Hydrogen in Scotland

Hydrogen In Scotland

The Role of Acorn Hydrogen in Enabling UK Net Zero

Element Energy July 2020

Element Energy Limited, Suite 1, Bishop Bateman Court, Thompson’s Lane, Cambridge, CB5 8AQ, Tel: +44 (0)1223 852499

Hydrogen in Scotland Final report

Authors

This report has been prepared by Element Energy, a strategic energy consultancy, specialising in the intelligent analysis of low carbon energy. The team of over 60 specialists provides consultancy services across a wide range of sectors, including the built environment, carbon capture and storage, industrial decarbonisation, smart electricity and gas networks, energy storage, renewable energy systems and low carbon transport. Element Energy provides insights on both technical and strategic issues, believing that the technical and engineering understanding of the real-world challenges support the strategic work. For comments or queries please contact: Emrah Durusut Associate Director [email protected] Silvian Baltac Senior Consultant [email protected] Enrique Garcia-Calvo Conde Consultant [email protected]

Acknowledgements

We would also like to convey our thanks to the following individuals for valuable input to the study: Dewi ab Iorwerth, Commercial Adviser, Pale Blue Dot Energy Tim Dumenil, Creative Spirit & Hydrogen Project Manager, Pale Blue Dot Energy Jack Gomersall, Futurist, Pale Blue Dot Energy Sam Gomersall, Hydrogen Champion, Pale Blue Dot Energy Ian Phillips, Transition Energiser & Acorn Hydrogen Project Director, Pale Blue Dot Energy Clare Lavelle, Head of Energy Consultancy, ARUP Jacob Kane, Senior Consultant, ARUP Mike Dolman, Associate Director, Element Energy Richard Riley, Principal Consultant, Element Energy Chris Bronsdon, Chief Executive Officer, Eneus Energy Kevin Kinsella, Senior Partner (Energy Transition), Environmental Resources Management (ERM) Mike Smith, Chief Executive Officer, North East CCUS (NECCUS) Dagmar Droogsma, Director of Industry, Scotch Whisky Association (SWA) Peter Clark, Deputy Director of Industry, Scotch Whisky Association (SWA) David Holman, Hydrogen & CCUS Lead, Scottish Enterprise Stuart McKay, Head of Carbon Capture and Storage, Scottish Government Phil Bradwell, Energy Futures Manager, SGN Mike Copson, Hydrogen Business Development Manager, Shell Mark Jessop, Senior Project Manager, Low Carbon Technology Development, SSE Patrick Little, Chief Process Engineer, Lead Process, Total Glyn Waterhouse, Lead Architect, Development Lead, Total Niki Mackenzie, Business Negotiation Lead, Total Mark Tandy, Business Manager, Total Disclaimer

This study was commissioned by the Acorn Consortium led by Pale Blue Dot Energy and comprising of industry participants Chrysaor, Shell and Total. As part of the Hydrogen Supply Competition Phase 2’s Acorn Hydrogen project, this study is funded by the UK Government’s Department of Business, Energy and Industrial Strategy (BEIS) with match funding from the industrial participants. The conclusions and recommendations do not necessarily represent the view of the commissioners. Whilst every effort has been made to ensure the accuracy of this report, neither the commissioners nor Element Energy warrant its accuracy or will, regardless of its or their negligence, assume liability for any foreseeable or unforeseeable use made of this report which liability is hereby excluded.

Hydrogen in Scotland Final report

Executive Summary

Introduction In 2019, the Climate Change Act, approved by the Scottish Government, set the ambitious target to achieve a carbon neutral Scotland by 2045, five years earlier than the UK Net Zero target. To accomplish these targets, the Committee on Climate Change (CCC) has identified hydrogen and carbon capture, utilisation and storage (CCUS) as indispensable technologies for the transition, highlighting the importance for a paced deployment of these technologies beginning in the 2020s. An early roll-out of these technologies is expected to lay the groundwork for additional future decarbonisation projects. The North Sea represents a unique asset to enable the UK and Scotland to meet their Net Zero targets whilst providing energy security. Historically, it represented the main source of oil and gas, powering the UK’s economy. More recently the uptake of offshore wind producing clean, renewable electricity has placed the North Sea at the centre of the decarbonisation agenda. During the transition to Net Zero, the North Sea will continue to be at the epicentre of decarbonisation. The extensive potential for renewable energy generation and the presence of major subsurface CO2 storage sites offer the unique opportunity to develop a Scottish economy where renewables, hydrogen and CCUS coexist and complement each other. Paving the way to Net Zero by using resources from the North Sea, the Acorn Hydrogen and Acorn CCS projects are expected to be the first large-scale hydrogen and CCS projects to be developed in Scotland. Acorn Hydrogen would be located at the St Fergus Gas Terminal, where currently 35% of the UK’s annual gas supply enters the National Transmission System, before being transported across the country for consumption. The Acorn Hydrogen project is initially planning the construction of a circa 200 MW hydrogen production plant, that could become operational by 2025, and which would allow for a 2% hydrogen blend into the National Transmission System (NTS). The emissions from the hydrogen production would be captured, transported, and safely stored in a depleted hydrocarbon reservoir, reusing current oil and gas (O&G) infrastructure, enabled by the sister project, Acorn CCS. This study examines the role that the Acorn Hydrogen project could play in unlocking Net Zero in Scotland and the UK. The Acorn Hydrogen project is one of the key large scale hydrogen projects on the UK path to Net Zero. The project is also highly scalable, due to large volumes of natural gas feedstock available, the massive offshore CO2 storage capacity and the availability of existing offshore pipeline infrastructure. This means that large volumes of hydrogen can be generated in the 2020s and beyond, offering an opportunity to establish hydrogen infrastructure before other complementary decarbonisation technologies reach scale.

Hydrogen in Scotland Final report

Three hydrogen growth scenarios for delivering Net Zero in Scotland There are multiple pathways in which Scotland can deliver a Net Zero economy and there continues to be debate around which pathway may eventually be pursued. However, it is widely recognised that hydrogen and CCS have a key role to play in all pathways. In order to characterise and define what the role for hydrogen (and consequently the role for Acorn Hydrogen) may be in a transitioning Scotland, three hydrogen growth scenarios have been examined. The three scenarios vary in their scale, scope and ambition.

The Regional Growth scenario explores a multifaceted role for Acorn Hydrogen, in which hydrogen is injected into the NTS to help decarbonise the gas network, as well as serving as a vector for regional decarbonisation. Hydrogen would be supplied to Aberdeen City and the wider Aberdeenshire region via a dedicated pipeline in order to decarbonise domestic and commercial heating and enable hydrogen mobility through conversion of the regional gas grid. Hydrogen would also be supplied to Peterhead Power Station (PPS). In addition, the Grangemouth industrial cluster would have its own supply of hydrogen to support industrial decarbonisation, enabled by CO2 transport and storage infrastructure deployed at St Fergus. Most of the infrastructure deployment is focused in the short and medium term, and demand reaches 19 TWh/year by 2050. The Scottish Hydrogen Economy scenario builds on the expertise gathered through the regional deployment of Acorn Hydrogen, using these learnings to expand outwards and helping roll-out a hydrogen economy across Scotland. Hydrogen is adopted in the same sectors as in the Regional Growth scenario (industry, power generation, heating, and transport) but at a Scottish level, while the national hydrogen outreach allows for decarbonisation of 20% of the energy demand from the distilling sector. The infrastructure needs for a nation- wide transition to a hydrogen economy are more complex, as hydrogen would need to be transported from different points of production to demand sites. In this scenario, the role of Acorn is both regional (as in the first scenario) but also serves as an enabler for other hydrogen projects. Both blue and green hydrogen coexist and complement each other in this scenario and meet a total demand of 72 TWh/year in 2050. The European Outreach scenario reflects a Scottish hydrogen economy, but also envisages Scotland as an important exporter of hydrogen. Although there is an ongoing discussion regarding the advantages of the different options for exporting and storing hydrogen, ammonia has been chosen as the hydrogen carrier to meet export demands to other regions of the UK and to continental Europe. Infrastructure is deployed to account for the additional demand, such as both blue and green hydrogen production capacity and elements needed for the ammonia value chain necessary to support international trade. The scenario leverages Scotland’s maritime infrastructure, acknowledging that the proximity of Peterhead Port to St Fergus means that it could play a major role in international trading. In 2050, the total annual blue and green hydrogen demand would be of 121 TWh/year, of which 48 TWh/year are exported. The three scenarios would require the conversion of the corresponding regional distribution network, domestic heating appliances, build-out of hydrogen storage, and the installation of hydrogen refuelling stations (HRSs) across Scotland.

Hydrogen in Scotland Final report

Acorn Hydrogen could play an essential role in unlocking benefits across Scotland and the UK, including helping achieve Net Zero, driving economic growth, and developing both physical and intangible assets that could be leveraged in the longer term.

Reducing emissions

Conversion of hydrogen into power and heat is free of any CO2 emissions at the point of use. Producing hydrogen with CCS as planned for Acorn Hydrogen enables production of low carbon hydrogen where CO2 emissions are captured and stored. This ‘blue hydrogen’ - along with ‘green hydrogen’ generated via electrolysis from renewable electricity - are two key energy vectors to enable Net Zero. The adoption of hydrogen in the different sectors of the Scottish economy (industry, power, heat, and transport) will bring decarbonisation benefits as CO2 emissions are eliminated. For example, from heating alone, 9 MtCO2/year could be avoided by hydrogen replacing the equivalent amount of natural gas used by domestic and non- domestic users in Scotland (48 TWh/year in 2018). In addition, hydrogen mobility would bring additional air quality benefits, thanks to reductions in particulate matter (PM) and NOx emissions that fossil fuels would otherwise emit in internal combustion engines. Beyond reducing emissions, Acorn Hydrogen could create economic benefits and unlock long-term growth in Scotland while helping to catalyse the Net Zero transition.

Unlocking economic growth: thousands of jobs could be created Large-scale adoption of hydrogen would also result in economic growth and long-term job creation across the hydrogen supply chain. The macro-economic benefits of a Scottish hydrogen economy would be multiple and would cover several sectors, ranging from hydrogen production through reformation and CCUS, to gas grid conversion, and spanning to production and operation of electrolysers and deployment of off-shore wind. This study estimates the economic benefits related to the development of Acorn Hydrogen, for example through key infrastructure that would enable a future Scottish hydrogen economy. The figures below refer to the deployment of blue hydrogen production, CCUS, conversion of the gas grid across Scotland following the learnings acquired through Acorn Hydrogen, hydrogen storage, and hydrogen refuelling infrastructure. The eventual large-scale uptake of green hydrogen, as a complementary and essential decarbonisation vector, would reuse and further expand this infrastructure, bringing additional benefits beyond those quantified below. In the Regional Growth scenario, benefits are limited to a regional level. Up to 13,000 jobs will be required in the year of peak investment in 2036. By 2050, this scenario would have added a cumulative of £8.6bn in Gross

Hydrogen in Scotland Final report

Value Added (GVA) to the UK economy. In 2050, the operation of infrastructure would support 2,500 total jobs and bring over £202m/year to the economy. The national outreach of the Scottish Hydrogen Economy scenario would also bring key benefits, such as the creation of 21,200 jobs to support the peaking growth of hydrogen in 2040. By 2050, a cumulative of £15.6bn in GVA would have been generated, of which £400m/year would arise in 2050 alone. In addition, long term operation would require 2,700 direct jobs and 2,500 indirect jobs in 2050 in this scenario. The positioning of Scotland as an important exporter of hydrogen in the European Outreach scenario would also contribute considerably to the economic benefits. Relative to the Scottish Hydrogen Economy scenario, building and supporting the exports infrastructure in the year of maximum growth (2040) would add 7,700 jobs, bringing the maximum total number of created jobs to 28,900. We estimate that in the long term, 4,200 direct jobs and 3,900 indirect jobs would be created in 2050 in relation to the operation of infrastructure, adding an estimate of over £660m/year to the UK economy. By 2050, a cumulative GVA of £22.5bn would be generated for the UK economy.

As mentioned above, thousands of jobs could be created both in the medium and long term. These would represent opportunities for growth across the UK, especially in the aftermath of the Covid-19 pandemic.

Ensuring a just transition and long-term growth Acorn Hydrogen and Acorn CCS are planning on the reuse of existing oil and gas infrastructure and existing natural gas distribution networks and would therefore contribute to the continuity of Scotland’s legacy as a major provider of energy within the UK. This reuse is expected to provide major economic savings. Acorn Hydrogen and Acorn CCS would thus yield a cost-effective supply chain, where the cost of the transition would be smaller due to infrastructure reuse. In addition, the uptake of hydrogen across Scotland could leverage local skills from workers in the oil and gas (O&G) sector and apply them to hydrogen and CCUS. The two projects would present a just transition opportunity for the local community to continue growing during the transition to Net Zero. Similarly, the relatively low disruption brought in by the use of hydrogen in carbon-intensive sectors, such as power plants or industry,

Hydrogen in Scotland Final report means that current workforce skills would be easily transferred once hydrogen substitutes natural gas, leading to job retention and savings associated with reskilling. In addition to the wide range of learnings and skills that would be developed in Scotland as a result of the hydrogen economy initiated by Acorn, the project has the potential of positioning Scotland as a leader in hydrogen and CCS technologies and trade. A Scottish decarbonised economy could produce vast amounts of blue hydrogen in the short and medium-term and green hydrogen in the long-term. The surplus of clean hydrogen that Scotland could produce in the future suggests that Scotland could become a leader in the national and international trade of the commodity. Under such a role, Scotland would be enabling the decarbonisation of regions which may struggle to decarbonise without help.

Acorn Hydrogen could pave the way in the energy transition The maturity of the Acorn Hydrogen project and potential for scale up within the next 10 years could create several physical and intangible assets that Scotland and the UK could use in the energy transition. Acorn Hydrogen would bring an opportunity for future hydrogen projects to exploit the physical assets that early deployment of Acorn Hydrogen would enable and are needed in the transition towards Net Zero. Key infrastructure could be deployed within the next 10 years as a result of Acorn Hydrogen, including transmission pipelines, conversion of the distribution network, hydrogen storage, appliances conversion and others. These would represent a key enabler for future blue and green hydrogen projects, as they would not have to overcome some of the initial hurdles inherent to the energy transition and could thus focus on accelerating decarbonisation. Acorn CCS would unlock similar benefits, allowing industrial CCS development in Scotland and positioning St Fergus as both a regional CCUS and hydrogen export centre, where multiple projects, such as the Hydrogen Coast, could utilise common infrastructure. Acorn Hydrogen and Acorn CCS could represent an early enabler for industrial decarbonisation. The integration of assets available for the decarbonisation of Scottish Industry – namely Acorn Hydrogen, Acorn CCS, and the Feeder 10 pipeline – present a significant low-carbon infrastructure opportunity for industry to decarbonise through both hydrogen for fuel switching and CCS for emissions reduction. The very large concentration of industries in Grangemouth and the wider Central Belt of Scotland, which jointly account for 60% of all Scottish industrial emissions, means that hydrogen and CCUS could decarbonise industry related emissions at pace and scale. Early decarbonisation would contribute to maintaining the Scottish industry level, which would otherwise see some of its 185,000 jobs and £12bn/year of generated GVA at risk.

Acorn Hydrogen could be one of the first, cross-sector, national decarbonisation projects in the UK which would bring considerable expertise in taking the UK closer to becoming carbon neutral, by building knowledge required for fuelling the transition. Blending of hydrogen with natural gas for power generation could also lead to significant opportunities for replication in other UK power stations. In addition, Acorn Hydrogen could enable

Hydrogen in Scotland Final report early demonstration of the feasibility of converting the distribution network for pure hydrogen use. Therefore, Acorn Hydrogen would enable technological, commercial and financial learnings for the large-scale implementation of a Net Zero economy.

Recommendations for further work to support hydrogen deployment This study sets out a range of possible scenarios in which hydrogen and CCUS may play a significant role in the journey to Net Zero. However, there are a series of commercial challenges that large-scale hydrogen adoption could face and that would require an update of current policies, to reduce market uncertainty and enable effective deployment of the different parts of the hydrogen supply chain. Further research is needed on business models, supply-chain constraints and skills.

 The business models around the hydrogen and CCUS infrastructure were not examined in this study. Whilst this is an active discussion topic at the Government level, certainty of the business models and applicability to Scotland would be required to ensure that the different stakeholders, such as hydrogen producers, infrastructure operators, industry, and power generation, could make investment decisions and work together.  The supply chain implications, including the availability of equipment and materials, as well as workforce, in Scotland or the UK, has not been fully investigated. Further work will be required to understand the value chain and workforce capabilities that could be deployed within the near term.  Skills conversion and retraining for local communities will be key in unlocking the benefits listed in this study at a local and Scottish level but also in ensuring a just transition. This aspect was not explored in this study. Further research would need to focus on examining the skill pool in the Aberdeen area and around other UK industrial clusters to understand the extent to which current O&G skills could be adapted to better fit with future technologies, such as hydrogen and CCUS.

Hydrogen in Scotland Final report

Acronyms and abbreviations

CAPEX Capital Expenditure Mt Mega tonne CCC Committee on Climate Change NAEI National Atmospheric Emissions CCGT Combined Cycle Gas Turbine Inventory CCS Carbon Capture and Storage NECCUS North East Carbon Capture CCUS Carbon Capture, Utilisation, and Utilisation and Storage Alliance Storage NG Natural Gas CEF Connecting Europe Facility NTS National Transmission System CO2 Carbon Dioxide ONS Office for National Statistics CO2e Carbon Dioxide Equivalents OPEX Operational Expenditure FEED Front-End Engineering Design O&G Oil and Gas GM Grangemouth PCI Project of Common Interest GS(M)R Gas Safety (Management) PM Particulate Matter Regulations PPS Peterhead Power Station GTYS Gas Ten Year Statement RD&D Research, Development & GVA Gross Value Added Demonstration GW Gigawatt SEPA Scottish Environment Protection H2 Hydrogen Agency HGV Heavy Goods Vehicle SNZI Scotland’s Net Zero Infrastructure HRS Hydrogen Refuelling Station SWA Scotch Whisky Association LNG Liquified Natural Gas TWh Terawatt hour LOHC Liquefied Organic Hydrogen T&S Transport and Storage Carriers UKCS UK Continental Shelf

Note on terminology

Whilst Carbon Capture, Utilisation, and Storage (CCUS) and Carbon Capture and Storage (CCS) are used almost interchangeably in the literature, for consistency purposes, this report only uses CCUS, with an exception when CCS is used directly in the cited sources. Potential blending of hydrogen into the NTS is expected to be done in St Fergus Gas Terminal, but St Fergus is used throughout the report for simplicity. All blending figures refer to a volume basis (v/v%). ‘Blue hydrogen’ refers to hydrogen produced from a feedstock of natural gas by steam methane reforming (SMR) or autothermal reforming (ATR) coupled with carbon capture, utilisation, and storage (CCUS) of the resulting carbon dioxide emissions. ‘Green hydrogen’ refers to hydrogen produced through water electrolysis using renewable electricity.

Hydrogen in Scotland Final report

Contents

1 Introduction ...... 11 1.1 Context ...... 11 1.2 Objectives and scope of the work ...... 13 1.3 Report structure ...... 13 2 Delivering Net Zero through Hydrogen ...... 14 2.1 Scenario 1: Regional Growth ...... 15 2.2 Scenario 2: Scottish Hydrogen Economy ...... 24 2.3 Scenario 3: European Outreach ...... 30 3 Acorn Hydrogen’s role and benefits ...... 33 3.1 Benefits for the UK economy ...... 33 3.2 Other benefits ...... 36 4 Unlocking benefits: conclusions and recommendations ...... 41 Appendix: Key modelling assumptions ...... 45

Hydrogen in Scotland Final report

1 Introduction

1.1 Context Scotland and the UK have ambitious plans to reach Net-Zero emissions. In May 2019 the Committee on Climate Change (CCC) published ‘Net Zero: The UK’s contribution to stopping global warming’. The report set out the CCC’s advice that the UK should commit to achieving Net Zero greenhouse gas emissions by 2050 and Scotland by 2045. Element Energy supported the CCC’s analysis on reducing industrial emissions through options such as CCUS, BECCS and hydrogen fuel switching, as well as reducing emissions from fossil fuel production and fugitive emissions. The Government and Devolved Administrations subsequently legislated for Net Zero greenhouse gas targets. Following this, the Scottish Government imposed its own ambitious target to become carbon neutral by 2045. Hydrogen and CCUS could play a major role in the energy transition. This level of ambition would require deep decarbonisation of all sectors of the Scottish economy and would involve large-scale deployment of new technologies. Whilst a variety of technologies and approaches are available for decarbonising different sectors of the economy, the CCC recommended investment be prioritised in two complementary technologies, Carbon Capture, Utilisation and Storage (CCUS) and hydrogen, due to their pivotal roles in enabling long-term deep decarbonisation.

Figure 1: Overview of the cross-sectoral Scottish decarbonisation targets1

Scotland has established a leading position in the hydrogen energy sector, with several high-profile projects that have demonstrated the performance of hydrogen and fuel cell technologies in various applications. Notable examples include the Aberdeen Hydrogen Fuel Cell Bus Project, Surf N Turf and BIG HIT (Orkney), and the Aberdeen Vision Project (SGN) with Acorn. Scotland has access to extensive CO2 storage capacity in the North Sea, which makes it viable to produce low-cost and low-carbon hydrogen with CCUS. Scotland also has high levels of renewable energy resources (e.g. wind power) and electricity generation in many areas of the country has been limited by the capacity of electricity networks for some time. By offering an alternative use for this renewable electricity, hydrogen produced from renewable electricity via water electrolysis offers the potential to facilitate increased use of existing renewable generators, introduction of new generation capacity, energy storage and cross-sector decarbonisation.

1 Adapted and updated from CCC Net Zero – The UK’s contribution to stopping global warming, The Committee on Climate Change, 2019

Hydrogen in Scotland Final report

Acorn Hydrogen, led by Pale Blue Dot Energy, is a blue hydrogen production project located at St Fergus. The project is one of the most mature and ambitious hydrogen projects in the UK. Having recently completed a feasibility study with funding support from the Hydrogen Supply Competition Phase 1 - an initiative of BEIS - Acorn Hydrogen has now moved to Phase 2. Hydrogen would be produced through advanced reformation of natural gas, a process capable of delivering low-carbon hydrogen alongside a concentrated stream of CO2, suitable for capture using existing technology. The project is strategically located at St Fergus, which represents the main entry point of natural gas from the North Sea into the National Transmission System (NTS), currently delivering 35% of all the UK’s natural gas consumption. The sister project, Acorn CCS, co-located at St Fergus would provide a route for the resulting

CO2 emissions to be captured, transported, and safely stored offshore. St Fergus therefore allows Acorn Hydrogen to strategically minimise infrastructure requirements for the delivery of both hydrogen to the NTS and CO2 offshore at significant scales, while also bringing Acorn Hydrogen expansion opportunities to nearby cities such as Aberdeen. Finally, St Fergus also offers enough space for potential modular build-out of more hydrogen generation capacity in the future.

Figure 2: Overview of the Acorn Hydrogen project concept

The initial design of Acorn Hydrogen considers a single development concept for a circa 200 MW plant - equivalent to 1.6 TWh annually - sized to meet the demands of a 2% blend into the NTS at St Fergus. However, the project could allow eventual scale-up of deployment to satisfy increasing long-term demand. Indeed, under the recommendations of the UK Committee on Climate Change, hydrogen is expected to play a significant role in the Scottish and UK economy in the decades leading up to 2050. For example, a previous study for Acorn

Hydrogen in Scotland Final report

Hydrogen concluded that annual productions of over 10 TWh of hydrogen may be possible2. Such production levels could involve a higher decarbonisation potential for the wider UK by increasing the levels of blending into the NTS or a phased conversion of the Aberdeen gas distribution to 100%, and could act as a stepping- stone in enabling fuel switching in industry, decarbonising the heat and power sectors, and fuelling a low-cost transition in transport. There is still uncertainty around the likely potential for hydrogen demand in Scotland and the magnitude of benefits to the UK economy in addition to enabling climate targets. As one of the most mature hydrogen deployment projects, Acorn Hydrogen would serve as the foundation of a future Scottish hydrogen economy. This report explores the role of Acorn Hydrogen in enabling the delivery of Net Zero across Scotland and the UK, whilst driving clean growth.

1.2 Objectives and scope of the work The aim of this study is to explore the role of Acorn Hydrogen in delivering Net Zero in Scotland and in the wider UK through the development of various hydrogen deployment scenarios. Specific objectives included:

 Explore the role of hydrogen in a series of ‘what if’ scenarios assessing the potential for hydrogen serving as a vector in decarbonising Scottish industry, transport, heating, power generation and serving as a new export commodity.  To collaborate with regional stakeholders to refine and validate the likely level of demand and timescales specific to each sector assessed.  To review the associated regional and national infrastructure requirements that would enable each scenario in order to provide a plausible timeline for the growth of infrastructure to meet the hydrogen demand in each scenario.  To understand the techno-economic implications of the necessary infrastructure to measure the costs associated with each scenario.  To conduct a macro-economic assessment to estimate the likely benefits of these scenarios in terms of jobs, GVA, and other socio-economic benefits, both for Scotland and for the wider UK economy.

1.3 Report structure The remainder of this report is structured into 5 chapters as follows: Chapter 2 describes three decarbonisation scenarios, different in scale, complexity, and scope: Chapter 3 presents the investment required for achieving these deployment scenarios and the macroeconomic benefits of successful deployment, in terms of GVA growth, jobs created, and trade. Chapter 4 provides a summary of this study, highlighting the benefits unlocked by each scenario, and provides recommendations for policy makers and future work. This report is also accompanied by an appendix detailing key figures of the scenarios and assumptions.

2 Acorn Hydrogen: Project Summary as part of the Acorn Hydrogen Feasibility Study Project, Pale Blue Dot Energy, 2019

Hydrogen in Scotland Final report

2 Delivering Net Zero through Hydrogen

There are multiple pathways available to the Scottish Government to reach its Net Zero decarbonisation targets by 2045. However, any one pathway will include a variety of energy sources within the energy mix and how each technology is represented in the mix will ultimately depend on the investments pursued, policies implemented and resources available. For Scotland, current developments for all these factors strongly indicate a future where hydrogen and CCUS would play a significant role within the energy mix. Even though these two technologies will exhibit some form of use and penetration into the Scottish energy mix, it is important to evaluate the extent of influence and role which these deep decarbonisation technologies may eventually play. Factors such as supply, and demand and the pertinent infrastructure needed to support both hydrogen and CCUS would determine their penetration into each sector of Scotland. In order to bring detail into how hydrogen and CCUS could help Scotland reach Net Zero, three scenarios have been developed. Each varies in scale, scope and ambition, but all focus on the value which hydrogen and CCUS could bring to Scotland and the wider UK.

 Scenario 1 – Regional Growth: The first scenario would see limited hydrogen and CCUS application in the nearest regions to St Fergus: Aberdeen City and Aberdeenshire, as well as in Grangemouth. In the latter location, the two technologies would be used to decarbonise some industrial sectors. In the Regional Growth scenario, hydrogen would find applications in the transport, power and heating sectors. Blending of up to 10% of hydrogen into the NTS to go to the rest of UK would also be included in order to increase the scenario’s decarbonisation potential.  Scenario 2 – Scottish Hydrogen Economy: In addition to considering the demand from Regional Growth, the Scottish Hydrogen Economy scenario envisages a Scotland-wide hydrogen and CCUS decarbonisation where the two are widely used to enable emissions reduction for transport, heating and in further industry. Relative to the Regional Growth scenario, this scenario supplies the same amount of hydrogen for power and for NTS blending to go to the rest of UK.  Scenario 3 – European Outreach: This scenario replicates the Scottish Hydrogen Economy scenario but predicts a leading role for Scotland with extra installed capacity to allow for hydrogen/ammonia exports to the UK and continental Europe. The shipping of CO2 emissions from other clusters to St Fergus is also included.

Figure 3: Illustrative representation of the scenario structure, (GM is Grangemouth)3 The following sections describe the uptake of hydrogen technologies under each scenario in more detail.

3 Blending of hydrogen up to 100% could be performed via a new dedicated hydrogen transmission pipeline system supplying Scotland.

Hydrogen in Scotland Final report

2.1 Scenario 1: Regional Growth Introduction This scenario considers a regional role for hydrogen in delivering Net Zero across Scotland. It examines the decarbonisation of Aberdeen City and Aberdeenshire through the conversion of transport, heat as well as the power sector; and through fuel switching in selected industrial sites in Aberdeen City and in the Grangemouth industrial cluster. Limited amounts of blending of up to 10% of hydrogen into the NTS via injection at St Fergus to go to the rest of UK are also included. In this scenario, hydrogen demands in Aberdeen City and Aberdeenshire would be met by hydrogen produced at Acorn, whereas hydrogen demand in Grangemouth industry could be met locally4. Blue hydrogen would be transported to the wider Aberdeenshire area via a dedicated hydrogen pipeline and distributed to meet heating demands via a process of conversion of the natural gas Figure 4: Infrastructure map of the Regional Growth scenario distribution network. There is an opportunity for hydrogen use at the Peterhead Power Station (PPS). NTS blending would gradually increase to 10% from the 2% start of Acorn Hydrogen production and would continue in the 2030s, declining in the mid-2030s as a decarbonising Scotland finds other roles for the NTS. This scenario also leverages current infrastructure. For example, the emissions associated with blue hydrogen production in Grangemouth would be transported to Acorn CCS following the repurposing of the Feeder 10 pipeline, one of the fully operational pipelines currently transporting natural gas from St Fergus to demand points in the South. Hydrogen blending The NTS is a key infrastructure system operated by National Grid, with the role of transporting high-pressure natural gas throughout the UK. The NTS acts as a backbone that feeds the intermediate and low pressure natural gas systems which deliver natural gas to connected users. Currently, natural gas is the only energy carrier transported by the NTS; however, as the UK moves towards a Net Zero economy, the role of the gas transmission system would likely change. In the short and medium term, hydrogen would start being injected into the NTS blended with natural gas. Injection of clean hydrogen would help start a nation-wide decarbonisation of the natural gas network. The volume blends may initially be small, but hydrogen concentrations would increase with time as evidence and experience for safety and performance is gathered. Small blends of hydrogen are undisruptive to most users and could serve as a short term strategy for decarbonising UK heat. All scenarios considered in this study

4 A local reformer would be installed to allow hydrogen production for Grangemouth industry.

Hydrogen in Scotland Final report assume that hydrogen could be blended in the NTS up to 10%. A discussion on some of the barriers and enablers for associated with hydrogen blending into the NTS are included in Section 4. Based on i) the forecasts for future natural gas flows through St Fergus provided in the Gas Ten Year Statement (GTYS) 5 and on ii) a phased increase of blending to 10% between the expected date of Acorn Hydrogen commissioning and 2030, it is estimated that demand for hydrogen blended in the NTS could be 1.5 TWh/year in 2025, reaching a peak of 7 TWh/year in 2030, before declining as described above. However, whilst small blends are currently technically feasible, these would ultimately depend on the future natural gas flows through St Fergus. The future of the gas system in the UK is further explored in the second scenario. The Gas Ten Year Statement (GTYS), prepared annually by National Grid, forecasts a reduction of the gas flow at St Fergus coming from the UK Continental Shelf (UKCS). Although the decline in supplies can vary depending on several factors, the reference Two Degrees Scenario used in this report forecasts a reduction of 67% between 2020 and 2050. Such decrease in flows could hinder the decarbonisation potential that hydrogen can provide when blended, even if high blends are permitted. Whilst noting that high-100% blends of hydrogen would be required to meet the 2045/2050 Net Zero legislation, such reduction in flow is uncertain and could be negated if demand for natural gas continues to exist, through new development of gas resources or due to gas imports from Norway or through other gas terminals across the UK.

Figure 5: Demand for NTS blending and evolution of gas flow through St Fergus (mmcm/year), as reported in 2019 GTYS

Gas grid conversion NTS hydrogen blending is not the only route that Acorn Hydrogen could decarbonise the gas network. In the Regional Growth Scenario, the gas grid conversion to hydrogen in Aberdeen City and Aberdeenshire, regions close to St Fergus where a significant heating demand exists, are explored. The conversion of the grid would follow a phased approach in agreement with the Aberdeen Vision Project, (described in the box below). Pioneering gas grid decarbonisation: The Aberdeen Vision Project

Aberdeen Vision is one of the most ambitious hydrogen projects being developed in Scotland due to its scope and interplay with other planned neighbouring projects. The project is being developed by SGN in collaboration with National Grid and Pale Blue Dot Energy. The project will provide a case for building a hydrogen pipeline from St Fergus to Aberdeen City. This pipeline would allow for the transition of Aberdeen City to hydrogen, which is envisaged to replace natural gas for heating demands and fossil fuels in transport. The transition to hydrogen for Aberdeen City is expected to be phased, starting first at a 20% blend and, once operation has been proven, increasing to 100% following a conversion of the network. This would be independent of and complement the blending of hydrogen into the NTS. As in this report, blending into the NTS and Aberdeen City would be enabled by the Acorn CCS and Acorn Hydrogen projects. Hydrogen would be produced in the Acorn Hydrogen facilities, while the CO2 emissions

5 Gas Ten Year Statement, NG, 2019

Hydrogen in Scotland Final report

would be captured and transported to Acorn CCS storage sites. An initial hydrogen production facility of circa 200MW is being considered to suffice for a 2% blend into the NTS. However, local markets other than blending into the NTS may be needed to ensure that the initial 200MW production facility achieves the high rates of plant utilisation required. In addition, supplying hydrogen from the initial 200MW reformer into Aberdeen City at levels desired by Aberdeen Vision would require the % blend into the NTS to reduce from 2%. If both Aberdeen Vision and a 2-10% blend into the NTS are to be achieved this may require additional hydrogen reformer capacity. The ambition and timing of Aberdeen Vision, ahead of other deployments, mean that the potential learnings of this project could be shared with other UK projects pursuing similar initiatives.

Acorn Hydrogen would deliver the initial blend to the regions’ distribution systems via the build-out of a dedicated hydrogen transmission pipeline which would be routed from St Fergus to Aberdeen. The hydrogen would then be blended up to 20% directly into the distribution network. The 20% blending specification has been chosen as conventional domestic boilers would not require modifications to continue operating.6 Blending into the gas grid in Aberdeen City and Aberdeenshire could start as early as 2025, based on conversations with key stakeholders. Full conversion of the gas grid could be carried out within 5 years of operation at reduced blends, giving enough time to demonstrate the operability of the network and build additional hydrogen production capacity. During the transition, natural gas would continue to be supplied to some of the distribution networks as different areas of the distribution networks become isolated from the NTS and connect to the hydrogen transmission pipeline, as shown in Figure 6. Once the transition has been completed, the demands have been calculated to be of 7 TWh/year by 2045 for both regions, equivalent to 0.9 GW of installed hydrogen production capacity. The transition of the distribution network to run fully on hydrogen would require the replacement of all domestic and commercial boilers to hydrogen-specific designs. Availability of hydrogen boilers needs to be anticipated as a factor to enable the sectorised conversion of the local distribution networks, given that natural gas fired boilers have a useful life of 10-14 years. In addition, the lower energy density of hydrogen means that a full conversion would require higher volumetric rates of hydrogen to meet the same demand. To account for this change in energy density, some sections of the network may require reinforcement works to solve capacity issues. In addition, modifications or replacement of domestic and industrial appliances, such as boilers, cookers, etc will be required. Relevant policy recommendations are discussed in Chapter 4. The conversion of the distribution system will follow a sectorised approach as shown below. During this transition, some industrial and power generation users (e.g. Peterhead Power Station, see below) may be early adopters of hydrogen, by connecting to the supply pipeline which would become the future hydrogen transmission system. Others (residential and small commercial users) may still use natural gas until their local distribution network and appliances have been converted to hydrogen. As a result, a newly built system for hydrogen will be needed as the existing natural gas transmission system will still be required to provide natural gas to the other parts of the region before the full completion of the network and appliance conversion.

6 All gas appliance sold after 1993 must comply with the 1990 Gas Appliance Directive 90/396/CCE (GAD), which demonstrates that these appliances are compatible with a gas composition of up to 23% hydrogen.

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Figure 6: Approach for the Scotland-wide grid conversion to hydrogen (illustrative)7

Power generation use Peterhead power station has an installed capacity of 1.15 GW. It is the only large-scale natural gas-fired power station in Scotland and, due to its proximity to St Fergus, is considered under all three scenarios. The power station emitted 0.95 MtCO2/year in 2017, equivalent to an estimated natural gas demand of 5.3 TWh/year in 2017.8 Peterhead Power Station could be decarbonised through the use of post-combustion CCS or hydrogen, as the plant is typically operated for peak demands.9 The current natural gas combined-cycle gas turbine (NG CCGT) was replaced in 2000. Considering an average turbine life of 30 years,7 the turbine would likely require replacement around 2030. Given the availability of hydrogen in the area, this analysis assumes that PPS would remain operational beyond 2030, at the current load factor. The initial opportunity for PPS to decarbonise in the mid-2020s is by blending hydrogen in the current NG CCGT, at a 15% blending ratio, equivalent to 0.3 TWh/year hydrogen.10 Beyond 2030, it is assumed that the turbine is replaced with a hydrogen gas turbine, enabling use of 5.3 TWh/year pure hydrogen for power generation, as shown in Figure 7.

7 Reproduced from Hydrogen for Economic Growth, Hy-Impact Series Study 1, Element Energy for Equinor, 2019; illustrative diagram only, regional differences may apply to Scotland and further work would be required to establish the exact steps for grid transition. 8 Emission data based on the National Atmospheric Emissions Inventory (NAEI) dataset, 2017; natural gas demand is estimated based on a load-factor of 56% and an average turbine efficiency of 57%, as previously discussed in previous EE work as part of the Hy-Impact Study 3, Element Energy for Equinor, 2019; however emerging data shows that 2018 emissions were more than double at 1.91 MtCO2/year, which could increase the potential for blending at PPS. 9 PPS’s long term power output could be influenced by the eventual decommissioning of other Scottish baseload generation plants: Hunterston (1GW) and Torness (1.3GW), both to close by 2030. 10 Although further feasibility studies for the blending of hydrogen in gas turbines are required, the Hydrogen Council’s Path to Hydrogen Competitiveness (2020) states that blends of up to 30% are a feasible transition solution. The peaking nature of the current operation of PPS may bring complexities in managing supply and demand of hydrogen. At times of low demand from the power station, surplus hydrogen could be diverted to an increased blending ratio, storage, or exports (as described in the European Outreach scenario).

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Figure 7: An example of the Potential for Peterhead’s demand for hydrogen (TWh/year)

Aberdeen City and Aberdeenshire hydrogen transport demand In the Regional Growth scenario, the build-out of a hydrogen transmission pipeline to Aberdeen City and Aberdeenshire could also enable the decarbonisation of the transport sector. Although some small hydrogen demand already exists for the 10 hydrogen fuelled buses in Aberdeen City,11 the supply of hydrogen from Acorn would allow for the entire vehicle fleet to convert to hydrogen. Due to high hydrogen purity requirements, opportunities for conversion of the vehicle fleet would also be higher once the distribution networks are converted to 100% hydrogen. Before full conversion, hydrogen supply to the hydrogen refuelling stations (HRS) would be limited to tube trailer supply from the main pipeline bringing hydrogen from St Fergus to Aberdeen.12 Under this scenario, we consider the transition of cars, vans, buses and HGVs to low-carbon alternatives, including both battery electric vehicles or fuel cell hydrogen vehicles, in line with Scottish Net Zero targets. The breakdown between the two powertrains and number of hydrogen fuelled vehicles are shown as figures in the Appendix: Key modelling assumptions13. Based on these figures, in this scenario, the resulting demand for hydrogen in transport would be of around 0.2 TWh/year, as seen in Figure 8, and would be satisfied by several hydrogen refuelling stations throughout the region.

Figure 8: Regional Growth transport demand for each transport fleet in TWh/year

11 As part of the European Union’s JIVE programme, 15 more hydrogen buses will enter service this summer. 12 The purity requirements of hydrogen fuel cells are very high, so a final purification step before use in HRSs would be required to bring the purity to usable standards, regardless of pipeline or tube trailer delivery. 13 Based on total cost of ownership (TCO) analysis of electric and hydrogen powertrains conducted by Element Energy transport practice. It must be noted that higher uptakes of hydrogen powertrains, especially across the heavier vehicle types (vans, HGVs, and buses) would be possible given their relatively high commercial readiness.

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Grangemouth Industry demand The Grangemouth industrial cluster is the most prominent concentration of industrial sites in Scotland and is part of the wider Central Belt of Scotland, which also includes other large emitters. In 2017, the cluster 14 accounted for 30% of Scotland’s industrial emissions (3.6 MtCO2). Grangemouth is home to some of the largest industrial point sources of CO2, arising from energy-intensive sectors such as refining, chemicals, olefin production, and power. Under the current Industrial Strategy, the UK could see two low-carbon industrial clusters by 2030, and the first Net Zero cluster by 2040.15 If the Grangemouth cluster is to remain competitive and comply with Scotland Net Zero targets, it would need to decarbonise within the given timeframe. There is already activity in the area, with the North East CCUS (NECCUS) alliance producing a roadmap examining the potential for industrial decarbonisation in the Central Belt of Scotland by 2045, evaluating the use of important technologies such as hydrogen and CCUS.16,17 The large variety of processes found in industry brings challenges to the decarbonisation pathway that industry could follow, with a “one-fit-all” approach unfeasible. Instead, depending on the nature of the process and the breakdown of fuel and process emissions, a cost-effective decarbonisation may require the implementation of either or both hydrogen and CCUS. Hydrogen is most suited for industries where fuel emissions are the major source of emissions, whereas industries characterised by process emissions would need to rely on emissions capture and storage. As depicted in the enlarged Grangemouth cluster in Figure 9, the Regional Growth scenario considers a handful of industrial sites around Grangemouth which were found suitable for hydrogen fuel switching, including chemicals, glass and power for the oil and gas facilities along with some food and drink in Aberdeenshire and paper and pulp in Aberdeen City.

Figure 9: Spatial location of Grangemouth industrial sites adopting hydrogen fuel switching18

Industrial decarbonisation of Grangemouth would be enabled to a large extent by further development of the Acorn CCS project. This is because industrial CO2 emissions resulting from local blue hydrogen production in Grangemouth and from Grangemouth industrial sites adopting CCUS would be captured and transported to St Fergus in gas phase via the Feeder 10 transmission pipeline. This pipeline is currently used to transport natural gas but could be repurposed as early as in 2027. In St Fergus, injection to offshore reservoirs would sequester the CO2 permanently. The forecasted total number of blue hydrogen related CO2 emissions can be found in Appendix: Key modelling assumptions. More details of the Acorn CCS Project can be found in the box below.

14 Scottish pollutant release inventory, Scottish Environment Protection Agency (SEPA), 2019. Emissions total given is for Grangemouth Refiner, Grangemouth CHP, Ineos Chemicals Grangemouth, Ineos Infrastructure (Grangemouth), and Ineos FPS Grangemouth. 15 BEIS in the budget, UK Government, 2020 16 The Roadmap, NECCUS, 2020. 17 Pale Blue Dot Energy is leading Scotland’s Net Zero Infrastructure (SNZI), a project also successful in the ISCF Industrial Decarbonisation Challenge, Phase 1 18 Some pipework may be required to connect selected sites to the hydrogen generated by any future Grangemouth reformer

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The transition to hydrogen for Grangemouth industry would therefore begin once the Feeder 10 and local hydrogen production become available. The proximity of the sites to decarbonise means that the transition could last several years. Sites in Aberdeen City and Aberdeenshire could convert earlier once hydrogen from St Fergus reaches the production site. The likely hydrogen demand in Grangemouth would reach 7 TWh/year by 2045, a year when 0.8 GW of hydrogen production capacity would be needed. Industries switching to hydrogen in Aberdeen City and Aberdeenshire would have a demand of 0.3 TWh/year by the same date. Use of hydrogen in industry would require the conversion of industrial appliances to hydrogen fuelled equivalents. In order to provide the same grade of heat, hydrogen boilers or CHP could be used to drive a steam process, whereas hydrogen ovens and heaters would find applications for direct low-temperature heating. For high-temperature needs, hydrogen furnaces would be employed. Substitution of these appliances is not expected to be disruptive to industrial processes, as conversion is available through retrofits and the mode of operation is similar to fossil-fuelled fired industrial appliances. Although hydrogen is less disruptive than electrification and is available via retrofits, electrification is considered to be closer to commercialisation19. Industrial hydrogen heaters are not yet available at scale, and boilers for mid-grade heating are only expected to become available in the second half of this decade20. This could imply that the selected industries adopting hydrogen fuel switching may take slightly longer than forecasted in this study to complete the conversion, as they wait for certainty of investment or for other industry players to switch first. However, this delay is not expected to be lengthy, as Scotland’s 2030 target to reduce emissions by 75% would require deep decarbonisation of industry to have already begun by such date.

Enabling industrial decarbonisation: The Acorn CCS Project

The Acorn CCS project, sister project of Acorn Hydrogen, is a CCS project being developed by Pale Blue Dot Energy. The project was enabled by early stage funding from the EU, UK and Scottish Governments, through several programmes also supporting other CCS initiatives across the UK and Europe. The Acorn CCS project is being developed at the St Fergus Gas Terminal in North East Scotland. The project’s strategic location allows for the reuse of existing oil and gas infrastructure in the North Sea, thus rendering a low- cost, low-risk project.

The project will be structured in phases and is expected to be operating in the early 2020s. In Phase 1, CO2 from gas processing will be captured from the St Fergus Gas Terminal. In Phase 2, Acorn CCS will grow to store CO2 emissions from other sources, including; Acorn Hydrogen, the Grangemouth industrial cluster and some of the most energy intensive sites in the UK. The transport of captured emissions from Grangemouth would be enabled by the reuse of the existing Feeder 10 pipeline, which runs between St Fergus and Grangemouth. Phase 2 of Acorn CCS also plans to import emissions from other UK and EU industrial clusters. The indicative timeframes are included in the figure below.

19 Industrial Fuel Switching Market Engagement Study, Element Energy and Jacobs for BEIS, 2018 20 Path to hydrogen competitiveness: A cost perspective, Hydrogen Council, 2020

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Figure 10: Timeframe for the two phases of the Acorn CCS project21 The role of Acorn CCS as a deep decarbonisation project is significant, as the project would help the UK to reach its ambitious decarbonisation targets by 2050. In addition, the early deployment of Acorn CCS implies that the project would serve as a catalyst which can provide evidence to develop other large-scale CCS projects in the UK and beyond. For all these reasons, Acorn CCS has been recognised as a European Union Project of Common Interest (PCI) under the Connecting Europe Facility (CEF).

Key infrastructure requirements Hydrogen infrastructure. Based on the demand analysis presented in the Regional Growth scenario for power, industry, heating, transport and NTS blending, the total annual demand by 2045 would be 19 TWh/year, as shown in figure below. Such demand would be met by Acorn Hydrogen (12 TWh/y) in St Fergus and a local hydrogen production facility (7 TWh/y) in Grangemouth. The required installed hydrogen reformer capacity would be of 1.6 GW for the former and 0.8 GW for the latter.

Figure 11: Total annual demand in TWh/year by sector in the Regional Growth scenario

21 The realised CO2 emissions captured by Acorn CCS related to Acorn Hydrogen production will eventually depend on the size and plant utilisation of the hydrogen production facility, a decision output expected from the Acorn Hydrogen Concept Study.

Hydrogen in Scotland Final report

CCUS infrastructure.22 In order to meet CCUS demands from blue hydrogen production from Acorn Hydrogen and Grangemouth, the infrastructure would be sized to support a maximum capture, transport and storage rate of 5 MtCO2/year in 2050, of which 1.8 MtCO2/year would be transported through Feeder 10 from 23 Grangemouth. By 2050, the cumulative amount of CO2 captured would be 105 MtCO2. Hydrogen storage. Hydrogen storage would also be required to ensure that demand for hydrogen can always be met. Whilst the reuse of the redundant Miller offshore gas pipeline connected to St Fergus is currently being considered for the transport of CO2 for storage, an option also being explored is the use of the Miller offshore pipeline for intraday storage of pressurised hydrogen to optimise operation of the Acorn Hydrogen reformer24. The storage capacity of the Miller pipeline could provide notable intra-day capacity. Inter-seasonal storage could be in the form of ammonia25, with the latter sized to store 2.2 TWh/year, equivalent to 11% of demand.26

22 This CCUS infrastructure does not account for additional CO2 emissions which may result in Grangemouth from adoption of CCUS technology in industrial process to capture fuel and process emissions. This is also applicable for the Scottish Hydrogen Economy Scenario and Scottish Hydrogen Economy Scenario with Exports. 23 Based on a hydrogen production emissions intensity factor of 0.25 MtCO2/TWh. 24 A final decision for the reuse of the Miller pipeline has not yet been taken. 25 Chemical plants (including ammonia) usually operate at a continuous load factor throughout the year, using a steady supply of hydrogen. This would be the case for Acorn Hydrogen as well, with hydrogen being produced steadily throughout the year, supplied to end-users in line with demand, and stored for winter if surplus is generated. 26 This is aligned with the H21 2100 Vision for Scotland hydrogen storage needs as ammonia (e.g. see H21 base and XL scenarios), H21 North of England report, Northern Gas Grid and Equinor, 2018.

Hydrogen in Scotland Final report

2.2 Scenario 2: Scottish Hydrogen Economy Introduction The Scottish Hydrogen Economy scenario explores the same hydrogen demand sectors as the Regional Growth scenario but expands geographically, to explore decarbonisation across all Scotland. Hydrogen blending up to 10% in the NTS to go to the rest of UK is considered in the early years. However, in the long-term, this scenario assumes that a designated hydrogen transmission system would serve as the main avenue for delivery of hydrogen around the country. Production of hydrogen would come from other sources besides Acorn Hydrogen at St Fergus and the Grangemouth local production for industry.27 Additional sources would need to be close to natural gas and CCUS transport infrastructure. Production of both blue and green hydrogen at multiple locations is considered. In this scenario, the time for conversion of different Scottish Figure 12: Infrastructure map of the Scottish Hydrogen Economy areas would be subject to the scenario availability of the hydrogen transmission infrastructure. As a result, the Aberdeen City and Aberdeenshire regions would convert first and would demonstrate the initial conversion of the gas distribution network to 20% before fully converting to hydrogen. Conversion in other regions would be at 100% hydrogen, gradually converting large urban areas like Edinburgh, Glasgow, and areas near Grangemouth where demands are high. Subsequent conversion would then be sectorised and subject to a radial growth of the transmission system and would stem from main cities. Scottish transport would see a Scotland-wide conversion of cars, vans, HGVs and buses, along with the fraction of trains still relying on diesel28 and the fleet of domestic vessels. Core-economy decarbonisation: industry and power generation The Scottish Hydrogen Economy scenario would see the decarbonisation of the sectors forming the core of the Scottish economy. Decarbonisation of industry would move beyond Grangemouth and would also consider other regions with clustered industries, such as in Fife, Glasgow, Ayrshire and Dumfries, and Galloway. The scenario includes additional industrial sub-sector hydrogen demand, predominantly from food and drink but also from glass, paper and pulp, chemical and pharmaceuticals and non-ferrous metallurgy. Decarbonisation of distilleries, many of which are located in rural areas, is also explored in this scenario. A total annual demand for hydrogen in industry of 9 TWh/year by 2045 is estimated. As in the previous scenario, Grangemouth industry would require its own dedicated hydrogen production facility, as three quarters of all the industrial

27 Having points of blue hydrogen production in Southern Scotland could benefit from possible south-to-north natural gas flows in the NTS to account for decreases in the future natural gas flows through St Fergus, as discussed in the 2019 GTYS. 28 For example, used on rail lines where electrification is prohibitively expensive or unpractical.

Hydrogen in Scotland Final report hydrogen demand would come from this cluster.29 Local production would allow for the Grangemouth cluster to complete the switch to hydrogen by the early 2030s. Contrastingly, switching in the more dispersed industrial sites around Scotland would occur at a slower rate – subject to the availability of hydrogen transmission infrastructure – and would be complete by 2040, in line with Scottish decarbonisation targets. As the only gas-fired power plant in Scotland, decarbonisation of the power sector in the Scottish Hydrogen Economy scenario would focus on PPS. As in the Regional Growth scenario, PPS would use hydrogen directly supplied by the nearby Acorn Hydrogen project at St Fergus. The power station’s annual demand and expected dates for conversion of the gas turbines would be the same as in the Regional Growth Scenario, standing at 5.3 TWh/year by 2045 following turbine conversion in 2030. Scottish-wide grid conversion As of 2016, 83% of the domestic heating demands in Scotland were met by natural gas, delivered through an extensive infrastructure of transmission and distribution pipelines.30 Decarbonisation of domestic heat, which represented 66% of all domestic energy use, would be required to meet the Net Zero targets.30 Whilst several pathways are possible, this scenario explores a world in which the gas network is converted to hydrogen through the build out of a new dedicated national hydrogen transmission system and conversion of the local distribution networks to run with hydrogen. This conversion is expected to occur in the medium to long term, and so this scenario also explores the initial requirement for hydrogen blending into the NTS to deliver a short to medium term decarbonisation contribution. In the Scottish Hydrogen Economy scenario, the new hydrogen national transmission system would replace the natural gas NTS, as it exists today, as the main energy transmission system as the different sectors switch to hydrogen. It is thus the case that the natural gas NTS would not become obsolete but its role would shift from feeding houses and businesses with gas directly in Scotland, and feeding gas South to England; to supplying the feedstock required for hydrogen production and other sectors adopting CCS, such as power (natural gas CCGT retrofitted or built with CCS) or industry where a gas replacement is seen as not technologically or commercially feasible (e.g. industrial sites with significant process emissions). The existing local distribution network, operated by SGN in Scotland, presents a long-term and cost-effective opportunity to decarbonise heat if converted to run on 100% hydrogen following the same conversion approach as in Figure 6. Conversion of the distribution network would therefore come first in urban areas, which would likely be closer to centralised hydrogen production (e.g. Aberdeen City close to St Fergus or Edinburgh close to Grangemouth), followed by other regions as the conversion of the distribution network expands outwards from key cities. In view of the expected growth of off-shore green hydrogen production, a potential off-shore transmission pipeline which transports hydrogen onshore would also accelerate the conversion of the distribution networks of coastal cities. As part of this conversion process, the local distribution grid would be detached and isolated from the current NTS and connected to the future hydrogen transmission system. To complete this task, a strategic reinforcement of the network and upgrades to district governors would be required to future proof the network31. In line with the Aberdeen Vision Project, a phased conversion of Aberdeen City is expected to occur after build- out of the initial Acorn Hydrogen production and the dedicated hydrogen transmission line. Aberdeen City would therefore be the first city to adopt hydrogen as early as 2025 through an initial conversion to 20%. The Aberdeen Vision Project could therefore serve as a stepping-stone to provide learnings for a wider Scottish

29 It is assumed that not all hydrogen production demand could be covered by Acorn Hydrogen and as such, a hydrogen transmission pipeline which is capable of transporting hydrogen nationally between the different points of production is most appropriate to ensure security of supply. 30 Scotland’s electricity and gas networks: vision to 2030, Scottish Government, 2019. 31 In line with the H21 North of England approach, this may require testing and upgrades to district governors (extensively located throughout cities), and would consist of testing a range of different district governors, including service governors (MP/LP direct feeds to domestic properties) to ensure operational functionality is not affected when regulating hydrogen. Identified issues may be dealt by replacing parts (e.g. valves) or the full governor.

Hydrogen in Scotland Final report conversion. Based on current heating demands32 and on the estimated timeline for hydrogen infrastructure availability, the 2045 Scottish-wide heating demand for hydrogen would be of 48 TWh/year, as shown below

Figure 13: Hydrogen heating demand in TWh/year following Scottish-wide grid conversion

Options for the transmission of hydrogen in Scotland

There are currently two main views for the future hydrogen transmission system in Scotland. Even though both of them would enable the decarbonisation of the Scottish economy through use of hydrogen, these views diverge in terms of the opportunities which natural gas may have in a Net Zero economy. Build-out of a new dedicated hydrogen transmission system. This strategy envisages a new transmission system only transporting pure hydrogen so that the incumbent NTS can continue to transport natural gas. This network would be gradually built, and its planning would take into consideration future sources of hydrogen production. As such, this transmission pipeline may have an offshore branch which transports green hydrogen onshore. The rationale behind this approach is that, in the future, there would be a wide adoption of CCS in industrial processes and localised production of blue hydrogen within industrial clusters or around areas with high population densities. Demand for pure natural gas would therefore continue to exist, for sites equipped with CCS, such as industry, power stations, and blue hydrogen production. This could potentially lead to some underutilisation of the current NTS, resulting in different branches that may become obsolete for natural gas transmission to be repurposed for transportation of captured CO2 to storage sites, i.e. the Feeder 10 pipeline mentioned previously. Adoption of high hydrogen blends into the NTS. This strategy sees the existing NTS being slowly repurposed to increasingly adopt higher blends of hydrogen with natural gas. For this approach to a full hydrogen conversion of the NTS it is envisaged that specific amounts of oxygen would be added to the blend in order to mitigate pipeline embrittlement risk. The rationale behind this approach is that the UK should detach as much as possible from direct use of natural gas in order to meet the Net Zero targets. Further, this strategy presents an appealing opportunity to repurpose what could become an underused extensive infrastructure system. However, given that the volumetric energy density of hydrogen is higher than that of natural gas, the system may require strategic reinforcement. Consequently, natural gas would be present in small blending amounts and users still requiring pure streams of natural gas would have to adopt a deblending step to remove the natural gas33, which could be expensive and could bring issues in managing supply and demand.

32 Based on BEIS Subnational gas consumption statistics 2005-2018 for the heating demand across Scotland. Regional Scenario (Aberdeen demand) is based on future refinements with inputs from Pale Blue Dot Energy and SGN. 33 Several deblending technologies are available, including Pressure Swing Absorption, Cryogenic Separation, and Membrane Separation. Deblending is being explored through the HyNTS Deblending project by National Grid Gas.

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It is noteworthy mentioning that there is a high degree of uncertainty as to which strategy may eventually be adopted.

Distilleries The distilleries sector is a key sector to the Scottish economy, representing a significant share of Scottish exports. Interest in decarbonisation of this sector is evidenced by the work being completed by the Scotch Whisky Association (SWA) and its 2020 Environmental Strategy, which recognises hydrogen as an important option to decarbonise the sector. There are over 130 distilleries in Scotland. The size of Scottish distilleries varies widely across the country and the source of fuel used has been traditionally determined by accessibility to the gas grid. The current fuel mix across the sector comprises natural gas (56%), fossil oils (18%), grid electricity (10%), renewable heat (8%) and other sources in small amounts34. The considerable number of malt distilleries close to Acorn Hydrogen, such as in Moray and Aberdeenshire, means that distilleries could be an important user of hydrogen. Heat represents a significant share of distilleries’ energy demand. Under the Scottish Hydrogen Economy scenario, we assume that, as articulated within the SWA Strategy, up to 20% of the baseline fossil fuel total primary energy use could be replaced by hydrogen by 2045,35 representing an equivalent of 0.7 TWh/year. Electrification and other measures, such as a switch to bioenergy, could help decarbonise the remainder of the total primary energy demand. Transition to hydrogen is expected to start in the mid-2030s, once initial demonstration projects for large scale hydrogen boilers have been pursued and necessary evidence is gathered. However, hydrogen fuel switching is subject to the availability of hydrogen in the geographical area, either via a hydrogen distribution pipeline connection or road/sea transport. Nevertheless, the rural location of many of these distilleries implies that the conversion would follow into the 2040s but must be completed by 2045.36 Note that the Scottish legislated 75% carbon reduction by 2030 would require an acceleration of this outcome. For sites where accessibility to gas grid represents a barrier for fuel switching, hydrogen would be delivered by truck (as it is currently done with heavy fuel oil and kerosene). However, other factors should be considered in order to successfully achieve decarbonisation of the sector.37 Transport decarbonisation The uptake of hydrogen transport is expected to experience an accelerated growth, in the Net Zero context. In line with this narrative, the Scottish Hydrogen Economy scenario would see part of the Scottish transport sector being decarbonised by hydrogen. The national conversion of hydrogen for transport would enable the conversion of a fraction of the cars, vans, buses and HGVs. The remaining fleet of diesel trains in Scotland, which are 29% of the total fleet, would be converted too. Regional scale ships, including ferries, fishing and tanker vessels, would be converted which cover most coastal demands. The split between battery and hydrogen fuelled vehicles is analogous to that of the Regional Growth scenario, and it is included in Appendix: Key modelling assumptions, along with a figure for the growth of the Scottish hydrogen fuelled fleet and key sources. Hydrogen is expected to play a significant role in long-range heavy vehicles, such as HGVs and buses, alongside trains and ships. It is estimated that the hydrogen demand for transport would be circa 10 TWh/year in 2045. Demand breakdown between the different fleets is exhibited in Error! Reference source not found.. This forecast of demand is also applicable to the European Outreach scenario.

34 Scotch whisky pathway to net zero, SWA, 2020 35 This is in line with current research conducted by the Scotch Whisky Association (SWA), the industry trade body as stated in the Scotch whisky pathway to net zero, SWA, 2020. 36 Electrification of heating demands of these rural distilleries may be difficult due to grid capacity constraints which could arise. 37 The continued existence of government schemes, such as the renewable heat incentive, can reduce project risk. In addition, technology for large hydrogen boilers needs to be scaled and further proven and the 20 years lifetime of currently used boilers implies that transition to hydrogen may be limited to those distilleries with boilers close to their useful life.

Hydrogen in Scotland Final report

Figure 14: Scotland-wide transport demand for each transport vehicle type in TWh/year By 2045, the Scottish refuelling infrastructure could be extensive and include over 400 HRSs, in addition to private facilities at depots (HGVs, buses, and trains) and main Scottish ports.

The interplay of blue and green hydrogen

Scotland’s proximity to natural gas resources and depleted oil and gas reservoirs for CO2 storage as well as the extensive offshore and onshore wind provides a prosperous environment for the production of both blue and green hydrogen. Blue hydrogen could be deployed at scale in the short and medium term thanks to its technological maturity and economics and also due to the urgency to deploy key infrastructure which can achieve deep multi-sectoral decarbonisation in the 2020s. Acorn Hydrogen would allow for blue hydrogen to serve as the first arrow in tackling climate change, as it could be initiated as early as 2025. Other similar blue hydrogen projects could follow and together would lead the way to installing the key transport infrastructure needed in a future hydrogen economy. Figure 15: Breakdown of blue and green hydrogen for the Scottish Hydrogen Economy scenario As of today, green hydrogen production technology for the deployment at industrial scale is less mature than natural gas reformation. In addition, a considerable renewable energy scale-up is required to electrolyse hydrogen in the quantities forecasted in this study. Large scale green hydrogen projects are already planned; however, these are not expected to reach a comparable scale with Acorn until in the mid- 2030s. For example, the Dolphyn project is aiming to deploy offshore hydrogen production using wind turbines coupled to electrolysers, reaching a green hydrogen production rate of 12 TWh/year by 2037. Favoured by competitive economics green hydrogen could play a significant role in the Scottish economy in the medium and long term.38 Our scenarios assume a rapid ramp-up in green hydrogen deployment in the mid-2030s, with deployment of new blue hydrogen production capacity ceasing past 2040, and blue and green hydrogen reaching an equal share in the generation mix by 2050.39 The growth trajectories for the Scottish Hydrogen Economy and the European Outreach scenarios are exhibited in Appendix: Key modelling assumptions.

38 It is expected that the economics of green hydrogen projects will reach parity with those of blue hydrogen in the 2030s. Renewable electricity, the main feedstock required for green hydrogen production, would continue to experience cost reductions thereafter, making large-scale green hydrogen projects more financially appealing than blue hydrogen. 39 The forecasted blue and green hydrogen breakdown into the future would reduce the inherent risk of depending on decreasing future gas flows through St Fergus for feedstock.

Hydrogen in Scotland Final report

Key infrastructure requirements Hydrogen infrastructure. Based on the demand analysis presented in the Scottish Hydrogen Economy scenario for power, industry, heating, transport and NTS blending, the total annual demand by 2045 would be 72 TWh/year, as shown in Figure 16. Consistent with the vision described above for green and blue hydrogen production, annual blue hydrogen demand in 2045 would stand at 36 TWh/year. Such demand would be met by Acorn Hydrogen, a local hydrogen production facility (7 TWh/year) in Grangemouth and other blue hydrogen local production sites. In 2045, the total required installed hydrogen production capacity would be of 4.4 GW.

Figure 16: Total annual demand in TWh/year by sector in the Scottish Hydrogen Economy scenario

CCUS infrastructure. In order to meet CCUS demands from blue hydrogen production facilities, the infrastructure would be sized to support a maximum capture, transport and storage rate of 9 MtCO2/year in 2050. The CCUS transport pipeline infrastructure required would eventually depend on the location of blue hydrogen production facilities. A minimum of 1.8 MtCO2/year would be transported via the Feeder 10 pipeline, with a potential to transport more if other hydrogen production facilities were close to the Central Belt40. By 2050, the cumulative amount of CO2 captured offshore would be of 150 MtCO2. Hydrogen storage. As per the Regional Growth scenario, the Miller offshore pipeline is also being explored in this scenario for intraday storage of pressurised hydrogen to meet Acorn Hydrogen demands. As in the previous scenario, the Miller pipeline could play a notable role in intra-day storage, whilst inter-seasonal storage could be in the form of ammonia, with the latter sized to store 8.8 TWh/year.

40 According to Pale Blue Dot Energy’s D17: Feeder 10 study (2017), the annual CO2 transport capacity of Feeder 10 is 6 MtCO2. If additional transport capacity were required, additional line compression can increase the capacity of the pipeline to 10 MtCO2. Alternatively, another CO2 pipeline could be constructed.

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2.3 Scenario 3: European Outreach Introduction Interest in using hydrogen as a decarbonisation vector have arisen in other regions besides Scotland, both in the UK and mainland Europe. Work to date entertains the idea that hydrogen, either in its liquified form, as ammonia or as a liquefied organic hydrogen carrier (LOHC), could become a commodity in the future, being traded at an inter-regional and international level. The European Outreach scenario leverages the rich wind and geological resources that could advantageously position Scottish hydrogen projects, including Acorn Hydrogen. The scenario explores a world in which Scotland becomes a leader in hydrogen production and engages in international trading opportunities with hydrogen, most probably in the form of ammonia.41 Figure 17: Infrastructure map of the European Outreach scenario This scenario follows the same demand narrative, possibility for different locations for blue hydrogen production and timeframes as the Scottish Hydrogen Economy for Scotland. However, this scenario envisages Acorn to play an important role as a Scottish provider for hydrogen exports. Due to the early deployment of Acorn Hydrogen, the project would initiate a market for hydrogen exports. Such export markets would then grow to incorporate production from other blue and green hydrogen projects. By 2050, hydrogen exports from Scotland would have found applications in high-demand regions such as South Wales and continental Europe. Hydrogen could be shipped from various ports around Scotland. However, Peterhead Port’s close proximity to St Fergus suggests that this port could service initial exports as additional transport infrastructure needed to support export levels would be minimised. Further, future offshore green hydrogen production projects will be located in the North Sea, making Peterhead Port the closest choice to service these green hydrogen exports too. The existing capacity of the port could allow for the simultaneous export of hydrogen and import of CO2 from other industrial clusters, as planned in the Acorn CCS project. Export potential National and international efforts to lay out decarbonisation strategies are pushing towards the development of an international market, where clean commodities are traded in a similar fashion to conventional fossil fuels. Such international decarbonisation strategies are now supporting a growing international market which has been initially catalysed by electricity interconnectors through which renewably produced electricity can be traded. In the case of the UK, this is currently taking place with the Netherlands, France, Ireland, Belgium and soon Norway, which allows for the balancing of excess production of electricity42.

41 Although other forms of exporting and storing hydrogen such as liquefied hydrogen or liquefied organic hydrogen carriers (LOHC) exist, there is an active discussion around the advantages of each and an existing uncertainty around which of these options may be more widely adopted. In this study, in order to be aligned with the H21 North of England report, exports and storage in the form of ammonia have been considered here. 42 Electricity interconnectors, Ofgem, 2020

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As clean hydrogen production grows in Scotland, a market for hydrogen, comparable to that of electricity, could flourish. Instead of using interconnectors, hydrogen as a trading commodity would be shipped to demand points43. In this scenario, Scotland’s pioneering position to develop a national hydrogen economy would be further exploited to include exports. These exports would meet a growing international demand from regions where local production of hydrogen may be limited due to infrastructure constraints or inherent competition. The H21 2100 Vision imagines that Scotland has the potential to produce 32 TWh/year of hydrogen that would be converted to ammonia and used to decarbonise South Wales.26 The South Wales cluster has been identified as a potential source for exports due to limited nearby CO2 storage opportunities, making local production of blue hydrogen difficult without significant investment in CO2 shipping to other storage sites. If growth of CO2 shipments were to allow for local hydrogen production, or if nearer UK clusters were to ship hydrogen to South Wales, then it is expected that the forecasted Scottish exports amount could be exported somewhere else in the UK to meet part of the 735 TWh/year of total annual hydrogen demand expected by 2050.44 In this scenario, demand for exports for the South Wales cluster would start in 2035 and would rapidly grow to 32 TWh/year by 2040, as seen in Figure 18. Based on the H21 2100 vision, it is assumed that Scotland could meet most of the hydrogen demand from the South Wales cluster45.

Figure 18: Exports demand assumed (TWh/year) and key receiving markets

Based on the review of several studies, the Hy-Impact Series Study 1 identified France and Germany as the international regions with most potential for the export of hydrogen from the UK46. The study predicts that the UK could supply up to 165 TWh/year of annual hydrogen demand coming from these two countries alone. By 2050, exports to continental Europe would be equal to 16 TWh/year (roughly 10% of all estimated exports to Europe). Based on the Hy-Impact Series Study 1 analysis, such figure would represent 10% of all UK hydrogen exports. The resulting demand would therefore stand at 48 TWh/y by 2050, adding significantly to the Scottish required hydrogen production capacity. It is expected that most of the additional growth for exports after 2040 would be met by green hydrogen production, in agreement with the expected evolution of the green and blue hydrogen split discussed earlier.

43 Ammonia maritime shipping is seen as the first approach in enabling exports due to the relatively low infrastructure required. Hydrogen transports via offshore pipeline could follow ammonia shipment, however, would require the building of the infrastructure, which would likely take longer. 44 Demand figure from Hydrogen for Economic Growth, Hy-Impact Series Study 1, Element Energy for Equinor, 2019. 45 Exports to the European Union could commence earlier than 2040, to satisfy the market demand emerging as a result of the European New Green Deal, by either swapping production capacity with that designated for South Wales or accelerating deployment, even earlier than 2035. 46 Germany’s National Hydrogen Strategy, approved by the German Government in June 2020, recognises that Germany will have to import sizeable amounts of hydrogen in the medium to long term. The strategy’s goal is to use green hydrogen to support market growth.

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Given the infrastructure synergies with ammonia based inter-seasonal storage, hydrogen is assumed to be exported in the form of ammonia by ship, similar to Liquified Natural Gas (LNG) today. This could lead to an extensive supply chain being deployed across Scotland and significant investment in port infrastructure. Key infrastructure requirements Hydrogen infrastructure. Based on the demand analysis presented in the European Outreach scenario for power, industry, heating, transport, NTS blending and exports, the total annual demand by 2045 would be of 114 TWh/year, as shown in figure below. Consistent with the vision described above for green and blue hydrogen production, annual blue hydrogen demand in 2045 would stand at 60 TWh/year. In 2045, the total required installed hydrogen production capacity would be of 7.2 GW.

Figure 19: Total annual demand in TWh/year by sector in the European Outreach scenario

CCUS infrastructure. In order to meet CCUS demands from blue hydrogen production facilities, the infrastructure would be sized to support a maximum capture, transport and storage rate of 15 MtCO2/year in 2050. The CCUS transport pipeline infrastructure required would eventually depend on the location of blue hydrogen production facilities. A minimum of 1.8 MtCO2/year would be transported via the Feeder 10 pipeline, with a potential to transport more if other hydrogen production facilities were close to the Central Belt. By 2050, 47 the cumulative amount of CO2 captured offshore would be of 232 MtCO2. Hydrogen storage. As per the Regional Growth scenario, the Miller offshore pipeline is also being explored in this scenario for intraday storage of pressurised hydrogen to meet Acorn Hydrogen demands. As in the previous scenario, the Miller pipeline could play a notable role in intra-day storage, whilst inter-seasonal storage could be in the form of ammonia, with the latter sized to store 8.8 TWh/year.

47 Such cumulative amount of CO2 stored would exceed Acorn CO2 site’s 152 MtCO2 secure storage limit, but development of the East Mey CO2 storage site (500 MtCO2 capacity) would add sufficient additional storage.

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3 Acorn Hydrogen’s role and benefits

The Acorn Hydrogen project could play an essential role in delivering Net Zero across Scotland and the UK. Through the Net Zero Report published in May 2019, the Committee on Climate Change predicts that by 2050, hydrogen and CCS would play a pivotal role in the UK energy landscape. Acorn Hydrogen has the potential of helping deliver both emission reductions, economic benefits and learnings that could accelerate the uptake of these two key technologies. This chapter examines in detail the role of Acorn Hydrogen in the UK and the macroeconomic benefits associated with the development and operation of hydrogen production and related infrastructure. In addition, other benefits that could stem out of the Acorn Hydrogen project are also examined.

3.1 Benefits for the UK economy All three scenarios focus on the deployment of hydrogen and CCS technologies between 2020 and 2050, in the short term, these scenarios build on the initial Acorn Hydrogen deployment at St Fergus. In the medium and long term, the scale of hydrogen deployment and role of Acorn Hydrogen and other future sources of hydrogen production vary across scenarios:

 Regional Growth considers a regional role for Acorn Hydrogen in which transport and heating only decarbonise in Aberdeen City and Aberdeenshire, providing regional benefits only.  Scottish Hydrogen Economy assumes that the deployment at St Fergus and the full decarbonisation of the Aberdeen gas grid would lead to significant learnings, and a similar approach is adopted across Scotland, helping deploy a hydrogen economy by 2050.  European Outreach considers a similar deployment as in the case of the second scenario but expanding the export capabilities beyond 2035. The economic benefits are directly proportional with the investment required for each scenario. The analysis included in this chapter focussed on infrastructure related to the production, distribution, and use of blue hydrogen, that could be unlocked as a result of the early deployment of Acorn Hydrogen48. In terms of investment, deploying the full infrastructure would require a capital expenditure of £6.0 to £19.1 billion between 2020 and 2050 across the different scenarios. As previously mentioned, given the similarities between the three scenarios in the short time, the investment profile follows a similar trend.

Figure 20: Capital expenditure under each scenario

48 Items not costed in this study include elements deemed to be replaced irrespective of hydrogen use, such as hydrogen gas turbine replacement for power generation or vehicle body of fuel cell vehicles; green hydrogen infrastructure, infrastructure upgrades for shipping of CO2 and ammonia in ports and any CCUS T&S not related to blue hydrogen production.

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 Regional Growth: The CAPEX cost investment of £6bn is centred around the production and storage of hydrogen at St Fergus, the infrastructure for the supply of hydrogen for use in Aberdeen, the buildout of blue hydrogen in Grangemouth, and the associated CO2 T&S infrastructure needed in both locations.  Scottish Hydrogen Economy: Additional costs mostly arise from Scotland-wide conversion of the gas grid and the required hydrogen production facilities needed; adding an additional CAPEX of £7.6bn.  European Outreach: Similar to the Scottish Hydrogen Economy scenario but dominated by increased hydrogen and ammonia production to allow exports beyond 2035; adding an additional CAPEX of £5.5bn. Whilst most of the capital would be invested between 2035 and 2040 depending on the scenario, the deployment would require further expenditure related to operations and feedstock beyond that. Several industries would be involved in this deployment, both on the construction side (e.g. building infrastructure on the ground or off-shore) but also in supplying the necessary equipment (e.g. manufacturing of machinery, metal products), as well as enabling the deployment (engineering services, insurance etc.)49. Whilst the infrastructure would be deployed around St Fergus and across Scotland, the benefits of this deployment would spread across the UK, due to direct and indirect jobs generated in the industries involved and in the associated supply chains. The figure below summarises the number of direct jobs created in relation to CAPEX related activities in 2030 and 2040.

Figure 21: Annual direct jobs created around CAPEX deployment across scenarios50

It can be noted that the number of jobs related to CAPEX would be similar in the short term (before 2030) across the three scenarios, the benefits diverge in line with the investment profile. For example, the Scottish Hydrogen Economy and European Outreach scenarios see a persistence of these jobs in the longer term (beyond 2040), which is associated with the continued deployment of infrastructure beyond the geographic scope of the Regional Growth scenario. It must be noted that the numbers shown in the diagram above only relate to the deployment of infrastructure that would be enabled by the first wave of blue hydrogen projects.

49 Full list of industries associated with the CAPEX deployment include: construction; machinery and equipment not elsewhere classified; fabricated metal products; electrical equipment; architectural and engineering services; mining support services; basic iron and steel; and insurance and reinsurance. Mining support activities is the Office for National Statistics (ONS) classification for activities related to the O&G industry, onto which the deployment of off-shore CCS infrastructure is mapped. 50 Indirect jobs vary between 475 and 950 in 2030 to 3,200 – 9,400 in 2040, before declining in line with the reduction in CAPEX.

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However, the benefits are expected to be much wider, when considering the ramp-up of green hydrogen technologies in the mid- to late-2030s. The CAPEX deployment would provide key opportunities in the communities where the infrastructure is deployed, increasing local employment and leveraging the O&G skills that are well established in the North East of Scotland. Section 3.2 below discusses further potential and opportunities related to using O&G skills and infrastructure in powering a transition to a hydrogen economy. The first wave of blue hydrogen projects would bring benefits to Scotland and the UK beyond the capital investment phase, through infrastructure operations. We estimate that operational costs (such as manning and maintenance) could vary from £0.09 bn/year in 2030 (across all scenarios) to between £0.18 and £0.56 bn/year in 2050. Additionally, feedstock for hydrogen production, such as natural gas and electricity, could account for £0.18 and £0.56 bn/year in 2050. In 2030, in each scenario, the operation and feedstock51 use are estimated to contribute with a GVA to the UK economy of £68 and £62 million/year, respectively, figures reaching £1.13 - £6.68 bn per year in 2040. In terms of jobs, up to 1,600 people could be involved in activities related to the infrastructure usage in 2030. The employment progression up to 2050 is shown in the diagram below:

Figure 22: Overview of the direct employment benefits related to the operation of infrastructure

It must be noted that OPEX jobs would be long-term jobs for both the local communities directly involved in the manning and operation of the infrastructure, engineering, and maintenance companies throughout the UK, as well as for those involved in the supply chain. As in the case of CAPEX jobs, additional jobs related to the operation of green hydrogen infrastructure, not quantified in this report, would be expected, in addition to the figures above.

51 Assumes that natural gas and electricity are purchased for the production of hydrogen, however this may not be the case in the scenario of a tolling arrangement; however benefits would still be generated as electricity and natural gas would still need to be produced.

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The benefits of deploying a UK-wide hydrogen economy

Under the current regulatory framework, with a UK-wide Net Zero 2050 target enshrined in regulation, there is no doubt that the UK will become a decarbonised economy provided suitable regulatory support is offered. While multiple pathways, such as hydrogen, CCS, and electrification are possible, Acorn hydrogen has the potential of propelling the UK into becoming a hydrogen economy. This study estimates that between 2,500 and 7,700 people, including direct and indirect jobs, could be involved in activities related to hydrogen production and usage in 2050 that could be triggered by Acorn in Scotland. There are several other blue and green hydrogen projects under development across the UK such as HyNet, H21 NoE, and Gigastack, supporting the UK in moving towards a hydrogen economy. Recent work by Element Energy estimated the benefits that could be unlocked by the UK becoming a hydrogen and CCS-centred economy. The Central Hy-Impact scenario (Decarbonised UK Economy) envisaged that hydrogen would play a role in decarbonising domestic, commercial, and industrial heating and power generation, as well as mobility across the UK. In addition, CCS would be deployed in industry and would help decarbonise conventional natural gas power stations. Coupled with the emissions captured from hydrogen production, 197 MtCO2/year would be captured by 2050. Such an ambitious roll-out would result in 195,000 jobs, including direct employment in infrastructure deployment and operational roles, as well as indirect supply-chain opportunities.

3.2 Other benefits The project’s location and consideration of the current regional energy industry means that Acorn Hydrogen could be integrated in a way which is compatible with many of the existing oil and gas skills and infrastructure. In addition, Acorn Hydrogen’s early deployment and build-out of the associated infrastructure means that the project could facilitate additional hydrogen projects in Scotland in the future as well as bringing an opportunity for an early deployment to decarbonise the Scottish industry. The timing of deployment relative to other global hydrogen projects means that Scotland could be positioned and earn a strong role in the international trade of clean hydrogen. All these benefits would help Scotland gather valuable expertise for a Net Zero future and make Scotland an exemplar of hydrogen economy to be replicated in other regions.

Growth and a just transition for local communities Over 26,000 jobs in the Aberdeen region are directly tied to the oil and gas sector, and the region is also the usual residence for up to 30% of all offshore oil and gas workers.52 As such, the forecasted decline in oil and gas supplies in the North Sea and the move towards a global economy less dependent on fossil fuels pose a current threat to the future of an important portion of the local community. Acorn Hydrogen along with Acorn CCS would promote the continuity of the region’s historic energy role through the creation of a hydrogen

52 Workforce Report, OGUK, 2019.

Hydrogen in Scotland Final report economy which exploits existing O&G infrastructure and leverages local skills in the oil and gas sector. Similarly, the small disruption brought in by the use of hydrogen in carbon-intensive sectors such as power plants or industry implies that current workforce skills would be easily transferred once hydrogen substitutes natural gas. Scotland’s legacy of O&G infrastructure reflects the nation’s essential role within the UK as a major provider of primary energy. Acorn Hydrogen’s commitment to re-invigorate some of this existing infrastructure as the UK transitions to Net Zero brings a just opportunity for local communities to reduce the costs of the transition where possible53. The project’s integrability with existing infrastructure would be extensive and would incorporate infrastructure which would otherwise become obsolete, such as depleted O&G reservoirs and pipelines. Moreover, Acorn Hydrogen would provide an alternative for the long-term use of current energy infrastructure in a Net Zero economy, such as gas distribution networks and the Feeder 10 pipeline. Finally, Acorn Hydrogen would potentially increase the competitiveness of some other existing activities and infrastructure, such as responsible gas extraction within the UKCS and development of the St Fergus Gas Terminal by creating a long-term source of natural gas demand for reformation or similarly in Peterhead port by creating additional shipping traffic in the form of hydrogen exports, both supplied by Acorn or by green hydrogen generation off-shore. For all these reasons, Acorn Hydrogen presents a unique decarbonisation opportunity which attempts to minimise disruption to the local communities by relying on familiar Scottish infrastructure. Given the scale and ambition of Acorn Hydrogen, the project could serve as the centre point for the development of a hydrogen export centre at St Fergus, as envisaged by the Hydrogen Coast initiative represented in Figure 23. The export centre could bring together other infrastructure deployment projects such as Acorn CCS, Aberdeen Vision, the Dolphyn project, and other future synergies with renewable deployments. The development of a hydrogen export centre located at St Fergus would bring a new wave of opportunities to the region, currently heavily dependent on the O&G industry, in a Net Zero world. Figure 23: The Hydrogen Coast, a cluster of projects delivering hydrogen along the East Coast of Scotland54

Facilitating future blue and green hydrogen projects A transition to a hydrogen economy would require the rollout of hydrogen infrastructure beyond production facilities: transmission pipelines, conversion of the distribution network, conversion of domestic appliances, build-out of HRSs, build-out of ammonia infrastructure and many other forms of infrastructure. All this infrastructure is key in order to ensure that the hydrogen supply chain is complete and well-integrated. As of

53 Work on societal acceptance and a just transition for North East Scotland has also been completed as a deliverable for Acorn CCS in D21: Societal Acceptance, Robert Gordon University for Pale Blue Dot Energy, 2018. 54 The Hydrogen Coast, Pale Blue Dot Energy with National Grid and SGN, 2019.

Hydrogen in Scotland Final report today, this infrastructure has not yet been converted nor built to allow Acorn Hydrogen to deliver hydrogen to users. However, as a result of the initiation in hydrogen production brought in by Acorn Hydrogen, it is expected that, within the next 10 years, much of the required infrastructure for the supply chain would be present and growing in a phased manner. The expected initial deployment of infrastructure initiated by Acorn Hydrogen would then make new hydrogen production and infrastructure projects more financially appealing, given that they could build onto existing ones. Acorn Hydrogen would therefore bring an opportunity for future hydrogen projects, both blue and green, to exploit the physical assets which are needed in moving towards Net Zero by removing some of the initial project barriers. In a similar manner, Acorn CCS would unlock analogous benefits by allowing industrial CCS development in Scotland, and could position St Fergus as both a regional CCS and hydrogen export centre, where multiple projects, such as the Hydrogen Coast, could utilise common infrastructure.

An early opportunity for industrial decarbonisation Acorn Hydrogen, and its sister project, the Acorn CCS project, could bring early opportunities for industrial decarbonisation in Scotland. The projects’ commission dates and scalability present Scottish industry with the options to fast-track its ambitious decarbonisation objectives and to prolong competitiveness. The two projects jointly allow for the decarbonisation of “hard-to-decarbonise” industry sectors in Scotland by providing a clean and high-density energy vector which has similar properties to those of incumbent fossil fuels. In Grangemouth, this early hope for industrial decarbonisation would be partially enabled by the reuse of the already existing Feeder 10 pipeline. The combination of Acorn CCS, the reuse of Feeder 10, and the local production of blue hydrogen means that the Grangemouth industry cluster could have a range of assets to enable early decarbonisation.

Building expertise for a Net Zero future The Acorn Hydrogen project has the potential to serve as a stepping-stone in achieving decarbonisation of the heat sector in the UK. In the short and medium term, the project could replace up to 7.5 TWh/year of natural gas with hydrogen in the NTS, avoiding the equivalent of 1.5 MtCO2/year and a total cumulative of 8 MtCO2. The project would not only demonstrate the feasibility of natural gas blending at low mixing ratios in the NTS, but would also serve as one of the earliest projects aiming to fully decarbonise a local gas grid in the UK. As an enabler for the Aberdeen Vision project, Acorn Hydrogen would provide a stable flow of low-carbon hydrogen and would bring together stakeholders from different areas of the value chain. These projects represent an early opportunity for Scotland and the UK to build the technical expertise required to fully decarbonise the gas grid. Skills and learnings developed as a result of the Aberdeen deployment could then be used to accelerate the grid conversion across Scotland and the rest of the UK. The possibility of quick scale up of the Acorn Hydrogen project and its proximity to PPS represents an early opportunity for demonstrating the feasibility of using hydrogen in power generation. The project could trial blending at 15% as early as 2025 and a full conversion of the power station to 100% thereafter. This could represent one of the earliest hydrogen demonstration projects in the power sector and could lead to significant learnings that the UK power sector could adopt in the future. For example, previous work by Element Energy found that over 200 TWh/year of hydrogen could be used in power generation in 20507. CCUS could play a major role throughout the UK by decarbonising power and by enabling industry to decarbonise and retain competitiveness. However, the few existing CCUS demonstration projects in the UK imply that building early expertise in the use of this technology is fundamental. Technologically, Acorn Hydrogen along with Acorn CCS would provide learnings on i) capturing emissions from reforming of natural gas and from a wide range of industrial processes, ii) transport of CO2 over nation-wide distances and iii) CO2 injection in offshore reservoirs with associated monitoring.

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Positioning Scotland as a leader In addition to the wide range of learnings and skills that would be developed in Scotland as a result of the hydrogen economy initiated by Acorn, the project has the potential of positioning Scotland as a leader in hydrogen and CCS technologies, their associated supply chains and the trading of CO2 and hydrogen.

By leveraging its wide resources, such as large-scale CO2 geological storage and offshore wind potential, Scotland could become a leader in exporting hydrogen to other regions. Indeed, the European Outreach scenario considered in this report explores a world in which Scotland could produce and export hydrogen as ammonia as early as 2035. This would position Scotland as an early mover with a major decarbonisation export centre in the North Sea enabling low carbon hydrogen exports to meet national and international demand. Initial exports could focus on helping decarbonise other parts of the UK, where hydrogen infrastructure may be less developed, such as South Wales. Beyond 2040, Scotland could expand its export to the European market, trading up to 48 TWh/year in 2050. Additional exports capacity would not only create more jobs but would also bring further benefits. For example, international trade of ammonia could bring investment in Scottish port infrastructure and ships, as well as attracting investment from companies involved in the hydrogen and ammonia supply chain. The Acorn Hydrogen project would inheritably rely on the integrated CCS project to produce low-carbon hydrogen. However, apart from serving as a store for the emissions from hydrogen production and Grangemouth industry, there is potential for the project to serve as an export centre, allowing other decarbonisation projects to store emissions. For example, other hydrogen and industrial decarbonisation projects emerging both within the UK or in Europe could ship and store their emissions in the Central North Sea, utilising the infrastructure at St Fergus initially laid down to develop the Acorn project. As a result, similar benefits as in the case of ammonia trade could materialise.

What if Acorn Hydrogen were to be unsuccessful?

Acorn Hydrogen is a project of important significance to the hydrogen economy and to the broader Scottish 2045 Net Zero and UK 2050 Net Zero decarbonisation strategies. Acorn Hydrogen is expected to help develop the market by supplying low-cost, clean hydrogen in large scale applications. Acorn Hydrogen would not just bring deep decarbonisation benefits but would also contribute to the UK’s socio-economic growth. It is therefore important to consider the missed opportunities that would arise if Acorn Hydrogen were not to materialise. The most quantifiable impact would be the opportunity cost in terms of added GVA and jobs which Acorn Hydrogen and hydrogen in Grangemouth could unlock, estimated under the Regional Growth scenario to be of £8.6bn GVA and 9,300 jobs. The effects would be observed nationally, but Scotland and Aberdeenshire in particular would see the largest missed opportunities. St Fergus’ chance to become the nation’s centre point for hydrogen production could dissipate and important synergies with other local projects such as Acorn CCS, Aberdeen Vision and Dolphyn would be compromised. Reduced arrival of additional industries to Aberdeenshire and neighbouring regions to exploit Acorn Hydrogen’s facilities would present an additional macroeconomic regional impact. Acorn Hydrogen is expected to contribute beyond hydrogen production. The project would require the build- out of complementary essential infrastructure, such as transmission and distribution networks and associated energy storage. If Acorn Hydrogen were not to occur, then this infrastructure would be compromised or delayed. As a result, the lack of initial momentum achieved through Acorn Hydrogen could compromise other future hydrogen projects which would have relied on such infrastructure being in place, such as the Grangemouth and Hydrogen Coast projects. A considerable delay in the delivery of one of the most promising vectors for deep decarbonisation would have important implications for industry. The Scottish industry could struggle to remain competitive whilst meeting its decarbonisation targets.

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Consequently, a fraction of the £12bn/year GVA and 185,000 jobs of the Scottish manufacturing industry55 would be at risk, as some sub-sectors could consider closure or relocation in the light on increasingly higher carbon prices.

In order to meet Scotland’s Net Zero targets, a gap of 50 MtCO2 of annual emissions would need to be closed by 204556. As discussed in this report, industry decarbonisation alone in the Scottish Hydrogen Economy would have reduced the gap by 9 MtCO2 by such a date. Acorn Hydrogen could additionally contribute substantially to Net Zero through deep decarbonisation in other sectors including transport and heat. The project’s failure would leave an emissions reduction gap which may be harder and less cost- effective to decarbonise through other means.

55 Scottish Government, Scottish Annual Business Statistics, 2017 56 This figure also considers CO2 emissions from Scottish peatland.

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4 Unlocking benefits: conclusions and recommendations

Up to 121 TWh/year of hydrogen could be produced in Scotland by 2050 This study has shown the different ways in which a regional or national decarbonisation of Scotland through adoption of hydrogen and associated CCUS infrastructure could develop. It has also quantified some of the benefits associated with three scenarios: Regional Growth, Scottish Hydrogen Economy, and European Outreach. The Regional Growth scenario examined the potential demand for hydrogen in various sectors: heating and transport in Aberdeen City and Aberdeenshire, power in PPS, industry in Grangemouth, and up to 10% blending into the NTS. This scenario envisages an annual hydrogen demand of 19 TWh/year by 2045. The Scottish Hydrogen Economy scenario covered the potential demand for hydrogen in the same sectors as the Regional Growth scenario, although with a national geographic scope: Scotland-wide heating, transport and industry sectors, power in PPS, and up to 10% blending into the NTS. This scenario forecasts an annual hydrogen demand of 72 TWh/year by 2045. The European Outreach scenario investigated the potential Scottish-wide demand for hydrogen to the same extent as the Scottish Hydrogen Economy scenario, but also included potential demand for hydrogen exports to South Wales and continental Europe. This scenario predicts an annual hydrogen demand of 114 TWh/year by 2045. In a decarbonised Scotland-wide hydrogen economy, hydrogen would be produced in multiple locations and from multiple sources. Both blue and green hydrogen production would be needed to meet the large hydrogen demand expected for 2050. Large scale projects for both types of hydrogen are already underway, such as Acorn Hydrogen (blue) and the Dolphyn project (green) and additional projects should be expected as hydrogen demand builds. In the Scottish Hydrogen Economy and European Outreach scenarios, green hydrogen is predicted to come online at scale in the 2030s. Green hydrogen would thereafter continue to grow at an accelerated pace - with economics comparable to those of blue hydrogen - all the way to 2050. In this year, the Scottish Hydrogen Economy and European Outreach scenarios would have a total green hydrogen annual demand of 36 TWh/year and 60 TWh/year, respectively. This study estimated the economic benefits related to the development of blue hydrogen production, CCUS, conversion of the gas grid across Scotland following the learnings acquired through Acorn Hydrogen, hydrogen storage, and hydrogen refuelling infrastructure. The eventual large-scale uptake of green hydrogen, as a complementary and essential decarbonisation vector, would reuse and further expand this infrastructure, bringing additional benefits beyond those quantified below. In the Regional Growth scenario, benefits are limited to a regional level. Up to 13,000 jobs will be required in the year of peak investment (2036). By 2050, this scenario will have added a cumulative £8.6bn in GVA to the UK economy. In 2050, the operation of infrastructure will support 2,500 total jobs and bring over £202m/year to the economy. The national outreach of the Scottish Hydrogen Economy scenario would also bring key benefits, such as the creation of 21,200 jobs to support the peaking growth of hydrogen in 2040. By 2050, a cumulative £15.6bn in GVA would have been generated, of which £400m would arise in 2050 alone. In addition, long term operation would require 2,700 direct jobs and 2,500 indirect jobs in 2050 in this scenario. The positioning of Scotland as an exporter of hydrogen in the European Outreach scenario would also contribute considerably to the economic benefits. Relative to the Scottish Hydrogen Economy scenario, building and supporting the exports infrastructure in the year of maximum growth (2040) would add 7,700 jobs, bringing the maximum total number of created jobs to 28,900. We estimate that in the long term, 4,200 direct jobs and 3,900 indirect jobs would be created in 2050 in relation to the operation of infrastructure, adding an estimate of over £660m/year to the UK economy. By 2050, a cumulative GVA of £22.5bn would be added to the UK economy.

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Figure 24: Overview of the benefits under each scenario57

Acorn could have a pivotal role in delivering growth and Net Zero In terms of other benefits, Acorn Hydrogen could help Scotland and the UK to move closer to carbon neutrality by delivering emissions reductions, bringing economic growth and ensuring a just transition for the local communities, and creating a series of valuable physical and intangible assets that could be used in the long term. Hydrogen uptake across several sectors would bring significant emissions reduction. For example, just by replacing the natural gas used for heating annually in Scotland, hydrogen could avoid 9 MtCO2/year in 2050. Much wider reductions would also be achieved by replacing gas in power generation and industry, and fossil fuels in transport. In addition to reducing the amounts of CO2 released into the atmosphere and limiting climate change, local air quality improvements are also expected as a result of NOx and PM reductions thanks to hydrogen mobility. As mentioned above, thousands of jobs could be created both in the medium and long term. These would represent opportunities for growth right across the UK, especially in the aftermath of the Covid-19 pandemic. The economic benefits of the Acorn Hydrogen project are not limited to jobs. The project is aiming to deliver significant cost savings by reusing current O&G infrastructure. In addition, it could leverage the pool of local skills as hydrogen and CCS would require skills similar to those of the O&G sector. This could represent a just transition opportunity for the local communities in building the skillset required in the Net Zero world. The high maturity of the Acorn Hydrogen project and ease of scale-up could help position Scotland as a leader in trading of hydrogen and CCUS skills and products, including ammonia, which could bring further additional benefits to the local communities.

57 CCC Net-Zero report (2019) estimated 270 TWh to be produced across the UK in 2050. Whilst this study only considers hydrogen uptake in Scotland, the hydrogen penetration level is higher than the CCC study, which assumes significant electrification of domestic and industrial heating.

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The advanced development and scalability potential of Acorn Hydrogen also mean that essential infrastructure, such as hydrogen production, pipelines, conversion of the gas grid and domestic, commercial, and industrial appliances, could be rolled-out within the next 10-15 years. The existence of this infrastructure would reduce the initial obstacles that other complementary hydrogen projects, both blue and green, would face in the 2030s if the Acorn Hydrogen roll-out did not take place. In addition, Acorn Hydrogen could represent an early enabler for industrial decarbonisation, as it would provide a set of assets available for the decarbonisation of the Scottish Industry - namely Acorn Hydrogen, Acorn CCS and the Feeder 10 pipeline, critical for the decarbonisation of the Grangemouth cluster. In addition, Acorn Hydrogen could be one of the world’s first, cross-sector, national decarbonisation projects which would bring considerable expertise in taking the UK closer to becoming carbon neutral. Blending of hydrogen with natural gas for power generation could also lead to major opportunities for replication in other UK power stations. In addition, Acorn Hydrogen could enable early demonstration of the feasibility of converting the distribution network for pure hydrogen use. Therefore, Acorn Hydrogen would enable technological, commercial, and financial learnings for the large-scale implementation of a Net Zero economy.

Barriers and enablers to deliver Net Zero As noted in the box in Section 3.2, the consequences of the Acorn Hydrogen project not taking place could be severe. The Scottish industry would struggle to remain competitive in a decarbonised economy, and some of the 185,000 jobs and £12bn/year generated GVA would therefore be put at risk. Support in unlocking the benefits examined in this report should not only ensure that the deployment at St Fergus does take place, but also to close some of the regulatory and practical aspects that could prevent Acorn Hydrogen from playing a crucial role in delivering Net Zero in Scotland and across the UK. Several technical, regulatory, and commercial barriers were identified as part of this study and are listed in the box below. These relate to the feasibility of blending hydrogen into the NTS in the first place, but expand down the value chain, from hydrogen transmission and distribution, to considering some of the burdens that end- users may face. To address these issues, further efforts should go into research, development, and demonstration (RD&D) of hydrogen at different points across the value chain, as well as in bringing together the hydrogen producers, end-users, and project developers. Barriers and enablers for conversion of the gas grid

The use of hydrogen in Scotland currently faces a series of barriers which could limit the scale of the scenarios presented in this study. A list of the identified barriers, and the respective scenario enablers, is discussed below. Regulation: The current regulatory framework, which sits within the Gas Safety (Management) Regulations (GS(M)R) 1996, limits the amount of hydrogen in the NTS to 0.1 mol%. The Gas Quality Working Group is completing work that would enable legislative changes to the specification of gas, which if successful would enable higher blends of hydrogen consistent with the goals of existing projects. The HyDeploy project is also working towards gathering evidence for blending by injecting blends of up to 20% into a private gas network.58 High blending levels have already been safely legislated in some countries e.g. the Netherlands, where blending of up to 12% is possible. Embrittlement: There is evidence that the insertion of hydrogen in high strength carbon steel pipelines, such as those used in the NTS, can reduce their useful life due to increased fatigue. Building a dedicated transmission line for hydrogen with materials not subject to embrittlement - as suggested in this report - is therefore deemed more recommendable than high percentage blending. This would bring further benefits, such as hydrogen being present in large concentrations, which is a requirement to be used in transport. Deblending: In all scenarios, hydrogen is expected to be blended up to 10% into the NTS. Such levels of blending would not be disruptive for power generation or domestic heating applications, but NTS users such

58 HyDeploy: Frequently Asked Questions, HyDeploy Consortium, 2018

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as compressor stations and other end-use equipment susceptible to components other than natural gas may require the removal of hydrogen via deblending. Deblending would unfavourably add to the project costs of some users. The need for deblending would be even higher if the hydrogen were to be mixed into the NTS beyond 20% concentration blends.

There are however other areas of research that have not been investigated as part of this study and would require further work and action from both public and private sector stakeholders:

 The business models around the hydrogen and CCUS infrastructure were not examined in this study. Whilst this is an active discussion topic at the Government level, certainty of the business models and applicability to Scotland would be required to ensure that the different stakeholders, such as hydrogen producers, infrastructure operators, industry, and power generators could make investment decisions and work together. Having stakeholders at different levels of the supply chain can help initiate the transition at a similar time so that hydrogen can find a market. This is decisive for any business model to make sound financial sense. For example, a hydrogen economy requires investment to focus on hydrogen transmission infrastructure as much as in hydrogen production. A Scotland-wide conversion of the gas grid could only occur if the necessary supply and demand points, which would not be necessarily located near each other throughout Scotland, are strategically connected. Sufficient infrastructure is essential to the security of supply as different sectors which at present utilise different fuels merge into users of hydrogen. Further, a defined projection of the investments to be made in hydrogen transport projects would reduce the risk of possible future hydrogen supply and demand projects. To achieve this, aggregating hydrogen policies at all the different stages of the hydrogen supply chain would mitigate risk and ensure that decisions on business models for a vertically integrated supply chain follow suit simultaneously.

 The supply chain implications, including the availability of equipment and materials, as well as workforce, in Scotland or the UK, has not been fully investigated. Whilst materials could be sourced from abroad, the UK and its industry have great potential to become a leader in hydrogen technologies. Additionally, this study estimated that over 20,900 people may be involved in CAPEX related activities at the peak of the deployment (2040), of which 15,300 would be in the construction industry alone. Whilst the deployment roll-out schedule is modelled considering conservative assumptions, workforce bottlenecks could become a problem. Further work will be required to understand the value chain and workforce needs which could be achieved within the near term.

 This study did not assess the skills conversion and retraining for local communities, which will be key in unlocking the benefits listed in this report at a local and national level but also in ensuring a just transition. Technical skills are usually located around industrial areas, such as the six main industrial clusters in the UK. The Aberdeen area has a strong heritage in O&G activities and is well placed to convert some of the current skills to better fit with future technologies, such as hydrogen and CCUS. Recent work by Element Energy for the Engineering Construction Industry Training Board highlights the feasibility of such a skill transition59, however additional research would be required to assess the local potential and logistical implications in Scotland.

59 Towards Net Zero: The implications of the transition to net zero emissions for the Engineering Construction Industry, Element Energy for ECITB, 2020.

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Appendix: Key modelling assumptions

Transport assumptions The future mobility uptake scenario was developed in line with the transport decarbonisation targets imposed by the Scottish Government in the Net Zero strategy. In the case of road vehicle, Element Energy modelling (such as the ECCo model) was used to determine the uptake of electric and hydrogen powertrains based on total cost of vehicle ownership. In the case of trains, it is assumed that all diesel trains will switch to hydrogen by 2045 in order to meet emission reduction standards. This is based on the assumption that train lines used by diesel trains are assumed not to be electrified due to cost or practical considerations.

Figure 25: Percentage of powertrain type for each road vehicle stock

Figure 26: Total hydrogen fuelled fleet numbers in the Scottish Hydrogen Economy Scenario

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Blue hydrogen CO2 captured emissions Annual blue hydrogen demand figures for each of the scenarios were used to calculate the total annual capture, transported and stored rates of CO2 arising from blue hydrogen production. These captured CO2 emissions include both Acorn Hydrogen production and other potential Scotland-wide blue hydrogen production. Based on previous studies from Pale Blue Dot Energy, the emissions intensity basis used to calculate the CO2 emissions related to hydrogen production is equivalent to 0.25MtCO2/TWh and the capture efficiency is assumed to be 90%. These rates were calculated in order to evaluate possible infrastructure capacity limitations related to use of existing Acorn CCS CO2 transport and storage assets.

Figure 27: Breakdown of the CO2 emissions associated with blue hydrogen production in each scenario60

Blue and green hydrogen demand breakdown The breakdown between blue and green hydrogen demand is deemed to have considerable implications in terms of the infrastructure needed in a future hydrogen economy. In addition, it is important to consider how the hydrogen production mix may vary in the long-term in light of expected cost reductions and progress in technological maturity. The following generation profiles were calculated based on engagement with Pale Blue Dot Energy, Arup, and Scottish Government, and assume that additional blue hydrogen deployment ceases beyond 2040.

Figure 28: Breakdown of the different production sources to meet hydrogen demand (TWh/year)

The figure above exhibits a breakdown between blue and green hydrogen production between 2020 and 2050. The final split between the two sources of hydrogen is the result of literature reading, evaluation of the status quo of both technologies and stakeholder engagement. The Regional Growth scenario assumes that the small and limited regional growth of hydrogen demand and its early plateauing discourages future investments into green hydrogen production. In the Hydrogen Scottish Economy and European Outreach scenarios, green hydrogen production starts to grow at scale in the mid- 2030s, a time where the economics of both types of hydrogen reach parity. In 2040, roll-out of additional blue hydrogen production capacity is forecasted to cease, and subsequent growth is expected to be met by a growing green hydrogen production industry.

60 In the 2019 GTYS, the forecasted natural gas flow through St Fergus in 2050 is of 91 TWh/year (in the Two Degrees scenario). Taking efficiency of conversion of natural gas to hydrogen to be 80%, sufficient natural gas should be present to meet all demands for blue hydrogen production throughout the three scenarios – maximum demand for blue hydrogen is 61 TWh/year in 2050 under the European Outreach Scenario.

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Breakdown of industry demand Several industries were considered for hydrogen use. Industries in scope include those for which hydrogen fuel switching is seen as a viable pathway. Figures above assume hydrogen replaces all fuel demand (natural gas, oil, and solid fuels) in the industries presented. This analysis follows the methodology in the EE Hy-Impact Study 1, and excludes industries such as cement, ethylene, iron and steel, and refineries. These sectors are characterised by process emissions and/or internal fuels use and are assumed to be more suitable to decarbonisation through CCS. The numbers generated are based on the atmospheric emissions of the industry, reported as part of the NAEI database (2017) and using average fuel mix for UK industry as reported in the ECUK Table 4.04 Industrial final energy consumption by end use (different processes), 2018.

Figure 29: Demand in TWh/year by fuel type in the different subsectors of the Scottish industry to adopt fuel switching. The food and drink subsector includes hydrogen demand for distilleries.

Table 1: Hydrogen demand under the explored scenario (TWh/year) Scenario Regional Growth Scottish Hydrogen Economy European Outreach Year 2030 2045 2050 2030 2045 2050 2030 2045 2050 NTS 7.4 0 0 7.4 0 0 7.4 0 0 blending Heat 0.5 7.3 7.3 0.5 48.1 48.1 0.5 48.1 48.1 Power 0.2 5.3 5.3 0.2 5.3 5.3 0.2 5.3 5.3 Industry 4.5 6.6 6.6 4.5 8.4 8.4 4.5 8.4 8.4 Distilleries - - - - 0.7 0.7 - 0.7 0.7 Transport - 0.2 0.2 1 10.2 10.3 1 10.2 10.3 Exports ------41 48 TOTAL 12.6 19.4 19.4 13.6 72.7 72.8 13.6 113.7 120.8

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Table 2:Summary of key cost assumptions used in the modelling Level Level Units Units Value Notes impact impact Cost type Cost Component to economicto Contribution Contribution

For the supply of ATR plant, £m/TWh prod. CAPEX 63.69 100% natural gas, 25% of separation and capacity the costs are counted conditioning for towards economic OPEX £m/TWh/year 5.58 100% Hydrogen injection Production Production impact modelling, corresponding to an Electricity 2.64 100% ATR efficiency of ~75% relative to OPEX £m/TWh/year business as usual ATR ATR demand in a gas-

Feedstock Feedstock Natural gas 22.04 25% centric UK economy. £m for a 4,600 100% CAPEX tonne/day ammonia 492 Ammonia synthesis unit production % of CAPEX 100% OPEX 3% £m for a 5 tank 100% Based on H21 NoE

storage as storage CAPEX facility @ 55200 222

2 Study (2018), tables Ammonia storage tonnes each 3.32 and 3.31 % of CAPEX 100% OPEX 3% £m for 2 x 4GW 100% CAPEX 529 ammonia crackers Ammonia cracking % of CAPEX 100% OPEX 3% Inter-seasonal H Inter-seasonal ammonia - 2 CAPEX £m/MtCO2 69.1 100% T&S 2 CO2 transport and £m/MtCO2/year Phase 1Phase CO Blue H Blue storage related to OPEX 98 100% Sourced from Acorn hydrogen CCS projects.

2 2 production CAPEX £m/MtCO2 3.9 100% T&S -CO Blue Blue H Phase 2 Phase OPEX £m/MtCO2/year 10 100% LP reinforcement CAPEX £ / connection 18.87 100%

LP isolations CAPEX £ / connection 9.06 100%

MP Isolations CAPEX £ / connection 4.23 100% Network conversion conversion Based on H21 District Governors CAPEX £ / connection 5.66 100% assumptions. and connections

Labour costs CAPEX £ / meter 471.96 100% Material costs - CAPEX £ / meter 499.47 100% boilers

Domestic Material costs - appliances conversion conversion CAPEX £ / meter 249.74 100% other appliances

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Costs used for i) the hydrogen transmisison system and ii) the intraday hydrogen storage were taken from confidential sources provided by Pale Blue Dot Energy and therefore exlcuded from the table above.

Hydrogen in Scotland Final report