5. Decentralised energy and storage

56 | Pathways for the GB Electricity Sector to 2030

5. Decentralised energy

and storage

Pathways for the GB Electricity Sector to 2030 | 57

SUMMARY

‘ Decentralised energy and storage will continue to grow rapidly’

All respondents thought decentralised energy would continue to grow rapidly over this period. Respondents believed technologies such as solar PV, battery storage, small-scale gas (e.g. OCGTs), and micro-CHP could play a significant role in 2030. Most agreed solar PV would continue to grow despite the sharp cuts in subsidies, although some argued cuts of this scale (c. 90% of cuts announced at the time of interviews) risked killing-off the market for solar PV just as costs were rapidly falling.

Many believed solar PV would reach ‘grid parity’ in the next few years at the residential level (where the comparator is retail prices), though some had concerns about whether there was a ‘level playing field’ for such comparisons (some questioned whether the consumers with solar PV were adequately covering the costs of grid access and back-up capacity that they continue to require). Many respondents commented there should be a ‘glide path’ of support for solar PV and other decentralised generation to facilitate these technologies as they approach grid parity and zero subsidy.

Electricity storage is widely regarded to be the single most important technological breakthrough likely to happen over the period to 2030 and a complete ‘game changer’ in the way that the power system operates. Views varied on when storage would be commercially viable at either a consumer or grid level, but many respondents argued it would be commercial at a distributed level within 3 to 5 years. One respondent said that it would ‘always remain 10 years away’.

Many agreed with the sense that the energy sector is about to go through the same sort of technology-led revolution that has been witnessed in telecommunications and banking in recent years. A number of respondents highlighted that with storage, smart meters, time of use tariffs and half-hourly metering in place, the value of electricity exported back into the grid could change significantly, as well as the need for investment in the transmission and distribution grid to support and manage more complex energy flows at all levels in the system.


Source: Department of Energy and Climate Change

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Figure 13: Will decentralised energy have a major role to play in the near future?

All respondents thought decentralised energy would continue to grow rapidly over this period. Some believed technologies such as solar PV, battery storage, small-scale gas (e.g. OCGTs), and micro-CHP could play a significant role in 2030. Most agreed solar PV would continue to grow despite the sharp cuts in subsidies, although some argued cuts of this scale (c. 90% of cuts announced at the time of interviews) risked killing-off the market for solar PV just as costs were rapidly falling.

Many believed solar PV would reach ‘grid parity’22 in the next few years at the residential level, i.e. the levelised cost of generation would reach or be lower than market retail prices, and the combination of small-scale renewables and electricity storage could create a complete paradigm shift in the way the power sector operates. Most interviewees believed the electricity storage market would be able to develop without subsidy, although some argued some kind of deployment grant for household storage may help encourage the market, and others mentioned the importance of availability of longer term Capacity Market / ancillary services contracts for large-scale storage.

Several respondents discussed the challenges of decentralised energy and the need to balance these against the opportunities. Many respondents believed the development of energy storage technology could have a huge positive impact on system management, although some believed commercial storage would ‘always remain 10 years away’. Some were

unsure whether the addition of storage would offer a means of managing more long-term volatility, e.g. the inter-seasonality of solar PV, while some saw balancing challenges shifting from hour-to-hour peaks to week-to-week periods of low solar and low wind output.

Several interviewees stressed the importance of ensuring a ‘level playing field’ existed between decentralised and conventional centralised generation, and the market would deliver the optimum level of each. Distributed generation and other decentralised solutions can have various costs and benefits for system management, and several respondents noted the importance of ensuring these network/system impacts were properly captured.

A number of respondents highlighted with storage, smart meters and time of use tariffs in place, the value of electricity exported back into the grid could change significantly, as well as the need for investment in the transmission and distribution grid. In a recent speech on UK energy policy, the Secretary of State announced work was already underway to remove barriers to half-hourly metering in order to facilitate the development of Time of Use Tariffs by suppliers.

Some respondents mentioned the importance of ‘community’ energy schemes as enablers for decentralised energy solutions, and argued more needed to be done to facilitate such approaches.

22 Grid parity is defined as the point at which the levelised cost of solar PV falls below the alternative cost of supplying that power; hence removing the need of Government support to generate cost-effectively. For residential customers, typically the retail price is used as the comparator.

23 Excluding ‘Renewable Other’ category in National Grid’s projections.

5.1 Interview responses

5. Decentralised energy (continued)

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Although there was no consensus on the definition of decentralised energy, most respondents believe fit to be a combination of generation, storage and demand side management. For the purposes of our analysis, decentralised energy (DE) refers to energy systems where electricity and heat are generated close to the load they serve coupled with demand side management. DE encompasses small-scale renewable technologies including rooftop solar, small-scale wind, biogas, geothermal, CHP/diesel and storage. Typically, it also involves technologies that unlocks demand side response potential. By combining local generation and the ability to manage demand, DE systems can dramatically reduce reliance on the central grid network.

Almost all interviewees believed there was a major role for decentralised energy in the future GB power sector. In particular, many thought decentralisation could take off in the UK as cost reductions in solar PV were coupled with technological breakthroughs in battery storage and the roll-out of smart meters increased the scope for demand-side

measures. Some interviewees noted increased decentralised energy came with system costs and system benefits, and noted these needed to be considered when defining Government strategy.

Outlined below is a selection of historical information and projections regarding distributed generation, electricity storage, decentralised heat, smart technology, alongside a discussion of system costs and benefits of a decentralised energy model. DSR and Demand-side management are discussed further in chapter 6.

5.2.1 Distributed generation

Many interviewees believed small-scale distributed generation would continue to grow rapidly over the period to 2030. The majority of respondents emphasised the importance of combining solar PV and other intermittent generation with electricity storage in this transition. Many emphasised the importance of solar PV in this transition but some also mentioned technologies such as micro CHP and small-scale wind generation.

Figure 15 below shows forecasts by National Grid in its 2015 Future Energy Scenarios for total installed distributed generation capacity. In the Gone Green scenario (the only scenario where the UK’s decarbonisation targets are met on time), National Grid estimates that, alongside c. 10GW of installed solar capacity, GB will have installed c. 7GW of distributed onshore and offshore wind and c. 6GW of CHP and other conventional distributed generation. In the Consumer Power scenario, this increases to c. 16GW of solar, c. 8GW of wind and c. 8GW of CHP and other conventional distributed generation23.

5.2 Analysis

Small Scale energy generation Energy storage system

Decentralised generation

Smart Technology ETRM system

Demand-side management

DSR Energy efficiency

Figure 14: Decentralised generation and demand-side management

Source: National Grid (2015) Future Energy Scenarios


5.2.1.1 Solar PV

Solar PV capacity has been increasing rapidly since the technology’s emergence. At a global level, installed capacity has increased from c. 4 GW to over 180 GW in the last 10 years, at a CAGR24 of c. 50%. This growth has been most pronounced in Europe, but the US and China have also seen notable growth since 2010 (see Figure 16).

Solar PV investment in the UK has been significant over this period. Capacity has shot to almost 8 GW between 2010 and 2015 according to DECC25, with almost 2.5 GW of new capacity installed in 2014 alone (see Figure 17).

Underpinning high deployment rates is the significant fall in costs across solar PV technologies. For <4 kW installations, installation costs in 2010 were approximately £5,000 per kW and are currently at a median figure of £1,834 per kW26 in the

Source: Department of Energy and Climate Change

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Source: DECC, Solar photovoltaics deployment, September 2015

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UK. Parsons Brinckerhoff’s cost assumptions for new build27 is even lower at £1,688 per kW for <4 kW installations and £1,021 per kW for installations over 250 kW.

In Germany, costs have declined rapidly too. The cost for a 100kW installation has decreased from approximately €4,110 per kW in 2009 to €1,240 per kW (see Figure 18) in 201428. The Solar Trade Association (STA) expects large-scale solar PV costs may be cheaper than wholesale energy by as early as 202529.

Many interviewees believed solar PV had the potential to reach grid parity in the short- to medium-term and this would mean capacity in GB would continue to grow. Grid parity is defined as the point at which the levelised cost of a technology falls below the alternative cost of supplying that power; hence removing the need of Government support to generate cost-effectively. For residential customers, typically the retail price is used as the comparator.

Market evidence suggests grid parity may have already been achieved in some countries for solar PV, and that grid parity may be achieved in GB within the next few years. Deutsche Bank estimates that solar PV has already reached grid parity in 30 countries and 14 US states for domestic consumers30, which they attribute to a combination of falling technology costs as well as ‘improving financing and customer acquisition costs’. Projections by the Renewable Energy Association (REA) and KPMG31 suggest

that grid parity may be reached in the UK within the next few years. Figures 19 and 20 show levelised cost of electricity (LCOE)32 projections for domestic rooftop and ground-mounted solar PV against retail and wholesale prices, and demonstrates how falling technology and financing costs could bring solar PV towards grid parity within as little as one to two years, depending on technology type and benchmark.

Other industry estimates show similar projections, for example the STA estimates that the levelised cost of ‘large-scale’ solar PV generation will fall below that for gas CCGT five years ahead of DECC projections (see Figure 21).

Analysis by Bloomberg New Energy Finance suggests the UK has significant potential for further cost reductions in LCOE of solar PV compared to other countries (see Figure 22).

With the eventuality of a subsidy-free solar PV and onshore wind industry, some interviewees have highlighted the dangers of abrupt subsidy cuts. The figure below shows the ‘cliff-edge’ caused by drastic subsidy cuts in the industry leading to a steep fall in deployment. Some respondents argue producing a similar cliff-edge in the UK renewable industry could risk a collapse in the supply chain which might increase the cost of restarting the industry in a subsidy-free world. Alternatively, a smooth transition for subsidy reductions towards grid-parity could sustain the supply chain.

Source: Photovoltaic Guide, Photovoltaic Price Index for a 100kW PV installation, http://www.photovoltaik-guide.de/pv-preisindex

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Source: Renewable Energy Association, KPMG analysis, ‘UK solar beyond subsidy: the transition’, July 2015

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Source: STA and DECC, Projected LCOE for large-scale solar PV and CCGT in 2014 £, http://www.solar-trade.org.uk/wp-content/uploads/2015/03/LCOE-report.pdf

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Figure 21: STA solar PV LCOE projections



5.2.1.2 Electricity storage

Interviewees generally agreed electricity storage could be a potentially game-changing technology. Respondents particularly emphasised the importance of small-scale household storage, but many also mentioned the benefits of increased grid-level storage capacity.

Many believed coupling solar PV and other small-scale generation (such as wind and micro CHP) with storage could have a catalysing effect on the decentralisation of the energy system. Some respondents argued Government should make time-limited

deployment grants available in order to help household-level battery systems reach commercial viability. However others believed up-take of household-level storage should be ‘left to the market’, there was wide-spread agreement that such technologies had an important role to play both to empowering consumers and to enhance energy security in a low-carbon and affordable way.

The majority of respondents emphasised the importance of small-scale batteries to open up the market for household-level distributed systems in the UK. In its recent position paper on system flexibility, Ofgem wrote that “[w]hile storage has been providing flexibility in other countries, and pumped storage has historically

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Figure 22: Levelised cost of solar electricity by region (USD/MWh)


33 https://www.ofgem.gov.uk/sites/default/files/docs/2015/09/flexibility_position_paper_final_0.pdf34 Tesla Energy, Press release on Tesla Powerwall, http://www.teslamotors.com/en_EU/presskit35 Forbes, Why Tesla Batteries are cheap enough to prevent new power plants,

http://www.forbes.com/sites/jeffmcmahon/2015/05/05/why-tesla-batteries-are-cheap-enough-to-prevent-new-power-plants/

played a strong role in GB, the potential of battery and other forms of storage to smooth intermittent generation or contribute to local balancing has not yet been fully realised in the UK”.33

A number of recent announcements have generated heightened public interest in battery storage technologies, particularly at the household level. In 2015, technology company Tesla announced it would be releasing its domestic energy storage unit the ‘Powerwall’ in GB in 201634. Priced at US$3,000 for a 7kWh model with an efficiency rating over 92%, Tesla’s Powerwall product is expected to bring about a shift in the household storage market. Tesla is also due to release its utility-scale product the ‘Powerpack’ at approximately US$250 per kWh35.

Recent reductions in technology costs, combined with improvements in scalability, have increased the potential for commercial deployment of battery storage. Figure 24 below shows estimates by Deutsche Bank for reductions in battery prices from 2008 to date and estimated reductions to 2024.

Several market participants also forecast battery prices to continue to fall. Table 3 shows company forecasts for their battery storage products. The US Department of Energy (DoE) also expects the trend of falling costs to continue, with an estimated 58% reduction by 2022 on 2015 prices. Tesla anticipates costs to half by as early as 2017 compared to 2015.

Some interviewees also mentioned other energy storage technologies, such as pumped storage, thermal storage, compressed air energy storage (CAES) and flywheels, an overview of which is provided below.

• Pumped-storage hydroelectricity involves using excess electricity to pump water from a low altitude to a higher ones and generating energy by discharging the pumped water. Pumped-storage hydro is the most prevalent commercial storage technology at present, forming over 99% storage capacity globally. There are currently four units in GB with a combined capacity of nearly 3 GW with the Scottish Government looking to expand on this storage capability. Similar to large-scale generation projects, pumped storage faces challenges as a result of the large scale of investment required.

• Thermal storage can be used to store heat for use at a later time, both short term and inter-seasonally. Heat energy can be stored in underground tanks or caverns for distribution via district heat networks (discussed further below). Technology developer, Isentropic, is currently developing a system that will use heat to compress argon for electricity generation.

• Compressed air energy storage (CAES) is a relatively new technology but some industry analysts predict it could play a significant role in the storage market. Highview Power is expected to commission a 5MW / 15MWh liquid air energy storage plant shortly, with funding support from DECC.

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Table 3: Falling battery prices in the global market


Note: Only includes battery costs. Does not include inverter and installation costsSource: Deutsche Bank, https://www.db.com/cr/en/docs/solar_report_full_length.pdf


36 Lightsource, Good Energy and Foresight Group (2015), The Decentralised Energy Transition, October 2015

Storelectric Ltd is also planning to build a 40MW / 800MWh facility in GB to be commissioned in 2020.

• Flywheels are mechanical devices that are able to store energy by accelerating rotors to high speeds and maintaining rotational energy in the system. Beacon Power currently owns a 20MW / 5MWh grid-level flywheel storage plant in New York, and flywheel systems are being developed to complement wind turbines during high wind speeds.

• Power-to-gas storage uses surplus energy to produce gas fuel. In Germany, RWE has developed a €2m 150kW pilot plant using surplus wind generation to convert water into hydrogen. Other technologies include producing ammonia from air and methane production. Some respondents noted the potential of power-to-gas technology in the UK, however this technology is still new.

One of the key benefits of electricity storage technologies is the ability to complement intermittent renewable energy generation technologies. Deutsche Bank estimates combining battery storage with solar PV and other small-scale / intermittent generation technology could create a household system that was at or below grid-parity within the next few years. Developer Lightsource predicts ‘whole house’ solutions, including both solar PV and storage technology, could facilitate self-sufficiency rates of 60-90%36.

Electricity storage can also be used for very fast discharge of power in order to provide ancillary services, i.e. services to help balance the transmission/distribution grids. Most respondents believed the use of electricity storage for providing ancillary services was close to being commercially viable in the market,

and that projects would soon start coming online for this purpose. Technologies such as battery storage are well-placed to fulfil purposes such as this. This is discussed in more detail in chapter 6 on demand-side response.

Several respondents, however, mentioned the market framework and regulatory mechanisms currently in place did not properly incentivise the development of electricity storage for this purpose, predominantly at grid-level but also at small-scale. Some respondents believed the classification of storage was hindering development of the market, in that it can be considered both generator and consumer, which has an effect on its treatment for network access and charging rules. Small-scale storage developers can also lose out in that they are charged retail prices for imported energy but receive wholesale prices for exported energy.

5.2.2 Decentralised heat

While interviewees mostly emphasised the growth potential of decentralised electricity, some also believed decentralised heating systems could play an increasingly important role in meeting GB’s energy requirements, mentioning technologies such as Combined Heat and Power (CHP) at both a district-level and micro-level. Respondents were clear that low-carbon heating would be a key consideration going forwards and would need clear policy signals to further delivery. However, presently, there were limited signals for home owners to change their heating system away from gas boilers to a more decarbonised system, which could include heat pumps, biomass and CHP.

Table 3: Falling battery prices in the global market

USD/kWh Technology Current Forecast

Aquion Energy Sodium-ion $500 $250

Eos Energy Storage Zinc Air - $160

Primus Power Flow – Zinc Halogen £500m -

EnerVault Flow – Iron Chromium - $250

Imergy Power Flow – Vanadium £3m $300

Redflow (Australia) Flow – Zinc Bromide £420m $525

Enstorage (Israel) Flow £280m $307 Note: Selected companies shown. Deutsche Bank sources were also obtained from GTM and Energystorage.orgSource: Deutsche Bank, Crossing the Chasm, February 2015


37 http://www.iea-ebc.org/fileadmin/user_upload/docs/Annex/EBC_Annex_54_Micro-Generation_Support_Mechanisms.pdf38 http://www.carbontrust.com/media/19529/ctv044_introducing_combined_heat_and_power.pdf41 Smart meter rollout for the domestic sector (GB), DECC, 201139 Smart meter rollout for the domestic sector (GB), DECC, 2011

CHP provides simultaneous generation of both electricity and heat. A micro CHP is essentially gas boilers that generate electricity with the excess heat at a residential level and have several benefits for both household and small business users, for example low installation and maintenance costs. They are low in carbon emissions and offer a 92% net efficiency (electric + thermal)37. The Carbon Trust has assessed a number of trial micro CHP projects, such as CHP boilers, in the UK and identified average reductions in energy costs of 20% where CHP is deployed38.

District heating is a means for distributing heat generated at a community level to households and non-households, via a network of insulated pipes, and is prevalent in a number of European countries such as Denmark, Germany and France. Heat sources for district heating can be diverse and from more than one point of supply, including both renewables and fossil fuels. This flexibility suggests a combination of large-scale CHP and district heating could form a decentralised model for heating that would allow the balancing of supply and demand while leveraging efficiencies in generation.

Recent analysis by Element Energy, Frontier and Imperial College for the Committee on Climate Change shows there are significant challenges to the deployment of district heating in the UK. The consortium lists a number of challenges to the roll-out of district heating, including market/regulatory barriers, lack of consumer interest and trust, demand uncertainty, technology costs and institutional factors. In their Central Scenario, the consortium assumes these barriers are overcome by introduction of financial incentives and amendments to existing policies favouring conventional heating options. In this scenario, district heat roll-out levels are still modest at 3% in 2020 and 9% in 2030 (see Figure 25).

5.2.3 Smart technology

Many respondents believed smart technology would play an increasingly important role over the next decade. Some respondents argued the roll-out of smart meters could facilitate a transition to a world where consumers could more actively manage their energy consumption, and smart appliances and time-of-use tariffs would enable users to shift consumption habits to benefit more from storage and DSR schemes as discussed in chapter 6. Other interviewees were more sceptical about whether consumers would participate in demand-shifting and whether data and whether smart

technology would properly incentivise a change in behaviour unless highly automated. Most agreed such developments created significant opportunities for innovation and the future of demand-side management was highly uncertain.

Increased smart meter up-take could lead to significant cost savings for consumers, both as a result of operational cost savings for energy companies and the development of dynamic pricing structures that incentivise value-creating changes in behaviour. In a 2011 study39 DECC estimated a total net benefit from installation of smart meters of approximately £4 billion (c. £15.8bn total benefits and c. £10.8bn total costs). Of the total benefits, £8.6bn is expected to arise from reduced supplier costs through avoided site visits and reduced customer enquiries, switching and debt handling. The cost and benefits of demand-side response is described in the following section.

Some interviewees noted the potential difficulties of getting high levels of consumer engagement with smart meters, at least in the early years. The success of initiatives such as demand side response, smart technology and domestic generation is dependent at least in part on the level of consumer engagement with load-shifting initiatives.

There are positive signs that consumers will engage fully with smart meters. In a recent survey carried out by Populus on behalf of Smart Energy GB40, 84 per cent of people with a smart meter said they were likely to recommend one to others. Consistent messaging is now required to explain the benefits that a smarter energy system can bring.

5.2.4 System costs and benefits

With the emergence of new generation technologies and the development of decentralised models, many respondents believed it was important to consider the ‘whole system cost and benefits’ attributable to different technologies in assessing overall levelised costs. The key point interviewees stressed was the importance of a ‘level playing field’ between competing supply-side solutions.

New generation capacity can increase the cost of managing and operating the electricity network, such as new grid connections and additional network reinforcements. Intermittent generation such as from renewable energy sources can also lead to additional system balancing costs as a result of the time and variability of power output. There can also be system benefits associated with renewable energy sources,



40 Smart Energy GB, Smart energy outlook, September 2015, http://www.smartenergygb.org/sites/default/files/Smart%20Energy%20Outlook%20September%202015_0.pdf

41 Imperial College London and NERA Economic Consulting, October 2015, Value of Flexibility in a Decarbonised Grid and System Externalities of Low-Carbon Generation Technologies42 Imperial College London and NERA Economic Consulting, October 2015, System Integration Costs for Alternative Low Carbon Generation Technologies – Policy Implications

e.g. reducing wholesale power prices and the ability for decentralisation helping to reduce peak transmission demand or reduce the number of new transmission connections required. Many respondents also acknowledged the potential role electricity storage could play in managing timing and balancing issues. Overall most interviewees agreed it was important for Government and industry to undertake further analysis to understand the whole system costs and benefits of decentralised energy systems in order to compare technologies on a like-for-like basis.

Respondents noted that Transmission Network Use of System (TNUoS) charges may not currently be reflective of all system costs and benefits of different generation technologies. The methodology for calculating TNUoS charges was only recently changed to account for the physical distance between the generator and end consumers and accounting for the degree of intermittency of generation.

There is uncertainty regarding how the balancing services use of system charge (BSUoS) charges are likely to develop going forward. BSUoS charges have increased in recent years due to a number of factors, for example increased intermittent generation, relatively lower load factors and implementation of Significant Code Review changes. Going forward, National

Grid estimates BSUoS charges to fall from a projected £1.78/MWh for 2015/16 to £1.63/MWh for 2016/17 (see Figure 26). Many interview respondents, however, believed the factors mentioned above would lead to increased BSUoS costs/volatility going forward, and that this would place increased burden on domestic generators and bill payers.

In recent reports41,42 by Imperial College London and NERA Economic Consulting (commissioned by the CCC), the key observations include it is feasible to manage a system in 2030 that is “deeply decarbonised with high levels of intermittent renewables (i.e. up to around 50GW of wind and solar)”. This translates to fairly low system integration costs of approximately £6-9/MWh for renewable generation technologies in a decarbonised scenario of 100g CO2/kWh relative to nuclear generation. This assessment considers the increased balancing costs, costs of necessary network reinforcements, backup capacity cost and the cost of maintaining system carbon emissions and conversely, the benefits of flexibility.

Source: Element Energy, Frontier Economics and Imperial College London (2015), Research on district heating and local approaches to heat decarbonisation

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Figure 25: District heating deployment in Element Power Central Scenario (TWh)


The research suggests the cost of integrating wind and solar would be larger at higher levels of decarbonisation, as shown in Table 4.

In addition to the studies mentioned above, Energy UK and its members are aware DECC has commissioned Frontier Economics to undertake a detailed analysis of the wider system costs and benefits of different energy sector technologies. Energy UK is supportive of this initiative by DECC and would welcome opportunity to discuss the results of the study.

While respondents acknowledged the work undertaken to date to recognise and account for the various system costs and benefits of different generation technologies, several interviewees believed more work needed to be done on how best to internalise these costs and ensure a level playing field existed for competing technologies. There are various ways to achieve this and Government should engage with industry and consult on its approach to assessing system costs and benefits as it is a highly complex exercise.

As well as the system costs of decentralised energy solutions, many respondents commented on the potential system benefits (among other positive externalities). For example, intermittent generation can be combined with storage and DSR capabilities to realise several potential system benefits:• Reduce transmission and distribution network losses: DECC

estimated in 2014, transmission losses amounted to 7.9% of total electricity demand with 23% of this occurring in transmission networks and 74% in distribution43 networks. By comparison, in Germany (where local generation is more prevalent as a result of municipal ownership) only 4% of electricity demand was lost44.

• Reduce network reinforcement costs: It is anticipated that the introduction of decentralised energy will fundamentally change the way distribution networks operate in the future. But, potentially, there may be reduced spend on network reinforcements (i.e. increasing the capacity of the network) as increased local generation will result in lower load at times of peak demand, allowing such reinforcements to be deferred. The development of the decentralised model (DSR equipped with storage) will be better prepared to deal with the intermittent generation on the grid. Ofgem estimates smart grids will save the UK between £2.5bn and £12bn by 2050 through reducing network reinforcement requirements45.

• Reduce investment required in peaking plant to meet high demand: In order to meet the UK’s loss of load expectation (LoLE) at times of peak demand, additional capacity is required. Certain kinds of capacity are eligible to participate in Capacity Market46. Total (gross) capacity payments from the first auction held in early 2015 are expected to be £956m47. A combination of storage and demand side response, coupled with enhanced efficiencies such as smart


Source: National Grid (2015)

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Figure 26: National Grid BSUoS estimates (October 2015)


43 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/447632/DUKES_2015_Chapter_5.pdf44 http://data.worldbank.org/indicator/EG.ELC.LOSS.ZS45 Analysis of Least Regrets Investments for RIIO-ED1 and supporting evidence, EA Technology (2013)46 https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/389832/Provisional_Results_Report-Ammendment.pdf47 https://www.frontier-economics.com/documents/2015/01/lcp-frontier-economics-review-first-gb-capacity-auction.pdf 48 http://www2.nationalgrid.com/UK/Industry-information/Electricity-transmission-operational-data/Report-explorer/Services-Reports/ 49 Unlike DNOs, Distribution System Operators or DSOs have a more active role in managing and facilitating electricity markets and flexible demand in local areas.

Traditional DNOs tend to focus more on asset-heavy outputs in operating the distribution networks.

appliances, will reduce peaks in demand and hence the requirement for such large-scale flexible plant.

• Reduce Balancing Market Costs: National Grid is forecasting system balancing costs for 2015/16 to be £882m48. Of the £882m, £178m is for response, including the spinning reserve, and £126m for the fast reserve. The expansion of storage and demand side response would be expected to significantly reduce the costs of balancing the electricity system, as the system operator could match demand to supply or use stored capacity promptly to maintain voltage levels, regulate frequency and act as spinning reserve capacity. Trials are underway at various locations aimed at refining these cost savings. For example, the 6MW trial storage facility at Leighton Buzzard. The project cost is £11.4m, however this is expected to decrease to £8.5m for future installations. The net cost is considerably lower at £3.3m, following the deduction of the net present value of future income streams from the provision of services to the grid (£2.6m) and system cost savings (£2.5m) arising from system balancing services such as the displacement of peaking plant. The net future cost is £2.2m lower than the costs of conventional reinforcement in this location.

Several respondents have mentioned the importance of a DNO to be incentivised appropriately to both accommodate and / or encourage decentralised energy. Some interviewees also suggested a more proactive oversight is required for decentralised energy and is best facilitated by shifting the role of a DNO towards a service-focused DSO model49. This is explored further in chapter 11 on Governance.

Table 4: Summary of relative integration cost of wind, PV and CCS relative to nuclear (in £/MWh)

Scenario Wind Solar PV CCS

100 g/kWh 6.2-7.6 6.1-9.2 (6.4)-(0.5)

50 g/kWh (wind-dominated) 12.5-15.6 12.1-17.1 (7.9)-(4.6)

50 g/kWh (solar-dominated) 9.5-14.3 26.2-27.6 (7.5)-(2.8) Note: Ranges reflect various methods adopted; brackets indicate negative valuesSource: Imperial College London, NERA, CCC, October 2015


6. Demand-side response


SUMMARY

‘ Demand-side response (DSR) has a key role to play’

All respondents believed demand side response and demand side management (DSM) had key roles to play over this period. Many respondents, however, expressed concerns whether current policy signals were adequate to bring this about. Views differed on how best to incentivise DSR and DSM over the period to 2030, and Energy UK encourages Government to engage with industry when considering the policy and regulatory measures to take.

Most see the roll-out of smart meters to every home and every small business by 2020 as an opportunity to build a more interactive demand management system with domestic and business customers. Some argued for relaxing the timetable for delivery to ensure adequate time for an effective smart-metering roll-out, and raised concerns regarding costs passed on to customers.

The ability to vary tariffs to reflect time of use, as recommended by the CMA, is seen as a critical step forward in unlocking the potential of DSR. Some also argued for moving swiftly to half-hourly metering and settlements for residential customers to facilitate this transition. Some questioned whether DSR is adequately reflected in the design of balancing measures run by National Grid. Others believed the Capacity Market should be amended to encourage greater DSR. A number of respondents argued that back-up diesel generation should not be counted as DSR going forwards, or eligible for capacity payments as it was already in receipt of other payments, e.g. for Triad avoidance.

Many respondents flagged the difficulties over the medium-term of balancing the electricity system in the summer troughs as well as the winter peaks. A number highlighted the greater likelihood of periods of negative prices and having to potentially constrain or turn down nuclear50 and wind if the predictions in National Grid’s Future Energy Scenarios (with lows of 16 GW on a summer’s day) come true. Again, greater interconnection, increased DSR/DSM and the potential of breakthroughs in storage were seen as potential solutions to these system balancing challenges. Also key to mitigating these ‘curtailment’ risks is the maintenance of a sensibly diverse generation mix.

50 Existing nuclear is not quite as flexible and would need up to 72 hours to turn down or ramped up.


Almost all respondents believed demand-side response (DSR) and demand-side management (DSM) would be key developments in the electricity sector51. Most interviewees agreed DSR is of growing importance with a key role to play over the next decade and supported the development of technology for this sector.

Some respondents were sceptical about the potential scale of DSR in the nearer term (the next five years). In the I&C sector, confidence in the potential value of DSR appeared to be growing, however several respondents believed breakthroughs in household-level DSR and any major advancement was likely around10 years away. They argued while it may prove to be a game-changing solution, there was uncertainty surrounding the policy encouraging DSR such as smart meters, time-of-use tariffs, smart grids etc. Government has since confirmed its support for the roll-out of smart meters to facilitate introduction of time-of-use-tariffs and other smart technology.

Comments made included the following:

“ DSR will play a key role in the energy industry.”

“ A combination of Demand Management and Decentralised Energy is likely to have a significant impact on the generation mix to 2030 and it is important for the system to be able to successfully integrate and manage this.”

“ DSR will be slow in the short-term, but will be significant over the long term. Technology may change at a rapid pace similar to storage.”

“ DSR, DSM and smart technology will play a key role in decarbonisation. However, there needs to be a right market structure with better incentives to encourage more innovation.”

51 Demand-Side Response in this report covers a broad range of mechanisms and capabilities to manage consumer demand for energy. It is used interchangeable with Demand-Side Management.

52 Demand net of on-site generation53 Thermal Green Demand Side Response: UK Market Overview and the Potential for DSR54 Sustainability First, Paper 13: ‘realising the Resource: GB Electricity Demand Project Overview, October 2014

6.1 Interview responses

Almost all respondents believed demand-side response and demand-side management would be key developments in the electricity sector.

6. Demand-side response (continued)


Demand-side response is one of the key demand management measures available to the help balance the network. DSR addresses balancing constraints by adjusting energy consumption with the aim to mitigate over or under-supply. It does so by:• Reducing / increasing consumption;• Shifting consumption; and• Optimising back-up generation or storage onsite.

By changing the profile of demand and increasing the flexibility of the demand side, DSR can assist the electricity market to adapt to the availability of (increasingly intermittent) supply and demand requirements. DSR encourages customers to undertake short-term shifting of demand, i.e. to increase as well as to decrease consumption (referred to as valley filling and peak shifting respectively), to increase export or to take excess energy from the electricity network.

Other demand-side management tools include energy efficiency and distributed energy as described in the chapters above. Energy efficiency permanently reduces the demand and includes measures such as building insulation, more efficient lighting solutions, building energy management systems (BEMS), higher efficiency boilers etc. Distributed energy refers to power generation on the system such as stand-alone distributed generation units, storage system (e.g. heat pumps, batteries), solar thermal systems etc. Energy efficiency and distributed or ‘decentralised’ energy are covered in separate chapters.

6.2.1 Benefits of DSR

Interview respondents flagged a number of benefits of DSR, and argued DSR could generate value for the GB system in the following ways:• Introduction of greater efficiency with regard to system

capacity (i.e. capacity required at times of system stress or peak demand) and guarantee adequate security of supply at potentially lower costs than thermal generation.

• Reduction in wholesale electricity prices by driving down the average generation costs. By reducing demand at peak periods, DSR can lead to lower peak prices which can be passed on to customers via lower energy bills.

• Improve the investment in transmission and distribution networks: A reduction in net-demand at peak

times52 on the transmission and distribution grid can reduce grid reinforcement costs for the network operators.

• Potentially reduce greenhouse gas emissions by reducing the demand for high emission peaking plants to balance the system. This is particularly important in the future in the context of the UK’s move to a low-carbon economy where there system will be constrained by intermittent generation. More efficient utilisation of plant helps reduce GHG emissions and resource consumption.

Interviewees acknowledged the benefits of DSR are difficult to quantify, although some pointed towards specific papers for indicative estimates. For example:• A report commissioned by Energy UK synthesising public

data suggested that 20% of peak demand (12GW) could be successfully shifted on demand53.

• A paper prepared by Sustainability First stated that the technical potential of demand management (capping) at system peaks is between 33% in winter and 29% in summer54.

• Based on a study prepared by DECC in 2014 assessing the total cost reduction impact of a Smart Grid DSR could have an overall reduction potential ranging between 20%-30%55.

• Other estimates vary, but many suggest a potential energy saving of over 10% of peak demand.

• In 2013 in the USA just the additional revenue earned by customers from DSR exceeded $2.2bn which comes in addition to the avoided infrastructure investment costs as a result of DSR56.

6.2.2 Barriers to DSR roll-out in GB

Several interview respondents expressed concerns that insufficient action was being taken to develop the market for DSR and demand-side management in GB, and mentioned a number of barriers to the roll-out of DSR products and technology.

Table 5 below sets out a variety of ways in which DSR currently operates in the GB market. Some of the mechanisms described below are still operating on a trial basis and are yet to be fully developed.

Interview respondents flagged a number of barriers to the deployment of DSR. The key areas mentioned included

55 Smart Grid Vision and Routemap: Smart Grid Forum: February 201456 SEDC, Mapping demand response in Europe today, April 2014

6.2 Analysis


concerns around market structure, the perception of DSR, economics and market and regulatory arrangements. • Market structure: Until recently, the supply market has

been relatively stable with the existence of predictable and manageable levels of generation; predictable fluctuations in demand through investment in flexible thermal generation; and grid re-enforcements. The distribution network is currently built with sufficient network capacity to accommodate peak flows. Consequently, there has been no need for network operators to actively manage their networks. Given the increasing penetration of renewables with distribution networks and continuing decline in industrial and larger scale demand, the system requires further investment in flexibility which DSR can provide. DSR could be one potential solution but needs the evolution of a flexibility market and commercial arrangements to encourage the engagement of suppliers, aggregators and consumers. National Grid’s Power Responsive campaign; the System Operability Framework process and DNO trials are a good start. The main type of engagement at present lies in Triad Avoidance57 and low levels of participation from in-house

demand management to reduce energy costs, mainly from energy intensive users. Work still needs to be done to engage SME and domestic sectors on the benefits of DSR.

• Perception of complication: Traditionally only energy intensive users have had half hourly metering installed. SMEs and domestic consumers have been metered on sector averaging profiles and have little knowledge or experience. With the advent of smart meters, and the support of their supplier / aggregator, consumers will become more aware of their ability and potential value of proactively managing their demand.

• Economic barriers: Consumers require a financial incentive to change their patterns of electricity consumption. This requires investment of both money and effort by customers. It also exposes them to risk: if they are unable to deliver the service for which they are contracted, they will be liable for penalties. For participation to be attractive, the benefits must outweigh the costs and risks. Aggregation of DSR can help here, as aggregators can build portfolios of customers who together can reliably meet system needs, while managing risks on those customers’ behalf.

Table 5: Schemes allowing DSR participation

Type Description

STOR/STOR Runway NG Balancing Service to increase generation or reduce demand with-in 20 to 240 minutes (depending on the type of contract).

Fast Reserve NG Balancing Service to procure active power where delivery must start within 2 minutes of the dispatch instruction.

Fast Frequency Response

NG Balancing Service to procure generation increase or demand reduction response with-in 30 seconds. Fast Frequency Response can be employed to mitigate falling system frequency (e.g. due to loss of supply), as opposed to dynamic frequency response which is used to minimise variations in steady state frequency.

Capacity Market Market wide mechanism for demand reduction within four hours of instruction.

Triad Avoidance Reduction in demand during TRIAD periods, the three highest system peak demands in any year. Demand reduction at those times is strongly incentivized.

DUoS Charge Avoidance Reduction in demand at peak time to avoid peak distribution charges for larger ‘maximum demand’ metered consumers.

DSR by DNOs This avoids network reinforcement (currently at trial stage).

Demand Turn Up NG Balancing Services to increase demand during periods of high generation and low demand (at development stage) – e.g. during periods of summer minimum demand when solar PV output is high.

Imbalance Charge Optimisation Reduction in the exposure to imbalance charges.

Wholesale Price Optimisation Reduction in the wholesale costs faced by the customers.

Source: Lightsource, Good Energy and Foresight Group (2015), The Decentralised Energy Transition, October 2015

6. Demand-side response (continued)

57 The triad system is the way National Grid charges businesses for the cost of the transmission network. By reducing load and increasing generation when national demand is at its highest, customers can save or earn money.


• Regulatory arrangements: The energy policy of the UK Government has been mainly focusing on permanent demand reduction with measures such as Green Deal and Energy Saving Opportunity Scheme (ESOS). DSR aggregators have seen an increased role in the ancillary services, as that is the only market open to it in the absence of the opportunity to participate in wholesale or balancing markets. Most demand-side response does not currently have access to wholesale and balancing market. The inability of demand-side participants to access the wholesale and balancing markets and their limited ability to access ancillary services markets (due to poor product design and procurement arrangements) has knock-on effects on the capacity market. DSR participants are not competing on the same basis as generation resources, which can access wholesale and balancing market revenues.

6.2.3 Unlocking the benefits of DSR in GB

The most consistent message from respondents regarding how to unlock the potential benefits of DSR was the importance in ensuring demand-side measures operated on a level playing field with other technologies. Some commented that comparisons of the cost effectiveness of different demand- and supply-side options should be done on a like-for-like basis.

Ultimately, however, a range of views was expressed regarding how to unlock the potential benefits of increased DSR/DSM in GB. The ability to vary tariffs to reflect time of use (ToUTs), as recommended by the CMA, was seen as a useful step forward. Some also argued for acceleration towards half-hourly metering and settlements for residential customers. Some questioned whether DSR is adequately reflected in the design of the new balancing measures run by National Grid, and others believed the capacity market should be amended to encourage greater DSR. A number of respondents believed back-up diesel generation should not be counted as DSR going forwards or eligible for capacity payments.

Given the wide range of options for incentivising/remunerating DSR, and the importance of ensuring a level playing field, Energy UK strongly encourages Government to engage with industry and consult on the potential measures it can take. Energy UK believes further work in this area is needed to arrive at the optimal policy/regulatory solutions.

5. Decentralised energy and storage

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