Negative Emissions Technologies (NETS): Feasibility Study - Technical Appendices

1. Current status of global nets projects

1.1 Introduction

As outlined in chapter 1 of the main report document, it is now well established that NETs are needed to reach global Net Zero targets. Significant efforts are therefore underway to develop and deploy NETs, with several advancements, feasibility studies and deployment of pilot and commercial scale NETs plants.

To achieve the NETs deployment rates necessary, the UK Government has funded £31.5M for the Greenhouse Gas Removal Demonstrators Programme and £70M for the GHG R&D Programme and Direct Air Capture and Greenhouse Gas Removal technologies competition in 2020^[1]. The purpose of the funds is to help improve the technological maturity of NETs^[2].

Under the £70M fund, funding was split into two segments: 1.) Phase 1 delivering £250,000 of funding per project; 2.) Phase 2 utilising funding to help construct 15 facilities, 13 of which fall into our criteria of being an engineered NET^{[3], [4]}. Only one of these projects will be partially situated in Scotland, led by Black Bull Biochar Ltd, who plan to utilise waste biomass residues from a site in Fort William to produce biochar in Cumbria^[4]. Please see Table 57 in Appendix 8 for further information.

There were two additional Scottish projects that did not pass Phase 2 funding: Storegga Dreamcatcher, a 0.5 MtCO₂/year DACCS project investigating the replacement of natural gas used in Carbon Engineering’s prototype with an alternative heat source (e.g. hydrogen)^{[6], [5]}; and the University of Edinburgh’s DACCS project, investigating the use of solar energy to capture 50ktCO₂/year of atmospheric CO₂ using an activated carbon adsorbent^[6].

1.1.1 Examples of NETs facilities

This section presents NETs facilities currently operational and in planning in the UK and globally. The list presented here is not exhaustive and is intended to provide examples of the various technologies being implemented worldwide.

1.1.1.1 Carbon Capture Scotland

Carbon Capture Scotland (previously known as Dry Ice Scotland) operate a dry ice production facility at Crocketford, Dumfries & Galloway, commissioned in 2021 and costing £4m. The company operate a combined capture capacity of 22 ktCO₂per year from biogenic sources such as biogas upgrading and fermentation in distilleries. The propriety equipment is modular and can be scaled up and applied across multiple sites and industries. The captured CO₂ is used to produce dry ice for the health, and food and drink sectors. The company also intend to provide NETs removals and future storage potential, with a stated aim of greater than 200 ktCO₂per year by 2030^[7].

Carbon Capture Scotland has recently announced Project NEXUS which has received funding from the Scottish Government and private investment. The £120m investment will consist of a series of infrastructure and supply chain projects that allow for a sustainable and commercial means of carbon dioxide removal, starting in 2023 with projects in central and northern Scotland. Note that whilst not definitively NET projects (due to the question over the permanence of the captured CO₂ (at least in the interim period before geological storage is available)), the project will support the development and advancement of NETs in Scotland.

1.1.1.2 BECCS Power

1.1.1.2.1 Drax Power Station, UK

Drax Power Station is currently operating two pilot scale BECCS facilities in North Yorkshire, with plans for commercial scale capture in 2027. The pilot scale facilities became operational in 2019 and 2020, capable of capturing a total of approximately 1.3 tonnes of CO₂ per day^[8]. One of the facilities is demonstrating the use of chemical absorption (based on an innovative solvent developed by C-Capture, a spin off from Leeds University) for capturing CO₂ from a stream of one of the Drax biomass boilers while the other is demonstrating Molten Carbonate Fuel Cell technology for CO₂ capture.

1.1.1.2.2 The Stockholm Exergi BECCS facility in Sweden

Stockholm Exergi is demonstrating BECCS on their biomass CHP site in Stockholm. The BECCS plant will be capable of capturing 800,000 tCO₂/year^[9]. Heat is recovered from the CHP system as well as the capture unit (potassium carbonate-based chemical absorption) and is used and is fed into the district heating system leading to improved efficiencies. The 120 MWe project received funding from the European Commission under the EU Innovation Programme and is expected to become operational by 2026.

1.1.1.2.3 Toshiba Mikawa Power Plant, Japan

In 2009, Toshiba Energy Systems and Solutions (ESS) began an initial pilot to capture 10 tCO₂/day from the Toshiba Mikawa power plant in Japan, a 50kW biomass-fired power plant. As of 2020, Toshiba ESS announced the operation of a large-scale carbon capture facility, building on the findings of the initial pilot in 2009. The large-scale facility is capable of capturing up to 500 tCO₂/day and is now one of the largest operational BECCS plant worldwide^[10].

1.1.1.3 BECCS EfW

The list of EfW sites considered is in Table 46 of Appendix 2.

1.1.1.4 BECCS biofuels

1.1.1.4.1 Operational

Carbon capture from fermentation is common areas with widespread bioethanol industry, such as Europe and North America. Table 1 shows a selection of the largest bioethanol with capture facilities currently operating. Also shown in the table is the total CO₂ captured from bioethanol production in Europe in 2021 and the USA in 2022.

Table 1: Selection of existing carbon capture equipped bioethanol plants in Europe and USA in 2021/22. Includes total recorded CO₂ capture

Site	CO2 destination	Location	Year	CO2 Captured (MtCO2/year)
Alco Bio Fuel[11]	Food and drink Refrigerated transport	Ghent, Belgium	2016 – 2022	0.1
Alco Energy[12]	Horticulture	Rotterdam, Netherlands	2016	0.4
Total capture from European bioethanol producers[13]			2021	1.05
Illinois industrial CCS[14]	Geological storage	Illinois, USA	2017	1
Arkalon CO2 compression facility[14]	Enhanced Oil Recovery	Kansas, USA	2009	0.29
Bonanza bioenergy[14]	Enhanced Oil Recovery	Kansas, USA	2012	0.1
Red Trail Energy CCS[14]	Geological storage	Dakota, USA	2022	0.18
Total capture from USA bioethanol producers[15]			2022	2.55
Husky Energy CO2 Injection[16]	Enhanced Oil Recovery	Saskatchewan, Canada	2012	0.1

1.1.1.4.2 Projects in planning

Projects in planning are those either with granted permission to construct their CCS facility or in the process of obtaining such permission.

The CCS institute lists 37 bioethanol CCS projects in development^[14]. 36 of the planned projects are in the USA with the majority (35 of 36) ranging from 90-570 ktCO₂per year in capture capacity, amounting to a total capacity of 9.32 MtCO₂ per year. The only planned project at mega tonne scale in the USA is the Aemetis ethanol plant in California, with a planned capacity of 2 Mt. However, only 400 ktCO₂per year capture is planned from Aemetis’ ethanol production facility, the remainder will be provided by third party facilities^[17]. In Canada, a further 3 MtCO₂ of capture capacity from ethanol production is expected to be operating by 2024^[14].

Table 2: Planned CO₂ capture at bioethanol production sites^[14]

Site	Location	CO2 destination	Year	Capture capacity
35 bioethanol facilities throughout USA		Geological storage	2024-2025	9.32 MtCO2 total. Ranging from 0.09 to 0.57 MtCO2, averaging 0.266 MtCO2
Aemetis	California, USA	Geological storage	2024	2 MtCO2. 0.4 MtCO2 from own production facility. 1.6 MtCO2 from third parties.
Federated co-operatives	Saskatchewan, Canada	Enhanced Oil Recovery	2024	3 MtCO2

In terms of potential UK pilot plants there are three that were being considered for Phase 2 CCUS funding^[18], but failed to pass.

Table 3: List of UK-based biofuel projects that failed to pass Phase 2 of the CCUS fund

Project	Technology	Location	Capacity			Operational Date
			Mt,waste/year	Ml,fuel/year	MtCO2/year
Alfanar’s Lighthouse Green Fuels plant[19]	Waste-to-SAF plant using gasification and Fischer Tropsch	Teesside, England (East Coast Cluster)	1	180	N/A	2027
Altalto Immingham waste to jet fuel[20]	Waste-to-fuel plant	Immingham, England (East Coast Cluster)	0.5	60	0.08	2027
Protos Biofuels Ltd[21]	Waste-to-fuel plant	Northwest England (HyNet)	150,000	N/A	0.16	2025

1.1.1.5 BECCS Industry

The list of industry sites considered is in Table 43 of Appendix 2.

1.1.1.6 BECCS Hydrogen

1.1.1.6.1 Operational

There are currently no operating BECCS Hydrogen plants in Scotland. However, there are circa 20 existing biomethane sites which could be used to produce hydrogen via SMR or auto thermal reforming (ATR)^[22].

Outside of the UK, there are some existing biohydrogen and bio-syngas production plants, with Table 4 summarising key projects identified from the IEA’s Clean Energy Demonstration Projects Database^[23] and Bioenergy ExCo database^[24].

Table 4: List of currently operational bio-gasification and bio-syngas plants

Project	Hydrogen Technology Type	CCS Installed	Location	Year	Capacity
AquaGreen PCE	Fast Pyrolysis of wet sludge and waste streams to produce syngas with CCS	Yes	Denmark	N/A - operational	N/A
Tokyo Sewage-to-H2plant	Waste-to-hydrogen gasification plant with CCS	Yes	Japan	2021	15-18 t/year of hydrogen
BayoTech H2-1000 hydrogen + carbon clean pilot	Methane reforming of syngas or biogas plant with CCS	Yes	USA	2022	3 ktCO2/year,
Waste2Value, Bioenergy and Sustainable Technologies GmbH	Gasification of lignocellulosics to produce H2 rich syngas without CCS	No	Austria	2022	1MW
AquaGreen/Farevejle wastewater facility	Fast Pyrolysis of wet sludge and waste streams to produce syngas without CCS	No	Denmark	2022	N/A
DTU Chemical engineering LT-CFB	Fast Pyrolysis to produce syngas without CCS	No	Denmark	2002	N/A
DTU Chemical engineering Viking Gasifier	Gasification of organic residues and waste streams to produce syngas without CCS	No	Denmark	2002	N/A
Hazer Process Demonstration Plant	Methane pyrolysis-cracking of biogas from sewage treatment without CCS*	No	Australia	2020	100 t/year of hydrogen

*Novel technology which stores carbon in the form of graphite

Key things to note from the above is that existing projects appear to favour the use of waste feedstocks (5 out of 8 projects) over more traditional biomass feedstocks, and that gasification and fast pyrolysis are the favoured routes of production (7 out of 8 projects). Furthermore, the majority of projects do not utilise CCS (5 out of 8 projects), and hence do not deliver negative emissions.

Several pilot projects producing syngas and/or biohydrogen without CCS also exist:

• LTU Green Fuels, DP1+DME pilot: Operating from 2011 to 2016, this Swedish pilot plant produced 2MW of clean syngas by gasifying black liquor and bio-oil. DME and methanol were also produced and sold as by-products.
• BIONICO pilot plant: Operating from 2015 to 2019, this Italian pilot plant produced 100kg/day of hydrogen using waste feedstocks that were anaerobically digested and converted to biohydrogen via membrane reactor technology^[25]. The project was funded by the EU’s Horizon 2020 programme.

  These have now closed down.

1.1.1.6.2 Projects in planning

There appears to be considerable scope for biohydrogen and bio-syngas within the next decade, with 32 projects being identified: 23 projects within the rest of the UK and 9 projects outside of it. Please note that some of the listed projects do not utilise CCS, and hence are considered as biohydrogen/bio-syngas projects instead of BECCS hydrogen.

1.1.1.6.3 Non-UK projects

Projects that are under development were discovered using the IEA’s Clean Energy Demonstration Projects Database^[23] and the Bioenergy ExCo database^[26].

Table 5: List of planned BECCS Hydrogen projects outside of the UK

Project	Hydrogen Technology Type	Location	Year	Capacity
FUREC[23]	Waste gasification without CCS	Netherlands	2022*	54 ktH2/year
Wabash Valley Resources (IN)[23]	Waste gasification with CCS	USA	2024	1,700 ktCO2/year
Mote biomass-to-hydrogen plant (CA)[23]	Waste gasification with CCS	USA	2024	150 ktCO2/year
OMNI CT – California[23]	Waste gasification without CCS	USA	2023	5 ktH2/year
Solena Group Plasma enhanced gasification[23]	Waste gasification without CCS	USA	2023	4 ktH2/year
Yosemite Clean Energy - Oroville[23]	Waste gasification without CCS	USA	2024	4.5 ktH2/year
Eni, Waste to Hydrogen[26]	Gasification of solid waste without CCS	Italy	N/A	0.1tH2/year
Stiesdal, SkyClean[26]	Fast pyrolysis of agricultural residues to produce syngas	Denmark	Mid 2020s	N/A
Springkildeprojektet, Frichs Pyrolysis ApS[26]	Fast pyrolysis of manure without CCS	Denmark	2021*	100 m3/hr syngas

*Project delayed and still under development

The majority of projects appear to be situated within the USA (5 out of 9 projects), which in turn promise to deliver the most significant carbon savings of 1.85 MtCO₂/year by 2024. These carbon savings will be attributed to the Wabash Valley Resources (IN) plant and Mote biomass-to-hydrogen plant. The choice of feedstock is also heavily weighted towards waste (8 out of 9 projects), which will likely not deliver negative emissions due to the lack of CCS being installed (7 out of 9 projects).

1.1.1.6.4 UK Projects

The UK specific projects were identified by referring to BEIS’s list of Phase 2 projects under the Direct air capture and greenhouse gas removal programme^[1] and the list of Phase 1 projects under the Hydrogen BECCS Innovation Programme^[27]. Both programmes form part of the UK’s Net Zero Innovation Portfolio. These projects all cover feasibility and FEED studies, which aim to investigate ways to improve the economics, energy efficiency and broaden the range of biomass feedstocks that can be utilised to produce biohydrogen.

Table 6: List of planned BECCS Hydrogen projects within the UK

Project	Company	Hydrogen Technology Type
Biohydrogen Greenhouse Gas Removal Demonstration	Advanced Biofuel Solutions Ltd[1]	Waste gasification with CCUS
CCH2: Carbon Capture and Hydrogen	KEW Projects Ltd[1], [1]	Gasification of biomass and refuse derived fuels (RDF) with CCS
Ince Bioenergy Carbon Capture & Storage (INBECCS) - Phase 2	Ince Bio Power Ltd[1]	Gasification of waste wood with CCS
Development of Biomass Gasification Tar Reformation and Ash Removal	Advanced Biofuel Solutions Ltd[27]	Biomass gasification with tar reformation and ash removal
Micro-H2hub utilising biogenic feedstock for hydrogen and CO2 production	Compact Syngas Solutions Ltd[27]	Gasification
Bio-hydrogen Produced by Enhanced Reforming (Bio-HyPER)	Cranfield University[27]	Gasification and biogas with the HyPER process
RiPR (Rising Pressure Reformer) using SCWG (Super Critical Water Gasification)	Helical Energy Ltd[27]	Gasification and RWGS
Enhancement of KEW biomass gasification technology performances through optimisation of the H2/CO2 separation process stage	Kew Projects Ltd[27]	Gasification
Northeast Waste Wood Hydrogen Demonstrator (NEW2H2)	Northumbria University[27]	Hydrogen production using waste wood
Novel plasma reforming technology for tars reduction in BECCS	Queen Mary University of London[27]	Plasma reforming
H2 production via Biomass gasification Integrated with innovative one-step Gas shift reforming and separation (BIG-H2)	Translational Energy Research Centre - The University of Sheffield[27]	Gasification
Hydrogen from Cyanobacteria - a biological route to zero-carbon or carbon-negative hydrogen	17Cicada Ltd[27]	Cyanobacteria
Eco Dark Fermentation	Alps Ecoscience UK Ltd[27]	Fermentation
Production of biohydrogen from waste biomass	CATAGEN Ltd[27]	Hydrogen production using recirculating-gas reactor
Pure Pyrolysis Refined	Environmental Power International (UK R&D) Limited[27]	Pyrolysis
HAROW – Hydrogen by Aqueous-Phase Reforming of Organic Wastes	ICMEA-UK Ltd[27]	Aqueous-Phase Reforming
Biohydrogen from Dark and Photo Fermentation	Phoebus Power Limited[27]	Fermentation
Thermal Catalytic Conversion of Syngas to Carbon Nanotubes	The Cool Corporation Ltd[27]	Thermal Catalytic Conversion
The Sustainable Biogas, Hydrogen, Graphene LOOP	United Utilities Water[27]	Biogas reforming
Hydrogen from organic waste with an integrated biological-thermal-electrochemical process	University of Aberdeen[27]	Thermal-electrochemical process
H2-Boost	University of Leeds[27]	Advanced wet oxidation and dark fermentation of organic waste
BIOHYGAS	University of South Wales[27]	Two-stage biohydrogen / biomethane AD system
Bio Hydrogen Demonstrator	Wood Group UK Ltd[27]	SMR of liquid biological feedstocks

Several key projects producing syngas and/or biohydrogen with CCS include:

• Advanced Biofuel Solutions Ltd: This UK company already has a plant in Swindon that is expected to become the world’s first facility to convert household waste into grid-quality biomethane (1,500 t/year) and hydrogen (500t/year)^{[26], [28]}. The funding from the Direct air capture and greenhouse gas removal programme will be utilised to expand hydrogen production, similar to that of the Swindon plant, with the aim to capture 1MtCO₂/year by 2030.
• KEW Projects Ltd: This midlands-based company is developing the world's first pressurised advanced gasification plant with CCS, with works expected to be completed by 2023-2024. The plant will produce a combination of renewable fuels and bio-hydrogen using waste. The aim is to produce 50 ktCO₂/year during 2025-2030 and 24 MtCO₂/year in the subsequent decade^{[22], [29]}
• Ince Bio Power Ltd: The largest waste wood gasification plant in the UK, providing 22MW of power to local households. The aim of the project is to install CCS to the existing site, which will deliver 7 ktCO₂/year of negative emissions by 2027 and be the first of its kind in the UK.^[30]

1.1.1.7 Biomethane BECCS

The list of biomethane sites considered is in Table 41 of Appendix 2.

1.1.1.8 Direct Air Capture (DAC)

1.1.1.8.1 Operational

There are 20 DAC pilot plants in operation worldwide at the moment, capturing less than 0.01 MtCO₂/year. These are detailed in Table 7 below.

Table 7: Breakdown in DAC pilot plants currently operational

DAC Technology Type	Company	Location	Year	Capacity (t/year)	Utilisation or Storage
Solid sorbent DAC	Climeworks[31]	Germany	2014	1	Utilisation for diesel
		Switzerland	2016	50	Utilisation for fuels
		Switzerland	2017	900	Utilisation for horticulture
		Iceland	2017	50	Storage
		Switzerland	2018	600	Utilisation for beverage carbonation
		Switzerland	2018	3	Utilisation for fuels
		Italy	2018	150	Utilisation for fuels
		Germany	2019	3	Utilisation for fuels
		Netherlands	2019	3	Utilisation for fuels
		Germany	2019	3	Utilisation for fuels
		Germany	2019	50	Utilisation for fuels
		Germany	2020	50	Utilisation for fuels
		Germany	2020	3	Utilisation for fuels
		Germany	2020	3	Utilisation for fuels
		Iceland	2021	4,000	Storage
	Global Thermostat[31]	United States	2010	500	N/A
		United States	2013	1,000	N/A
	Hydrocell[32], [52]	Finland	N/A	1.387	Utilisation for e-fuels
Liquid solvent DAC	Carbon Engineering	Canada[31]	2015	365	Utilisation for e-fuels
		Canada[33]	2021	1,000	Utilisation for e-fuels

1.1.1.8.2 Projects in planning

On a global scale, Iceland, Saudi Arabia, and Scotland are all ideal locations for DAC, due to the proximity of cheap and abundant excess renewable energy (the average auction price of Saudi-Arabian solar projects awarded in 2020 was $18.3/MWh (£14.3/MWh^[34])^{[22], [35]}. However, as detailed below, only 2 projects are being built in these locations at present. There are 11 DAC facilities under development at the moment, capable of capturing 5.5 MtCO₂/year by 2030^[36], as well as five pilot projects funded by the UK’s Direct Air Capture and Green House Gas Removal technologies competition. A breakdown of these projects is illustrated in Table 8.

The key projects in the pipeline cover both CO₂ storage and utilisation. For storage, Climeworks’ Mammoth project^[37] will build upon their existing DAC technology to capture 36,000 tCO₂/year, and Carbon Engineering aims to capture 1.5-2.5 MtCO₂/year through their DAC1^[38], Storegga^[4] and Norwegian Carbon Removal^[39] projects. In terms of utilisation, both Climeworks and Global Thermostat are aiming to produce e-fuels for Norsk e-fuels^[40] and HIF Haru Oni e-fuels^[41]. There are also plans for 1PointFive and Carbon Engineering to collaborate and deploy up to 70 large scale DAC projects by 2035, each of which could capture 1MtCO₂/year^[42].

If successful, the pilot projects funded under the UK’s DAC competition could capture up to 1.6 MtCO₂/year. In particular, the NNB Generation Company (SZC) Ltd and Rolls Royce Plc projects show the most potential; with the former aiming to utilise 400MWth of waste heat from Sizewell C power station to capture 1.5MtCO₂/year, and the latter aiming to capture circa 0.1 MtCO₂/year.

Table 8: Breakdown in DAC projects that are under development

DAC Technology Type	Company	Project	Location	Year	Capacity (t/year)	Utilisation or Storage
Solid sorbent DAC	Climeworks	Norsk e-fuel[40]	Norway	2026	80,000*	Utilisation in e-fuels
	Mammoth[37]	Iceland	2024	36,000	Storage
	Global Thermostat	HIF Haru Oni e-fuels[41]	Chile	N/A	2,190**	Utilisation in e-fuels
	NNB Generation Company (SZC) Limited	Sizewell C[4]	England, UK	N/A	1,500,000	Storage
	CO2CirculAir B.V.	SMART-DAC[4]	Northern Ireland, UK	N/A	100	Storage
Liquid solvent DAC	Carbon Engineering	DAC1[38]	Unites States	2024	500,000	Storage
		Storegga[4]	Scotland, UK	2026	500,000-1,000,000	Storage
		Carbon Removal Project[39]	Norway	N/A	500,000-1,000,000	Storage
	Rolls-Royce plc	Environmental CO2 Removal[4]	England, UK	N/A	100,000	Storage
	Mission Zero Technologies Ltd	DRIVE[4]	UK	N/A	120	Storage and utilisation
Mineralisation DAC	Cambridge Carbon Capture Ltd	Direct air CO2 capture and mineralisation[4]	England, UK	N/A	100	Utilisation in construction

* Producing 25 Ml/year by 2026. Converted to CO₂ utilisation by assuming a fuel density of 800 kgm-3 and 100% conversion of CO₂ to fuel.

** Utilising 250 kgCO₂/day and assuming 24/7 operation throughout the year

1.1.1.9 Biochar

There are currently no operating biochar plants in the UK. However, there are a considerable number of demonstration plants situated in Western Europe, Australia, Canada, and China. The table below summarises these projects using data taken from the IEA’s Clean Energy Demonstration Projects Database^[43] and Bioenergy ExCo database^[26]. Note that projects which dispose of or burn biochar have been included in this table.

Table 9: List of global planned biochar projects

Project	Biochar Technology Type	Location	Year	Capacity/ products
Loganholme Wastewater Treatment Plant Gasification Facility Demonstration Project[23]	Biochar and biofuel production from wastewater	Australia	2019	N/A
Renergi, Bioenergy, Collie, Waste to Energy through Pyrolysis[23]	Biodiesel, biokerosene and biochar production via pyrolysis of waste	Australia	2020	13kt/year of pyrolysis products
PCH Alberta	Produces SNG from fast pyrolysis of biomass. Biochar produced is burnt onsite	Canada	2018	0.1 m3/year of syngas
Dali County Facility	Pyrolysis of rice husks to produce bio-oil, biochar, and non-condensable gases	China	N/A - operational	4,500 m3/year of bio-oil
AquaGreen PCE	Pyrolysis of wet sludge to produces syngas, solid fuels, and biochar	Denmark	N/A - operational	N/A
AquaGreen Farevejle wastewater facility	Pyrolysis of wet sludge to produces syngas, solid fuels, and biochar	Denmark	2022	N/A
Susteen TCR300	Pyrolysis of sewage sludge to produce bio-oil and biochar	Germany	2018	0.1t/year of pyrolysis oil
Empyro Enschede	Fast pyrolysis to produce bio-oil and char. Char is burnt onsite.	Netherlands	1998	1,000 t/year of pyrolysis oil
Empyro	Fast pyrolysis of organic residues to produce pyrolysis oil, steam, power and biochar	Netherlands	2015	3,200 kg/hr pyrolysis oil
Karlsruhe Institute of Technology (KIT), Bioliq	Fast pyrolysis of straw to produce bio-oil, solid fuels, and biochar	Germany	2010	0.3 t/h bio-oil

Unlike BECCS Hydrogen, the source of feedstock appears to be evenly distributed between the use of waste, woody biomass, and other organic products (i.e., straw and rice husks). Furthermore, the majority of these projects only produce biochar as a by-product, which is either burnt onsite, disposed of, or utilised in other industries.

1.1.2 Pathways for global NETs (capacity)

As of April 2021, the European Union as well as 44 countries have pledged to meet a Net Zero emissions target, accounting for approximately 70% of global CO₂ emissions. The use of NETs feature in the pledges, albeit with varying approaches and scale of deployment. The Climate Change Act commits the UK to an 80% reduction in GHG emissions by 2050 relative to 1990 levels. To achieve this reduction of NETs emissions to a value of 160 MtCO₂/year in 2050, NETs, particularly DACCS and BECCS, will contribute significantly.

The IEA published its “Net Zero by 2050: A Roadmap for the Global Energy Sector”^[44] in 2021, outlining a pathway for the global energy sector to achieve Net Zero emissions by 2050. The Net Zero Emissions (NZE) Scenario developed states that a total of 7.6 GtCO₂ is to be captured in 2050; 30% of which comes from BECCS and DACCS, 50% from fossil fuel combustion, and 20% from industrial processes. Currently, there are approximately 35 commercial CCUS facilities in operation globally, with a collective CO₂ capture capacity of 45 Mt CO₂/year.

To meet the targets outlined in the NZE Scenario, global capture capacity needs to increase to 1.2 GtCO₂/ year in 2030 and 7.6 GtCO₂/ year in 2050. .

1.2 Technology options

Several options existing for engineered NETs including BECCS, DACCS and biochar.

A key indicator of a technology’s maturity, and hence likelihood of deployment, is known as its Technology Readiness Level (TRL). Each technology and project will be assigned a TRL level, ranging from 1-9, with a TRL of 1 being the lowest and TRL 9 the highest. Definitions of each TRL level are detailed in Table 10 below.

Table 10: Breakdown in TRL description

Phase	TRL Level	Description
Research	1	Basic principles
	2	Concept and application formulation
	3	Concept validation
Development	4	Experimental pilot
	5	Demonstration pilot
	6	Industrial pilot
Deployment	7	First implementation
	8	A few records of implementation
	9	Extensive implementation

1.2.1 BECCS

BECCS refers to technologies which combine bioenergy applications with CCS. BECCS processes consist of biomass production, biomass conversion, CO₂ capture, CO₂ transport and CO₂ utilisation or storage. There are a wide range of available biomass conversion and CO₂ capture technologies, which are introduced within this section. The final output will depend on the technologies used, ranging from the generation of electricity and heat to the production of hydrogen, biofuels or biomethane. A more detailed review of BECCS applications is given in section 2.

1.2.1.1 Biomass conversion

Biomass conversion refers to the process in which biomass feedstocks are converted into energy. There are several different methods and technologies available, consisting of combustion, gasification, pyrolysis, fermentation and anaerobic digestion. A summary of the various technologies is outlined in Table 11 below.

Table 11. Biomass conversion technologies

Conversion technology	Description	Products
Combustion	Combustion with oxygen	Electricity, heat
Gasification	Partial combustion of biomass or waste feedstocks	Syngas, electricity, heat
Pyrolysis	Thermal degradation of a solid fuel in the absence of oxygen to produce char	Biochar, syngas
Fermentation	Organic material is broken down by micro-organisms with low oxygen levels	Bioethanol and other biofuels
Anaerobic digestion	Organic material is broken down by micro-organisms in the absence of oxygen	Biogas

All of the listed technologies are at TRL 9 (without CO₂ capture) but not are all well-established with CO₂ capture. CO₂ capture on combustion of biomass has been demonstrated by Drax and Stockholm Exergi as well as other operators worldwide. The capture of CO₂ from process emissions in fermentation and AD sites has also been demonstrated. The capture of CO₂ from biomass gasification and pyrolysis processes is less established and still at TRLs below 7.

Biomass combustion technologies are substantially advanced and have been demonstrated commercially in the UK and globally at large capacities up to 300MWe. All other biomass conversion technologies have been demonstrated on a smaller scale. More detail on the various conversion techniques is shown in Appendix 2.

1.2.1.2 CO₂capture Options

There are many carbon capture options including post-combustion carbon capture, pre-combustion carbon capture, oxy-fuel combustion, chemical looping, carbonate looping and supercritical CO₂ (the Allam cycle). Different approaches are applicable to the different biomass conversion technologies listed above. Table 12 provides a summary of the three most-developed carbon capture approaches (post-combustion capture, pre-combustion capture and oxyfuel combustion are discussed below) applicable to power plants (including CHP and DH) and industrial sites. For each approach, there are also several different technologies available as shown in Table 13. The TRL levels in the last column refers to biomass plants with carbon capture with post-combustion capture being the most advanced in terms of large-scale technology demonstration while gasification systems with pre-combustion capture are still in the pilot testing phase (Assessing the cost reduction potential and competitiveness of novel (Next Generation) UK carbon capture technology, Benchmarking state-of-the-art and next generation technologies, Wood)^[45].

Table 12. Types of carbon capture methods

Carbon capture technology	Description	Advantages	Disadvantages	CO2 capture rate	TRL
Post-combustion capture	Removal of CO2 from a flue gas stream. Chemical absorption	Can be retrofitted to existing sites Commercially proven in some industries	High energy penalty for solvent regeneration	~90%	TRL 7-8
Pre-combustion capture	Capture of CO2 from syngas, where the syngas is produced through gasification. Can utilise physical absorption due to relatively high pressures, thus reducing costs.	Results in a high CO2 concentration and high partial pressure	High capital and operating costs	~90%	TRL 5-6
Oxy-fuel combustion capture	Combustion with a stream of oxygen, resulting in a flue gas with higher CO2 concentration and hence easier CO2 separate	Reduced downstream processing of CO2	High energy requirement for air separation unit (ASU)	~90%	TRL 7

Pre-combustion capture

Pre-combustion carbon capture systems are applied to biomass gasification processes. CO₂ is extracted from the syngas prior to combustion, where specific options included biomass integrated gasification combined cycle plants (BIGCC) with solvent absorption, sorbent enhanced reforming using carbonate looping and membrane separate of hydrogen from syngas^[46].

Post-combustion capture

Post-combustion capture systems are applied at the end of biomass conversion processes, where CO₂ is separated from the flue gas stream from biomass combustion or incineration.

Table 13. Types of CO₂ capture technologies

CO2 capture technology	Description	Variations
Membrane separation	Separation of CO2 across a selective membrane	Inorganic membranes, Polymeric membranes, hybrid membranes
Adsorption	Molecular sieves or activated carbon are used to adsorb CO2. Desorption of CO2 is then carried out by pressure swing adsorption, or temperature swing adsorption	Molecular sieves, activated carbon
Chemical absorption	Reaction of CO2 with a chemical solvent to form an intermediate compound. The original solvent and CO2 can be regenerated upon application of heat	Solvents include amines, ammonia, ionic liquids
Physical absorption	Physical absorption of CO2 into a solvent	Solvents include methanol and glycol based
Cryogenic separation	Separation of CO2 by condensation at low temperatures and separation by boiling point difference.

Oxy-fuel combustion capture

Oxy-fuel combustion involves the combustion of a fuel in a high purity oxygen stream, rather than air, resulting in the production of a flue gas with a much higher CO₂ concentration. This allows for a much easier CO₂ separation process when compared to combustion with air, as the CO₂ can be cleaned, compressed, and stored with less downstream processing when compared to combusting fuel with air^[46].

Although oxy-fuel combustion capture systems have several advantages, a key disadvantage relates to the energy requirements of the Air Separation Unit (ASU) to produce the oxygen required, and the CO₂ purification unit.

1.2.2 Direct Air Carbon Capture and Storage (DACCS)

DACCS works by drawing in ambient air using fans and contacting the CO₂ present with specialist sorbents, where the CO₂ is subsequently captured via adsorption or absorption. CO₂-depleted air is produced as an output. The sorbent is then regenerated by altering the process conditions, typically by elevating temperatures and/or reducing pressures, which in turn releases the CO₂ as a pure stream ready for capture.

As the CO₂ concentration in air is significantly lower than compared to BECCS and biochar flue gas streams (between 3-8 vol%)^[47], then DACCS exhibits a higher energy penalty and hence is more expensive. Despite this, researchers have suggested that DACCS shows the most immediate promise in Scotland out of all engineering NETs^[22], as it can achieve considerable carbon removal efficiencies (85.4%-97%)^[48], is flexible in location^{[49], [50]}, and is not constrained by the availability of limited resources (e.g. biomass)^[35]. Furthermore, DACCS does not require complex MRV and carbon accounting methods, as it is a closed system technology achieving permanent removal^[35].

Existing DACCS systems are predominantly based on liquid solvent CO₂ capture or solid sorbent-based carbon capture^[51]. The liquid solvent process is pioneered by Carbon Engineering, whilst the solid sorbent process is led by Climeworks and Global Thermostat. There are also new technologies being developed which offer promises of reduced energy demands and cost^[52]. The energy demands of these alternative configurations, along with their carbon removal potential, are detail in Table 14 below. The costs of these configurations are broken down in Table 33, page 68. More detail on the specific DACCS technology aspects is given in Appendix 3.

Table 14: Breakdown in energy demands and carbon removal for each DACCS technology

Company	Heat (MWh/tCO2)*	Electrical (kWh/tCO2)	Carbon removal efficiency
Carbon Engineering	1.46[23]-2.45**	0[23]-1,535[52]	10-92%[49]
Climeworks	1.5-2.0[52]	200–300[52]	9-97%[50]
Global Thermostat	1.17-1.41[52]	150–260[52]	N/A
Antecy	2.08[52]	694[52]	N/A
MSA	0[52]	316-326[52]	N/A
Molecular filters	N/A	333[52]	N/A

*Units transposed to MWh from varying sources

** In this instance natural gas is burnt in a NGCC unit and electricity is generated onsite.

When compared to BECCS, DACCS is less effective in terms of carbon removal, as it requires large quantities of heat and power per tCO₂; BECCS on the other hand act as a NETs producer^[53]. However, the potential for DACCS scale up is technically unlimited, as CO₂ is sourced directly from the atmosphere and is not constrained by biomass feedstocks that can exhibit supply chain, price, and transport issues.

1.2.3 Biochar

Biochar is a charcoal-like product formed during pyrolysis, where a biomass feedstock is thermally decomposed in the absence or at very low oxygen levels^[54]. This process is similar to gasification, despite exhibiting lower efficiencies, and can be achieved through slow or fast pyrolysis^[55].

Slow pyrolysis is favoured when producing biochar and can be achieved following a batchwise or continuous process configuration. During batchwise pyrolysis, heat is sourced from burning a portion of the biomass feedstock, whilst continuous pyrolysis initially sources heat externally, before switching to burning the combustible gases released during pyrolysis. Fast pyrolysis is favoured when maximising biofuel production, with yields of up to 80% being achievable under the right conditions. The heat used in fast pyrolysis is typically delivered using an inert solid material that acts as the energy carrier (i.e., a fluidised bed)^[56].

The choice of feedstock to produce biochar is broad, with organic wastes, forestry residues and mixed plastic all being possible^{[57], [58]}. The biochar product can subsequently be applied to soils, where the original carbon sequestered during biomass feedstock growth (via photosynthesis) is retained in a stable form that is resistant to decomposition, and thus enables negative emissions^[59]. Typically, slower biochar application rates are prefered^[54]. Pyrolysis temperatures typically range from 350degC to 650degC, below which the process is considered to be “toast” rather than pyrolysis, and above leads to significant material loss. Varying these temperatures also has a direct impact on the structure, composition, and physical characteristics of the biochar, which in turn contribute towards the biochar’s recalcitrancy. In particular, temperature impacts the number of aliphatic chains and aromatic rings, the proportion of fulvic and humic acids, the concentration of nutrients (e.g., phosphorous and nitrogen), ash content, pH, porosity and surface area. Typically, higher temperatures are favoured^[54].

An alternative production method is via hydrothermal carbonization (known as wet mild pyrolysis), where biomass is anaerobically decomposed at 180degC to 280degC in the presence of subcritical liquid water. The advantage of this process is its ability to process biomass with a high moisture content (i.e., wetter waste feedstocks)^[60].

1.3 Policy & regulatory evidence review

1.3.1 Existing Scottish policies and regulations

Under an amended Climate Change Act, Scotland set out an ambitious target to achieve a 75% reduction in emissions by 2030 compared to 1990 levels^[61]. This will be funded through the Industrial Strategy Challenge Fund^[3]. However, according to the CCC^[62] this would not be possible even under the most optimistic scenario (the ‘tailwinds’ pathway), which predicts a 69% reduction in emissions.

Under the ‘Developing Scotland’s circular economy’ paper^[63], the Scottish Government proposes to reduce landfill waste to 5%, by achieving a recycling rate of 70%, reducing 15% of total waste compared to 2011, and reducing food waste by 33% (compared to 2023) by 2025. This reduction in waste could significantly impact feedstock supplies going towards EfW, gasification and biomethane sites.

1.3.2 Existing UK policies, regulations and recommendations

The UK Government has announced over £100M in funds to help develop GGRs and screen them on their potential to deliver negative emissions, reduce costs and scalability^[2]. £31.5M of these funds will be delegated to five land based GGR demonstrator projects (including biochar and perennial bioenergy crops) under the Strategic Priorities Fund. The development of CCUS clusters is also underway, with the UK Government announcing £1B worth of funds^[59]. To help further encourage the deployment of NETs and formation of a CO₂ utilisation market, the UK Government is planning to invest £15M in a new grant-funding competition for SAF production and introduce SAF blending mandates by 2025^[2]. SAFs typically comprise of biofuels and e-fuels, that latter of which is manufactured via the Fischer Tropsch process using captured CO₂^[64].

In 2021, the National Infrastructure Commission (NIC) made 8 key policy suggestions for the UK Government to enact^[3], the majority of which the UK Government agreed with^[65]. Firstly, the UK Government has reiterated that they are committed to achieving at least 5 MtCO₂/year of GGRs by 2030, by delivering on their £100M GGR innovation fund and wishing to develop GGRs incentives. Secondly, the UK Government has confirmed they will obligate polluting sectors to offset their emissions, covering 100% of emissions by 2050. Lastly, they have reiterated that CO₂ T&S infrastructure will be delivered by the end of this decade^[65]. However, the UK Government only partially accepts to have polluting sectors pay for removals in order to reach carbon targets^[65], which can undermine the viability of implementing policies that penalise heavy emitting polluters, such as the GGR Obligation Scheme (please see Section 1.3.3 for further detail).

The UK is expecting to issue a Biomass Strategy in 2023, which will review the amount of sustainable biomass in the UK to source biochar^[59].

Stakeholders wish for a combination of price and quantity instruments to promote GGR deployment. Price mechanisms will be vital to attracting investment in early GGR projects and quantity mechanisms will play a larger role in reaching targets for removals once technologies have matured. Also, technology-neutrality should be a long-term goal once technologies mature, and a market-led mechanism becomes feasible^[59].

UK Government must ensure that new policies complement existing ones, such as the 25 Year Environment Plan and Sustainable Development Goals^[59].

1.3.3 Potential policy or regulatory levers

1.3.3.1 Expand support for GGRs via additional funds

The CCC^[2] recommends that the UK Government should expand upon its existing UK Greenhouse Gas Removal Demonstrators programme, in order to further develop field experiments, pilots, and demonstration and commercialisation projects. For less mature GGRs, government support is necessary to enable innovation and demonstration, before the private sector deploys them in response to £/tCO₂ incentives^[59]. As for large-scale NETs, public funding provides a chance to develop and test the technology without the risk of private investment being retracted^[66]. Continued government support for pilot projects helps improve understanding of a technology's risks, so that appropriate safeguards can be put in place, as well as help provide financial certainty through long term contracts^[59]. Analysis by Vivid economics further builds upon this and suggests that research councils can fund research and innovation into low-carbon technologies through the Natural Environment Research Council (NERC), Economic & Social Research Council (ESRC), and Engineering and Physical Sciences Research Council (EPSRC)^[59]. Furthermore, the Government should help coordinate opportunities between GGRs and wider CCUS deployment, to help share the cost of CO₂ T&S infrastructure^[59].

Despite the benefit of Government funds, it is also necessary that fiscal incentivises are put in place. Without them the high capital and operating costs of GGRs makes private investment unattractive and there is lack of a stable revenue stream for the provision of negaisstive emions^[59]. Furthermore, pilot projects are needed to more fully understand the environmental impacts, negative emissions potential, and can help establish repeatable and effective practices in deploying land-based GGR^[59].

1.3.3.2 Expand the Contracts for Difference (CfD) scheme

The CfD scheme is the UK Government’s main mechanism for supporting low-carbon electricity generation. CfDs incentivise investment in renewable energy by providing developers of projects that have with high upfront costs and long lifetimes with direct protection from volatile wholesale prices, and they protect consumers from paying increased support costs when electricity prices are high. This is done by having a pre-agreed price for the low carbon electricity that the generators produce, for the duration of the contract – this is known as the ‘strike price’.

The CfD scheme could be expanded to include GGR or CCUS facilities. This approach could prove attractive to investors, as it secures a revenue stream for the GGR developers and reduces financial risk associated with upfront capital investment^[59]. Furthermore, it has proven to be successful in the past for renewable energy, which experienced significant cost reductions and scale up once initial CfDs were issued.

Analysis by Ricardo^[67] highlights that a CfD auction could be easily adjusted to target BECCS specifically, and be applied to the three main biomass conversion/CHP sites in Scotland: Markinch CHP (55 MWe), Steven's Croft power station (44 MWe), and Westfield Biomass Plant (10 MWe). These sites have potential to achieve 0.8MtCO₂/year of negative emissions^[67], which is equivalent to 15% of the CCPu’s 2032 target^[68] Further analysis by Vivid economics^[59]suggests that the ‘strike price’ for BECCS Power could be linked to the electricity price, whilst for BECCS Industry and DACCS the ‘strike price’ could be linked to the ETS price.

1.3.3.3 UK ETS

Prior to Brexit, the UK had adopted the EU-ETS. This policy allowed operators that undertook CCS to not have to surrender allowances where emissions had been verified as captured and permanently stored. The UK now has its own ETS, which follows a similar cap and trade scheme that caps the total level of GHG emissions a at a reserve price of £22/t. This cap will reduce in line with the UK’s Net Zero commitments (i.e., reaching zero by 2050), increasing the price. This scheme does not cover any GGRs^[69].

The Government can link contracts with GGR providers (i.e., CfDs) for revenue to the UK ETS, allowing offsets to be traded. This will act as an additional revenue source for GGR providers, helping us reduce the initial volatility of GGR revenues. The inclusion of GGRs in the UK ETS will help provide market-based solutions for stimulating investment, and move us towards a single, integrated compliance market for carbon, with negative emissions supporting liquidity as the ETS allowance cap falls over time^{[59], [62]}. However, the UK ETS won’t be a sufficient incentive on its own^[59].

1.3.3.4 GGR Obligation Scheme

As an alternative to including negative emissions within the UK ETS, a negative emissions obligation scheme could be implemented instead. This is viewed as a good alternative, as it avoids the risk of potentially undermining the UK ETS due to the uncertain nature of GGRs^{[59], [62]}. Companies would be required to secure negative emission certificates to meet their obligations, focussing on fossil fuel suppliers (calculated as a percentage of the carbon content of fuels) and wholesale distributors of agricultural products (calculated as a percentage of GHG emissions associated with agricultural activities). These certificates can be traded with other obligated emitters^{[59], [62]}. Additional benefits of the system include focussing on a “polluter pays principle”, which will be more politically acceptable, and the fact that the heaviest emitting sectors would be covered^{[59], [62]}. However, one key risk is pass through costs impacting low-income households disproportionately. Another key disadvantage is the initial limited GGR market size, which could lead to volatile certificate prices during the early stages of deployment, and risk weaking the incentives. Furthermore, the trading of these certificates would require rigorous accounting standards (please see the MRV section above)^{[59], [62]}.

1.3.3.5 GGR tax credit/carbon levy

This is a scheme where energy intensive industries receive a reduction in tax liabilities (£/tCO₂) if they adopt GGRs and/or CCS, which can then be traded to allow realisation of their true value^[59]. There two main options available: 1.) provide tax credits paid for in £/tCO₂ of GHGs removed, modelled after the 45Q tax credit for CCS; 2.) provide a tax credit for initial (capital) investment for GGRs, similar to the 48a/b tax code in the US^[62]. It has been proven in the past that high carbon prices/carbon taxes/tax credits have created markets where NETs are more commercially viable (e.g., the California carbon tax credit)^[66]. Please note that stakeholders believe tax credits should be available to everyone, and not just be limited to heavily polluting industries^[59].

The benefits of this tax credit are that it provides a strong incentive to develop capital intensive GGRs (e.g. BECCS Power), has a lower MRV accounting requirement compared to the GGR Obligation Scheme, and incentivises both emission reductions and GGR deployment simultaneously^[59]. However, a key risk is that tax credits can easily change overtime, which exposes investors to risk, and hence the Government needs to provide additional guarantees to ensure that tax credits will pursue over time. Furthermore, the monetary benefits of this scheme will go to corporations, which is less politically favourable than compared to the other options discussed. Finally, similar to the GGR Obligation Scheme, there is a risk of pass-through costs impacting low-income households^{[59], [62]}.

Analysis on the necessary carbon and negative emission prices needed to make BECCS and EfW-CCS competitive with coal-CCS and coal was conducted by Pour et al^[70]:

• For BECCS to be competitive with coal-CCS, the carbon price will need to be between £107/tCO₂* to £160/tCO₂ *
• For BECCS to be competitive with coal-CCS the negative emission price will need to be between £17/tCO₂ - £68/tCO₂ *
• For BECCS to be competitive with coal the negative emissions price needs to be between £68/tCO₂* to £135/tCO₂* respectively.
• For EfW-CCS to be competitive with coal-CCS, the negative emissions price needs to be £68/tonne* to complete with coal-CCS.
• For EfW-CCS to be competitive with coal, the carbon price will need to be between £110- £169/tCO₂*

We could also input a fertiliser tax to incentivise the application of biochar to soils^[59].

*Values converted from USD to GBP using conversion of 1 USD = 0.83 GBP.

1.3.3.6 GGR Subsidies

Subsidies from the Government are another option, which are categorised into:

1.) Targeted grants aimed at individual landowners who deploy small-scale GGR projects (e.g., biochar).

2.) Service contracts aimed at businesses that deploy large-scale GGRs.

In both instances, a government body responsible for the programme would screen the proposals based on feasibility and enter into contracts with successful bidders^[59].

Some key benefits associated with this incentive are its lower risk, its cost being progressively distributed across the tax base, and greater Government control over GGR locations. This latter point is important, as it enables targeted GGR deployment to maximise co-benefits. However, this choice of incentive is expensive (costing £6B-£20B/year by 2050) and leads to less efficient allocation of resources compared to market-based policies^[59]. These levers have not been included in the pathway analysis but could aid deployment, particularly in scenario 1).

1.3.3.7 Monitoring, verification and reporting (MVR)

Across the literature reviewed, a frequently cited barrier to GGR deployment is the lack of a MRV protocol^[2]. To ensure BECCS is low carbon, biomass feedstocks need to be sourced locally and sustainably. However, at present the IPCC's Guidelines for National Greenhouse Gas Inventories does not account for removals reported in the jurisdictions producing the biomass or storing the CO₂^[2], and there are no UNFCCC accounting guidelines for most GGRs^[59]. A robust MVR protocol would fill in these gaps; reducing the risk of relying on carbon-intensive biomass imports and accommodate for varying GHG accounting accuracies between different GGRs^[66]. This latter point is key, as it facilities an environment where negative emission certificates can be traded whilst maintaining certificate equivalence^[59]. Furthermore, an appropriate Certificate Authority (CA) should be established, who can issue negative emission certificates and hold the power to guarantee removals are verifiable and quantifiable^[59]. There is also a risk associated with the ‘mitigation deterrence’ effect of GGRs^[66], which refers to the risk of incentives making GGRs more attractive than compared to developing/adopting other low-carbon technologies^[2]. The Government has confirmed that they understand this risk, and will design an appropriate GGR monitoring scheme to combat it accordingly^[59]Please note that the Government has only partially accepted putting in place a MRV regime by 2024^[65].

Biochar carbon accounting is still under development and depends on the potential for mobilisation of the stored carbon and its possible return to atmosphere. Carbon permitting and regulations that prevents such releases will be necessary^[35].

1.3.3.8 Other policy options

The permanent land use change requirement could be relaxed to help support production of biomass for BECCS, so that farmers can more flexibly switch back to agricultural land use after an initial rotation, and biochar could be incentivised through inclusion in the Agriculture Reform Programme (ARP)^[59]. Furthermore, BECCS Hydrogen deployment could be scaled up if included in the Renewable Transport Fuels Obligation (RTFO)^[59].

1.3.3.9 Potential policy issues

The Climate Change Committee highlighted potential policy issues^[2]:

• Who has responsibility for accounting of GHG removals, does it lie with the producer or consumer?
• Setting a negative emission threshold may only lead to inefficient GGR technologies being deployed (e.g., a BECCS Power plant without heat recovery). This is counterintuitive, and policy should include a minimum NETs efficiency alongside any negative emissions thresholds.
• Public support for NETs is necessary, with analysis by the Climate Assembly highlighting the public’s negative view on engineered GGRs compared to natural solutions. Building early on with sequential small-scale deployment could help build a social license for engineered GGRs.
• Policy must ensure strong governance so that biomass is harvested sustainably. Biomass cannot be harvested if it is detrimental to the surrounding area and impacts natural CO₂ sequestration.

1.3.4 Existing International policies

In recent years, there have also been several global advancements in incentives that have been developed to promote the accelerated deployment of NETs. NETs policy support to date has predominantly focused on direct grant support, aimed at addressing financial barriers with deployment of NETs due to high upfront capital costs and potential high operating costs. However, efforts are underway to develop further incentives for NETs through regulations and mandatory standards.

In November 2022, the European Commission adopted a proposal for an EU-wide voluntary framework for certification of carbon removals^[71]. The proposal is now under review by EU countries and lawmakers to determine if it will be approved. The certification process must be credible, hence the proposal sets out proposed rules for independent verification of CO₂ removals, as well as proposed rules to recognise certification schemes that can be used to demonstrate compliance^[71]. The certification of carbon removals from NETs can help support future inclusion of NETs in carbon markets, hence providing a direct incentive to invest in the technologies.

An overview of existing global support mechanisms is outlined in Table 15 below.

Table 15. International NETs policy support

Policy support	Location	Year
BECCS reverse auction	Sweden	2021 (announced)
NETs tariff	Luxembourg	2022
Direct Air Capture combined with long-term carbon storage, coupled to existing low-carbon energy	US	2021
Bipartisan Infrastructure Law	US	2021

1.3.4.1 BECCS Reverse auction, Sweden

The Swedish Government has announced a reserve auction, covering bio-CCS projects with a total budget of £3.2 billion. The reverse auction will determine who can deploy BECCS at the lowest cost, with companies bidding on the quantities of CO₂ that can be captured^[72]. Winners of the auction will then receive support in the form of subsidies. The support will cover CO₂ capture, transport and storage fees over a period of 15 years. The Swedish Energy Agency hope to hold the first round of the auction in 2023, followed by storage occurring in 2026^[73].

1.3.4.2 NETs Tariff, Luxembourg

NETs have been concluded as being required to reach Net Zero targets for the EU and many of the member states, as part of the strategy identified in the European Green Deal and the 2021 European Climate Law. The EU commission has therefore proposed to develop the certification of carbon removals (CCR) which will be discussed in the first quarter of 2023. The aim of the CCR is to support the scale-up of atmospheric carbon removal with the use of engineered GGR technologies, such as BECCS and DACCS, as well as improved forestry and agriculture practises.

Luxembourg has developed and introduced national legislation to support engineered GGR, known as the Luxembourg Negative Emissions Tariff (LNET). The LNETS is designed as a support scheme to CCR based upon the German renewable energy feed-in tariff, providing a premium per tonne of removed carbon through five-year contracts assured by the government.

1.3.4.3 Direct Air Capture combined with long-term carbon storage, coupled to existing low-carbon energy, USA

This funding opportunity in the US aims to support front-end engineering design (FEED) studies for DACCS projects, capable of capturing a minimum of 5,000 tCO₂/year. Covering a total of £11.8 million*, 5 DACCS projects have received funding through this policy mechanism as of August 2022.

1.3.4.4 Bipartisan Infrastructure Law, USA

Beginning in 2021, the Bipartisan Infrastructure Law (BIL) aims to commercialise carbon management, industrial decarbonisation technologies and associated infrastructure, containing a total of £10.2 billion* to be provided over a five-year period. As part of the BIL, the Department of Energy (DOE) in the US will provide up to £3 billion* support to regional DAC hubs, with the aim of establishing four regional hubs capable of capturing 1 million tCO₂/year. The BIL is made up of several additional programmes, with a focus on carbon capture technologies, as well as transport and storage infrastructure.

*Values converted from USD to GBP using conversion of 1 USD = 0.83 GBP.

1.4 Non-engineered nets

Non-engineered NETs are out of scope of this report; however, we have summarised these in chapter 1.4 of the main report and Appendix 9 for reader reference.

1.5 Bioresources

Carbon capture technologies discussed in section 1.2, with the exception of DACCS, can only be considered NETs when combined with a feedstock which has absorbed carbon from the atmosphere. The negative emissions that can be achieved is therefore dependent on sourcing such feedstocks, ensuring sustainable supply and avoiding indirect land use change.

Ricardo studied the availability of bioresources in Scotland in 2022, for ClimateXChange (CXC)^[67]. The project subdivided feedstocks into directly combustible biomass and those more appropriate for anaerobic digestion or liquid biofuel production. This report has divided feedstock into solid and non-solid biomass.

The tables in sections 1.5.1 and 1.5.2 show the currently utilised biomass resource, and the available resource currently (latest available data), in 2030 and 2045. The available resource accounts for biomass that should be left in-situ (for maintenance of soil condition, for example) and those that remain after competing uses have been satisfied. Where the available resource equals the currently used resource, there is neither excess resource nor is the resource overused. Where the available resource exceeds the currently used resource, there is potential to increase the amount of biomass used for energy. Where the future available resource is lower than the currently used resource, the amount of biomass used for energy must decrease in the future or potentially use biomass at an unsustainable rate.

If biomass is sourced from forests, concerns may centre on woodland loss and degradation, and if sourced from dedicated energy crops there’s a risk of competition for land to grow food^[59]. The large-scale of biomass required can cause additional pressure on land, water and biodiversity^[74].

Table 16 shows some typical energy and density criteria for bioresources. Non-biogenic resources are also included in this table for reference.

Table 16: Chemical and energy properties of biogenic and non-biogenic fuels. Note non-biogenic fuels included in this list for reference

Type	Moisture content (%)	NCV (GJ/t)	Bulk density Kg/m3	Energy density GJ/m3
Biogenic
Miscanthus (balled)	25%	13	140-180	1.8-2.3
Wood chip	30%	13	250	3
Wood pellet	10%	18	650	11
Torrefied wood pellets[75]	0%	22	720	16
Non-biogenic
Natural gas	N/A	38	0.9	0.035
LPG	N/A	46	510	24
Heating oil	N/A	43	845	36
Coal (Anthracite)	N/A	33	1100	36
SRF*/RDF[76]	Site specific, up to 23 GJ/tonne depending on composition. Biomass content variable.

*Note that the acronym SRF can stand for solid recovered fuel or short rotation forestry, here we are talking about solid recovered fuel. We have not used the acronym for forestry in this report to minimise confusion.

1.5.1 Solid biomass

The largest source for solid biomass in Scotland is from the forestry industry. Use of roundwood suitable for timber for bioenergy is not considered viable. Therefore, the available resource includes only residues: Portions of small roundwood (SRW) and brash. Arboriculturally arising (tree felling in parks, verges and gardens) have also been included in the resource, assuming this is less likely to enter sawlog supply chains.

A secondary by-product of forestry are sawmill residues. These are predominantly woodchip (60%), with smaller quantities of sawdust (28%) and bark (11%). Wood processing industries take the largest share of this resource (54%), in woodchip and sawdust for purposes such as panel board production. 26% of sawmill residues are already used for bioenergy, including wood pellet production. Most bark is sold for other purposes, not used in wood production or energy.

Due to the long maturation time of traditional forestry plantations, the current level of forestation in Scotland is indicative of the availability of forestry and sawmill residues in the medium term. Future afforestation will not increase the availability of residues until after 2045. The availability of SRW for bioenergy (constituting the greatest part of the forestry residue resource) is expected to decline to 2045, whilst brash and arboricultural arisings may increase. However, the availability of large roundwood is expected to increase to 2037-41, resulting in greater production of sawmill residues. The estimate assumes half of the sawmill residue increase will be directed to bioenergy, increasing the proportion for this purpose from 26% currently to 34% in 2030. Beyond 2041, the supply of large roundwood (and therefore sawmill residues) is expected to decline.

Emerging sources for biomass, specifically intended for energy uses, are short rotation forestry (commonly referred to as SRF, but not in this report due to acronym used elsewhere), short rotation coppicing (SRC) and perennial energy crops. There is currently no largescale resource, however, the report estimates a potential SRF resource of 100kt/year by 2045 and a perennial energy crop resource (including short rotation coppice) of 150kt/year per year by 2030, rising to 640kt/year by 2045.

Previous work by Ricardo, for CXC, indicated a theoretical potential of 5.78, 1.75 and 0.52 Mt/year for short rotation forestry, SRC and miscanthus respectively^[67]. This work accounted for physical constraints on land suitability (such as access, soil type and climate). The later work for CXC (resulting in estimates presented in Table 17) assumed limits on planting rates for each type of energy crop. For short rotation forestry and Miscanthus this was fixed at 1000ha per year. For SRC this started at 1000 ha per year, increasing by 20% with each passing year. The planting area for SRC was limited to 5% of permanent grassland (amounting to 57,113 ha). This limit was imposed to comply with Greening rules at the time of the study and, at the assumed planting rate, is reached by 2036. SRF and Miscanthus planting is allowed up to the area of suitable land identified in the 2020 Ricardo study (912,600 ha and 51,800 ha, respectively), however neither limit is reached within the timeline of the model due to the restricted planting rate. It should also be noted that a rotation of 15 years was applied to short rotation forestry, therefore even if widespread planting begins by 2025, resource is not available until 2040.

Table 17: Solid biomass resource; current, 2030 and 2045 projections

Feedstock	Currently used for bioenergy (Mt)	Current available resource (Mt)	2030 available resource (Mt)	2045 available resource (Mt)
Forestry residues and arb arisings	1.12	1.2	0.94	0.95
Sawmill residues	0.45	0.45	0.98	0.81
Short rotation forestry	0	0	0	0.1
Perennial energy crops	0	0	0.15	0.64
Straw	0	0.29	0.29	0.29
Waste wood	0.29	0.29	0.29	0.29
Residual waste (biogenic component)	0.56	0.56	0.14	0.14

Straw is an agricultural residue of cereal crops, which may be directly combusted. There is currently no widespread use of straw for bioenergy in Scotland, straw also has a large number competing uses, such as: Animal bedding, feed and horticulture. These uses consume around 80% of the current production. Leaving a potential resource of 290kt, which is not expected to change to 2045.

Wood waste arises from a number of sectors. Cleaner wood comes from packaging, pallets and joinery, whilst dirtier waste wood arises from construction and demolition, civic amenity sites. Wood from fencing, railways and telegraph poles may be classed as hazardous waste due to use of preservatives. 290kt is currently used for bioenergy and the available resource is not expected to change throughout the time period.

Residual waste is the waste left after recyclables and food waste have been removed. The organic component of the residual waste for combustion is expected to decline from current levels, both from policies aimed at waste prevention (decoupling population and economic growth from waste quantities) and greater recovery of food waste for anaerobic digestion. The specific mix of fuel used in EfW sites determines the biogenic CO₂ that can be captured – our assumptions for future sites use an equivalent CO₂ capture potential per unit fuel input as the existing sites in operation – but if this mix changes, then the CO₂ capture potential will also vary.

1.5.2 Non-solid biomass

Non-solid wastes are those either entirely liquid or with comparatively low solid content. They are generally not suitable for direct combustion, without first drying to remove the liquid content, but are ideal for anaerobic digestion or some methods of liquid biofuel production. Table 18 and Table 19 both show the same resources, however, Table 19 expresses the quantity of resource as the energy content (MWh) of their assumed products, which is biodiesel for used cooking oil (UCO) and tallow, and biogas for all other resources. Comparison of the two tables highlights the large range in energy content across the resources, from 0.003 MWh/t for spent lees/wash (from whisky production), to 10.1 MWh/t for UCO to biodiesel.

Table 18: Non-solid biomass resource; current, 2030 and 2045 projections

Feedstock	Currently used for bioenergy (Mt)	Current available resource (Mt)	2030 available resource (Mt)	2045 available resource (Mt)
Food waste	0.18	0.18	0.27	0.27
Whisky by-products	0.74	2.49	2.75	3.16
Brewery by-products	0	0	0	0.01
Dairy by-products	0.03	0.04	0.04	0.04
Animal processing by-products	0	0.07	0.07	0.07
Sewage sludge	0.35	1.53	1.56	1.56
Farm slurries	0.07	10.26	10.26	10.26
Used cooking oil	0.01	0.02	0.02	0.02
Tallow	0.04	0.06	0.06	0.06

Table 19: Non-solid biomass resource; current, 2030 and 2045 projections, table presented in MWh. Quantities expressed in MWh (biogas or biodiesel for UCO and tallow).

Feedstock	Currently used for bioenergy (MWh)	Current available resource (MWh)	2030 available resource (MWh)	2045 available resource (MWh)
Food waste	202	202	299	299
Whisky by-products	145	319	379	479
Brewery by-products	0	0.57	1.14	2.06
Dairy by-products	5.80	8.64	8.64	8.64
Animal processing by-products	0	51.4	51.4	51.4
Sewage sludge	90.4	392	398	400
Farm slurries	8.66	1,187	1,187	1,187
Used cooking oil	138	210	213	214
Tallow	330	500	500	500

Food wastes arises from domestic and commercial sectors. Scotland has a target to reduce food waste by 33% by 2025. However, the Ricardo study assumed an increase in the rate of food waste collection, up to 70% by 2030. Therefore, there is a NETs increase in the available food waste resource.

Whisky by-products include draff, pot ale, spent lees/wash and distillers’ dark grains (DDG). Brewery by-products (spent grain, hops and yeast) provide a much smaller potential resource (both in weight and energy). These sectors have been identified as having growth potential. The CXC study has assumed a growth in production (and therefore by-products) of 7.5% by 2030 and 20% by 2045. Draff and DDGS have the greatest energy potential per tonne, but also have value as animal feed. The largest potential by weight and total energy is pot ale, a by-product of the first distillation process with sold content of only 4%, most of which is disposed of as waste-water.

The main dairy by-product is Whey (the liquid remains of cheese making). The current total production of 500kt is primarily located in Dumfries and Galloway, where it is mainly used for animal feed. However, a small amount of the resource (25.5kt) in Argyll and Bute is used for anaerobic digestion. The available resource is not expected to change from the current level to 2045.

Animal processing by-products include fish, shellfish and abattoir wastes (primarily blood and bones, and some fat). By energy content, shellfish waste (undersized shellfish or parts not suitable for consumption) has the greatest potential (81.6% of the available resource) and is not considered to have any competing uses. Animal blood and bones comprises 14.8% of the available resource, the total resource is greater than shellfish waste but is primarily used for fertiliser or animal feed, leaving a smaller resource available for bioenergy. The available resource is not expected to change.

Sewage sludge arises from waste treatment plants, the availability of the resource is expected to increase in proportion to Scotland’s population. An increase of 1.5% by 2030 and 2% by 2045. Some sewage sludge is dried for direct combustion and a larger amount already sent for AD, amounting to around 350kt. The available resource is estimated to be 4 times the currently utilised resource. These are naturally concentrated in areas of high population concentration.

Farm slurries constitute the largest non-solid biomass resource, by weight and total energy, it is also largely underutilised. These arise from dairy, beef and pig farms which may present difficulties for economic use as the resource is dispersed. The study has assumed that 75% of the resource may be available to bioenergy. The size of the resource is not expected to change from the present day to 2045.

Used cooking oil (UCO) and tallow are assumed to be used to produce biodiesel in Table 19. In comparison to other non-solid biomasses, the energy potential is out of proportion to the total mass due to their relatively high energy densities (10.1 and 9.1 MWh/t, respectively). UCO arises from catering premises, food factories and households. As with sewage sludge, the scale of the resource is expected to increase in proportion to Scotland’s population (increasing by 1.5% by 2030 and 2% by 2045). 70% of UCO is assumed to be available for bioenergy, alternative uses include lubricants and manufacturing additives.

Tallow is a by-product of meat processing, produced by rendering fat. Tallow, in common with many animal products, is categorised for permissible uses. Category 3 tallow, suitable for use is soap and cosmetics, is a high value product and unlikely to be used for energy. Category 2 tallow can be used for industrial applications. Category 1 may only be used for burning or fuel production, production is estimated as 55 ktper year, of which two thirds is already used for bioenergy. The current size of the resource is not expected to change to 2045.

1.6 CO₂transportation and storage (T&S)

The main methods of CO₂ transportation are via pipeline, shipping, rail or truck. Pipelines are favoured when transporting in large quantities (1–5 Mt) and over moderate distances (100–500 km), whilst shipping is better suited to longer journeys (>2,400 km). Shipping does have the advantage of being more flexible and scalable; however, it also requires well-developed hubs, terminals, and a pressurisation station to de-liquify compressed CO₂, all of which are expensive^[52].

Haszeldine et al^[35]estimated the cost of CCS implementation to be between £70-200/tCO₂ for capture and £20/tCO₂ for storage, which are expected to reduce by 50% by 2050 if deployed at scale (meaning capturing, transporting and storing CO₂ at capacities >400 ktCO₂/year)^[22].

The deployment of all NETs is dependent on CO₂ T&S and hydrogen infrastructure. In Scotland, the Acorn site shows the most promise, which plans to repurpose the Feeder 10 gas pipeline to transport CO₂ from Peterhead port to St Fergus gas terminal at a capacity of 12 MtCO₂/year and be sequestered in the North Sea. The site plans to be operational until 2060^[22]. In the instance that the Acorn site is not developed in time, the Scottish Government can utilise alternative CCUS clusters (e.g., East Coast Cluster) that aim to be in operation by the close of this decade. Table 20 shows a breakdown in typical CO₂ transport and storage costs.

Table 20: Breakdown in typical CO₂ transportation and storage costs

Category	Method	Cost (£/t CO2) *
CO2 Transport	Truck	11.8
	Train	6.8
	Onshore Pipeline	1.7 – 40.5
	Offshore Pipeline	3.4 – 48.5
	Shipping	10.1 – 18.6
Storage	Geological storage	9.3

*Values converted from USD to GBP using conversion of 1 USD = 0.83 GBP.

Additional costs found from IEAGHG Paper^[77]:

Table 21: Breakdown in typical CO₂ transportation and storage costs according to the IEAGHG

Category	Method	Capacity (MtCO2/year)	Cost range (£/tCO2)
CO2 transport	Onshore pipeline	3	3.32 - 9.12
		10	1.66 - 3.32
		30	1.08 - 1.66
	Offshore pipeline	3	5.81 - 12.44
		10	2.49 - 4.15
		30	1.66 - 2.07
CO2 Storage	Depleted Oil-Gas field onshore- reusing wells onshore	N/A	1.33 - 9.12
	Depleted Oil-Gas field no reusing wells onshore	N/A	1.33 - 13.02
	Saline formation onshore	N/A	2.49 - 14.93
	Depleted Oil-gas field offshore- reusing wells offshore	N/A	2.49 - 11.61
	Depleted Oil-Gas field offshore- no reusing wells offshore	N/A	3.9 - 18.25
	Saline formation offshore	N/A	7.46 - 25.71

*Costs are in per 250km of pipeline constructed. All costs quoted above were converted to sterling using a conversion factor of USD to 0.83 pounds.

Revised costs used in the LCOC Analysis

Table 22: Transport costs used in the LCOC analysis

Transport Mode	Distance (km)	Cost ($/tCO2)	Cost (£/tCO2/km)
Truck	100	13	0.126
Rail	598	7.3	0.013
Pipe (onshore)	250	5.5	0.015
Pipe (offshore)	100	4	0.033
	500	18	0.029
	>1000	30	0.024
Shipping	100	20	0.163
	500	24	0.039
	>1000	27	0.022

Table 23: Storage costs used in the LCOC analysis

Storage Method	Cost (£/tCO2)
	Low	High
Depleted Oil-Gas field onshore- reusing wells onshore	1.292256972	8.884266682
Depleted Oil-Gas field no reusing wells onshore	1.292256972	12.68027154
Saline formation onshore	2.422981822	14.53789093
Depleted Oil-gas field offshore- reusing wells offshore	2.422981822	11.3072485
Depleted Oil-Gas field offshore- no reusing wells offshore	3.796004855	17.76853336
Saline formation offshore	7.268945467	25.03747883