infrastructure Commission has cautioned that “there is limited experience of using the regulated asset base model for anything as complex and risky as nuclear [power]” and said that “it is not clear what the best model” for financing new nuclear power projects would be. Dr Gross told us that a new nuclear power station “could be cheaper than Hinkley”, but that in order to achieve this the Government would need to “take a public stake in the ownership” of the plant.
Box 3: The Regulated Asset Base model
Under the Regulated Asset Base model, an independent regulator manages the return on investment that investors in the construction of an infrastructure asset receive. This return on investment is recovered from consumers. In the case of a nuclear power station, this would be through consumers’ energy bills. Depending upon the details of the model used, investors can start to receive their return on investment during the construction of the power plant. This can increase the attractiveness to investors, who currently must invest many years before the plant will start generating power and therefore income. Different models either involve investors accepting all of the risks of the project not being completed (in return for a greater return on investment) or the risk being shared between investors and consumers. A Regulated Asset Base model has been used to fund construction of the Thames Tideway Tunnel project.
83.The Secretary of State for Business, Energy and Industrial Strategy told Parliament in January 2019 that the Government intended to publish its assessment of the Regulated Asset Base model for new nuclear power projects “by the summer at the latest”. Tom Greatrex told us that there was “real urgency” in the need for a decision from the Government on future financing models for nuclear power, and highlighted one timepoint in particular:
There is a point at which you can, in a relatively straightforward way, transfer the supply chain [from Hinkley to Sizewell] and use the same equipment while the supply chain is in place. That means EDF needs to make a final investment decision, probably in 2021–22, so that needs a policy framework in the next year or so to be able to be in a sufficiently strong position to deliver that project, get the maximum cost reduction and make that contribution to help replace the fleet, most of which is going off by 2030.
This aligns with the National Infrastructure Commission’s recommended “one by one” approach to new nuclear plants, in which the UK seeks to maintain—but not grow—its nuclear industry and supply chains, by planning to be building no more than one new nuclear plant at a time.
84.Although it is not possible to directly compare the costs of different power generation technologies, the Government is right to support nuclear power subject to it representing value for money, because full lifecycle emissions from nuclear power will help the UK to achieve its emissions reduction targets. The Government must make a decision on implementing a regulated asset base framework for nuclear power by the end of this year. Subject to value for money, the Government should seek to support new nuclear power generation so as to sustain, but not grow, the UK’s nuclear power industry. It must anticipate any gap in future generation capacity such a policy would cause, and support sufficient renewable power alternatives to fill the gap.
85.Small modular nuclear reactors (SMRs) are made of standardised factory-manufactured parts delivered ready for assembly, although Tom Greatrex clarified that “SMRs are used as a catch-all term for a whole range of different technologies”. SMRs may offer nuclear power at lower cost than conventional nuclear power plants because of their amenability to mass manufacture, as a result of their size and standardisation. Rolls-Royce, a major developer of SMRs, told us that these reactors “offer a convincing alternative to the uncertainties of large nuclear new build in the UK” and said that it was “prepared to invest in [an SMR development] programme, if matched by Government support”.
86.The Government’s ‘Expert Finance Working Group on Small Nuclear Reactors’ recently concluded that the UK “could be well placed to develop first-of-a-kind small reactors projects”. It made seven recommendations for Government action to support development of SMRs in the UK, including:
87.One component of the Government’s Nuclear Sector Deal was a new framework for SMRs, with the Government providing up to £56m to support the research and development of advanced nuclear technologies and stating its intention to “bring together vendors, utilities, energy intensive users and the finance sector to further develop credible commercial propositions that could be financed by the private sector” in response to the Expert Finance Working Group’s recommendations for developing first-of-a-kind projects. Tom Greatrex indicated that “the whole range” of recommendations from the Expert Finance Working Group “need to be implemented if [the UK wants] to try to have the opportunity of small modular reactors”.
88.The Government’s support for small modular nuclear reactors in the Nuclear Sector Deal is welcome. The Government must ensure that it delivers on the recommendations from the Expert Finance Working Group on Small Nuclear Reactors, including on regulatory developments, without undue delay. The Government should set out, in its response to this Report, what steps it has taken since the publication of the Group’s report and propose a pathway—with indicative dates for key milestones—for the deployment of a first-of-a-kind small modular nuclear reactor by 2030.
89.Conventional nuclear power and small modular nuclear reactors generate power from nuclear fission, which is the separation of heavy elements into lighter ones. An alternative is to generate power from nuclear fusion, which is the production of heavier elements from light ones. Tokamak Energy Ltd described the following benefits of nuclear fusion:
Fusion energy from tokamaks will be clean and safe. There is no emission of carbon from combustion, no long-lived radioactive waste and no risk of meltdown or proliferation. There is plentiful fuel for mankind’s total needs for millennia.
Professor Jim Skea, of Imperial College London, told us however that the “problem” with nuclear fusion was that “while fusion has stayed 30 or 40 years in the future, other things like nuclear fission and renewable energy have achieved that kind of goal in the shorter term”. The Engineering and Physical Sciences Research Council has said that although “the timeline for delivery is beyond the 2050 emission target, fusion is an attractive technology that needs to be developed”.
90.The UK has a national nuclear fusion programme at the Culham Centre for Fusion Energy, which also hosts the Joint European Torus (currently the most powerful magnetic fusion device in the world) on behalf of the EUROfusion consortium funded as part of EURATOM 2020. Both programmes receive funding from the EU under the EURATOM treaty. The Government confirmed in 2017 its intention to leave EURATOM as it leaves the EU. The Government signed an agreement with the European Commission in March 2019 to keep the Joint European Torus open until the end of 2020, securing at least €100m in additional inward investment from the EU.
91.Tokamak Energy Ltd, which aims to accelerate the development and deployment of fusion energy, told us that it had now attracted over £50m of private investment but argued that the Government should “do more to encourage stronger private investment in fusion energy development”, flagging recent developments in the USA:
The US Nuclear Energy Innovation and Modernization Act (NEIMA) was passed in January 2019. It explicitly includes fusion in the definition of “advanced nuclear reactor” and provides for establishment of a regulatory framework for advanced nuclear power plants, including fusion, by December 2027.
Acknowledging the UK Atomic Energy Authority’s recently announced ‘Spherical Tokamak for Energy Production’ project that aims to design and build a compact fusion power station in the UK by 2040, Tokamak Energy Ltd nevertheless argued that the Government should “do more to encourage stronger private investment in fusion energy development, for example by matching some of the legislative and policy measures used in the USA to encourage private ventures to develop fusion technology and future fusion power plants”.
92.Nuclear fusion is unlikely to make a substantial contribution to the UK’s net-zero target for 2050. Nevertheless, it could ultimately provide significant quantities of energy from abundant fuels and without radioactive waste. The Government must ensure that, whatever the terms of the UK’s departure from the European Union, the long-term future of nuclear fusion research in the UK is not disrupted. It should additionally review the case for providing support for the nuclear fusion industry similar to the measures introduced recently by the US Government.
136 Department for Business, Energy and Industrial Strategy, ‘’ (2019), p6
137 Committee on Climate Change, ‘’ (2018), p56
138 Committee on Climate Change, ‘’ (2018), p53
139 Committee on Climate Change, ‘’ (2018), p11
140 Committee on Climate Change, ‘’ (2018), p68
141 Department for Business, Energy and Industrial Strategy, ‘’ (2018)
142 Department for Business, Energy and Industrial Strategy, ‘’ (2019), Tables 1 and 2; Committee analysis
143 Department for Business, Energy and Industrial Strategy, ‘’ (2019), p3 and Carbon Budget Order 2011 (); Committee analysis
144 Department for Business, Energy and Industrial Strategy, ‘’ (2018), p117
145 Intergovernmental Panel on Climate Change, ‘’ (2014), p539
146 Department for Business, Energy and Industrial Strategy, ‘’ (2018), p117
147 Department for Business, Energy and Industrial Strategy, ‘’ (2018), p3
148 ‘’, International Atomic Energy Agency, accessed 17 April 2019
149 National Infrastructure Commission, ‘’ (2016), p5
150 National Grid Energy Systems Operator, ‘’ (2018), p3
151 Committee on Climate Change, ‘’ (2018), p59
152 Current generation taken from Department for Business, Energy and Industrial Strategy, ‘’ (2018); Science and Technology Committee analysis
153 National Grid System Operator, ‘’ (2018), p96
155 HM Government, ‘’ (2018) and ‘’ (2019)
156 HM Government, ‘’ (2018), p7
157 HM Government, ‘’ (2019), p4
158 HM Government, ‘’ (2018)
159 HM Government, ‘’ (2018), p7
160 HM Government, ‘’ (2019), p4
161 Committee analysis assuming a load factor of about 40%, which offshore wind has consistently achieved since 2013—Department for Business, Energy and Industrial Strategy, ‘’ (2018), p185
162 ‘’, Department for Business, Energy and Industrial Strategy, accessed 30 May 2019
165 Offshore Renewable Energy Catapult ()
167 Committee on Climate Change, ‘’ (2018), pp59 and 64
170 Committee on Climate Change, ‘’ (2018), pp74 and 78
171 Committee on Climate Change, ‘’ (2018), p83
172 ‘’, BBC News, 8 November 2018 and ‘’, BBC News, 17 January 2019
174 National Grid System Operator, ‘’ (2019) and HM Government, ‘’ (2017), p96
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176 UK Energy Research Centre, ‘’ (2017), p1
177 ‘’, Department for Business, Energy and Industrial Strategy, accessed 3 June 2019
178 Department of Energy and Climate Change, ‘’ (2015) and Department for Business, Energy and Industrial Strategy, ‘’ (2017)
179 For example, see Drax Group plc (), para 39
180 Department for Business, Energy and Industrial Strategy, ‘’ (2017)
181 Department for Business, Energy and Industrial Strategy, ‘’ (2017), p99
182 For example, see: EDF Energy (), para 8; Energy UK (), paras 5–6; E.ON (), para 17; RenewableUK (), section 2; and
183 Committee on Climate Change, ‘’ (2018), p54 and National Infrastructure Commission, ‘’ (2018), pp40–42
184 Wind Europe, ‘’ (2019), p17
185 Department for Business, Energy and Industrial Strategy, ‘’ (2016), p29
186 Department for Business, Energy and Industrial Strategy (), para 18
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188 Solar Trade Association (), para 3 and Solar Power Europe, ‘’ (2018), p20
189 Committee on Climate Change, ‘’ (2018), p61
190 ; the Committee on Climate Change, of which Prof Bell was recently made a member, similarly said in 2017 that “with suitable long-term contracts [renewable power technologies] can be deployed without subsidy beyond the application of a carbon price to fossil fuel generation”—’’, Committee on Climate Change, accessed 7 June 2019
192 BVG Associates, ‘’ (2018)—this report was commissioned by ScottishPower Renewables, Innogy, Statkraft and Vattenfall
193 Citizens Advice, ‘’ (2016)
194 M. Grubb and P. Drummond, ‘’ (2018)
196 Conservative and Unionist Party, ‘’ (2017), p22
198 Department for Business, Energy and Industrial Strategy, ‘’ (2019), pp25–26
199 Energy UK (), para 6
200 Centre for Sustainable Energy ‘’ (2017), p2; the policy guidance was changed by , 18 June 2015
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213 HM Government, ‘’ (2019) and Department for Business, Energy and Industrial Strategy, ‘’ (2017), p99
214 For example, see: Renewable Energy Association (), paras 7 and 9; Nova Innovation Ltd (); Marine Energy Wales (); The Geological Society (), para 3; RenewableUK (), section 3
215 RenewableUK (), section 3
216 See: Menter Mon (); Sustainable Marine Energy (), para 9; Marine Energy Wales (), para 5.3; RenewableUK (), section 3
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218 Marine Energy Wales (), para 5.3
219 Committee on Climate Change, ‘’ (2018), p59
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223 Ministry of Housing, Communities and Local Government, ‘’ (2018), para 154
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264 Open from Ofgem, 4 August 2017
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268 from BEAMA, Association for Decentralised Energy, techUK, Renewable Energy Association, Solar Trade Association and RenewableUK to Rt Hon Greg Clark, 4 February 2019
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281 Energy Systems Catapult (), para 24
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286 National Infrastructure Commission, ‘’ (2018), p38
288 Rt Hon Greg Clark MP, ‘’, 17 January 2019
291 National Infrastructure Commission, ‘’ (2018), p39
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297 HM Government, ‘’ (2018), pp21–23
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305 European Union (Notification of Withdrawal) Act 2017, and HM Government, ‘’ (2017), chapter 9
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307 Tokamak Energy Ltd (), para 5
308 ‘’, Nuclear Advanced Manufacturing Research Centre, accessed 9 July 2019
309 Tokamak Energy Ltd (), paras 6 and 9–11
Published: 22 August 2019