Written evidence submitted by AMP Clean Energy (HCC0040)
AMP Clean Energy Response to the Scottish Affairs Committee Call for Evidence - Hydrogen and carbon capture in Scotland
Introduction
AMP Clean Energy is a distributed energy business focused on Net Zero customer solutions to decarbonise heat and grid solutions to enable the decarbonisation of electricity. Our mission is to develop and finance decentralised energy projects which meet the commercial and industrial sustainability agenda and support the UK’s Net Zero ambition. We are committed to funding customers with complete low carbon energy solutions, delivering the best possible customer service.
The company has funded and manages more than 160 clean energy projects across the UK, and has 86MW of biomass boilers and 120MW of flexible generation in operation or under construction. We have a number of hydrogen projects in early-stage development and intend to participate in the allocation process which will commence this year for the initial round of revenue support.
AMP Clean Energy’s key message is simple: at a UK level, grid connected electrolysis should be allowed and should be considered be to meet the Low Carbon Hydrogen Standard – this is consistent with other decarbonisation policies. Furthermore, the grid in Scotland is already largely decarbonised and there is no credible argument as to why hydrogen produced today from electrolysis sited in Scotland and connected to the grid should not be considered low carbon. A policy which means that electrolysers in Scotland need to be linked to specific renewable generation (either physically or virtually) will limit uptake; lead to sub-optimal outcomes; and will also limit the usefulness of hydrogen production in helping tackle the significant electrical grid constraints that are already faced in periods of high winds, which will be exacerbated going forwards.
Detailed responses to the key areas identified by the Call for Evidence are set out below.
Response to key issues identified in the Call for Evidence
Question 1 - To what extent are the ambitions of the UK Hydrogen Strategy, published August 2021, adequate for Scotland?
AMP Clean Energy agrees with the principles set out in the UK Hydrogen Strategy and has engaged with the subsequent consultations on the UK Hydrogen Business Model, Low Carbon Standard, and Net Zero Hydrogen Fund. While we are supportive of the overall aims of these documents, we believe there is a significant risk to the growth of the Scottish Hydrogen Industry which must be addressed.
The minded-to position is that grid-connected hydrogen will not be considered ‘low carbon’ under the Low Carbon Hydrogen Standard. Projects which show a direct connection to a renewable generating asset, or a PPA and spatial and temporal correlation, would be low carbon; however, we believe that these models are overly restrictive and difficult to scale.
To achieve the stated aims we must support grid connected electrolysers (which will provide the capacity to make green hydrogen) and we should not conflate the decarbonisation of electricity with our green hydrogen objectives. Electricity policy (via CfDs and carbon prices) should drive low carbon generation capacity and hydrogen policy should drive electrolyser capacity (via CfDs, FCLs and locational grid charges) so that we can effectively decarbonise industrial heat, manage intermittency and provide long term and inter seasonal energy storage.
In light of today’s heightened security of supply concerns and the cost-of-living crisis, we simply need more of both. Linking the two policies via the requirements for additionality and PPAs (either private wire or sleave PPAs) will simply lead to
a) the sub scale deployment of electrolysers;
b) the sub optimal location of electrolysers in areas where green hydrogen can be made, but not used; and
c) higher CfD prices and more expensive outcomes for the taxpayer.
We do not require our RHI subsidised or grant funded heat pumps to prove additionality or to a have a PPA with a wind farm. In fact, in the case of heat pumps, RHI is paid on all metered heat including the heat generated from electricity and furthermore there is no test of the carbon content of this electricity. We also don’t require consumers buying electric vehicles (arguably the fastest growing source of electricity consumption now and over the next decade) to demonstrate that their cars charge directly from a solar panel to qualify for benefit in kind tax deductions. Such a requirement to do so, would simply stall the growth of this sector in its tracks. Why would or should it be any different with electrolysers?
If we are serious about building green hydrogen capacity, we need a more pragmatic approach to catalysing action and we need to drop the unnecessary requirements for additionality and PPAs, concepts which seem to have been borrowed in part from Road Transport Fuel Obligation policy.
If there is a conceptual determination to link electrolysers with low carbon generation (which again is not consistent with UK policy on electric cars, heat pumps, subsidised hydrogen buses), then there should be a focus on facilitating grid-connected electrolysis in geographical areas where the carbon intensity of the grid has already reached suitably low levels, such as Scotland. We believe that this could meet the ultimate gCO2e/MJLHV threshold for the standard. Our suggestions on this topic are discussed further in response to Question 2, but we must emphasise that this is very much a second-best outcome to that one described above.
Question 2 - What should be the focus of UK Government investment to ensure that Scottish industry, supported by Scottish research, is able to become a world leader in green hydrogen for domestic use and export?
We encourage the Scottish Affairs Committee to promote inclusion of a regional approach and use of constrained generation to the Low Carbon Hydrogen Standard, so that the Scottish hydrogen industry can become a world leader in hydrogen production.
A regional approach
If there is a requirement to link electrolysers to the form of electricity generation, then grid-connected electrolysis should be supported in geographical areas where the carbon intensity of the grid has already reached suitably low levels, given the huge differential in emissions from power production in the best- and worst-performing parts of the country. This regional approach could kick-start grid electrolysis in the first half of this decade in Scotland and unlock a significant production pathway with lower emissions that fossil gas SMR with CCS, for example.
The case for a regional approach is borne out by the latest figures on regional grid carbon intensity. The annual average for emissions from Scotland’s power sector in 2019 was 41g/kWh, compared to 181g/kWh for Great Britain in 2020. Indeed, Scotland’s emissions have been below 50g/kWh for the last three years and are expected to fall further from 2025, when National Grid ESO’s Stability Pathfinder project displaces the requirement for Peterhead gas-fired power station to support the stability of the transmission network.
This regional approach to low carbon electrolysis could be based on emissions in each Distribution Network Operator (DNO) area, or Transmission Network Use of System charging zone, with data on the former already available in real time at https://carbonintensity.org.uk/, meaning that a historical record could be developed to act as a tool for carbon intensity calculations in the future.
At the time of writing (Friday 25 February), emissions in the north Scotland DNO are 7gCO2/kWh and south Scotland is below 30gCO2/kWh, while emissions in South Wales were in excess of 330gCO2/kWh.
A regional approach would also deliver a direct link between low carbon electricity production and hydrogen production more effectively than, for example, the use of REGOs, unless there was to also be a requirement to show a temporal and spatial correlation between power generation and hydrogen production. We believe this would be overly complex and bureaucratic, therefore limiting growth. Likewise, if the standard were only to allow a direct physical link between renewable generation and hydrogen production, that would constrain growth and lead to a greater amount of SMR and CCS.
Another alternative is allowing grid electrolysis only in island networks, which will hugely limit growth, or waiting for the entire GB grid to sufficiently decarbonise, which will not happen until the early 2030’s according to the analysis presented in the consultation. Both of these options would represent missed opportunities to support grid electrolysis where it would already be low carbon.
Use of constrained generation
There is also an opportunity for clean hydrogen production from the use of power generation which would otherwise be ‘constrained’ due to limited inter-connection between different parts of the GB transmission network and the rapid growth of renewables. While not a perfect correlation, these areas are likely to be the regions with the lowest grid carbon intensity. Not only would this pathway facilitate low carbon hydrogen production in Scotland, but it would also contribute to balancing the wider electricity network and facilitate the integration of power generation with energy demand for heat and transport throughout the UK.
National Grid ESO estimates the cost of managing constraints at anywhere between £0.8 billion and £1.25 billion by the end of this decade due to the increasing volumes of renewable power generation, with the boundaries between East Anglia and the neighbouring network, and between Scottish Power Transmission and National Grid Transmission increasingly constrained.
The main method for managing these constraints is the Balancing Mechanism, in which generators and/or consumers offer to decrease generation/increase consumption or ‘bid’ to increase generation/reduce consumption. Similar to the proposal on regional carbon intensity, we believe that it would be possible to audit the power imported through offers in the Balancing Mechanism by a hydrogen production facility to develop a robust carbon weighting, and that projects in areas of high renewables penetration and high network constraints would be sufficiently low carbon.
The inclusion of this model to the Low Carbon Hydrogen Standard would ensure additionality, as by definition, the power generated and consumed would otherwise have been ‘constrained off’ through the Balancing Mechanism.
Similar to the proposal to allow regional carbon intensity, this would again incentivise hydrogen production in Scotland in terms of renewable energy capacity and the transmission network, reducing the economic burden of constraint payments and the overall need for additional investment in network infrastructure.
Finally, while the proposals in the above documents are agnostic on the end uses of hydrogen produced, both our suggestions above would support the development of a key form of long duration energy storage in the areas where this is most required due to higher penetration of renewables and a constrained grid.
Additionality
Lastly, we suggest that the Low Carbon Hydrogen Standard should not include any requirements on additionality. We believe that this would be an error and would artificially constrain the development of low carbon hydrogen production, and other policies to promote switching away from fossil fuels, such as support for electric vehicles or heat pumps, do not require a similar test to be met in order to access support.
We believe that interventions to reduce and ultimately remove carbon-based power generation from our electricity mix should be at a system-wide level rather being woven into every single policy lever. Indeed, it is likely that hydrogen production and use will be key to the decarbonisation of the electricity grid in the 2030s, and the priority should be the establishment of a new sector and production below the ultimate emissions threshold, rather trying to ‘map’ every single MWh of electricity which goes into hydrogen production.
The two pathways set out above (a regional approach and using constrained generation) would ensure additionality by increasing power demand in areas with potential for growth in renewables and also where there is an increasing challenge in terms of using the power which is already being generated.
Question 2 sources
Question 3 - Which market mechanism should be used to incentivise investment in producing low-cost green hydrogen?
Overall, we agree with the Government’s proposed approach to introduce a contractual, producer-focused business model, and believe that this is key to the development of the hydrogen production sector. However, we have a number of comments on the proposals for the Low Carbon Hydrogen Standard and Business Model and other key issues, outlined below.
Hydrogen business model
We favour the use of counterfactual fuel prices rather than projects’ sales prices, with three reference prices for the main markets for hydrogen use:
a) Gas price index to act as a reference price for heat projects;
b) Diesel price index to act as a reference for transport projects.
c) Electricity price index to act as a reference for hydrogen to electricity projects.
To ensure that there is a transparent comparison between projects using different reference prices, bids should be assessed on the basis of the spread between the opening strike price and the opening reference price (henceforth “the spread”). The advantages of having three different reference prices are as follows:
a) A universal, transparent reference price for all projects serving the same markets, whilst at the same time enabling projects to compete based on the amount of subsidy they require per MWh of hydrogen (or spread). This will mean that CfD bids are assessed on a like-for-like basis and that the best projects which require the least subsidy (or spread) succeed in the process;
b) Greater simplicity and reduced reporting/reconciliation, as opposed to a sales reference price which would otherwise require each project’s commercials to be audited and verified; and,
c) Provides an incentive for end users to switch because the reference price is directly linked to the fuel that they are switching away from.
A real, comparative example of how this would work is:
1) Project Option 1 is designed to use hydrogen for an industrial combustion process. To be financially viable, the project requires total revenue equivalent to £0.15 per kWh of energy sales. The reference price for this application is £0.03 per kWh (the gas price) and therefore the opening spread is £0.12. This project would therefore bid £0.12 per kWh and tie to the Gas Price reference.
2) Project Option 2 is creating hydrogen for use as a transport fuel. Given the higher capital investment, this project requires revenues equivalent to £0.20 per kWh. The reference price for this application is £0.10 per kWh (the diesel price) and therefore the opening spread is £0.10. This project would therefore bid £0.10 per kWh and tie to the Diesel Price reference.
In this scenario Project Option 2 would be the preferred bidder.
Other key issues
If the objective is creation of a significant hydrogen production sector, we believe that grid electrolysis has a number of advantages, as discussed above. These include the ability to site production close to demand, and could be deployed at significant scale. Facilitating this would offer the best support for investment for Scottish projects; if not allowed, even on a regional basis, other more expensive forms of production will inevitably fill the gap.
Further, the level of constraints in Scotland is likely to dwarf the growth of hydrogen production, with more than 25GW of new offshore wind capacity either in development or leasing, and significant levels of new onshore wind and solar development. As such, projects targeting the use of power output which would otherwise be constrained – i.e., wasted – are extremely unlikely to create a driver for additional high carbon generation, rather they would promote better use of existing generation capacity.
In addition to the introduction of support for hydrogen, we believe there are steps that government can and should take specifically to reduce the costs of production of green hydrogen. The most obvious recommendation is to remove Final Consumption Levies (FCLs) from the costs of electricity inputs to electrolysis, as is already the case for electricity storage projects and Energy Intensive Users. This would reduce energy input costs for liable projects by at least 30% and significantly reduce the cost differential between green hydrogen and blue; indeed, it would make no sense for grid-connected electrolysis to pay Final Consumption Levies when blue hydrogen would not.
If FCLs are not removed from grid-connected electrolysis projects accessing the proposed business model for hydrogen production, a significant proportion of the revenue support for any grid-connected project will merely go to meeting the costs associated with funding Contracts for Difference (CFDs), the Renewables Obligation (RO), and the Feed in Tariff (FIT). We would argue that it makes no sense for government to introduce a new subsidy to allow developers to meet the costs of existing subsidies in other parts of the market.
Question 4 - What infrastructure, and investment in infrastructure, is needed for green hydrogen to be easily available for heavy transport and buses across the whole of Scotland?
In the short-term, it appears most likely that hydrogen will be produced and stored at re-fuelling depots for both heavy and public transport. This again reinforces the advantages of grid-connected projects being eligible for financial support, given that it is unlikely that there will be significant renewable energy resources available at these locations, meaning the only viable electrical input for electrolysis will be from the grid.
Longer-term, if parts or the entirety of the gas distribution or transmission networks are re-purposed to carry hydrogen, then this will, clearly, offer an alternative to on-site production.
Question 5 - What role should the oil and gas industry play in achieving a “just transition” to blue and green hydrogen in Scotland?
No comment.
Question 6 - What training is required to build a hydrogen-ready workforce in Scotland? What is the long-term sustainability of the Scottish workforce for hydrogen power?
While it is difficult to be definitive at this stage, at the very least we will require companies and personnel with the skills required to manage the operation of hydrogen production and distribution infrastructure, and any transport or other machinery switching from gas or other fuels to hydrogen.
March 2022