Devices, mostly distribution connected, storing electricity generated by low carbon sources when supply is abundant and releasing it at peak demand times.
Physical links allowing for energy flows between countries to maintain system balance. When demand is high in the UK, interconnectors import electricity from overseas, when supply is high, they export clean power.
Zero carbon emissions transport fleet relying on electric cars or hydrogen for heavy good vehicles and shipping.
Industrial organisations vary their demand for energy to smooth network constraints through flexible contracts with financial incentives. For example, delaying an energy-intensive process to another time when energy demand is very high throughout the system.
Corporates use the renewable energy supplied to them directly from their premises. The generator and the consumer are directly connected without going through the distribution network or through a licenced supplier.
Low carbon demand for electricity or hydrogen to power production processes, engines and green transport.
Renewable plants such as offshore and onshore wind farms providing clean cheap electricity supply at scale and connected to the high voltage transmission network.
Renewable plants such as offshore and onshore wind farms providing clean cheap electricity supply at scale and connected to the high voltage transmission network.
Flexible demand from electrified and energy efficient homes where users balance their consumption with smart meters and flexible tariffs. Consumers offer “behind-the-meter” services to the network such as electricity supply from their plug-in electric vehicles or their solar panels.
Urban areas using digital technology to collect data and manage assets such as travel infrastructure, heating systems in a smart and sustainable way. Neighbourhoods and business can also use data and small-scale green generation to increase their energy resilience and flexibility via electricity trading or the creation of microgrids.
Third party intermediaries managing demand from consumers and supply from generation plants.
They send signals to consumers to modify their demand as a response to the system’s requirements or market prices.
A small network of electricity users with a local source of supply able to function independently from the national network, and to take actions to reduce demand/supply to maintain self-balance.
A renewables-led net zero revolution
At the end of a stunning decade of growth for renewables and building on our commitments under the Paris Agreement, the UK set a legally binding target of achieving net zero emissions by 2050. But what does “net zero” really mean? While the decarbonisation of the power sector is well underway, removing all carbon emissions from all the sectors of our economies is a challenge of a different order.
Net zero emissions ultimately means that the total balance of our emissions should be neutral. Any remaining emissions from hard-to-decarbonise sectors of the economy will have to be additionally offset by negative emissions in other sectors by, for example, capturing carbon from the air or through large-scale reforestation.
The bedrock of the transition to net zero in the UK is the transformation of the energy system from an inflexible, centralised, high carbon system to a smart, flexible, low carbon system dominated by renewable energy
RenewableUK members are delivering innovative solutions to climate change
Reaching net zero will mean virtually ending emissions from the power sector. Our members have the expertise and experience to achieve this, and the technologies to do so are widely available and affordable globally. In the decades ahead, renewable energy sources will penetrate the global energy markets faster than any other source in history, completely changing the way the energy system01BP Energy outlook 2019 operates. And they are here to stay.
In terms of how we both generate and consume energy, changes are happening which will bring greater flexibility, transparency and digitisation. We are confident that with the right markets and policies, we can secure low cost energy, decarbonisation and energy security through a renewables-led system
RenewableUK is optimistic, but we need to go further, faster. This is our vision of the energy transition.
The next decade will be the most important fight against climate change: the final decade to avoid disaster.
Scientists say that we have only 10 years to put the systems and investments in place that will prevent temperatures from rising above 1.5°C – or risk an exponential increase in climate-related disasters. The Committee on Climate Change (CCC) suggests that if replicated around the world, policies to deliver the UK net zero target would deliver a greater than 50% chance of limiting the temperature increase to 1.5 degrees.
This decade will be the most important in the fight against climate change: the final decade to avoid disaster.
This report explores our vision of changes in the energy system over the next 30 years to meet our net zero target. From the rapid, total decarbonisation of our power sector to greening our other energy sources, RenewableUK members are leading the fastest energy transition of any major economy
Future energy supply
The Government’s scheme for clean power auctions, Contracts for Difference (CfD), has been very successful in creating a stable, reliable framework for investment in renewable capacity in the UK. The CfD is designed to deliver large volumes of low carbon power at the lowest net cost to the consumer. In the case of offshore wind, it has harnessed the powers of the market to successfully deliver large volumes of cheap, low carbon energy. The scheme has ultimately allowed unprecedented cost reductions over the past five years. CfD contracts allow owners of capital-intensive projects such as wind farms, to have a 15-year visibility on their future revenue for energy supplied to the electricity grid. This has allowed them to significantly reduce their cost of capital (the cost of borrowing in most cases), become more competitive and, in turn, push their prices down. The UK system has become the preferred regime to deploy renewable energy infrastructure projects and the UK’s two-way CfD model is being replicated in many other countries as it is recognised as procuring the greatest volumes at least cost. The International Renewable Energy Agency (IRENA) calculate that onshore wind and solar PV are now a less expensive source of new electricity than the cheapest fossil fuel alternatives globally03https://www.irena.org/newsroom/pressreleases/2019/May/Falling-Renewable-Power-Costs-Open-Door-to-Greater-Climate-Ambition . In 2019, all the wind capacity commissioned in the UK came from projects having previously secured a CfD contractCfD contractThe Contracts for Difference (CfD) scheme is the government’s main mechanism for supporting low-carbon electricity generation. CfDs incentivise investment in renewable energy by providing developers of projects with high upfront costs and long lifetimes with direct protection from volatile wholesale prices, and they protect consumers from paying increased support costs when electricity prices are high..
Onshore wind and solar PV are now a less expensive source of new electricity than the cheapest fossil fuel alternatives globally
Looking to the future, as old conventional generation retires and nuclear power stations come to the end of their operational lives, the need to ramp up the deployment of all renewable energy sources becomes even more urgent. This combination of factors could result in what the CCC calls the “low carbon generation gap” of over 30TWh by 2030 in addition to the low carbon capacity already secured (Hinkley Point C Nuclear power station and renewable technologies from CfD Allocation Rounds One and Two).
In June 2019, the UK Government committed to a new legally binding target of “net zero” by 2050, following an increased desire from the public for action to tackle climate change, and the huge success of renewable deployment. The Scottish Government and the Welsh Government adopted targets of net zero by 2045 and 2050 respectively. These targets mean that the progress we have seen so far, and the technology delivered to date, will now have to go further and faster. RenewableUK members are at the centre of delivering this ambition. They are already investing, building and supplying the electricity that the system will rely on within the next decade
II. Future technologies needed in a renewable-led power system
A. Offshore wind
Since the first offshore wind farm was built off the coast of Blyth in 2000, the UK’s operational capacity has now grown to almost 10GW.
With more projects already under construction or with contracts, as well as projects with leasing and in development, the UK has the pipeline to deliver 37GW (subject to the challenges described below). We also have a new extensions and further rounds of leasing from The Crown Estate and Crown Estate Scotland which will add to the UK offshore potential.
Wind deployment in the UK
The cost reduction achieved by the offshore wind industry has been remarkable and it is testament to strong partnership working between government and industry, and continuing innovation from the offshore sector. In 2012, the Offshore Wind Programme Board (OWPB) showcased the industry’s strong ambitions by committing to driving costs down to £100/MWh for project contracts signed from 202004Offshore wind cost reduction task force report, Offshore Wind Programme Board, 2012. The commitment was considered pioneering at the time, but it instilled a sense of trust within markets participants to believe in the sector and to provide certainty for the necessary investment in innovation and supply chain development. The sector achieved it four years in advance of the deadline.
The Contract for Difference regime has been one of the main accelerators of offshore wind deployment. In the three auction rounds held so far, strike prices – stabilised price received per MWh of electricity supplied – went from £119.89 for projects built in 2017 to £39.6505Strike price results from the CfD allocation rounds in 2014 and 2019 in £2012 prices for projects to be built in 2023, ahead of the OWPB targets. This is almost a 70% reduction in cost over the last five years. Projects securing contracts in the most recent allocation round could end up paying back to consumers; as an illustration Government’s intermittent reference price in 2025 is £50.90/MWh06https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/799074/Allocation_Round_3_Allocation_Framework__2019.pdf, which means that developers would ultimately receive £50.90/MWh from selling their power and pay £11.25/MWh back to consumers, therefore keeping £39.65/MWh. The cost reduction has been achieved as project developers have gained confidence and experience, technology innovation, building trust in their supply chain and investors. This has in turn allowed innovation and incredible technology advancements to come forward. Most importantly, the cost of borrowing capital through long term contracts has fallen thanks to the certainty provided by the CfD. Our analysis shows that the Internal Rate of Return (IRR, the expected return on investment) is the factor that has the greatest influence on the cost of an offshore project.
Offshore in the UK
RenewableUK’s offshore model calculates projects’ construction timescales, based on size, distance from shore, number of turbines, array cable length, number of cables and other equipment required. Our latest forecasts include the decommissioning of projects reaching over 25 years of life. The model shows that 2024 and 2025 will be exciting years for the delivery of our offshore wind deployment and its supply chain. Over 5.5GW of capacity should be commissioned between these two years, the highest build out rates ever seen in our country. Furthermore, the first 12MW turbines – the world’s most powerful wind turbine as of 2020 developed by GE – will be erected for the first time in the US and shortly thereafter in UK waters. At the same time, the world’s biggest offshore wind farm development is planning to release first power in the UK by 202307Dogger Bank Projects by Equinor and SSE will have a total installed capacity of 3.6GW By 2025, over 20GW of offshore wind will be operational in the UK seas, twice the capacity we have now.
Last year, the Offshore Wind Sector Deal signed between the UK Government and the Offshore Wind Industry Council included a target of 30GW by 2030. Since then, the positive results from the latest auctions in September 2019 and new climate targets, have seen ambition increase even further to 40GW by 2030. The offshore wind sector supports these targets and believes they can be achieved if the leasing, planning and procuring frameworks all allow for that ramp up.
RenewableUK’s offshore wind scenario shows that with the right incentives, operational wind capacity could reach 40GW by 2030, in line with the UK Government’s offshore wind target. We then see offshore wind potentially ramping up to over 90 GW by 2050 in our high ambition scenario. However, such an increase in deployment will not be possible without some specific assumptions supporting the build out rates of the technology in the medium term, and life extension and their individual investment cases in the longer term.
Deploying offshore wind at the scale and pace required to meet the UK’s increased ambition and our net-zero target is not without its challenges. First and foremost is the need for a strong partnership between industry and Government, and accelerated cooperation between Government departments. The scenario presented here is based on a move to annual auctions after the next planned auction rounds in 2021 and 2023. With faster timeframes, the UK could hold two further auction rounds from 2024 to deliver new projects in time for 2030.
Another important point to consider is the barriers faced by project developers operating in a busy marine environment, with many users of seabed space. Whilst recognising offshore wind’s significant contribution to tackling climate change, development must be done in harmony with maintaining the biodiversity of the marine environment. With the potential to restore and improve marine environments, a holistic and cross sector approach to marine management is necessary to keep our seas sustainable. This will require partnership working with other industries – such as shipping, fishing, aviation, oil and gas, aggregates etc. Marine industries can no longer work in silos but must together find a more strategic approach to effective co-existence. In a decade of action, activities in UK waters must be prioritised, with overarching policies being re-thought to realise the change required to meet net-zero. The management of this changing environment, a requirement for rapid change and the need for effective delivery of projects will not happen without people. Significant resource, particularly within the statutory bodies, is required to champion our vision, ensuring that as a collective, the UK marine environment delivers on its targets
Increasing our offshore wind capacity will require working in partnership with other industries in the sea like shipping, aviation, oil and gas whilst respecting the environment
During the investment decision process, wind farm developers estimate how much electricity they will be able to supply and how cost efficient their technology will be. The ability to rely on the offshore transmission network to efficiently sell the power and optimise the assets weighs on the ability to deploy an asset and its cost. As more wind farms are deployed in the North Sea, a coordinated strategy in connecting them to a more complex offshore high voltage network will be key. Under the current system, projects are having to wait up to 10 years to connect to the grid and projects without a grid connection offer are not allowed to participate in CfD auction rounds. Timely connection agreements are vital to meet our deployment schedules.
Ramping up deployment of offshore wind to the levels set out by the UK Government and supported by the CCC, will also mean enabling innovative technologies such as floating offshore wind, which can access deeper waters, thereby increasing geographic diversity. RenewableUK’s model assumes the deployment of floating offshore wind is competitively allocated alongside fixed bottom offshore wind after 2030. The industry is confident it can deploy up to 2GW of floating offshore wind in the UK waters before 2030. The technology could reach cost parity with bottom fixed offshore turbines in the 2030s, as developers move further offshore where the wind resources can be higher and more consistent. Floating offshore wind could eventually be cheaper and faster to install than fixed bottom turbines, and therefore the model assumes that up to 20GW of the operational offshore capacity by 2050 could come from floating wind turbines.
To meet the levels of deployment required to achieve net zero, it will be necessary to ensure a sustained roll out of commercial scale floating wind, and the repowering of the older wind farms to ensure we do not lose valuable generating capacity. This potential requires a credible, transparent framework allowing for the utilisation of innovation happening in the sector: newer and more efficient wind turbines, reaching deeper waters and windier regions in the sea with optimised operations and maintenance.
New offshore wind projects have a 60-year lease contract which means they could be optimised to operate beyond their expected designed lifetime if the regulatory regime allowed asset owners to perform the required changes to their site. The current design life of an offshore turbine is typically around 25 years. Technological improvements could allow turbines to perform better and for longer. Fatigue-loading can happen after a load bearing component (i.e. foundations) has been used for a long period of time. It means that the assets in most cases will have to be optimised if the project is to run for longer than 25 years. Historic data on offshore wind repowering in the UK currently does not exist, and the UK Government is only just starting to look at the regulation around end of life.
Our high ambition deployment scenario suggests that by 2050, assuming the above recommendations are followed, offshore wind capacity (including floating) could reach over 90GW if the current capacity is able to keep operating until then. However, as the chart shows, without the full repowering or life extension of the wind farms, capacity could be limited to 71GW. This would fall short of the CCC’s 75GW by 2050 in a net zero scenario. Repowered projects, as is the case in the onshore sector, usually upgrade old equipment with more efficient technology, thereby increasing their total capacity. The government’s end of life decommissioning guidance will be of great importance to the sector and will allow us to position ourselves on the higher end of that forecast. RenewableUK believes that the newest projects with High Voltage Direct Connections (HVDC) will be better equipped to upgrade their assets to bigger and more powerful turbines, without the need to fully change the layout and the connection cables. Such assets could therefore be more likely to repower than the older wind farms that are currently being decommissioned
B. Onshore wind
When it comes to achieving net zero, reliance on a single technology is not an option and so a range of low carbon sources are needed to meet 100% of our electricity needs. Onshore wind in the UK has a vital role to play in meeting that ambition. The sector has grown significantly since the UK’s first commercial wind farm, Delabole, started generating electricity in Cornwall in 1991. With over 13 GW of installed capacity, the onshore wind sector is currently powering the equivalent of more than eight million homes in the UK every year. In 2019, onshore wind generation supplied 10% of our electricity. From small distribution-connected wind farms to utility-scale sites, the onshore wind industry provides the diverse, clean and cheap generation that the grid needs. However, the CCC recommends a much greater level of deployment by 2030 to ensure we keep on track with our net zero ambitions. Their indicative scenario suggests an indicative level of 35GW by 2035.
The cost of onshore wind generation continues to fall, and it is one of the cheapest forms of new generation at a global level, with a maximum Levelised Cost of Energy (LCOE) in the UK of around £49.40/MWh, at 2017 prices for projects commissioning next year (2021)09£49.4/MWh is the forecasted strike price for Onshore in a CfD auction, assumed to be the highest LCOE at the time of the auction, BVG Associates, June 2018, The Power of Onshore Wind; this is lower than new build CCGT, the cheapest fossil-fuelled generation. At a global level, the cost reductions achieved in the industry have turned onshore wind into a major source of cheap, clean power and an essential technology of the energy transition.
However, despite this success, onshore wind has not been able to participate in the two last Contracts for Difference (CfD) auction and the industry build-out has slowed drastically as a result. Without a route to market, visibility on their investment and a supportive planning policy, project developers have struggled to make a viable business case. The UK Government’s announcement of the return of Pot 1 auctions for onshore wind and solar in March 2020 is therefore extremely welcomed and follows years of targeted and strategic advocacy from RenewableUK.
Our current dataset shows a small percentage of projects announced as “merchant”. This means that these projects are to be built on a merchant base (selling your power to a utility via the market) or with shorter term fixed purchase agreements with corporates (Corporate PPAs). These projects tend to have a higher cost of capital as the project owners bear the market price risk on their own10ARUP REPORT on CFD cost of capital.
RenewableUK has considered three main scenarios of onshore build out. In our lower growth scenario, without repowering or a support mechanism, onshore wind capacity would grow by only 1GW in the next decade as the rate of new wind farm installations is outpaced by the retirement of older projects. In our medium scenario, using past trends for merchant and repowering construction rates, our onshore wind model suggests that onshore capacity would grow to 20GW by 2030. By 2050, it would fall from that level as the merchant build out rates are not fast enough to compensate the lost capacity from decommissioning wind farms.
Our high forecast scenario envisages significant growth in onshore wind with capacity growing to 26GW by 2030 and 36GW by 2050, compliant with the CCC’s indications. Reaching this level requires a set of supportive policies from Government, such as the Pot 1 auction, and improved timescales for grid connection.
RenewableUK’s high forecast indeed shows that, in addition to the level of possible merchant projects observed, the rest of the deployment is procured through competitive government backed mechanisms (a Pot 1 CfD). The cost reduction observed in onshore wind in recent years and the competitive prices achieved in recent offshore wind auctions suggest that strike prices for onshore wind contracts are likely to be below wholesale prices, and even the capture pricescapture pricesFor more information on capture prices please see chapter 3, section 1 forecasted for onshore wind in the next decade. We anticipate that around 3.4GW of consented projects could participate in the next Pot 1 CfD auction. Recent strike price estimates published by BEIS in the Government’s consultation on future Auction Round 4, model a winning price of £33.00/MWh at 2012 prices. With greater access to ancillary markets to allow project developers to stack from different revenue streams, depending on the market and on their generation profile, we believe the number of projects choosing to go through the merchant route could increase as it would make the investment case more attractive to certain asset owners. Additionally, greater optimisation of asset use via different channels, will also mean that projects applying for a CfD become more competitive in their bidding.
The model indicates that the majority of onshore wind projects will be located in Scotland (over 20GW by 2050). Planning regulation is a devolved power and a more favourable planning framework for new build in Scotland, along with clearer guidance supporting repowering projects are likely to make it more attractive for project owners. The model, however, still assumes over 5GW of capacity coming from extended or repowered projects located in England by 2050, which will be crucial to reach the net zero levels mentioned above. Finally, similarly to offshore wind, onshore wind farms are subject to particularly long timescales when obtaining their network connections. The transmission and distribution operator’s capacity to efficiently increase the network capacity when and where it is needed and allocate it to clean decentralised energy projects in the pipeline, will determine the rate at which onshore wind projects are built over the next few decades.
Much more onshore wind capacity will be needed to achieve the levels of ambition necessitated by net zero
The important assumptions behind these modelled, high levels of deployment are therefore an effective planning environment with improved connection timescales and the ability to stack revenues. Regardless of which financing route developers pursue, it is clear that much more capacity will be needed to achieve the levels of ambition necessitated by net zero
C. Solar Technologies11Visit https://www.solar-trade.org.uk for more information on solar technologies in the UK
Solar PV is already a vital component of the UK’s renewable energy generation mix and will be essential to meeting the UK’s carbon budgets and net zero commitments too. Solar is one of the most cost-effective renewable energy technologies to deploy today, based on Levelised Cost of Electricity (LCOE). Solar can be deployed rapidly with sites able to begin supplying electricity to the grid within 6 months of beginning construction.
The Committee on Climate Change projects that 40GW of installed solar capacity will be needed by 2030 to keep on track to achieve net zero by 2050. As of January 2020, the total installed capacity of solar PV in the UK is 13.4GW12https://www.gov.uk/government/statistics/solar-photovoltaics-deployment.
After a downturn in the pace of solar PV deployment in recent years, following the removal of existing subsidy mechanisms, the solar sector has adapted swiftly alongside further cost decreases, pivoting largely to subsidy free and merchant-based project development. There are currently 7-8GW of utility scale solar PV projects in the pipeline, with over 1GW of projects added to the pipeline in the first quarter of 202013https://www.solarpowerportal.co.uk/blogs/uk_utility_solar_pipeline_continues_growth_near_term_window_allows_supplier. The latest figures show that there are currently over 1GW of shovel ready solar projects14https://www.gov.uk/government/publications/renewable-energy-planning-database-monthly-extract.
These figures represent predominantly utility scale projects. While the precise figures are harder to quantify, the Solar Trade Association (STA) anticipates that substantial additional capacity is in the pipeline from the commercial, industrial, and domestic markets as well. Of the projects currently in the development pipeline, the vast majority were already announced prior to the Government announcement that solar would be included in the next allocation round (AR4) of the Contracts for Difference (CfD) scheme. The additional certainty and support provided by access to CfDs for solar will undoubtedly bolster the development pipeline further.
The STA’s high ambition scenario forecasts a total operational capacity of 27 GW by 2030, assuming the reinstatement of Pot 1 technologies in CfDs, which the Government has already announced, alongside as strong Power Purchase Agreement (PPA) market, and reforms to business rates for solar. The Government will need to go even further with enabling measures if it wants to accelerate deployment in the medium to long term such as public sector PPAs and support for solar and storage within the Home Upgrades Grant Scheme to finance domestic retrofits.
Distribution grid upgrades will also be essential to allow continued growth of distributed solar generation throughout the 2020s. It will be crucial for Ofgem and Distribution Network Operators to work collaboratively with industry to create a favourable policy environment and target grid upgrades strategically to enable to greatest possible penetration of distributed generation assets.
D. Marine technologies
The UK’s tidal stream and wave energy industries are at a critical time in their development. While innovation and demonstration projects gained significant public support at the beginning of the last decade, the lack of a mechanism allowing the technology to be deployed beyond a handful of devices per project has now had a knock-on impact on private sector investor confidence. Currently there are 22 tidal and 23 wave energy developers in the UK and a potential 13GW in the pipeline. The majority of projects are located on the coasts of Orkney and Caithness in Scotland, west coast of Scotland, Northern Ireland and Anglesey, south wales and in the south west of England. However only under 10MW are currently operational. The latest UK based device commissioned was Orbital Marine’s 2MW tidal stream project in Orkney. which tested at EMEC’s tidal test site across 2017/18. The 6 MW MeyGen tidal stream project exported 13.8 GWh to the grid in 2019 alone.
Distributing diverse sources of clean energy supply in various locations of the UK is an important parameter to consider when building the energy supply of tomorrow. Tidal energy, in particular, can provide a predictable volume of power that is not related to the prevailing weather conditions, which makes it a great partner to wind and solar generation and, as a result, helps satisfy demand at low costs in 2050. Developers are willing to drive their innovation forward and we are seeing projects joining with electrolysis facilities to couple up the efficient production of power from marine sources with the production of renewable (green) hydrogen – a much-needed technology in the transition.
The UK’s tidal stream industry could bring economic benefits worth £1.4bn and support 4,000 jobs by 2030 and 14,500 by 2040. Wave technology could generate £4bn by 2040 with 8,100 jobs, focused in coastal areas in need of economic regeneration15“TIDAL STREAM AND WAVE ENERGY COST REDUCTION AND INDUSTRIAL BENEFIT”, OREC, 2018, https://s3-eu-west-1.amazonaws.com/media.newore.catapult/app/uploads/2018/05/04120736/Tidal-Stream-and-Wave-Energy-Cost-Reduction-and-Ind-Benefit-FINAL-v03.02.pdf. These calculations from the Offshore Renewable Energy Catapult assume a CfD-type revenue support of £1.3bn.
By 2050, the global market for marine renewables could grow to £76bn and almost every country with good marine resources is now supporting this industry – including Canada, the USA and China. However, there is a very real danger that as momentum grows in these countries, the UK risks handing over its global leadership to other countries. To benefit from this growth, the UK needs to present a clear success story of technology and project development, where UK companies can develop and showcase their expertise. Creating a framework in which these innovation projects can get certainty on their revenue, deploy and learn by doing will allow us to reap the benefits illustrated in OREC’s 2018 report soon. Within a competitive auction process, innovative technologies like these are at a disadvantage when compared to more established renewables. There is a need for a dedicated support for the commercialisation of wave and tidal technologies to deliver a world leading sector in the UK, which will create local economic benefits and a strong export sector
E. Energy Storage
Energy Storage represents a wide range of technologies, from different types of batteries (including Electric Vehicles) to compressed air, liquid air, and at the very large scale, pumped hydro and hydrogenpumped hydro and hydrogenFor more information on duration storage go to chapter 4.. These technologies will be heavily represented in our future mix and our members are actively trying to deploy and integrate them into their portfolios.
As the deployment of renewable generation increases, storing cheap renewable power, and when there is an excess, discharging it when demand is higher, will become vital to the future functioning of the grid. Battery storage is playing an increasing role in voltage control and frequency response – they already make up the vast majority of frequency response providers. It is therefore essential to the future of the UK’s energy system that storage is able to deploy at scale across the country. Innovation at global level has already allowed for important cost reductions in battery technology over recent years. This is making markets very bullish about the use of storage in the future, especially short-term, fast response batteries.
More than 10 GW of battery projects are built or planned to be built in the UK.
The majority of the storage pipeline in the UK is battery storage. More than 10GW of battery projects are built or planned to be built in the UK. The UK saw a step-change increase in planning applications for batteries in 2017, when these projects were first able to participate in the capacity market, indicating a clear interest from technology developers in accessing these types of markets for revenue. We are also seeing an increase in the average size of projects, from under 10MW of average project capacity in 2015 to over 30MW in 2019. Co-located projects, combining an electricity generation plant with a battery can increase the economics of the storage facility while providing the extra flexibility needed for some merchant renewable projects.
While the majority of current projects are a combination of gas plants with storage to take advantage of grid connections, we are seeing an increase in applications for solar projects combined with batteries in England and a growing interest for onshore wind collocated projects in Scotland and offshore wind as well. The announcement that onshore wind projects would be now able to participate in future CfD rounds will drive interest in the technology and asset owners will likely explore more co-location options. Some of the main players in this new market are EDF, Pivot Power, Statera and RES, all of whom are active in several power supply and flexibility markets, providing services to National Grid, Distribution Network Operators (DNOs), as well as operating in the wholesale energy markets.
The CCC presents battery storage as one of the key UK strengths in low carbon electricity together with wind and solar PVs technologies – with good potential to capture global market shares if investment accelerates. According to the Electricity System Operator (National Grid ESO), storage capacity could increase to up to 23GW by 2050 in a net zero scenario. In order to achieve this, we need to ensure that the 10GW+ of projects in the pipeline get built and become operational in the next decade. This means that in certain situation, batteries, if empty, could absorb that same amount of extra capacity generated from wind.
Though storage is not an electricity generation technology per se, it will play a major role in our future system as a key enabler of the transition towards a renewable-led energy system. For more on storage as a flexibility enabler – see chapter 4.
The implementation of the exemption for electricity storage from the Nationally Significant Infrastructure Project (NSIP) regime in England and Wales in the early 2020s will be a step in the right direction to allow deployment at scale, making it easier for projects in planning to take forward with their applications. However, the arrival of hybrid technologies such as co-location raises questions around the definitions we use. A more appropriate approach should be developed to move away from the current classification of intermittent and non-intermittent generation – a classification that is based on the specific function of a given asset on the network e.g. collocated renewable asset. The Energy Networks Association (ENA) is looking to enable storage projects to progress up the connection queues to connect earlier and ease some of the system constraints (an action under the Smart Systems and Flexibility). The network changes mean that storage capacity providing a flexible alternative to network reinforcement would be able to speed the connection process for other projects as well. By 2025 there should be clarity on how this approach will work in practice for the concerned projects, to mitigate the risk of potential gaming, as well as greater details on the contractual arrangements for projects which are allowed to connect earlier (e.g. access to wider markets such as balancing services). Beyond 2025, there is a need to move towards greater market co-optimisation, improving the trading and allocation of ancillary services such as frequency response and inertia closer to real-time. Storage will not only contribute to peak demand but, more generally, will help smooth periods of peak flow in the system
Interconnectors will be an important source of balancing and seasonal flexibility. The 2020s will see an increase in the interconnection capacity of the UK, from 4GW today to 12GW in 2025. As renewables generate at the lowest cost, they will be called to supply demand first. When not met by the amount of power generated by renewables, demand will have to be met by other sources of low carbon technology. Power coming from the continent through interconnectors currently responds to these market signals and supplies power to the UK at market price. As we depart the EU, it is essential that these flows maintain optimum responsiveness and flexibility. As other countries also decarbonise their grid, that supply will increasingly become more green and cheaper.
As the UK transitions to a net zero economy and increases its renewable capacity levels, the amount of clean power flowing from the UK to the rest of the continent will increase. We believe that by 2050, the total net flows through interconnectors should be close to zero, this means that on average the amount of electricity imported should equal the amount of electricity exported at time of excess renewable generation. The increased interconnector capacity will play a large part in stabilising price fluctuations.
Alongside wind as the main source of renewable generation (~over 100GW installed by 2050), there will be an increased need for varied sources of low carbon generation to provide the diversity that our system requires.
G. Other technologies
In its Future Energy Scenarios publication, National Grid ESO, suggests that a net zero compliant scenario would require a total phase out of non-abated thermal generation technologies. The only natural gas plants able to still operate at peak will have to run with Carbon Capture, Utilisation and Storage (CCUS) technology. In their own indicative net zero generation mix, the CCC assumes 175GW of variable renewable generation such as wind, solar and marine energy, followed by other renewable generation such as Bioenergy with CCS (BECCS) and hydro (~10GW). In this scenario, renewables would account for 66% of the UK generation mix. The level of penetration of RES-E in the supply would potentially be increased if we consider the possibility to delay its supply with the use of storage or even with green supply from interconnectors. Adding RenewableUK’s own optimum scenario for onshore and offshore wind, the generation from renewable energy sources (RES) could increase to 76% of the UK power mix by 2050, assuming similar levels of load factors and integration of renewables. Peaking plants are, by definition, very rarely used while gas with CCS and Nuclear would together represent a quarter of UK generation
III. Supply chain and future investment:
The technology that will be needed over the next few years, the levels of deployment that will be required to be compliant with our climate targets and the mechanisms which will allow us to procure them at least cost have been set out above.
We now turn to the investors who will provide the capital required for net zero. Who are the key players who will fund the transition? And who will build it?
With prices reducing, fossil fuel industries becoming less important in the mix and best practice in renewable asset management becoming increasingly well understood by lenders, we are expecting more capital to come from debt finance rather than equity finance. Financial institutions, such as banks lend, with the certainty of getting their money back with some interests at a specific date.
Since 2010, Europe has attracted c.£80bn of new investment in offshore wind, with the UK attracting 48% of this, making it the biggest offshore wind market in Europe and globally. CfD allocation round 3 projects are already tapping into the debt and equity markets and attracting significant levels of liquidity to successfully achieve a financial investment decision (FID) in 2020. In the high deployment scenario presented, and assuming capex costs per MW at £2.0m, a total private investment of £54bn would be required in the UK to achieve 2030 targets. Significant reduction in the technology cost curve and increased cost-competitiveness through economies of scale, coupled with advantageous borrowing macroeconomic conditions means that each gigawatt at this point is significantly less capital intensive than in the earlier days of deployment. On annual terms, the high deployment scenario represents an annual run-rate of investment of c.£5.7bn. However, investment required in the 2027-2032 ramp up period would be around £44bn or £8.7bn per annum.
This is more investment than ever seen in the market for that sector in a five-year period. This is a huge opportunity for lenders who grasp the significance of our net zero ambitions. We have seen an exponential growth in capital targeting the renewables sector driven by environmental, social and governance (ESG) impacts and the climate change agenda is very well understood by the financial sector.
Low political risk and strong, clear government backing is key to continue to drive momentum to deliver renewables targets. Strong government backing will continue to drive competitive auctions which, supported by an accommodating macro environment, can deliver an all-time low cost of capital to a capex intensive industry – which should result in additional value for money for taxpayers.
New investment in the UK supply chain to meet our UK content commitment will overwhelmingly come from private companies responding to commercial opportunity. However, it will require strategic Government investment to support re-investment by our supply chain as well as upgrades to enabling infrastructure (such as ports) and other business support to improve competitiveness regionally but also internationally. Regional, as well as central, delivery agencies can stimulate the level of inward investment activity required to maximise UK content and innovation in the supply chain
Future green demand
II. Future transport
Transport is the largest source of UK emissions and most of it comes from road transport, which is also one the biggest contributors to poor air quality in the UK’s cities. The CCC recommends that all emissions from surface transport should be zero by 2050.
The consensus solution to reduce these emissions relies on extensive electrification coupled with hydrogen for long-distance Heavy Goods Vehicles and ships.
Government’s 2018 Road to Zero report sets several milestones:
- by 2030, over 50% of new car registrations should all be Ultra Low Emission (ULE),
- all sales of petrol and diesel cars will end by 2040 (possibly sooner18https://www.bbc.co.uk/news/science-environment-51366123)
- in 2050 almost all vehicles will be zero emissions.
Subsequently, the government has brought forward the phase out date for sales of new internal combustion engines to 2035.
Deloitte’s Global Automotive Consumer Survey found in 2018 that the two main barriers for UK consumers considering buying an EV were the driving range and the price premium compared to non-electric options. The manufacture of both electric vehicles and batteries are global markets and we are confident that the trends seen in cost reduction will continue this decade, resolving both ‘range anxiety’ and the cost premium barriers.
As battery costs have fallen, car manufacturers have tended to increase battery size and range to address range anxiety, rather than reducing up-front costs. We have observed up to 19% learning rates in the cost reduction trajectory for li-ion batteries globally to date, which means that for every doubling of batteries produced globally, the costs of production decrease by 19%. If this trend continues and driving range increases, price parity with combustion engines will happen in the next five years. According to the CCC, electric vehicles are likely to be cheaper than petrol and diesel vehicles before 2030.
This means that with the right framework and incentives, the demand for EVs and the switch to low carbon fleets in industries relying on fuelled transport will follow. The car and battery manufacturing sectors are two very distinct industries, at different stages of their growth and requiring a very different set of skills and supply chain support. There will be a dramatic increase in demand for battery cells globally from the automotive sector, but also from co-location and storage projects in the power sector. Ensuring that there is sufficient and sustainable supply for production of electric cars will be important medium-term challenge.
The limiting factor in the short-term, however, may stem from the supply side rather the demand side if more lithium ion battery plants are not developed in Europe. Serious targets will create the right signals for the market and Vivid Economics modelled19https://www.wwf.org.uk/sites/default/files/2018-03/Final%20-%20WWF%20-%20accelerating%20the%20EV%20transition%20-%20part%201.pdf that accelerating the phase out of petrol cars to 2030 instead of 2040 could increase the number of electric cars and vans on the road from around 0.1 million today to 20 million in 2030 – this compares to 13 million expected under the previous 2040 phase out policy.
On the power supply side, National Grid ESO predicts that the increase in electricity demand will mirror the increase in renewables20FES 2019. This means that as demand for power to charge our clean road transport grows in the country, the supply of clean renewable generation will match it. This will ultimately improve the levels of penetration of renewable energy sources steadily and support new business models for low carbon energy projects.
By 2035, energy produced from renewable sources could be around 250-300TWh if we deploy the right levels of wind and solar as discussed above. Vivid Economics analysis for the CCC in 2018 suggests that 10 million electric vehicles could be on the roads, at low cost, by 2035. This could represent almost an extra 40TWh to annual demand for power.
The new charging infrastructure needed for electric cars and vans will significantly increase demand on the system, presenting challenges for distribution networks. System flexibility through smart charging is essential to accommodate and smooth inevitable peaks in demand and electric vehicles, effectively batteries on wheels, can provide great levels of flexibility to our energy system if used efficiently with smart charging and V2G technology. This is discussed further in chapter 5.
In their global outlook report of 2019, BNEF estimates that over 500 million EVs will be on the road, globally, by 2040. This is approximately half the total number of cars on the world’s roads today. If the UK were to accelerate the EV roll out as suggested by the CCC and Vivid Economics and follow the global trend, the impact on power demand would be significant before the end of the decade and would track the increased rates of deployment of wind capacity
Shipping and aviation:
Shipping and aviation are not explicitly mentioned in the net zero targets that the government has committed to by 2050. However, the CCC strongly advises that a plan is set out for these sectors and to include them within the targets.
The International Maritime Organisation’s decarbonisation strategy aims for a 50% reduction of current emissions by 2050. In addition to behavioural changes (speeds and weight limits) this will also mean a switch to low carbon fuels.
The International Maritime Organisation’s decarbonisation strategy aims for a 50% reduction of current emissions by 2050.
RenewableUK members support the CCC’s views that hydrogen will be key for the maritime sector in reducing GHG emissions from ships. Industry believes that renewable hydrogen21Hydrogen produced via electrolysis using power coming from renewable sources will become cost competitive with other forms of low carbon fuels within this decade and should be prioritised by the maritime sector for meeting their decarbonisation targets.
As with the electrification of transport and heat, green hydrogen used for shipping and, in the longer-term, aviation will translate into an increased demand for renewable power and therefore in increased renewable penetration between 2030 and 2050
III. Future heat: heat pumps, district heating, efficiency and hydrogen
The most important steps to take over the next 10 years will involve radical change in the way we, as consumers, make use of clean energy. The green energy generated from renewable sources needs to make its way to peoples’ homes, industrial activities and businesses.
The UK is historically very reliant on gas and counts a total of 26 million gas boilers installed across the country. These have a life expectancy of between 10 and 15 years and are costly to replace. It is, therefore, very important to ensure that households looking for a replacement now and in the future are always are directed to the low carbon options available to them. The totality of these boilers will, in effect, have to be either upgraded or replaced by low carbon heat options.
Gas user with hybrid heat pumps vs. gas boilers
In line with CCC and BEAMA’s recommendations, it is essential that all new installations of heating should be low carbon by 2030 and energy efficiency/insulation measures must be retrofitted in older buildings. By 2050, buildings should no longer be heated via natural gas networks.
While the use of renewable hydrogen is a key low carbon option for reducing emissions from energy intensive industries and heavy goods transport, its use is not as straightforward for the building sector and depends on the location of both the hydrogen production facility and the building. It should only be used and prioritised over other options in specific cases where it is truly cost-effective.
The industry is optimistic about the different options available to support a transition to net zero in the heating sector. Once again, the technology is known and ready to be rolled out at scale if the right incentives and frameworks are put in place to support a sustained level of investment. Government must do its part in the building sector to significantly improve levels of housing energy efficiency for new and existing building stock and support efficient electrification where needed. Government must work with industry to reach an economically viable deployment strategy for heat pumps and district heating, while on the supply side government should work on market creation for biogas and renewable hydrogen.
One of the low carbon technology options for heating our buildings is heat networks, also known as district heating. A heat network is a distribution system of pipes that takes heat from a central source and delivers it to a number of buildings. The heat source can be a Combined Heat and Power (CHP) plant, energy from waste, canals, rivers etc. It is estimated by the CCC that around 18% of UK heat will need to come from heat networks by 2050 if the UK is to meet its carbon targets cost effectively.
The second option is heat pumps; a technology that can be installed in buildings and houses to extract free heat from soil, air or water with very little electricity usage and great efficiency ratio. The initial cost and installation are the main barrier for this technology, but the running costs are low during the 15 years of its lifespan.
The final option, hydrogen boilers hybrid heat pumps, uses hydrogen for houses connected to the gas grid. RenewableUK believes renewable hydrogen will play an important role in the future energy system. In these technologies, hydrogen is used instead of natural gas to fuel the boiler and produce heat. Green hydrogen produced from renewable electricity sources could come directly through the existing gas network and/or from a decentralised generation source attached to the building ie. solar roof panels. The CCC estimates that an uptake of 16 million hydrogen boilers could deliver similar emissions savings as a scenario using 19 million heat pumps. The number of hydrogen boilers installed will depend on the extent of electrification we observe in the building sector. Hybrid heat pumps offer a viable option in that they allow a smooth transition to electricity-supplied heat but with the option to burn hydrogen during peak times.
While the relatively low cost of gas in the last decade has undermined investment in electrification, falling electricity prices due to the higher levels of cheap renewable generation – coupled with strong government incentives – cause us to believe the balance could shift more rapidly in this decade and the next – particularly if carbon costs were appropriately applied.
Levelling the playing field for these technologies to be commercialised at scale and for local authorities to adopt them should be Government’s central strategy. Once again, private-public partnership with clear targets on cost reduction and deployment are key to providing the reassurance that markets need when investing in new technologies. Despite current domestic heat incentives, the upfront installation costs and lack of transparency on the schemes remain an issue for individual homes. Possible public policy solutions for low carbon heating could be delivered through a mix of incentives and targeted support, taxation measures and regulation. However, ability to pay must be central to policy and vulnerable customers protected in this transition
What does it mean for electricity demand?
Electricity demand from the domestic sector will increase as these technologies are rolled out. Despite being highly efficient, the use of district heating and heat pumps to replace current natural gas heating will raise power demand regardless of whether this is in new build or retrofitted homes. Replacing 1 million domestic gas boilers with heat pumps will increase electricity demand by 5TWh annually. The CCC recommended levels of heat pumps and district heating by 2050 would increase electricity demand by roughly 100TWh a year – one third of current annual UK electricity.
As we deploy the renewable generation capacity that will meet this increased level of demand, hybrid heating technology will be a key enabler in the transition to fully electric heating. Modelled usage of hybrid heat pumps from the ESO suggests that these devices would use only 20% of the gas used by a gas boiler throughout a normal year and only at peak times during the winter months. The rest of the time the heat pump would be relying on efficient use of low-cost electricity.
By 2050, demand for gas from various sectors of our economy will be less than 50TWh per year, while the rest of our demand will be met by low carbon electricity or renewable hydrogen. Power demand will more than double compared to today’s levels. More than half of it will come from building electricity demand such as heat, appliances and computing (360TWh from the total 645TWh according to the CCC’s further ambition scenario)
IIII. Future industry
While overall emissions from industry are lower than the domestic sector, some industries are hard to decarbonise because their industrial processes are likely to be too expensive to electrify.
Hydrogen provides a credible low carbon option for fuelling emission intensive industries like steel, iron, ceramic and chemicals. We are already seeing some projects under development for fuel switching solutions in the steel industry that include hydrogen such as Tata Steel or electrification such as Liberty House group. Our view is that within this decade, emission intensive industrial processes will have moved to low carbon options.
Hydrogen is viewed as one of the most economic options to decarbonise industry. At present, however, it is overwhelmingly produced from fossil fuel sources. While green hydrogen is already competitive in niche applications22https://www.nature.com/articles/s41560-019-0326-1, it will soon reach cost parity with hydrogen produced23BNEF, Hydrogen: The Economics of Production From Renewables, Aug 2019 from fossil fuels. Analysis from WoodMac recently reported that the electricity used would need to cost under $30/MWh for green hydrogen to be fully competitive with grey hydrogen from markets like Australia or Japan. In the UK, to make a like-for-like comparison between renewable and other sources of hydrogen, we must include carbon pricing for grey hydrogen, as well as the capital and operational costs of CCUS plants to transport and store the carbon from blue hydrogen. These additional costs, and the renewables sector’s record of cost reduction, are likely to make green hydrogen competitive in the UK sooner than in many other markets.
FES 2019 suggest that demand for hydrogen in a net zero world will increase from 1TWh per year to 324TWh in 2050. Already, the UK is investing in demonstration projects that can help drive renewable hydrogen down the cost curve. ITM’s Gigastack demonstration electrolysers manufactured in the UK will produce renewable hydrogen for the Phillips 66 Humber Refinery using power from Ørsted’s Hornsea Two offshore wind farm. The Dolphyn project by ERM will produce hydrogen from a large-scale floating wind turbine.
UK government funding granted to these new projects will support the deployment of a UK renewable hydrogen expertise and supply chain to meet future demand. It is essential that the UK Hydrogen Taskforce, launched in 2020, recognises the role green hydrogen can play in an open, competitive market. As the UK rapidly decarbonises our power supply using low cost renewables, a route to market for green hydrogen will ensure we can fully capture the potential of renewables in the transition to net zero.
Shifting our energy demand for carbon intensive fuels to demand for green electricity and zero carbon fuel alternatives like green hydrogen is essential to reduce our CO2 emissions. The technology and the appetite for it are there but require the right policy framework and incentives to meet our net zero targets on time
Generation from wind and solar is, of course, varies according to weather, and the absence of fuel cost makes cheap make solar and wind very competitive in wholesale markets. This means that when the wind is blowing in one specific region of the country, all the wind farms locally will be able to supply increased volumes of electricity to the market at the same time. This increased supply of cheap clean generation at a given time will have a downward influence on market prices in general and particularly on the specific prices that the renewable generators will get for their electricity on that day.
Periods of lower prices are not uncommon in any market, but they become particularly challenging when demand on the other side of the system is not high enough to absorb all the cheap supply. Not only does this mean that generators, in this case wind farms, get less for their MWh in the market but some of them must also stop generating to reduce the pressure on the demand side. The result is therefore low or sometimes negative wholesale power prices correlated to high levels of output of one or various renewable sources. In recent years, we have seen more periods of negative pricing on the system, particularly during very windy periods.
We believe that lower energy costs are a benefit to all those who consume electricity.
This subject has been much discussed in energy literature over recent years and is one that needs to be addressed when discussing the future of the energy system in a renewables-dominated world. Ultimately, we believe that lower energy costs are a benefit to all those who consume electricity. For project developers, however, it can highly impact their ability to recover their investment overall when selling their electricity to the market. The current electricity market is designed around the marginal of cost of our generation which is likely to become closer to zero as we successfully manage the decarbonisation of our grid.
The volume of future projects being built, and the contract prices depend on developers being able to recover their investment costs. At the moment, the energy market primarily rewards the ability to provide a constant level of energy, with a small premium in situations of peak demand. To keep being able to procure the levels of clean energy projects needed to meet our targets at the lowest possible cost, it is important that project owners are able to be rewarded for other sources of value they bring to the system, particularly around flexibility, as we will discuss later. This challenge is likely to decrease as we ramp up electrification of demand and reduce the instances of excess supply in our power markets. However, making market access more flexible for renewable generators will allow them to make the best use of their asset and be able to be more responsive when negative price situations happen in the future.
The relationship between increased variable capacity installed and prices is not a linear one. The biggest drop in prices in recent years happened between 2018 and 2019* when very little onshore wind capacity was added. Price variations are hard to predict and do not depend directly on the amount of capacity built.*2020 price figures do not include the most recent drop in prices observed in April 2020 amid the UK lockdown
Predicting future market prices and quantifying the level of “discount” that renewable generators will face is a very difficult task. The dynamic between future generation and prices is not a linear one and will be mitigated by various factors such as:
- Supply flexibility by allowing renewable operators to sell their electricity to different markets
- More widespread deployment of renewables across the country, reducing local weather effects
- Flexibility, via storage, to delay the supply of the electricity produced and store it when power prices are cheap (either in the form of batteries or other methods such as renewable hydrogen)
- Electricity exports to neighbouring markets when domestic demand is insufficiently high
- Electric vehicles and flexible domestic appliances for behind the meter flexibility
- Increased average power demand from domestic and industrial consumers due to electrification
- Response from consumers on flexible tariffs allowing them to adapt their consumption to benefit from low prices
All these options are explored in the next chapters of this report
A low carbon generation mix requires a new approach to system management. Solar generates during the day and more so in summer. It is seasonally predictable and forecasting of cloudy conditions is improving with AI developments from National Grid. National Grid can predict wind with over 95% accuracy, 48 hours in advance and it can deliver in very high volumes. Nuclear provides constant, thermal generation, but is inflexible and unresponsive to system needs. In a system with an extensive mix of variable, clean and decentralised supply, system management will become more complex and more dynamic. The system operator must ensure that demand and supply are balanced at all times, that frequency remains between a specific range and that the lights do not go out.
To manage a system incorporating increasing penetration of variable renewables and to ensure that it is in balance, system flexibility will be essential. There is a range of tools that National Grid will be able to use, from energy storage, to demand response and interconnection with European markets. There will also a requirement for a degree of low carbon backup, peaking, generation, such as gas with carbon capture and storage, if we are to reach net zero. National Grid ESO already uses many of these functions to manage the system on a day to day basis and has done for many years. The costs of these are recovered through balancing services (“BSUoS”) charges.
The additional cost of these tools to manage renewable generation has been referred to as “system integration costs” of renewables – the difference in the costs between running a high carbon system as it has been run historically, as opposed to a future renewables-based system. There has been much analysis of these costs and research suggests they are estimated to be in the range of £6.00-12.00/MWh24UKERC cost of energy review.
The Committee on Climate Change has shown that renewable generation could make up more than 60% of the electricity supply before there are significant increases in system costs and that “Additional system flexibility can increase the share [of renewables] that can be accommodated, with higher shares generally associated with lower overall system costs”.
The benefits of a smart system and flexibility are also borne out by the National Infrastructure Commission, which concluded that a smart, flexible system will save consumers as much as £8 billion per year by 2030. The UK is making good progress on developing a more flexible system, but deployment of flexible technologies, systems and markets will need to increase as system wide decarbonisation accelerates. In 2017, Ofgem and BEIS published the Smart Systems and Flexibility Plan, with a progress update in October 2018. RenewableUK chairs the Wind Advisory Group with National Grid ESO to enable wind generation to provide a greater proportion of flexibility services to the system, such as frequency response, which make these markets more liquid, reducing costs for the ESO and, ultimately, the consumer. The ESO announced in May 2019 that it intends to be able to run the system for periods with no fossil fuel generation by 2025, relying solely on renewables for balancing services.
The deployment of renewables should therefore not be seen in isolation, but as a wider part of whole system reform and of the transition to a low carbon economy. Reform will include everything from building more interconnectors to enabling vehicle to grid technologies that can respond to variable renewable generation. The transition is also being supported by the increasing role that local network operators, the DNOs, will play as they become system operators, DSOs. This transition will play out over the coming decade and will have an important role to play in reducing system costs, by delivering flexibility locally, which will be discussed in the next section.
Overall,with the correct systems in place, we can anticipate that a more flexible, renewable dominated system will be cheaper for consumers. Read chapter 4 and 5 to understand how
Enabling technologies and innovation
I. Storage Technology
Co-location of storage
As part of the move towards a more flexible, low carbon decentralised system, we are experiencing a rapid increase of energy storage co-located with generating stations, as well as in homes and businesses. There are currently 23 projects where batteries are operating alongside wind, solar or marine generators, and a further 41 are consented, waiting to be commissioned in the UK.
At present, co-location of generation and storage is primarily driven by the advantages of sharing connections. However, co-location offers huge potential for integrating larger volumes of renewable sources. First, storage capability enables a project to provide a greater level of flexibility to the grid by delaying and smoothing the renewable energy supply that flows into our system when needed. The main advantage, however, is that co-located projects allow renewable generators to optimise their asset by adapting their usage profile to respond to market signals and, therefore, increase returns.
On low price days, variable generation plants with co-location facilities will be incentivised to store their electricity production rather than selling it to the market. This will allow them to protect themselves from prices plunges while also benefitting the system operator with less output from these plants. In particular, combining battery storage with renewables can provide several opportunities to time-shift the power output. For example, installing storage alongside already accredited RO or FiT schemes will allow them to maximise the market value by selling as much power as possible into the highest priced periods without altering the total installed capacity of their assets. It can allow the operator to release greater value from its asset through providing balancing and ancillary services to the system operator (either locally or at national level).
Standalone battery storage
The energy storage market has been rapidly developing over the past five years in the UK with the greatest focus being on lithium-ion batteries (see chapter 2). Cost reductions driven by the boom in electric vehicles have support development of storage systems that can efficiently respond to short duration – up to four-hour – fluctuations in demand and supply. Closer to real time markets and the move towards instantaneous response to signals make small-scale batteries increasingly more competitive than traditional providers. Storage units are becoming more and more active on the balancing markets but are currently demonstrating only some of the benefits they could bring to the network. Batteries can react within milliseconds to provide the rapid frequency response needed by the ESO to be able to run the system within its normal operating limits.
Large scale storage
Storing molecules has historically been much easier than storing electrons and is well suited to longer term and larger scale storage. The transition to a low carbon energy system creates new opportunities to bring forward a new generation of long-duration storage, with low-cost of large-scale renewables changing the economic case and technological options for new storage projects.
Pumped hydro storage
This type of storage is already well-established and is the predominant large-scale technology, globally, in the form of hydrological storage facilities, such as dams and pumped-storage power plants. Pumped storage uses two water reservoirs for storing energy, where the water is pumped from the lower to the upper reservoir at off-peak times when electricity is cheap and released when power is needed. It is a technology that meets a number of system needs, including a range of ancillary services, time-shifting renewable generation at scale and is able to soak up a huge amount of demand. Pumped storage is a proven technology which has been around for decades and makes up 95% of the world’s storage facilities. There is potential to significantly increase pumped storage capacity in GB.
Large scale energy storage could be even more important for security of supply in a net-zero world with large quantities of renewables on the system. An important aspect of large-scale energy storage is the relatively low cost of cycling, meaning the timing at which the electricity is generated is irrelevant. This would allow for electricity to be stored when it is cheap and dispatched later when it is needed over longer periods for longer-term balancing needs of the grid. As well as pumped storage, new forms of large-scale storage, such as liquid or compressed air solutions are coming to market.
With significant quantities of zero marginal cost generation such as wind on the system, there will be often periods with a surplus of generation and low prices. Large-scale energy storage can provide flexible bulk power management services for electricity, gas and heat. Action is needed on multiple levels and barriers to deployment need to be removed. While there is still a need for R&D on emerging large-scale energy storage technologies we can benefit from synergies of developments in areas with significant crossover such as power to gas, grid management and energy system integration. Developing the definition of energy storage in energy regulation is one of the first steps to assist the management of grid constraints and market access for storage
As discussed in other chapters of this report, RenewableUK members believe hydrogen technology and its usage for carbon intensive processes, transport and heat in our economy will be crucial to meeting our carbon targets. With the drastic cost reductions of renewable generation in the world, the business case for renewable hydrogen is strengthening rapidly. A variety of different projects to produce green hydrogen are emerging in the UK showing the clear bullish outlook in the renewables sector. Green hydrogen complements the trend of generating energy in a distributed context and the need to store it.
Currently 6% of the global natural gas extracted is used for the production of hydrogen from steam reformation. This is known as grey hydrogen – or blue, if the CO2 produced from the process is captured with CCUS facilities. The global production of this gas emits the equivalent CO2 to the UK and Indonesia combined annually.
As of 2019, hydrogen is mainly used as an industrial feedstock, primarily for the production of ammonia, methanol and petroleum refining but demand for new uses linked to decarbonisation is increasing.
As renewables become cheaper and the cost of producing electricity reduces, alternatives to produce hydrogen by electrolysis emerge. This CO2-free process produces renewable (green) hydrogen. It represents only 2% of the current production of hydrogen but the range of outlets for this clean fuel, such as low carbon heating options, energy storage and green heavy goods transport make it highly attractive.
If the necessary mechanisms are in place, the early applications of green hydrogen are likely to be dominant in the transport and building sectors. Local transport and ‘return-to-base’ fleets are likely to harness the benefits of hydrogen fuel first. Furthermore, the building sector is likely to adopt blending of green hydrogen with natural gas, whilst the infrastructure and appliances are upgraded to support higher concentrations of up to 100% hydrogen gas.
Finally, because it can be stored transported and transformed, renewable hydrogen can play a very crucial role in managing periods of both peak demand for clean electricity and high supply of renewable generation.
Heat demand is the most volatile type of energy demand, both across individual days and throughout the year, with greatest volatility in the winter. While these patterns can be predicted, making sure it naturally equates with wind or solar generation is not possible. It is worth recalling, however, that during the “Beast from the East” storm in March 2018, high levels of wind generation relieved significant system pressure as heating could be prioritised for the tight gas supply available. Renewable hydrogen increases optionality for a low carbon energy system as it can contribute to winter demand for both heat and power. If the ESO wants to be able to manage the system without having to call on last resort, non-low carbon sources, it could be able to rely on hydrogen as seasonal storage
II. Demand side technology
There is a crucial role for residential demand to manage an increasingly decentralised energy system. Taking action behind-the-meter is usually associated with anything which could bring down the amount of energy used or purchased in advance. Examples of this include improving the energy efficiency of the building/residence, investing in onsite renewables as well as improving energy efficiency practices – demand shifting or shedding. In a similar way, energy storage solutions can be installed onsite or co-located with already existing generation systems such as solar, wind or CHP.
The increased complexity of the system and the need to be able to flexibly match supply and demand means that digitisation is an important part of the transition. An essential part of digitisation is the ability to accurately measure customer energy demands so the system can provide energy in the most efficient and cost-effective way, and customers can accurately understand how they use energy. The roll-out of smart meters will be able to provide the means to measure energy demands through a consistent approach to capturing and sharing data, providing access for many innovative supply services. Smart meters allow households to take advantage of time varying prices by monitoring consumption in real time and the potential for automatically optimising smart appliances. Smart meters are part of a transformation in how households will buy energy in the future. Some examples of this are automated switching, peer-to-peer trading and smart pre-payment meters.
Vehicle to grid technology
As mentioned in other sections of this report, it is widely expected that electric vehicles (EVs) on the UK roads will increase in proportion with the UK’s ambition to ban the sale of new ICE cars by 2035. The annual increase in electricity demand is likely to be matched by the annual generation from the increased renewable capacity that is built. However, connecting millions of EVs and coordinating their charging and discharging using smart technology will minimise the network costs of accommodating the extra demand from EVs, while also allowing the grid to balance the integration of high levels of renewable resources.
Smart charging in smart homes provides another important way to store renewable electricity at times of excess supply – through direct storage by end consumers. With the possibility to charge overnight when only wind and nuclear are running and then providing power from a vehicle to the grid when supply is low, the consumer can smoothing the demand and supply across the system. With the right market incentives and regulatory barriers, consumers will even be able to see direct rewards in their energy bill at the end of the month. This is discussed in chapter 5.
The Road to Zero Strategy26https://www.gov.uk/government/publications/reducing-emissions-from-road-transport-road-to-zero-strategy from Government acknowledges these benefits and insists that all new domestic charging points should come installed with smart technology to allow for these types of flexible services. However, it is important to make sure that these are effectively used by consumers; transparency, education and cost reduction are still needed to deliver the many benefits V2G technology can offer. Element Energy and the Energy Systems Catapult’s report, Vehicle to Grid Britain, shows that, to be profitable to the wider system, V2G technology will require high plug-in rates. This will allow the relatively small batteries in cars to be aggregated together and help manage grid congestions and reduce the need for expensive upgrades to grid infrastructure.
RenewableUK members are actively working with the automobile sector to build a charging network fit for the future, providing smart charging points to homeowners, businesses and local authorities across the UK
Domestic solar roof panels are a type of behind-the-meter generation where the solar PV produces power on site. As the power is being generated by the customer, not produced on the side of the grid, it is referred to as ‘behind the meter’. Such systems range in size and complexity but could be quite flexible in practice. Increasingly we will be seeing new domestic solar roofs paired with battery storage, smart energy management and EV charge points, allowing householders to store self-generated power and potentially reduce their grid imports at time of peak demand. An additional benefit is that revenue can also be generated from any surplus energy that is fed back into the grid, if this is agreed in a form of a fixed or variable (time of use), contract (export tariff). The value of smart tariffs can be substantial for homes. Octopus Energy’s Outgoing Octopus time of use export tariff suggests that those with solar, storage and smart meters can earn over £400 more than homes on a fixed export tariff. Imperial’s analysis of the residential sector’s flexibility potential suggests whole system cost savings of £6.9bn are possible, through reducing investment requirements in network infrastructure and opting for cost-effective wind and solar instead of more expensive low carbon generation like nuclear and CCS.
As the volume of renewable generation increases on the system, there is a wide range of emerging technologies that will be able to support their integration at low cost
New business models and disruptors
New tariffs and incentives:
The Octopus Agile trial, which offered lower energy prices to households during periods of low wholesale prices, suggests that consumers can indeed provide a great level of demand side flexibility if incentivised through specific tariffs: consumers on that tariff shifted electricity consumption out of peak periods by 28%. Electric vehicle (EV) drivers reduced peak consumption even further, by 47%27https://octopus.energy/static/consumer/documents/agile-report.pdf. Time of use tariffs will help unlock decarbonisation of our economy, by incentivising consumers to use more energy at times when the wind is blowing. This will help the system operator balance demand, flatten it and ultimately reduce balancing costs for everybody. At the same time, consumers would benefit from lower prices if they can shift their electricity use.
The renewables industry believes that the inevitable trajectory of changing technologies, markets and behaviours is for a smarter, more flexible system. Government needs to act to make sure this transition is delivered without disruption or cost to consumers and to ensure that it can generate the most value from the change.
What is particularly interesting about these new tariffs offered to consumers is that the value, to both the system and customer bills, increases as we accelerate the switch to electric/hybrid heating and electric vehicles. This again demonstrates that demand, as well as supply, the decarbonisation of our energy supply and demand is part of the solution.
It is urgent that the transition to a smart and flexible system, with smart tariffs, is supported by a suitable policy and regulatory framework. Even with the roll out of smart meters, widespread time of use tariffs are still a long way off for households. The renewables industry believes that the inevitable trajectory of changing technologies, markets and behaviours is toward a smarter, more flexible system. Government needs to ensure that market regulation supports this transition in a way that avoids disruption or cost to consumers and which maximises benefits from these changes.
In the world we are trying to build, this transition ultimately means two things: reduced emissions and reduced energy bills for households. However, in order for the system to be able to absorb all that excess supply and for consumers to benefit from an overall wholesale power price reduction, we need to ensure that the distribution networks and suppliers, which are directly connected to the consumers, are able to be flexible and pass on the real benefits to them. The problem does not come from “too much renewable energy” but from not enough flexibility and transparency to adapt and reap the benefits of cheap, clean power
Ancillary markets and revenue stacking:
At present, the main source of revenue for renewable generators are the wholesale markets, and government contracts such as the CfD and Capacity Market. In future, market participants will need to be more flexible with their generation and supply, participating in different markets, providing services to the system operator while at the same time improving their investment case.
Moreover, by enabling generators and storage providers to fully access and maximise the value of the services they can offer the system, we can cut costs while maintaining security of supply.
The ESO should develop more regular and interdependent procurement, for a broader range of services to balance the system. Different generators, users and storage providers can offer all sorts of different services, but not all fit into the contracts on offer. For example, a wider range of contract lengths must include a focus on procuring services closer to real time to support participation from wind generators, who can provide services cheaply, but only in a forecast window of a few days. Furthermore, short-term contracts allow for assets such as storage to offer the best services to range of markets depending on what the system needs, rather than having to pick one weeks or months in advance, when no one can predict exactly what is needed. There needs to be removal of exclusivity clauses within balancing products to allow this diversity of offers and we need to move away from manual to automatic dispatch of distributed energy assets to improve system efficiency
Traditionally, Distribution (i.e. local) Network Operators (DNOs)have been responsible for the management of their own networks, with activities largely limited to investment in new network infrastructure (cables) and maintenance of these assets (outage and fault maintenance). However, as the system changes to one with more assets connected to distribution networks, including assets that are able to manage both supply and demand, the need to move towards more sophisticated system management becomes more pressing. Network companies will move from not just owning the local network, but operating flows on the system too – they will become Distribution System Operators (DSOs).
Network companies will move from not just owning the local network, but operating flows on the system too – they will become Distribution System Operators.
In the transition from DNOs to DSOs, activities such as investing in more network reinforcement are increasingly being opened up to non-traditional methods such as flexible resources – storage and demand response – to provide that service. Additionally, DSOs, in their interaction with the National Grid ESO markets would be able to address system needs locally, both through providing a service to ESO and through opening up new local market opportunities to distribution providers across demand and generation. Such new market mechanisms would require DNOs to take a more active role as system operators and develop and procure services such as reactive power and constraint management as an alternative to network reinforcement in the future. This transition is already in motion with nascent markets being developed by the DNOs across the UK.
By 2030 and beyond, we require these markets to become mainstream with consistency applied across DSOs, in order to increase market confidence. Over the next ten years we will need to see more clarity on addressing current conflicts of interest for example, where DSOs are allowed to send signals and directly manage specific assets such as EVs.
With the move from national to more local power network management, increasingly the methods which are developed will become more complex and innovative. In the immediate term, we need to adopt methods to allow for improved visibility and understanding of lower voltages, including 11kV and domestic. Better data from collection to data management practices will be needed to support efficient management of the network at local level
Aggregators and Virtual Lead Parties
As should be apparent, in the future there are going to be many more active players in the energy market – from households with EVs and demand responsive fridges to industrial demand response, and generators of all sizes. But the energy market is complex, and households and smaller businesses may not want to actively participate. Aggregators exist to pull together many small players to provide a large offering to the system, such as demand response. They can enter simple contracts with homes, via a supplier, and share in the profits
Virtual lead parties
In the past, “lead parties” in the energy system have been those with the generation or demand assets contracting with National Grid. However, not everyone can do that, and so the concept of Virtual Lead Parties (VLP) came about. The VLP can act on behalf of one, or many, market participants as the “balancing party”. A balancing party is responsible for accurately notifying contracts and identifying imbalance while the balancing service provider is a party that provides services to the ESO – VLPs incorporate elements of both these roles, however they do get exposed to imbalance in the same way as balancing responsible parties.
Virtual lower plants
Virtual Power plants (VPPs) represents a system which is able to control digitally connected individual generators across a country – from battery storage to individual wind farms. The VPP uses complex algorithms to monitor the grid and its stability, to provide an effective way of measuring real-time power generation from connected assets. Such platforms provide the opportunity to adjust power generation to meet power demands within seconds to provide services to the network.
We are at an incredibly exciting time for the power system. New technologies, data management, digitisation and communication are opening up new markets and business models that will help manage the future energy system. This will enable us to increase the volume of renewable resources on the system, while continuing to minimise costs for the consumer.
We are at an incredibly exciting time for the power system.
New technologies, data management, digitisation and communication are opening up new markets and business models that will help manage the future energy system. This will enable us to increase the volume of renewable resources on the system, while continuing to reduce costs for the consumer
- Enabling actions from Government and new governance structures to support deployment of offshore wind and floating wind recognising the system benefits from dispersing these resources
- Maintain routes to market and certainty to support investment in cheap decentralised renewables, such as onshore wind
- Build markets for innovative technologies, such as marine renewables and renewable hydrogen, to allow deployment and cost reduction
- Ensure that energy market regulation accelerates the transition to a smart, flexible, low carbon energy system
- Create a fair, cost reflective approach to network charging and connection queue regime that delivers net zero at least cost
- Renewable hydrogen to fuel emission-intensive industries
- Put in place the correct framework to enable consumers to adapt consumption and receive pass through benefits of lower cost electricity at times of low demand or high renewables output
- Implement and build on the Smart Systems and Flexibility plan to accelerate the development of flexibility markets at national and local level
- Encourage greater flexibility through increasing interconnection, vehicle-to-grid (V2G) technologies and industrial demand response to maximise variable renewable generation
Whether it is investing in new generation technologies where the UK has a competitive advantage, developing batteries to ensure a secure clean power grid, partnering with the automobile sector to build the EV charging network, installing low cost heat pumps in UK homes or producing home-grown renewable hydrogen, our members are using their expertise to build the energy system of tomorrow.
Our unparalleled success in decarbonising the power sector was kickstarted by ambitious public policies that supported innovation at scale, allowing companies to learn, build supply chains and reduce costs. As targets become more ambitious, the importance of this support for market signals and investment in all sectors of the energy system becomes greater.
The UK’s net zero energy system will be renewables-led and will provide cheap, clean power to a wider range of consumers with specific needs. Renewable electricity, both directly and indirectly through the production of renewable hydrogen and ammonia, will meet the vast majority of our energy needs. We are confident that this vision can be realised but it will require the development of stable markets with the right incentives in place to support the companies and investors who will deliver it. The investments needed in all aspects of the energy system are long-term and capital intensive.
Putting in place clear, long-term market signals will allow our technologies and companies to do what they do best: innovate and problem-solve
RenewableUK is the only trade association to encompass both the transmission and distribution aspects of the changing energy system. Across the organisation, work is being done to support the energy transition. RenewableUK’s members are building our future energy system, powered by clean electricity. We bring them together to deliver that future faster; a future which is better for industry, billpayers, and the environment. We support over 400 member companies to ensure increasing amounts of renewable electricity are deployed across the UK and to access export markets all over the world. Our members are business leaders, technology innovators, and expert thinkers from right across industry