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

Appendix 2. LCOC analysis

Data sources

Disregarded sites

The following sites were disregarded due to a lack of data in the literature, the site is fossil fuel powered, and/or the site is located on an island. In the instance that the site is an island, the capture carbon would have to be shipped and then transported by road to one pf our chosen CO₂ injection points, which is unrealistic given that the site will offer low CO₂ capture potentials.

Table 40: A list of sites disregarded from our analysis

Site	Owner	Type of Technology	Reason
North British Distillery	Lothian Distillers	Grain whisky	Already deploys CCS
Caol Ila	Diageo	Malt whisky	Island based
Laphroaig	Beam Suntory	Malt whisky
Bunnahabhain	Burn Stewart Distillers (Distell International)	Malt whisky
Highland Park	The Edrington Group	Malt whisky
Jura	Whyte & Mackay (Emperador)	Malt whisky
Lagavulin	Diageo	Malt whisky
Bowmore	Beam Suntory	Malt whisky
Bruichladdich	Rémy Cointreau	Malt whisky
Scapa	Chivas Brothers Ltd. (Pernod Ricard)	Malt whisky
Ardbeg	The Glenmorangie Co. (LVMH)	Malt whisky
Arran	Isle of Arran Distillers	Malt whisky
Tobermory	Burn Stewart Distillers (Distell International)	Malt whisky
Lagg	Isle of Arran Distillers	Malt whisky
Ardnahoe	Hunter Laing & Co.	Malt whisky
Kilchoman	Kilchoman Distillery Co.	Malt whisky
Harris	Isle of Harris Distillers Ltd.	Malt whisky
Isle of Raasay	R&B Distillers	Malt whisky
Abhainn Dearg	Mark Tayburn	Malt whisky
Lerwick Energy Recovery Plant	Shetland Islands Council	BECCS EfW (Heat only)
Western Isles Integrated Waste Management Facility	Western Isles Waste Management	BECCS AD (CHP)
Pulp Mill House[150]	Pulp-tec	BECCS Industry (pulp)	Lack of data
Cullen[151]	Robert Cullen Ltd	BECCS Industry (pulp)
Sapphire Mill	Fourstones Paper Mill Co Ltd	BECCS Industry (paper towel)	A gas-powered site. No potential for NETs

BECCS Biomethane

The following sites considered were identified using the NNFCC database and REPD.

Table 41: BECCS Biomethane data point summary. Extracted from the literature and used in the calculations for the NETs Model

Plant	Owner	Operational Status	Type of Technology	Gross Electrical Capacity (MWe)	Feedstock Capacity (t/year)	Biomethane produced (m3/hr)	Data source
Portgordon Maltings Beyside	Grissan Energy	Operational	Biomethane grid injection & CHP	5	837,500	800	NNFCC
Brae of Pert Farm	Qila Energy	Operational	Biomethane grid injection & CHP	0.25	35,000	550	NNFCC
Charlesfield Industrial Estate	Charlesfield First	Operational	Biomethane grid injection & CHP	0.249	24,995	550	NNFCC
Cumbernauld AD	Shanks	Operational	Biomethane grid injection & CHP	3.6	100,000	495	NNFCC
Downiehills Farm	Buchan Biogas	Operational	Biomethane grid injection & CHP	0.5	55,000	550	NNFCC
Girvan Distillery	Grissan Energy	Operational	Biomethane grid injection & CHP	7.2	300,000	2,750	NNFCC
Glenfiddich Distillery	William Grant & Sons	Operational	Biomethane grid injection	3.5	80,000	2,000*	NNFCC
Hatton Farm AD	Grissan Energy	Operational	Biomethane grid injection & CHP	0.5	38,000	450	NNFCC
Inchdairnie Farm	Qila Energy	Operational	Biomethane grid injection & CHP	2	40,000	500	NNFCC
Invergordon Distillery	Whyte & Mackay	Operational	Biomethane grid injection & CHP	0.25	36,500	500	NNFCC
Keithick Farm	Keithick Biogas	Operational	Biomethane grid injection & CHP	0.249	36,000	605	NNFCC
Lockerbie Creamery	Lockerbie Biogas Ltd	Operational	Biomethane grid injection	0.5	98,250	768	NNFCC
Morayhill AD	Qila Energy	Operational	Biomethane grid injection & CHP	0.25	40,000	495	NNFCC
Peacehill Farm	TD Forster & Son	Operational	Biomethane grid injection & CHP	0.237	30,450	550	NNFCC
Rosskeen Farm	Qila Energy	Operational	Biomethane grid injection & CHP	0.25	36,000	450	NNFCC
Savock Farm	Qila Energy	Operational	Biomethane grid injection & CHP	0.25	40,000	600	NNFCC
Tambowie Farm	Tambowie Biogas	Operational	Biomethane grid injection & CHP	0.973	24,000	220	NNFCC
TECA AD	Aberdeen City Council	Operational	Biomethane grid injection & CHP	0.35	81,012	425	NNFCC
Portgordon Maltings – Anaerobic Digestion Facility	Grissan Engineering Services Limited	Permission Granted	Biomethane	0	0	2,000**	REPD
Lockerbie Creamery – Anaerobic Digester	Lockerbie Biogas Limited	Permission Granted	Biomethane	0	0	916***	REPD
Mains Of Boquhan - Anaerobic Digester Facility	Grahams Family Dairy	Permission Granted	Biomethane	0	21,500	274****	REPD
Millerhill AD	Biogen	Operational	BECCS Biomethane (grid injection & CHP)	1.5	35,000	445.6	NNFCC

* Regarding the Glenfiddich Distillery site, it is split into two installations. The first consists of two 11.5m high by 30m diameter reactors with a 3.5 MW biogas-fuelled CHP^[152], and the second installation includes two 14.7m high by 28m diameter reactors^[153]. Assuming a standard medium-sized anaerobic digestor tank produces around 500m3/hr of biomethane, the estimated biomethane production potential is approximately 2000 m3/hr.

** The information provided in the REPD Database regarding the operational capacity of the Portgordon Maltings site was insufficient. To obtain more comprehensive details, we conducted a thorough examination of the planning application submitted to the council.^[154] Our investigation revealed that the project had been divided into two phases, which were represented separately in the REPD. The complete project consists of four primary digester plant tanks, each measuring 28m in diameter and 16.9m in height, along with three smaller feedstock tanks measuring 22.5m in diameter and 10m in height. The primary source of feedstock for the project will be waste from the malting plant and nearby distilleries. Considering that both project phases are located on the same site, we have chosen to merge them. Based on the assumption that an average biomethane tanker has a capacity of 500 m3/hr, we have determined a total site capacity of 2,000 m³/year.

*** The information provided in the REPD Database regarding the operational capacity of the Lockerbie Creamery site was insufficient. To obtain more comprehensive details, we conducted a thorough examination of the planning application submitted to the council.^[155] The application for the project exhibited several variations, and according to the SEPA permit, the installation will comprise of two 1.5MWth input natural gas CHP units and inject around 54,965 MWh of biomethane into the grid. This injection rate is equivalent to ~5,496,500 m3/year, which we have utilised in our analysis.

**** The information provided in the REPD Database regarding the operational capacity of the Mains of Boquhan site was insufficient. To obtain more comprehensive details, we conducted a thorough examination of the planning application submitted to the council.^[156] According to the application, the site is designated as an AD Upgrading facility utilizing the water scrubbing method. The proposed feedstock inputs for the facility include whey (20,000t), sludge from milk pasteurization (500t), manure (500t), and grass silage (500t), totalling 21,500 tonnes per year. Since the provided data only pertains to feedstock inputs, it was necessary to employ calculations specific to BECCS AD Upgrading to determine the biomethane production capacity and associated costs. This approach differs from the methodology used for other BECCS Biomethane sites.

BECCS Power

The following sites considered were identified using the REPD.

Table 42: BECCS Power data point summary. Extracted from the literature and used in the calculations for the NETs Model

Plant	Owner	Operational Status	Type of Technology	Gross Electrical Capacity (MWe)	Data source
Markinch Biomass CHP Plant	RWE	Operational	BECCS Power (CHP)	65	REPD
Stevens Croft	E.ON	Operational	BECCS Power	50.4	REPD
Westfield Biomass Power Station	EPR Scotland	Operational	BECCS Power	12.5	REPD
Speyside Biomass CHP Plant	Speyside Renewable Energy Partnership	Operational	BECCS Power (CHP)	12.5	REPD
Rothes Bio-Plant	Scottish Bio-Power	Operational	BECCS Power (CHP)	8.3	REPD
Sustainable Power and Research Campus	University of St Andrews	Operational	BECCS Power (CHP)	6.5	REPD
Acharn Forest Killin Biomass Plant	Northern Energy Developments	Operational	BECCS Power (CHP)	5.6	REPD
Diageo Biomass Energy Project	Diageo	Operational	BECCS Power	5.5	REPD
Harbour Road	Glennon Brothers Troon	Operational	BECCS Power (CHP)	2.6	REPD
Gleneagles Hotel Biomass Boiler Plant Room	AMP Energy Services Limited	Operational	BECCS Power	1.2	REPD
Macphie of Glenbervie	Macphie Ltd.	Operational	BECCS Power	1.2	REPD
Co-Op, Polwarth Street - Biomass boilers	Gold Energy Limited	Permission Granted	BECCS Power	0.44	REPD
Hillhead Of Coldwells, Longhaven - Biomass Boilers	Private Developer	Permission Granted	BECCS Power	0.26	REPD
Little Broomfield - Biomass boiler	Private Developer	Permission Granted	BECCS Power	0.21	REPD

BECCS Industry

The sites considered were identified using the REPD, HNPD, SPRI, and CHPQA databases. The Morayhill Mill site was identified through the REPD, but site-specific data was obtained through stakeholder engagement.

Table 43: BECCS Industry data point summary. Extracted from the literature and used in the calculations for the NETs Modell

Plant	Owner	Operational Status	Type of Technology	Gross Electrical Capacity (MWe)	Data source
Caledonian Papermill	Caledonian Paper	Operational	BECCS Industry CHP (paper - coated magazine)	26	REPD and CHPQA
Cowie Biomass Facility	Norbord	Operational	BECCS Industry CHP (Particle & MDF)	15	REPD and CHPQA
Invergordon Pellet Mill	Balcas	Operational	BECCS Industry CHP (wood pellets)	5	REPD and CHPQA
Morayhill Mill	Norbord	Operational	BECCS Industry (Oriented Strand Board)	100*	Stakeholder engagement
Barony Road, Auchinleck	Egger Barony LTD (particle)	Operational	BECCS Industry CHP (Chipboard and wood recycling)	5.5	HNPD
Dunbar Cement	Tarmac	Operational	BECCS Industry (Cement)	N/A	SPRI and websites[114], [108]

Please note that the REPD mistakenly states that the following sites are not CHPs: Caledonian Papermill, Cowie Biomass Facility, Invergordon Pellet Mill, and Barony Road, Auchinleck. We understand that these sites are CHPs based off previous CHPQA submissions and additional information found in the literature.

No data on the heat and power usages of the Dunbar Cement site could be found in the literature; therefore, the carbon capture capacity of the site was determining using data submitted to SEPA under the SPRI Database. This in turn was used to determine the costs. The only data that was found was the production of 867 t,clinker per day^[114] and that the site aims to use a fuel mixture that consists of 45% SRF^[108]_.

Caledonian Paper Mill

This paper mill has been in production since April 1989 and has the capacity to produce 250,000 tonnes of lightweight coated paper (LWC) specifically designed for printing magazines, catalogues, and brochures^[157]. The mill operates a 26 MWe CHP plant that exclusively uses 100% biomass as fuel, derived from both virgin and recycled sources, including solids sourced from a primary effluent treatment plant.

Cowie Biomass Facility

The site produces Caberfloor^[158], a specially processed and compressed woodchip material. The site operates both a large biomass boiler that produces steam as well as two high-pressure natural-gas turbines to produce hot exhaust gas and to supply on-site power. The SPRI database indicates emissions with a biomass content of 72.4%, but it is unclear whether this includes sources outside of the CHP plant.

Invergordon Pellet Mill

This site produces wood pellets^[159]. Again, there is limited data on site heat and power demands, with the planning application^[160] and REPD mentioning that a biomass fired CHP is present onsite.

Morayhill Mill

This site manufactures Oriented Strand Board (OSB) using timber chips sourced from nearby sawmills. Any timber residue from the plant is used to fuel a biomass boiler. This includes bark stripped from the logs at the start of the manufacturing process, wood dust extracted from various production processes around the plant, along with any timber residue and non-specification timber flakes. The burner generates heat for use in the drying and curing stages in board production. The SPRI database confirmed that emissions from this site are 100% biogenic.

After some stakeholder engagement we learnt that there are two biomass burners present onsite, one 57 MW_th and the other 43 MW_th.

Egger Barony

This site manufactures approximately 400,000 m³ of raw chipboard per annum^[161], which can then either be used in its raw form or be upgraded for use in the furniture and interior design markets or building market. In 2021 Egger stated that they wish the Barony plant to be powered 100% through a new biomass CHP (5.5 MWe output) and generate hot gas to be used in drying wood material^[162]. This CHP has now been completed and features in the Heat Networks Planning Database^[163], where heat is sold to an industrial customer nearby consisting of three buildings. The SPRI database confirmed that emissions from this site are 100% biogenic.

Dunbar Cement

The site produces 867 t/d of clinker with a heat consumption of 3.26 MJ/kg^[114].

Dunbar cement plant by agreeing a contract with leading Scottish resource management company, Hamilton Waste and Recycling, to begin using Solid Recovered Fuel (SRF) at the plant^[164]. Combined with other waste-derived fuels, this new supply of SRF at Dunbar will support our aim to replace up to 45% of its traditional fossil-based fuels with alternatives which are fully or partially classed as carbon neutral.

Disregarded sites

Sapphire Mill was initially considered, since it manufactures paper towels. However, upon further investigation, we found that the site sources heat and power demands via natural gas. This was reflected in the SPRI database which shows no mention of biogenic emissions.

The sites Pulp Mill House and Robert Cullen Ltd were all considered due their work in manufacturing moulded pulp. However, since no information was available on their site operations then they were removed from the analysis.

BECCS AD

The sites considered were identified using the NNFCC database and REPD.

Table 44: BECCS AD data point summary. Extracted from the literature and used in the calculations for the NETs Model

Plant	Owner	Operational Status	Type of Technology	Gross Electrical Capacity (MWe)	Feedstock Capacity (t/year)	Data source
Rainton Farm	D Finlay & Son	Operational	BECCS AD (CHP)	0.025	2,500	NNFCC
Loanhead Farm	N Poett	Operational	BECCS AD (CHP)	0.05	2,000	NNFCC
Carterhaugh Farm	BQ Farming Partnership	Operational	BECCS AD (CHP)	0.195	2,000	NNFCC
Genoch Mains Farm	Mr J McIntosh	Operational	BECCS AD (CHP)	0.225	17,500	NNFCC
Genoch Mains Farm (Extension)	Mr J McIntosh	Operational	BECCS AD (CHP)	0.237	17,500	NNFCC
Kirkton Farm	Kirkton Farm	Operational	BECCS AD (CHP)	0.475	2,000	NNFCC
Wester Clockeasy Farm	AGTEC	Operational	BECCS AD (CHP)	0.125	5,000	NNFCC
Dronley Farm AD	Dronley Farming Ltd	Operational	BECCS AD (CHP)	0.0623	3,000	NNFCC
East Reston Farm AD	RH & DH Allan	Operational	BECCS AD (CHP)	0.076	3,500	NNFCC
Mains of Fortrie AD	D Bartlet & Son	Operational	BECCS AD (CHP)	0.076	3,500	NNFCC
Old Ballikinrain House AD	M Percy Ltd	Operational	BECCS AD (CHP)	0.076	3,500	NNFCC
Forthar Farm AD	J&C Wilson	Operational	BECCS AD (CHP)	0.1275	5,000	NNFCC
Meinside AD	Mein Farming Ltd	Operational	BECCS AD (CHP)	0.088	4,500	NNFCC
Baltier Farm	Baltier Farm	Operational	BECCS AD (CHP)	0.5	10,000	NNFCC
Girvan Road AD	AGTEC	Operational	BECCS AD (CHP)	0.098	7,000	NNFCC
Lemington Farm AD	Greenshields Agri Ltd	Operational	BECCS AD (CHP)	0.18	8,000	NNFCC
Mayfield Farm	PALL	Operational	BECCS AD (CHP)	0.2	7,000	NNFCC
Balmangan Farm	Mathers Dairy Utensils	Operational	BECCS AD (CHP)	0.124	5,500	NNFCC
Crofthead farm	W Callander	Operational	BECCS AD (CHP)	0.124	3,000	NNFCC
Slacks Farm	D Kincaid	Operational	BECCS AD (CHP)	0.124	3,000	NNFCC
Standingstone Farm	Mathers Dairy Utensils	Operational	BECCS AD (CHP)	0.124	5,500	NNFCC
East Denside Farm	M Forbes	Operational	BECCS AD (CHP)	0.243	5000	NNFCC
Knockrivoch Farm	Knockrivoch Farm	Operational	BECCS AD (Heat only)	0.15*	480	NNFCC
East Knockbrex AD	Iain Service & Co Ltd	Operational	BECCS AD (CHP)	0.154	12,800	NNFCC
Littleton Farm (2)	Mathers Dairy Utensils	Operational	BECCS AD (CHP)	0.19	5,500	NNFCC
Harpers Transport AD	Harpers Transport	Operational	BECCS AD (CHP)	0.197	10,000	NNFCC
Ignis Wick AD	Ignis Wick Ltd	Operational	BECCS AD (CHP)	0.197	6,000	NNFCC
Balmachie Farm AD	JF Lascelles	Operational	BECCS AD (CHP)	0.086	4,000	NNFCC
Slains Park Farm	J Forbes	Operational	BECCS AD (CHP)	0.399	8,000	NNFCC
Standhill Farm	JG Shanks & Son	Operational	BECCS AD (CHP)	0.185	11,000	NNFCC
Woodside Farm	AGTEC	Operational	BECCS AD (CHP)	0.1792	5,228	NNFCC
Balmenach Distillery	Inver House Distillers	Operational	BECCS AD (CHP)	0.25	5,000	NNFCC
Auchencheyne AD	Auchencheyne Ltd	Operational	BECCS AD (CHP)	0.1275	5,000	NNFCC
Girvan Mains Farm	AB Young	Operational	BECCS AD (CHP)	0.238	8,000	NNFCC
Allerbeck Farm	Wyseby Hill Ltd	Operational	BECCS AD (CHP)	0.093	5,770	NNFCC
Camieston Farm AD	Camieston Renewables Ltd	Operational	BECCS AD (CHP)	0.485	18,000	NNFCC
Kinknockie Farm	Yorston & Sinclair	Operational	BECCS AD (CHP)	0.457	9,500	NNFCC
Gask Farm	J Rennie & Son	Operational	BECCS AD (CHP)	0.46	15,000	NNFCC
Broadwigg Farm	N Forsyth & Son	Operational	BECCS AD (CHP)	0.465	28,000	NNFCC
North British Distillery AD	North British Distillery	Operational	BECCS AD (CHP)	0.479	9,855	NNFCC
Bendochy Farm	ET Bioenergy	Operational	BECCS AD (CHP)	0.44	9,500	NNFCC
Claylands Farm	Strathendrick Biogas	Operational	BECCS AD (CHP)	0.499	30,000	NNFCC
Dailuaine Distillery	Diageo	Operational	BECCS AD (CHP)	0.5	15,000	NNFCC
Edge Farm Composting	GP Green Recycling	Operational	BECCS AD (CHP)	0.5	12,000	NNFCC
Glendullan Distillery	Diageo	Operational	BECCS AD (CHP)	0.5	15,000	NNFCC
Levenseat Recycling facility	Levenseat	Operational	BECCS AD (CHP)	0.5	25,000	NNFCC
Pure Malt Products	Pure Malt Products	Operational	BECCS AD (CHP)	0.5	25,000	NNFCC
Roseisle Speyside Whisky Distillery	Diageo	Operational	BECCS AD (CHP)	0.5	47,450	NNFCC
Charlesfield Farm	Hoddom & Kinmount Estates	Operational	BECCS AD (CHP)	0.475	11,200	NNFCC
Glenmorangie Distillery	Glenmorangie	Operational	BECCS AD (Heat only)	940	0	NNFCC
Wester Alves Farm	Wester Alves Biogas	Operational	BECCS AD (CHP)	0.8	25,000	NNFCC
Wester Kerrowgair Farm	Qila Energy	Operational	BECCS AD (CHP)	0.45	20,650	NNFCC
GSK Irvine	GlaxoSmithKline	Operational	BECCS AD (CHP)	0.98	10,000	NNFCC
Deerdykes Composting and Organics Recycling Facility	Scottish Water Horizons	Operational	BECCS AD (CHP)	1	30,000	NNFCC
Auchentoshan Distillery	Morrison Bowmore Distillers	Operational	BECCS AD (CHP)	0.5	20,000	NNFCC
West Roucan Farm	J Cunnigham-Jardine	Operational	BECCS AD (CHP)	0.95	20,000	NNFCC
Lochhead Landfill (Dry-AD)	Fife Council	Operational	BECCS AD (CHP)	1.14	45,000	NNFCC
Binn Farm AD	TEG Biogas	Operational	BECCS AD (CHP)	1.4	30,000	NNFCC
Barkip AD	SSE	Operational	BECCS AD (CHP)	2.2	75,000	NNFCC
Charlesfield Industrial Estate (2)	Iona Capital	Operational	BECCS AD (CHP)	3	36,000	NNFCC
Glenfiddich Distillery AD (Extension)	William Grant and Sons Distillers	Permission Granted	BECCS AD (CHP)	2	0	REPD
Skeddoway Farm	RM Brown & Son	Operational	BECCS AD (CHP)	2	0	NNFCC
Energen biogas Cumbernauld	Bio Capital Limited	Operational	BECCS AD (CHP)	2.4	0	REPD
Balmcassie Commercial Park - Anaerobic digestion plant	Brewdog Limited	Under Construction	BECCS AD (CHP)	3.5	0	REPD
Academy Road - Energy Centre & Anaerobic Digestion Facility	Grissan Engineering Services Limited	Permission Granted	BECCS AD (CHP)	4	0	REPD
Glasgow Renewable Energy and Recycling Centre	Viridor	Operational	BECCS AD (CHP)	4	100,000	NNFCC
Cameron Bridge Distillery	Diageo	Operational	BECCS AD (CHP)	5.5	90,000	NNFCC

*Heat only site so units are kW_th

BECCS Fermentation

This data from whisky distilleries was taken from Whisky Invest Direct^{[165], [166]} and for beer producing sites from the Scottish Carbon Capture Storage (SCCS)^[92].

Table 45: BECCS Fermentation data point summary. Extracted from the literature and used in the calculations for the NETs Model

Plant	Owner	Operational Status	Type of Technology	Alcohol production Capacity (MLPA)	Data source
Cameronbridge	Diageo	Operational	Grain whisky	110	Whisky Invest Direct
Girvan	William Grant & Sons	Operational	Grain whisky	110	Whisky Invest Direct
Invergordon	Whyte & MacKay	Operational	Grain whisky	36	Whisky Invest Direct
Strathclyde	Chivas Brothers	Operational	Grain whisky	39	Whisky Invest Direct
Starlaw/Glen Turner Distillery	La Martiniquaise	Operational	Grain whisky	25	Whisky Invest Direct
Loch Lomond (Grain)	Loch Lomond Group	Operational	Grain whisky	18	Whisky Invest Direct
Reivers	Mossburn Distillery Co.	Operational	Grain whisky	0.1	Whisky Invest Direct
Glenlivet	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	21	Whisky Invest Direct
Glenfiddich	William Grant & Sons	Operational	Malt whisky	21	Whisky Invest Direct
Macallan	The Edrington Group	Operational	Malt whisky	15	Whisky Invest Direct
Ailsa Bay	William Grant & Sons	Operational	Malt whisky	12	Whisky Invest Direct
Glen Ord	Diageo	Operational	Malt whisky	11.5	Whisky Invest Direct
Roseisle	Diageo	Operational	Malt whisky	10.8	Whisky Invest Direct
Dalmunach	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	10.5	Whisky Invest Direct
Teaninich	Diageo	Operational	Malt whisky	10.2	Whisky Invest Direct
Glenmorangie	The Glenmorangie Co. (LVMH)	Operational	Malt whisky	6.5	Whisky Invest Direct
Glen Grant	Campari Group	Operational	Malt whisky	6.1	Whisky Invest Direct
Glen Moray	Glen Turner (La Martiniquaise)	Operational	Malt whisky	6	Whisky Invest Direct
Dufftown	Diageo	Operational	Malt whisky	5.9	Whisky Invest Direct
Miltonduff	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	5.8	Whisky Invest Direct
Glen Keith	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	5.7	Whisky Invest Direct
Auchroisk	Diageo	Operational	Malt whisky	5.7	Whisky Invest Direct
Balvenie	William Grant & Sons	Operational	Malt whisky	5.6	Whisky Invest Direct
Glenrothes	The Edrington Group	Operational	Malt whisky	5.5	Whisky Invest Direct
Tomatin	Tomatin Distillery Co.	Operational	Malt whisky	5	Whisky Invest Direct
Ardmore	Beam Suntory	Operational	Malt whisky	4.9	Whisky Invest Direct
Tormore	Elixir Distillers	Operational	Malt whisky	4.9	Whisky Invest Direct
Dailuaine	Diageo	Operational	Malt whisky	4.9	Whisky Invest Direct
Loch Lomond (Malt)	Loch Lomond Group	Operational	Malt whisky	4.75	Whisky Invest Direct
Longmorn	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	4.7	Whisky Invest Direct
Clynelish	Diageo	Operational	Malt whisky	4.7	Whisky Invest Direct
Allt-a-Bhainne	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	4.5	Whisky Invest Direct
Braeval	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	4.5	Whisky Invest Direct
Kininvie	William Grant & Sons	Operational	Malt whisky	4.4	Whisky Invest Direct
Glenburgie	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	4.3	Whisky Invest Direct
Dalmore	Whyte & Mackay (Emperador)	Operational	Malt whisky	4.3	Whisky Invest Direct
Speyburn	Inver House Distillers (Thai Beverages plc)	Operational	Malt whisky	4.2	Whisky Invest Direct
Craigellachie	John Dewar & Sons (Bacardi)	Operational	Malt whisky	4.2	Whisky Invest Direct
Tamnavulin	Whyte & Mackay (Emperador)	Operational	Malt whisky	4.2	Whisky Invest Direct
Glentauchers	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	4.1	Whisky Invest Direct
Royal Brackla	John Dewar & Sons (Bacardi)	Operational	Malt whisky	4.1	Whisky Invest Direct
Tamdhu	Ian Macleod Distillers	Operational	Malt whisky	4	Whisky Invest Direct
Glenfarclas	J. & G. Grant	Operational	Malt whisky	4	Whisky Invest Direct
Glenallachie	The Glenallachie Distillers Co.	Operational	Malt whisky	4	Whisky Invest Direct
Aberlour	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	3.8	Whisky Invest Direct
Mortlach	Diageo	Operational	Malt whisky	3.8	Whisky Invest Direct
Linkwood	Diageo	Operational	Malt whisky	3.7	Whisky Invest Direct
Benrinnes	Diageo	Operational	Malt whisky	3.6	Whisky Invest Direct
Glendullan	Diageo	Operational	Malt whisky	3.6	Whisky Invest Direct
Macduff [Glen Deveron]	John Dewar & Sons (Bacardi)	Operational	Malt whisky	3.4	Whisky Invest Direct
Tomintoul	Angus Dundee Distillers	Operational	Malt whisky	3.3	Whisky Invest Direct
Cardhu	Diageo	Operational	Malt whisky	3.3	Whisky Invest Direct
Aberfeldy	John Dewar & Sons (Bacardi)	Operational	Malt whisky	3.3	Whisky Invest Direct
Laphroaig	Beam Suntory	Operational	Malt whisky	3.275	Whisky Invest Direct
Inchgower	Diageo	Operational	Malt whisky	3.2	Whisky Invest Direct
Aultmore	John Dewar & Sons (Bacardi)	Operational	Malt whisky	3.2	Whisky Invest Direct
Talisker	Diageo	Operational	Malt whisky	3	Whisky Invest Direct
Tullibardine	Picard Vins & Spiriteaux	Operational	Malt whisky	2.9	Whisky Invest Direct
BenRiach	Benriach Distillery Co. (Brown Forman)	Operational	Malt whisky	2.8	Whisky Invest Direct
Glenlossie	Diageo	Operational	Malt whisky	2.8	Whisky Invest Direct
Balmenach	Inver House Distillers (Thai Beverages plc)	Operational	Malt whisky	2.8	Whisky Invest Direct
Deanston	Burn Stewart Distillers (Distell International)	Operational	Malt whisky	2.7	Whisky Invest Direct
Glen Elgin	Diageo	Operational	Malt whisky	2.6	Whisky Invest Direct
Mannochmore	Diageo	Operational	Malt whisky	2.6	Whisky Invest Direct
Strathisla	Chivas Brothers Ltd. (Pernod Ricard)	Operational	Malt whisky	2.5	Whisky Invest Direct
Blair Athol	Diageo	Operational	Malt whisky	2.5	Whisky Invest Direct
Glenkinchie	Diageo	Operational	Malt whisky	2.5	Whisky Invest Direct
Fettercairn	Whyte & Mackay (Emperador)	Operational	Malt whisky	2.3	Whisky Invest Direct
Cragganmore	Diageo	Operational	Malt whisky	2.2	Whisky Invest Direct
Dalwhinnie	Diageo	Operational	Malt whisky	2.2	Whisky Invest Direct
Auchentoshan	Beam Suntory	Operational	Malt whisky	2.15	Whisky Invest Direct
Ben Nevis	Ben Nevis Distillery Ltd (Nikka, Asahi Breweries)	Operational	Malt whisky	2	Whisky Invest Direct
Strathmill	Diageo	Operational	Malt whisky	2	Whisky Invest Direct
Inchdairnie	Inchdairnie Distillery Ltd	Operational	Malt whisky	2	Whisky Invest Direct
Glendronach	Benriach Distillery Co. (Brown Forman)	Operational	Malt whisky	1.8	Whisky Invest Direct
Balblair	Inver House Distillers (Thai Beverages plc)	Operational	Malt whisky	1.8	Whisky Invest Direct
Knockdhu [AnCnoc]	Inver House Distillers (Thai Beverages plc)	Operational	Malt whisky	1.8	Whisky Invest Direct
Borders	The Three Stills Co. Ltd	Operational	Malt whisky	1.8	Whisky Invest Direct
Glen Spey	Diageo	Operational	Malt whisky	1.6	Whisky Invest Direct
Bladnoch	Bladnoch Distillery Ltd	Operational	Malt whisky	1.5	Whisky Invest Direct
Glencadam	Angus Dundee Distillers	Operational	Malt whisky	1.4	Whisky Invest Direct
Knockando	Diageo	Operational	Malt whisky	1.4	Whisky Invest Direct
Pulteney	Inver House Distillers (Thai Beverages plc)	Operational	Malt whisky	1.4	Whisky Invest Direct
Glen Garioch	Beam Suntory	Operational	Malt whisky	1.3	Whisky Invest Direct
Glengoyne	Ian Macleod Distillers	Operational	Malt whisky	1.1	Whisky Invest Direct
Glenglassaugh	Benriach Distillery Co. (Brown Forman)	Operational	Malt whisky	1	Whisky Invest Direct
Ardross	Greenwood Distillers	Operational	Malt whisky	1	Whisky Invest Direct
Oban	Diageo	Operational	Malt whisky	0.8	Whisky Invest Direct
Brora/Clynelish Distillery	Diageo	Operational	Malt whisky	0.8	Whisky Invest Direct
Falkirk	Falkirk Distilling Co.	Operational	Malt whisky	0.75	Whisky Invest Direct
Glengyle	J & A Mitchell	Operational	Malt whisky	0.75	Whisky Invest Direct
Springbank	J & A Mitchell	Operational	Malt whisky	0.75	Whisky Invest Direct
Glen Scotia	Loch Lomond Group	Operational	Malt whisky	0.75	Whisky Invest Direct
Aberargie	The Perth Distilling Co.	Operational	Malt whisky	0.75	Whisky Invest Direct
Burn o'Bennie	Mike Bain & Liam Pennycook	Operational	Malt whisky	0.69	Whisky Invest Direct
Speyside	Speyside Distillers Co.	Operational	Malt whisky	0.6	Whisky Invest Direct
Royal Lochnagar	Diageo	Operational	Malt whisky	0.5	Whisky Invest Direct
Benromach	Gordon & MacPhail	Operational	Malt whisky	0.5	Whisky Invest Direct
Bonnington	John Crabbie & Co.	Operational	Malt whisky	0.5	Whisky Invest Direct
Glenturret	Lalique Group	Operational	Malt whisky	0.5	Whisky Invest Direct
Clydeside	Morrison Glasgow Distillers	Operational	Malt whisky	0.5	Whisky Invest Direct
Torabhaig	Mossburn Distillers	Operational	Malt whisky	0.5	Whisky Invest Direct
Ardnamurchan	Adelphi Distillery Ltd	Operational	Malt whisky	0.45	Whisky Invest Direct
Glasgow	The Glasgow Distillery Co.	Operational	Malt whisky	0.44	Whisky Invest Direct
Eden Mill	Paul Miller	Operational	Malt whisky	0.3	Whisky Invest Direct
Edradour No.2	Signatory Vintage Scotch Whisky Co. Ltd	Operational	Malt whisky	0.27	Whisky Invest Direct
Annandale	Annandale Distillery Co.	Operational	Malt whisky	0.26	Whisky Invest Direct
Arbikie	Arbikie Distilling Ltd	Operational	Malt whisky	0.25	Whisky Invest Direct
Holyrood	Holyrood Distillery Ltd.	Operational	Malt whisky	0.25	Whisky Invest Direct
Lindores Abbey	The Lindores Distilling Co.	Operational	Malt whisky	0.25	Whisky Invest Direct
Kingsbarns	Wemyss Vintage Malts	Operational	Malt whisky	0.205	Whisky Invest Direct
Lone Wolf	Brewdog plc.	Operational	Malt whisky	0.2	Whisky Invest Direct
Lochlea	Lochlea Distilling Co.	Operational	Malt whisky	0.18	Whisky Invest Direct
Wolfburn	Aurora Brewing Ltd	Operational	Malt whisky	0.175	Whisky Invest Direct
GlenWyvis	GlenWyvis Distillery Ltd	Operational	Malt whisky	0.15	Whisky Invest Direct
Strathearn	Douglas Laing	Operational	Malt whisky	0.14	Whisky Invest Direct
Edradour	Signatory Vintage Scotch Whisky Co. Ltd	Operational	Malt whisky	0.135	Whisky Invest Direct
Nc'nean	Drimnin Distillery Co.	Operational	Malt whisky	0.1	Whisky Invest Direct
Ballindalloch	MacPherson-Grant	Operational	Malt whisky	0.1	Whisky Invest Direct
Daftmill	Francis Cuthbert	Operational	Malt whisky	0.065	Whisky Invest Direct
Dornoch	Phil & Simon Thompson	Operational	Malt whisky	0.025	Whisky Invest Direct
Tennent Caledonian	Wellpark Brewery	Operational	Beer production	8.36	SCCS
Belhaven	Belhaven	Operational	Beer production	0.51	SCCS

BECCS EfW/ACT

The sites considered were identified using the REPD and relevant websites/blog posts.

Table 46: BECCS EfW/ACT data point summary. Extracted from the literature and used in the calculations for the NETs Model

Plant	Owner	Operational Status	Type of Technology	Gross Electrical Capacity (MWe)	Fuel source	Data source
Thainstone Energy Park Project ERF	Agile Energy Recovery	Application Submitted	BECCS EfW	35	MSW	REPD
Dunbar EfW (previously Oxwellmains EfW)	Viridor	Operational	BECCS EfW	25.6	MSW	REPD
Westfield (former Opencast Coal Mine)	Brockwell Energy	Under Construction	BECCS EfW	23.7	MSW	Website[167] Blog post[168]
CalaChem Fine Chemicals (Grangemouth) - Earlsgate Energy Centre	Brockwell Energy, Covanta and Green Investment Group	Under Construction	BECCS EfW (CHP)	21.5	MSW	REPD
South Clyde Energy Centre	Fortum (formerly Peel Environmental)	Under Construction	BECCS EfW	20	MSW	REPD
Oldhall Industrial Estate	Dover Yard	Permission Granted	BECCS EfW	15	MSW	REPD
Millerhill EfW	FCC Environment	Operational	BECCS EfW	12.5	MSW	REPD
Barr Killoch Energy Recovery Park	Barr Environmental Limited	Application Submitted	BECCS EfW	12	RDF	REPD
Ness Energy Project	Aberdeen / Aberdeenshire / Moray Councils	Under Construction	BECCS EfW (CHP)	11.1	MSW	REPD
Baldovie Industrial Estate (Forties Road)	MVV Environment	Under Construction	BECCS EfW (CHP)	10	MSW	REPD
Baldovie	Dundee Energy Recycling	Operational	BECCS EfW	8.3	MSW	REPD
Binn Farm EfW	Binn Group	Permission Granted	BECCS EfW	7.3	MSW	REPD
Polmont landfill site EfW	NPL Group	Planning application submitted	BECCS EfW	7.4	MSW	News paper[169]
Drumgray Energy Recovery Centre (DERC)	FCC	Planning granted	BECCS EfW (CHP)	25.5	MSW	Blog post[170]
Charlesfield Biomass CHP Plant	Charlesfield First LLP & Biogas Power	Operational	BECCS EfW ACT (CHP)	10	MSW	REPD
Coatbridge Material Recovery and Renewable Energy Facility	Golder Associates (UK) Ltd/ Shore Energy	Under Construction	BECCS EfW ACT (CHP)	25	MSW	REPD
Levenseat Waste Management Facility	Levenseat	Permission Granted	BECCS EfW ACT (CHP)	17	RDF	REPD
Levenseat EfW	Levenseat	Operational	BECCS EfW ACT	12.5	RDF	REPD
Glasgow Renewable Energy and Recycling Centre (ACT)	Viridor	Operational	BECCS EfW ACT (CHP)	10	MSW	REPD
Achnabreck	Northern Energy Developments	Permission Granted	BECCS Power ACT (CHP)	5.5	Wood pellets	REPD
Binn Eco Park	SITA UK/Binn Group	Permission Granted	BECCS EfW ACT	4.6	RDF	REPD
Avondale Quarry (Pilot)	Grangemouth Generation Ltd	Operational	BECCS EfW ACT	2	MSW	REPD

Carbon Capture Calculations

The following section provides an overview of the modelling parameters and methodology used to estimate the CO₂ capture potential of each NET.

BECCS Biomethane

We utilised a simple mass balance to determine the CO₂ capture potential of a biomethane facility (see Figure 19 below). The methodology used was as follows:

1.) Since we know the amount of biomethane produced hourly, taken from the NNFCC or estimated using the REPD, then we can estimate the annual biomethane production rate by assuming standard operating hours of 6,000 hr/year (this is equivalent to a utilisation factor of 68%).

2.) The amount of methane directed to the upgrading facility, from the anaerobic digestor, can be determined by assuming that 4.7% of the methane entering the upgrader is lost to the surroundings^[171]_.

3.) The amount of biogas and CO₂ directed towards the upgrading facility can be determined by assuming a biogas composition of 55:45 methane to CO₂ (on a volumetric basis)^[171].

4.) By assuming that the biogas exiting the anaerobic digestor is under normal conditions (i.e., at 25 degC and 1 atm) then the mass of CO₂ entering the CO₂ capture unit can be determined using a density of 1.795 kg/m³.

5.) The CO₂ production potentials determining using this mass balance method were compared to mass balance benchmarks found in a LCA paper (0.00161 tCO₂/m³,biomethane)^[132]. The values were found to be very close to one another and hence confirms our assumptions and calculations are valid.

6.) The capture potential was finally determined by applying a CO₂ capture efficiency of 95%.

The comparison of CO₂ production potentials through our mass balance method and that of the LCA mass balance benchmarks are shown below in Table 47. The values are very close, deviating by +- 0.002 MtCO₂/year, validating our assumptions and calculations.

Table 47: Fermentation CO₂ production rates comparison. Calculated using our mass balance method, compared against an LCA paper.

Site	CO2 generated from upgrading (Mt/year)
	General Mass Balance	LCA Mass Balance
Portgordon Maltings Beyside	0.007	0.008
Brae of Pert Farm	0.005	0.005
Charlesfield Industrial Estate	0.005	0.005
Cumbernauld AD	0.005	0.005
Downiehills Farm	0.005	0.005
Girvan Distillery	0.025	0.027
Glenfiddich Distillery	0.018	0.019
Hatton Farm AD	0.004	0.004
Inchdairnie Farm	0.005	0.005
Invergordon Distillery	0.005	0.005
Keithick Farm	0.006	0.006
Lockerbie Creamery	0.007	0.007
Morayhill AD	0.005	0.005
Peacehill Farm	0.005	0.005
Rosskeen Farm	0.004	0.004
Savock Farm	0.006	0.006
Tambowie Farm	0.002	0.002
TECA AD	0.004	0.004
Portgordon Maltings - Anaerobic Digestion Facility, Phase 2	0.018	0.019
Lockerbie Creamery - Anaerobic Digester	0.008	0.009

BECCS Power and Industry (Wood)

As described in the Data Sources section, all the BECCS Industry (Wood) sites considered in our study employ biomass boilers or CHPs on-site. These units are the focus for potential CCS implementation, enabling negative emissions similar to BECCS Power sites. Consequently, our carbon and cost calculations will adopt the same methodology and utilise identical parameters for BECCS Power and Industry (Wood).

To determine the CO₂ capture potential of a power only, CHP or heat only site, we carried out the following:

1.) The fuel input rate going into the CHP or power plant was determined by back-calculating from the gross electrical capacity, quoted in the REPD, using an assumed electrical efficiency of 38.7% for power only sites and 25% for CHPs^[46]. If the site is heat only then a heat efficiency of 80% is used.

2.) The CO₂ production rate was then determined by applying a conversion factor of 0.35 kgCO₂/kWh,fuel using the BEIS greenhouse gas reporting conversion factors^[93], taken from the ‘Outside of Scopes’ tab.

3.) The CO₂ capture potential of the site was then determined using an assumed capture efficiency of 90%.

An example calculation for Caledonian Papermill is provided in Box 1 below.

Box 1: CO₂ capture potential, BECCS Power calculation

Caledonian Papermill (26 MWe CHP).

To ensure the validity of our assumptions and data sources, the CO₂ production potential of the BECCS Power and Industry (Wood) sites were compared to values from the SPRI Database^[172]. The comparison revealed a general alignment between the values, as demonstrated in below. It is worth noting that data for most BECCS Power sites was unavailable in the SPRI Database due to their low gross capacities. This further supports the reasonableness of our assumptions and data sources.

Table 48: BECCS Power and Industry (wood) CO₂ production rates comparison. Compared using two data sources: our own calculations based on REPD data and the values quoted in the SPRI database.

Site	NET	REPD (MtCO2/year)	SPRI (MtCO2/year)
Markinch Biomass CHP Plant	BECCS Power (CHP)	0.717444	0.371911
Stevens Croft	BECCS Power	0.359363721	0.388518964
Westfield Biomass Power Station	BECCS Power	0.089127907	0.108348
Caledonian Papermill	BECCS Industry CHP (paper - coated magazine)	0.2869776	0.3012053
Cowie Biomass Facility	BECCS Industry CHP (Particle & MDF)	0.165564	0.264579705
Invergordon Pellet Mill	BECCS Industry CHP (wood pellets)	0.055188	N/A
Morayhill Mill	BECCS Industry (Oriented Strand Board)	0.344925	0.19257725
Barony Road, Auchinleck	BECCS Industry CHP (Chipboard and wood recycling)	0.0607068	0.020513208

BECCS Cement

Due to limited data availability for calculating the CO₂ capture potential, we relied on the CO₂ emissions rate provided by the SPRI database to estimate our own CO₂ capture potential. To determine the portion of emissions considered biogenic, we assumed that approximately 40% of cement emissions result from the combustion of fossil fuels^[173]. Additionally, considering that Dunbar Cement intends to utilise a fuel mix composed of 45% RDF/SRF waste, with a biogenic content of 17%^[174], we determined the quantity of emissions classified as biogenic.

BECCS AD

For the AD sites, we assume that all generated biogas is converted into biomethane, with a small portion being utilised by an onsite CHP to meet onsite requirements. With these assumptions, we can determine the maximum CO₂ capture potential for each site.

To determine the CO₂ capture potential, we carried out the following:

1.) The feedstock input data, provided via the NNFCC Database, was utilised to determine the biogas production rate using a feedstock to biogas mass balance benchmark taken from an LCA paper (0.17 kg,biogas/kg,feedstock).

2.) The volume of biogas produced is then determined using an assumed biogas density of 1.2 kgm^-3.

3.) The CO₂ and biomethane production rate are calculated using the assumed biogas composition of 55:45 methane to CO₂ on a volumetric basis. The mass of CO₂ produced can then be determined using the density of CO₂ under standard conditions (1.795 kgm^-3).

4.) Finally, the CO₂ capture potential is determined using a CO₂ capture efficiency of 95%.

Six of the sites listed in Table 44 lacked data on feedstock input rates, making it difficult to calculate their carbon capture potential. Consequently, additional research was required. Among them, five sites had gross power capacities available in either the REPD or NNFCC databases. For these sites, a similar methodology to that used for BECCS Power/Industry (Wood) could be applied, although with different efficiencies, utilisation factors, and emission conversion factors. As for the remaining heat-only site (‘Glenmorangie Distillery’), its planning application documents indicated a biogas production rate of 8000 m³/day, enabling the determination of its CO₂ capture potential using the same methodology as BECCS Biomethane.

An example calculation for the ‘Glenfiddich Distillery AD (Extension)’ site is shown below.

Box 2: AD CO₂ capture potential example

The annual electricity production potential is calculated using our utilisation factor of 68%, derived from the assumption that a standard AD site operates at 6000hr/year.

Determine biogas fuel input rate going into the CHP by assuming an CHP electrical efficiency of 25%. The volumetric rate of this input can then be determined by assuming a biogas energy density of 26 MJ/m³.

To determine biomethane production and CO₂ capture potential, we assume that all biogas is now upgraded. Using a typical biogas composition of 55:45 methane and CO₂ (volume basis), that we exhibit a 5% biomethane losses during upgrading, and a CO₂ capture potential of 95%.

BECCS Fermentation

For the brewery sites, we have estimated CO₂ capture potentials as well as costs by assuming that the sites operate like industrial bioethanol plants.

To determine the CO₂ capture potential, we carried out the following:

1.) The litres of pure alcohol (LPA) produced by each site is provided^[92]. We can utilise a CO₂ conversion factor of 754.7 tonnes per Ml of alcohol to determine the quantity of CO₂ produced.

2.) The CO₂ capture potential can then be determined using a capture efficiency of 90%

BECCS EfW/ACT

For EfW/ACT sites, we can apply the same methodology as BECCS Power and Industry (Wood), but with variations in efficiencies, utilisation factors, and emission conversion factors. Another possible approach is to directly calculate CO₂ capture potentials by gathering waste input rates from literature. However, we chose not to use this method in order to maintain consistency in our methodology, as well as to reduce errors and discrepancies in assumptions and data sources, enabling a more accurate and meaningful comparison of different NETs on a like-for-like basis.

To determine the CO₂ capture potential, we carried out the following:

1.) Firstly, we calculate the waste input rate. For this purpose, we employed a back-calculation approach utilising the electrical gross capacities provided in the REPD data and assuming a plant utilisation factor of 85%^[175]. The power-only sites utilised an electrical capacity of 22%, calculated based off data sourced from AECOM and a MSW energy capacity of 10 MJ/kg^[77], while an assumed value of 15% was used for CHP sites and 80% heat efficiency for heat only sites.

2.) Based on the waste input rate we can determine the CO₂ production potential using conversion factors. Depending on the choice of waste used, which can be either MSW or RDF/SFR, then the CO₂ capture potential will change. This is due to three factors: 1.) SRF/RDF is a more energy dense fuel, 2.) MSW is a more carbon intense fuel, and 3.) SRF/RDF has a higher biogenic carbon content (on a mass basis).

3.) A standard 90% capture rate is then employed to determine CO₂ capture potential.

An example below for the ‘Thainstone Energy Park Project ERF’ site is provided in Box 3.

Box 3: BECCS EfW example CO₂ capture calculation

Determine EfW power efficiency based off AECOM data:

• Waste input = 350,000 t/year
• MSW LHV = 10 MJ/kg (taken from IEAGHG)
• Net power output (pre-CCS) = 25MWe
• Convert net to gross efficiency using a standard industrial scaler of 1.11

Determine waste input using electrical efficiency

Convert waste input into units of mass using the waste energy densities (10 MJ/kg for MSW and 13 MJ/kg for SFR/RDF)

Determine CO₂ captured

To double check our calculations, we compared our determined values for waste input against that quoted in the literature (see Table 49 below).

Table 49: Waste input rate comparison of EfW/ACT sites. Comparing REPD data (utilised in our calculations) against literature values

Site	REPD feedstock input (t/year)	Literature feedstock input (t/year)	Reference
Thainstone Energy Park Project ERF	422,414	200,000	[176]l
Dunbar EfW (previously Oxwellmains EfW)	308,966	300,000	[177]
Westfield (former Opencast Coal Mine)	286,034	200,000	[178]
CalaChem Fine Chemicals (Grangemouth) - Earlsgate Energy Centre	384,214	162,000	[179]
South Clyde Energy Centre	241,379	350,000	[180]
Oldhall Industrial Estate	181,034	180,000	[181]
Millerhill EfW	150,862	152,500	[182]
Barr Killoch Energy Recovery Park	111,406	166,000	[183]
Ness Energy Project	198,361	150,000	[184]
Baldovie Industrial Estate (Forties Road)	178,704	110,000	[185]
Baldovie	100,172	90,000	[185]
Binn Farm EfW	88,103	85,000	[186]
Lerwick Energy Recovery Plant	19,549	26,000	[187]
Polmont landfill site EfW	89,310	150,000	[188]
Drumgray Energy Recovery Centre (DERC)	455,695	300,000	[189]
Charlesfield Biomass CHP Plant	178704	70,000	[190]
Coatbridge Material Recovery and Renewable Energy Facility	446760	160,000	[191]
Levenseat Waste Management Facility	233689.8462	315,000	[192]
Levenseat EfW	116047.7454	215,000	[192]
Glasgow Renewable Energy and Recycling Centre (ACT)	178704	222,000	[193]
Achnabreck	38413.95275	N/A	N/A
Binn Eco Park	42705.57029	60,000	[194]
Avondale Quarry (Pilot)	24137.93103	N/A	N/A

Please note that for the ‘Achnabreck’ site, we could not utilise the above calculations, since this site plans on gasifying wood. Again, we used the REPD method to determine CO₂ production potential, using the same CO₂ conversion factor as BECCS Power/Industry (Wood). The feedstock input rate was then calculated using a wood pellet energy density of 4.8 kWh/kg, using that the fuel has a moisture content of 10%^[195].

We compared our CO₂ production values to the benchmark values provided by Tolvik^[196], using a waste to CO₂ benchmark of 0.992 kg CO₂/kg waste. Our calculations using the REPD method closely aligned with the Tolvik benchmark (refer to Table 50), reinforcing our confidence in our assumptions and methodology. The only site which had significant deviation were: Barr Killoch Energy Recovery Park, Levenseat Waste Management Facility, Levenseat EfW, and Binn Eco Park. and which is planning to burn RDF/SFR fuel instead of MSW. Please note that the Achnabreck site gasifies wood pellets - not waste, and hence cannot be compared against the Tolvik benchmark.

Table 50: EfW/ACT CO₂ production potential comparison. Compared using our REPD method and Tolvik benchmarks

Site	NET	CO2 production (Mt/year)		Difference (%)
		REPD Method	Tolvik benchmark
Thainstone Energy Park Project ERF	BECCS EfW	0.423	0.419	1%
Dunbar EfW (previously Oxwellmains EfW)	BECCS EfW	0.309	0.306	1%
Westfield (former Opencast Coal Mine)	BECCS EfW	0.286	0.284	1%
CalaChem Fine Chemicals (Grangemouth) - Earlsgate Energy Centre	BECCS EfW (CHP)	0.384	0.381	1%
South Clyde Energy Centre	BECCS EfW	0.242	0.239	1%
Oldhall Industrial Estate	BECCS EfW	0.181	0.180	1%
Millerhill EfW	BECCS EfW	0.151	0.150	1%
Barr Killoch Energy Recovery Park	BECCS EfW	0.124	0.111	11%
Ness Energy Project	BECCS EfW (CHP)	0.198	0.197	1%
Baldovie Industrial Estate (Forties Road)	BECCS EfW (CHP)	0.179	0.177	1%
Baldovie	BECCS EfW	0.100	0.099	1%
Binn Farm EfW	BECCS EfW	0.088	0.087	1%
Lerwick Energy Recovery Plant	BECCS EfW (Heat only)	0.020	0.019	1%
Polmont landfill site EfW	BECCS EfW	0.089	0.089	1%
Charlesfield Biomass CHP Plant	BECCS EfW ACT (CHP)	0.179	0.177	1%
Coatbridge Material Recovery and Renewable Energy Facility	BECCS EfW ACT (CHP)	0.447	0.443	1%
Levenseat Waste Management Facility	BECCS EfW ACT (CHP)	0.261	0.232	11%
Levenseat EfW	BECCS EfW ACT	0.130	0.115	11%
Glasgow Renewable Energy and Recycling Centre (ACT)	BECCS EfW ACT (CHP)	0.179	0.177	1%
Achnabreck	BECCS Power ACT (CHP)	0.098	N/A	N/A
Binn Eco Park	BECCS EfW ACT	0.048	0.042	11%
Avondale Quarry (Pilot)	BECCS EfW ACT	0.024	0.024	1%

Table 51 on the subsequent pages provides summary of the NETs parameters used in the analysis.

Summary of NETs parameters

Table 51: A breakdown in parameters used to model NETs carbon capture potential

NET	Gross Power Efficiency (power only)	Net Power Efficiency (CHP)	Net Heat Efficiency (CHP)	Gross Heat efficiency (heat only)	Utilisation Factor	Conversion Factor (kg/kWh)	Lifespan (years)	CO2 Capture efficiency	Biogenic content of carbon (%mass)	Reference
BECCS Biomethane	N/A	N/A	N/A	N/A						Not used
					68%					Assumed
						N/A*				Not used
							20			[197]
								95%		Assumed
									100%	Assumed
BECCS Power & Industry (Wood)	38.7%									BEIS, Wood (2018)[45]
		25%								Assumed
			37.5%
				80%						Assumed
					90%					Assumed
						0.35				BEIS, GHG Reporting[93]**
							25			BEIS, Wood (2018)[45]
								90%		BEIS, Wood (2018)[45]
									100%	Assumed
BECCS Cement	N/A	N/A	N/A	N/A	N/A	N/A				Not used
							30			IEA
								90%		BEIS, Wood (2018)[45]
									3%***
BECCS Fermentation	N/A	N/A	N/A	N/A	N/A					Not used
						754.7*****				SCCS Paper[92]
							30			l
								90%		Assumed
									100%	Assumed
BECCS EfW/ACT	22%******									AECOM[175]
		15%								Assumed
			31%
				80%						Assumed
					85%					AECOM[175]
						0.36 (MSW) 0.31 (RDF/SFR)				IEAGHG[77]
							20			AECOM[175]
								90%		BEIS, Wood (2018)[45]
									50% (MSW) 17% (RDF/SFR)	IEAGHG[77]and IEA

*Mass balance used instead

**The greenhouse gas reporting conversion factors used were taken from the ‘Outside of Scopes’ tab.

***We understand that 40% of cement emissions are from combustion, with Dunbar Cement aiming to utilise 45% SFR in their fuel mix which has a biogenic content of 17%.

****This corresponds to the amount of biogas output per tonne of feedstock anaerobically digested. The units are t/t.

*****Units of tonnes of CO₂ produced per mega litre of alcohol produced (MLA)

******See calculations above in EfW section to see how this efficiency is derived.

LCOC Methodology

The Levelised Cost of Carbon (LCOC) will serve as a filtering mechanism for potential NETs sites. It supports the determination of whether these sites should be included in subsequent pathway analysis or not; the higher the LCOC the less economically attractive the site.

Sites located on islands were excluded from further analysis due to the complexities involved in transporting the CO₂ to a suitable storage location.

Table 52: A breakdown in the definitions of the various parameters used to determine LCOC

Variable	Meaning	Units
LCOCexisting	This figure serves as a summary of the economic viability of a particular Negative Emission Technology (NET), acting as an indicator to aid in the selection process among different NETs options.	£/tCO2,captured
CAPEX	This figure accounts for the investment cost associated with purchasing, installing, and commissioning plant equipment.	M£
Capital Recovery Factor (CRF)	This figure represents the fraction of the initial capital investment that needs to be recovered each year to cover the cost of the investment. It is used to annualise the investment cost.	N/A, this is a dimensionless quantity
OPEXfix	This figure accounts for expenses that remain relatively constant regardless of the level of production. This figure is typically in proportion with the capital expenditure.	£M/year
OPEXvar	This figure accounts for expenses that vary in proportion to the level of production. For industrial sites this cost is typically heavily linked to energy costs.	£M/year
Ctransport	This figure represents the cost associated with transporting the CO2 to the designated storage site(s). In this report, we have made the assumption that the CO2 can be transported either entirely by truck to St Peterhead, or partially by truck to an injection point, where it is then injected into a pipeline.	£M/year
Cstorage	This figure represents the cost of storing the CO2 in the North Sea. In this report, our assumption is based on the utilisation of depleted oil and gas wells, which aligns with the proposed approach of the Acorn project.	£M/year
Crevenue	This figure represents the gain in revenue associated with selling heat and power from BECCS Power, BECCS Industry and BECCS EfW sites. It's important to note that the analysis does not include revenues derived from the sale of biomethane for future BECCS Biomethane and AD Upgrading sites.	£M/year
CO2,captured	This figure depicts the quantity of CO2 captured by the NETs site. Please note that this is not the same as the negative emission potential, which does not account for emissions from fossil sources.	MtCO2/year

Cost Analysis

Capital Expenditure (CAPEX)

In estimating the CAPEX, we employed the widely used sixth-tenths rule, which is a method for approximating costs. According to this rule, the cost of a project can be estimated by taking the cost of a comparable completed project and scaling it by the exponent 0.6, based on the capacity of the reference plant. This scaling can be done by considering various factors such as CO₂ capture potential, heat or power production, biomethane production, or any other relevant parameter. An example calculation is provided below.

It's important to note that this method provides a quick and rough estimate of costs. However, it should be used with caution, as it may not encompass all the unique aspects and complexities of each specific project. It's worth mentioning that we do not intend to conduct a detailed cost analysis for each NETs site in our current scope, making this method sufficient for our purposes.

Operational Expenditure (OPEX)

The OPEX is divided into two categories: Fixed costs and Variable costs. Fixed OPEX encompasses ongoing expenses that tend to remain consistent regardless of the production or operational level. Examples include salaries, benefits, equipment maintenance, repairs, and insurance. On the other hand, Variable OPEX includes costs that fluctuate based on the level of production or operation. These costs can include raw materials, fuel, maintenance supplies, and energy consumption.

For existing sites, we assumed that the fixed OPEX would amount to 5% of the CAPEX (a typical industrial benchmark), while the variable OPEX would account for increases in fuel/electricity usage alone as this is typically the main source of variable OPEX cost. We could account for additional variable costs; however, this would to a complex cost analysis for each site which is outside of the scope of this project. Although cost benchmarks for Variable and Fixed OPEX were available in the literature, we chose not to utilise them due to significant discrepancies in assumptions and parameters included in the costs, depending on the specific NETs being discussed. As a result, the costs for existing NETs would not be comparable on a like-for-like basis. The exception was the ‘Dunbar Cement’ plant, where site-specific data on heat and power demands was unavailable in the literature, and so we had to rely on benchmarks to determine Variable OPEX.

When evaluating future sites, it was necessary to consider the overall costs associated with both installing and operating a NETs site. To accomplish this, cost benchmarks were employed in their entirety and then scaled up using the sixth-tenths rule. This approach ensured that the complete range of costs were considered for accurate cost estimation. Although this approach may lead to potential cost overestimation, it is not a concern since our objective does not necessitate comparing future sites on a like-for-like basis.

We tested our assumption of fixed OPEX being equivalent to 5% CAPEX, for existing sites, by comparing the respective costs to industrial benchmarks. The overall estimation was reasonably close, as shown below in Table 53. Please note that all cost benchmarks have been scaled to 2023 costs via inflation and converted to pounds sterling.

Table 53: OPEX and CAPEX comparison used in modelling. A comparison between the assumption of fixed OPEX for existing projects, estimated to be equivalent to 5% of CAPEX, and the fixed OPEX benchmarks cited in the literature

NET	5% assumption (£/tCO2)	Cost benchmark
BECCS EfW (combustion and ACT)	16.1	15.7[175]
BECCS Biomethane	11.4	7[197]
BECCS AD Upgrading	263.3*	N/A, not broken down into fixed and variable OPEX[171]
BECCS Fermentation	2.3	3.1[198]
BECCS Power and BECCS Industry (Wood)	4.1	3.3[45]
BECCS Industry (Cement)	0.0041**	0.0037[175]**

*Please note that AD Upgrading is in units of £/m³/year

**Please note that BECCS Industry (Cement) is in units of £/tclinker/day

BECCS Biomethane

For existing sites, the costs associated with CCS installation encompassed CO₂ liquefaction only. This is because biomethane sites already separate out CO₂ into a pure stream during the biogas upgrading process, and hence the CO₂ capture is more efficient, less energy intensive, and cheaper. The resulting liquefication process takes the capture carbon and removes water and impurities, where the clean CO₂ stream is then compressed to high pressures in preparation for transport.

CO₂ Liquefication

The initial step of liquefication is to compress the gas to the desired pressure (circa 130 bar) and help it reach its critical temperature. Water is then removed by condensation to prevent hydration and the gas is subsequently cooled (e.g., using a set of heat exchangers or expansion cooling) to transition the gas into a liquid. An impurity removal unit is used to remove impurities when the delivered CO₂ needs to meet a high purity requirement.

CAPEX

To determine the CAPEX of liquefication a benchmark was taken from a 2022 techno-economic analysis paper investigating the costs associated with CO₂ capture for AD Upgrading sites. The paper considers a reference case of an AD Upgrading facility producing 4400 tCO₂ at a CAPEX of 1MEUR.

To determine the CAPEX for future sites, we also have to account for the costs associated with constructing the AD Upgrading and AD plant. These costs were taken from a techno-economic analysis paper that investigates biomethane upgrading via the water scrubbing method, which accounts for investment costs in constructing the biogas plant, silage pit, AD upgrading plant, gas grid connection, and CNG service station. For simplicity, we have assumed the water scrubbing technique is used in all biogas AD Upgrading sites in Scotland, so that this paper can be applied to all biomethane sites. This assumption is reasonable, given the fact that around one third of AD Upgrading sites in the UK use water scrubbing technology, according to the EBA Statistical Report of 2020. However, an improvement opportunity of the analysis is to consider membrane separation costs in the analysis instead.

OPEX

As previously mentioned, the Fixed OPEX for existing sites was taken to be 5%. This assumption was also applied to future sites since the CCS OPEX benchmarks from the 2022 AD Upgrading paper was not clearly broken down.

The Variable OPEX for existing sites was calculated by determining the power demands of CO₂ liquefication (i.e., powering the compressors and chiller). This method was also used for new sites, again due to an unclear breakdown in CCS OPEX from the 2022 Upgrading paper. The liquefication power demands were taken from a 2019 paper which details a thorough breakdown in cooling and compression power requirements, with compression requiring 12.5 MW and cooling 40.48 MW in order to capture 1 MtCO₂/year. We are assuming to compress CO₂ to 130 MPa in preparation for transport, which is a standard industrial benchmark.

An example calculation is shown in Box 4 below for the ‘Portgordon Maltings Beyside’ site.

Box 4: Example Variable OPEX calculation process

We use the liquefication power demand of 52.98 MW, in order to capture 1 MtCO₂/year, and convert to MJ/kg. We assume standard operating hours of 6000 hr/year for an AD Upgrading site.

To convert to MJ/year, we multiply the energy demand by the CO₂ capture potential and scale up using the sixth tenths rule.

To determine the cost of this power demand, an electricity price of 14.6 p/kWh was used based off Ofgem’s wholesale electricity price. This final cost is taken as the Variable OPEX.

When considering future sites, the Variable OPEX associated with the AD and Upgrading plants was taken from a 2018 paper. The total OPEX was quoted as a single figure, including both fixed and variable OPEX, which accounts for maintenance and overheads, electricity demands, thermal demands, feedstock and disposal costs, plant OPEX, depreciation, and gate fee(s).

Revenue

We did not include revenue sources from biomethane in our analysis because they fall outside the mass/energy balance boundary that we established.

BECCS Power and Industry Wood

The costs for BECCS Power and BECCS Industry (Wood) were taken from the same source. This is because BECCS Industry (Wood) sites either have biomass boilers or biomass powered CHPs onsite that meet onsite demands (as described earlier in Data Sources). The reference is a 2018 BEIS paper (BEIS Wood 2018). This paper examines the costs associated with installing CCS on a 498 MWe bioenergy power station capturing circa 4.2 MtCO₂/year.

CAPEX

The sixth tenths rule is applied, where the costs associated with constructing the bioenergy plant and installing the CCS equipment are £813.7M and £322M respectively.

OPEX

Fixed OPEX was taken to be 5% of CAPEX.

To determine Variable OPEX of existing sites, we had to determine the impact installing CCS would have on the NETs power export of a site. In particular, installing CCS requires heat demands of circa 3.4 MJ/kg,CO₂, which are sourced by extracting low-pressure steam from the turbine at circa 3 bar. As a result, the overall efficiency of the site decreases by approximately 5%. In our analysis, we have used these drops in NETs efficiency to determine losses in revenue, which is equivalent to an increase in Variable OPEX.

If a site is in fact a CHP, then we have to account for the impacts on both power and heat export. To make this analysis simpler, and avoid the need to undertake multivariable optimisation, we assumed that the power export of a site will remain the same, but the heat export potential is impacted by the CCS heat requirements. This results in NETs power efficiencies remaining constant and heat efficiencies dropping. An electrical efficiency of 25% was assumed for CHP sites, based off CHPQA knowledge, and the resulting heat efficiency (pre-CCS) was determined using a z ratio of 3.5. The price of heat was taken to be 4 p/kWh.

The assumed low price of heat is justified by the fact that we are considering the heat price at the export point rather than the price at which heat is sold directly to the customer, such as 12p/kWh through a third party. In this scenario, the generator sells heat to a third party at 4p/kWh. The third party is responsible for constructing and operating the heat network, which incurs significant costs. Subsequently, the third-party charges the customer for the heat supplied.

Box 5 below is a summary of how Variable OPEX was calculated for “Markinch Biomass CHP Plant”

Box 5: Further example of variable OPEX calculation process

Using the assumed NETs power efficiency of 25%, we can calculate the heat efficiency using the CHP zed ratio of 3.5. This results in a NETs heat efficiency of ~37.5%.

Taking the feedstock input rate, we can determine the heat export potential pre-CCS.

Using a standard CCS heat demand of 3.4 MJ/kg, CO₂, we can determine the resulting heat demand of CCS using the annual CO₂ capture potential. This enables us to check whether the site can meet CCS demands without the need for the installation of an additional boiler.

Using a heat price of 4p/kWh, we can determine the variable OPEX.

For the Morayhill Mill industrial site, which is a heat only site, we have assumed that the gross boiler efficiency is 80%. The same methodology to CHP sites is then applied, where a heat efficiency post-CCS was found to be 50%.

For future sites, we directly applied the bioenergy and CCS benchmarks quoted in the 2018 BEIS paper to determine fixed and variable OPEX. One key thing to note is that the benchmarks used do not account for fuel usage within the Variable OPEX benchmark. Therefore, a wood pellet price of £24/MWh was applied and scaled up according to the feedstock demands of the site.

Revenue

For future sites, the same methodology described above was applied to determine the revenue stream potential of each site, using the expected heat and/or power export potential post-CCS and multiplying it by the respective energy costs (14.6 p/kWh and 4 p/kWh for power and heat respectively).

BECCS Cement

The only site associated with BECCS Cement is Dunbar Cement, which is already operational. As there are no other cement sites expected to be constructed in Scotland, that we have only considered the costs associated with installing and operating CCS.

CAPEX

The investment cost of CCS was taken from the reference site used as the cost benchmark assumed a clinker production rate of 1 Mt/year and a carbon capture potential of 0.8 MtCO₂/year, as well as utilising some waste as a fuel feedstock. This last point is ideal for our calculations of Dunbar cement, which plans to implement a 45% blend of SRF/RDF into their fuel feedstock.

The investment cost of CCS, obtained from the AECOM Next Generation Carbon Capture Technology techno economic analysis paper, for a reference site producing 1 Mt/year of clinker and capturing 0.8 MtCO₂/year is £192.5M. This reference site also utilises waste as a fuel feedstock, which aligns with our calculations for Dunbar cement due to the site aiming to incorporate a 45% blend of SRF/RDF into their fuel feedstock. The capital expenditure covers EPC and Project Development costs.

OPEX

The Fixed OPEX was taken to be 5% of the CCS Capex.

As there was no data available on the heat and power usages of the Dunbar Cement site in the literature, then the Variable OPEX was determined by applying cost benchmarks directly, despite the site being operational. This does go against the methodology applied to all other existing NETs sites; however, no other options were available to us. This will lead to the LCOC of the Dunbar Cement site being overestimated compared to other existing industrial sites. An improvement point for this work is that the Variable OPEX of the Dunbar Cement site is recalculated based on potential increases in heat and power demands for the site, as well as the impact CCS has on potential losses in revenue sales from clinker, heat and power. The variable OPEX was taken to be £72.7M/year for the reference site.

Due to the lack of available data on the heat and power usages of the Dunbar Cement site, the Variable OPEX was determined by directly applying cost benchmarks, despite the site being operational. This deviates from the methodology used for other existing sites, but no other options were available. The Variable OPEX for the reference site was £72.7M/year. An improvement for this study is to recalculate the Variable OPEX of the Dunbar Cement site considering the impacts CCS will have on heat and power demands, as well as potential revenue losses from clinker, heat, and power sales.

BECCS AD

For existing sites, the costs associated with BECCS AD were taken to be that associated with constructing and operating an AD Upgrading and liquefication plant. As for future sites, the costs associated with constructing and operating an AD facility also had to be accounted for. The calculations, as well as the cost benchmarks used, are discussion previously in the BECCS Biomethane cost section.

BECCS Fermentation

For existing sites, the costs associated with BECCS Fermentation were taken to be that associated with constructing and operating the CCS plant. As potential future sites were not listed in the literature, please see the Data Sources section, then costs associated with future sites (e.g., cost of building a whisky distillery or brewery) were not investigated into. Similar to BECCS Biomethane sites, the mechanism for capturing carbon will be similar to the CO₂ liquefication process, since the stream of CO₂ exiting the distillery is pure. In our case, we used a 2014 paper published by the US Department of Energy which investigated the cost of capturing carbon from a bioethanol plant, which is a reasonable approximation to a whisky distillery and/or brewery. The paper in question considers a reference bioethanol plant that produces 50 Mgal/year of ethanol and 0.145045 MtCO₂/year.

CAPEX

The investment cost associated with capturing 0.145045 MtCO₂/year is £7.846M. This cost was then scaled up accordingly using sixth tenths rule and the alcohol production rate.

OPEX

The fixed OPEX was again taken to be 5% of CCS Capex.

Similar to BECCS Biomethane, the electricity requirements associated with processing this pure CO₂ are similar to that of CO₂ liquefication. Regarding this 2014 bioethanol paper, a power demand of 1.9 MWh/hr is needed to capture the carbon, which is equivalent to 14147.4 MWh/year based off the fact that the reference bioethanol plant operates at a utilisation factor of 85%. Now assuming a standard carbon capture efficiency of 90%, we can achieve a power demand of 109.9 GWh/MtCO₂.

Please see Box 6 below for a breakdown in this calculation.

Box 6: Example of fixed OPEX calculation for BECCS fermentation, power demand

A power demand of 1.9 MWh/hr is needed to capture the carbon, which is equivalent to 14147.4 MWh/year based off the fact that the reference bioethanol plant operates at a utilisation factor of 85%.

Assuming a standard carbon capture efficiency of 90%, we can achieve a power demand of 109.9 GWh/MtCO₂

Using the sixth tenths rule, we can then scale up the power demand depending on the alcohol production rate. The final cost associated with power usage can then be calculated using an electricity price of 14.6 p/kWh.

Please see the calculations in Box 7 relating to ‘Cameronbridge’ grain whisky distillery

Box 7: Example of fixed OPEX calculation, cost implication

The CCS power requirement is scaled using the sixth-tenths rule

The power requirement is costed

BECCS EfW/ACT

The paper used to source our CCS cost benchmarks is from the AECOM Next Generation Carbon Capture Technology paper, which quotes a reference site that processes 350,000 t/year of waste, has a gross power output 29 MWe and captures 0.3 MtCO₂/year. Costs associated with constructing and operating a EfW facility were taken from a Catapult Energy Systems paper that focussed on UK deployment of EfW facilities, considering a ‘Core EfW Plant’ where 350,000 t/year of waste is burnt under a gross capacity of 32MWe.

CAPEX

The investment cost of capturing 0.3 MtCO₂/year from a EfW site is quoted to be £96.8M, which is then scaled accordingly using sixth tenths and the CO₂ capture potential of each site. When considering future sites, the investment cost associated with constructing an EfW facility is taken to be £224M, when not scaled for inflation.

OPEX

For existing sites, the fixed OPEX is again taken to be 5% of CAPEX.

The methodology behind calculating Variable OPEX for existing EfW/ACT sites is similar to that of BECCS Power and Industry (Wood). The key difference is the choice around the electrical and heat efficiencies used, which are calculated below using parameters described in the AECOM paper.

The NETs power efficiency pre and post CCS is 19% and 11% for power only sites

Given the fact that the reference case consumed 350,000 t/year of MSW and that the site operates 7446 hr/year, then we can determine the fuel energy input rate based on the fact that MSW has an energy density of 10 MJ/kg.

We know that the gross power is 29 MWe, NETs power output (pre-CCS) is 25 MWe, and NETs power output (post-CCS) is 14 MWe. Furthermore, we know that the Therefore, we can determine the power efficiencies.

The choice of NETs power and heat efficiencies (pre-CCS) of a EfW CHP was determined based off CHPQA data. The power and heat efficiencies were taken to be 15% and 31% respectively.

The NETs heat efficiency of a EfW CHP was determined to be 0.4% once CCS was installed (i.e., all heat output from the CHP is utilised onsite to meet CCS demands). An example calculation for the “Charlesfield Biomass CHP Plant” site is shown in Box 8.

Box 8: BECCS EfW OPEX calculation example

Taking the feedstock input rate, we can determine the heat export potential pre-CCS.

Using a standard CCS heat demand of 3.4 MJ/kg,CO₂, we can determine the resulting heat demand of CCS using the annual CO₂ capture potential. This enables us to check whether the site can meet CCS demands without the need for the installation of an additional boiler.

Using a heat price of 4p/kWh, we can determine the variable OPEX.

For the only heat only site, Lerwick Energy Recovery Plant, the heat efficiency pre-CCS was taken to be 76.7%. This is based off calculations using data from the Tolvik 2022 EfW statistics paper, where the site is labelled as Gremista. The total heat export from this site was 49 GW_th in 2022, the waste input rate 23,000 t/year, and the energy density of the fuel was assumed to be 10 MJ/kg (MSW equivalent). This calculated heat efficiency is reasonable compared to industrial benchmarks of a typical boiler efficiency being ~80%.

For future sites, we directly applied the EfW plant and CCS benchmarks quoted in the AECOM and Catapult Energy Systems papers. This includes the proposed Achnabreck site, which plans on gasifying wood pellets in a CHP. The reasoning behind why we used these benchmarks is because the technology is the same and hence costs are unlikely to differ significantly if we switch the biomass source. However, it is still worth noting that an improvement point to this work is to update the Achnabreak cost calculations so that they are more closely aligned to woody biomass gasification, since the fuel density and gasification efficiencies will differ compared to waste, which in turn will impact the variable OPEX costs slightly.

CO₂ Transport

The costs associated with carbon transport were determined in a separate Excel tool compared to the LCOC Tool.

In this case, the X and Y coordinates identified during the literature review of each site were taken and mapped against potential CO₂ injection points across Scotland using GIS Mapping.

The key CO₂ injection points considered were all along the St Fergus gas pipeline, which is proposed to be upgraded to enable CO₂ transport cross country as part of the Acorn project. The injection points were Bathgate, Kirriemuir, Garlogie, and Peterhead. The distance between all four injection points and the proposed NETs site were calculated in km using GIS Mapping by assuming that all sites will initially transport CO₂ by truck to an injection point unless they are physically located next to one of the four proposed injection points. The shortest possible road distance was then selected.

The onshore pipeline distances from each of the four injection points to the St Peterhead gas terminal was then calculated using GIS mapping and are shown in Table 13 of the main report.

The final offshore pipeline distance from the Peterhead to the Acorn site is 80km for all sites.

The resulting costs associated with each mode of travel: road, onshore pipeline, and offshore pipeline, are then calculated using the benchmarks outlined in Table 20, page 36 following benchmarks taken from the IEAGHG EfW-CCS paper. The benchmarks can then be used to scale linearly scale up transport costs based on CO₂ production capacity and transport distance.

CO₂ Storage

Storage costs were taken directly from the IEAGHG EfW CCS paper, where the high-end costs were utilised in order to ensure that costs are conservative. As these costs are quoted in a £/tCO₂ basis, with no reference to plant size, then costs are linearly scaled up based on CO₂ capture capacity.

Inflation

To ensure all cost benchmarks are within the correct format, they are adjusted for inflation and converted to pounds sterling using indexes from the World Bank and exchange rates from the OECD. Please note that inflation indexes were only available up to 2021. An improvement point of this analysis is to utilise updated inflationary figures, when they are available, to determine the difference in costs based on the fact that the British economy is going through a period of very high inflation.

Table 54: Figures used to convert costs into British Pounds Sterling and scaled for inflation

Parameter	2010	2011	2012	2013	2014	2015	2016	2017	2018	2019	2020	2021
GDP deflator index (2010 =100) to 2021 for US	91.86	93.77	95.52	97.19	99.01	100.00	101.00	102.92	105.40	107.29	108.69	113.57
GDP deflator index (2021 =100) to 2021 for US	0.81	0.83	0.84	0.86	0.87	0.88	0.89	0.91	0.93	0.94	0.96	1.00
Exchange rate USD to GBP	0.65	0.62	0.63	0.64	0.61	0.65	0.74	0.78	0.75	0.78	0.78	0.73
Exchange rate USD to Euro	0.75	0.72	0.78	0.75	0.75	0.90	0.90	0.89	0.85	0.89	0.88	0.85
Exchange rate Euros to GBP	0.86	0.87	0.81	0.85	0.81	0.73	0.82	0.88	0.89	0.88	0.89	0.86