RenewableUK – Written evidence (LES0036)

About RenewableUK

RenewableUK’s members are building our future energy system, powered by clean energy. We bring them together to deliver that future faster; a future which is better for industry, billpayers, and the environment. We support over 450 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.

RenewableUK welcomes the opportunity to comment on this call for evidence on long-duration energy storage. This inquiry has come at a critical time where the UK must begin to ramp up deployment of long-duration energy storage to achieve a cost-effective and net-zero electricity network which will rely predominantly on variable renewable energy.

Our key recommendation is that the Department of Energy Security and Net Zero urgently release its minded-to consultation on the preferred approach to best enable investment in long-duration energy storage by 2024. Many of these necessary projects have long lead times and required new infrastructure. We are running out of time to have long duration energy storage in place by 2035 to ensure a net zero, reliable and cost-effective energy system.

We have outlined our responses to the inquiry’s questions below.

1. How much medium- and long-duration energy storage will be needed to reach the Government’s goal of a fully decarbonised power grid by 2035 and net zero by 2050, and by when will it need to be ready?

There are a range of estimates on how much energy storage is needed. In terms of additional power long duration storage (technologies such as pumped storage, compressed air energy storage and liquid air energy storage, that do not rely on hydrogen as a storage medium), AFRY’s analysis for DESNZ (then BEIS) published in 2022 estimated[1] that between 2.5 and 3GW is a low regrets level by 2050. AFRY estimated that support for long duration storage deployment could lead to system cost saving within the range of £13-£24bn.[2]

Power analytic company, Aurora, reported in February 2022 that up to 24GW/48 TWh of long duration energy storage – equivalent of eight times the current installed capacity – could be needed to integrate wind power as well as solar into a secure net zero electricity system. In this report, long-duration energy storage was defined as technologies able to provide energy for over 4 hours at full capacity.

There are also vastly differing estimates on how much green hydrogen long-duration storage would be required for a net zero electricity system, as there are many different variables including the use of nuclear power, and extreme weather patterns:

• The Climate Change Committee has stated that 2.1-2.8 TWh of hydrogen storage is deployed by 2030, 3.3-5.2 TWh by 2035, and 7.1- 11.6 TWh by 2050,[3] and
• AFRY has estimated between 11.4TWh to 17.2TWh would be required by 2050.[4]
• A Royal Society study, examining a worst-case scenario for the UK has estimated that between 60 – 100TWh of hydrogen storage would be required.[5]

Under what scenarios would the grid draw heavily on long-duration storage? How well are these scenarios understood?

According to the ESO’s Future Energy Scenarios’ 2023 Leading the Way Scenario,[6] 86% of electricity generation will come from wind and solar by 2035. There will be periods where there is an undersupply of wind and solar power, when the grid will need to draw on short to long storage. Longer periods of undersupply are called ‘dunkelflautes’.

While there may be flexible generation that will be able to fill in the troughs in renewable energy output, most notably hydrogen, CCGT with CCUS, and biomass, without the ability to store (and use) the excess renewable energy generation over long durations, substantial amounts of energy will be wasted, raising costs of delivery.

What is the range of estimates for likely electricity demand in 2035?

The ESO’s Future Energy Scenarios 2023 provides an analysis on energy demand.

2. How sensitive is the amount of storage needed to assumptions about the future balance of supply and demand on the grid?

What role could greater grid interconnectivity between Great Britain, Northern Ireland and other nations play in addressing the imbalance between supply and demand?

Flexible technologies are vital to meeting Governments targets, including integrating 50GW of offshore wind by 2030, helping to deliver on up to 10GW of low carbon hydrogen and 18GW of interconnector capacity BESS commitments by 2030. By 2030 and beyond multi-purpose interconnectors (MPIs) in particular will have a large role to play in integrating more renewables across GB and Europe and will be important source of balancing and seasonal flexibility.

What role could demand-side management of electricity play in reducing the dependence on storage?

Increasing energy efficiency to reduce demand and switching to electrification where possible will reduce the need for storage.

What role could nuclear power, fossil fuel generation with carbon capture and storage, or other energy technologies, play in reducing the need for energy storage on a net zero grid?

No comment.

What impact will future climate change have on demand – for example, how much will the seasonal differences in power demand change with warmer winters and greater use of air conditioning? 

No comment.

3. Which technologies can scale up to play a major role in storage?

Which timescales for storage are different technologies most suited to? Is there a preferred technology for medium-duration and long-duration storage?

The UK market is not short of innovative storage technologies which operate on a range of durations and offer a spectrum of system services. Various technologies[7] meet the definition of long duration electricity storage (the ability to provide energy for over 4 hours):

• Flow batteries – long-duration batteries which work by turning electricity into chemical energy that can be reversed when the device discharges.
• Mechanical – convert electricity into mechanical energy that is released by reversing these processes. The released energy is used to drive turbines or generators, producing electricity. It includes technologies such as flywheel storage, compressed air or liquid air storage or pump hydro.
• Thermal – technologies store energy as heat in various materials. It includes technologies such as water tanks, underground aquifers and mine water systems or pumped thermal energy storage.
• Hydrogen – low-carbon hydrogen can be stored in large quantities and converted back to electricity when needed on the grid. Hydrogen can be stored as a gas in underground salt caverns or underground aquifers and depleted gas fields. Hydrogen can also be converted to other gaseous or liquid synthetic fuels (such as ammonia or methane), which may be easier and/or cheaper to store and transport.

What are the technology readiness levels for these energy storage technologies?

Power analytic company Aurora has provided a useful breakdown of technologies in their 2022 report:[8]

Is there a distinct role for technologies that store heat instead of electricity?

No comment.

Is it possible to produce enough domestic green hydrogen to fulfil long-term energy storage demand needs?

As discussed above, there are varying estimates of how much green hydrogen storage is required. However, the main issue is whether we have the market support and facilities to allow a domestic green hydrogen market to service storage needs. We outline below our recommendations on how to address the barriers to green hydrogen deployment:

i)                  Green hydrogen is capital intensive and there is a lack of investment certainty

A key issue is that we currently don’t have a domestic green hydrogen market as the end-to-end costs are high and it does not have a clear route to market. While the Hydrogen Business Model (HBM), Net Zero Hydrogen Fund (NZHF) and recent announcement of projects entering the negotiation stage of Hydrogen Allocation Round 1 (HAR1) are positive steps, the current framework is complex, experiences significant delays and includes design features that are not fit for purpose. The Government should:

• Strictly adhere to established deadlines for the completion of the HBM and NZHF, and finalise contractual terms for HAR1 as soon as possible.
• Clarify the allocation pot up to and beyond 2030, and the application decision-making process should be streamlined to 6 months, in line with the CfD scheme.
• Delay a shift from bilateral agreements to competitive auctions, until satisfied that competitive auctions would not place unnecessary pressure on hydrogen developers to cut costs at the expense of domestic supply chains.

Please see our responses to the Call for Evidence on the Future Policy Framework for Allocation of the Low Carbon Hydrogen Business Model and Hydrogen Allocation Round 2: Market Engagement for more detail.

ii)               The UK’s planning regime is slow, complex and difficult to navigate for developers seeking consent

The UK needs a planning and permitting regime that encourages renewable hydrogen deployment at scale and speed. However, there are several sticking points in the current planning framework which are causing unnecessary delays and investor uncertainty:

• a lack of guidance specific to green hydrogen projects, resulting in confusion around what is required when co-locating with a renewable energy project;
• a lack of knowledge, internal resources and guidance within relative departments responsible for processing applications, leading to a risk around consent and hampering decision making.
• perceived negative impact on local water supply, particularly water scarcity, is also a sticking point.
• Green hydrogen developments are not able to be brought forward as an NSIP where they are of sufficient scale and need a range of consents. In some instances, project developers are forced between two consenting regimes
• community pushback due to knowledge gaps and misconception around green hydrogen production.

The Government should prioritise amending and updating the existing planning framework to include green hydrogen and create simpler, faster and more predictable processes for the deployment of green hydrogen projects. This involves:

• Updating all relevant national guidance to include green hydrogen;
• Adopting a strategic approach to future water needs, including for electrolysis;
• Futureproofing the environmental regulators and HSE for net zero;
• Modernising the planning regime for green hydrogen; and
• Educating relevant stakeholders about green hydrogen.

Our full recommendations are outlined in our report Planning for Onshore Green Hydrogen.

iii)             Build out of associated infrastructure is slow

The development of significant amounts of new or repurposed infrastructure is essential for transporting hydrogen from production sites to demand centres and/or storing it; but this can take several years to build. Large transport and storage infrastructure projects have relatively long lead times (~5 years construction) with limited room to accelerate without significant financial commitments ahead of Financial Investment Decision.

The planned 2025 release date for large scale Transport and Storage business model support is therefore too late and could significantly hinder the rollout of infrastructure needed to underpin the hydrogen economy. The Government should bring forward the commencement date for the Transport and Storage Business model as associated infrastructure for hydrogen projects can take up to 7 years to build and therefore may cause delay to the operation of projects.

The Government should also establish a dedicated business model for green hydrogen storage during the growth phase to mitigate volume risks associated with a low user base while the hydrogen economy grows. This support should be extended to providers of storage.

The Government should also encourage the retrofitting of existing infrastructure to allow for the transportation of hydrogen.

4. What policy support is currently in place to support deployment of storage technologies? Is it sufficient to support deployment at scale?

How good is the economic case for long-duration energy storage? What policies and market structures need to be put in place to make the business case viable?

Many long -duration energy storage technologies have not yet been able to scale-up and still require a route to market. It is clear that Government policy is not sufficient to support the development of these innovative energy technologies, and Government must urgently implement measures to address the issues outlined below.

The need to develop appropriate policy to enable investment in long-duration storage has been recognised by DESNZ. With an initial call for evidence in Summer 2021, BEIS suggested four possible approaches to support the deployment of long duration electricity storage.

However, since then progress has stalled. In August 2022, the Department committed to develop policy to enable investment in long duration storage by 2024. Even so, the industry lacks clarity on the preferred approach to support deployment and there are serious doubts that the government’s commitment can be met. Time is running out to develop and design appropriate policy to support investment within this timeframe.

There is long-established and growing consensus across the industry that an adapted cap and floor mechanism is the most appropriate tool to support deployment in long duration storage technologies. In December 2021, KPMG analysis on four different approaches to support long duration storage deployment concluded that “a cap and floor revenue support mechanism has the potential to be suitable for long-duration storage projects” and explored a number of detailed design features which should be considered by the Government such as pass through costs, flexibility to reflect different technologies incentives to deliver market outcomes[9]. Several further reports have also recommended an adapted Cap & Floor mechanism.

What role does the Review of Electricity Market Arrangements need to play to support medium- and long-duration storage development?

As part of Review of Electricity Market Arrangements (REMA), the Government should clarify what incentives and signals are most appropriate to encourage long duration energy storage to operate in concert with system need including mitigating system constraint.

The Government should set out a vision on reforms impacting long duration storage and how they could interact – removing barriers to participation in the Capacity Market, reforming the Capacity Market to ensure it aligns with net zero, future ancillary services and revenue stabilisation mechanism.

How will the grid need to change to support long-duration storage? Which stakeholders (e.g. energy companies, the Electricity System Operator, National Gas) should be planning for these changes?

The ESO, and in due course, the Future System Operator, should continue to play a role in setting scenarios for the requirements for long-duration storage. These scenarios will inform the Centralised Strategic Network Plan (CSNP), that will set out what grid is required. However, long-duration storage will play a central role in reducing the need for new network, as some forms of storage, such as liquid air can be more flexible in terms of location and be placed in front of constraints.

Is the Government’s current reliance on market actors and technology competitions likely to deliver the storage needs on time?

As noted above, the industry is still waiting for the government to publish a final decision on the market framework. These could deliver the needs on time, but time is running out to publish the necessary details for market actors to deliver.

5. How well developed is the UK industry across different storage technologies, such as hydrogen or redox flow batteries? How does the UK compare to global competitors in these industries?

In regards to green hydrogen, several developers are already exploring geological storage for green hydrogen, including Inovyn who are exploring repurposing salt caverns in Cheshire, SSE and Equinor who are looking at developing a new salt cavern at their Aldbrough site, and Centrica who are exploring converting the Rough facility to store hydrogen. The successful redevelopment could offer a phased capacity build up to 10TWh of storage to UK infrastructure.

However, while there are up to 2GW of green hydrogen projects in the pipeline according to Energy Pulse, only 4MW is currently operational.[10] In comparison, 460MW of projects (greater in size than 5MW) globally reached FID outside of the UK between 2020 and 2022.[11]

There is a serious risk that by the time the first UK projects eventually get the go ahead they will be competing with larger opportunities in countries with more experience and simpler business models, as well as facing supply chain and talent bottlenecks. As another example, as at the end of April 2022, there was just a single electrolyser factory in the UK, located in Sheffield whereas Europe has doubled its electrolyser manufacturing capacity between 2020 to 2022.

Despite this, Siemens Energy reports that the current planned capacity falls short of what is needed to meet the ambitious targets set by the UK and EU.[12] Soaring global demand for green hydrogen has resulted in lead times for electrolysers ranging from 9 to 18 months and compressors at 18 to 26 months.[13] As the US’s Inflation Reduction Act tax credit system takes effect, and major component manufacturers secure contracts with US-based green hydrogen developers, it is likely these bottlenecks will exasperate.

The Government must support respond to international tax incentives that are already driving investment in green hydrogen projects and supply chain outside the UK. Treasury could also establish a co-investment fund to assist in mobilising capital investment in new hydrogen manufacturing capacity and facilities. The OWMIS scheme is an example of a previous successful grant funding programme to secure manufacturing investment, which unlocked private investment in manufacturing across a number of UK sites.

For more information, see our Surveying the UK’s Green Hydrogen Supply Chain Capability report.

Are there any storage technologies that have a significant export potential for the UK?

In global markets, the UK has potential to gain a significant foothold, particularly in Europe where the EU aims to import 10Mt of renewable hydrogen by 2030. Germany, with its projected hydrogen demand of 90-110TWh by 2030 and domestic production target of only 14TWh, for example, presents a huge opportunity.[14] The UK’s abundant offshore wind resource and proximity to Europe position make it ideally positioned to meet this demand and become a major hydrogen exporter.

Gasunie and Tennet’s analysis indicates that mainland Europe may require between 200TWh to 1,200TWh of hydrogen annually by 2050, depending on the scenario. To satisfy this demand, the UK would need to produce 40GW to 240GW of offshore wind power at the cost of £20-40/MWh, which would create an export industry for the UK worth between £4bn to £48bn per year.[15] In order words, the UK has the potential to play a pivotal role in meeting Europe’s hydrogen demand and reap significant economic benefits in the process.

We recommend a comprehensive assessment of the UK’s future hydrogen transmission pipeline requirements, followed by independent bilateral negotiations to fund them. Such negotiations should be conducted outside the current T&S business model if required. It is crucial that future offshore wind leasing rounds, such as ScotWind and the Celtic Sea, should be taken into account while formulating these negotiations.

For which technologies does the UK have significant existing research or industrial capacity? Is the Government doing enough to support the industry to grow and drive exports and economic growth?

The Government allocated £68m in funding to support novel energy storage as part of the Longer Duration Energy Storage Demonstration competition, with the aim to prove the business case of for new and first-of-a-kind long duration storage technologies to investors. The Government should continue to support innovation in less established long duration storage technologies via grants and competitions.

Existing research and development funding from Government has successfully leveraged additional private investment. For example, the Government’s £31 million allocated for floating wind was matched by £30 million of industry funding.

Anchoring research and development in the UK is critical for ensuring that the UK supply chain remains internationally competitive, so we would advise the Government review and increase currently allocated funding. The target of Government should be to ensure that we have a more ambitious package than our competitor nations in areas in which the UK could lead technological innovation.

6. Beyond the cost of deploying long-duration energy storage, what major barriers exist to its successful scale up (e.g. the availability of a skilled workforce, the ability to construct the necessary infrastructure on time, or safety concerns around new technologies)?

The main barriers to large-scale deployment of long-duration energy storage projects are:

i)                   A lack of revenue and policy certainty

For most forms of shorter duration storage, the business case rests on high cycling rates – potentially charging and discharging multiple times a day in the case of batteries, playing and arbitraging a number of short-term markets. For long duration storage this business model is too risky because they need more visible long term cash flows to secure finance and investment given high upfront costs and long lead times. With 12 hours + discharge rates for some technologies, or inter-seasonal cycles for others, alternative business cases are be needed.

The challenge to build a viable business case within the energy market landscape now is also made harder as DESNZ is currently reviewing electricity market arrangements for the British power system[16].

ii)                 Technologies are capital intensive

High capital costs as well as high initial project costs in the case of pumped storage due to scale of the projects or limited deployment or widespread commercialisation for emerging long duration storage technologies. The high capex requirement for long duration storage projects further exacerbates the revenue uncertainty and increases the overall risk profile of projects.

iii)               Long lead times for development of assets due to permitting, connection queues and construction[17]

For instance, construction of greenfield pumped hydro projects can take between 5-7 years depending on the size[18]. Pumped hydro storage projects are still subject to the 50MW Nationally Significant Infrastructure Projects (NSIP) capacity threshold, which was once a barrier to battery storage deployment in England and Wales before the changes in regulations by BEIS in October 2019.[19] According to DESNZ, this is due to the planning impacts of pumped hydro being much greater than the likes of other storage technologies.

The majority of long duration storage assets are expected to be grid connected and therefore subject to similar network capacity constraints and prolonged delays to connect. The challenge to accelerate delivery of much-needed grid power lines will need to be resolved so that new assets are able to come online and charge and discharge from that network.

iv)               Future skills

A domestic green hydrogen economy will require a significant investment in skills across the workforce, with estimates of up to 9,000 roles in the sector by 2030, increasing to up to 100,000 jobs by 2050 under a high hydrogen deployment scenario.[20] Technical roles may require many years of training to for employees to meet the required standard. There is currently vast expertise accumulated in the oil and gas sector from which many employees may be retrained, though this may cannibalise existing energy sector talent in the near-term.[21]

A lack of necessary skills, due to lack of talent or training, will also create bottle necks and delays on projects.

7. What steps should the Government take now to ensure this storage can come online later in the current decade?

Can the UK learn from other countries that have successful policies for supporting large-scale energy storage, or from pilot projects elsewhere?

There are several key steps the Government should take to ramp up necessary deployment of long duration energy storage, in addition to the key recommendations for green hydrogen outlined above in question 3:

i)                  DESNZ should urgently publish a minded-to consultation on the preferred approach to best enable investment in long duration storage by 2024

RenewableUK recommends that the Department of Energy Security and Net Zero decides on policy to enable investment in LDES and urgently publish a minded-to consultation, following its call for evidence in Summer 2021. This should include a revenue stabilisation mechanism via an adapted cap and floor mechanism, to allow early projects to reach Final Investment Decision by 2024. The consultation should also address:

• The approach to support deployment of long duration storage. This should place strong consideration on the preferred industry mechanism – an adapted cap and floor.
• Considerations for detailed design of the preferred approach, including eligibility, length of contract, how the cap will operate and who will administer the scheme.
• The timeline to deliver sufficient level of long duration storage well in advance of 2035.

ii)                 Government should review and refresh the Smart Systems and Flexibility Plan, with a strategy for long-duration energy storage delivery

A refreshed Smart Systems and Flexibility Plan needs to clearly set out the strategic vision for long duration storage technologies by 2035 and thereafter 2035-2050, which will help the industry to understand what it needs to build towards.

iii)               The ESO should consider extending zero rating on grid capacity to storage in order to maximise efficient use of the grid and maximise the acceleration of renewable energy grid connections.

Long-duration energy storage assets require a different set of connection modelling assumptions from the ESO than generation assets as they can charge and discharge from the network.

11 September 2023