NATIONAL GRID ELECTRICITY SYSTEM OPERATOR – WRITTEN EVIDENCE ESI0032 – UK ENERGY SUPPLY AND INVESTMENT

 

Introduction

National Grid Electricity System Operator (ESO) is responsible for the real time balancing of electricity on the GB electricity network.  We use our unique position, at the heart of the GB electricity network, to consider how energy use may change in the future, and the capability of the GB electricity network to meet these changes. 

Future System Operator

In 2021, BEIS and Ofgem launched the Future System Operator consultation[1] (FSO), to which both bodies reached a conclusion in April 2022. Their decision is for the ESO to be at the heart of the FSO, which will be an expert, impartial, public body with responsibilities across both the electricity and gas systems. The FSO will drive progress towards net zero while maintaining energy security and minimising costs for consumers. The FSO will take on all the main existing roles and responsibilities of the ESO and take on the longer-term planning, forecasting and market strategy functions in respect of gas.

Context

The ESO’s submission to the Call for Evidence covers our responses to: 1) Questions from the inquiry call for evidence that are relevant to the ESO; 2) Oral evidence given by inquiry Witnesses to-date; and 3) Queries raised directly with the ESO by the Committee Clerk, where relevant. Each year we publish the Future Energy Scenarios[2] which represent a range of different, credible ways to decarbonise our energy system to deliver net-zero by 2050. Analysis in our submission is based upon our 2021 Future Energy Scenarios which can be found on our website[3].

Key points of our response

Response to Consultation Questions

What are the main challenges as regards energy supply and storage which public policy must address over the next decade?

Energy imbalance

  1. The electricity sector must decarbonise rapidly to meet net zero, including to facilitate the electrification of heat and transport. Resource adequacy will need to be carefully managed as the power system continues to decarbonise.
  2. Peak electricity demands will increase[4] between now and 2050, meaning generation capacity could need to increase by up to three-fold. As power system decarbonisation progresses, we will see larger and more prolonged periods of excess demand and excess generation[5]. In periods of excess demand, we are currently able to rely on unabated coal or gas to fill the gaps, but as the power system transitions away from these sources to 2035, sufficient supply and demand-side measures will need to be in place to maintain security of supply.
  3. During periods when wind generation exceeds demand, large volumes of renewable generation will not be needed, meaning that asset owners may need to be paid to curtail their output. The introduction of technologies such as electrolysis, batteries, and electric vehicles can substantially mitigate curtailment of intermittent renewable generation by storing it for future use.

Flexibility

  1. We need flexibility to manage the electricity system safely and securely. Sources of flexibility enable us to match supply and demand quickly.
  2. Flexibility has traditionally been managed from the supply-side of the electricity system e.g. by increasing or decreasing electricity generation from gas turbines. In 2020, 58% of our total power output from flexible electricity technologies came from natural gas[6]. As unabated fossil fuel generation reduces to 2035 and 2050, this source of flexibility will decrease.
  3. The type of flexibility natural gas provides will continue to be important to the whole future energy system. As its use diminishes, alternative solutions are needed. Focus is required to optimise the energy system infrastructure changes needed to deliver zero-carbon energy to consumers[7].
  4. Interconnection capacity, vehicle-to-X[8], biomass generation, hydrogen production and generation, energy storage (of different scales, durations and technology types) can all provide flexibility to the electricity system. The degree to which any one technology will contribute to managing renewable generation and peak demands on the electricity system will vary. To reach net zero by 2050, our modelling suggests plausible scenarios of 210GW-230GW[9] of demand and supply flexibility needed on the electricity system by 2050.
  5. Flexibility can be provided by varying demand to match supply, through consumers increasing or reducing demand or shifting the time at which they consume energy. To varying degrees, this type of demand side flexibility can be provided from the residential, industrial, commercial or transport sectors.
  6. Though the impact on the electricity system of an individual action is low, research[10] of 20,000 households from a consortium including National Grid ESO indicates that aggregating individual actions could have a significant impact in reducing or increasing demand, depending on what the electricity system requires. The Crowdflex project indicated that consumers on dynamic time-of-use tariffs could reduce their peak demand by 7%-14%, with similar results across EV-owning and non-EV owning households.
  7.         Crucially, we see domestic demand side flexibility as empowering consumers. The focus for domestic consumers will be energy intensive appliances such as dishwashers, washing machines and electric vehicles. The timing that these appliances run at can generally be shifted by several hours without impacting the consumer. 

Flexibility - long duration energy storage

  1.         When planning in a weather dependent energy system, consideration should be given to ensuring supplies are secure if a rare or severe weather event occurs. For example, one that occurs once every 10 or 20 years that would result in extremely long periods of time where there is little to no wind available on the system or consecutive periods with the same challenge.
  2.         The conversation on how to secure supply in these rare, very long periods of insufficient renewable supply, has suggested that long duration energy storage (LDES) should be explored as a potential solution. Although LDES should remain on the table as an option to secure supply, the rarer and more extreme the event you are securing against, the more difficult it is to see how the economics of LDES will work for this specific application. It appears more likely that another option may be required for these extreme events and LDES will be used to cover more frequent, less prolonged periods of low renewable output in conjunction with nuclear, carbon capture and storage with gas or hydrogen.
  3.         The price of LDES will be set by three things: rarity of operation, uncertainty of operation and the value of the energy storage to the energy system. The risk premiums mean that if an LDES asset plans to operate just once in 20 years, then they need to charge enough in that one event to cover 20 years of cost. To justify investing in that business model, an investor would need to account for the possibility that they might wait more than 20 years for the extreme weather event, which would further increase the price of LDES for this application.
  4.         Investment in short duration storage is growing rapidly, indicating industry confidence in the future market, but we do not see the same pipeline of future projects for medium and LDES. Discussions with the ESO’s storage stakeholders indicate that the market signals to justify investment in LDES are not strong enough yet, the costs of large storage projects are high and future revenues are too uncertain.
  5.         We suggest that the ESO, industry, the Government and Ofgem collaborate to understand and agree the durations and scales of prolonged renewable intermittency where it makes economic sense to use LDES and where other sources of supply would be better suited. This could include flexible carbon capture and storage, flexible nuclear power, hydrogen turbines, and unabated gas. Reaching a collaboratively developed conclusion on this across the energy sector, government and regulation, would ensure that any public policy surrounding business models for LDES are appropriate and incentivise investment.
  6.         Another option, which warrants discussion, is a business model where the LDES gets an availability payment for being ready to operate and earns less or nothing when it operates. This moves the uncertainty risk onto a central body.

Flexibility - hydrogen and hydrogen storage

  1.         Hydrogen is essential to achieve net zero, by supporting decarbonisation in different parts of the economy – particularly some of the hardest to abate sectors such as industry, heat or non-passenger transport.
  2.         The areas of the economy in which hydrogen is used will determine the production levels required and the way in which hydrogen is stored and transported. It will be important that the right incentives and signals are in place to deliver the necessary supporting hydrogen infrastructure in a timely manner as government decisions are made.
  3.         There are currently uncertainties including the role of hydrogen in the future of domestic heating which, until resolved, are a current barrier to long-term certainty of the sector. We support the Government’s hydrogen trials and would welcome their acceleration, along with the provision to industry of a clear message on how hydrogen will be used for heating.
  4.         Hydrogen storage is necessary to support whole energy system security of supply, as well as to accommodate any electrolysed hydrogen at times of excess wind or solar. This storage capacity could act as a sink for renewable energy generated when demand is low and make it available for later use. Despite low round-trip efficiency, H2 storage has the potential to manage seasonal differences in demand for heating, provided that sufficient hydrogen storage capacity comes online. We assume[11] that any hydrogen stored will be in salt caverns, as is currently the case with natural gas storage. By 2050, the electricity system may require 50TWh of hydrogen storage to manage winter demand.
  5.         The Government should commission further detailed study, via the British Geological Survey, to provide clarity on suitable hydrogen storage sites to provide the hydrogen industry with confidence that sufficient storage capacity is available for a high hydrogen economy. A recent[12] study indicated that the UK has a theoretical hydrogen storage capacity of 3000 TWh but this drops to 200 TWh when small sites are discounted as unsuitable.

Energy storage - strategic reserves

  1.         We are supportive of the Government’s indication in the British Energy Security Strategy that it will design new business models for hydrogen storage infrastructure.
  2.         Before its wind-down was agreed, the offshore gas storage facility at Rough provided a significant portion of the UK’s natural gas storage, acting as a strategic reserve. Its closure was predicated on being able to purchase natural gas at a spot price that was not as costly and volatile as it is today.
  3.         The wider electrification of the economy and the Government’s indication[13] of its intention to transition away from the use of natural gas, means that if we are to rely on other forms of energy storage, the Government should consider whether a strategic reserve is necessary for future periods of low renewable energy generation and high energy demand.
  4.         Though an energy storage reserve is beneficial to future security of supply, the storage facility at Rough was wound-down due to the economics of long-term gas storage not being viable. The Government should work with industry to understand whether the same level of security of supply could be achieved in a different way.
  5.         Lessons from Rough suggest that a strategic energy storage reserve cannot be pump-primed and left to the merchant market to operate. Any strategic energy storage reserve would likely require state intervention, meaning the Government would need be willing to support something uneconomic for a long period of time.
  6.         The development of a global green hydrogen market should be explored as a way of ensuring strategic security of supply. Hydrogen can be produced via electricity and an electrolyser, meaning it is less likely than natural gas to be used for geopolitical gain in challenging times. The Government should engage at international level to assess the feasibility of developing a market of this nature.

What should the Government do to incentivise and enable investment in, and financing of, reliable and affordable energy that is in line with its climate objectives, including net zero by 2050?

Current electricity markets cannot deliver net zero 2050 effectively

  1.         There is growing industry consensus that the existing electricity market design is not fit to deliver net zero by 2050 and that electricity market reform is required to achieve a carbon-free electricity system by 2035.
  2.         Current market design:
  3.         Dynamic real-time locational price signals are needed to achieve net zero. The lack of these sharper price signals, and the use of a national wholesale electricity price, exacerbates existing problems electricity network.

Reforming the market to support flexibility and security of supply – nodal pricing

  1.           The ESO’s Net Zero Market Reform[14] programme is developing new market design options to support power system decarbonisation, the resource adequacy and flexibility required to keep the lights on and reduce costs.

 

  1.         Broadly, three locational approaches to pricing exist for the GB electricity market. A single national price, which is the current framework; a zonal pricing system, where the system is divided into several regional zones with individual prices; and nodal pricing, where the system is divided into many different nodes with individual prices.
  2.         In the case of nodal pricing, different nodes are priced on their ability to flow power, meaning that in an area with significant levels of generation, prices would be low and in an area with low generation but significant demand, prices would be higher.

 

  1.         Although our analysis is not a firm conclusion, nodal pricing appears to be the only option that we see addressing critical issues in the current design - efficient dispatch of generation to reduce balancing costs; accurate signals for interconnectors and storage; sharp locational price signals needed to realise the full energy system value of demand side flexibility and more adaptable and resilient to changes in electricity market conditions.

 

  1.         Price signals that accurately reflect location and time will facilitate an effective, flexible demand side but current network charges do not reflect the real-time dynamic variation in congestion costs. Greater within-day price variations with nodal pricing would greatly increase the incentive on consumers to shift demand to times of greatest local renewable output, reducing the peaking capacity requirements

Nodal pricing - impact on investment

  1.         For asset investment, sharper locational signals can positively impact business cases. For example, improved signals will clearly indicate where flexible assets (e.g. energy storage or an electrolyser to produce green hydrogen) should be placed to alleviate network constraints.

 

  1.         Although electricity transmission investment is required to achieve net zero, the introduction of nodal pricing could reduce the future quantity of transmission build that is required, as an improved balance between supply and demand may mean that less liquidity (level of generation capacity) is required.

 

  1.         There has been some concern that a move to nodal pricing could impact on investment in renewables as it increases uncertainty. Our analysis of international markets where nodal pricing has been implemented (such as certain US states) indicates that a change to nodal pricing does not reduce investment in renewable generation.

 

  1.         We support BEIS’ announcement of its Review of Electricity Market Arrangements (REMA) and encourage the scope of the review to consider investment signals, flexibility, location and operability, as well as the policy changes required to deliver nodal pricing within GB.

 

  1.         Any decision on market arrangements will need alignment between the Government and the energy regulator. We now await the outcomes of Ofgem’s commissioned study of the design options for nodal pricing in GB.

Incentivising behaviour

  1.         Deploying and connecting the technologies that can contribute to achieving net zero will be a significant achievement but the way these technologies behave within the energy system is important to security of supply.

 

  1.         Technologies need to behave in a way that benefits the energy system, rather than simply connecting. An example of this is the way that energy storage charges and discharges. Energy storage should ideally dispatch in the best interest of the energy system but this is not always the case.

 

  1.         Incentives exist for an energy storage asset owner to hold onto their storage until the moment it is most valuable to the power system (e.g. [15] day 12) rather than discharge earlier but the incentives are not strong enough. For example, if an energy storage asset charged at 30 £/MWh, it could discharge at 70 £/MWh, or hold the energy for longer in the hope of getting 140 £/MWh. There is a stronger incentive to take the 70 £/MWh now and then see if they can charge their asset again before the price rises to 140 £/MWh. The benefits of this rapid cycling and taking known value now, beat the benefits of waiting for unknown possible future value. If there is sufficient energy storage liquidity in the market then this would not be a problem but the price of energy storage when it is most needed by the power system could be very high and value to the consumer must be taken into account.

 

Planning reform

  1.         We welcome the Government’s commitments in the British Energy Security Strategy to planning reform that will see the acceleration of both network transmission and offshore wind projects. This is a critical commitment that will increase the speed at which we can meet decarbonisation targets.

 

  1.         Increasing the speed at which onshore transmission can be built will reduce constraint costs for consumers to the tune of billions of pounds by the end of the 2020s. The Government should continue to focus on reforms to the National Planning Statement that speed up delivery of onshore transmission.

Current National Electricity Transmission System planning

  1.         To identify the future transmission requirements of the National Electricity Transmission System (NETS), there are several inputs that are fed into the planning process and at various stages.
  2.         The ESO models production and consumption pathways to 2050 and gives an overview of peak demands and generation capacity across the UK. We use this data to identify points on the transmission network where more capacity is required. Once these requirements are understood, we invite stakeholders to propose solutions and recommend the most economic and efficient solutions to proceed.
  3.         A step-change in the speed and scale of transmission build and deployment is required. Growth in transmission network must be efficient for consumers and take account of the impacts on communities and the environment.
  4.         The ESO is currently working on delivering a holistic approach to future network planning and design to deliver the infrastructure to achieve net zero. To deliver optimum energy engineering solutions that consider economic, environmental and community impacts and address the pace of transmission build, future system planning should follow a similar approach to our Holistic Network Design[16]. Following this approach allows a long-term, coordinated view of the energy system rather than an annual or shorter-term, iterative approach to building new infrastructure.

The role of the Future System Operator

  1.         BEIS and Ofgem published their joint response[17] to the public FSO consultation on 6th April 2022. The response indicates that the FSO will expand over time to look at the whole energy system. As well as all the current roles of the ESO, the transition will see it take on new activities in gas network planning, gas market strategy and long-term gas forecasting.
  2.         The FSO will have a statutory supporting duty to consider whole system impacts and therefore it is expected that the FSO will need to consider the development of CCUS, hydrogen and heat and transport decarbonisation as part of its responsibilities in system forecasting, strategic network planning and when advising government or Ofgem.
  3.         Roles on local area energy planning, as suggested by a Witness to the inquiry, are not yet decided and it may be that an organisation external to the FSO is best placed to engage with local and combined authorities to plan the delivery of their net zero ambitions. We will continue to engage with BEIS and Ofgem to develop a clear pathway to delivering the FSO and establishing its future roles in a timely manner.

 

29 April 2022

 

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[1] BEIS & Ofgem (2021) – Proposals for a Future System Operator consultation

[2] Future Energy Scenarios report and supporting documents - https://www.nationalgrideso.com/future-energy/future-energy-scenarios/fes-2020-documents 

[3] Alongside the Future Energy Scenarios report we publish a FES in 5 summary covering the major topics of the larger report. FES in 5 is available here - https://www.nationalgrideso.com/document/174016/download 

[4] FES 2021 – Key insights – Figure SV.22: Installed electricity generation capacity, storage and interconnection to 2050 pg.112.

[5] National Grid ESO (2021) – Net Zero Market Reform: Case for Change and Options Assessment Framework. Modelling of a renewable-heavy energy system during a week in 2035 indicates average potential excess generation of 39GW.

[6] FES 2021 – Where are we now? Electricity system flexibility

[7] FES 2021 – Whole energy system flexibility

[8] Vehicle-to-x technologies (V2X) allow an electric vehicle to export the energy within its battery for another use, for example to a home or to the electricity grid. This offers additional flexibility to the energy system and a potential revenue source for businesses and consumers.

[9] FES 2021 – What we’ve found. Supply and demand flexibility in 2050 – power output of flexible technologies pg.13Figure FL.3

[10] Energy Networks Association (2021) – Innovation portal: Crowdflex project

[11] FES 2021 – Hydrogen Supply: Overview of hydrogen storage

[12] British Geological Survey 2020 - Theoretical capacity for underground hydrogen storage in UK salt caverns

[13] BEIS (2022) – British Energy Security Strategy

[14] National Grid ESO (2021) – Net Zero Market Reform

[15] This is a nominal day only to illustrate the point

[16] ESO (2021) Latest News - Offshore Coordination Project – Holistic Network Design

[17] BEIS and Ofgem (2022) – Response to the Future System Operator consultation