Statera Energy – Written evidence (LES0023)


Statera Energy is a leading UK developer of flexible energy generation and storage technologies which help balance the grid. We build, own, and operate flexible assets such as batteries, pumped hydro-electric storage, and hydrogen production, storage, and power generation. We were recently a successful applicant to the Net Zero Hydrogen Fund (Strand 1), securing development expenditure funding to support a 3GW electrolyser project at Kintore, Aberdeenshire.


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?


In their study, ‘Long duration electricity storage in GB Aurora found that up to 24 GW of Long Duration Electricity Storage (LDES) would be required by 2035 to effectively manage the intermittency of renewable generation. They define ‘long-duration’ as everything longer than 4 hours. In the Future Energy Scenarios 2023, the System Transformation Scenario requires 41.5GW of medium-duration storage (batteries, liquid air, compressed air and pumped hydro) and 56TWh of hydrogen storage for 2050.


The grid would draw heavily on periods of combined low wind and solar generation that last longer than a day, particularly if these periods last several days. These have come to be known as ‘dunkelflaute’.


A Brief Climatology of Dunkelflaute Events over and Surrounding the North and Baltic Sea Areas found that dunkelflaute periods historically occur between two and ten times each year, and they are most often in November, December, and January. The study also found that there was moderate correlation of dunkelflaute events for neighbouring countries. This suggests that whilst interconnection can help ensure security of supply, it is unlikely to be sufficient on its own, and long duration storage would be required.


Demand will vary depending on the scale of electrification. The Future Energy Scenarios 2023 shows total electricity demand for 2035 ranging from 400TWh in the system transformation scenario to 479TWh in leading the way.



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

Whilst these technologies may have a role to play in the future generation mix, nuclear and fossil fuel generation with carbon capture cannot help with the problem of excess renewable generation. Given the government’s commitment to 50GW of offshore wind by 2030, there will be significant periods of excess renewable generation because the transmission network does not have the capacity to transport the energy to demand. Without storage technologies, this excess generation will go to waste. Storage technologies can therefore provide value in maximising the capacity of intermittent renewable generation to meet demand.


Interconnectors can contribute to addressing the imbalance between supply and demand but only with the right price signals. Currently, with a single national electricity price, situations can arise where GB can be exporting electricity from an area where there is insufficient supply or importing electricity into an area where there is insufficient demand. For example, there is often significant oversupply in Scotland and Northern England, but if the national price in GB is higher than the electricity price in Norway, GB would still be importing electricity via the NSL, exacerbating constraints. Without accurate price signals, interconnectors can increase balancing costs and negatively impact security of supply by exacerbating peak demand.


Furthermore, as a result of leaving the European Union, the GB market has de-coupled from the EU market and there is no longer a single GB day-ahead clearing price. As electricity is no longer traded through the EU market coupling regime, the channel interconnectors have reverted to explicit capacity allocation. This means customers use interconnector services to buy or sell capacity and energy separately, and they are required to choose a specific interconnector and flow direction. Explicit trading is far less efficient and leads to far greater occasions of ‘flows against price difference’ – where the interconnector doesn’t flow from low price to high price, but rather the other way around.


As a result of these inefficiencies, interconnectors should not be relied upon for ensuring security of supply.


Whilst demand management can certainly contribute to reducing the dependence on storage, the scale and timeframes of the oversupply of renewables cannot be met solely through demand management. Carbon Tracker has estimated that wind congestion could reach 18TWh by 2030, a fivefold increase compared with today.


The ESO’s Demand Flexibility Service last winter delivered 3,300MWh in electricity reductions at peak times across the 22 events. This was at a time of high customer engagement as a result of the extremely high energy prices and the war in Ukraine and the level of engagement cannot necessarily be relied upon in future. Until demand flexibility can be automated and therefore deployed at scale with little cost, it is unlikely to have significant uptake beyond the most engaged consumers who are most able to respond to signals. Furthermore, this type of demand-side management is best suited to reducing peak demand but is not suitable for providing long term security of supply in the case of multi-day wind droughts.




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

Batteries are best suited to shorter duration, intraday storageup to 6-8 hours typically. Pumped storage is well suited to medium-duration storage as it typically has lower £/kWh storage costs than battery storage when moving to longer durations. Hydrogen electrolysis, storage, and hydrogen to power is best suited for the longest time frames as hydrogen can be stored inter-seasonally.


The majority of energy storage technologies have a high technology readiness level. Pumped hydro storage, electrolysers and gas storage are all mature technologies. Hydrogen to power has a lower technology readiness level and has not yet been deployed on a commercial scale but is expected to be commercially available within the next 4-5 years.



The level of energy storage demand needs depends on the decarbonisation pathway, particularly how heat and transport decarbonise. We already have high levels of curtailment of wind generation, and an ambitious pipeline for the future wind deployment that will provide significantly more opportunity for electrolysis. Therefore, it would be possible to produce sufficient volume of green hydrogen, but the challenge would be the transportation and storage of that hydrogen. Without transmission blending and a dedicated hydrogen pipeline, hydrogen production, storage and demand cannot be connected.


In our view, the government needs to provide clear strategic direction about the future of hydrogen networks to ensure the development of an integrated hydrogen economy that can meet energy storage needs. We believe that it would also be beneficial for the government to state their ambition for green hydrogen beyond 2030.




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


The government has committed to developing policies to enable investment in long-duration energy storage (LDES) by 2024. However, given the long lead times for pumped hydro projects, it is unlikely that new projects will be operational before 2030. It light of the urgent need for storage before 2030, government must ensure that a subsidy scheme for pumped hydro is operational as soon as possible.


For hydrogen storage, a clear strategy for hydrogen networks is required as it is very challenging to develop hydrogen storage at scale without a view of how demand, supply and storage will be connected.


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?


Pumped hydro storage is capital intensive with long lead times. Given that the Capacity Market's four-year lead time is insufficient, and the Contracts for Difference scheme does not cover energy storage, a dedicated support scheme is needed, and a cap and floor is the preferred option.


A key barrier for hydrogen storage is the absence of an onshore storage licensing regime. Government must provide guidance to developers about the appropriate route for applying for a hydrogen storage licence.


It is our view that there is a critical need for greater strategic planning and coordination between the Electricity System Operator, National Gas, Ofgem and DESNZ. In the future, our assumption is that the Future System Operator will be responsible for coordinating the development of natural gas, hydrogen, CO2 and electricity networks, and the cross-vector interactions between these networks. However, given the FSO is not yet operational, coordination between these different bodies is crucial for the efficient development and redeployment of new and existing networks. Strategic planning cannot wait until the FSO is in a position to take on that role.


Hydrogen storage and pumped storage are largely geologically constrained, and therefore sharper locational investment signals would have minimal impact. However, we believe that stronger locational signals can incentivise the efficient location of electrolysers. The government has already acknowledged this in the recent Hydrogen Allocation Round 2 market engagement, and we are in support of the proposals to reward the siting electrolysers in locations that provide wider system benefits. The ability of electrolysers and certain types of hydrogen demand to be sited efficiently, unlike hydrogen storage (which is limited by geology), underscores the need for networks to connect these assets.


REMA also has a role to play in sending sharper operational signals for storage. It is currently very difficult to forecast balancing actions taken by the System Operator. More transparent dispatch signals could ensure that storage assets are able to maximise arbitrage opportunities in the wholesale market.


In theory yes, so long as the networks (both electricity and hydrogen) and market frameworks are in place. As previously mentioned, there is currently no subsidy scheme in place for pumped storage, and this is urgently needed given the long lead times.



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?


Our key concern is around the hydrogen supply chain, particularly for procuring electrolysers at scale.


There are currently not many hydrogen electrolyser manufacturers, and only one which produces electrolysers at scale in the UK. The US’s Inflation Reduction Act and the EU's Green Deal Industrial Plan aim to grow domestic manufacturing markets for hydrogen electrolysers. These strong protectionist pulls make it harder for UK companies to compete internationally.


Statera is developing a large-scale GW capacity electrolyser in Scotland, and we are aware of various challenges that may arise with the supply chain. The largest electrolyser manufacturer in the UK currently only has ~200MW per year of capacity, ramping up to ~700MW this year – this would take several years to reach the intended capacity of our own development. Manufacturers outside the UK have already sold most of their capacity for the coming years, largely to their domestic markets. UK government’s target is 10GW of low carbon hydrogen by 2030, with 5GW of that being from electrolytic hydrogen. That target may be difficult to meet given the lack of UK’s manufacturing-capability and the domestic focus of hydrogen policy in the US and EU.




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)?

We do not believe that there are sufficient training schemes to ensure the skills pipeline needed to delivery energy storage. This is of particular concern for the low carbon hydrogen industry given its nascency. The hydrogen economy will require many of the same skills as the oil and gas industry, particularly in terms of technology, and health and safety. Aberdeen has long been a skills centre for oil and gas, and those skills are hugely valuable to the development of a low carbon hydrogen industry.


Incentivising manufacturing and the electrolysers themselves to locate in Scotland not only benefits the electricity system as a whole but also provides significant reskilling opportunities for the existing oil and gas industry as it transitions away from fossil fuels. Attracting workers to come to the UK will be hard in the face of competition with the US and EU, but the government has a huge opportunity to utilise existing skills and create a centre of excellence for hydrogen in Scotland.


There are significant lead times to develop the necessary infrastructure. Whilst it can vary, pumped hydro projects can take ~6 years to from Final Investment Decision to being operational. We are particularly concerned about the pace of development of hydrogen networks. Furthermore, electrolyser projects are being developed on the basis of government targets for wind deployment. It is critical that these infrastructure targets are met to avoid negative knock-on implications for the entire hydrogen supply chain.



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

For hydrogen storage to be of maximum value, it has to be connected to both supply and demand. A more integrated hydrogen economy would be more secure and reliable than a less integrated one. This is because it would be more efficient in its use of infrastructure, better able to coordinate demand and supply, and offtakers would be less reliant on any one source of hydrogen.


In our view, blending at transmission level is an important stepping-stone in ramping up all elements of the hydrogen economy. It is particularly important in the interim period before the development of dedicated hydrogen pipelines. The needs case for dedicated hydrogen pipeline is harder to make when there is so little hydrogen production and demand, but the development of the production and demand is difficult without network infrastructure. A clear strategic direction for the development of a hydrogen network, as well as a decision on blending hydrogen at both transmission and distribution levels, is crucial.


11 September 2023