Notice

HAR2 clarification questions (updated 9 April 2024)

Updated 9 April 2024

Clarification questions (added 9 April 2024)

Q028(a): Our company is an SME. Will that be viewed positively in itself for the assessment of section 7.2.2 “New Entrants and SME”?

This element of the economic benefits and supply chain development criterion is about assessing how Projects identify and promote new entrants and SMEs into supply chains through their projects. The focus is not on whether the proposed project itself is led by a SME.

Q028(b): For section 7.1 “Economic benefits”: In the case of two different equipment suppliers (one from the UK, one from outside of the UK) being capable of supplying within the stated project delivery timelines and a final decision has not been made, which one should be chosen for the answer of this section? The application guidance makes it sound as if it would benefit the application to choose the UK supplier, although that decision might not have been taken yet. On the other hand, this might be reductive to the supply chain resilience efforts that have been underway and led to two equipment suppliers being brought forward.

It is up to the project to assess which is the most likely supplier choice and reflect that in the application. It is important to note that the selection of a supplier may also have an impact on scoring in respect of other evaluation criteria, such as Cost and other elements of the Economic Benefits and Supply Chain Development criterion. The Government has an open market policy with respect to the Second Hydrogen Allocation Round so that suppliers from other countries should not be discriminated against. It is therefore not the case that a project with a higher proportion of CAPEX coming from UK suppliers will be directly allocated a higher score for the economic benefits proportion of the Economic Benefits and Supply Chain Development criterion. Scores for this criterion instead will be based on the economic benefits estimated to be generated by the jobs supported by a project, and the economic benefits will vary based on the region of the UK where those jobs are located. We expect that all applicants should be able to demonstrate economic benefits due to projects being located in the UK, and this accounting for a significant proportion of their jobs. 

Q028(c): Expenditure incurred before the LCHA contract award is not eligible for support under the LCHA, for example potentially significant DEVEX. Will differences in the priorly incurred expenses between projects be reflected in the assumed project IRR during the strike price negotiation phase after shortlisting?

Services costs incurred prior to contract award (e.g. pre-FEED, other DEVEX) are ineligible for support under HPBM. IRR will reflect each project’s individual risk profile and will be for projects to determine however it should not include any ineligible costs. Projects that reach the negotiations stage will be required to submit a best and final offer that includes an IRR. This should be an IRR which makes the project commercially viable and which the project can stand behind. However, whilst HAR2 is a not a purely cost competitive round, projects with a higher IRR may look less competitive than other projects. DESNZ is looking for risk to be shared appropriately between the project and government, and projects which seek to pass most or all of their risk onto government are unlikely to be seen as representing value for money and therefore risk not getting an award.

Q028(d): Could you please elaborate on the classification of allowable and disallowable capital for the purpose of the strike price negotiation after shortlisting. Will equipment CAPEX essential to the functioning of an HPF, e.g., compressors or storage units, be deemed allowable capital if it is linked to the requirements of the offtaker?

CAPEX for compression equipment and storage units located at the hydrogen production facility are both allowable cost categories and eligible to be funded through the strike price. However, we would strongly recommend that projects consider whether they can pass costs linked to the requirements of their offtakers (e.g. compression required above the output of the production system, additional storage capacity) onto their offtakers, rather than load these costs onto the strike price, especially in cases where higher cost fuels are being displaced (e.g. diesel). CAPEX for compression equipment and storage units at offtaker facilities are not eligible to be funded through the strike price.

Q028(e): Do applications need to evidence that the end customer has a commercially viable and widely available technology (at TRL 7 or above) for the use of the hydrogen? If so, how does this fit alongside fuel cell HGVs and other early stage commercialisation solutions?

There are not requirements on the TRL of end-user technologies. The robustness of project’s offtaker plans will however be scrutinised, including the technical and commercial viability of offtakers being able to receive the specified hydrogen volumes. Please see section 5.3.2 of the application form and 3.6.2 of the application guidance for more information on how offtaker arrangements will be assessed.

Q028(f): Is it possible to submit 2 separate applications for the same project location and with the same offtaker if they differ materially in their production technology, e.g., one project concept deploys an electrolytic HPF whereas the other one relies on gas splitting producing solid carbon?

Projects should refrain from submitting speculative applications into the HAR2 application process. Projects should select their most deliverable and cost effective project via one chosen technology.

Q065: In order to achieve planning permission for the site before the deadline, we may need to change sites if complications arise. Can we change sites after HAR2 application submission as long as the site remains within the UK? How would we update DESNZ of this change?

Such significant project or technical changes can be permitted but will be reviewed on a case-by-case basis. As a minimum, the project must remain eligible as per the eligibility criteria listed in the application guidance. The project should also remain deliverable and value for money. If significant changes are made late in the allocation process, there is a risk this may reduce the likelihood of success during final negotiations, as negotiations are informed by the data submitted throughout the due diligence stage.

Q066(a): Annex A, sheet “Offtaker Details” Row 19 asks for the notice that offtakers expect to receive of failure to supply. Is this notice period in regards to notice before a failure to supply or after a failure to supply?

This question aims to gauge offtaker resilience in the event of a supply outage. It asks for a theoretical notice period an offtaker would require ahead of a supply failure event in order to maintain continuity of operations (e.g. time needed to switch back from hydrogen to natural gas). Short notice periods would indicate an offtaker’s relative resilience to supply outages (i.e. ability to switch to alternative sources easily). Please explain where offtakers have no viable alternatives to their primary hydrogen supplier. 

Q066(b): Annex A, sheet “Production Facility” cell D92 calculates the plant BOL efficiency by dividing the plant production capacity by the total plant electricity capacity in cell D23. However, in theory, the total plant electricity capacity would include peak BoP loads, which is not representative of the “average” plant electricity capacity. Hence, the plant BOL efficiency will be underestimated as it assumes that all BoP loads will run on maximum load, independent off how much hydrogen is actually being produced. For additional context and as (only one) example, this way of calculating seems right for the electrolyser system efficiency as this system’s load correlates directly with the volume of hydrogen produced. However, BoP items, such as additional compressors at refuelling stations will not be deployed with each kg produced.

This is intended to capture the ‘maximum’ and ‘nominal’ efficiency of the entire plant, to understand the total energy requirements (including downstream compression) required to produce hydrogen at the required spec for transport/offtake. The nominal, maximum efficiency of the electrolyser system is also calculated in cell D98 to understand efficiency inherent to only the production part of the process. It is understood that the efficiency calculations in the ‘Production Facility’ sheet are specific to maximum BoP load which is not necessarily representative of operational efficiency. Efficiency will also be considered with respect to total hydrogen produced relative to total electricity consumed to check the competitiveness of average efficiency and to ensure any degradation in performance is also captured.

Q067(a): 5.3.2 Offtakers: We have an industrial offtaker who is switching to hydrogen burners for their industrial processes and planning to switch a portion of their logistics fleet to hydrogen vehicles. This is therefore two different offtake sectors, but for the same offtake company. Can you confirm if we should treat this as one offtaker and limit our response to 500 words total, or can assume this is two offtakers and write 500 words each for the mobility and industrial offtakers (1,000 words total)? 

The 500 words per offtaker is a guideline to provide a maximum word count – please consider reasonable ways to lay out the required information for this offtaker (including both sectors) in under 1000 words, without unnecessary repetition. While we require responses/evidence to be comprehensive, it is important information is concisely presented.

Q067(b): 7.2.1 Supply Chain Resilience: In the Supply Chain Resilience section it says, “Use the answer to explain how your systems will work. Please create a table listing all the key components and your approach to mitigate installation and operational/ maintenance risks for each of them” – can you confirm where it mentions “systems” if this refers to the protocols and procedures in the procurement strategy, or how the physical equipment will operate from a technical perspective once installed?

This question is about processes you have in place, or plan to put in place, to mitigate risks affecting the supply of key components and associated materials. The reference to systems is in relation to these processes rather than to technical detail about how the equipment operates.

Q068(a): We note from section 3.5.9 of the HAR2 Application Guidance that applicants are to submit their fugitive hydrogen emissions risk reduction plan and annual report template. Please advise how projects that have not completed detail engineering should complete this? This requires detailed information such as the number of flanges, valves, fittings etc, a level of detail that development projects will likely be lacking at this stage.

Pre-operational projects are required to complete the Risk Reduction Plan. Sections 1 and 3 are qualitative assessments where DESNZ wishes to understand design plans and considerations to measure, monitor, and mitigate fugitive hydrogen losses.

Section 2 has a quantitative assessment to estimate (not measure) the rate of fugitive hydrogen losses. Detailed evidence is therefore not a requirement for estimating emissions. The estimate can be a high-level approximation supported with mass balances, literature studies, simulations etc. If any source of fugitive hydrogen emission is considered immaterial, applicants can fill in the relevant cell in section 2 with a zero and explain why this is considered negligible.

Q068(b): We note from section 3.5.9 of the HAR2 Application Guidance that applicants are to submit their fugitive hydrogen emissions risk reduction plan and annual report template.  How can applicants provide adequate proof of fugitive emission management (more than a framework/ guideline) when projects are in the design phase at this stage?

The fugitive hydrogen emission risk reduction annual report is an obligation for operational facilities. This report will be filled in yearly with a justification of the estimated value of fugitive hydrogen losses. Annual submissions detailing how hydrogen emissions will be minimised and decreasing fugitive hydrogen emissions year-on-year can provide adequate confidence of fugitive hydrogen emissions management.

Q069(a): The TRL selection drop down in Annex A1, tab Production Facility, cell D14 indicates TRLs from 1 - 10. The application guidance document indicates a TRL assessment from 1 - 9. Please clarify the reason for different and confirm the scale that should be used.

Please choose a TRL between 1 and 9 in Annex A. 

Q069(b): Are words in tables, table/ diagram headers, in-text referencing exempt from total Word Count?

Paragraph 5 on page 10 of the Project Application Form states, reasonable and proportionate inclusion of diagrams and simple tables will be excluded from the word count, as well as any headings and subheadings. This also applies to concise figure and table captions. As well as evidence such as links to a website source, which can be included within the specific evidence table located underneath each answer box. However please note Projects are required to submit specific, targeted evidence to support the application. Lack of evidence, poor quality evidence, or large quantities of evidence that is not directly relevant to what is sought may negatively impact the assessment of the projects. In text referencing is included in the word count and is not exempt.  

Q069(c): A mandatory risk register has been requested by DESNZ in the Application Form, but it is unclear which question points to this reference document. Could DESNZ please provide guidance here? Also, is there a standard DESNZ template for the risk register to be used by all projects noting that projects may interpret the likelihood and severity of certain risks differently? If a template is to be shared, would it be possible to issue this asap due to the upcoming submission deadline.

The risk register is relevant to section 5.2.1 of the Project Application Form.

There is no standard template. Projects are responsible for managing their own deliverables and ensuring risk is managed appropriately as the design/ project develops.

Q070: Question on the word count for a given section – you have specified that figures and tables will not count towards total word count (or headings/sub-headings), will figure captions count towards wordcount? Or are they also exempt?

Paragraph 5 on page 10 of the Project Application Form states, reasonable and proportionate inclusion of diagrams and simple tables will be excluded from the word count, as well as any headings and subheadings. This also applies to concise figure and table captions. As well as evidence such as links to a website source, which can be included within the specific evidence table located underneath each answer box. However please note Projects are required to submit specific, targeted evidence to support the application. Lack of evidence, poor quality evidence, or large quantities of evidence that is not directly relevant to what is sought may negatively impact the assessment of the projects. In text referencing is included in the word count and is not exempt.

Q071: Could we please request clarification of what sort of information and/or evidence applicants could be expected to provide to answer the following part of the application, as it is quite an open question and can be interpreted several ways:  “Details of the preventative measures that the Project is taking to ensure that equipment critical to operation is selected, integrated, constructed, and commissioned will meet the performance and reliability requirements over the lifetime of the contract”.

DESNZ would like to understand the risk assessment/ management and due diligence steps undertaken by the applicant when designing the facility, selecting equipment, and establishing supply chains, to ensure that the facility will meet the design criteria/specification and will operate as intended over the design lifetime.

Q072: I am trying to assess what the gas reference price would have been and wondered whether there’s an official data set of gas reference prices that I could access. I appreciate it is basically a monthly average of month ahead prices but want to make sure that I completely replicate the way it will be done by DESNZ. 

The Hydrogen Production Business Model (HPBM) includes a Reference Price floor, which will be the lower of the natural gas price and the Strike Price (or 1.2x the natural gas price when the hydrogen is being used for feedstock purposes). The natural gas price in the HPBM is set as the month-ahead price of the National Balancing Point (NBP) Virtual Trading Point as published on ICE Futures Europe.

Section 9.9 to 9.15 of the August 2023 Low Carbon Hydrogen Agreement (LCHA) Standard Terms & Conditions details the process that the Low Carbon Contracts Company (LCCC) will use to calculate the Reference Price floor.

Q073: Regarding the word count within each of the Application subsections, are the words within i) Headings; ii) Sub-Headings and iii) Captions for Figures / Tables included or excluded within the total word count for that subsection?

Paragraph 5 on page 10 of the Project Application Form states, reasonable and proportionate inclusion of diagrams and simple tables will be excluded from the word count, as well as any headings and subheadings. This also applies to concise figure and table captions. As well as evidence such as links to a website source, which can be included within the specific evidence table located underneath each answer box. However please note Projects are required to submit specific, targeted evidence to support the application. Lack of evidence, poor quality evidence, or large quantities of evidence that is not directly relevant to what is sought may negatively impact the assessment of the projects. In text referencing is included in the word count and is not exempt.

Q074(a): What is the latest point in the application/ negotiation process that a developer can confirm their project’s grid connection date?

As part of the application to HAR2:

• The planned date for the developer signing/accepting the grid connection/offer should be noted in cell D28 in the ‘Project Details & Timelines’ tab of the Project Datasheet.
• All key activity timelines/milestones should be shown in the submitted Project Schedule, including milestones relating to securing your grid connection, which includes timelines for signing the agreement and for the site works required up to energisation. Projects will score more favourably if such plans are credible and evidenced (e.g. a grid connection offer from the DNO).

Throughout the HAR2 process, deliverability will continue to be assessed, which includes progress-to-date and the credibility of plans to secure all necessary elements of the project (including required electrical connections).

Q074(b): If a project is shortlisted with a grid connection for a certain capacity and the developer subsequently secures an increased grid connection capacity, can this be accommodated during the negotiation process or is the project tied to the capacity submitted in the original application?

To be judged as deliverable throughout the HAR2 process, projects must show they have credible plans and are making sufficient progress towards securing an electricity connection(s) that can meet the plant’s nominal maximum electricity capacity. Projects would be allowed to oversize their grid connection, but added costs for extra capacity above the plant’s capacity would not be eligible for subsidy for this project.

Changes to the plant’s capacity during negotiations would be a significant technical change. Such significant project or technical changes can be permitted but will be reviewed on a case-by-case basis. As a minimum, the project must remain eligible as per the eligibility criteria listed in the assessment guidance. The project should also remain deliverable and value for money. If significant changes are made late in the allocation process, there is a risk this may reduce the likelihood of success during final negotiations, as negotiations are informed by data submitted throughout due diligence.

Q074(c): Will green hydrogen produced as a feedstock for Sustainable Aviation Fuel (SAF) production qualify for hydrogen business model funding?

For HAR2, any offtaker of low carbon hydrogen is a “qualifying offtaker” except where:

• their planned end-use of the hydrogen is for hydrogen blending into the gas distribution and/or transmission network,
• the hydrogen is to be exported, and/or
• the offtaker is a risk-taking intermediary. For the purpose of determining eligibility, a risk-taking intermediary is defined as a person that purchases hydrogen for the purpose of resale.

The Low Carbon Hydrogen Agreement (LCHA) currently allows producers to claim subsidy for sales of hydrogen to feedstock users. However, these sales will be subject to an alternative floor price, which is currently the natural gas price multiplied by 1.2.

The LCHA prohibits hydrogen producers from receiving any subsidy in relation to the costs of their project, other than Hydrogen Production Business Model (HPBM) support and specific exemptions. Exemptions include the Renewable Transport Fuel Obligation (RTFO), noting that “Qualifying offtakers” cannot claim the total invoiced volumes which are qualifying volumes of hydrogen under the Renewable Transport Fuel Obligation (RTFO) Scheme.

The Department for Transport consulted on the UK Sustainable Aviation Fuel (SAF) Mandate in 2023 where it was proposed that rules on multiple incentives would align with the RTFO as close as possible. Officials are developing the government response to the consultation which will confirm how government will proceed. The government response will be published in Spring 2024. Whilst the SAF mandate is under development, we cannot comment on treatment of the mandate under the LCHA.

Q074(d): Will green hydrogen produced as a feedstock for e-methanol production – both for use in industry and as a fuel for shipping – qualify for hydrogen business model funding?

For HAR2, any offtaker of low carbon hydrogen is a “qualifying offtaker” except where:

• their planned end-use of the hydrogen is for hydrogen blending into the gas distribution and/or transmission network,
• the hydrogen is to be exported, and/or
• the offtaker is a risk-taking intermediary. For the purpose of determining eligibility, a risk-taking intermediary is defined as a person that purchases hydrogen for the purpose of resale.

The Low Carbon Hydrogen Agreement (LCHA) currently allows producers to claim subsidy for sales of hydrogen to feedstock users. However, these sales will be subject to an alternative floor price, which is currently the natural gas price multiplied by 1.2.

The LCHA prohibits hydrogen producers from receiving any subsidy in relation to the costs of their project, other than HPBM support and specific exemptions. Exemptions include the Renewable Transport Fuel Obligation (RTFO), noting that “Qualifying offtakers” cannot claim the total invoiced volumes which are qualifying volumes of hydrogen under the Renewable Transport Fuel Obligation (RTFO) Scheme.

Q074(e): If TNUoS charging bands were to change during the contract period of an agreed LCHA for a successful HAR2 project, would that be classified as a Qualified Change In Law (QCIL) that would entitle the developer to an adjustment in the Strike Price – for example, if the new banding methodology resulted in an increased demand residual charge to the electrolyser?

The British Industry Supercharger, announced in February 2023, is a package of targeted measures to support eligible Energy Intensive Industries (EIIs) with the costs of their electricity bills. The expectation is that the British Industry Supercharger will be rolled out between April 2024 and April 2025. It is designed to support eligible EIIs with three policy costs which are put on bills. The three elements are:

• 100% exemption for the indirect costs of renewable energy policies (the Contracts for Difference, Renewables Obligation and Small-Scale Feed In Tariffs);
• 100% exemption for the capacity market costs; and
• 60% exemption for network costs

Network charges for electricity (TNUoS, BSUoS and DUoS) are eligible to be included in a project’s strike price. Applying the ‘no better, no worse’ principle, an “EII Network Charges Compensation Change in Law” (i.e. a CiL which results in Electricity Suppliers being compensated for their TNUoS, BSUoS and DUoS charges) has been included in the Low Carbon Hydrogen Agreement (LCHA) as a specific type of QCiL.

Section 42 of the LCHA sets out the process used to determine whether a QCiL has occurred and the implications of this. Condition 43 sets out the process to be followed to calculate the appropriate level of QCiL Compensation in the event of a QCiL, which would include assessing the costs and/or savings that a project incurs/realises as a direct result of a QCiL. 

Should there be unforeseeable changes in law, a producer may be able to seek compensation through other Qualifying Change in Law (QCiL) provisions in the LCHA, should this meet relevant criteria.

Q075: We are progressing a HAR 2 application with an offtaker who wishes to decarbonise their existing natural gas usage using low carbon hydrogen. The offtaker currently uses natural gas in a CHP unit to generate heat and power for use entirely in their own operations. We understand this is eligible having reviewed the eligibility criteria and clarifying questions; please can you confirm this is an acceptable use case for low carbon hydrogen in HAR 2?

The remainder of the low carbon hydrogen produced in the scheme is proposed for use instead of LPG and natural gas for heating in other facilities.

For HAR2, any offtaker of low carbon hydrogen is a “qualifying offtaker” except where:

• their planned end-use of the hydrogen is for hydrogen blending into the gas distribution and/or transmission network,
• the hydrogen is to be exported, and/or
• the offtaker is a risk-taking intermediary. For the purpose of determining eligibility, a risk-taking intermediary is defined as a person that purchases hydrogen for the purpose of resale.

Accordingly, the offtaker you have described appears to be eligible, so long as the hydrogen produced is being sold directly to the offtaker and not via a risk-taking intermediary.

Q076: Do DESNZ have any obligations to keep our external agreements with counterparties confidential, particularly where they are commercially sensitive? Or is there any FoI risk?

Our offtakers would like some reassurances around confidential commercial information and whether this could be in the public domain if subject to FoIs.

DESNZ will not publish the submitted application or any commercially sensitive information.

Information submitted by applicants will be saved on secure servers with controlled access, meaning only allocated assessors will be able to view the information. Every assessor will receive training on how to securely handle all project information.

The directorate responsible for HAR2 does receive Freedom of Information requests (FOI), but as they normally pertain to Hydrogen, they are predominantly dealt with under Environmental Information Regulations, similar to FOIs. This provides exceptions in which we can withhold information. One such exception states:

• Confidentiality of commercial or industrial information where such confidentiality is provided by law to protect a legitimate economic interest – regulation 12(5)(e).

Organisations can apply this exception, to withhold information, if the information is commercial or industrial in nature, the confidentiality is protecting legitimate economic interest or if disclosure would adversely affect confidentiality.

Q077: Where can we access the gas price that will be used as the gas reference price when comparing strike price, reference price, achieved sales price etc?

Is there a table published monthly with the gas price and does it have historical figures?

The Hydrogen Production Business Model (HPBM) includes a Reference Price floor, which will be the lower of the natural gas price and the Strike Price (or 1.2x the natural gas price when the hydrogen is being used for feedstock purposes). The natural gas price in the HPBM is set as the month-ahead price of the National Balancing Point (NBP) Virtual Trading Point as published on ICE Futures Europe.

Section 9.9 to 9.15 of the August 2023 Low Carbon Hydrogen Agreement (LCHA) Standard Terms & Conditions details the process that the Low Carbon Contracts Company (LCCC) will use to calculate the Reference Price floor.

Q078(a): Eligible Infrastructure

HAR2 Application Guidance states that support through the HPBM may include revenue support for limited hydrogen transport infrastructure. One of our projects will include compression and filling infrastructure that is necessary to accommodate the export of hydrogen via tube trailers. Will this compression and filling infrastructure be eligible for support under the LCHA?

CAPEX for compression equipment at the hydrogen production site is eligible to be included in the strike price. Strike price calculations will be subject to the cost assurance and value for money assessments during the negotiations. As such, we would strongly recommend that projects looking to compress to higher pressures consider whether they can pass any of these costs through to their offtakers, rather than load these costs onto the strike price, especially in cases where higher cost fuels are being displaced (e.g. diesel). CAPEX for compression equipment at offtaker facilities is not eligible. Please note that for HAR2, we may make some updates to the Low Carbon Hydrogen Agreement (LCHA) to reflect policy changes and intend to engage with industry in due course. Please also note that volumes of hydrogen exported for use outside the UK are not eligible for revenue support under the Hydrogen Production Business Model.

Q078(b): Document Uploads

Within the HAR Application Portal, Part 2 Section B Document Uploads has several separate areas for uploading documents, and in some cases, this goes on to compartmentalise down into the various sections from within the Application Form (e.g. Section 4 Project Summary, and Section 5 Deliverability, both have separate upload buttons). If a piece of supporting documentation is relevant to several sections of the Application Form, should that same piece of evidence be uploaded multiple times to each of the separate areas where it has been referenced?

If a piece of supporting documentation is relevant to several sections of the Project Application Form, please only upload it once in the first section that it was referenced but make it clear in the Reference Matrix all the sections that it is relevant to. One piece of evidence should not be duplicated and uploaded multiple times to each section.

Q079(a): Please can you clarify what would be considered suitable evidence where project capex is via balance sheet of applicant?

A letter of support from the investor would be considered acceptable evidence of balance sheet financing.

Q079(b): Can you provide some guidance on the volume of detail to be provided as evidence as this could potentially be a huge number of files.  For example, we have five quotes for a particular package, do you wish to see all quotes or just the selected supplier?

Projects are required to submit specific and targeted evidence to support their application. As a minimum this must include the mandatory evidence outlined in the application form. The quality of evidence is critical in reviewing the application. Lack of evidence, poor quality evidence, or large quantities of evidence that isn’t directly relevant to what is sought in the evaluation criteria may negatively impact the assessment of the projects. However, if multiple documents support an applicant’s narrative, enhance credibility of claims, or provide insight into the robustness of governance and/or decision-making processes, etc., these may add additional value. If large documents are required and submitted, please ensure specific pages or sections are referenced within the relevant sections of the application form, to make clear which answers the document is supporting.

Q080: We understand that the cost of ancillary services is ineligible in the strike price. However, if on-site liquefaction is necessary to enable the storage and transport of the fuel over long distances, can liquefaction costs be included in storage and transport CAPEX and thus be an eligible cost according to limb (d) on page 19 of the HPBM Head of Terms?

As liquefaction may be used to facilitate storage and the delivery of hydrogen to offtakers, the CAPEX costs are eligible for support under the Low Carbon Hydrogen Agreement (LCHA). However, note that in relation to costs associated with hydrogen transport and storage infrastructure, whether or not they will be included in the Strike Price, will be negotiated on a project-by-project basis by taking several factors into account including necessity, affordability and value for money for Government. Projects should consider the cost impact of such methods and the impact on overall competitiveness.

Q081(a): The application guidance states (paragraph 3.6.3) that services costs incurred prior to contract award, for example pre-FEED and other devex costs, are ineligible for support. Does that apply to the costs of planning, feasibility and other internal resources incurred before contract award, in order to develop the project? Are any FEED costs incurred prior to contract award eligible?

Support will only be provided in accordance with the provisions of the Low Carbon Hydrogen Agreement (LCHA) after negotiations have been completed and contracts are signed. Government will not be responsible for, nor make any commitment in respect of, development costs (i.e pre-FEED and FEED costs) that are incurred prior to the Agreement Date.

Q081(b): Are decommissioning costs eligible for support and if so where are they included in the Annex A Project Datasheet?

The support a Producer receives under the Hydrogen Production Business Model (HPBM) reflects their need to cover their fixed and variable costs of production, financing costs, and an equity return. Decomissioning costs are not eligible for HPBM support.   

Q081(c): The Above Ground Static Storage section in the Capex tab of the Annex A Project Datasheet does not include a cell to include Compression Costs.  This appears to be an omission, as most projects will need to store at pressures above 30 – 40 bar and to do so will require compression.  Where shall we put these costs in the Annex A Project Datasheet?

Please provide the total cost of the storage system, including compression costs, in rows 40 or 41 as appropriate and use the comments section to provide a more granular cost breakdown.

Q081(d): Will the cost assessment process take into account the level of contingency included in capex estimates to ensure consistency when comparing relative cost effectiveness across projects – that is, not penalising a submission which makes a larger contingency provision?

We expect all projects to include some level of contingency in their CAPEX cost estimates. The cost assessment process will use project CAPEX cost data inclusive of contingency. It is for projects to decide the level of contingency that will accurately reflect their likely cost.

Projects are encouraged to provide as accurate and robust information as possible, as the credibility of the figures provided and quality of supporting evidence will affect the score received by a project. This is to ensure projects do not score more highly by falsely understating their costs.

Q081(e): From HAR1 experience, what period of elapsed time should we include in our delivery schedule between these two key events: ‘DESNZ confirming BAFO acceptable’ and ‘Hydrogen producer Signing LCHA’?

We intend to provide an update on timelines for shortlisted projects at the Agreeing an Offer stage, including contract award.

Q081(f): For Wider Electricity System Benefits question 8.2, the project location is the only information to be provided. However the guidance states that projects which locate behind common network constraints will score most highly. It will not be possible to assess this just from the project location. Should we provide additional network constraints information elsewhere in the application form or the Annex A Project Datasheet?

The electricity network constraints score will be determined using the map developed by DESNZ with National Grid ESO. As set out in the HAR2 Application Guidance, the map scoring is based on estimated curtailed electricity volumes from constraints analysis. GB regions will be scored proportionately to the amount of curtailed electricity in each region, so constrained regions will score much more favourably than unconstrained regions on location. Whilst we recognise all GB regions will experience network constraints to some extent, projects that locate in regions behind the most common networks constraints will have the most significant positive impact on the electricity network. No further information is needed beyond the project location, which will be used to assign a score.

Q082(a): The developer is to make significant investments in either compressed gas transportation or liquefaction facilities to commoditise and deliver the hydrogen to off-takers.  In the absence of Transmission blending, these facilities are not ancillary and are fundamental to creating a vendible Hydrogen stream.  Please confirm whether such costs are eligible for support under the LCHA.

As compression and liquefaction may be used to facilitate the delivery of hydrogen to offtakers, the costs of both are eligible for support under the Low Carbon Hydrogen Agreement (LCHA). However, note that in relation to costs associated with hydrogen transport and storage infrastructure, whether or not they will be included in the Strike Price, will be negotiated on a project-by-project basis by taking several factors into account including necessity, affordability and value for money for Government. Projects should consider the cost impact of such methods and the impact on overall competitiveness.

Q082(b): Will the shortlisting for HAR2 only refer to the project name (and not detail the offtake approach) as was done for HAR1.

We intend to publish the names of shortlisted projects similarly to HAR1, and not detail the offtake approach.

Q083(a): In Annex A, there is a section where we have to input data yearly, please clarify whether this is Calendar Year or Fiscal Year.

All annual data is to be provided in calendar years.

Q083(b): We are discussing potential CAPEX subsidy with a certain government for the project and expect to know the result whether to be granted and amount as well after application submission for HAR2. In this case, how we can explain this in the HAR2 application document, especially in Annex A?

Please include this information in the “Funding Sources” section of the “Funding Sources & IRR” tab. Use the comments section and the relevant parts of the application form to explain the details of this funding arrangement, highlighting if this is a non-UK source, and to provide information on the estimated amount. 

Q084: In submitting our HAR2 application, we will be sharing a considerable amount of commercially sensitive information with DESNZ.  We would normally expect to have signed some form of a non-disclosure agreement (NDA) ahead of sharing such information.  Is DESNZ able to share its standard NDA template with prospective bidders?  If no such NDA is available, would DESNZ be willing to enter a standard NDA with prospective bidders?  If no such NDA is contemplated, what assurances can DESNZ provide that the information that we share as part of our application will remain strictly confidential?

DESNZ will not publish the submitted application or any commercially sensitive information. It is expected that details of support offered for Projects, such as public descriptions and amounts, may be published following the completion of the Agreeing an Offer stage and awards.

DESNZ does not think NDAs are necessary as DESNZ considers its privacy notice and the information about the use of Projects’ data in our Application Guidance sufficient to protect Projects and their data.

Government may also share information provided by Projects (including information within the Submissions or EOIs) with other parts of government for the purposes of policy development and facilitating coordination in certain areas if relevant. In addition, this information may be aggregated and anonymised for the purposes of engagement with external audiences.

Government will also follow all applicable data protection laws in how it treats your personal information.

Q085: We note that the guidance for both the Hydrogen Volumes & Prices tab and the Electricity Volumes & Prices tab of Annex A1 state that “Information….must only be provided over the expected duration of the Low Carbon Hydrogen Agreement (15 years from COD). Including costs or volumes beyond this date may make your project look more costly than it is”. Our (Target) COD is part way through a calendar year.  In detailing these volumes and prices, do we include this data for the 16 calendar years covered by our 15-year LCHA or just the first 15 calendar years?

Hydrogen and electricity volume data provided should accurately reflect the expected production and consumption levels over the duration of the contract. Where required, please include electricity price data for the additional calendar year and adjust volumes for the first/last contract year where these do not cover the full calendar year.

Q086: Regarding Annex 1 Project Datasheet, the CAPEX sheet requires the cost per item including contingency as well as the contingency percentage. However, the OPEX sheet seems to be structured differently and only requires you enter the cost of the item as well as the level of certainty. It is not clear whether this cost should be the total cost (including contingency) or whether this should be the base cost with the contingency added.

In the OPEX sheet, this should include the base cost only without added contingency, based on the OPEX assumptions taken. Only CAPEX line items require inclusion of contingency in the cost provided, reflecting the CAPEX cost classification for each item.

Q087: In Annex A1, Worksheet ‘H2 Volumes & Sales Price,’ Row 12 – is load factor calculated using DESNZ hidden formula and terminology meant to be a) just load factor, or b) load factor % * plant availability %?

We’d expect it to be (a), but at present the formula appears to calculate (b). e.g. if row 10 production data is already after consideration of load factor (as we define it) 95% and plant availability 90%, then row 12 calculates “load factor” as 85.5% (95% * 90%) instead of 95%.

We can’t edit or see the full formula background to row 12 output.

As a workaround we tried grossing up the H2 produced in row 10 by the plant availability % - to show production pre plant availability and then report load factor as expected in row 12 which solves load factor % issue to then report at 95%, but then creates other issues:

1. Row 10 data then isn’t actually the H2 produced, as doesn’t consider availability/maintenance and so it too high.
2. Row 17 then reports storage vols based on the plant availability impact, which is not correct.

Please can you let us know if it’s a template issue with load factor/hours of operation formula, or just a difference in terminology as to what we each call load factor.

In this case, row 12 is intended to be option b) as you have described. To clarify:

Row 10 should consider the real expected production from the facility. This should consider both the electricity supply profile (the load factor) and expected maintenance downtime (the availability).

Row 12 therefore intends to reflect the actual annual H2 production relative to the annual production if operating at maximum capacity for the full year, based on the production capacity figure in cell D96 of the ‘Production Facility’ tab.

In the ‘Production Facility’ tab, please refer to row 103 to specify your plant availability separately.

QES39: Given that the delivery window for projects is 31st March 2026 – 2029 and projects will be at different stages of definition reflective of their COD date, how is DESNZ going to account for this when assessing applications?

The application guidance has consistently stated that shortlisted projects are expected to be at an advanced stage of FEED. At the application stage, DESNZ will evaluate the credibility of the project’s plans for reaching a minimum level of engineering design progress by the ‘agreeing an offer stage’ of HAR2. This minimum threshold is set at a level of definition that is reasonable to ensure due diligence and negotiations can be performed more effectively. Project’s plans will be evaluated against this pass/ fail threshold first, before being able to progress to an assessment of deliverability.

During the assessment of applications, projects will be scored on how robust and realistic their schedule is relative to their stage of development and projected COD. While there is a wide delivery window to cater for different project types/sizes, DESNZ expects all shortlisted projects to evidence they will be able to meet the maturity threshold by the ‘agreeing an offer’ stage, to ensure more effective due diligence and negotiations.

QES40: What minimum level of project definition (e.g. feasibility, Pre-FEED, FEED) is expected from projects on application submission and then at each stage of the process; shortlisting, negotiation and agreeing an offer?

The application guidance has consistently stated that shortlisted projects are expected to be at an advanced stage of FEED. At the application stage, DESNZ will evaluate the credibility of the project’s plans for reaching a minimum level of engineering design progress by the ‘agreeing an offer stage’ of HAR2. This minimum threshold is set at a level of definition that is reasonable to ensure due diligence and negotiations can be performed more effectively. Project’s plans will be evaluated against this pass/fail threshold first, before being able to progress to an assessment of deliverability.

During the assessment of applications, projects will be scored on how robust and realistic their schedule is relative to their stage of development and projected COD. While there is a wide delivery window to cater for different project types/ sizes, DESNZ expects all shortlisted projects to evidence they will be able to meet the maturity threshold by the ‘agreeing an offer’ stage, to ensure more effective due diligence and negotiations.

Clarification questions (added 21 March 2024)

Q042: In Annex A you ask for Date of Water Connection Offer Signature & Date of Grid Connection Offer Signature - are you asking for the date the agreement will provide the water/electricity or the date the document was signed? If the latter, your form does not give the ability to select the dates we need in the past.

Thank you for identifying an issue in the Project Datasheet templates. We have now updated these templates to give the ability to select past dates. Please select the agreement signature date from the dropdown.

Q058(a): Section 8.1 in the application form alludes to the fact that the ability to participate in the balancing mechanism is seen positively. However, potential future curtailment volumes and balancing mechanism bid outcomes are unknown and thus the volume of additional MWhs is also uncertain. How do you assess these potential volumes to calculate the share of additional power sourced?

It is correct that different sources of excess electricity that would otherwise have led to curtailment can be treated as additional, including from the balancing mechanism and from specific generation assets.

To demonstrate additionality for curtailment from specific generation assets, the project must provide evidence that the specific generation asset is forecast to be curtailed in the future (including forecast curtailment volumes over time), and that the hydrogen production facility can use this electricity e.g. they are co-located via private wire with the assets and/or there is an indicative PPA in place.

For balancing mechanism curtailment, evidence is needed to demonstrate the hydrogen production facility has the ability or is planning to have the ability to operate in the balancing mechanism, including projected volumes expected to be procured in this way. This will need to be evidenced via an electricity procurement plan.

Q058(b): For the eligibility part of the application, you are referencing the need to evidence the ability to claim RTFCs under the ‘Access to finance’ section. To that end, as advised in the application guidance, we have provided the RTFO administrator with project concepts. However, we expect the RTFO administrator to deal with a large number of requests at this time.

In the case that we will not receive a response in time for April 19th, would the evidence of us sharing this information and requesting confirmation from the RTFC administrator be considered as sufficient evidence to prove eligibility (given that we would have followed the application guidance of requesting this information more than 1 month in advance)?

If your project relies on RTFO support from the Department for Transport, you must upload evidence that confirms that the portion of fuel being claimed against the RTFO may be eligible for RTFO support. At a minimum, this must be documentation outlining how the project meets the requirements of the RTFO. This does not have to, but can also, include evidence of early engagement with the RTFO Administrator regarding the project or a provisional letter from the RTFO Administrator outlining that the project should, in-principle, be eligible for an application for renewable transport fuel certificates (RTFCs) depending on the stage of the project.

Q058(c): Experience from HAR1 and the current version of the LCHA indicate that after shortlisting strike price exclusions might be negotiated. If we already know that we can exclude certain CAPEX items due to being able to recover costs via our offtakers, how can we indicate this positive impact on the estimated strike price of our application (in section 6 of the application form/ Annex A)? Will these strike price exclusions be taken into account at this stage of the application process given the positive impact on value for money?

In relation to eligible costs, projects should include all relevant items in their Annex A submissions. It is crucial that cost data provided in Annex A accurately reflects the proposed plant design as set out in the Deliverability section the Application Form.  

If a project is able to pass a proportion of their costs onto offtakers they should indicate this in the deliverability section of the Project Application Form and use a relevant comments section in Annex A to explain why these categories can be excluded or costs reduced.

The Achieved Sales Price in the ‘H2 Volume and Sales Price’ should be reported after deducting the Strike Price Exclusion Amount.

As stated in the application guidance, there are categories of costs that are not eligible for funding under LCHA and these must not be included in Annex A. These include:

• OPEX associated with operating and maintaining hydrogen transport infrastructure (such as pipelines or tube trailers)
• Services costs incurred prior to contract award (e.g. pre-FEED, other DEVEX)
• Indirect and direct taxes and duties, including, but not limited to:
  • VAT
  • Green levies on electricity (such as Renewables Obligation, Feed-In Tariffs, Contracts for Difference)
  • business rates
  • import duties on imported materials and equipment

We will provide further guidance on HAR2 cost eligibility, including the treatment of Strike Price Exclusions, after shortlisting.

Q059: The land for our project is not owned by us, to progress with HAR2 is an option to take the land provided we are successful in receiving funding for HAR2 acceptable or do we need a full lease agreement in place?

Please refer to the LCHA for contractual requirements/ milestones. Projects will need to demonstrate to DESNZ that their project, as planned, is deliverable within the required timeframes.

This includes providing a reasonable level of assurance to DESNZ (with evidence if available) that the project will be able to secure the land required for their site.

Q060(a): What is the level of detail required for Level 2/ Level 3 project plan? Would it be possible for the government’s definition to be provided?

A level 3 schedule should provide durations and sequencing of all major activities for each of the project phases, for example,

1. All major project milestones, for example, FID, COD etc.
   
2. Major project phases, for example, feasibility design, consenting, detailed engineering, procurement, construction, commissioning.
   
3. Major delivery activities required to deliver the above phases. For examples, for consenting, this would include, pre application consultation, surveys, planning statement preparation, determination period.

Applicants should provide at least a level 2 schedule. However, if applicants have developed the next level down (level 3), they are encouraged to submit this to demonstrate further robustness in their delivery plan.

Q060(b): What level of detail is required for the design intent document?

Projects are responsible for managing their own deliverables as their design develops.

Please refer to the application form and guidance to understand the information required for each criterion. Please supply evidence where possible to substantiate the information provided in your response. Please see Section 5.3 of the Project Application Form and Section 3.6.2 of the Application Guidance for information on the design intent document.

Q060(c): Will the names of applicants (including unsuccessful applicants) to the process ever be published and if so, when?

We intend to publish the names of shortlisted projects who will be invited to the agreeing an offer stage in Autumn 2024 and successful projects to be offered contracts from early 2025. We do not intend to publish the names of unsuccessful applicants. Please note these dates are indicative, and government reserves the right to alter these at any stage in the process.

Q060(d): How confidential are the applications and would details ever be accessible through Freedom of Information Act requests? Is there an option to submit commercially sensitive information as evidence and ensure that it could never be accessed through an FOI request?

Information submitted by applicants will be saved on secure servers with controlled access, meaning only allocated assessors will be able to view the information.  Every assessor will receive training on how to securely handle all project information.

The directorate responsible for HAR2 does receive Freedom of Information requests (FOI), but as they normally pertain to Hydrogen, they are predominantly dealt with under Environmental Information Regulations, similar to FOIs.  See the Environmental Information Regulations which provides exceptions in which we can withhold information. One such exception states:

• confidentiality of commercial or industrial information where such confidentiality is provided by law to protect a legitimate economic interest – regulation 12(5)(e)

Organisations can apply this exception, to withhold information, if the information is commercial or industrial in nature, the confidentiality is protecting legitimate economic interest or if disclosure would adversely affect confidentiality.

Q060(e): When negotiating the LCHA, can we profile our sales cap over the 15 years? Having a fixed cap doesn’t allow grid-connected projects wanting to maximise use of curtailed wind to ramp up production in line with wind generation targets and constraint forecasts. Also, can we profile the Assumed Load Factor across the course of each year?

The LCHA Sales Cap is annualised (the Annual Sales Cap) for the purposes of providing annual limits on sales. This is intended to incentivise Producers to provide a relatively stable and predictable supply of hydrogen to the market.

Producers are able to move volume across the course of the LCHA with an upper annual sales limit of 125% of the Annual Sales Cap (the Permitted Annual Sales Cap) which will allow them to manage fluctuations in supply and demand.

Where Producers exceed the Permitted Annual Sales Cap in any 3 years of the contract, the LCCC will have the right, though not the obligation, to unilaterally terminate the contract.

The Assumed Load Factor is a fixed percentage across the term of the LCHA, determined from the Initial LCHA Sales Cap and the Initial Installed Capacity Estimate agreed for each project.

We may make some changes to the draft LCHA for HAR2 and will engage with industry in due course on any proposals.

Annex A Project Datasheet allows projects to report their expected hydrogen production volumes as well as electricity consumption on an annual basis. That will be the basis for the cost criterion assessment. Projects can submit supporting evidence to demonstrate how their production profiles vary over the course of each year. 

Q060(f): When the ‘Wider electricity system benefits scoring framework’ refers to the ‘demonstration of providing system benefits’, would it be helpful to provide evidence beyond the location of the plant, and use of curtailed power? For example system benefits analysis.

Evidence on wider electricity system benefits will be scored based on the factors as set out in the application guidance, focusing on the location of the hydrogen production facility and the ability to demonstrate additionality. No further information is required at this time, unless it helps to substantiate the additionality claims.

Q060(g): What level of detail is required for evidence of balancing supply and demand between the production plant and the offtakers - for example hourly profiles with storage balances?

The technical information required is in the data annex, in the relevant tabs related to storage, offtakers and offtaker volumes. The parameters of the storage should be suitable for enabling the offtake profile detailed in the annex.

Q060(h): Postcodes are required for equipment suppliers - will projects with UK suppliers score higher? How should projects balance priorities across supporting UK suppliers and delivering best value?

The government has an open market policy with respect to the Second Hydrogen Allocation Round so that suppliers from other countries should not be discriminated against. It is therefore not the case that a project with a higher proportion of CAPEX coming from UK suppliers will be directly allocated a higher score for the economic benefits proportion of the Economic Benefits and Supply Chain Development criterion. Scores for this criterion instead will be based on the economic benefits estimated to be generated by the jobs supported by a project, and the economic benefits will vary based on the region of the UK where those jobs are located. We expect that all applicants should be able to demonstrate economic benefits due to projects being located in the UK, and this accounting for a significant proportion of their jobs.

It is important to note that the selection of a supplier may also have an impact on scoring in respect of other evaluation criteria, such as Deliverability, Cost and other elements of the Economic Benefits and Supply Chain Development criterion. Deliverability criterion is weighted at 40%, the Cost criterion is weighted at 30% and the Economic Benefits and Supply Chain Development criterion is weighted at 20% of the evaluation criteria. It is for the project to decide on the optimal balance between these criteria.

Q060(i): DESNZ have stated that network charges such as TNUoS can be recovered via the strike price, but how does DESNZ expect producers to calculate the TNUoS costs for the full 15 year contract term?

Projects should provide their best estimates of the future long term network charges, including TNUoS. Projects should explain the assumptions made when estimating these costs, where relevant set out third-party sources the forecast is based on and highlight the likely level of uncertainty in relation to these estimates.

Q060(j): If the project will deliver cryogenic hydrogen to offtakers, where should Capex for liquefaction facilities be included in Annex A1?

Hydrogen Production Business Model policy, as indicated in the Heads of Terms document published in December 2022, is that costs associated with the liquefaction of hydrogen are to be considered ineligible for coverage in the Strike Price. As a general matter, where an offtaker requires hydrogen to be supplied at nonstandard or non-commodity specifications, the offtaker should bear the cost of reaching that specification.

Q061(a): Section 7.2.1, paragraph 2, states that “this question focuses on the ‘physical equipment’ that will be installed.” Following this statement, the paragraph states, “The substantiating evidence should give us confidence you have appropriate processes in place, or plan to put them in place, to deal with the risks relating to all services and equipment outlined above in section 5.2.3”. The paragraph seemingly contradicts itself, initially stating a sole focus on physical equipment but changing to both services and equipment outlined in Section 5.2.3. Could you please provide clarity on the scope of this question?

The focus is on the supply of key physical equipment. The scope does not include labour ‘directly’ employed by the project, but instead the practices of the suppliers of key equipment.

Q061(b): As outlined in the LCHA, costs will be either categorised into strike price inclusions or exclusions depending on their purpose and discussions with DESNZ. When completing ANNEX_A1 for Section 6, do you require the applicant to provide all costs associated with the production and distribution of hydrogen, or only costs associated with strike price inclusions, as assumed by the applicant? (for example, capital costs for tube trailers could be considered a strike price exclusion. Could one exclude this cost?).

The CAPEX and Non-Electricity OPEX sheets in Annex_A1 state that “You must not include any costs that are ineligible for support under the LCHA”. In other words, it is understood that anything is subject to the Strike Price Exclusion cannot be included. To align with this assumption, should the Hydrogen Sales Price column in the H2 Volume and Selling Price sheet be filled in with the Achieved Sales Price, that is, the amount after deducting the Strike Price Exclusion Amount?

In relation to eligible costs, projects should include all relevant items in their Annex A submissions. It is crucial that cost data provided in Annex A accurately reflects the proposed plant design as set out in the Deliverability section the Application Form.  

If a project is able to pass a proportion of their costs onto offtakers they should indicate this in the deliverability section of the Project Application Form and use a relevant comments section in Annex A to explain why these categories can be excluded or costs reduced.

The Achieved Sales Price in the ‘H2 Volume and Sales Price’ should be reported after deducting the Strike Price Exclusion Amount.

As stated in the application guidance, there are categories of costs that are not eligible for funding under LCHA and these must not be included in Annex A. These include:

• OPEX associated with operating and maintaining hydrogen transport infrastructure (such as pipelines or tube trailers)
• services costs incurred prior to contract award (e.g. pre-FEED, other DEVEX)
• indirect and direct taxes and duties, including, but not limited to:
  • VAT
  • green levies on electricity (such as Renewables Obligation, Feed-In Tariffs, Contracts for Difference)
  • business rates
  • import duties on imported materials and equipment

We will provide further guidance on HAR2 cost eligibility, including the treatment of Strike Price Exclusions, after shortlisting.

Q062: We note that the summary of ‘Updates to the Low Carbon Agreement’ provided to the HPBM Stakeholder Forum on 25 January 2024 indicated in the section on Initial Conditions Precedent that “The Facility description ICP has been updated to include a description of any UKLCH Electricity Storage System (being any Electricity Storage System which will be subsidised via the LCHA)”.  Is it possible to clarify whether the costs associated with the construction and / or operation of an Electricity Storage System associated with a Facility are eligible for inclusion in the Strike Price? Please can you advise how such costs (if included) should be covered in Annex A in our application?

The HPBM may subsidise an electricity storage system, with such decision made on a project-by-project basis, as agreed between DESNZ and the Producer. As such the January 2024 Front End Agreement includes provisions to account for this. Please note that we expect to provide further detail on HPBM cost eligibility in due course.

Please use the ‘Other Balance of Plant’ row in the CAPEX tab of Annex A Project Datasheet to report the associated construction costs, and ‘Other (please provide detail in comments)’ rows in the Non-Electricity OPEX tab for operating costs.

Q063: We are working on the schedules for HAR2 and would like to clarify how DESNZ will assess our choice of date for the various HAR2 timelines. We are having to estimate the expected date of these milestones due to the current vague time periods attached to each milestone in the HAR2 guidance. We are using June 2025 for when we expect the LCHA to be awarded to successful projects and aligning all the development milestones to this date. Would this be acceptable to DESNZ?

DESNZ will assess deliverability of schedules based on credibility and confidence of the Applicant to deliver to that timeline. If assumptions are made, DESNZ expect to see reasoned justification of such assumptions, similarly for impacts on critical path and other milestone tasks. The indicative timeline set out in the HAR2 application guidance states that contracts will be awarded from early 2025. Projects are expected to be able to meet LCHA milestones, however, it is not expected that the milestone dates form the basis for construction of project schedules. Projects should aim to deliver at a pace practical for them and should have sufficient float to mitigate against delivery risks.

Q064: In the Hydrogen Emissions Calculator v7 Electrolysis document from the Low Carbon Hydrogen Standard webpage. After filling out initial questions and choosing the pathway via cell E21 as Electrolysis using mixed electricity inputs. On the tab ‘Dashboard’ it states that in cell E20 ‘Pathway not chosen’ where I believe that the pathway was chosen in the ‘Initial_questions’ tab to provide the consignment GHG emissions for Hydrogen from Grid electricity.

Following the guidance there is still this error and would like to clarify if there is an error in the excel document or is there a step not shown? Or if HAR2 team could specify what input is required by the user and where in the document to update the cell E20 in ‘Dashboard’.

If Electrolysis using mixed electricity inputs pathway is selected, ‘Pathway not chosen’ will appear in the Dashboard for consignments that contribute 0% to the total hydrogen output. These rows have no impact on the GHG result.

We have published v4.8 of the Hydrogen Emissions Calculator. In this update, we have made it clearer that ‘Input electricity source not chosen’ will appear for consignments with 0% contribution rather than ‘Pathway not chosen’ when the mixed electricity input pathway is selected.

Clarification questions (added 14 March 2024)

Q029: I have a few questions relating to the project eligibility for HAR2.

1. Would gasification/pyrolysis of coal constitute an eligible production technology?

2. Could carbon capture be included? If not, why?

3. Provided that the primary applicant is a UK registered business (for example, the plant operator), and the plant is located entirely in the UK, does the production technology supplier also need to be UK-based?

Gasification/ pyrolysis of coal is not an eligible production technology. Coal is a non-renewable resource, and its gasification releases large amounts of carbon dioxide.

Gasification/ pyrolysis of biomass/ waste (without CCUS) is eligible. Biomass is considered a renewable resource, and its gasification can be low carbon when the biomass is sustainably sourced and managed. HAR2 will only support non-CCUS enabled hydrogen production. We encourage eligible projects that have access to the CCUS networks to apply for support via the Cluster Sequencing process, for Track-1 expansion or Track-2.

Q030: We have some further clarification questions set out below:

- ECB: Will applicants receive the outputs of your economic benefits model related to the project? Are you able to share the methodology used to calculate number of jobs using the information provided in the template?

- Costs: We realise there is a general expectation that the average strike price will be lower than HAR1 but NZHF upfront CAPEX support is no longer available. Could you confirm to what extent CAPEX funding support can/will be built into the strike price for HAR2?

- General: This relates to providing references to information contained within the application, that isn’t part of an evidence document. e.g. a website source. How do you want us to reference external sources and will references count towards the word count?

Economic Benefits

Assessment of the Economic Benefits criterion will follow the process outlined in section 3.6.4 of the HAR2 Application Guidance document. Scoring for the economic benefits criterion will be based on the economic benefits estimated to be generated by the jobs supported by a project. This will be evaluated using standard Green Book appraisal methods.

Costs

In HAR1, CAPEX covered by the Net Zero Hydrogen Fund (NZHF) grant was excluded from the strike price, along with any return on this proportion of the CAPEX. With no NZHF funding in HAR2, project strike prices will be estimated based on project’s full eligible capex amount and successful projects’ total eligible capex will be funded via the Hydrogen Production Business Model.

Please note that, scores for the cost criterion will be allocated on a relative basis so that a project’s score reflects its cost-effectiveness relative to other HAR2 applicants.

Eligible CAPEX cost under the draft Low Carbon Hydrogen Agreement (LCHA) include:      

• CAPEX associated with the construction and operation of the Facility
• CAPEX associated with the construction of limited hydrogen transport infrastructure
• CAPEX associated with the construction and/or operation (as applicable) of limited hydrogen storage infrastructure

However, note that in relation to CAPEX cost associated with hydrogen transport and storage infrastructure, whether or not they will be included in the Strike Price will be negotiated on a project-by-project basis by taking several factors into account including necessity, affordability and value for money for Government.

For example, CAPEX for compression equipment and storage units located at the hydrogen production facility are both allowable cost categories and eligible to be funded through the strike price. However, we would strongly recommend that projects consider whether they can pass costs linked to the requirements of their offtakers (for example compression required above the output of the production system, additional storage capacity) onto their offtakers, rather than load these costs onto the strike price, especially in cases where higher cost fuels are being displaced (such as diesel). CAPEX for compression equipment and storage units at offtaker facilities are not eligible to be funded through the strike price. Please refer to the LCHA Heads of Terms for further information. Please note that for HAR2, we may make some updates to the LCHA to reflect policy changes and intend to engage with industry in due course.

General

Paragraph 5 on page 10 states that the reference section doesn’t contribute towards the word count. Reasonable and proportionate inclusion of diagrams and simple tables will be excluded from the word counts, as well as any headings and subheadings. This also applies to evidence such as links to a website source, which can be included within the specific evidence table located underneath each answer box. However please note Projects are required to submit specific, targeted evidence to support the application. Lack of evidence, poor quality evidence, or large quantities of evidence that is not directly relevant to what is sought may negatively impact the assessment of the projects.

Q031: I am part of a UK based joint venture for the storage of liquid Hydrogen offshore and the off take into the UK electricity network.

In the first instance we will be shipping hydrogen from multiple sources into a UK port.

Would we qualify for this round of support?

The eligibility criteria for the Second Hydrogen Allocation Round (HAR2) are set out in section 3.5 of the Application Guidance. The Hydrogen Production Business Model (HPBM) is a contractual business model for hydrogen producers to incentivise the production and use of low carbon hydrogen through the provision of ongoing revenue support. We cannot confirm eligibility for support of individual projects at this stage. It is the responsibility of the project to submit an EOI and subsequently decide if they wish to submit a full application to the HAR2 process. Assessors will complete an eligibility check following submission of applications to confirm the application meets the defined eligibility criteria. Those that are considered to meet the eligibility criteria will proceed to the next stage of the allocation process set out in section 3.6 of the Application Guidance. Any Projects that are found to be ineligible will be notified in writing and will not progress to the next stage. The intention of the Hydrogen Production Business Model (HPBM) is only to support domestic low carbon hydrogen production and does not currently support the import of hydrogen.

Q032: I was wondering if you could point me in the correct direction of the equation mentioned for calculating the hydrogen production capacity. This is to ensure the project is 5MW H2 HHV (output) or higher. (Hydrogen production capacity – maximum MW of hydrogen output of the facility in high heating value terms before load factor or plant availability are taken into account).

The 5 MW H2 (HHV) production capacity threshold relates to the instantaneous, maximum nominal capacity of the plant. This will be specific to your design and expected performance of your system(s) and may be calculated in different ways. For example: a production plant capable of producing hydrogen at a maximum rate of 127 kg/h would translate to approximately 5 MW H2 (HHV) capacity.

Q033: We are unclear on what evidence is required to demonstrate that a TRL of 7 has been met. Would you be able to clarify this point please?

Projects are required to provide a relevant production technology specification and evidence to prove that at a minimum, TRL 7 ‘Integrated Pilot System Demonstrated’ has been successfully demonstrated when submitting their full application by 19 April 2024.    For example, this can be evidenced by providing a specification document outlining the hydrogen production technology type being used by the Project. Applicants can obtain this from their technology supplier. Applicants could also detail specific examples where the supplier has operated/ demonstrated the system. Assessors will complete an eligibility check following submission of applications to confirm the application meets the defined eligibility criteria. Those that are considered to meet the eligibility criteria will proceed to the next stage of the allocation process set out in section 3.6 of the Application Guidance.

Q034(a): For section 6 “Costs”, will the scoring be purely based on the derived estimated unit production cost of hydrogen or instead on the derived estimated difference amount per kg of qualifying volumes in accordance with the most recent LCHA Standard Terms and Conditions – Condition 10.1? For additional context, if HoTs or other offtake evidence indicates an achieved sales price consistently above the natural gas reference price, would that be taken into account for the scoring of section 6 “Costs”?

We will estimate each project’s costs per unit of production (MWh HHV) based on information submitted by projects in Annex A1, including data on the Total Hydrogen Produced. As per Annex A1 guidance (“H2 Volumes & Sales Prices” section): “Information provided on total production levels (row 9) must include all hydrogen output from the production facility over the lifetime of the Low Carbon Hydrogen Agreement (15 years from COD).” That includes any volumes produced and then sold to non-qualifying offtakers.

While sales price information will not directly feed into Section 6 “Cost” assessment,  we would strongly recommend that projects consider whether they can pass costs linked to the requirements of their offtakers (e.g. compression required above the output of the production system, additional storage capacity) onto their offtakers, rather than load these costs onto the strike price, especially in cases where higher cost fuels are being displaced (e.g. diesel).

Q034(b): Is an offtaker that in the past has received government support from other funding programmes, which are not HAR-related, eligible as a qualifying offtaker (for example, if an offtaker has received funding from the Advanced Fuels Fund)?

Qualifying offtakers refers to offtakers in respect of which the hydrogen sold is eligible for Hydrogen Production Business Model (HPBM) support under this allocation round, provided all other requirements are met. Any offtaker of low carbon hydrogen is a “qualifying offtaker” except where:

• their planned end-use of the hydrogen is for hydrogen blending into the gas distribution and/or transmission network
• the hydrogen is to be exported, and/or
• the offtaker is a risk-taking intermediary. For the purpose of determining eligibility, a risk-taking intermediary is defined as a person that purchases hydrogen for the purpose of resale

There are no provisions in the draft LCHA that prohibit offtakers from being in receipt of past government subsidies.

Q034(c): As a project developer with various power generation assets, that are not co-located, we have the benefit of flexibly sleeving power to different hydrogen production facilities, increasing deliverability of these hydrogen projects from our point of view. As a result, there might be an overlap in the power sources that we are looking to include in applications for different projects. However, given the likelihood that the same assessor might assess two or more of our applications, we are worried that this might implicitly lead to a penalisation in the initial application scoring due to power sources and their production being assigned to more than one hydrogen production facility. Can you clarify how you intend to make sure that the application scoring does not penalise on the grounds of portfolio factors and if you will communicate the impact of portfolio factors at the application shortlisting stage?

In principle, it is possible for the same generation assets to be assigned to different hydrogen production facilities. However, if during assessment we identify a risk that the asset may not be able to supply the volumes of electricity being claimed by multiple hydrogen production facilities (if all sites claiming the assets electricity supply were successful), we will need to factor this into the scoring. Government may conduct integration checks at the shortlisting stage, to consider if the projects are additional to one another. In this case, being additional means checking that where multiple projects are dependent on the same electricity supply these can support the combined hydrogen volumes from the individual projects. Where a conflict is identified between multiple projects at this stage, Government may choose to apply an integration score to adjust projects’ overall scores. If assurances can be provided that the asset could support all projects being claimed, this will need to be evidenced to provide assurances. The integration score will take into account several factors including: whether offtake or supply could accommodate each project, the maturity level of projects’ agreements with relevant third parties, credibility of any contingency plans and the projects’ overall scores at assessment. See Section 4 of the Application Guidance for more information on integration checks.

Q035: We represent a major business consortium looking at green ammonia (produced via solar) and cracking this to isolate pure hydrogen. We have infrastructure in place and all partners in supply chain including a downstream application of the hydrogen to methanol (via CO2 hydrogenation). Would this hydrogen production technology from this route qualify for HAR2 support?

Producing hydrogen through ammonia cracking technologies is not an eligible production method in the Second Hydrogen Allocation Round (HAR2), as the intention of the Hydrogen Production Business Model (HPBM) is only to support domestic low carbon hydrogen production, and because ammonia requires projects to have already produced or sourced the hydrogen elsewhere to then convert to ammonia it is not considered “domestic hydrogen production.” We also note that ammonia cracking has a low Technology Readiness Level (TRL) and is yet to be demonstrated at scale.

Q036: I’d welcome guidance on the availability of LCHS compliant PPA’s.  We’ve had a number of conversations with the large utilities in the UK and none of them currently have a product available that delivers cost competitive LCHS compliant power that also delivers economic electrolyser efficiency e.g. a PPA from multiple green generators types.

It would be very helpful to understand how DESNZ satisfied itself that LCHS compliant PPA’s we’re technically deliverable, economic and available in the market place.

The requirements in the UK Low Carbon Hydrogen Standard (LCHS) have been developed alongside industry engagement and consultation. As such, the requirements are designed to be deliverable for hydrogen producers. Projects which applied to the First Hydrogen Allocation Round (HAR1) have been able to secure LCHS compliant Power Purchase Agreements    to meet the requirements of the LCHS.

Q037: Please I clarify that the HAR2 competition will award successful projects with a funding of assumed strike price per kg of hydrogen, over a period of 15 years from the start of commercial production.

As an example from HAR1, if the awarded strike price is £9.4/kg (£241/MWh) for a 5T/day green hydrogen production project. Assuming no downtime, this would equate to an annual hydrogen production of 1,825T and over 15 years the cumulative production will be 27,375T. We understand that HAR2 funding award for this example case will be £17.1M per year (@ £9.4/kg), linked to the production over 15 years, from the date of commercial production.

We understand that the strike price will be competitively determined. Please can you confirm that the duration and extent of funding is correct.

Baseline level of support under the Low Carbon Hydrogen Agreement (LCHA) is determined by the interaction between the project strike price and the reference price, but there are other provisions in the LCHA that might impact the final support amount a project receives. Please see section 9 (page 141) of the draft LCHA for full payment calculation details.

The LCHA will have a contract term of 15 years, subject to early termination provisions.

Q038: Can we initially submit the application using this subsidiary’s legal entity and then later transfer (novate) the application to the final legal entity that will ultimately own the grid connection?

Yes, a project can transfer the ownership from one subsidiary to another throughout the HAR2 process, subject to successful due diligence of the entity the application is transferred to. It should be noted that this is also dependent on the timing of the transfer, and whether DESNZ have sufficient time to consider this change and conduct any additional due diligence ahead of the timelines set out for contract award.     

Q039: We understand that there will be preference given (i.e. higher score associated with) to use new/additional renewable electricity for green hydrogen production.

The renewables electricity could be from wind or solar. Please can you clarify if electricity derived from combustion (CHP engine) of biogas from new AD (anaerobic digestion) plants could be considered as new renewable electricity. The biogas is currently not being treated at all – vented to atmosphere. This new AD plant will generate electricity from what would otherwise be vented methane emissions.

The Wider System Benefits criterion seeks to incentivise additional low carbon electricity generation. The proposed generation source (biogas from AD plants in a CHP) would be considered low carbon electricity input under the UK Low Carbon Hydrogen Standard (LCHS), so if it meets the additionality principles, it may be treated as additional.

Q040: In HAR1, projects were required to achieve COD within the Target Commissioning Window which spanned from June 2026 to June 2027 (very latest for projects). Projects would be penalised should they not achieve COD within this window, and their contract would be terminated should they not achieve COD by the long stop date (June 2028).  Will the same approach be taken for HAR2 - that is, projects must achieve COD within the planned COD window (March 2026-2029), will be penalised thereafter, and will have their contract terminated if the longstop date is missed?  If so, can DESNZ confirm the longstop date or period of time after the end of the COD window when the longstop date is planned?

As set out in the HAR2 Application Guidance, projects will need to demonstrate that they can be commercially operational within one of three set delivery years between 31 March 2026 and 31 March 2029. In the context of new build hydrogen production facilities, being operational means the date the Project is confirmed to meet the relevant Operational Conditions Precedent (OCP) and the Project begins operating and is capable of producing hydrogen that will be sold to offtaker(s).

Successful applicants will agree, in the Agreeing an Offer stage, a Target Commissioning Date and Target Commissioning Window within which the project is expecting to ‘commission’ the facility and fulfil the LCHA’s Operational Conditions Precedent. The latter must be fulfilled before a Start Date can be declared and payments can commence. If the Producer has not satisfied the Operational Conditions Precedent by the end of the Target Commissioning Window, the 15-year term of the LCHA will start to erode. However, payments will not commence unless and until the Start Date occurs. The Longstop Date is the last day of a 12-month period following the final day of the Target Commissioning Window. If the Producer fails to satisfy the Operational Conditions Precedent by the Longstop Date, the LCHA Counterparty has a right to terminate the LCHA.

Q041(a): Where trailers are being leased rather than purchased, would these leasing costs be eligible costs under the HPBM?

The costs associated with specified hydrogen Transport and Storage (T&S) infrastructure in the Strike Price will be negotiated on a project-by-project basis by taking several factors into account including necessity, affordability, and value for money. Leasing costs may be considered eligible costs for inclusion in the Strike Price if the Producer can evidence (to the satisfaction of DESNZ during negotiations) that:

1. the lease term represents a significant majority (i.e. more than 75%) of the economic life of the asset being leased; and

2. as at the date of the lease, the present value of the minimum lease payments amounts to almost all (i.e. more than 90%) of the fair value of the leased asset.

We may make some updates to the draft LCHA for HAR2, including to enable support for leased transport infrastructure and will engage with industry in due course on any proposals.

Q041(b): Where a project is using pipelines to transport hydrogen to customers, would the whole length of the pipeline to the customer(s) be eligible under the HPBM?

The costs associated with specified hydrogen Transport and Storage (T&S) infrastructure in the Strike Price will be negotiated on a project-by-project basis by taking several factors into account including necessity, affordability, and value for money.

Q043: We are planning to submit an application into HAR2 for a 10MW H2 output (HHV) project.

Please can I ask if we will be able to change the H2 output, reduce to 5MW or increase to 15MW, before the HAR2 contract is awarded.

It is governments expectation that any changes to H2 output are minimal between final Application Submission and Contract Award. If changes are made between the Application Submission stage and ahead of Contract Award, Applicants should ensure:

1. The project’s capacity stays above 5MW H2 HHV;

2. The project provides a clear justification for the change and updates DESNZ on the expected impact on costs and plans; and

3. The project submits updated information as necessary for DESNZ to appraise the impact to cost and deliverability of the project.

Negotiations will be on the basis of information provided during due diligence and so any changes in capacity late in the allocation process may impact the project’s ability to negotiate and therefore be successful in being awarded a contract. Each project will be considered on a case-by-case basis and DESNZ reserves the right to accept or reject a change in project hydrogen production capacity.

Q044: Can you please clarify what you mean by a Level 3 Project Schedule?

Is there a standard or definition that you can refer to, for example RIBA level 4?

A level 3 schedule should provide durations and sequencing of all major activities for each of the project phases, for example,

1. All major project milestones, for example, FID, COD etc.

2. Major project phases, for example, feasibility design, consenting, detailed engineering, procurement, construction, commissioning.

3. Major delivery activities required to deliver the above phases. For examples, for consenting, this would include, pre application consultation, surveys, planning statement preparation, determination period.

If applicants have developed the next level down in the schedule, they are encouraged to submit this to demonstrate further robustness in the delivery plan.

Q045: Please could you clarify what is meant by “delivery supply chain” in the following description of mandatory evidence for HAR2 (deliverability):

- Engagement with the delivery supply chain, long lead equipment suppliers, electricity supplier(s), feedstock supplier(s), planning authorities and utilities

Does this mean suppliers of other equipment (excluding long lead items)? Or logistics/ equipment delivery service providers? If the latter, is this required if the equipment supplier contracts places responsibility for delivery of equipment on the supplier, so the applicant will not engage with these service providers directly?

This refers to the mandatory evidence required in for questions in section ‘5.2 Project Deliverability’ of the application form. To understand the current status of development progress, we require evidence of ‘supplier’ engagement, where available.

In this case, this ‘supplier’ refers to both equipment (key equipment in particular, but all equipment as available) and project delivery services (any delivery services spanning plant design, management, engineering, procurement, construction/ installation, commissioning), relevant to question 5.2.3. It is understood that in many cases, delivery and installation/ commissioning will be included in the equipment supplier contract and therefore these services do not need to be procured separately.  ‘Supplier’ also refers to any entities where engagement is necessary to secure all planning consents, environmental permits/ licenses and land agreements required to deliver the project, relevant to question 5.2.2.

Q046(a): A follow on question to the published response to Clarification Question QES1.

DESNZ has implied an expectation of HAR2 Strike Prices target below HAR1.

Noting NZHF is not available for HAR2 and that HAR1 Strike Price was reduced by the fact that Capex component was based on only 80% of Capex given NZHF support for remaining 20% of Capex:

- Please can DESNZ share a HAR1 average Strike Price rebased/ adjusted to exclude the NZHF impact?

- Or alternatively, please can DESNZ confirm that the different basis of the Strike Price between HAR1 and HAR2 (HAR2 Strike Price to include 100% of Capex versus only 80% of Capex in HAR1) will be factored into such comparisons.

DESNZ will not be sharing a rebased and/or adjusted strike price. However, DESNZ will consider the impact to CAPEX costs during the HAR2 process. We are committed to delivering value for money for the taxpayer and HAR1 cost data will be one of the tools we will use for understanding general cost-competitiveness of HAR2 projects, taking into account differences in project configurations.

Scores for the cost criterion will be allocated on a relative basis so that a project’s score reflects its cost-effectiveness relative to other applicants.

Q046(b): The HAR2 guidance refers readers to the Dec 22 draft HPBM heads of terms for full details on eligible and ineligible costs. This states that costs in relation to electricity storage are an ineligible cost. However, the LCHA FEA shared in January 2024 notes that Electricity Storage System may be subsidised via the LCHA as agreed between DESNZ and the Producer.

- Can you please confirm the policy position related to subsidy support for electricity storage under the LCHA.

- And, if the cost of Electricity Storage System is subsidised via the LCHA, does the use of the batteries need to be solely for hydrogen production?

The HPBM draft Heads of Terms (HOT) provided a framework for the principal terms and conditions that were expected to be included in the LCHA for initial projects and do not constitute definitive drafting of the LCHA’s terms. The HPBM may subsidise an electricity storage system, with such decision made on a project-by-project basis, as agreed between DESNZ and the Producer. As such the January 2024 Front End Agreement includes provisions to account for this. Please note that we expect to provide further detail on HPBM cost eligibility in due course.

Q046(c): The Electrolytic HEC (V4.7) found on the government website seems to contain links to DESNZ Sharepoint locations that cannot be updated. Can DESNZ please fix the issue and re-upload a working spreadsheet please?

We will publish an updated version of both the HECs (V4.8) on the UK low carbon hydrogen standard emissions reporting and sustainability criteria page soon, to fix errors relating to the links contained within the files.  Projects will be notified once the updated HEC has been published.

When saving the HEC files to your computer, ensure that the file name does not contain any spaces (for example “Copy LCHS_UK_HEC_v4.8_FULL” as this may cause errors to links within the workbooks.

Q047: I have a question relating to the LCHS and the HEC.

The LCHS is clear that if your project does not meet the theoretical 30 bar, 99.9% purity, you use the equations provided in the data annexes to calculate the electricity consumption of the compressors and purification units. However, it’s not entirely clear to us what assumption you make about where any impurities would go and how any losses of hydrogen in the PSA would be accounted for when you’re doing those theoretical calculations?

This is ‘theoretical’ compression and purification, the LCHS accounts for the most significant emissions sources only, that is, the power input to compression and purification.

As these are theoretical calculations, there are no actual tail gas streams for impurities or actual hydrogen losses occurring via these processes. There is a wide range of impurities that are possible. Therefore, the associated theoretical emissions could either be modest or a modest credit (if tail gases are sold as a coproduct), so for simplicity, DESNZ decided not to account for these aspects when calculating the theoretical burden of meeting the LCHS limits.

Any real compression and purification equipment onsite should account for the actual GHG emissions related to impurities and fugitive losses. While hydrogen is not yet accounted for as having a GWP under the LCHS, projects should minimise hydrogen losses as set out in the LCHS methodology.

Q048: On one of our partner bids, the partner has expressed their intention not to proceed.  They have advised they are happy for us to continue with the project and bid without them.  We would like to do this.

Is there a process whereby we can assume the Lead Party status on an EOI where we are currently the named party?  We would need to flip another of our EOIs so that the partner becomes the lead and we are the named party (so we are not leading on more than 6).

Applicants may change the configuration of their project set up between the EOI stage and submission of the final application, but the Project Representative who is responsible for submitting the full application is expected to still be part of the venture as either a partner or from the primary organisation responsible for project development.

For HAR2, a business can lead on up to six applications, which must be materially different, and can be included as a collaborator, or project partner, in a further six applications.

Q049: We are looking to apply for a 20MW HHV green hydrogen project for HAR2.

Please can you advise if it would be possible to bring the proposed plant online in 2 phases (10MW each), with the first phase in Q3 2026 and the second phase in Q2 2027.

DESNZ will not permit phased commissioning of a project (i.e. where the producer receives payments for selling hydrogen produced by an earlier phase without the later phases also having been commissioned). In other words, while it is possible to apply to HAR2 with a single 20MW project targeting commissioning in Q2 2027 – and to indicate that the build will be completed in stages – the project cannot be deemed operational and become eligible for HPBM payments until it has demonstrably commissioned at least 80% of the project’s ‘initial installed capacity estimate’. Under the ‘new build’ eligibility criteria, government may support a subsequent expansion of at least 5MW of hydrogen capacity to an existing project, or the carrying out of works to an existing project where at least 5MW (H2 HHV) of new hydrogen production capacity is added to an existing plant.

Q050: Where in Annex B do we reference evidence used only in Annex A and not used in the application form? For example there is nowhere in Annex B to reference evidence used in Annex A Tabs ‘Production Facility’ and ‘H2 Storage Facilities’, possibly this would go under 5.3.1 but the link between questions and tabs is not explicit.  The same goes for some other tabs. This is making referencing problematic for applicants and could potentially be confusing for assessors if evidence expected under 5.3.1 say is absent, because it is only used in the Annex A ‘Production Facility’ tab for example. May we add extra columns in Annex B for each tab of Annex A to make this work properly?

Thank you for raising this concern. Where evidence only supports Annex A entries:

• For data in “Eligibility”, “Project Detail & Timelines”, “Production Facility”, “H2 storage Facility”, “Offtaker Details” tabs, assign to the most relevant question in sections 3, 4, 5
• For data in “Economic Benefits”, assign to 7.1
• For all other tabs assign to 6. Cost

In the relevant section of the application list all evidence as referenced in Annex B, highlighting where evidence is only relevant to data in Annex A.

Q051(a): Ref Table page 54 of HAR 2 Guidance ‘Wider electricity system benefits scoring framework’:

Can you please clarify which regions in the map (A, B, C, D, E and F) correspond to the descriptions and the scores set out in the table? Are the letters in figure 1 (the map) to be matched to the scores as follows:

A = 5
B = 4
C = 3
D = 2
E = 1
F = 0

Or should we interpret this differently, and, if yes, can you please clarify how we should interpret it?

Our understanding for the scores 0 to 3 in the table is that, given the two sub-criteria are separated by an ‘and / or’, these sub-criteria do not need to be met at the same time. In other words, if for example a project is located in region E in the map (assuming this is a region with ‘less positive impact’, but it can deliver up to 30% additional electricity, then the score would be 2. If it can deliver limited additionality, then the score would be 1. Can you please confirm if this interpretation is correct or, if not, how we should interpret this?

On the other hand, if the project is located in region F, then from reading the table it looks like it can only score zero, is this correct? or can this be scored 1 or 2 if it delivers limited or up to 30% additionality respectively?

As set out in the Assessment Guidance, GB regions will be scored proportionately to the amount of curtailed electricity in each region, so constrained regions will score much more favourably than unconstrained regions on location. Therefore, we would expect regions A and B to score much more favourably than other regions. A maximum score of 5 can be scored for the Wider Electricity System Benefits criterion.

It is correct that the sub criteria (location and additionality) do not need to be met at the same time; it is a combined score across both sub criteria and therefore projects with no additionality can still score for wider system benefits if they are located in optimal regions and vice versa.

Q051(b): Ref Deliverability Scoring Framework

With reference to the Deliverability Scoring Framework, could you please clarify if projects that can achieve an earlier COD would be given higher scores?

We would expect that, as long as the specified COD is within the three specified delivery years, it won’t matter if the specified COD is earlier. We understand that what matters is how credible the delivery plan is in relation to the specified delivery date, but we would be grateful if you can confirm that our interpretation is correct.

Your interpretation is correct – projects that are able to achieve an earlier COD will not be given higher scores for Deliverability.

Q052: Noting that using HPBM funded green hydrogen for blending with natural gas is not eligible in HAR 2, how is blending HPBM funded green hydrogen with bio-methane considered in HAR 2?

As set out in the HAR2 Application Guidance, hydrogen blending into the gas distribution and/or transmission network is not a qualifying offtaker for HAR2. This includes hydrogen that is intended to be blended with gas or bio-methane for other purposes that is to be used in the gas distribution and/or transmission network. Blending in other scenarios is permitted and would be subject to deliverability assessment.   

Q053(a): Regarding DA.54 “Kept in inert underground storage” – please can you elaborate on what must be inert? Is this to specify the storage arrangement and carbon black must remain inert to each other, i.e. not pose a risk of reacting in some way?

Kept in inert underground storage should prevent the solid carbon to be placed  in contact with high temperatures, ignition sources, elevated oxygen levels, biogenic material/high levels of microbes, solvents or acid/alkaline conditions (or similar conditions that could lead to loss or conversion of the carbon), and is not at risk of being flooded, washed away, ground down and lost by subsurface movements. Inert underground storage should ensure that the solid carbon put in storage underground will stay there without the risk of the leakages and the solid carbon turning into CO2, CH4 or other Hydrocarbon Liquid / Gases.

Q053(b): Regarding DA.54 “e.g. disused mines and bunkers..” – please can you elaborate on the word disused? Is this to specify the storage arrangement must be permanent and not disturbed and hence could be a disused section of an active mine or underground storage facility?

Disused mines and bunkers refer to sites that are no longer in active use. These sites were previously operational but have since been abandoned or closed down. A disused section of a site could also be allowed but it must be completely safe to use and any activity (people/machinery) must be prevented in that area as this would increase the risks of potential leaches or losses of the solid carbon.

Q053(c): Regarding DA.54 “Kept in inert underground storage” – could the sequestration of carbon in a disused section of an open cast mine, which was subsequently back filled be acceptable?

We would not categorise an open cast mines as underground storage. There are risks associated with erosion/loss to atmosphere, leaching or accidents/arson.

Q054(a): HAR2 Application Guidance Section 1.4 (Page 15) contemplates Award of Contract “from 2025”.  “From 2025” is open-ended. Can you please be more specific about when contract award is more likely to occur?  Will projects scheduled for earlier delivery years be given preference over those in later delivery years?

The dates set out within the Application Guidance are indicative. At this stage, we are unable to provide further detail on when Contract Award will take place.

Q054(b): In the HAR2 Application Guidance Section 3.5 (Page 27), the Offtake Eligibility Criteria states that a project is eligible if it “has identified and engaged with at least one qualifying offtaker”. Please can you clarify DESNZ’s expectations with regard to the % of total production that it expects to be evidenced from a project’s potential offtakers at this stage?

In order to be eligible to apply to HAR2, projects are required to show they have identified and engaged with at least one qualifying offtaker, however there is no requirement around this offtaker accounting for a minimum % of total production.

To achieve the minimum deliverability score required, projects will need to demonstrate they have commercially and technically viable offtakers for the majority of the planned hydrogen production volumes , or provide sufficient evidence to demonstrate that there is sufficient demand for the planned production volumes which the site can feasibly supply.

Q054(c): We have a question regarding the setting of the Target Commissioning Window (HAR2 Application Guidance Section 3.5.2 (Page 28)).  Looking at our current build schedule, our Target COD Date is scheduled to fall in the second half of the final 31 March 2028 – 31 March 2029 delivery year.  This would lead to a 12-month Target Commissioning Window that would partially fall outside of the final delivery year.   Can you please confirm that Target Commissioning Windows are allowed to fall outside of the final delivery year provided that the Target COD Date falls within such delivery year?

Eligibility criteria sets out that projects must be able to demonstrate a commercial operation date within one of the three set delivery years. In the context of new build hydrogen production facilities, being operational means the date the Project is confirmed to meet the relevant Operational Conditions Precedent (OCP) and the Project begins operating and is capable of producing hydrogen that will be sold to offtaker(s). The Target Commissioning Window will be set at the agreeing the offer stage and does not form part of the eligibility consideration.

Q054(d): HAR2 Application Guidance Section 3.6.2 (Page 42) states that “shortlisted projects will be expected to progress and evidence they are at an advanced stage of FEED, be able to move forward with all the regulatory processes and consents needed to realise their Project”.  In what form is DESNZ expecting such evidence to take?

During assessment of applications, DESNZ will holistically assess the credibility of the project’s schedule/ plans for reaching a sufficient level of engineering maturity by the ‘agreeing an offer’ stage of the allocation round.

At the ‘agreeing an offer’ stage of HAR2, evidence of this maturity level may include (but is not limited to) deliverables from a completed pre-FEED, deliverables from an ongoing FEED demonstrating increasing project definition and cost certainty, or evidence that the relevant FEED contractor is engaged in the development of the design.

Q054(e): Regarding HAR2 Application Guidance Section 5.2 (Page 61), is it possible to give some guidance as to how projects will be selected for the potentially different assessment pathways contemplated in this section?  Is it likely to be by size?  Is it likely to be by delivery year?  Is it likely to be by technology type?

We are currently working on the design of these stages and incorporating lessons learned from the HAR1 agreeing   an offer process. We intend to set out more detail on the potential different pathways we may use to group projects in the future.

Q055: If a project is using biomethane as a feedstock and sequestering solid carbon, is it possible to claim a CDR from another policy/ voluntary market, and qualify as producing low-carbon hydrogen? For example, could you produce 0 gCO2e/MJ H2 (rather than negative) and use the “surplus” negative emissions to claim a CDR? In this way, there is no double counting taking place.

A negative GHG Emission Intensity does not imply necessary or sufficient evidence has been provided to meet UK Government requirements for a ‘greenhouse gas removal’, or ‘permanence’ of storage for biogenic CO2/Solid Carbon, or monitoring/ reporting/ verification of the same. Separate UK policies are being developed in these areas.

Any emissions accounted for under this Emission Category shall not be credited or claimed elsewhere (for example, as a carbon credit in other policies or voluntary markets). If credited elsewhere, any emissions sequestration benefit can no longer be included in the overall emissions calculation for the purposes of the Standard.   

Any emissions accounted for under this Emission Category shall be directly related to processes within the System Boundary. Carbon offsets (or similar) from other processes cannot be claimed under the Standard.

Q056: Planning in Northern Ireland is a long process, will we need planning permission approved by award of contract in early 2025 for the project to be able to progress? If planning is not approved by contract award in early 2025, are we disqualified from HAR2 support? We have predicted a COD of mid 2028, so there is time available between contract award in early 2025 and COD in mid 2028 for planning permission to be approved.

We will holistically assess the credibility of the project schedule/ plans, including all activities, to meet the targeted COD date. We can confirm that, at a minimum, projects will be expected to of at least evidenced submission of planning application(s) by contract award. The latest that full planning approval will need to be evidenced is at the milestone delivery date (12 months after contract award), so expected to be in early 2026. In the event an ICP is not satisfied, the LCCC, ‘acting reasonably’, have the right to terminate a contract.

Q057: Regarding “Solid Carbon Sequestration”: is the location of carbon sequestration (in cement, concrete or inert underground storage) restricted in anyway? i.e. UK only.

Solid carbon should be sequestered in in inert underground storage the UK.  There is however no restriction under the LCHS to prevent the export of products (cement/ concrete) which the solid carbon has been sequestered in.

Clarification questions, last engagement session (added 14 March 2024)

QES30: In Annex A1 template (Funding Sources & IRR Tab), what metric for IRR is most useful to DESNZ? The current LCHA states post-tax real discount rate, whereas a previously answered HAR2 clarification question (Q15) states that DESNZ uses pre-tax real discount rate to calculate project Strike Prices.

Within the Annex A template, Applicants can choose the terms in which they report their IRR, with four categories available: pre-tax nominal, pre-tax real, post-tax nominal and post-tax real.

DESNZ will be estimating the strike price in pre-tax real terms. Therefore, if Applicants have estimates of their pre-tax real IRR, this should be provided in the Annex template.

We will accept post-tax real estimates, however for the strike price estimations these will be converted to pre-tax real. For future negotiations process, DESNZ will request post-tax real IRRs as that is the requirement set out in the draft LCHA contract.

QES31: In the offtaker sales tabs, if a Producer is selling to an offtaker on a floating price basis (e.g. related to the displaced natural gas), how do we indicate that this is floating? Likewise if any power sources are indexed to market prices.

Offtake sale prices: in the “H2 Volumes & Sales Prices” tab in Annex A, Applicants should include their best estimate of the long term hydrogen sales price, while indicating in the comments box that given volumes will be sold on floating basis.

Electricity prices: Annex A Electricity Source tab allows Applicants to specify whether and how price for electricity from any given source will be indexed. Applicant then report their electricity prices for that source in real 2024 prices in the Electricity Volumes & Prices tab.

QES32: Grid network costs and REGOs are largely uncontrollable and mostly common for all projects. On what basis should applicants forecast these costs, and will projects be penalised for forecasts that differ significantly from DESNZ’ forecasts?

Projects should include their best forecast of future network and REGO prices. Projects should also use the comments section to explain assumptions behind the forecast and provide any supporting documentation where possible. These forecasts, as one component of project’s overall costs, will impact project scores for the Costs categories.

Given the uncertainty over these cost categories it is for Projects to decide how to manage that risk, how much of that risk they are willing to absorb.

QES33: AACE Cost classification - could you confirm the abbreviation please

Association for the Advancement of Cost Engineering

QES34: How do we reference evidence in Annex B used only in Annex A, not used in the application form? Apart from Q6 7.1 8.1 and 8.2 that explicitly reference Annex A, several tabs of Annex A are not explicit in Annex B making referencing problematic for applicant and assessor. Related to this what tab relates to which application form question needs more clearly defined.

Where evidence only supports Annex A entries:

• for data in “Eligibility”, “Project Detail & Timelines”, “Production Facility”, “H2 storage Facility”, “Offtaker Details” tabs, assign to the most relevant question in sections 3, 4, 5
• for data in “Economic Benefits”, assign to 7.1
• for all other tabs assign to 6. Cost

In the relevant section of the application list all evidence as referenced in Annex B, highlighting where evidence is only relevant to data in Annex A.

QES35: Is a third-party’s forecast of electricity prices acceptable as a source of data for calculating LCOE? Or must a developer on cite the forecast price of the generator with which it hopes to engage for the purchase of electricity.

Electricity price information provided in the ‘Electricity Volumes and Prices’ tab should be, as much as possible, a reflection of project’s actual electricity costs over the contract lifetime. Therefore, applicant should ideally provide price forecasts from the generator/ supplier which it is most likely to choose as the preferred electricity supplier. 

Where that is not available, project can provide a third-party electricity forecasts, but should use the comments section to explain the source of the forecast and why the project believes that forecast is a credible reflection of its actual electricity costs.

Please note the credibility of the figures provided and quality of supporting evidence will affect the score received by a project.

QES36: Relevant to DESNZ point about historical dates not recording in the Project Details & Timelines Tab (of Annex A1 template), when you ask for “Date of Water Connection Offer Signature” & “Date of Grid Connection Offer Signature”, we assume you’re asking for the date the agreements will provide the water/ electricity? But if it means the date the document itself was signed, that would be covered in the Comments column?

This should be the date the grid connection offer from your supplier has been accepted and signed – not the date you will start using the electricity. Additional information can be added into the comments such as the date the offer was provided – and we expect other information to be shown in the schedule applicants submit as part of their applications.

QES37: Is there a word limit for text in the Comments sections in the Annex? There’s not much space, but sounds like you’d like applicants to use it to elaborate on quite a few answers.

There is no word limit for the comments boxes in Annex A1 – Project Datasheet. Applicants should use the comments boxes to provide a concise explanation for any information and evidence provided to support eligibility claims.

QES38: Where gate fees are received for waste to be processed in gasification projects, should that income be expressed as a negative price?

Yes, if a project receives a payment for any of the input sources, such as waste gate fees, that should be expressed as negative price in the ‘Non-Elec Input Volumes & Prices’ section.

Clarification questions (added 22 February 2024)

Q024: Regarding the forthcoming call for HAR2 just a few questions:

1. Is it a grant fund for new build or an ongoing subsidy for Hydrogen production or both?
2. If it’s a grant what is the total a project can apply for and the level of match-funding?
3. If a subsidy, for what and how much?

Only new build hydrogen production facilities are eligible to apply to HAR2 to be considered for revenue support through the Hydrogen Production Business Model (HPBM).  Government is defining ‘New Build Production Facilities’ as a newly constructed facility built for the specific purpose of producing hydrogen. This also includes the carrying out of works to an existing project where at least 5MW (H2 HHV) of new hydrogen production capacity is added to an existing plant.  

The HPBM is delivered through a private law contract, the Low Carbon Hydrogen Agreement (LCHA), between a government appointed counterparty and an eligible hydrogen producer. The contract term set out in the draft LCHA is 15 years for all technologies and project sizes with capital repayments spread evenly across the term.

There will be no Net Zero Hydrogen Fund CAPEX grant support available at point of application. However, Government recognises the value of providing up-front CAPEX to reduce the amount of ongoing revenue support projects require through the HPBM and therefore the position on NZHF CAPEX will remain under review. Government will inform applicants at the earliest opportunity should NZHF CAPEX be introduced at a later stage.  

The HPBM provides price support through a variable premium design, similar to the successful Contracts for Difference scheme for renewable electricity. The producer is paid a subsidy for each unit of low carbon hydrogen sold, based on the difference between a Strike Price reflecting the cost of producing hydrogen and a Reference Price reflecting the market value of hydrogen.  Further information on eligible costs under the HPBM are set out in section 3.6.3 of the Application Guidance.   

Q025(a): Is a project being operational before 31 March 2026 considered eligible (for example 6 months before)?

No, Projects must be operational between 31 March 2026 and 31 March 2029 to be eligible for HAR2. See Section 3.5.2 of the Application Guidance for further information on this eligibility criteria. 

Q025(b): Is it possible to withdraw our application from the tender process at any time?

Yes, Projects can withdraw applications at any point in the process.

Q026(a): Is the strike price somehow taken into consideration for the selection of the project? In the ‘costs’ or ‘value for money’ selection criteria?

As part of the cost assessment process, we will use the cost information submitted in Annex A to consider project’s total cost per unit of hydrogen produced and use that as a basis for comparing project’s cost-effectiveness relative to other applicants. As per application guidance, the final cost score received by a project will also be affected by the credibility of the figures provided and quality of supporting evidence.

Q026(b): Is there a link between the strike price and the CAPEX/OPEX that we consider in the excel file?     For example, will you calculate a LCOH with the CAPEX and OPEX and the strike price should be equal to the LCOH?

CAPEX and OPEX information submitted by projects through Annex A will directly inform assessment stage strike price estimates.

The strike price will be estimated according to the following formula:

Strike price (£/MWh H2 HHV) = (C+O+E+R)/V

Where:

• C = CAPEX (£): The total eligible CAPEX investment supported through the strike price.
• O = O&M OPEX (£): The total eligible operating and maintenance costs (that is, OPEX excluding energy and input costs) supported through the strike price.
• E = Energy and Input Costs (£): The total energy/input costs supported through the strike price. This will be estimated through an assessment of both the £/MWh unit costs and the energy / input consumption required (MWh of energy input per unit of hydrogen produced).
• R = Cost of Capital (£): The rate of return supported through the strike price. This is calculated as an annual % return applied to the CAPEX investment, in real pre-tax terms.
• V = Volumes Sold (MWh): The total sales volumes included in the strike price.

Q026(c): How do you calculate the reference price? Which temporality?

The Reference Price is intended to represent the market price received by the producer for each unit of hydrogen (note, sales of hydrogen for feedstock purposes have a different reference price floor). In the absence of a market benchmark price for hydrogen (low carbon or otherwise), the draft Low Carbon Hydrogen Agreement (LCHA) sets out a Reference Price comprising the producer’s Achieved Sales Price, with a floor at the natural gas price (and a higher floor for feedstock purposes). We will seek to encourage the development of a market benchmark as the hydrogen market develops.

Where relevant, there will be a calculation for the Reference Price for Qualifying Volumes and for Non-Qualifying Volumes. These calculations are set out within Section 9 (payment calculations) of the draft Low Carbon Hydrogen Agreement and will be calculated by the LCHA counterparty in relation to the relevant billing period. Billing period means one Month. We may make some updates to the draft LCHA for HAR2 and will engage with industry in due course on any proposals.

Q026(d): What natural gas price do you take into account? Which temporality?

The Low Carbon Hydrogen Agreement uses a month ahead natural gas price, defined as the National Balancing Point (NBP) Virtual Trading Point as published on ICE Futures Europe.

Q026(e): How do you calculate the achieved sales price? How often will it be updated?

The ‘Achieved Sales Price’ (expressed in £ per MWh (HHV)) is the Total Sales Price less specified exclusions. Where relevant, there will be an Achieved Sales Price for Qualifying Volumes and for Non-Qualifying Volumes and each Achieved Sales Price will include only the same eligible costs as the negotiated Strike Price.

The calculations for the Achieved Sales Price are set out within Section 9 (payment calculations) of the draft Low Carbon Hydrogen Agreement (LCHA) and will be calculated by the LCHA counterparty in relation to the relevant billing period. Billing period means one Month. We may make some updates to the LCHA for HAR2 and will engage with industry in due course on any proposals.

Q026(f): What is the Price Discovery Incentive? How do you concretely set it up?

The Price Discovery Incentive (PDI) promotes price discovery and encourages the producer to seek a higher sales price, this enables the producer to receive an additional amount linked to the increment by which the Reference Price exceeds the price floor for each unit of hydrogen sold.

The PDI provides producers with 10% of the increase in the Achieved Sales Price premium above the natural gas Reference Price floor.

The calculation for the PDI is set out within section 11 (Price Discovery Incentive) of the draft Low Carbon Hydrogen Agreement and will be calculated by the LCHA counterparty in relation to the relevant billing period. Billing period means one Month. We may make some updates to the LCHA for HAR2 and will engage with industry in due course on any proposals.

Q026(g): How the sliding scale mechanism would be implemented? What would be the top-up amount received by the producer?

The Sliding Scale Top Up (SSTU) is intended to provide protection for volume risk beyond the control of the Producer and is determined over each billing period of one month. Provided the Sliding Scale Top Up condition has been satisfied, this will be payable by the LCHA Counterparty to the Producer following a qualifying event.

The SSTU calculation is set out within section 12 (Sliding Scale Top Up Amount) of the draft Low Carbon Hydrogen Agreement. The SSTU amount a Producer receives is based on:

• Non-Variable Cost Strike Price: the Non-Variable Cost Strike Price describes the non-variable elements of the Strike Price. Simply remove the variable costs, such as electricity, from the Strike Price and you have the NVCSP. The NVCSP is used in the Sliding Scale Top Up as it is the cost the Producer continues to face when not producing and selling hydrogen.
• Trigger point: the Sliding Scale Top Up Amount’s trigger point is 50% of the reference sales volumes to align with the SSTU’s principles of only protecting from unexpected drop of demand, rather than business as usual demand variation (which would require a higher trigger point).
• Constants b, D: The constants b, D in the formula determine the amount of the NVCSP covered under the Sliding Scale Top Up Amount.
• Constant A: This constant is intended to reflect the NVCSP of the Producer. For electrolytic projects, we may use an average of the NVCSP for all projects to align with HPBM’s principle of addressing general risks, rather than project specific ones, and to reduce administrative complexity.
• Level of support: The level of support is aligned with the primary design principles outlined in the August 2021 consultation: (a) the Sliding Scale Top Up provides some support for the residual volume risk left over from Producers managing this themselves (e.g. through take-or-pay arrangements with offtakers); and (b) Producers should always be better off increasing production.

We may make some updates to the LCHA for HAR2 and will engage with industry in due course on any proposals.

Q026(h): Is there a minimum volume to be produced during the 15 years? Per year? Per month?

There is no criterion related to the amount of hydrogen produced. However, government has set a minimum production capacity of 5MW (H2 HHV). With regards to the metric, this is the maximum MW of hydrogen output of the facility in high heating value terms, before load factor or plant availability are taken into account. This eligibility criteria only relates to the instantaneous, maximum nominal capacity of the project – this must be at least 5 MW H2 (HHV).

While there is no minimum production volume requirement, it is the projects responsibility to ensure a load factor that will result in a strike price that offers value for money to government.

Q027: Following on from your response to question 001, we would like to raise a similar query. We may be unable to set up a SPV or a JV until after the application stage. Would we be able to create a JV or SPV after submitting an Application under individual company names, as long as the project representative that has submitted the application is part of the SPV or JV?

Yes, applicants may create a JV or SPV after submitting an Application under individual company names, but the Project Representative who is responsible for submitting the full application, is expected to still be part of the venture as either a partner or from the primary organisation responsible for project development. Applicants must have formed their JV or SPV at the point of negotiations concluding, as UJVs are not able to receive hydrogen business model support.

Clarification questions 2nd engagement session (added 22 February 2024)

QES18: RTFO support and HBM premium are not cumulative. However, is it allowed to get RTFO support for part of the H2 production, and the HBM premium for the rest of the production?

Yes, producers in receipt of HPBM support will be allowed to participate in the Renewable Transport Fuel Obligation from the Department for Transport. Some volumes produced will be allowed to be claimed under the RTFO, subject to meeting the RTFO’s eligibility criteria, but claiming under both the HPBM and RTFO for the same volumes of hydrogen will not be permitted.

Applicants who intend to seek support under both the RTFO and HPBM will need to demonstrate that the project is capable of meeting all of the HAR2 and RTFO eligibility criteria. Further detail on RTFO evidence is set out in Section 3.5.10 of the Application Guidance.

QES19: When will projects need to take FID following contract award?

The timing for a final investment decision (FID) is a commercial decision for each project. However, we expect to see projects maintaining the necessary momentum to meet their planned commercial operation date.   

The decision to award support to projects is subject to conditions being satisfied at the point of contract award. For example, projects would need to demonstrate to DESNZ sufficient progress towards satisfying key contractual requirements set out within the Low Carbon Hydrogen Agreement (LCHA), such as Initial Conditions Precedents (ICPs) which must be fulfilled and evidence to the LCHA Counterparty within 20 days post-signature.         

If projects are awarded a contract, they would also need to demonstrate to the LCHA Counterparty compliance with the Milestone Requirement (12 months after contract signature) to ensure they are on track to meet the operational requirements of the LCHA and their planned commercial operation date, via evidence of an agreed provable spend or commercial commitments.

QES20: You make reference that you reserve the right to assess projects against two or more pathways. Can you shed more light on how these pathways will be defined? e.g. Will this be by Delivery Year? Will this be by size of project?

We reserve the right to subdivide the shortlist of projects into two or more groups, each group entering a separate pathway to agreeing an offer.

Government will issue a formal invitation to enter the process of the Agreeing an Offer stage to relevant projects who have been shortlisted following assessment. That invitation will set out information on the different pathways, if the government sets up different pathways to the Agreeing an Offer stage.

Projects are also reminded that government intends to apply lessons learned from HAR1 to develop the processes applicable to the HAR2 Agreeing an Offer stage and we do reserve the right to make changes to the process  to take into account those lessons learned.

QES21: What impact could a UK general election have on the overall HAR2 timetable and on DESNZ’s ability to progress project shortlisting / due diligence and overall decision making?

The timeline set out in Section 1.4 of the Application Guidance is the indicative timeline that we are working towards. We will continue to update projects throughout the process as we move onto each new stage in terms of what the timeline looks like.

QES22: Similar to the way volumes can be opted out of HPBM and into RTFO, is a similar ability expected to be allowed for any SAF scheme from the DfT (which is likely to follow RTFO rules).

The SAF Mandate was consulted on in 2023 where it was proposed that rules on multiple incentives would align with the RTFO as close as possible. Officials are developing the government response to the consultation which will confirm how government will proceed. The government response will be published in Spring 2024. DESNZ and DfT will consider interactions between the HPBM and SAF mandate and work closely with developers to ensure that they are familiar with multiple incentives rules in the context of SAF production.

QES23: Can you please provide some guidance on the thinking behind when projects could be awarded contracts?  ‘From early 2025’ is rather open-ended.

The timeline set out in Section 1.4 of the Application Guidance is the indicative timeline that we are working towards to award contracts to successful projects. We intend to update projects throughout the allocation process, on anticipated timelines for each stage of the process. Our current timeline has been set out to allow time for each application stage to the best of our understanding and from our experience of delivering the first hydrogen allocation round (HAR1). Please note, government reserves the right to alter these timelines at any stage in the process.

QES24: The government is already exposed to high power prices via electricity CfDs - why not remove government and project risk by offering to back to back this with HPBM projects?

Through the hydrogen allocation process projects are incentivised to choose an electricity sourcing strategy that minimises production costs and it is for projects to manage their electricity cost risk.

QES25: Do you need to submit the hydrogen emission calculator file with the application, or just the output from it?

A full HEC file with supporting evidence will have to be submitted. We will conduct a full assessment of the file to ensure the calculator is completed accurately with the appropriate information required for the relevant pathway.

QES26: “5.3.2 Offtaker arrangements - agreements & development plan (500 words per offtaker)”. Where a project has a portfolio of offtakers can a 500 word portfolio summary also be submitted alongside each Offtaker’s 500 words? A portfolio summary can cover off regional arrangements for the existing portfolio and future build out plans.

Additional evidence can be provided alongside the Project Application Form response as long as properly referenced but cannot be used to continue an answer. Projects should note the application submission is what is scored, and any supporting evidence provided is used to substantiate and validate that the response is accurate and robust. This evidence must be clearly referenced underneath the written response statement it is being used to support, including where relevant, reference to specific sections or pages within the supporting documentation. Multiple answers can reference the same document.

QES27: You indicate that you expect applicants to convince you that they can manage the key delivery and technical risks. Where (how) do we address key commercial risks?

In particular, managing variations in power price and power connection charges against the CPI indexation of the LCHA.

What can be shared with applicants on how these risks were addressed by successful HAR1 applicants?

The low carbon hydrogen agreement is designed so that government absorbs a level of that commercial risk that enables the project to go ahead. However, this risk level needs to be appropriately balanced between the project and the government. For managing variations in the power price and power connection charges, we expect projects to include in their strike price projections they can stand behind throughout the lifetime of the contract. When projects agree to a strike price, they need to be comfortable that the strike price includes a level of cost recovery that manages that risk in terms of future projections. The strike price is not indexed to the power price. Successful HAR1 applicants took a position on these issues that balanced risk appropriately between HMG and the project. Whilst HAR2 is not purely price competitive, projects that look to pass all price risk onto HMG will likely appear to offer poor value for money relative to other projects.

QES28: Going into this session my question was to ask if 5.3.4 and 5.3.5 are mandatory for Electrolytic projects; however, based on content presented today, can I confirm that for an electrolytic project 5.3.4 Feedstock would be water, and 5.3.5 Waste / co-product would be oxygen for example?

Yes, for an electrolytic project, 5.3.4 Feedstock would be water and 5.3.5 Waste / co-product would be oxygen. 5.3.4 and 5.3.5 are both mandatory, but Projects must answer them in the best way they can and in the way that is most relevant to the Project. It is understood that projects with a later COD would not have a water agreement in place at application, but a robust plan in place of this of where the project will source water from is important. Similarly, for oxygen, the Project may have a market for this and we would like to understand that    arrangement, but if the oxygen is going to be vented to the atmosphere we would like to see evidence that the Project is doing that safely with all the necessary permitting in place.

QES29: Feedstock and Electricity Supply are not always going to be straightforward. Focussing on the latter, there are notable constraints on the distribution and transmission networks given the scale of reinforcement and generation or storage connections. While demand capacity may be available and new load may provide wider system benefits, a physical connection point may not until enabling works are completed. Other potential barriers include the existing SQSS clauses, Power System Analysis assumptions, behind the meter limitations and liabilities based on Final Sums.

Perhaps not a question that can be fully covered during the session, yet to aid HAR2 and future rounds it would be great to understand what plans are in place to address perceived barriers through existing industry / Ofgem working groups or a dedicated working group for Hydrogen. In recent years there have been code modifications and changes to assumptions to removed perceived barriers for battery energy storage, hence opportunity to resolve earlier in development here with a coordinated approach.

As set out in the British Energy Security Strategy, government is committed to ensuring consideration is given in our hydrogen production policies to the siting of hydrogen electrolysers to best use surplus low carbon electricity and to reduce electricity network constraints.

Electrolytic hydrogen projects can bring significant system wide benefits by locating in an optimal position to help to manage network constraints, or to use excess electricity that would have otherwise been curtailed or constrained.

The Hydrogen Delivery Council includes a Hydrogen Production Working Group which discusses issues related to system integration of electrolysis. These issues will continue to be discussed within that group and through wider industry engagement.

Clarification questions, engagement sessions, 15 and 22 January 2024 (added 2 February 2024)

QES1: We note that there is no longer NZHF CAPEX support at the point of application. However, it is unclear to what extent capex support will be built into the strike price noting govt. has said there is an expectation that HAR2 strike prices are below the average of HAR1. Could govt. clarify this?

In HAR1, CAPEX covered by the Net Zero Hydrogen Fund (NZHF) grant was excluded from the strike price, along with any return on this proportion of the CAPEX.

Eligible CAPEX cost under the draft Low Carbon Hydrogen Agreement (LCHA) include:

• CAPEX associated with the construction and operation of the Facility
• CAPEX associated with the construction of hydrogen transport infrastructure
• CAPEX associated with the construction and/or operation (as applicable) of hydrogen storage infrastructure

However, note that in relation to CAPEX cost associated with hydrogen transport and storage infrastructure, whether or not they will be included in the Strike Price will be negotiated on a project-by-project basis by taking several factors into account including necessity, affordability and value for money for government.

For example, CAPEX for compression equipment and storage units located at the hydrogen production facility are both allowable cost categories and eligible to be funded through the strike price. However, we would strongly recommend that projects consider whether they can pass costs linked to the requirements of their offtakers (for example compression required above the output of the production system, additional storage capacity) onto their offtakers, rather than load these costs onto the strike price, especially in cases where higher cost fuels are being displaced (e.g. diesel). CAPEX for compression equipment and storage units at offtaker facilities are not eligible to be funded through the strike price. Please note that for HAR2, we may make some updates to the LCHA to reflect policy changes and intend to engage with industry in due course. Please refer to the Low Carbon Hydrogen Agreement Heads of Terms for further information.

QES2: It is not entirely clear what capex costs can be included in the strike price. As an example, would the capital cost of compression equipment utilised upstream of refuelling vehicles, or upstream of mixing hydrogen of the right pressure into a blending unit at the offtaker point, be included?

CAPEX for compression equipment at the hydrogen production site is eligible to be included in the strike price. Strike price calculations will be subject to the cost assurance and value for money assessments during the negotiations. As such, we would strongly recommend that projects looking to compress to higher pressures consider whether they can pass any of these costs through to their offtakers, rather than load these costs onto the strike price, especially in cases where higher cost fuels are being displaced (e.g. diesel). CAPEX for compression equipment at offtaker facilities is not eligible. Low Carbon Hydrogen Agreement Heads of Terms for further information.

QES3: In addition to the minimum hydrogen production capacity, given there is a higher potential capacity threshold (875MW vs 250MW (initially) for HAR1) is there an expectation/desire for larger projects (eg c100MW) to come forward as part of HAR2?

We have stretching ambitions to deploy hydrogen at scale (ambitions of up to 1GW of electrolytic hydrogen capacity in operation or construction by 2025, and up to 10GW of low carbon hydrogen production capacity by 2030 subject to affordability and value for money) and develop a world class hydrogen economy, this has guided our approach to designing funding support. One of the key strategic objectives of HAR2 is to support projects to deploy at scale.

For HAR2 we have various eligibility criteria, including a minimum hydrogen production capacity of 5MW (H2 HHV), as long as a project meets these, they will be eligible to apply. See Section 3.5 of the HAR2 Application Guidance for further details on the HAR2 eligibility criteria.

We are aware of a healthy pipeline of projects, including some larger projects that may come forward for HAR2, and we would welcome applications from larger projects. Government hopes to support up to 875MW through HAR2, but reserves the right to allocate less, for example if it does not see sufficient projects coming forward that meet the requirements of the round and present VfM to government.

QES4: Does EOI require we indicate project location?

Yes, the Project Representative will need to provide the location and postcode of the project plant, as well as the address the applicant business is registered to when submitting the EoI form.  EoI answers are considered as indicative only and not as firm responses.

QES5: If several electrolysers are located at different locations (different post codes) each having qualifying minimum capacity (MW), would this be treated:

- as one single project, so one single EoI
- or different projects - do we need to use multiple EoIs?

Electrolysers located at different locations will be treated as separate projects and you will need to submit an EoI for each of these projects. There is no limit for EoI form submissions. The limit stated in the application guidance, that a business can lead on up to six applications, which must be materially different, and can be included as a collaborator, or project partner, in a further six applications, applies to the full application submission only.

QES6: When will be the last opportunity to ask questions / clarifications before submission?

The deadline for the submission of clarification questions is 23:59 on 22 March 2024, ahead of the submission window closing on 19 April 2024.

QES7: Is it permissible to use ammonia cracking under gas splitting technologies?

It is not permissible to use ammonia cracking under gas splitting technologies. The Low Carbon Hydrogen Standard (LCHS) and Hydrogen Production Business Model (HPBM) are primarily focused on hydrogen production; and do not cover hydrogen derivatives including ammonia. Future versions of the standard may consider other aspects of the supply chain for hydrogen and its derivatives, including conversion to and reconversion from ammonia.

QES8: When talking about meeting an average emissions threshold on the LCHS, could you elaborate on this? Does this equate to an average across the lifetime of the LCCC contract or other?

The full details on how averaging works in the Low Carbon Hydrogen Standard (LCHS) can be found in Chapter 7 of the main document. We have summarised below.

On a monthly basis, each discrete consignment of hydrogen produced in that calendar month must be reported to the delivery partner, including both compliant and non-compliant consignments. A hydrogen facility can then choose to calculate and report a weighted average for any number of discrete consignments in that calendar month, but only for those which meet the ‘Conditions of Standard Compliance’ and have a non-negative greenhouse gas (GHG) emission intensity.

If the GHG emission intensity of a weighted average consignment meets the 20gCO2e/MJ emission threshold, then all discrete consignments included in the average can be claimed as compliant.

QES9: The call criteria says 5MW (HHV) minimum H2 production capacity. Is this averaged over 24 hours and 365 days/ year?      

Production capacity does not take into account load factor or availability. It reflects the maximum production output of a facility. For example, a facility with a production capacity of 5 MW would produce 5MWh of H2 (in HHV terms) in one hour of operations at maximum capacity/full power.

QES10: Please can you comment about the reason for min 50% biogenic waste content for waste to hydrogen project given that the list of eligible waste is wider.

The minimum waste and residue requirement applies to biogenic inputs only, to encourage the use of biogenic wastes and residues wherever possible. The hydrogen produced from these inputs typically delivers greater GHG savings than hydrogen derived from newly produced biomass. Use of wastes and residues does not incur emissions related to crop cultivation or land-use change and eases any potential competition for resources with food and feed crops.

The requirement in the Low Carbon Hydrogen Standard (LCHS) aligns with policies and principles set out in other UK schemes, including the Renewable Transport Fuel Obligation (RTFO), Greenhouse Gas Support Scheme (GSSS), Renewable Heat Incentive (RHI), and the Biomass Strategy.

To clarify, there is no list of eligible wastes in the LCHS, though evidence may need to be provided for fossil wastes where a counterfactual has not already been provided (see Chapter 5 for further detail). Legal requirements around the use of waste, including the application of the waste hierarchy, apply separately.

QES11: Can a 5MW HHV project be split across based at 3 (or multiple) different locations? Will this be treated as one project?

The 5MW threshold applies to individual projects and should comprise one single facility in a single location. Projects will not be able to aggregate capacity across different locations.  

QES12: A project of 5MW HHV minimum capacity could comprise both volumes supported by RTFO and HAR2 - correct?

Producers in receipt of Hydrogen Production Business Model (HPBM) support will be allowed to participate in the Renewable Transport Fuel Obligation (RTFO). Some volumes produced will be allowed to be claimed under the RTFO, subject to meeting the RTFO’s eligibility criteria, but claiming under both the HPBM and RTFO for the same volumes of hydrogen will not be permitted. Specific reporting, monitoring and enforcement arrangements guarding against producers claiming under both schemes for the same costs will be included in the Low Carbon Hydrogen Agreement (LCHA).

Applicants who intend to seek support under both the RTFO and HPBM will need to demonstrate that the project is capable of meeting all of the HAR2 and RTFO eligibility criteria, including the 5MW (H2 HHV) minimum hydrogen production capacity. Further detail on RTFO evidence is set out in Section 3.5.10 of the Application Guidance.

QES13: The guidance states projects should be able to support a potential heating trial. Is this a requirement for all projects, or more of a desirable attribute?

If the former, could you elaborate on the required evidence to demonstrate this has been accounted for?

It is not a requirement of HAR2 for projects to be able to support potential hydrogen heating trials, or something projects will be scored favourably for. This guidance is for projects which are considering supporting a government hydrogen heating trial. In these instances, government will consider evidence of progress towards an agreement to supply hydrogen to heating trials to be acceptable evidence of offtaker demand for those volumes of hydrogen for the purpose of the Deliverability assessment. Please see Section 3.6.2, page 42 of the HAR2 Application Guidance for information on the extra provisions these projects will be required to think about when applying, to score well under the Deliverability criterion.

QES14: Can you say any more about how cost maturity will be factored into the cost assessment? I.e. will more mature costs / lower AACE classes score more highly? 

Supporting evidence provided should both justify your cost estimate and the cost class you provide against each line item. Where evidence isn’t provided to support a given cost class, we may adjust our view of what the cost class should be and therefore our estimate of how uncertain that cost is when generating scores. We do this to make sure projects can’t just state that their costs are very low and certain without justifying evidence.

QES15: For the economic benefits template and location of equipment supply, we may not be able to say where we are getting all of our equipment from at the time of application, and therefore may not be able to provide a postcode. This is due to FEED ongoing. Where projects aren’t able to provide a specific postcode at this time, how do you envisage projects will answer this? It is unlikely that projects will know this information at this stage. Can we estimate and say where we think items will be sourced from but this would be subject to change?

We understand that projects may not have certainty on supply locations for all line items depending on stage of project development. Projects should complete the economic benefits tab based on their current understanding of where they expect to source components from. Projects will be scored more favourably if supporting evidence can be provided confirming the expected sourcing of these components (e.g. evidence of engagement with suppliers, cost quotes).

QES16: In Supply Chain section, is there credit given for maximising local / UK content?

The government has an open market policy with respect to the Second hydrogen allocation round so we will not score more favourably for greater local/UK content. In the supply chain development section, we are looking to see that you are developing the supply chain for your project and giving proper consideration to its resilience, SMEs and skills.

QES17: Is there network map showing the current network constraints areas?

Within the HAR2 Application Guidance, we have included a section on Electricity Constraints in the wider network. Alongside this, a map which has been developed between DESNZ and National Grid ESO shows the network constraints areas in GB (Figure 1).

The following transmission system boundaries divide the zones in Figure 1:

• Boundary B2 divides zones A-B
• Boundary B6 divides zones B-D
• Boundary B7a divides zones D-E
• Boundary B8 divides zones E-F
• Boundary EC5 divides zones F-C

Please see slide 15 of the Electricity Ten Year Statement (ETYS) 2022 for a map which sets out these boundaries. ETYS 2022 can be found under the heading ‘What’s new in ETYS 2023’.

Clarification questions, 2 February 2024

Q013: In instances where the hydrogen will be used to replace fossil fuels other than natural gas such as coal, will there be scope to revise the ‘gas reference price’ to be the reference price of the fuel it is replacing?

If yes, what will the process be to determine when this is appropriate?

The Reference Price is intended to represent the market price received by the producer for each unit of hydrogen (note, sales of hydrogen for feedstock purposes have a different reference price floor). In the absence of a market benchmark price for hydrogen (low carbon or otherwise), the draft Low Carbon Hydrogen Agreement (LCHA) sets out a Reference Price comprising the producer’s Achieved Sales Price, with a floor at the natural gas price (and a higher floor for feedstock purposes). We will seek to encourage the development of a market benchmark as the hydrogen market develops. We may make some updates to the draft LCHA for HAR2 and will engage with industry in due course on any proposals.

Q014: Is there a word limit on the mandatory information (such as the design intent document)?

There is no word limit for the mandatory information that needs to be submitted with the application. However, this information must be clearly referenced underneath the written response statement(s) it is being used to support, including where relevant, reference to specific sections or pages within the documentation. Lack of evidence, poor quality evidence, or large quantities of evidence that is not directly relevant to what is sought may negatively impact the assessment of projects.

Q015(a): This question is in relation to strike price.

Section 9 of the LCHA describes calculations of:

RP: Max (ASP, Floor Price), where RP is the Reference Price and ASP is the Achieved Sales Price

Floor Price: Min (SP, GRP) where SP is the Strike Price and GRP is the Gas Reference Price

Section 10 determines the DA or Difference Amount:

DA: (SP-RP) * Sum of Invoiced Qualifying volumes

If the DA is positive such amount shall be payable by the LCHA Counterparty to the producer
If the DA is negative such amount shall be payable by the producer to the LCHA Counterparty.

Could you provide some clarity on how the Strike Price is determined?

Our understanding is that the strike price will be determined based on CAPEX (electrolyser, compressor, balance of plant, FEED) and OPEX, with some exclusions, and then this will be reviewed by you.

But as an estimation exercise, once we have estimated the COST of the project, how do we obtain a reference strike price? Divide by yearly nominal output, output over the duration of the agreement, and so on?

Electrolytic projects can obtain a strike price using the below formula:

Electrolytic Strike Price (£/MWh H2 HHV) =

Total CAPEX (£) + Total NonElectricity OPEX (£) + Total Electricity Costs (£) + Total Cost of Capital (£)

divided by

LCHA Sales Cap (MWh)

Where:

• LCHA Sales Cap - The total H2 volumes expected to be sold to offtakers over the lifetime of the LCHA contract (15 years from COD).
• Total CAPEX (£) – The total CAPEX value of all strike price inclusion line items
• Total Non-Electricity OPEX (£) – The total value of all your non-electricity OPEX strike price inclusion line items over the lifetime of the LCHA contract
• Total Electricity Costs (£) – Weighted average electricity price (excluding any ineligible costs or strike price exclusions (e.g. policy costs)) multiplied by the total electricity volumes consumed over contract lifetime
• Total Cost of Capital (£) – The total return you are seeking to be included in your strike price. This should be based on a pre-tax real WACC.

The strike price will include CAPEX and OPEX for the facility, as well as an appropriate level of return on the capital invested in the project. Support through the HPBM may include revenue support for limited hydrogen transport and storage infrastructure, agreed on a project-by-project basis by taking several factors into account, including necessity, affordability and VfM. More specifically, this could include:

• the CAPEX, but not OPEX, costs associated with limited hydrogen transport infrastructure, and
• the CAPEX and/or OPEX costs associated with limited storage infrastructure.

Projects will be required to provide cost information throughout the agreeing an offer process to ensure projects meet minimum value for money requirements. These costs and information provided through the Request for Information (RFI) template will enable DESNZ to undertake due diligence. Final Strike Prices will then be determined through a bilateral process, with support assessed on a project-by-project basis taking into account several factors, including necessity, affordability and value for money.

At this point the strike price costs for the project will be locked in. Producers will be unable to change the strike price, unless through any predefined means in the LCHA.

Q015b: In relation to the Minimum Hydrogen Production Capacity, will a 5 MW electrolyser, connected to a fluctuating renewable feed, reach the required capacity of 5 MW H2 HHV? For example: Nominal capacity: 5MW. Load factor (average): 50%. Hydrogen production (approx.): 2,000 Kg/day. Will this comply or should we remove the load factor from the calculation?

Regarding Clarification Question Q004(b), it is stated that a maximum capacity of 3ton per day would infer a capacity of 4.93MWH2 HHV and would not be eligible for HAR2. Do we consider actual production volumes of 2ton per day as stated above and multiply by HHV, or just use the nominal capacity of 5MW for a 5MW electrolyser?

The eligibility criteria only relates to the instantaneous, maximum nominal capacity of the project – this must be at least 5 MW H2 (HHV). There is no eligibility criterion related to the amount of hydrogen produced. That said, the load factor will need to be sufficient to achieve a competitive strike price for the project.

Regarding question Q004(b), only the capacity of the project will be used to judge eligibility, not the amount produced. A project producing 2ton/day can still be eligible if their maximum nominal capacity is at least 5 MW H2 (HHV), due to the project’s load factor. The capacity of the project in H2 (HHV) terms will depend on the maximum nominal electrical capacity (MWe) and efficiency (% HHV) of the project.

Q016: With reference to Section 3.5.3 entitled “Using core technology that has been tested in a commercial environment”, relevant excerpt: “with a Technology Readiness Level (TRL) of 7 or more To be eligible to apply to HAR2, projects must be using core production technology that has been tested in a commercial environment, with a TRL of 7 or more.”

At what point in the HAR 2 application process should TRL 7 be reached? Should it be at this level prior to EOI, for example, or is it acceptable if the expected TRL 7 is reached at another point during the HAR 2 application process?

To be eligible to apply to HAR2, projects must be using core production technology that has been tested in a commercial environment, with a TRL of 7 or more. Projects are required to provide a relevant production technology specification and evidence to prove that at a minimum, TRL 7 ‘Integrated Pilot System Demonstrated’ has been successfully demonstrated when submitting their full application by 19 April 2024. Projects must confirm their selected technology meets TRL7 at the EOI stage, although they may proceed if this level has not yet been achieved.

Q017: If the strike price is set at £241/MWh which equates to £9,399 per tonne of hydrogen (at 39MW ie HHV) does this mean that the project will receive £9,399 per tonne of hydrogen produced?

The pricing appears to be compared in terms of MWh but what happens if the hydrogen produced only creates 33MW in the clients’ industrial process due to efficiency losses?

The achieved sales value with the customer will be based on the MWh consumed by them. If the hydrogen only provides 33MW then the sales value will be substantially less per tonne than the agreed strike price sales value but the shortfall will not be picked up if the calculation only looks at the sales price and ignores the volume shortfall.

Under the Low Carbon Hydrogen Agreement (LCHA), difference payments will be paid per MWh of qualifying hydrogen produced and sold. Payments will be made in the form of a variable premium, calculated as the difference between the ‘Strike Price’ and the ‘Reference Price’, the latter of which is the higher of (a) the producer’s ‘Achieved Sales Price’; and (b) the ‘Price Floor’, which is the lower of the natural gas price and the Strike Price (with a different Price Floor where the hydrogen is used for feedstock purposes). The payment enables the producer to achieve the necessary return for each unit of hydrogen over the lifetime of the contract (although the level of subsidy from the government will fluctuate).

Because payments are made per unit of hydrogen sold, the payment will therefore be made on the basis of the quantities of hydrogen reported on invoices to offtakers. In general, It is expected that producers will invoice offtakers for the quantity of hydrogen delivered to the offtaker’s site, rather than the energy realised through the offtaker’s own industrial process. Therefore, there should not be a significant shortfall between the quantity of hydrogen produced by the producer, and the quantity delivered and sold to an offtaker. The LCHA has not been designed to account for the energy efficiency of offtakers’ individual industrial processes.

Q018a: For the EoI submission, does the project representative also need to be the representative that submits the final application or will the expression of interest open the application form for everyone within the company?

The Online Application Form link will only be sent to the email address of the Project Representative that submits the EOI form, and they will be responsible for submitting the full application and all relevant Project Information.

The Project Representative can manage users on the Online Application Form and invite others to collaborate on the application - however it is recommended that the number of other users invited to collaborate is limited and their access rights are removed once they have completed their contribution. Users with the “Owner” or “Administrator” roles can complete questions, invite users, manage users, and submit the application. Users with the “Basic” role can only complete questions.

If you wish to invite someone who does not have an account on the applications service, you do not need to ask them to create an account before being invited. They will be sent instructions about creating an account when you invite them. It is your organisation’s responsibility to verify the work of any collaborators.

Q018b: Also for the EoI submission, is it possible to submit an expression of interest already, even while we are in discussion with project partners but can’t yet name them in the EoI form? Does that impact the type of “pre-qualification” achieved via the EoI submission. Furthermore, if due to not being able to input information at this stage, we receive feedback from DESNZ that some parts of the project seem to not yet fulfil the eligibility criteria, does that still qualify the EoI and open the application form for that specific project on February 6th?

Applicants may change the configuration of their project, including project partners, between the Expression of Interest (EoI) stage and submission of the final application. EoI answers are considered as indicative only and not as final responses.

The EoI stage gives DESNZ the opportunity to complete an initial eligibility check, and feedback may be provided if it appears that the project does not meet one or more of the eligibility criteria. However, projects will not be prevented from making a full application based on the information provided.

The Online Application Form link will be sent to the email address of the Project Representative once the EoI form has been submitted, regardless of Government’s view on whether the project may be eligible or ineligible from the information provided. If feedback has been provided, DESNZ encourages projects to consider this when finalising project configuration as part of your final submission. The final submission which is due by 23:59 on 19 April 2024, will require you to provide evidence to prove your project meets the eligibility criteria.

Q019a: If we were successful with HAR2 and gaining a contract under the HPBM, is this a standard 15 year contract for price support or award on a case by case basis?

Also, are there penalties should we wish to terminate early for any reason?

The contract term set out in the draft Low Carbon Hydrogen Agreement (LCHA) is 15 years for all technologies and project sizes with capital repayments spread evenly across the term. The primary reasons are that it reflects a reasonable amount of time for a market for low-carbon hydrogen to emerge, and it is long enough to secure private sector financing.

Similarly to the renewable Contracts for Difference, Industrial Carbon Capture Contract or Dispatchable Power Agreement, there is no termination right for the Producer in the LCHA, as the LCHA is a mechanism to provide a subsidy to the Producer.

We may make some updates to the draft LCHA for HAR2 and will engage with industry in due course on any proposals.

Q019b: If we decide HAR3 is better for us to wait for timescale wise, is there any benefit in us still submitting an EOI by the 6th Feb for HAR2?

We think we would meet the submission criteria. Just wondered if worth still submitting an EOI for feedback etc.

To be considered for an application to HAR2, a Project Representative must first submit an Expression of Interest (EoI) to government on behalf of their project by 23:59 on 5 February 2024. Submission of the EoI form is a necessary condition for participation in HAR2 and projects should only submit an EOI based upon their intention to participate within HAR2.

Government may provide feedback to Projects at the EoI stage if it appears from the information provided that a project does not meet one or more of the eligibility criteria. 

Q020: Can you please clarify the TRL7 eligibility criterion. The HAR2 guidance states that “To be eligible to apply to HAR2, projects must be using core production technology that has been tested in a commercial environment, with a TRL of 7 or more. This criterion ensures our funding picks up where DESNZ innovation funding ends.”

Does an applicant have to demonstrate how they meet this criteria by the closing date for applications (19/4/24) or by the date project delivery commences?

To be eligible to apply to HAR2, projects must be using core production technology that has been tested in a commercial environment, with a TRL of 7 or more. Projects are required to provide a relevant production technology specification and evidence to prove that at a minimum, TRL 7 ‘Integrated Pilot System Demonstrated’ has been successfully demonstrated when submitting their full application by 19 April 2024. Assessors will complete an eligibility check following submission of applications to confirm the application meets the defined eligibility criteria. Those that are considered to meet the eligibility criteria will proceed to evaluation.

Q021: Does the Environment Agency information in Annex A of the HAR2 Application Guidance   apply to potential applicants in Wales?

In Wales, the Environmental Regulator is Natural Resources Wales, who advise that the Environmental Principles and processes are broadly aligned with those set out in the Environment Agency information.  Please contact the NRW industrial decarbonisation team [email protected] for case-specific guidance, and application information.

Q022: The HAR2 DESNZ decision and Contract award is stated in various HAR2 documentation as “early 2025.”

Please can you clarify what is meant by “early 2025” and ideally share current target month for this?

The dates set out within the Application Guidance are indicative. At this stage, we are unable to confirm when Contract Award will take place.

Q023a: EoI question 1b requires the applicant to provide the address (including postcode) of the project plant. If a project has yet to select its location out of several potential locations all within close proximity to each other how should this field be handled?

EoI answers are considered as indicative only and not as firm responses, however Applicants should use the EoI form to indicate all potential locations for their plants. Applicants may change the configuration of their project set up including the location of project plant between the EoI stage and submission of the final application.

Supporting evidence to demonstrate eligibility is only required when submitting final applications. Applicants must ensure the Eligibility Cover Page is completed within Annex A – Project Datasheet, and must provide and reference evidence for each Eligibility Criteria to support your submission.

Q023b: I understand that answers provided in the EoI are not binding at this stage, and answers to questions such as intended Delivery Year and Commercial Operations Date can be amended later?

Yes, Applicants may change the configuration of their project set up including the Intended Delivery Year and Commercial Operation Date between the EoI stage and submission of the final application.

Q023c: Section 3 of the HAR Guidance explains that “a business can lead on up to six applications” but I believe I have heard it communicated verbally during an engagement session that there is no limit on the number of EoIs that can be submitted? I cannot find this written down anywhere so would appreciate confirmation of this point.

There is no limit for Expression of Interest form submissions. The limit stated in the application guidance, that a business can lead on up to six applications, which must be materially different, and can be included as a collaborator, or project partner, in a further six applications, applies to the full application submission only.

Clarification questions, 22 January 2024

Q005: Regarding the splitting of gas producing solid carbon: Would gas splitting of Biomethane with carbon in liquid form qualify under this scheme? The biogenic liquid will be utilised in food, beverage and other industries displacing conventional sources and offering more available volume in a decreasing UK market.

No, gas splitting producing carbon in liquid form is not eligible under HAR2. To be eligible to apply to HAR2 a project must be using one of the eligible technologies listed under section 3.5.5. of the application guidance. This includes gas splitting producing solid carbon, where the carbon produced must be in solid, but not liquid form.

More detail about different technologies and relevant requirements can be found in the Low Carbon Hydrogen Standard (LCHS). If you have further questions about how your project may fit with the LCHS, please contact [email protected]. However, note that eligible technologies are indicated in the HAR2 application guidance - there are some technologies which are covered by the LCHS but not eligible under HAR2.

Q006(a): Will it be possible to engage / ask questions to DESNZ in between phases and outside the formal engagement sessions e.g. between 6th February and 19th April 2024? And, if yes, will DESNZ be able to provide swift replies to perspective applicants and what is the expected response time?

As set out in section 2.3 of the application guidance, projects can submit Clarification Questions on the application process to DESNZ by emailing HAR2@energysecurity.gov.uk. Government will publish the question and the response provided, with all identifying data anonymised. We aim to publish responses to clarification questions within 10 working days. The deadline for the submission of clarification questions is 23:59 on 22 March 2024, ahead of the submission window closing on 19 April 2024.

Q006(b): To what extent do you expect the deadlines for the application stages set in section 1.4 (pages 14 and 15) to be rigid?

We have set out the timeline for each stage of HAR2 to the best of our knowledge and we do not anticipate that the timeline for the application window will change. However as stated in the application guidance dates are indicative, and government reserves the right to alter these timelines at any stage in the process.

Q006(c): Can the additionality criteria 1. ‘New purpose-built assets’ be met by an electrolyser that takes electricity from the grid if this is linked to an unsubsidised new RES plant via an eligible PPA? Or does there need to be a direct connection between the RES plant and the electrolyser?

Links to new purpose built assets can be proven either via physical link i.e. a private wire connection, or through the grid via a PPA, provided this PPA covers physical delivery of electricity via the electricity transmission and distribution network.

Supporting evidence will be required to prove the links to this additional asset, including:

• Indicative PPAs with specific generators
• A breakdown of % of additionality electricity from generation sources
• Schedules for delivery of generation assets being claimed as additional.

The scores will be determined based on the; i) percentage of the facility’s overall electricity demand being supplied by additional sources; and ii) the quality of the evidence to prove this additional electricity will be delivered to the site.

Q006(d): Can the additionality criteria 3. Extension of the life of existing assets” be met by an electrolyser that takes electricity from the grid if this is linked to a life extended RES plant via an eligible PPA? Or does there need to be a direct connection between the RES plant and the electrolyser?

As per the above, additionality can be via physically linked private wire or through the grid via a PPA, provided the criteria are met.

Q006(e): We are unclear on what score would be given to a project that falls partially under different score descriptions in the table. We are unclear on aspects of the scoring criteria: how would the project be scored if it is able to show partial evidence to achieve a high score? Would the project be scored on the maximum score where the project demonstrates all criteria or is the project scored proportionally to all criteria. For example, a project demonstrates one of the criteria sufficiently in a category of 5 however, does not fulfil the second bullet but fits in category of 4. Will the score be 4, 4.5 or 5?

Projects will need to meet the descriptions for a score in full to be awarded it. For example, to score a 5, projects will need to provide clear evidence that it meets both categories i.e. the project will have a full portion of electricity input sourced from additional generation and will be located in the regions with the most positive impact on the electricity network. It is not possible to score a 4.5. If a project is located in the regions with the most positive impact on the electricity network but has a good portion of electricity input sourced from additional generation, and not a full portion, then it will score a 4.

Q006(f): Can DESNZ provide more clarity on the boundaries of Figure 1 regarding positive impact scoring on the electricity grid?

The following transmission system boundaries divide the zones in figure 1:

• Boundary B2 divides zones A-B
• Boundary B6 divides zones B-D
• Boundary B7a divides zones D-E
• Boundary B8 divides zones E-F
• Boundary EC5 divides zones F-C

Please see slide 15 of the Electricity Ten Year Statement (ETYS) 2022 for a map which sets out these boundaries. ETYS 2022 can be found under the heading ‘What’s new in ETYS 2023’.

Q006(g): Service providers (FEED / EPC / HSE) may use teams with expertise drawn from a variety of business premises (UK and international) and flexible working arrangements. It may be that no single postcode is providing “the majority” (>51%) of the work. Would it be acceptable to provide “the largest proportion by invoice value”?

In column H, the source (e.g. UK domestic vs. imported) should refer to where the majority of the work is taking place. If the majority (50% +) of the work is taking place outside the UK, then imported should be selected in column H, and no postcode should be provided in column I. If the majority of the work is taking place inside the UK, then the approach you have proposed is correct (i.e. use the postcode where the largest proportion of the work is taking place, even if this postcode accounts for less than 50% of the total work).

Q006(h): If a Project may have the option to ‘use’ but not necessarily ‘rely on’, not yet operational generation assets, are development plan details required? This could be a disproportionately large volume of supplementary information.

Projects must provide a portfolio of electricity sources that can supply the total project capacity. Where a source requires generation assets or private wire / connection infrastructure that is not yet constructed, the project should detail development progress and/or credible plans that align with the project requirements to score highly.

An electricity source which is not ‘relied upon’ to make up the total project capacity but is instead a secondary ‘option’ is not essential to project operation. Hence while development plans for such sources may provide further confidence in project deliverability, they are expected to be less detailed if provided and are not necessary to score highly on this question.

Please provide all mandatory evidence noted in the application form. Provision of further supplementary evidence can help us validate the credibility of project plans, however DESNZ recognise the importance of quality information over quantity, for both the evidence provided and the accompanying application form narrative.

Q006(i): Where additionality is due to projected curtailment of (e.g.) renewable assets, does DESNZ have a preferred scenario for these projections?

Where additionality is being claimed for otherwise curtailed electricity from a specific asset, we would expect this to either be a co-located generation asset or for there to be an indicative PPA in place for the use of otherwise curtailed electricity from the specific generation asset. Evidence would be provided in the form of modelling of projected excess volumes from the specific linked asset, including an indicative contract for the utilisation of these volumes by the hydrogen production facility.

Q006(j): More clarity would be welcome on whether a project would score higher if a higher proportion of CAPEX comes from UK suppliers, therefore supporting UK jobs.

The government has an open market policy with respect to the Second Hydrogen Allocation Round so that suppliers from other countries should not be discriminated against. It is therefore not the case that a project with a higher proportion of CAPEX coming from UK suppliers will be directly allocated a higher score for the economic benefits proportion of the Economic Benefits and Supply Chain Development criterion. Scores for this criterion instead will be based on the economic benefits estimated to be generated by the jobs supported by a project, and the economic benefits will vary based on the region of the UK where those jobs are located. We expect that all applicants should be able to demonstrate economic benefits due to projects being located in the UK, and this accounting for a significant proportion of their jobs.

Q007: Do you know whether the limit of 6 applications for HAR2 also applies to the EoI stage, or would we be able to submit more than 6 EoIs which could then be trimmed down for the application stage?

There is no limit for Expression of Interest form submissions. The limit stated in the application guidance, that a business can lead on up to six applications, which must be materially different, and can be included as a collaborator, or project partner, in a further six applications, applies to the full application submission only. In the event a business submits more than six full applications, the first six applications submitted will be reviewed and assessed only. Any subsequent full applications beyond that will not be accepted.

Q008: Are you able to provide any guidance regarding the level of potential return which might be available to bidders under the CfD model.

In particular, what is the IRR or potential equity return anticipated for developers under HAR2? In the case of equity return, we would like to understand whether any figures assume specific debt/gearing levels.

We are not in the position to comment on the returns expected from investors. DESNZ run a competitive allocation round which aims to select projects which are deliverable and affordable for contract award. 

Q009: Please can you confirm how many tonnes of hydrogen production is targeted by the target 875MW of hydrogen production capacity?

Also, how many tonnes of hydrogen you expect a 5MW HHV facility to produce?

The government target is based on capacity, not amount of hydrogen produced. As per section 3.5.8 of the Application Guidance, the 5MW threshold refers to the minimum nominal hydrogen production capacity and must be at least 5 MW of hydrogen (in Higher Heating terms), before load factor or plant availability are taken into account.

While there is no target for the amount produced from a 5 MW HHV facility, each project requires a load factor that enables them to achieve a competitive strike price for their specific configuration/requirements.

Q010: As part of the eligibility criteria for HAR2, projects will need to be led by ‘a UK registered business’. Could I confirm the evidence required to support this? Would this consist of registered address in the UK and company number? Would financial statements for a set period of time also be required?

In addition, would a UK based subsidiary of a company be eligible to lead a HAR2 project? If so, would staff from the parent company (based outside of the UK) be eligible to participate in the project delivery?

Mandatory evidence requirement in respect of this eligibility criterion is a UK company registration number. Projects will also need to provide a location plan of the proposed facility, including a postcode. DESNZ does not place any restriction relating to project’s workforce in the process of delivering and managing the project. Further information on mandatory evidence requirements for each eligibility criteria can be found in Annex A – Project Datasheet.

As set out in section 3.5.1 of the Application Guidance, the application must be led by a UK registered business. To lead a project or work alone, your organisation must be a UK registered business of any size. A business is defined as an enterprise undertaking economic activities. Academic institutions, research and technology organisations (RTOs), public sector organisations or charities cannot lead or work alone. A project would be ineligible if it was led by an organisation domiciled in a country outside of the UK. In order for the project to be eligible, the lead applicant must be a business incorporated in the UK.

Q011: Please could you confirm our understanding that the allocation of carbon emissions to solid carbon output as a co-product is currently ruled out under the LCHS?

This is based on our reading of para 5.59 of LCHS v3.

We can confirm your understanding is correct that the allocation of carbon emissions to solid carbon output as a co-product is currently ruled out of the Low Carbon Hydrogen Standard (LCHS). The emissions relating to the solid carbon will be the hydrogen producer’s responsibility and therefore cannot be claimed as a co-product.

In version 3 of the LCHS, gas splitting producing solid carbon was added as an eligible hydrogen production pathway with a condition of standard compliance that the hydrogen production facility must use the solid carbon output in a permissible end use (incorporated into cement/concrete and kept in inert underground storage). Solid carbon arising from biogenic inputs which meets the conditions of the LCHS shall be assigned a sequestration credit of 3.664 gCO₂e/gC for this new emission category. This will significantly lower the overall GHG Emission Intensity of the Hydrogen produced, potentially being negative.

Q012: Has the question in Annex A regarding the grid reference to be answered in relation to the map given on page 54 of the application guidance notes. Ie between A and F or is there some other guidance available?

In the HAR2 Application Guidance Document, Section 3.6.5, ‘wider electricity system benefits’ sets out the guidance for locational scoring for electricity system impacts. During assessment, projects will need to provide their location, which will be assigned to the relevant region of GB as based on the map set out in figure 1. Projects will be scored based on this region, with region A scoring highest and region F scoring lowest, based on the level of positive impact of their project location on the electricity system.

Clarification questions, 10 January 2024

Q001: We are going through a process of bringing in a project partner for our HAR2 projects which will require an SPV at some point. Can we make the EOI under the company name and then make a submission in April under the name of the SPV of which we will be a shareholder?

Yes, applicants may change the configuration of their project set up between the EOI stage and submission of the final application, but the Project Representative who is responsible for submitting the full application is expected to still be part of the venture as either a partner or from the primary organisation responsible for project development.

As stated on page 18 of the Application Guidance, to be considered for an application to HAR2, a Project Representative must first submit an Expression of Interest (EoI) to government on behalf of their project by 23:59 on 5 February 2024. The Project Representative is expected to be from the primary, or partner, organisation responsible for Project development which must be a legal entity. The Online Application Form link will be sent to the email address of the Project Representative, and they will be responsible for submitting the full application and all relevant Project Information. 

Q002: In the low carbon hydrogen standard published in December 2023, Biogenic Gas Reforming is an eligible Hydrogen Production Pathway. However, within the HAR2 scheme overview, there is only a reference to gasification and pyrolysis. Please can you confirm that Biogenic Gas Reforming is an eligible pathway for HAR2?

Biogenic Gas Reforming is not an eligible production technology for HAR2. The technologies outlined in section 3.5.5 of the Application Guidance are eligible to apply to HAR2. This includes:

• electrolysis – defined as splitting water into hydrogen and oxygen using electricity
• gasification/ pyrolysis of biomass/ wastes without CCS – defined as the thermochemical decomposition of solid or liquid biomass or waste feedstocks in the presence of limited or no oxygen
• gas splitting producing solid carbon – defined as the heating or ionisation of fossil/biogenic hydrocarbon gases, to generate hydrogen and solid carbon

Q003(a): Is there any formal appeal route if an applicant is deemed non eligible or is later excluded from the process?

There will be no formal appeals route in HAR2 to ensure integrity of the competition timelines, as was the case in HAR1. Feedback will be offered to all projects that are not successful in the HAR2 process. Projects that are deemed ineligible will be offered feedback that details the reason(s) why they were ineligible.         

Q003(b): I noted the Grid diagram of the UK to determine where the need for bolstering the network.  This seems remarkably simplistic and in effect disadvantages any project located in the SW, SE and Midlands.  That cannot be right.  There are grid constraints in the SW as we know.  Will it be purely looking at this map or will there be a more meaningful test?

The Wider Electricity System Benefits criterion is weighted at 10% of the evaluation criteria. Scores across Additionality and Network Constraints will be combined to give a total Wider Electricity System Benefits score. Deliverability (40%), Cost (30%), and Economic Benefits and Supply Chain Development (20%) make up the other 90% of the evaluation criteria. The electricity network constraints score is unlikely to disadvantage projects located in unconstrained regions in the competition as other criteria have a much higher weighting.

We have expanded the Wider Electricity System Benefits criteria to incentivise projects that locate in beneficial areas for electricity network constraints, following positive stakeholder feedback. The electricity network constraints score will be determined using the map developed by DESNZ in collaboration with National Grid Electricity System Operator (ESO). As set out in the HAR2 Application Guidance, the map scoring is based on estimated curtailed electricity volumes from ESO constraints analysis. GB regions will be scored proportionately to the amount of curtailed electricity in each region, so constrained regions will score more favourably  than unconstrained regions on location. 

Whilst we recognise all GB regions will experience network constraints to some extent, projects that locate in regions behind the most common networks constraints will have the most significant positive impact on the electricity network.      

The Wider Electricity System Benefits criterion will continue to incentivise projects that use additional electricity (as defined by our principles of additionality) that help to reduce electricity system impacts and may help to bring forward new generation that wouldn’t otherwise have been available, regardless of where they are located. The total score for this criterion will be a combination of the network constraint location and additionality scores.  

Q004(a): I work at a farm-based biogas plant and I have been working on a business plan to diversify our production and have recently come across the idea of green hydrogen. Over the last 2 months I have been making connections with potential offtakers, technology suppliers and so on with a view to producing hydrogen on-site through biomethane pyrolysis or steam methane reforming. We are interested in applying for the HAR2 but have some queries about our eligibility, would you be able to help?

Firstly, it mentions in the eligibility criteria that biogas plants that already have CCUS technology in place are ineligible. We process and use our CO2 into biogenic CO2 for use in the food and drinks sector. I was wondering whether we would therefore be ineligible and if so, why this was the case?   As it does make us carbon neutral/carbon negative, which is better from an emissions standpoint.

As set out in the government response to the HAR2 Market Engagement document and the HAR2 application guidance, projects developing carbon capture and storage (CCS)-enabled hydrogen production plants are not eligible to apply to HAR2 but may apply for Hydrogen Production Business Model support via the Cluster Sequencing process (find further information on the Cluster Sequencing process).

However, carbon capture and usage (CCU)-enabled plants which do not require CO2 storage - for example a hydrogen production project using a low carbon feedstock that intends to use carbon capture technology and sell the resulting CO2 - may be eligible to apply to HAR2, subject to meeting all other eligibility requirements. In this case, the project could only apply for support on costs associated with the new-build hydrogen production plant, and not on any costs associated with the carbon capture technology.

Q004(b): Secondly, it mentions that applicants must have intentions to build an additional 5MW of hydrogen capacity. In terms of scale, is this 5MW per day or per year? Just to get a rough idea of whether we are in the right ballpark…

I have done some calculations and believe we could produce between 3-8 tons of hydrogen per day, depending on how much biomethane we use, but I’m not sure how this would translate to MW.

As per section 3.5.8 of the Application Guidance, the 5MW threshold refers to the ‘nominal’ maximum capacity of hydrogen production and must be at least 5MW H2 (Higher Heating Value terms), before load factor or plant availability are taken into account. If the plant was operating at maximum capacity all day and producing 3 tons per day, this would infer a capacity of around 4.93 MW H2 (HHV), which would not be eligible for HAR2.