Fortissat Community Minewater Geothermal Energy District Heating Network

ACKNOWLEDGEMENTS

This report was funded by and prepared for the Scottish Ministers under the Geothermal Energy Challenge Fund, part of the Low Carbon Infrastructure Transition Programme (LCITP) which is funded by the European Regional Development Fund.

The project consortium would like to extend a special thank you to Carole Stewart, Kathleen Robertson, Richard Gachagan and Johann MacDougal of the Scottish Government for their assistance throughout the creation of this report.

In addition, we would also like to extend our thanks to the following individuals, whose support and input merits acknowledgement:

• John Rattray, Farm Manager at Hartwood Home Farm • Margaret McLean, Allanton Tenants and Residents Association • John McKechnie, SEPA • Lynda Stevenson, NLC Housing and Social Work Services • David Miller, NLC Regeneration & Environmental Services • Alex Neil, MSP, Member for Airdrie and Shotts • Ian Booth, Aberdeen Heat and Power • Ron Tracey, Shettleston Housing Association

The project consortium would also like to extend gratitude to Fergus Ewing MSP, Minister for Business, Energy and Tourism, for his enthusiasm in supporting the development of Scottish geothermal energy demonstrator projects, of which this report is a valuable catalysing step.

Fortissat Community Minewater Geothermal Energy District Heating Network

TABLE OF CONTENTS

Preface ...... I EXECUTIVE SUMMARY ...... I Introduction ...... I Project Aims ...... I Site and Study Area ...... I Geothermal Supply ...... II District Heating Network ...... III Development Options ...... IV Delivery Model ...... VI Next Steps ...... XII Chapter 1 – Introduction ...... 1 1.1 Overview of Proposal ...... 1 1.2 Project Team and Structure ...... 2 1.3 Report Structure ...... 3 Chapter 2 – Environmental Baseline ...... 5 2.1 Introduction ...... 5 2.2 Site ...... 5 2.3 Surrounding Context ...... 8 2.4 Proposed Development ...... 11 Chapter 3 - Geothermal Supply ...... 13 3.1 Introduction ...... 13 3.2 Minewater Geothermal Energy - Basic Principles ...... 13 3.3 The Resource – The Mine System ...... 14 3.4 Geology, Hydrogeology and Drilling ...... 22 3.5 Option Appraisal for Geothermal System ...... 28 Chapter 4 – District Heating Network ...... 32 4.1 Introduction ...... 32 4.2 Heat Demand Analysis ...... 32 4.3 Preliminary Network Analysis ...... 36 4.4 Preliminary Scenario Appraisal ...... 39 4.5 Final Network Design ...... 43 4.6 Energy Centre Design ...... 47 Chapter 5 – Development Options ...... 55 5.1 Introduction ...... 55 5.2 Option 1 – ‘Preferred’ ...... 56 5.3 Option 2 – ‘Alternative’ ...... 57 5.4 Options Summary Table ...... 58 5.5 Option Comparison – Passive Treatment vs Reinjection ...... 58 5.6 Risk Management ...... 62 5.7 Opportunities ...... 66 5.8 Carbon Audit ...... 66

Fortissat Community Minewater Geothermal Energy District Heating Network

Chapter 6 – Delivery Model ...... 68 6.1 Summary ...... 68 6.2 Overview of Proposal ...... 68 6.3 Project Evolution ...... 70 6.4 Metering and Tariff Options ...... 71 6.5 Overview of Business Models and Legal Structures ...... 72 6.6 Delivery Structure Options ...... 76 6.7 Pros and Cons of Commercial Structures ...... 77 6.8 Structure of SPV ...... 80 6.9 Financial Model – Medium Term ...... 81 6.10 Revenue Streams ...... 82 6.11 Initial Results of Financial Analysis ...... 84 6.12 Sensitivity Analysis ...... 86 6.13 Financial Model – Long Term ...... 88 6.14 Conclusions from Financial Modelling ...... 91 Chapter 7 – Next Steps ...... 92 7.1 Introduction ...... 92 7.2 Geothermal Resource – Confirming the Heat Supply ...... 92 7.3 Community Engagement – Heat Demand ...... 96 7.4 District Heat Network (DHN) ...... 97 7.5 Business Plan ...... 98 7.6 Indicative Programme ...... 99 7.7 Funding Requirements ...... 101 References ...... 102

Fortissat Community Minewater Geothermal Energy District Heating Network

DRAWING LIST Chapter 1 – Introduction 1.1 Location plan 1.1 Location plan 1.2 Land ownership and control Chapter 2 – Environmental Baseline 2.1 Water Features Survey (preliminary) 2.2 Planning designations 2.3 Natural Heritage Designations 2.4 Cultural Heritage Designations 2.5 Landscape Character Chapter 3 - Geothermal Supply 3.1 Wilsontown Main Coal Workings 3.2 Woodmuir Smithy Coal working extent 3.3 Outline 3D WNMA and WRSM 3.4 Armadale Coal working extent 3.5 Mill Coal working extent 3.6 Shotts Gas Coal working extent 3.7 Lower Drumgray Coal working extent 3.8 Middle Drumgray Coal working extent 3.9 Upper Drumgray Coal working extent 3.10 Outline of all 3D modelled surfaces 3.11 Mine workings in 3D 3.12 Option 1 (Geo-6, Kingshill): Production well with passive minewater treatment system 3.13 Option 2 (Geo-3, Hartwood): Production well and injection well(s) Chapter 4 – District Heating Network 4.1 Percentage of social rented properties 4.2 Preliminary Network Layout (Fortissat) 4.3 Potentially Viable Network Layout 4.4 Production well locations and target areas of demand 4.5 Network A and B Layout 4.6 Network C Layout 4.7 Indicative gas and electrical connections to Energy Centre Chapter 5 – Development Options 5.1 Option 1: Production well with passive minewater treatment system Alternative Network Layouts A, B and C 5.2 Option 2: Production well and injection well(s) Network Layout C Chapter 6 – Delivery Model - No Drawings Chapter 7 – Next Steps - No Drawings

Fortissat Community Minewater Geothermal Energy District Heating Network

FIGURE LIST

Chapter 1 – Introduction 1.1 Project Team Structure Chapter 2 – Environmental Baseline No Figures Chapter 3 - Geothermal Supply 3.1 Schematic Diagram of a generic minewater geothermal energy doublet system 3.2 Geothermal gradient from bottom-hole temperature-depth measurements in collieries in the Midland Valley. Chapter 4 – District Heating Network 4.1 Shotts district heating load duration curve 4.2 Network C (Allanton and Hartwood) district heating load duration curve 4.3 Peak daily demand profiles (Network C) 4.4 Yearly diversified demand profile (Network C) 4.5 Indicative energy centre block diagram 4.6 Heat supply by source type Chapter 5 – Development Options 5.1 Illustrative diagram of passive minewater treatment system 5.2 Illustrative diagram of doublet system with production and injection well(s) Chapter 6 – Delivery Model 6.1 Gateshead Energy Centre 6.2 Commercial structure options 6.3 Relationship of control to risk 6.4 Tornado diagram showing IRR sensitivities for Option 1C 6.5 Tornado diagram showing 20 year aggregate cash flow sensitivities for Option 1C Chapter 7 – Next Steps 7.1 Indicative project timeline with a focus on the Development Stage

Fortissat Community Minewater Geothermal Energy District Heating Network

TABLE LIST

Chapter 1 – Introduction No Tables Chapter 2 – Environmental Baseline No Tables Chapter 3 - Geothermal Supply 3.1 Summary of mined workings within coal seams within and adjacent to the study area 3.2 Minimum, intermediate and maximum geothermal potential (in kWh) of the water stored in the in the WNMA and WRSM mines. 3.3 Flow pathway analysis for Geo-Option 3 3.4 Advantages and disadvantages of Geo-Option 3 3.5 Advantages and disadvantages of Geo-Option 6 Chapter 4 – District Heating Network 4.1 Summary of Study Area Heat Demands 4.2 Published fuel costs from price comparison website 4.3 Summary of technical parameters and potential revenue for each of the nine heat supply options 4.4 Estimates of required mine-water flow rates for heat pumps at 45% of the diversified peak 4.5 Indicative heat pump outputs in kW for various flow rates and COP values 4.6 Technical parameters of network options 4.7 Indicative cost of heat production for various values of temperature raise 4.8 Required volume of thermal store for low and high temperature networks 4.9 DUoS time bands and charges for high voltage connection with Scottish Power Energy Networks, assumed to be half-hourly metered 4.10 DECC quarterly non-domestic electricity prices 4.11 Network pressure losses, pumping power and annual power consumption Chapter 5 – Development Options 5.1 Summary table of minewater geothermal DHN development options 5.2 Option comparison – Passive Treatment and Reinjection 5.3 Risk Register - Risks and mitigating actions associated with geothermal supply 5.4 Risk Register - Risks and mitigating actions associated with the district heating network 5.5 Risk Register - Risk and mitigating actions associated aspects of the project other than geothermal supply and the district heating network 5.6 BAU carbon emissions with 100% of heat generated from domestic gas heating systems 5.7 Projected carbon emissions 5.8 A low estimate of the carbon emissions savings associated different design options Chapter 6 – Delivery Model 6.1 Summary of the advantages and disadvantages of potential ESCO structures 6.2 District Heating Network Options 6.3 Water/Ground-source heat pump RHI Tariffs as of December 2015 6.4 CAPEX and OPEX figures as input to the financial model 6.5 Headline results for design options

Fortissat Community Minewater Geothermal Energy District Heating Network

6.6: Improvements in project IRR and aggregate 20 year cash flow when accounting for potential cost saving through implementation of a passive minewater treatment facility integrated with the geothermal DHN 6.7 Sensitivity testing on Option 1C for impact of key parameters on project IRR 6.8 Sensitivity testing on Option 1C for impact of key parameters on 20 sum net cash (NCF) 6.9 Capital equipment overhaul costs 6.10 Long term cash flow model 6.11 Long Term cash flow incorporating minewater treatment cost savings Chapter 7 – Next Steps No Tables

Fortissat Community Minewater Geothermal Energy District Heating Network

TECHNICAL APPENDICES Chapter 1 – Introduction A1 Glossary of Terms Chapter 2 – Environmental Baseline A.2 Regulations, Guidance and Consultations Chapter 3 - Geothermal Supply A3.1 Potential minewater heat recovery at Hartwood, North Lanarkshire A3.2 Minewater Hydrology, Thermal Breakthrough, Modelling, and Minewater Hydrochemistry A3.3 Field Monitoring and Laboratory Testing at Kingshill A3.4 Minewater Analysis A3.5 Minewater Treatment at Kingshill A3.6 Site Visit to Kingshill A3.7 Well Schematics A3.8 Geothermal Supply Cost Assumptions for Financial Model Chapter 4 – District Heating Network A4.1 DHN and Energy Centre Cost and Revenue Schedule for Financial Analysis Chapter 5 – Development Options No Technical Appendices Chapter 6 – Delivery Model A6.1 Site Visit to Shettleston A6.2 Site Visit to Aberdeen Heat & Power Chapter 7 – Next Steps No Technical Appendices

Fortissat Community Minewater Geothermal Energy District Heating Network

Preface

Edinburgh Centre for Carbon Innovation High School Yards, Infirmary Street Edinburgh EH1 1LZ, SCOTLAND

Thursday 25th February 2016

A suite of four observations form the point of departure for this study into the economic- and technical viability of a community minewater geothermal scheme in Lanarkshire’s Fortissat Ward, in Scotland’s Central Belt. When viewed within the wider UK or European context, Scotland has (i) a relatively low gas-grid penetration rate; (ii) relatively high (± 50%) demand for heating as a proportion of total energy demand, only 1.4% of which is currently delivered through low-carbon sources; (iii) an anomalously high incidence of fuel poverty, particularly in rural areas; and (iv) an outstanding and virtually unexploited minewater geothermal resource base. In view of this, and as the following pages make clear, we believe the case for a demonstrator project in Fortissat – designed from the very outset with replicability and scalability in mind – merits serious consideration.

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Alex Schlicke Jelte Harnmeijer David Townsend Scene Consulting James Hutton Institute Townrock Energy

Fortissat Community Minewater Geothermal Energy District Heating Network

EXECUTIVE SUMMARY

INTRODUCTION

This report presents the findings of the feasibility assessment for a potential minewater geothermal energy system in the vicinity of the James Hutton Institute’s (JHI) Hartwood Home Farm, North Lanarkshire. The study area extends 5km from the site centre, which is roughly equivalent to the Fortissat ward of North Lanarkshire, and includes the settlements of Hartwood, Allanton, Shotts and Salsburgh.

The Fortissat Minewater Geothermal proposal is one of four projects awarded funding from the Scottish Government’s Geothermal Energy Challenge Fund (GECF), for the ‘Catalyst Stage’ which covers initial strategy development and feasibility work. These projects have been funded to explore the potential of Scotland’s geothermal resource to meet the energy needs of local communities.

PROJECT AIMS

The aim of this project has been to assess the feasibility and define the initial strategy to develop Scotland’s first minewater geothermal scheme in a rural area with social deprivation. While focused on the specifics of the location, the project is conceived as a readily replicable and fully operational mine-water geothermal district heating system demonstrator project that would act as proof of concept for Scotland-wide duplication.

The project also addresses the complex technical and stakeholder management issues associated with development of a community district heating system within a varied portfolio of existing accommodation held under mixed tenure rather than a new build housing scenario. North Lanarkshire Council is engaged in the project and actively investigating all options for improving housing energy efficiency, reducing heating costs, and reducing carbon from heat in their Council homes.

SITE AND STUDY AREA

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treatment systems), has been Hartwood Home Farm, reflecting the role of JHI as the grantee. However, as the understanding of the geothermal resource developed, and the potential for Council owned properties to form the basis for the heat market, further engagement with North Lanarkshire Council (NLC) as project partner enabled the potential for alternative locations for site infrastructure within land in the ownership of NLC to be investigated as options. This has established the former Kingshill Colliery No. 1, now the designated Kingshill Local Nature Reserve (LNR) / Kingshill Wetlands and Plantations Site of Importance for Nature Conservation (SINC), as a potential site.

GEOTHERMAL SUPPLY

The minewater geothermal resource mapping has identified the worked coal seams of the Kingshill Colliery as by far the largest geothermal resource in the area of interest and has been the main focus of this study, following a geothermal systems option appraisal which considered the various mine systems in the study area. Kingshill Colliery is one of Scotland’s largest historical mine systems and the mine seams (primarily comprising the Wilsontown Main (WNMA) and Woodmuir Smithy (WRSM) seams) partly underlie the southern area of the James Hutton Institute’s Hartwood Home Research Farm, and extend southwards under the village of Allanton. The former Kingshill Colliery No. 1 site lies to the south of Allanton, and is in the ownership of North Lanarkshire Council. Following its decommissioning, reclamation works included forestry planting, the creation of grassland habitat, lagoon reclamation and surface water drainage improvements. It is now designated as a Site of Importance for Nature Conservation, and a Local Nature Reserve. However, the drainage maintenance presents an ongoing financial burden to the Council, and minewater resurgence issues continue to affect homes in Allanton. The development of a geothermal minewater system in this location therefore simultaneously presents environmental constraints and benefits which need to be addressed as the project progresses. The estimates of the geothermal potential in the WRSM and WNMA, subject to the uncertainties implicit in a desk-based assessment, represent 258 years of heat extraction at a rate of 0.63 MegaWatts (MW), or 71 years of heat extraction at a rate of 2.3 MW.

Two preferred options have been identified for the geothermal supply in two locations, and with alternative methods for discharging the minewater. The ‘preferred’ option locates the production well at or in the vicinity of the Kingshill shaft to the south of Allanton, and proposes a passive treatment system to treat the minewater at surface prior to discharge to an existing watercourse. This option is preferred due to its potential to mitigate existing minewater resurgence issues affecting the village of Allanton, both by properly treating the minewater, and by locally lowering the

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water table. The ‘alternative’ option proposes a geothermal doublet system, with a production well and injection well(s) located on Hartwood Home Farm.

DISTRICT HEATING NETWORK

In parallel with the geothermal system options appraisal, an appraisal of the district heating network (DHN) design options and associated heat market has been undertaken. The initial focus for assessing the energy needs of local communities in the area encompassed the town of Shotts, the villages of Hartwood, Allanton and Salsburgh, and residential and non-residential development within the area, roughly equivalent to the Fortissat Ward of North Lanarkshire. The feasibility study identified constraints and opportunities in relation to using the available geothermal energy to provide heat in this area, to inform the identification of potentially viable heat networks. Balancing the risks and opportunities, a medium term potential has been identified which connects Allanton and Hartwood to a DHN. This DHN is scaled to enable the primary heat source for the energy centre to come from the geothermal minewater, pumped from a single production well.

The estimated minewater temperature of 18 °C necessitates a heat pump based system. Heat is extracted from the minewater using a heat pump and upgraded to the required network flow temperature. The heat pump model has been developed to take account of the diversified demand profile, with a gas boiler providing system top-up and back-up.

As the financial analysis indicates marginal difference between a high temperature and low temperature network (due to the higher capital costs of the low temperature system being offset by the lower operating costs for a network of this size) and the low temperature network has a Co- efficient of Performance (COP) above 2.9 to make it eligible for the Renewable Heat Incentive (RHI), a low temperature network of 75/45 flow and return temperatures is proposed.

There is a longer term potential to extend the network to Shotts. While this is an economically attractive heat market for district heating, the heat demand would require more than one production well and reinjection well(s) and/or alternative sources of energy for the DHN, and consequently is identified as a longer term opportunity once the initial network is operational and the geothermal resource is better understood.

Due to the separation distance, a DHN in Salsburgh would be more effective as a standalone system, and an alternative energy source would be required as there is not a viable minewater geothermal resource in the vicinity of Salsburgh.

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DEVELOPMENT OPTIONS

The Development Options integrate the geothermal system design options appraisal and district heating network (DHN) design options appraisal. Two alternative design options are presented, taking into account all subsurface and surface factors considered.

Option 1 consists of a single production well and passive minewater treatment facility. The identified location for the production well is south of Allanton near or even at the Kingshill Mineshaft No.1. Pumping minewater in this vicinity offers the highest potential for lowering the local water table and reducing or preventing the minewater resurgence issues which affect this area and the village of Allanton which is downslope from there. It also allows the polishing wetlands to be located in an area already providing this facility, and contribute to the objectives of the Local Nature Reserve and Site of Importance for Nature Conservation. Minewater would be pumped from the WRSM seam at a depth of c. 340 m below surface level. This option has been modelled with three DHN designs – networks A, B and C – to assess the impact of the heat network’s scale on the financial performance of the project.

Figure ES.1: Illustrative diagram of passive minewater treatment facility.

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Option 2 consists of a production well and two injection wells, with no passive minewater treatment. The geothermal system and heat centre components of this option are contained entirely within the JHI Hartwood Home Farm land boundary. This option produces and injects minewater from the WRSM seam at a depth of ca. 380 m below surface level. The heat centre in this option is situated between Allanton and Hartwood, so only network C, the largest DHN, has been modelled.

Figure ES.2: Illustrative diagram of doublet system with production and injection well(s).

The advantages and disadvantages of the two options – one proposing a passive treatment system, and the other proposing reinjection (with alternative locations for the production wells) – are compiled to compare the options. The options are also subject to a risk assessment, and opportunities from this project are identified.

The geothermal minewater DHN for Allanton and Hartwood has been calculated to offset 782 tonnes of CO2/year based on the 2015 UK electricity mix. However, it should be noted that this figure is based on displacing gas consumption, and the homes in Hartwood are off gas-grid, many using oil. Displacing this fuel source would further reduce carbon emissions.

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DELIVERY MODEL

The feasibility study has considered the potential business models and legal structures currently deployed for DHN in the UK, and potential Energy Services Company (ESCO) structures for the Fortissat Minewater Geothermal project, and how these might evolve over the lifetime of the development. A preliminary financial model has been prepared to assess the commercial viability of the development options, and the results are summarised.

There are a number of different factors that need to be taken into consideration in selecting a preferred structure to deliver and run the project. These include, but are not necessarily limited to:

• The preferred technical scenario; • The delivery structure; • The procurement strategy; • The Council’s strategic priorities for the project; • The willingness of the Council to work with a joint venture partner(s) or to enter long term supply contracts with a 3rd party; • Longer term transition and exit strategy (if any); • Tax considerations; • EU State Aid considerations.

To provide a reference point for these factors, a review of existing heat networks has been undertaken, and a comparison undertaken of the advantages and disadvantages of the different commercial structures available. For the purposes of the preliminary financial model we have assumed that the project is delivered using a company limited by shares.

A key work stream during the next phase of the project will be to identify the preferred structure for the project. It should be noted that North Lanarkshire Council is currently considering the most appropriate business model for the development of a community heating network at high-rise flats in Motherwell. During our discussion with the Council there is the potential that the same operating model may be applicable for the Fortissat geothermal project. Using the same model may result in some cost savings but care will need to be taken in determining whether the model will require adjustment for a rural DHN connected to a geothermal project and dealing with both privately owned and social housing.

A financial model has been built to describe and evaluate the first 40 years of the project life as per the DECC Heat Network Project Metric Template. The financial model has intentionally been

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designed to be flexible and adaptable so that it can be used throughout the development process, including for the ultimate financing of the project construction. The structure of the financial model allows additional functionality to be added easily as the project continues to take shape.

The financial model evaluates multiple scenarios based around a heating network that comprises:

• A minewater production well; • A heat exchanger and clean source loop pipe to capture heat at the production wellhead; • An energy centre that captures heat from the minewater; • A back-up gas boiler; • A district heating network comprising pipework and pumps; • Housing stock upgrades comprising energy efficiency improvements and a domestic heat interface unit replacing gas boilers; and • Two options for minewater disposal: either injection wells back into the mine; or a surface passive water treatment plant.

Construction is assumed to take 20 months, with the system becoming operational by 1 April 2021. Ongoing operating expenditure includes plant and well maintenance, electricity consumption, treatment of waste water and gas consumption for the back-up boiler.

The following preferred design options have been considered:

Design option Description

1A 700 kW heat pump, 173 council houses and 155 private houses, low temperature DHN, passive treatment facility [Allanton only]

1B 1 MW heat pump, 197 council houses, 240 private houses, low temperature DHN, 1 school, passive treatment facility [Allanton only]

1C 2 MW heat pump, 201 council houses, 415 private houses, low temperature DHN, 1 school, passive treatment facility [Allanton and Hartwood] 2 2 MW heat pump, 201 council houses, 415 private houses, low temperature DHN, 1 school, injection wells [Allanton and Hartwood]

Table ES.1: District Heating Network Options

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project with potentially wide applications throughout Scotland, the Fortissat project will attract preferential financing terms and/or an element of grant funding.

The following table summarises the capital and operating expenditure assumptions that have been used in the preliminary financial model. The development is still at an early stage and the detailed design process has not yet begun. Some of the costs may change substantially as the project progresses and as additional studies are undertaken. Where significant uncertainty exists we have intentionally used conservative estimates.

Option 1a Option 1b Option 1c Option 2 700 kW Pump 1 MW Pump 2 MW Pump 2 MW Pump Low Temp Low Temp Low Temp Low Temp (75°C) (75°C) (75°C) (75°C) Small Network Medium Large Network Small Network Network

Capex (£ real) Production well(s) 460,000 460,000 460,000 500,000 Energy centre 2,730,823 3,995,080 6,781,253 6,976,623 Gas grid connection 21,566 21,566 21,566 122,366 Electricity grid connection 245,750 245,750 245,750 331,000 Heating sytem upgrades 590,400 786,600 1,108,800 1,108,800 Fabric energy efficiency 29,450 45,600 78,850 78,850 measures Passive treatment system 1,200,000 1,200,000 1,200,000 - Injection wells - - - 1,000,000 Injection well downhole - - - 15,000 pumps Total capex (£ real) 5,277,990 6,754,597 9,896,220 10,132,640

Opex (£ real per annum)

Operating expenditure 74,278 96,799 167,227 182,867 Employee costs 17,500 17,500 35,000 35,000 Passive treatment system 30,000 30,000 30,000 - Total opex (£ real per 121,778 144,299 232,227 217,867 annum) Table ES.2: CAPEX and OPEX figures as input to the financial model, for Options 1A, 1B, 1C and 2 low Temp.

The majority of the costs increase as the network size increases. The exceptions are the production wells, gas and electrical grid connections, and the cost of the passive treatment system.

It should be noted that the CAPEX and OPEX estimates above do not include the costs of administration, billing, etc. These depend upon the ESCO structure which is selected and will therefore need to be defined more fully at the next stage of the project.

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The revenue is composed of two elements: heat sales to customers and income from the Renewable Heat Incentive.

A heat network is fundamentally different to the gas or electricity markets, in that as a closed loop network, rather than a national grid, there is only one ‘supplier’. Appropriate governance structures need to be put in place for all heat customers to provide safeguards that the heat tariff is equivalent, if not discounted, against other forms of energy supply. This may also be necessary to provide the incentive for heat users to sign up in the first place – particularly given the potential for up-front connection costs, and the inevitability of construction disturbance caused by the implementation of building efficiency measures, internal wet system upgrades (upsized radiators), and boiler replacement with Heat Interface Units to enable connection to a low temperature network.

The revenue for heat sales was modelled as 6 p/kWh which offers a 2% saving to Council tenants compared to an assumed price of heat from gas of approximately 6.13 p/kWh. Owner-occupiers would benefit from a higher alternative price if the cost of boiler replacement is factored in, however this could be handled through a connection charge to customers wishing to connect to the network.

Specific decisions on heat prices will need to be further considered in order to offer an incentive to customers to connect. The issues to consider will be:

• How investment cost of heat interface unit (HIU) and branch connection are shared between the network operator and the customer;

• Standing/capacity charges for heat (£/kW) supplied to customers and whether this cost varies between customers; and

• Unit cost of heat (£/kWh) supplied to customers:

o Whether this cost varies between different types of off-takers;

o Whether or not cost varies with time of day, season, etcetera;

o Whether or not the tariff rates be linked to gas-prices, for instance through a % discount or offset and floor-price.

The unit cost of heat is not the only consideration. For example if the network operator provides financial support for the investment in energy efficiency improvements to customer properties, then these should result in an overall reduction in heat demand. It may then be reasonable to consider a

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higher unit cost than the Business as Usual alternative while offering customers a reduction in their annual energy bill.

In order to understand the effect of variations in the usage tariff on the financial model, this was one of a number of factors which were included in a sensitivity analysis. Other factors include variations in the CAPEX and OPEX, and the rate applied for the Renewable Heat Incentive.

Another factor which has the potential to affect the financial model relates to the cost savings to the Council arising from the new minewater treatment facility. The Council currently spends an average of £50,000 per annum on mitigating minewater resurgence from Kingshill on the village of Allanton. The initial results of the financial analysis are reported with and without this cost saving taken into account.

The figures in Table ES.3 below show the key financial metrics for the four design options. For the time being we have elected to use the 20 year aggregate cash flow rather than net present value. This is due to the current uncertainty around the ESCO structure and the resultant difficulty in determining an appropriate discount rate.

20 year Design Option: Project CAPEX Descriptor net cash COP % Debt HP Size, Temp IRR (%) (£m) (£m)

1A: 700kW LT small network + Pump, 75°C passive treatment -3.1 0.0 5.7 3.34 50

1B: 1MW Pump, LT medium network + 75°C passive treatment -0.8 0.0 7.2 3.39 50

1C: 2MW Pump, LT large network + 75°C passive treatment 3.2 1.6 10.6 3.58 60

2: 2MW Pump, LT large network + 75°C injection wells 3.4 1.7 10.8 3.58 60

Table ES.3: Headline results for design options 1A, 1B, 1C and 2.

The obvious conclusion to draw from these figures is that the number of users connected to the network is critically important. The higher the network demand, the better the returns for investors. Only the largest network options (1C and 2) have positive IRRs and positive aggregate net cash flows over the first 20 years. However, in neither case is the Project IRR sufficiently high to attract external investors. This indicates that the project structure will be a not-for-profit ESCO which is 100% owned by the Council. This preliminary conclusion may change as the CAPEX and OPEX estimates are refined further in the next phase of development.

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If the cost savings for the Council for mitigating minewater resurgence through a new passive minewater treatment facility are taken into account in options 1A, 1B and 1C then the figures in would be as follows:

20 year Design Option: Project CAPEX Descriptor net cash COP % Debt HP Size, Temp IRR (%) (£m) (£m) 1A: 700kW LT small network + Pump, 75°C passive treatment -1.7 0.0 5.7 3.34 50 1B: 1MW Pump, LT medium network + 75°C passive treatment 0.6 0.0 7.2 3.39 50 1C: 2MW Pump, LT large network + 75°C passive treatment 4.6 2.7 10.6 3.58 60 Table ES.4 Improvements in project IRR and aggregate 20 year cash flow when accounting for potential cost saving to NLC of £50,000 per annum through implementation of a passive minewater treatment facility integrated with the geothermal DHN

The longer term financial modelling indicate that the removal of the RHI revenue after 20 years will have an adverse impact on the project economics. There are however a number of ways in which this reduction in revenue could be addressed, including:

• The expansion of the network into Shotts would increase the Linear Heat Density and therefore the potential revenue. • Setting up a trading arm as a subsidiary, to connect non-Council off-takers on a commercial basis. • DECC expects gas prices to increase in the future. This will drive up the costs of alternative sources of heating and allow higher tariffs to be used at Fortissat, while still offering customers a discount compared to the alternatives. • Given the ambitious UK and Scottish targets for decarbonising heat, it is possible that new policies could be implemented to either (i) reform or extend the RHI, or (ii) replace the RHI with another support mechanism. • Direct carbon taxes may become more prevalent. This would have the impact of increasing the price of gas and heating oil, which in turn would allow the Fortissat project to charge a higher tariff while still offering customers a discount.

There are also a number of factors which may in future reduce the project’s operating costs. It is difficult to predict at this stage the likelihood of any of these occurring, or the impact that they may have on the project economics. These factors include:

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• The project relies on electricity to power the heat pumps, Electric Submersible Pump (ESP) and network pumps. It is possible that electricity cost will reduce over time as increased penetration of renewable energy in the UK lowers the marginal cost of generation. • It may be possible in the future to install on-site electricity generation (e.g. solar PV) in order to lower the electricity cost for the project. • A gradual improvement in minewater chemistry may reduce maintenance costs for the equipment. • Maintenance and infrastructure costs may decrease as heat networks become more common in the UK.

NEXT STEPS

The Fortissat Community Minewater Geothermal Energy District Heating Network project has the potential for multiple benefits – social, environmental, carbon reduction, financial.

On the basis that the Catalyst Stage has identified a potentially feasible project, and the outcomes of the engagement undertaken to date has been positive, the next steps and an indicative programme are set out for the Development Stage. There are distinct, but interdependent work streams identified:

(i) confirming the heat resource through testing and using the data on flow rates, minewater chemistry and temperature to design how the geothermal energy system will be built and maintained;

(ii) confirming the heat market through both consultation and developing detailed proposals for how the required building efficiency measures and connections will be programmed and financed, and how the operational system will be managed.

These need to be progressed in parallel. In order to proceed, there will need to be increasing levels of confidence and certainty for both the supply and demand as the knowledge and understanding of how the system will be built and operated is refined.

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Chapter 1 – Introduction

1.1 OVERVIEW OF PROPOSAL

The “site”, for the purposes of the feasibility study and as the focus for defining locations for key infrastructure elements (such as production well, energy centre and reinjection well / passive treatment systems), has been Hartwood Home Farm, reflecting the role of JHI as the grantee. However, as the understanding of the geothermal resource developed, and the potential for Council owned properties to form the basis for the heat market, further engagement with North Lanarkshire Council (NLC) as project partner enabled the potential for alternative locations for site infrastructure within land in the ownership of NLC to be investigated as options. This has established the former Kingshill Colliery No. 1, now the designated Kingshill Local Nature Reserve (LNR) / Kingshill Wetlands and Plantations Site of Importance for Nature Conservation (SINC), as a potential site. Land ownership and control is shown in Drawing 1.2.

Kingshill Colliery is one of Scotland’s largest historical mine systems and the mine seams partly underlie the southern area of Hartwood Home Farm. This was identified as by far the largest geothermal resource in the area of interest, and has been the main focus of this study, following a geothermal systems option appraisal which considered the various mine systems in the study area.

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within the area. The feasibility study identified constraints and opportunities in relation to using the available geothermal energy to provide heat in this area, to inform the identification of potentially viable heat networks.

The geothermal- and DHN options appraisals have formed the basis for determining two main development options, in two locations, and with alternative methods for discharging the minewater. The two options are compared, with risks and opportunities identified for each, and a preliminary carbon audit undertaken. The preferred option locates the production well at or close to the site of the Kingshill shaft, with a passive minewater treatment system discharging the water at surface. This has the potential to alleviate existing minewater resurgence which affects properties in the village of Allanton and are an ongoing maintenance burden to NLC and residents. Alternative sizes of the district heat network are considered for this option. An alternative option has also been considered, which locates the production well and two reinjection wells within Hartwood Home Farm. The medium term development potential for the DHN is focused on the villages of Allanton and Hartwood, with potential future extension to Shotts identified as a long term development potential.

The feasibility study has also considered the potential business models and legal structures currently deployed for DHN in the UK, and potential Energy Services Company (ESCo) structures for the Fortissat Minewater Geothermal project, and how these might evolve over the lifetime of the development. A preliminary financial model has been prepared to assess the commercial viability of the development options, and the results are summarised.

On the basis that the Catalyst Stage has identified a potentially feasible project, and the outcomes of the engagement undertaken to date has been positive, the Next Steps and an indicative programme are set out for the Development Stage.

1.2 PROJECT TEAM AND STRUCTURE

The project team was appointed by the Project Managers, David Townsend of Town Rock Energy and Jelte Harnmeijer of James Hutton Institute, in part during the grant application process and in part shortly after the grant was awarded. The Grantee is James Hutton Ltd which is wholly owned by James Hutton Institute (JHI). Philip Gane of JHI led on administration of the grant. The key strategic partner is North Lanarkshire Council, who have been engaged in an ongoing process. The project team’s structure is illustrated in the following organogram in Figure 1.1.

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Figure 1.1: Project team structure

1.3 REPORT STRUCTURE

Following this Introduction, the report has been structured as follows:

Chapter 2 – Environmental Baseline

Chapter 3 – Geothermal Supply

Chapter 4 – District Heat Network

Chapter 5 – Development Options

Chapter 6 – Delivery Model

Chapter 7 – Next Steps

Report references are at the end of the main report.

Technical Appendices have been included from the sub-consultants providing further detail on the baseline information and optioneering which has informed the assessment process and outcomes:

Appendix 1 – Glossary of Terms

Appendix 2 – Minewater Geothermal Regulation, Guidance and Consultation

Appendix 3 – Geothermal Technical Appendices

A3.1 – Potential MineWater Heat Recovery at Hartwood Home Farm, North Lanarkshire

A3.2 – Minewater Hydrology, Thermal Breakthrough Modelling, Minewater Hydrochemistry and Geo-Options Appraisal with Annex Drawings for Each Geo-Option

A3.3 – Kingshill Water Field Monitoring and Laboratory Testing

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A3.4 – Kingshill Water Analysis

A3.5 – Minewater Treatment at Kingshill

A3.6 – Kingshill Site Visit

A3.7 – Indicative Well Schematics

A3.8 – Geothermal System Cost Assumptions for Financial Model

Appendix 4 – District Heating Network and Energy Centre Cost Schedule for Financial Model

[There are no Appendices relating to Chapter 5]

Appendix 6 – Delivery Model Case Study Site Visits

A6.1 – Site Visit to Shettleston

A6.2 – Site Visit to Aberdeen Heat And Power

[There are no Appendices relating to Chapter 7]

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Chapter 2 – Environmental Baseline

2.1 INTRODUCTION

This chapter presents the baseline environmental information in and around the James Hutton Institute’s (JHI) Hartwood Home Farm, with the 5km study area from the site centre roughly equivalent to the Fortissat ward of North Lanarkshire. It provides the physical and environmental context for the potential minewater geothermal system and district heating network (DHN) in this area.

2.2 SITE

2.2.1 Location Hartwood Home Farm extends over the fields surrounding the village of Hartwood in North Lanarkshire. The village currently comprises approximately 85 houses, and is served by Hartwood railway station. A location plan is shown in Drawing 1.1.

Hartwood lies midway between Edinburgh and Glasgow and close to the M8. It is on a railway line connecting Edinburgh and Glasgow. It is close to the town of Shotts, and the area includes other villages and smaller settlements, including Allanton and Salsburgh. The area is typical of a former coal mining area with its associated social and economic deprivation.

Kingshill Colliery No. 1 is located to the south of Allanton. The village comprises approximately 567 houses, of which approximately 40% are council owned. There is also a small primary school, community centre, take-away and shop.

2.2.2 Land Ownership and Control Land ownership and control is an important consideration influencing the location of potential infrastructure on site, connection routes and extent of the DHN, and construction and operational access to site.

The land under the control of JHI extends to approximately 348.6 hectares. It is rented by JHI on a long lease from Scottish Government until 2070.

Part of the site is under option to ABO Wind for sub-lease as part of its proposals for Hartwood Wind Farm (planning application reference 14/01699/FUL, decision pending). The lease option agreement includes a 500m wind protection zone with development restrictions stating that no structure of

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greater than 4m in height can be constructed. This is not anticipated to represent a development constraint for a geothermal DHN, but is worth being aware of in the location and design of the energy centre (in the event that the wind farm is granted consent).

There are a number of other institutions owning land neighbouring Hartwood Home Farm, including Forestry Commission Scotland, the National Health Service Scotland, and the Scottish Prisons Service. Network Rail owns the railway line and rail infrastructure which bisects the farm and Hartwood Village. North Lanarkshire Council (NLC) departments are also major landowners, with the Roads and Transportation Service owning the roads and verges in the local area, the Council’s Greenspace Development (Regeneration and Environment Services) owning the Kingshill Local Nature Reserve to the south of Allanton, and Housing and Social Work Service owning areas of Council housing within the surrounding settlements as shown in Drawing 1.2.

2.2.3 Land Use and Land Cover Hartwood Home Farm is located on the single largest soil class in Scotland (Rowanhill Series) which occurs widely over Carboniferous rocks in central Scotland. This soil series is generally associated with poor drainage, and is mostly suitable for permanent pasture but in some places there is potential for arable production. It has also been recognised as a farm highly suitable for research as it represents a substantial category of land in Scotland and therefore necessarily has relevance in searching for more sustainable land use futures, particularly on wet upland soils under predominantly grassland systems. There is currently c. 45 ha of woodland in the form of shelterbelts, with a need to consider the regeneration of these.

Kingshill LNR extends to 112.5ha, and contains meadows, woodlands and ponds established as part of the reclamation of derelict land associated with the former colliery. While the site is designated for its nature conservation interest and has two waymarked trails, there are also ongoing legacy issues in relation to the former coal mine, in particular in relation to surface discharge of minewater. Although one main discharge passes through a passive treatment system, comprising aeration cascade, settlement lagoon and wetland ‘polishing ponds’, there are other discharges within the area which require diversion from Allanton via cut-off drainage ditches on the south side of the village.

Within the wider study area, the land use is predominantly a mix of farmland, commercial forestry plantation and settlement. There are areas of former opencast mining, and evidence of past mining operations, which influence the character of the landscape.

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2.2.4 Hydrology Hartwood Home Farm contains a network of small burns as shown in Drawing 2.1, some of which are potentially prone to flooding, as indicated by SEPA’s Flood map, especially those to the South of Hartwood Village on or to the south of the site boundary, along the South Calder Water, and along the Curry Burn, between the east of the site and Shotts. This potential flood risk, combined with general poor drainage of the soil may require a flood risk assessment, ground condition surveys and drainage strategy as part of preparing supporting information for planning and designing the minewater geothermal DHN.

Understanding the local hydrology is of particular relevance to obtaining CAR Licence from SEPA for the borehole(s), and this requires a water features survey for a radius of 1200m from the location of the borehole(s). This can largely be undertaken from desk-based sources, but does require a walkover survey to identify general wetland types. As two potential borehole designs involving different borehole location(s) are singled out in this feasibility study, a single preferred location has not been finalised, and the resulting study area is a substantial area for a walkover, which has not been undertaken to date.

However, a single day walkover was undertaken in the southern part of Hartwood Home Farm, which reflects the most likely location for a borehole within the JHI land ownership, and that most of the semi-natural habitats of interest are likely to occur (given the presence of the South Calder Water). The main findings from this survey, undertaken by Cameron Ecology (18th September, 2015) comprised:

• Typically of a farm in this area, the vast majority of the area is agriculturally improved grassland. In the National Vegetation Classification (NVC) these come out as MG6 or MG7. These are not really semi-natural habitats because they are a direct result of being sown as a seed mix with agricultural rye-grass cultivars. Some areas were ploughed grasslands at the time of the survey, so these are simply recorded as ‘ploughed’.

• Potential GWDTE NVC communities recorded include:

Marshy Grassland • M23a - Juncus acutiflorus rush-pasture - there’s only a small amount of this, mostly around the M27 tall herb fen (see below)

• M23b - Juncus effusus rush pasture - one or two areas with this. This is a common and widespread vegetation type, more commonly thought to occur as a result of impeded surface drainage than groundwater.

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• MG10a - Holcus lanatus - Jucus effusus rush pasture - one of the fields coded as this is shown as having been ploughed on the aerial photo, despite the photo being fairly recent. It’s also more or less on the top of a hill. This is pretty strong evidence that in this case MG10-type vegetation is a result of impeded surface drainage (clay soil) rather than groundwater as such. Most of the other areas of this vegetation community are wet bits of otherwise improved fields and are likely to have a similar origin.

Fen • M27a - Filipendula ulmaria - Angelica sylvestris tall herb fen. In the context of Lanarkshire these are quite attractive areas. They have an herb-rich form of M23a as a fringe around them. Parts of this area were quite dry at the time of the survey. Given its location immediately adjacent to the watercourse and in the bend of a meander it is possible that periodic surface water inundation sustains this vegetation.

Neutral Grassland • MG9 - Deschampsia cespitosa occurs in the watercourse valley sides. This is not normally considered an ecologically valuable vegetation type. It occurs in the valley floor in a couple of places.

• Other Habitats - Various other habitats have been recorded, none of these are especially notable - plantation woodland, bracken, etc. MG1 grassland is a neutral grassland type but isn’t on the list of potentially groundwater dependent communities - there are various places where this occurs, again mostly in the valley of the South Calder Water.

The hydrology at Kingshill is complex, and influenced by the minewater chemistry, with an existing passive minewater treatment system and areas of minewater resurgence at surface. These are discussed in more detail in Chapter 3 on Geothermal Supply and Technical Appendix A3.2.

2.3 SURROUNDING CONTEXT

2.3.1 Planning Designations The village of Hartwood is designated as HCF1A - Protecting Residential Amenity and Community Facilities - Residential Areas on the Proposals Map of the North Lanarkshire Local Plan (NLLP). The surrounding countryside, including Hartwood Home Farm, is designated as NBE 3B - Assessing Development in the Rural Investment Area. The site and its surrounding context, in relation to the Local Plan Proposals Map, is shown in Drawing 2.2.

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The location of the site within the Rural Investment Area (RIA), means that all planning applications would be subject to the criteria of NLLP policy NBE 3B – Assessing Development in the Rural Investment Area, which states: “The Council will protect the character and promote development in the Green Belt and the Rural Investment Area by restricting development to acceptable types and operating assessment criteria.” The criteria are listed in full in the policy.

2.3.2 Natural Heritage Designations A review of environmental designated sites from Scottish Natural Heritage (SNH) information services has confirmed that there are no environmental designations within the land ownership boundary. The review included the following designated sites:

• Sites of Special Scientific Interest (SSSI)

• Special Areas of Conservation (SAC)

• Special Protection Areas (SPA)

• Ramsar

• National Scenic Areas (NSA)

• National Nature Reserves (NNR)

• National Parks

• Local Nature Reserves (LNR)

The closest designations to the site comprise:

• Kingshill LNR, approximately 1.5km S of the farm complex, on the S side of Allanton;

• Hassockrigg and North Shotts Moss SSSI, a raised bog approximately 2.75km NE of the farm complex, on the E side of Shotts;

• North Shotts Moss SAC, comprising a degraded and active raised bog approximately 2.75km NE of the farm complex, on the E side of Shotts;

• Braedale Hill LNR, approximately 3.5km SE of the farm complex, on the S side of Newmains;

• Greenhead Moss and Perchy Pond LNR, approximately 6km SE of the farm complex, just under 5km from the site boundary, on the SE side of Wishaw.

Natural Heritage designations within 5km of the site are shown in Drawing 2.3.

In addition to the above listed designations, there are a number of Sites of Importance for Nature Conservation, designated in the Local Plan (as Natural Environment Areas) and shown in Drawing

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2.2. These locally designated sites contain significant plants, animals or wildlife habitats, identified for protection and enhancement in the North Lanarkshire Biodiversity Action Plan.

2.3.3 Cultural Heritage Designations A review of cultural heritage designated sites included the following designated sites:

• Listed Buildings

• Canmore

• Historic Environment Record (HER)

• Scheduled Monuments (SM)

• Gardens & Designed Landscapes (GDL)

• Conservation Areas

• Inventory Battlefields

• World Heritage Sites

There is one site of national importance - an Inventory listed Garden and Designed Landscape, Allanton, dating from the late 18th and early 19th century, valued as outstanding as a work of art and for its historical association, and high for its scenic value.

There are three sites of local value, in the form of Category C listed buildings within ~1km of the site, comprising:

• Hartwood Hospital, central administration block, flanking villa wards and attached service range to rear

• Hartwood Hospital, Nurses Home

• Allanton Mill

There are further sites of local interest. The Royal Commission on the Ancient and Historical Monuments of Scotland (RCAHMS) on its “Canmore” database includes a number of sites (listings including site types described variously as tramway, colliery, rig and furrow, spoilheap, quarry reservoir, farmstead and building). There are a number of other Canmore listings in the local area.

Cultural Heritage designations within 5km of the site are shown in Drawing 2.4.

2.3.4 Landscape Character Hartwood Home Farm is located within an area characterised as Plateau Farmland in the Glasgow and Clyde Valley Landscape Character Assessment (SNH Review no. 116, 1999), as shown in Drawing

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2.5. This landscape occurs on the lower slopes of all the Plateau Moorland areas encircling Glasgow and its conurbation. Plateau Farmlands are characterised by their transitional location between the sheltered landscapes of Rolling Farmlands and Broad Valley Lowland, and exposed uplands and moorlands.

The key characteristics, features and qualities of this landscape type are:

• Extensive, gently undulating landform;

• Dominance of pastoral farming, but with some mosses surviving;

• Limited and declining tree cover;

• Visually prominent settlements and activities such as mineral working;

• The rural character of the Plateau Farmland has suffered as tree cover has declined and the visual influence of settlements, transport infrastructure and mineral working has increased.

2.3.5 Settlement Context As noted, Hartwood Home Farm is located in the fields surrounding the village of Hartwood. The village currently comprises approximately 85 houses, and is served by Hartwood railway station.

The remains of Hartwood Hospital (to the W of the village) and Hartwoodhill Hospital (to the east of the village), are now derelict, and are set within a mature landscape framework. The sites are owned by NHS Scotland, and are being marketed for sale by Rydens LLP, and promoted for housing through the Local Development Plan consultation process.

2.3.6 Transportation Network Hartwood Home Farm is bisected by a railway line connecting Edinburgh to Glasgow. There is a railway station in Hartwood Village. The village is accessible via the ‘C’ class road network.

The M8 passes between on an east-west axis approximately 2 and 3km from the site’s northern boundary. Connections to the M8 are provided to the west by the A73; and to the east by the B717/B7057, both on a north-south axis. The A71 passes within 500m of the site’s southern boundary.

2.4 PROPOSED DEVELOPMENT

2.4.1 Hartwood Wind Farm Hartwood Wind Farm is a proposal for 7 wind turbines with a maximum height to blade tip (HTT) of 126.5m, and ancillary infrastructure including electrical control building, crane pads, access tracks

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and associated fencing. It is located partly on Hartwood Home Farm and partly on land owned by Forestry Commission Scotland to the north.

The proposal was submitted to North Lanarkshire Council on 25 August 2014 (application reference 14/01699/FUL) and is currently pending consideration.

2.4.2 Potential New Housing The remains of Hartwood Hospital (to the W of the village) and Hartwoodhill Hospital (to the E of the village, are now derelict, and are set within a mature landscape framework. Both sites were promoted at the Call for Sites stage of the emerging Local Development Plan as potential housing / mixed use sites by Ryden LLP on behalf of the NHS Lanarkshire (Sep 2013). Both sites are currently being marketed for sale by Rydens LLP (February 2016).

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Chapter 3 - Geothermal Supply

3.1 INTRODUCTION

This chapter introduces the basic principles of minewater geothermal energy and provides an overview of the mine systems in the study area. It identifies the coal seams most likely to provide the best resource for minewater geothermal energy, and provides preliminary desk based assessment of the temperature and volume to provide estimates of the heat potential (within the mine) and instantaneous geothermal potential (for a district heating network). Kingshill Colliery is one of Scotland’s largest historical mine systems and the mine seams partly underlie the southern area of Hartwood Home Farm. This was identified as by far the largest geothermal resource in the area of interest, and has been the main focus of this study. This chapter also reviews the mine records to identify targets for the drilling, considerations for the drilling techniques, and considerations for optimising performance of the operational system, including considerations of minewater chemistry and thermal breakthrough (where the cooler minewater returned to the mine after heat has been extracted decreases the source temperature). This assessment forms the evidence base for a geothermal systems option appraisal which considers the pros and cons of the various mine systems in the study area to identify two preferred options.

3.2 MINEWATER GEOTHERMAL ENERGY - BASIC PRINCIPLES

Conceptually, three interconnected elements are required to allow geothermal energy to be exploited from minewater (Figure 3.1, next page):

1) A heat source or heat reservoir. To be exploitable, a heat reservoir typically needs to contain permeable pathways (e.g. mine workings or natural permeability) and a substantial volume of mobile groundwater that can be pumped, via a drilled borehole, to a heat exchange system at the surface.

2) A heat transfer or energy conversion system. For example, a heat exchanger coupled to an array of electrically-powered heat pumps. These can recover heat from the mine-water and increase the temperature to levels capable of serving a District Heat Network (DHN) which supplies heat consumers.

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3) A disposal system. The “thermally spent” minewater then needs to be disposed of responsibly. It can be transported via a buried pipe to a separate re-injection borehole, which returns the water to the mine system (a “zero net abstraction system”). Alternatively, the thermally spent minewater could be treated, passively and at modest cost, before being discharged to a natural watercourse. This would avoid the cost of one or more expensive injection boreholes.

Figure 3.1: Schematic diagram of a generic mine-water geothermal energy doublet system (not to scale). PWL and SWL are pumping water level and static water level respectively. PLEASE NOTE: the mined seams displayed in this diagram do not represent the actual fluid flow pathway between the injection and production wells, and are for illustrative purposes only. Also note that in some designs a plate heat exchanger may be installed at the production well head to transfer heat into a clean loop which transfers heat to the heat pumps, to avoid corrosion of the heat pumps.

3.3 THE RESOURCE – THE MINE SYSTEM

In this project, digitised information from mine abandonment plans has been used to build a new 3D computer model of the mine workings below and adjacent to the James Hutton Institute’s Hartwood Home Farm. The project study area also considered mine workings within the project area of interest, an area approximating the Fortissat Ward of North Lanarkshire Council (Drawing 1.1).

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The 3D model provides the necessary information to make an estimate of the extent and volume of mine workings available (Section 3.2.2) and the potential geothermal resource they represent (Section 3.2.3).

3.3.1 Mine Geometry Digital scans of mine workings from coal mine abandonment plans held by the BGS were used to create Geographic Information System (GIS) shape-files of the positions of the disused mine workings, shafts and adits in and around the project area. Stone drivages (underground tunnels linking across different seams), roadways, spot height and contour data, where recorded, were also digitised.

The shape-files were then imported into MoveTM software for production of the 3D model of the subsurface geometry of the underground coal workings. The eight coal seams considered (in stratigraphic order from youngest to oldest) were:

• Upper Drumgray Coal (UDC) – shallowest • Middle Drumgray Coal (MDC) • Lower Drumgray Coal (LDC) • Shotts Gas Coal (SGA) • Mill Coal (MILL) • Armadale Main Coal (ARM) • Woodmuir Smithy Coal (WRSM) • Wilsontown Main Coal (WNMA) – deepest Mine depths are expressed relative to sea level – Ordnance Datum (OD). The Woodmuir Smithy (WRSM) and Wilsontown Main (WNMA) seams are substantially deeper (below -200 m OD, Drawings 3.1 - 3.3) than all the other worked seams, which occur above sea level (+0m OD, Drawings 3.4 - 3.9) and typically within several tens of metres of the surface.

Shallow mineworkings occur under the Hartwood Farm site to the west and south-west of Shotts/Dykehead. Most workings are less than 100 m beneath the ground surface. In addition to those listed above, seams worked within the Scottish Lower Coal Measures Formation include the Kiltongue Coal and Airdrie Virtuewell Coal. The Lower Drumgray (Shotts Smithy) Coal was worked more extensively between Salsburgh and Shotts/Dykehead. The workings were mostly less than 100 m below the surface. Scottish Middle Coal Measures Formation coals were worked in surface coal mines to the south and west of Shotts Prison.

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Additional data imported into the 3D model included a digital terrain model (DTM), and the Hartwood Home Farm study area (Drawing 1.1), provided by the James Hutton Research Institute (JHI). The maximum and minimum depths (relative to OD) were calculated from the model for each seam, as well as the estimated volume of mine workings. It is likely that the worked coals across the area will vary in thickness, and therefore an average value of 1 m (taken from boreholes) was chosen for volume calculations. The results are summarised in Table 3.1. The extent of each modelled seam with elevation (OD) is shown in Appendix A3.1 in stratigraphic order. Drawing 3.10 illustrates an outline of all the 3D modelled surfaces, and Drawing 3.11 presents a 3D image of the modelled seams.

Within the wider Fortissat study area (Drawing 1.1), the following areas of mine workings were not modelled:

1. Small area in the WNMA to the south of Spoutcross along the southern boundary 2. Small area in the WRSM to the north-east of Harthill along the north-eastern boundary 3. Three areas in the LDC: a. in the north-western corner around South Lanridge Farm b. in the north between Kirk of Shotts and Shotts Prison c. 1 – 2 km to the north-east of Shotts 4. Small area in the UDC around Fernieshaw along the western boundary

With the exception of the WRSM workings near Harthill, which reach depths of around 500 m, these unmodelled workings are shallow (100 m or less).

Minimum Maximum Potential total mined Coal Full Name depth (m, depth (m, volume m3 (assuming 1 Seam relative to OD) relative to OD) m thick workings) UDC Upper Drumgray Coal 238 103.7 1392517 MDC Middle Drumgray Coal 228.6 131.1 566714 LDC Lower Drumgray Coal 213.9 75.5 1168779 SGA Shotts Gas Coal 210.6 196.9 17040

MILL Mill Coal 175.7 110.8 87032 ARM Armadale Main Coal 168.2 127.4 139456

WRSM Woodmuir Smithy Coal 79.9 -276.8 10725782 WNMA Wilson Town Main Coal -9.7 -304.2 5902271

Table 3.1: Summary of mined workings within coal seams within and adjacent to the study area, and associated mined volume and elevation (OD) ranges. Note: in several cases, the locations of maximum and (especially) minimum depths lie outside the Hartwood Home Farm study area.

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3.3.2 Mine-Water Temperature and Volume Based on an estimated geothermal potential in the mined regions of the Midland Valley of 5 x 108 kWh/km2 (Gillespie et al., 2013), a previous feasibility study estimated a potential resource of 3.5 x 108 kWh below the original 0.7 km2 Hartwood Home Farm study area. In the light of the 3D seam model, this has now been re-evaluated. The re-evaluation will focus on the Wilsontown Main (WNMA) and Woodmuir Smithy (WRSM) seams (Drawing 3.1, 3.2 and 3.3) as these are both the most aerially extensive and deepest (presumed warmest) seams. The workings of these two seams underlie an area of 10.7 km2 (Table 3.1) and were formerly worked via Kingshill No. 1 colliery. The WRSM directly overlies the WNMA with about 30 m separation, and the two are believed to be hydraulically interlinked via the shaft of the Kingshill Colliery and also via stone drivages that are likely to have remained open after mine closure (Drawing 3.3). The coal seams dip down to the north: thus, the maximum worked depth is found in the northern part of the WNMA workings (- 304.2 m OD – Table 3.1) just on the southern edge of the Hartwood Home Farm study area. The geothermal heat potential of the mines depends on the available mine-water volume and temperature.

Minewater Temperature Temperature typically increases with depth in the earth – the geothermal gradient. This is approximately 30.5°C/km across onshore Scotland. Minewater temperatures in Scotland range from 12 to 21°C, with a mean of 17°C (Gillespie et al., 2013), but a comparison of temperature with depth in mine workings does not show a clear geothermal gradient (Figure 3.1). This probably reflects the very dynamic nature of water circulation within many mine systems.

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y = 0.0147x + 9 20

10 Temperature (°C)

0 0 100 200 300 400 500 600 700 800 900 Depth (m)

Figure 3.2: Geothermal gradient from bottom-hole temperature-depth measurements in collieries in the Midland Valley.

We do not know the water temperature in the WRSM or WNMA workings: this can only be resolved through drilling and testing a well. Thus, our estimates of geothermal potential are based on three possible scenarios:

• Worst case: a temperature of 13.9°C, based on the recorded temperature of water discharging from a pipe intercepting the abandoned Kingshill No. 1 shaft (Appendix A3.2 and A3.4). It is felt that this is likely to be an underestimate, as the currently discharging water may have been cooled by interaction with the groundwater in shallower, overlying strata. • Intermediate case: a temperature of 17°C, based on Burley et al.’s (1984) recorded temperature of 17°C from 549 m bgl (below -309 m OD) at the nearby Polkemmet Colliery, and also reflecting the mean minewater temperature for Scotland. • Best case: a temperature of 19.2°C, based on the temperature of water pumped from the shaft of Polkemmet Colliery, which is of similar depth and is broadly analogous to Kingshill Colliery (Ó Dochartaigh, pers. comm., 2015 – see also Appendix A3.2).

Reservoir Volume The estimated geothermal potential depends not only on the reservoir temperature, but also on the volume of warm rock and water that can be intercepted by a geothermal system. A number of assumptions are possible and these are all documented in Appendix A3.1

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• Assumption 1: only the heat contained in the minewater within the worked seams is available. • Assumption 2: the heat contained both in the water and mineral matrix in the worked seams is available. • Assumption 3: the heat contained in the worked seams and any adjacent aquifer (of assumed porosity 10%) is available. The volume of the mine reservoir has been calculated based on each of these three assumptions and has been modified by a so-called “recovery factor”. This is based on the observation that a geothermal doublet comprising an abstraction and a recharge well will preferentially access the heat contained in the strata between the two wells and may not be able to efficiently access the entire volume of mine voids.

The estimates (Appendix 3.1) are based on a calculated combined mined volume of the WNMA and WRSM (and interconnecting stone drivages) of 16.92 million m3 (Table 3.1). Because minewater discharges are observed at +200 m OD at Kingshill No. 1 Colliery and at +183 m OD at Redmire Crescent, Allanton (North Lanarkshire Council, 1999), the workings are assumed to be completely flooded. Because the WNMA and WRSM seams were worked by longwall techniques, they can be assumed to have collapsed and become filled with porous goaf. Thus, the volume of the mine workings needs to be modified to take into account this collapse (e.g. Gillespie et al., 2013) to give a final water-filled void space:

• A minimum estimate of volume assumes a void space of 20% in areas that have been longwall mined in addition to open stone drivages with a radius of 2m, 3.62 million m3. • One could further reasonably assume that the surrounding rock formations (silty sandstone) will have been fractured due to mining activity, such that the void space is likely to be closer to 30%, 5.28 million m3. • A maximum volume estimate would assume that open roadways and drifts would increase porosity further, but the proportion of these is not known. A void volume of 35% is tentatively estimated if a number of these roadways and drifts were open, 6.12 million m3.

3.3.3 Estimated Heat Potential (WRSM and WNMA Seams) The calculations performed by the British Geological Survey which form the basis of Section 3.2.2. have effectively resulted in 9 estimates of the geothermal potential, based on:

• Three assumptions about the nature of the mine reservoir. • Three estimates of abstracted minewater temperature (best, intermediate and worst case. In all cases, the reinjection temperature is (somewhat arbitrarily) set to 7°C. In the case of Assumptions 1 and 2, these temperatures are coupled to maximum (35%), intermediate (30%)

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and minimum (20%) assumptions regarding the porosity of the mined strata. In the case of Assumption 3, the temperatures are coupled to best (500 m), intermediate (320 m), and worst case (120 m) assumptions regarding the thickness of the adjacent aquifer.

Details of how the results were calculated are presented in Appendix A3.1, with the results summarised in Table 3.2:

Reservoir Model 1 Model 2 Model 3 model Minewater only Minewater & rock Mine and aquifer

Recovery None 0.33 0.42 factor 7 7 13.9 °C 2.90 x 10 kWh 3.78 x 10 1.42 x 109 Mine-water 7 7 17 °C 6.13 x 10 4.83 x 10 5.49 x 109 temperature 7 7 19.2 °C 8.67 x 10 5.69 x 10 1.05 x 1010 Table 3.2: Minimum, intermediate and maximum geothermal potential (in kWh) of the water stored in the in the WNMA and WRSM mines. Reinjection temperature of 7°C is assumed in all cases.

The assessments made in Table 3.2 that neglect the aquifer system (i.e. Assumptions 1 and 2), assume that the minewater within the workings is isolated and does not interact with adjacent aquifer strata or the surface. However, evidence indicates that there is likely to be a good hydraulic recharge of the mine-water system; Younger and Adams (1999) suggest a complete flooding of the mine within 15 years of the closure of the Kingshill No. 1 colliery; the Carboniferous sedimentary aquifers in Scotland are expected to have a reasonably high transmissivity (10 to 1000 m2/day) even if they are not mined (Ó Dochartaigh et al., 2015). It might be hoped that this recharge would also help to sustain temperatures somewhat as natural groundwater through-flows might mix with reinjection fluids in the mine. It is therefore likely that the estimates associated with Assumptions 1 and 2 in Table 3.2 are too low.

There is thus a significant degree of uncertainty surrounding the estimates of geothermal potential in the WRSM and WNMA mined seams. However, if there is a good connection between the mine system and the surrounding aquifer, the minewater geothermal potential beneath the Hartwood Home Farm study area might be an order of magnitude higher than initially estimated, between 1.42 x 109 and 5.49 x 109 kWh. This corresponds to the initial feasibility study estimate of 5 x 108 kWh/km2; the total geothermal potential in this study is predominantly due to the increased mined area being considered. However, these estimates rely strongly on a good hydraulic continuity with

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the whole aquifer: if this is not the case then the geothermal potential could be up to two orders of magnitude lower.

To put these estimates in context, a resource of 1.42 x 109 kWh represents:

• 258 years of extraction at a rate of 0.63 MW (5.5 x 106 kWh per year) • 71 years of heat extraction at a rate of 2.3 MW (2 x 107 kWh per year) – representing an abstraction of 50 L/s water at 18°C, with reinjection at 7°C (see Appendix 3.2), which is considered feasible given the historic pumping rates at Kingshill and Polkemmet Collieries.

3.3.4 Instantaneous Geothermal Potential The results presented in the sections above estimate the total geothermal heat resource associated with the Wilsontown Main (WNMA) and Woodmuir Smithy (WRSM) mine workings in kWh. The assumed reinjection temperature �!"# of 7 °C and three possible minewater temperatures �! of

19.2, 17 and 13.9 °C produce temperature differentials �! − �!"# of 12.2, 10 and 6.9 °C respectively. The calculations can thus be modified relatively simply to accommodate a range of other assumptions about the minewater and reinjection temperatures.

At any given point in time, however, a production well will be producing a quantity Q of water (L/s) at a temperature �!. The water will pass through a heat exchanger (coupled to the evaporator of a heat pump) and a quantity H of heat will be extracted from the water (kW or kJ/s). The water will leave the heat exchanger at a temperature �!"# and will then be reinjected or otherwise discharged. The instantaneous rate of heat available is given by:

� = ��!"# �! − �!!"

As the volumetric heat capacity of water (Cwat) is 4.18 kJ/L/°C, the amount of heat available for every 10 L/s of water is 41.8 kW for every 1 °C temperature change across the heat exchanger.

Over the long term, it is possible (especially in a geothermal well doublet) that the temperature �! of the abstracted minewater will decrease, thus also decreasing the efficiency of heat extraction. The actual sustainability of the system will depend to a large degree on the flow pathways and thermal breakthrough times, which are dependent both on the mine network and the setup of the geothermal system. These aspects will need to be modelled in detail at the next stage of project design if the minewater is to be reinjected.

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3.4 GEOLOGY, HYDROGEOLOGY AND DRILLING

The deep Woodmuir Smithy (WRSM) and Wilsontown Main (WNMA) seams in the southern part of the study area were worked by longwall methods from Kingshill No. 1 Colliery, which comprised two shafts. The workings of Kingshill No. 1 colliery are thought to interlink into Kingshill No. 3 colliery further south and into other collieries further up-dip towards the south, via stone drivages and shafts. The situation is directly analogous to that at Polkemmet Colliery, whose hydrogeology and water chemistry are much better known, some 10 km to the NE.

3.4.1 Kingshill No.1 Colliery Background Kingshill Colliery No. 1 (also known as Allanton Colliery) was opened in 1919 and closed in 1968. It was abandoned in 1975. The two shafts are recorded as being 344 m (No. 1 shaft) and 371 m (No. 2 shaft) deep. According to the mine abandonment plan, however, the shafts are given as 378 and 376 m, respectively. The colliery has now been demolished. According to the British Geological Survey “Wellmaster” database, Kingshill No. 1 Colliery was typically dewatered at an average continuous rate of 41.7 L/s when working, with maximum rates of 98.5 L/s.

Although Kingshill Colliery No.1 was not closed until 1968, from 1951 onwards a significant proportion of the output from the mines was brought to the surface from Kingshill Colliery No. 3, further to the south. This remained open until 1974 and was abandoned in 1975.

Further detail on the Kingshill Colliery No. 1 background, including references, are provided in Appendix A3.2, with detail on the existing passive minewater treatment system included in Appendix A3.5.

3.4.2 Mining Techniques and Hydrogeological Targets The Woodmuir Smithy (WRSM) and Wilsontown Main (WNMA) seams at Kingshill No. 1 were worked by advancing longwall techniques. Since the 1950’s, most underground mining has used longwall methods, as opposed to stoop and room mining which was common until the mid-20th century.

In longwall mining the coal seam is worked between two parallel access roadways. Following mining, the roof strata are allowed to collapse and the void becomes filled with broken overburden (called goaf). The coal panel between the roadways is generally between 100 to 250m wide and it has been estimated that about 20% of the mined void would remain after mining induced subsidence has occurred.

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Mining profoundly alters the hydrogeology of targeted areas. Many shafts, roadways and other linear access structures were built to last and may be likely to remain as open voids in the subsurface today. When these structures are below the water table, they act as extremely permeable, interconnected channels for groundwater flow.

The location of longwall mining areas and access structures dictates where groundwater could be abstracted from and subsequently determines where drilling should occur. Within the seams worked at Kingshill Colliery there are three types of target that need to be considered before drilling a borehole:

Main access roadways Main access roadways and drifts are most likely to remain open. They were typically constructed of spaced steel arches, with the roof supported by transverse concrete or timber beams between them.

Maingate and tailgate roadways Maingate and tailgate roadways were those which flanked and provided access to longwall faces. It cannot be guaranteed that such access roadways are still open - supports may have been removed after the longwall face was worked out. It is more likely that maingate and tailgate roadways would have been left open in the case of advancing longwall faces (as in the case of Kingshill No. 1) than in the case of retreating longwall faces.

Goaf (collapsed longwall workings) and fractured strata above them After the roadways, the worked out seam is likely to remain the most permeable zone, even though it contains goaf. The goaf horizon will be dominated by intergranular flow, while fracture flow will dominate in the disturbed zone above. The potential advantage of drilling into goaf is that one avoids the direct 1-dimensional flow pathways that roadways represent; thus heat breakthrough in a well doublet is more likely to be slower. The main disadvantage is the limited capacity for abstracting large yields. While enhanced permeability could reasonably be expected in the goaf and in the fractured strata for several tens of metres above the worked seams, one should not automatically expect that the permeability would be large enough to sustain abstractions of several tens of L/s. Reinjection of such quantities of water into a porous goaf (as opposed to an open roadway) would be even more problematic.

3.4.3 Hydraulic Risks and Optimising Performance

Targets for Drilling For a potential production well, requiring large volumes of water, the preferred drilling target would be a main access roadway. If the disposal of thermally spent water involves reinjection wells, these

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should also preferably target main access roadways. In theory, injection wells are the hydraulic opposite of production wells. However, in reality, injection wells typically exhibit somewhat lower performance than production wells, such that more than one injection well may be required for each production well. If the natural mine-water levels are near the surface or even artesian – which is likely for the Hartwood and Allanton area – then we may have to inject water under excess pressure, which implies specialist construction and grouting techniques and pressure-testing.

Alternatively, it may be possible to avoid reinjecting the thermally spent water. The spent water could be treated by a passive minewater treatment facility, prior to discharge to a surface watercourse. The advantage of this would be avoiding the need to drill and maintain costly injection wells, and avoiding the risk of thermal feedback. It might also provide the added benefit of lowering minewater levels regionally and mitigating some of the negative impacts of surface mine-water discharge in the Allanton area. The main disadvantages would be the cost of constructing and operating a treatment plant, and the fact that pumping could gradually lower the water levels in the mine system, increasing pumping costs over time. The benefits of this design option over a reinjection doublet is discussed further in Chapter 5, and the potential design of any treatment plant is considered in Appendix A3.5.

Reduced system performance There are a number of reasons why performance of an injection well may deteriorate over time. Injection wells are more prone to clogging if particles are present in the water and they can promote bacterial biofilm growth on the well screen or borehole wall. Any contact between water and atmospheric oxygen prior to or during reinjection may increase the risk of iron and manganese oxi- hydroxide precipitation. Therefore, the operation of a production-injection doublet system must be a pressurised and sealed system to minimise contact between water and atmosphere to reduce the risk of chemical clogging. Because of these risks, more than one injection well may be required for each production well.

Thermal feedback Injecting thermally spent groundwater too close to where it is abstracted it can cause a short circuiting effect – thermal feedback or thermal breakthrough - where the cool reinjected water simply flows directly back to the production well causing a decrease in source temperature. This can compromise the efficiency of the system and even its long-term sustainability. Thus, care should be taken that the flow pathway between the production and injection well(s) should be as indirect and “diffuse” as possible, in order to decrease the speed, magnitude and risk of thermal breakthrough.

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To evaluate the risk of thermal breakthrough, various modelling approaches can be adopted. In this study, two simple, analytical models have been applied to each considered geothermal well doublet option to delimit two extreme possibilities (see Appendix A3.2):

• a 1-dimensional tunnel model which assumes a single mined roadway connection. • a 2-dimensional porous medium model which assumes a well doublet in a conventional porous aquifer.

The real behaviour of a well doublet in a mine is likely to fall between these two extremes – but there is a risk that it could approximate more closely to the 1-dimensional scenario, which predicts very rapid thermal breakthrough.

3.4.4 Minewater Chemistry The chemistry of minewater can be very unlike normal groundwater, largely because it has been exposed to sulphide minerals (and their secondary oxidation products) in the worked strata. The hydrochemistry of the water from Kingshill (and nearby Polkemmet) Colliery is discussed in depth in Appendix A3.2. The chemistry of the minewater is important for the sustainable operation of the geothermal system (avoiding problems with clogging, scaling or corrosion) and is also critical if the water is to be treated prior to disposal to a surface watercourse. Although the minewater chemistry can only be determined by pumping and sampling an existing shaft or exploratory borehole, it seems possible that water pumped from the deep (Woodmuir Smithy or Wilsontown Main) workings interconnected with Kingshill No. 1 Colliery may:

• Contain in the region of 10-70 mg/L iron, a few mg/L manganese and in excess of 1000 mg/L sulphate. The pH is likely to be circum-neutral .

• Be chemically reducing and anoxic, and may contain ammoniacal nitrogen and hydrogen sulphide.

• Deteriorate with initial pumping, as shallower minewater is drawn down-dip from the south, but should then improve slowly over the course of decades, as the system is flushed of pyrite weathering products.

Recent field and laboratory analyses Manual field readings of water / air temperature, pH, redox potential (Eh) and electrical conductivity (EC) have been taken from the Kingshill minewater surface discharge between 3rd November 2015 and 26th January 2016. In addition, three duplicate pairs of samples (six samples total) have been collected on 3rd November 2015, 2nd December 2015 and 6th January 2016, respectively. The

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sampling point was an emergence at 55.7952°N 3.8276°W (NGR 285514 657276) prior to entry into a council-run system of treatment ponds. The raw data from the field and laboratory measurements are provided in Appendix A3.3, and a full analysis of these measurements is provided in Appendix A3.4.

3.4.5 Drilling Techniques & Submersible Pump Installation The drilling of a geothermal well to depths potentially in excess of 300 m into the Wilsontown Main or Woodmuir Smithy coal seam workings is not a trivial undertaking. It will require a rotary drilling rig capable of drilling with sufficient verticality to encounter and penetrate a specific roadway of width c. 5 m. Potential contractors will not only have to demonstrate that they have the experience and equipment capable of constructing such a borehole, but also that they:

• have experience of drilling, and managing drilling fluids, in deep, mined Coal Measures strata; • are able to manage any issues arising from encountering methane risks while drilling; • are able to diligently manage potential artesian conditions and to ensure excellent grout integrity; • are capable of responsibly managing potentially contaminated mine-water returns during the drilling process. The drilling method will likely be a rotary method, which may involve a combination of drilling fluids. The crucial element will be ensuring sufficient precision and verticality to encounter a narrow mine roadway target at in excess of 300 m depth.

Casing materials will be selected to be compatible with expected minewater chemistry (see Appendices 3.2 - 3.4).

A carefully considered grouting program will be required, with sufficient annular clearance behind the casing to emplace a low permeability grout seal. Especially if artesian conditions, or excess pressure in a re-injection borehole, are anticipated (this will depend on the configuration of the design option selected – see Section 3.4) the grout integrity and strength will be especially important and will need to be demonstrated.

In addition to the technical requirements as detailed above, the drilling methodology will need to satisfy the relevant environmental legislation. Details on this and the licensing requirements and process are contained in Appendix A.2.

The production well will be equipped with an electrical submersible pump (ESP) at a depth well below the anticipated minimum pumping water level. The likely pump diameter will be either nominal 6 inch or 8 inch. The final pump selection will depend on:

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• The anticipated discharge (which will depend both on demand and anticipated sustainable minewater yield); • The anticipated pumping head, which cannot be finally known until a borehole has been test- pumped.

The diameter of the pump will constrain the diameter of the borehole above the level of pump emplacement (for example, an 8” pump will require a borehole diameter of at least 11-12”). Below the level of the pump, the borehole diameter can be narrower, resulting in cost savings.

Because injection boreholes do not require a production pump, they may be able to be drilled at a somewhat reduced diameter (although they will still need to be wide enough to ensure hydraulically efficient operation, the installation of one or more reinjection mains, and possibly a smaller diameter pump for back-pump/clearance purposes).

There is an argument for drilling a narrower diameter borehole as an exploration borehole, for sampling and test pumping purposes, prior to drilling a main production borehole. This adds considerable extra expense to the project, however. Depending on the option (Section 3.4 and Chapter 5) selected, such an exploration borehole might be converted to a re-injection borehole, or re-drilled to a full diameter production borehole.

3.4.6 Yield of a Mine vs Pumping Costs When designing a system of pumping boreholes, it should be remembered that their total discharge will be limited by at least two factors:

(i) the yield of each production borehole, which will be controlled by the hydraulic properties of the rocks and mine workings in the vicinity of the borehole and also by interference with nearby production and injection boreholes;

(ii) the hydraulic resource contained in the mine itself and the rate at which the mine as a whole is replenished by recharge.

It is not necessarily the case, therefore, that because one borehole can sustain a yield of, say, 40 L/s, the mine would necessarily yield a sustainable rate of 120 L/s if three boreholes were drilled.

Furthermore, there is a relationship between pumping water level and discharge rate, both for an individual borehole and the mine as a whole. Thus, for example, if one borehole produces 40 L/s, this may draw the minewater level down 40 m. If two boreholes produce 80 L/s, the minewater level may drop 170 m. While the total production rate has doubled, the pumping costs associated with production may have quadrupled (as the energy expended in pumping water up from greater depth

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will have increased). The figures cited above are examples only: the exact relationship between discharge and water level is not known and can only be established by a pumping test conducted on a real borehole. This is important to bear in mind when considering the drilling of additional production boreholes to expand the capacity of a geothermal system utilising minewater from a single mine.

3.5 OPTION APPRAISAL FOR GEOTHERMAL SYSTEM

Several locations within the Kingshill colliery for wells and surface discharge to a passive minewater treatment facility were assessed. Geo-Options 1 - 5 (Appendix A3.2 Geo-Options 1 – 5; A3.2 Annex Drawings GEO-1 – GEO-5) were based on a doublet minewater geothermal system with production and injection wells, whereas Geo-Options 6 – 8 (Appendix A3.2 Geo-Options 6 – 8; A3.2 Annex Drawings GEO-6 – GEO-8) incorporate a new passive minewater treatment facility adjacent to a production well. Many opportunities and constraints were taken into consideration to highlight the preferred options to proceed with specific system design and economics, including:

• Proximity to heat demand, i.e. consumers • Proximity to existing minewater treatment site • Available land area for development • Subsurface hydraulic connections of mines and subsequent modelling of thermal breakthrough • Subsurface hydraulic connections across faults • Complexities of directional drilling • Analysis of artesian conditions • Assessment of environmentally sensitive areas for drilling • Analysis of surface gradients for gravity flow through a potential passive mine-water treatment facility • Proximity to existing gas and electricity networks • Proximity to access roads • Potential environmental benefits to local communities

3.5.1 Modelling Thermal Breakthrough Five abstraction - heat exchange - reinjection (geothermal doublet) scenarios have been identified. A number of critical assumptions have been made to enable analytical modelling to be carried out.

For each modelled geothermal well doublet option (Appendix A3.2), a 1-dimensional direct roadway connection scenario (Rodriguez & Diaz, 2009) and a 2-dimensional porous medium well doublet

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scenario (Banks, 2009, 2011) were evaluated to effectively delimit possible extreme responses of the aquifer. The reality will be somewhere in between (and arguably closer to the 1D roadway model than the 2D porous medium model) and can only be simulated further by site-specific numerical models. Appendix 3.2 demonstrates the methodology and results for each scenario.

3.5.2 Options Ruled Out for Locating Production and Injection Wells / Surface Discharge Eight options for the installation of a geothermal well system have been considered. These are referred to as Geo-Options to avoid confusion with the District Heat Network (DHN) Options (Chapter 4) and Development Options (Chapter 5). Five of these involve geothermal well doublets, while the other three envision only production wells, coupled with passive minewater treatment and discharge to a surface watercourse. The eight scenarios are detailed in Appendix A3.2, and a consideration of passive minewater treatment is found in Appendix A3.5. Six of the eight options have been ruled out as being technically, environmentally and/or economically unfavourable. The remaining two favoured options are presented in Sections 3.4.3 and 3.4.4. These Geo-Options are then taken forward and integrated with the preferred DHN-Options in Chapter 5.

3.5.3 Geo-Option 3 (doublet system) Description: Both production and injection wells drilled (potentially c. 380 m deep) into the WRSM seam, north of the main E-W fault and in the southern part of the Hartwood Home Farm study area. Artesian head in workings could be c. 20 m (given a ground elevation of c. +180 m OD).

Geo-Option 3 is illustrated in Drawing 3.13.

1-D Discrete roadway model 2-D Porous medium well doublet model Pathway 1: L = 1732 m Pathway = 1245 m (direct) Breakthrough time = 5.0 days Breakthrough time = 5924 days (assuming Abstraction temperature after 10 years = 7.3°C thickness of porous zone = 30 m) Heat extracted from rock after 10 years = 61 Abstraction temperature after 10 years = 18°C kW Table 3.3: Flow pathway analysis for Geo-Option 3, assumes abstraction at 50 L/s and 18°C, reinjection at 7°C.

Pro Con Potentially artesian heads i.e. low pumping Environmental difficulties in drilling with costs at the production well. Artesian head may potentially artesian conditions. not be as strong as in the case of options 1 and 2, thus fewer problems with drilling and reinjection. Moderately long flow pathways separated by Likely need to reinject under pressure. fault.

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Pro Con Drilling sites not in environmentally sensitive Minewater resurgence is an existing river valley bottoms. environmental problem to the south of Allanton, raising the potential sensitivity of new workings in this area which do not address this issue.

Table 3.4: Advantages and disadvantages of Geo-Option 3

Geo-Option 3 was judged to be the optimal doublet system due (i) to it being within the Hartwood Home Farm study area, (ii) having a moderately long subsurface flow pathway, (iii) less strong artesian potential than Geo-Options 1 or 2 and (iv) being located away from the river. There is, however, a significant risk of rapid thermal breakthrough which will need to be evaluated with detailed numerical modelling at the next stage of feasibility study.

Geo-Option 3 is the option progressed as Development Option 2 (Chapter 5).

3.5.4 Geo-Option 6 (production well with passive minewater treatment facility) Description: Single production borehole to over c. 340 m depth (depending on ground elevation), into WRSM seam near Kingshill No. 1 colliery, or even from colliery shaft if still accessible (Coal Authority believe that the colliery shafts are sealed, but at present it is unknown how and at what depth). Passive minewater treatment facility on former colliery land, then discharge to a watercourse.

Geo-Option 6 is illustrated in Drawing 3.12.

Flow pathway analysis: None (no reinjection)

Pro Con Static water level likely to be within 10 m of Capital cost of constructing treatment works, surface, thus low pumping costs (although and its ongoing maintenance (though if passive, pumping head will probably be deeper). ongoing costs should be modest).

Abstraction from Woodmuir Smithy seam will Acquisition of an environmental liability decrease heads, and should (at least partially) (potentially polluting discharge). relieve uncontrolled overflows / waterlogging at Allanton. Thus, an environmental benefit and benefit to community.

Proper treatment system to be installed. Possible ongoing liability for uncontrolled outbursts of mine-water if pumping ceases in future.

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Pro Con

No costs associated with injection boreholes. Uncertainty regarding low measured No ongoing maintenance of reinjection temperature at existing discharge of 13.9 °C. boreholes.

Fewer issues with thermal breakthrough, thus There is some potential for drawing in MW yields should be sustainable over long progressively cooler water down dip with time - period. Potential heat extracted from 50 L/s (if thus reducing abstraction temperature such a yield can be sustained) with 11°C temp (insufficient data to quantify this possibility at drop = 2.3 MW. present).

Table 3.5: Advantages and disadvantages of Geo-Option 6

Geo-Option 6 was judged to be the optimal scenario for a passive minewater treatment facility due to its location in close proximity to the historic minewater lagoons and current minewater leakage and drainage ditch; plenty of brownfield space and old access roads.

Geo-Option 6 is the option progressed as Development Option 1 (Chapter 5).

3.5.5 Comparison of Favoured Options Of the two favoured options, Geo-Option 6 is regarded as the most technically favoured option. Despite the necessity to construct a passive minewater treatment system, it avoids the technical risks of Geo-Option 3, and provides added value to local communities (minewater treatment and potentially alleviation of minewater breakout issues).

The main risks associated with Geo-Option 3 would be related to

(i) Drilling, grouting and reinjecting into workings with a (potentially) 20 m artesian head and (ii) The significant risk of thermal feedback along mine roadways.

Artesian heads will make drilling and grouting rather challenging. If grout seals are inadequate, there is risk of leakage of contaminated minewater up the annulus to the surface, which could be difficult to control. Any boreholes would need to have a rigorous abandonment and sealing plan, in the event that the geothermal system ceases to operate in the future.

The comparative merits of the two options are considered further in Chapter 5, integrating the option appraisal from the DHN systems analysis.

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Chapter 4 – District Heating Network

4.1 INTRODUCTION

This chapter undertakes an analysis of the potential heat demand in the study area and a preliminary network analysis to identify target areas with potential for medium and longer term connection to a District Heating Network (DHN) powered by minewater geothermal energy. The preliminary network analysis was then refined into three alternative sizes of network for medium term development – ranging from the smallest network which connects part of Allanton only to a network which connects all of Allanton and Hartwood – taking into account the two preferred geothermal energy options. This process involved a detailed analysis of demand to establish peak demand and demand profile for each scenario, to enable the energy centre, thermal store and network to be appropriately sized, and the operating profile of the heat pump to be modelled. This provided the necessary level of detail to form the basis for the cost schedule and inform decisions about the network operating temperatures. In addition to modelling three alternate sizes of network for medium term development, the chapter also identifies a longer term opportunity for extending the network to Shotts, subject to identifying further heat sources to power the expanded network.

4.2 HEAT DEMAND ANALYSIS

4.2.1 Identifying Potential Demand The Scotland Heat Map was used to identify areas of heat demand in Hartwood and the surrounding area. It was evident from an early stage that the only locations within an accessible distance of a geothermal resource were Hartwood, Allanton and Shotts. Salsburgh was also considered within the scope of the study but the low heat density in the town, lack of underlying geothermal resource and distance from viable sources of geothermal energy do not imply a likely economic opportunity for connection. Of these settlements, Shotts is by far the largest and would therefore be likely to be a main target for heat supply over the longer term. Allanton is also a relatively good target area as it is closer to the JHI Hartwood Farm and has a reasonable property density, with the majority of properties being semi-detached 4-in-a-block.

The overall demand for each area can be seen in Table 4.1 below.

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Study Area Properties Total Heat Demand

Hartwood 83 1631 MWh

Allanton 567 9454 MWh

North Shotts 2328 38238 MWh

Table 4.1: Summary of study area heat demands

To the north-west of Shotts lies HMP Shotts, a large prison with a capacity for about 550 inmates. No heat demand data for the prison is available in the heat map, and an estimated demand per inmate was assigned using CIBSE energy benchmarks is therefore used. The exact number of inmates could not be confirmed and so the lower of the figures found – 528 inmates – was used giving an estimated yearly demand of 9,959 MWh. However, further research established that the prison has recently had its own CHP system installed, with further plans for wood biomass, and so would unlikely to connect.

4.2.2 Business as Usual Scenario The alternative business case to district heating is assumed to be the retention of gas supplies, where gas networks currently are present, or electricity, oil or solid fuel. This business as usual (BAU) assessment is important to model a heat sales price from district heating that is competitive and will compel the local community to agree to connect. For the purposes of modelling a competitive heat price the status quo case is modelled based on a gas supply.

The cost of heat from a gas boiler comprises the fuel costs (both fixed and variable costs from the supplier) as well as the cost of maintenance and replacement of the gas boiler. Council and Registered Social Landlord (RSL) tenants do not pay for the boiler replacement, whereas owner- occupiers will include this cost.

Typical unit costs for gas (Based on a monthly billing or pre-payment tariff) were obtained from a price comparison website in January 2016 and are listed below:

Green Star British Gas Scottish SSE E.On Energy Power Unit Cost p/kWh 2.5 4.0 3.4 4.1 4.2 Standing Charge p/day 32.8 26.0 20.6 25.8 31.5 Standing Charge p/kWh 1.0 0.8 0.6 0.8 0.9 corrected to fuel use Fuel supply tariff p/kWh 3.4 4.8 4.0 4.8 5.1 Table 4.2: Published fuel costs from price comparison website.

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DECC also publish average domestic gas prices to customers and data for the third quarter in 2015 shows an average gas tariff of 4.9 p/kWh. This figure will be used as the basis for the alternative business case. The gross boiler efficiency of an existing boiler is expected to be 80% and therefore the unit cost of heat is calculated to be 6.125 p/kWh. The cost of boiler replacement can be calculated as a cost per kWh of heat used assuming a typical annual use of heat of 12,500 kWh and a boiler replacement cost1 of £2000 on a 15 year replacement lifecycle equates to a unit cost of 1.07 p/kWh.

The total unit cost of heat in the alternative business case is therefore:

• 7.19 p/kWh to owner occupiers; and • 6.13 p/kWh to Council/RSL tenants

4.2.3 Qualitative Evaluation of Target Areas The three target areas are made up primarily of residential properties of mixed ownership. The tenure layer of the Scottish Heat Map shown in Drawing 4.1 illustrates the percentage of properties in an area that are socially rented. Darker shades represent higher percentages and it can be seen that Allanton and some parts of North Shotts have relatively high numbers of socially rented properties.

While exact figures for the proportion of socially rented properties can be extracted from the Heat Map Data for each area, more detailed and up to date information has been obtained from North Lanarkshire Council to ensure that the correct properties are focused on in the analysis.

Hartwood This is the least populous of the three potential target areas and consists of 83 private residential properties, none of which are connected to the gas grid. Although off-grid properties often have higher heating costs – therefore increasing the saving potential of a DHN – guaranteeing connection uptake from all private properties is usually difficult.

However, during consultations with the local residents, high levels of community engagement and interest were shown in the project. This would improve the likelihood of connecting all properties to the network, and hence the chance of there being enough demand to justify the installation costs.

Allanton This small village that lies to the south of Hartwood and consists of 567 properties, of which approximately 40% are council owned. There is also a small primary school on the eastern side

1 Including installation of the boiler

Fortissat Community Minewater Geothermal Energy District Heating Network 34

which would help to diversify the network load, and – due to it being a council owned building – could be considered a very likely connection, therefore helping to increase the overall demand on the proposed network.

North Shotts This is by far the largest of the three study areas and has a high proportion of socially rented properties; making it a very suitable target for a district heating network. Shotts also contains a large High School and supermarket, which could help to provide stable sources of demand to balance out the heavily residential demand profile on the network.

A network supplying Shotts from an energy centre near Hartwood would at some point have to cross the Shotts Railway line. This can be a very expensive procedure as Network Rail has been known to charge in the region of £20,000 - £30,000 p.a. at an interest rate of RPI + 5% for permission to build across – either under or over – one of their lines. However, these charges may not be applied – project team research with Aberdeen Heat and Power established that no charges are incurred by the heat network in Aberdeen which crosses a railway line.

Salsburgh Salsburgh is an off-gas-grid town to the north-west of Hartwood Home Farm, with approximately 41% Council owned properties. Salsburgh’s potential in this project is severely limited by the high CAPEX costs associated with the large length of pipe – approximately 4500m – that would be required to connect it to the rest of the geothermal network. To evaluate its potential as a standalone scheme, the network has been analysed with and without this large section of pipe.

4.2.4 Heating Network and Demand Analysis The District Heating Opportunity Assessment Tool (DHOAT) developed by Ramboll for the Scottish Government was used to analyse the heat map data and preliminary network designs. This tool provides clear indications of what the peak and annual demands would be, as well as a preliminary set of KPI data including Linear Heat Density2 (LHD) and indicative network CAPEX and OPEX costs.

The outputs of each scenario were compared against one another to help determine which would be most suitable for a heating network; this decision is based on both the technical figures derived from this modelling as well as knowledge on the local property types, potential connection issues and any other commercial or construction hurdles.

2 LHD is the ratio of demand per unit pipe length and provides an early stage indication of whether the network has enough demand to justify the initial capital costs of pipe installation

Fortissat Community Minewater Geothermal Energy District Heating Network 35

4.3 PRELIMINARY NETWORK ANALYSIS

North Lanarkshire Council (NLC) have a duty under the Energy Efficiency Standard for Social Housing (EESSH) to improve the overall energy efficiency of social housing by 2020. To achieve this, a minimum energy rating was introduced for gas or electric heated social rented homes. Over the next 5 years, NLC will focus on the homes that do not already meet this standard.

North Lanarkshire Council’s Housing Department, as project partner with responsibility for council tenants, provided an initial focus on council owned properties for this project. In addition, the Council would be a key stakeholder for connections to a network and building fabric improvements; therefore the networks were designed around areas of high council property density. Two scenarios were analysed for each network; one where only council properties were connected and one where all properties in that area were connected. The effects of this will be discussed fully in Section 4.3.

4.3.1 Preliminary Network Layouts

HW011 - Hartwood This network would supply heat to all of the properties in Hartwood. Its proximity to JHI owned land and therefore the proposed well locations would reduce the length of connecting pipe required and therefore the overall network costs.

HW021 – Allanton Council Only This option would supply all of the existing council housing and the local Primary School in Allanton, to the South of Hartwood. As discussed above, these properties are fairly spread out so do not represent a particularly high demand density.

HW022 – Allanton All Residential This option is the parallel analysis of HW021 that connects to all available properties, not just council owned ones. This more than doubles the number of connections for the same length of pipe, which would have a similarly large effect on the LHD.

HW031 – North Shotts Council Only Although Shotts is the largest area of demand, its council properties are also very spread out, once again resulting in a low LHD. The area also includes a fairly large supermarket, a Primary School, and a large High School that will help to raise demand and provide a more diverse demand profile.

Fortissat Community Minewater Geothermal Energy District Heating Network 36

HW032 – North Shotts all properties This variation to the North Shotts network would connect all the properties that are in reach of the network that would be designed solely for the council properties. As a lot of the buildings are multi- residence, connecting these extra properties would not incur a huge added costs over the work already suggested for option HW031. This option would require a similar length of pipe to supply a much greater demand, raising the LHD significantly.

HW041 – Shotts Council Only & Shotts Prison These final variations on the Shotts network analysed the effect of connecting Shotts Prison. However it was discovered that the prison has its own CHP system and so no further analysis was carried out beyond this initial opportunity model.

HW042 – Shotts All Residential & Shotts Prison Again, this option is a variation on HW041 that includes all of the available properties. However as mentioned, the potential for connection to the prison is very unlikely so will not be analysed any further than this stage.

HW051 – Salsburgh The proposed Salsburgh network can be seen in the Drawing 4.2. This includes connections to all the properties that are in reach of the network that would be designed solely for the council properties. As discussed, the network will be analysed with and without the long connection that stems from the Northern end of the Hartwood section. The analysis without it relates to network HW052 in Table 4.3.

4.3.2 Modelling Results The linear heat density (LHD) offers a useful rule of thumb to assess the potential economic viability of a network, and while networks with low LHDs can be made to work commercially, their viability is sensitive to factors such as the heat sales price and finance costs and they are likely to have to operate on a low IRR thus potentially reducing the finance options available. Where the prevailing heat source is not gas then there is a greater carbon and cost benefit to consumers to switch to district heating and the heat supply cost to consumers can increase while remaining competitive with oil or other alternatives.

The scenario that has the highest LHD is the extended North Shotts network that theoretically connects to the Prison, which as previously mentioned is highly unlikely due to their recently installed CHP and wood biomass aspirations. Despite this option not being likely, its analysis does show the effect that one large source of demand can have on a network’s performance, and should

Fortissat Community Minewater Geothermal Energy District Heating Network 37

be kept in mind as any large future developments in the area could offer up large demand and similar performance benefits for the network.

Some of the council housing in both Shotts and Allanton has been sold off, with the remaining properties now interspersed with owner-occupiers. This results in a more widely distributed demand, requiring longer lengths of pipe per property, hence a lower LHD in a scenario where only Council properties are connected.

A side by side comparison of the various scenarios can be seen in Table 4.3 and clearly shows the negative performance impacts that result from only connecting council owned properties. When comparing the model results for Allanton – projects HW021 and HW022 – it can be seen that connecting only council properties results in a LHD that is almost three times lower than that of the mixed tenure network. For all other options the decrease is approximately half. This would suggest that if a network in this area is to have any chance of being economically feasible, it would have to supply private properties as well as Council-owned ones.

Short Name HW011 HW021 HW022 HW031 HW032 HW041 HW042 HW051 HW052 Reference

DHN Design Alone Option - Only Only Tenure Tenure Shotts & Shotts & Allanton: Allanton: Salsburgh Hartwood Salsburgh: Stand Council Only Prison: Mixed Shotts: Mixed Mixed Tenure Prison: Council Shotts: Council

Proposed Water Water Water Water Water Water Water Water Supply Asset ------System Geothermal Geothermal Geothermal Geothermal Geothermal Geothermal Geothermal Geothermal Stand Alone Mine Mine Mine Mine Mine Mine Mine Mine

Technical Parameters Network 1,308 4,535 4,535 12,937 12,937 13,300 13,300 9,030 4,565 Length [m]

Total Heat Demand 1,600 2,600 6,700 9,600 24,100 20,200 34,800 8,400 8,400 [MWh]

Peak Demand 0.8 1.3 3.3 4.8 11.7 8.7 15.6 4.2 4.2 (MW)

Primary Supply Asset 0.192 0.312 0.804 1.152 2.892 2.424 4.176 1.008 1.008 Capacity (MW)

Fortissat Community Minewater Geothermal Energy District Heating Network 38

Short Name HW011 HW021 HW022 HW031 HW032 HW041 HW042 HW051 HW052 Reference

No. of 83 152 371 687 1527 727 1567 445 445 Connections

Linear Heat Density 1.25 0.56 1.47 0.74 1.87 1.52 2.61 0.93 1.83 MWh/m

Required Source Flow 6.9 9.5 25.0 49.1 108.5 82.7 142.1 36.0 36.0 Rate (l/s)

Potential Revenue Weighted Average Heat Selling Price £63 £60 £61 £62 £60 £31 £43 £62 £62 to Customers £/MWh

Revenue £101k £155k £409k £596k £1,457k £636k £1,497k £520k £520k

Table 4.3: Summary of technical parameters and potential revenue for each of the nine heat supply options.

4.3.3 Land Ownership An important consideration will be the location and route of the energy centre and district heating network respectively. The acceptability of locating the energy centre and production and/or reinjection wells as well as the cost of wayleaves and civils cost will be influenced by the land use and ownership. The James Hutton Institute own a large portion of land around the Hartwood area – as shown in Drawing 1.2 – which is a consideration for any network to be proposed there as it could guarantee an area for the energy centre and potentially the production and/or re-injection wells.

4.4 PRELIMINARY SCENARIO APPRAISAL

While a high level analysis of several network scenarios was useful in the initial stages of the project to outline the overall scope of demand potential, a detailed look into the more feasible networks was required to meet the final project requirements and ensure the results from any financial analysis and other modelling were as accurate as possible. The network options were therefore narrowed down based on their KPI (as mentioned in Section 4.3), how their capacity matched the geothermal resource and other non-technical factors.

Fortissat Community Minewater Geothermal Energy District Heating Network 39

4.4.1 Scenario Flow Requirements To provide an initial estimate of the well requirements for each scenario, outputs from the early stage modelling were converted into required heat pump capacities and hence required flow rates.

A diversification3 factor of 0.6 was used for all scenarios and the Heat Pump was assumed to provide 45% of this. The table below was constructed using the following equation based on a coefficient of performance (COP) of 3 and a temperature drop of 5°C.

�� − 1 � × ! �� = �! ∙ ∆�

Total Required Flow Rate Annual Undiversified Diversified Heat Pump DHN Design Option (L/s), Demand Peak (MW) Peak (MW) Output COP = 3 (MWh) (MW)

Hartwood 1600 0.8 0.48 0.22 6.9

Allanton: Council Only 2500 1.1 0.66 0.30 9.5

Allanton: Mixed Tenure 6000 2.9 1.74 0.78 25.0

Shotts: Council Only 11300 5.7 3.42 1.54 49.1

Shotts: Mixed Tenure 25700 12.6 7.56 3.40 108.5

Shotts & Prison: Council Only 21900 9.6 5.76 2.59 82.7

Shotts & Prison: Mixed Tenure 36300 16.5 9.9 4.46 142.1

Salsburgh 8400 4.2 2.5 1.13 36.0

Salsburgh: Stand-Alone 8400 4.2 2.5 1.13 36.0

Table 4.4: Estimates of required mine-water flow rates for heat pumps at 45% of the diversified peak.

4.4.2 Determining Geothermal Heating Potential Whereas a traditional heat network would have its extent defined either by choice or by available demand, the extent and capacity of a geothermal based network is mostly defined by the heating potential of the target resource. This is determined by both the temperature – which influences the achievable COP of the heat pump – and extraction flow rates from the resource.

Initial research from the geology members of the project (Chapter 3) revealed that the target mine workings are under artesian conditions, resulting in an overflow from an old well shaft close to Allanton of approximately 18l/s. Further to this, when Kingshill Colliery No.1 was previously being pumped to prevent overflow, it was at a flow rate of 41.7 l/s for several years. These figures were

3 Diversity is a factor that is applied to reduce the overall peak to account for the timing variations for when a large number of properties call for heat.

Fortissat Community Minewater Geothermal Energy District Heating Network 40

used to calculate a range of heat production rates, which can be seen in Table 4.4. A temperature drop of 5°C was assumed and values calculated using the following equation:

� ∙ �! ∙ ∆� ∙ �� = ! �� − 1

Heat Output (kW) for Varying Flow Rate & COP

Abstraction Flow Rate From Well (l/s) COP 10 15 20 25 30 35 40 45 50

2.0 418 627 836 1045 1254 1463 1672 1881 2090

2.5 348 523 697 871 1045 1219 1393 1568 1742

3.0 314 470 627 784 941 1097 1254 1411 1568

3.5 293 439 585 732 878 1024 1170 1317 1463

Table 4.5: Indicative heat pump outputs in kW for various flow rates and COP values.

Upon comparison of these initial estimates with the required flow rates and heat demand values in Table 4.5 it can be seen that there is likely to be enough flow to supply the smaller networks proposed at Hartwood and Allanton. In theory there may also be enough for a network in North Shotts supplying only Council properties. However, as was discussed in Section 4.3.2; for the Shotts proposals to be economically viable, they would need to connect to as many properties as possible, therefore increasing the network demand and required source flow rate to over 100 litres per second which is not considered to be a sustainable abstraction rate from a single borehole and therefore raises the capital costs and risk profile.

Figure 4.1 uses a load duration curve to illustrate that one geothermal production well producing up to 45 L/s can only provide a small proportion of the annual Shotts heat demand (blue area). It is estimated that three geothermal production wells would be required to provide enough heat for a Shotts district heating network. This should be explored in future analysis with a view of expanding the district heating network to Shotts, but the required flow rates from the geothermal resource may not be achievable (see Section 3.4.6.). Once the demonstrator minewater geothermal project has been proved, this may provide evidence that the mines can sustain additional wells with higher abstractions to allow expansion of the network to Shotts.

Fortissat Community Minewater Geothermal Energy District Heating Network 41

Load Duration Curve - Shotts

9 Shotts - Thermal Store and 8 Backup Boiler 7 Shotts - 1.4 MW WSHP

Peak heat demand (MWh) 2

0 1 284 567 850 1133 1416 1699 1982 2265 2548 2831 3114 3397 3680 3963 4246 4529 4812 5095 5378 5661 5944 6227 6510 6793 7076 7359 7642 7925 8208 8491 Hours exceeding total heat demand

Figure 4.1: Shotts district heating load duration curve showing heat provided from one geothermal production well in blue, and the heat that would need to be provided from additional heat sources in red.

4.4.3 Re-Evaluation of Project Extent

North Shotts Due to the uncertainty around achieving flows above the previously extracted rates the network supplying North Shotts would probably be too large a network for the geothermal resource being targeted. As the largest study area in the project, its associated capital costs were estimated to be as much as £34m, compounding the financial risks of the well not meeting the required production rates. Because of these factors, Shotts was not considered as a final design option and was not included in any further analysis. However this study has shown that North Shotts is a potentially economically viable location for a district heating network with alternative or complementary renewable heat sources to the minewater geothermal resource.

Salsburgh The network up to Salsburgh was analysed including all properties and with the full length of pipe required to connect it indicated a LHD of 0.97. This would suggest that it is not a viable network option for this scenario as the heat sales could not be enough to cover the high CAPEX costs of installation. Added to this, the heat loss in such a long section of pipe would be fairly significant,

Fortissat Community Minewater Geothermal Energy District Heating Network 42

further increasing the running costs of the network. For these reasons, Salsburgh was not considered as a final option for more detailed analysis although it should be noted that as a network which was able to secure its own nearby supply (from a non-geothermal resource), it has significantly more potential.

Minimum Network Extent As there are high CAPEX costs associated with both the geothermal well and the DHN, a very small network is unlikely to provide enough revenue to pay these back over a feasible timescale. The smallest of the scenarios previously analysed was the network at Hartwood. This would only provide heat to 83 properties, none of which are council owned; therefore excluding NLC as a potential project partner. Despite the fact that Hartwood is not on the national gas grid – and therefore likely has more expensive heating costs – this added value was deemed too small to overcome the other large barriers, therefore Hartwood would not be considered for a network on its own, only as part of a larger network including Allanton.

Target Property Types As discussed in Section 4.2.2, networks that only connect to council housing would tend to perform poorly due to lack of demand relative to the size (and cost) of the network. The scenarios taken forward into further analysis were designed on the assumption that all properties, private and council owned would be connected.

4.5 FINAL NETWORK DESIGN

4.5.1 Energy Centre Location Typically in district heating design, it is good practice that the energy centre should be located as close to the demand as possible to minimise the heat losses and costs associated with long lengths of high capacity insulated transmission pipe. However, due to the high iron content of the water in the target mines of this project, it is desirable to extract heat as close to the production well as possible to minimise the risk of exposure to oxygen and hence fouling of the equipment.

In a situation where the production well is not located close to the heat demand, this creates a set of opposing requirements. To meet both of them, the systems have been designed with an intermediate section of pipe that hydraulically separates the energy centre from the well by extracting heat at the well head and transporting it via this loop of clean water to the energy centre.

Fortissat Community Minewater Geothermal Energy District Heating Network 43

Option 1 Of the two most suitable production wells, the closest to Allanton is Option 1, located at the site of the old Kingshill Colliery No.1 mine-shaft. The energy centre for the two potential Allanton networks (Networks A and B) would be located on the outskirts of the town as shown in Drawing 4.4 with an interconnection loop of 650 m to the production well. It should be noted that neither the production well or Energy Centre are located on JHI’s land in this options.

Option 2 For Network C supplying both Allanton and Hartwood, the energy centre would be best located equal distances from either source of heat demand to reduce heat losses. There is an area of JHI owned land that is ideally suited for this, just off Hartwood Road between the two villages as shown in Drawing 4.4. This makes Option 2 the most suitable for this network as it is located just 450m away, also on JHI’s land. It should be noted at this point that Option 1 is also compatible with Network C.

4.5.2 Final Network Design To allow for some variation in the final analysis, networks were designed for three different sizes of system. The results of these would then be compared to determine the most economical scale for the district heating scheme. The options can be seen in Drawing 4.5 and Drawing 4.6 are described below.

Network A This is the smallest network proposed, located in the West side of Allanton and connecting to all houses located within the extent of the council owned properties.

Network B This proposes a larger network in Allanton that supplies the same properties as Network A, but also includes an extension to connect the Primary School and properties over to the East.

Networks A and B are displayed in Drawing 4.5.

Network C This option is the largest of the proposed schemes and would supply all properties in Hartwood as well as the majority of properties in Allanton through a common network.

Network C is displayed in Drawing 4.6.

Fortissat Community Minewater Geothermal Energy District Heating Network 44

4.5.3 Matching Demand to Supply As discussed in Section 4.3.2. the heat demand must be proportionate to the potential heat supplied from the geothermal system. Given the demonstrator status of the proposed project only one production well is suggested in each system, providing a maximum of 45 L/s of minewater. As Figure 4.1 illustrated how Shotts can be ruled out at this stage due to heat demand being too high, Figure 4.2 below shows how Network C can be “ruled-in” as an optimal heat market for a single minewater geothermal production well.

Load Duration Curve - Network C

3 Network C - Thermal Store and Backup Boiler 2.5 Network C - 1.4 MW WSHP

1.5

1 Peak heat demand (MWh) 0.5

0 1 284 567 850 1133 1416 1699 1982 2265 2548 2831 3114 3397 3680 3963 4246 4529 4812 5095 5378 5661 5944 6227 6510 6793 7076 7359 7642 7925 8208 8491 Hours exceeding total heat demand

Figure 4.2: Network C (Allanton and Hartwood) district heating load duration curve showing heat provided from one geothermal production well in blue, and the heat provided from the thermal store and back-up boiler.

4.5.4 Detailed Analysis of Demand Upon finalisation of the network layouts, the heat map data for the properties to be supplied was analysed to determine the peak demand for each scenario as well as the demand profiles. This enabled the energy centre to be correctly designed to meet the network demands without being oversized. The daily undiversified peak demands for Network C can be seen in Figure 4.2. These profiles are simply the sum of all individual properties and so represent a very high peak.

Fortissat Community Minewater Geothermal Energy District Heating Network 45

Figure 4.3: Peak daily demand profiles for Network C.

Diversification of Demand Profiles Due to the fact that not all individual property peaks will occur at exactly the same time, the demand profiles must be diversified to prevent oversizing the system. As the number of properties on a network increases, the diversity also increases. This leads to a significant reduction in the peak demand seen at the energy centre.

Total Diversified Average Peak Total Linear Heat Annual Peak Property Network Demand Network Density Demand Demand Demand (MW) Length (m) (MWh/m) (MWh) (MW) (kWh)

A 3860 2.79 1.45 11767 1730 2.23

B 5713 4.48 2.33 12439 3328 1.72

C 9670 8.38 4.36 15250 6175 1.57

Table 4.6: Technical parameters of network options.

The energy centres and heat pumps were sized based on this diversified peak to ensure that the top- up boilers and overall plant capacity could always meet the entire network demand.

It should be noted that the peaks visible in Figure 4.4 are lower than the overall diversified peak demand as it is based on a monthly average, which will be lower as the peak will not be reached every day of a month.

Fortissat Community Minewater Geothermal Energy District Heating Network 46

Figure 4.4: Yearly diversified demand profile for average day in month, Network C.

4.5.5 Sizing Network The pipe sizes and hence costs for the proposed networks were determined using Ramboll’s thermal and hydraulic modelling software, System Rørnet. The heat demands from individual buildings were grouped, then diversified and applied to nodes on the main branches of the network. This simplification has very little effect on the end results, but speeds up analysis by not sizing each individual property connection.

The software calculates the appropriate diameter for each section of pipe based on the demand on its nodes. This generates a pipe schedule that shows total lengths required of each pipe size and enables accurate heat losses, pressure drops and costs to be determined for each network option and temperature scenario.

4.6 ENERGY CENTRE DESIGN

4.6.1 Heating System Overview The water to be extracted from the mines below Allanton is expected to have a temperature of about 18 °C which necessitates a heat pump based system.

Heat will be extracted from the minewater using a heat pump and upgraded to the required network flow temperature, covered further in Section 4.6.2.

Fortissat Community Minewater Geothermal Energy District Heating Network 47

The system will require back up gas boilers that meet the full output capacity of the system, both to meet peak demands and to cover for any down-time that the heat pump may experience.

HEAT Well Head EXCHANGER Energy Centre

Heat FILTER Pump Thermal Store

Passive Water Treatment or Re- Back Up Injection Well Gas Boilers

Figure 4.5: Indicative energy centre block diagram for all scenarios. Exact operating conditions such as flow rates, temperatures and outputs will vary.

4.6.2 Network Operating Conditions Two network scenarios have been analysed: a low temperature and a high temperature system. The low temperature network could operate on 75/45 flow and return temperatures, resulting in a temperature raise of 57°C, and the high temperature network will operate on 85/60 flow and return temperatures, requiring a temperature raise of 67°C (these scenarios are highlighted in bold in the table below). These different temperature raises affect the COP that a heat pump can achieve and in turn the cost of heat production.

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COP at Flow Indicative Cost of Heat for Varying Electricity Price (p/kWh) Temperature Raise (°C) Temp 6 8 10 12 14

52 3.46 1.73 2.31 2.89 3.47 4.05

57 (low temperature 75/45) 3.06 1.96 2.61 3.27 3.92 4.57

62 2.70 2.23 2.97 3.71 4.45 5.19

67 (high temperature 85/60) 2.36 2.54 3.39 4.24 5.09 5.93

72 2.05 2.93 3.91 4.89 5.86 6.84

Table 4.7: Indicative cost of heat production for various values of temperature raise. COP data from supplier.

The network operating temperatures can also affect other aspects of the energy centre design, network capacity and heat losses and associated costs. Lower network temperatures will result in lower heat losses from the pipe network. A wide delta-T reduces the flow rate in the network and therefore offers lower pipe diameters.

To be eligible for the renewable heat incentive (RHI) heat pumps must perform with a COP of 2.9 or greater. In the High Temperature scenarios this is not achieved and the sensitivity of this has been tested in the financial model. It is likely that qualification as a Deep Geothermal heat source and the resultant RHI tariff will influence the economic viability of the project (see Chapter 7).

The most significant impact of operating a low temperature network is the way that it affects customers. This is further discussed in Section 4.6.4 below.

Ruling-out of High Temperature Network The results of the financial analysis prepared to inform Chapter 6 indicate that the financial performance of all three network designs is similar when deploying a high temperature and low temperature network. The higher capital costs of the low temperature system are off-set by the higher operating costs of the high temperature system for a network of this (relatively small) size.

In addition, the COP of the heat pump’s performance in the high temperature network is consistently below 2.9 (see Table 4.8), which is the minimum required COP to be eligible for the RHI. Without the RHI the project is not economically viable.

The high temperature network option is therefore ruled out at this stage.

It is possible that bespoke heat pumps could achieve high temperatures whilst performing above a 2.9 COP. If so, this could be explored in the next stage of design.

Fortissat Community Minewater Geothermal Energy District Heating Network 49

4.6.3 Reducing Fouling Risk The risk of fouling caused by iron precipitation will be minimised by installing an additional brazed plate heat exchanger right at the well head, reducing the length of pipe minewater travels through and hence the likelihood of a leak. The heat will be transferred into a secondary source loop of clean water that will then act as the cold side of the heat exchanger, eliminating any contact between the minewater and more expensive plant equipment.

4.6.4 Building Requirements Traditional gas central heating systems are designed to operate on flow/return temperatures of 82/71, which does not provide a high enough temperature drop for either a low temperature or high temperature DHN to be effective. For a property to maintain the same level of thermal comfort while reducing the mean temperature of the radiators, extra insulation is required or larger surface area emitters (radiators) are required.

Whatever network temperature is selected, the thermal comfort in buildings must be maintained. If network temperatures are reduced to optimise the network and heat generation efficiency then the investment to allow compatibility of connecting buildings to these temperatures must be included in the financial modelling for the project. Analysis of these costs can be found in Appendix A4.

4.6.5 Thermal Store Sizing The thermal stores for each scenario design have been sized to hold 3 hours’ worth of the peak heat pump output. This is on the higher side of some guidelines and estimates; however this larger capacity will allow the heat pump to cover a higher proportion of the peak network demand, hence reducing the need for additional gas boiler top-up.

The store’s physical size requirements are based not only on the capacity desired, but the temperature difference at which the water can be stored. This should ideally be the same as the difference between the network flow and return temperatures, provided the store is thoroughly insulated. This required size was calculated on a per MW basis, to be applied to all scenarios.

Fortissat Community Minewater Geothermal Energy District Heating Network 50

� � = , �ℎ�� = 1��×3ℎ��×3600!∙!!!!, �! = 4.18!"/!"∙°! �! ∙ ∆�

Heat Pump Output Store Volume(m3): LT, Store Volume(m3): HT, Network (kW) ∆T=30C ∆T=25C

A 700 60 72

B 1000 86 103

C 2000 172 206

Table 4.8: Required volume of thermal store for low and high temperature networks.

4.6.6 Heat Pump Operating Profile An excel model was created to determine the operating profile of the heat pump for each network option. This was done to provide detailed operating costs as well as a profile that RHI payments could be applied to in the financial analysis.

The main operating cost for a heat pump consists of the electricity used. Due to the tariff-based structure that many electricity providers operate on, this can vary largely depending on what time of day the heat pump is operating.

The benefit of using a heat pump along with a large thermal store is that the fuel costs can be minimised by charging the thermal store during off-peak times while electricity is cheaper, then turning off the heat pump during peak times and using the stored energy to cover the gap.

Electricity Tariffs The main variation in electricity price for non-domestic customers comes from the Distribution Use of Service (DUoS) charges. These are shown for the local Distribution Network Operator (DNO) in Table 4.9:

Charging Tariffs High Tariff Medium Tariff Low Tariff

Charge (p/kWh) 7.73 0.42 0.02

09:00 - 16:00 00.00 - 09.00 Time Band 16:00 to 19:00 19:00 - 20:30 20.30 - 24.00

Table 4.9: DUoS time bands and charges for high voltage connection with Scottish Power Energy Networks, assumed to be half-hourly metered.

It should be noted that these charges are additive to the standard electricity prices. This base price was taken as an average over the two most recent quarters from the DECC quarterly non-domestic fuel prices for the appropriate electricity consumption bands as 10.47 p/kWh.

Fortissat Community Minewater Geothermal Energy District Heating Network 51

Cost of Electricity (p/kWh) Size of Consumer (MWh) Q1 - 2015 Q2 - 2015

0-20 13.90 13.41

20-499 12.35 12.10

500-1999 10.98 10.82

2000-19999 10.08 9.99

20000-69999 9.73 9.84

70000-150000 9.56 9.55

150000+ 9.16 9.13

Average 10.62 10.46

Table 4.10: DECC quarterly non-domestic electricity prices. Averaged values shown in bold.

This base electricity price plus the DUoS charge results in an energy cost of 18.2 p/kWh and – with reference to the process used in Table 4.7 – an equivalent cost of heat produced during peak times of approximately 6 p/kWh, compared to approximately 3.4 p/kWh during off-peak times.

Heat Pump Model The excel model created was based around the premise of avoiding heat pump operation during the peak time for electricity rates. The technical parameters of each scenario such as the thermal store size and heat pump capacity were used to determine a daily operating profile, an example of which can be seen in Figure 4.6.

As previously mentioned, the initial comparison of peak time heat pump operation and heat from gas boilers did not include the RHI. This was due to several factors. Firstly, the future of the RHI was somewhat uncertain at the time of the model’s construction – government budget announcements were pending – and secondly, it was deemed beneficial for the modelling that the thermal store was completely emptied at least once a day, thereby utilising the cheaper heat generated during off peak times.

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Figure 4.6: Heat pump modelling output for February of network option 1A – breakdown of heat utilised.

As shown in Figure 4.6, the heat pump is running at full capacity overnight to charge the store, which is then partially depleted during the morning peak. The heat pump will then continue running at peak output during the afternoon to ensure that the thermal store is as full as possible and able to provide a large portion of the evening peak demand while the heat pumps are off.

4.6.7 Pressure Losses and Distribution Pumps The pressure losses for each system were calculated as part of the System Rørnet analysis. The required hydraulic power was also generated in this analysis then the pump power calculated through use of the total pump efficiency. This was estimated to be 65% based on the efficiency of the pumps recommended in the Grundfos online sizing tool.

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Hydraulic Pump Network Network Total Network Power Power Total Power Temperature Flow Rate Pressure Option Required (65% Consumption Scenario (l/s) Loss (kPa) (kW) efficient)

A 11.6 265 5.1 7.8 3138 Low B 18.6 375 8.5 13.1 5249 Temperature C 34.8 612 21.1 32.5 12997

A 13.9 191 6.0 9.2 3692 High B 22.3 368 10.0 15.4 6154 Temperature C 41.7 549 28.2 43.4 17372

Table 4.11: Network pressure losses, pumping power and annual power consumption.

The pumps were assumed to run for approximately 400 Equivalent Full Load Hours (EFLH), giving the annual power consumption. This is notably lower than the heat pumps’ EFLH as the relationship between flow and pump power is cubic; i.e. a pump running at 50% flow will be using just 12.5% of its max rated power.

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Chapter 5 – Development Options

5.1 INTRODUCTION

This chapter presents the Development Options which integrate the geothermal system design options appraisal (Chapter 3 and Appendix A3.2) and district heating network (DHN) design options appraisal (Chapter 4). Two alternative design options are presented, taking into account all subsurface and surface factors considered. The advantages and disadvantages of the two options – one proposing a passive treatment system, and the other proposing reinjection (with alternative locations for the production wells) – are compiled to compare the options.

This chapter also presents the risk assessment for the project, the opportunities, and a carbon audit which estimates the reduction in carbon emissions from the geothermal energy district heating network against business as usual.

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5.2 OPTION 1 – ‘PREFERRED’

Figure 5.1: Illustrative diagram of passive minewater treatment facility.

Option 1 is shown in Drawing 5.1.

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5.3 OPTION 2 – ‘ALTERNATIVE’

Figure 5.2: Illustrative diagram of doublet system with production and injection well(s).

Option 2 is shown in Drawing 5.2.

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5.4 OPTIONS SUMMARY TABLE

The options are outlined in Table 5.1:

Preferred Design Geothermal System District Heat Network Option

Option 1A Production well with passive Network A: minewater treatment facility Allanton West only

Option 1B Production well with passive Network B: minewater treatment facility Allanton West and East

Option 1C Production well with passive Network C: minewater treatment facility Allanton West and East and Hartwood

Option 2 Production well with reinjection Network C: wells for minewater disposal Allanton West and East and Hartwood

Table 5.1: Summary table of minewater geothermal DHN development options.

5.5 OPTION COMPARISON – PASSIVE TREATMENT VS REINJECTION

There are advantages and disadvantages with both the Development Options under consideration, and Table 5.2 below, while not exhaustive, seeks to highlight the key considerations which have been identified at this stage in the process:

Theme Option 1 – Passive Treatment Option 2 – Reinjection

Advantages Advantages Production well and passive Production well and injection wells are treatment system are within the land within the land ownership of JHI and ownership of NLC Greenspace are therefore immediately accessible Land Development Service, with potential for testing at Development Stage. Ownership for straightforward collaboration with NLC Housing and Social Work Services in progressing development.

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Disadvantages Disadvantages JHI role in progressing development JHI ownership will require position to will need to be clarified for be agreed with NLC as part of Development Stage as they have no Demonstrator Stage. ongoing stake in project.

Advantages Advantages Minewater resurgence and drainage No environmental designations apply issues are ongoing environmental and to site and borehole locations are not financial burden to Council and adjacent to existing watercourses or residents in Allanton and could be identified wetland areas. mitigated by proposal.

Creation of new wetland areas offers potential for biodiversity gains, improving quality of water to local watercourses, and providing an attractive recreational area for the local community.

Environmental Disadvantages Disadvantages constraints Production well and passive Proposal does not incorporate the treatment system are within an area potential to mitigate the existing designated as a Local Nature Reserve, minewater issues affecting Allanton. Site of Importance for Nature While the system would be net Conservation, and known to contain neutral (i.e. the same volume of species of interest for Local minewater would be reinjected as Biodiversity Action Plan, which may pumped), the presence of a constrain development locations, minewater geothermal system increase survey requirements and accessing the mine seams from which create resistance to proposals. the resurgence issues arise, would almost inevitably lead to association between the geothermal system and the ongoing environmental issues affecting the area.

Advantages Advantages Proposal will bring the existing Proposal in-sync with pollution minewater discharge from Kingshill principles of returning abstractions to Regulatory within the CAR Licencing, with the their source. Framework consequence there will be a Suspended materials (Fe, Mn) remain “Responsible Person” under the within the minewater. Licence.

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Disadvantages Disadvantages Suspended materials will oxidise and No improvement to the existing will require to be disposed of to situation where Kingshill discharges landfill once collected in settlement are unlicensed. basin.

Information required to satisfy regulator will need to be scoped as it is not pre-defined and extended test period required.

Surface discharge will require Flood Risk Assessment to demonstrate acceptability.

Advantages Advantages Passive treatment system eliminates Open loop geothermal systems have the potential complexities of a precedent elsewhere. reinjection system and increases the overall robustness of the system and Potential that this option has wider the reliability of the DHN. replicability as it does not require the same space requirements, which may Avoids the possibility of thermal not be available in more densely breakthrough. developed locations suitable for geothermal energy.

Maintains pressure in the mine system. Geothermal Technical Maintains volume of water in mine Issues system to avoid increasing ESP pumping costs.

Disadvantages Disadvantages Extended testing period required to There are inherent risks associated gather sufficient baseline with injection wells, as described in environmental information to design Chapter 3. It is generally true that system and secure CAR Licence. injection of fluids into mines is more difficult than extraction. Several Changes to minewater chemistry over problems may arise: time may affect design of system and • In permeable rocks, re-injection is its performance, requiring easier but the risk of cold water modifications. breaking through to the production wells is higher.

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• If injection is made into the collapsed longwall workings then there may be reduction in injection flow capacity due to collapse. • There is a high risk that geochemical reactions cause iron or other deposits to collect near the well and within the well, and these may eventually require cleaning or even re-drilling.

As the area around Fortissat has high groundwater levels higher pressure may be required to inject fluids into the already saturated substrate. This is a particular risk if the wellhead is located below 200 m OD and could lead to high pumping costs.

District Advantages Advantages Heating System is scale-able. Allows energy centre to be located Network close to and between both target Technical Energy centre is readily accessible to villages. Issues existing and gas electricity network.

Energy centre location allows potential to include visitor facilities related to the nature reserve as well.

Disadvantages Disadvantages Location of energy centre more Location of energy centre less distant from Shotts for potential accessible to existing gas network for future expansion of network. system backup, resulting in higher connection costs.

Table 5.2: Summary table of preferred and alternative minewater geothermal DHN development options.

While it is evident from the above option comparison that there are both advantages and disadvantages to both systems, at this point Option 1 is identified as the ‘Preferred’ option due to the potential for it to mitigate existing minewater resurgence issues which currently blight Allanton. This is considered to widen the appeal of the project for all key stakeholders.

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5.6 RISK MANAGEMENT

Throughout the project development to date, risks and opportunities that have arisen in project meetings and technical reports have been captured. The register in Tables 5.3, 5.4 and 5.5 document the current view of risks and identifies potential actions that can be taken in subsequent stages of the project to reduce risks. Following risks, there is a discussion on opportunities.

In this project a risk is any issue that may lead to a loss in value; an opportunity can add value to the project. Risks and opportunities may be discrete events, such as removal of the RHI; or broader uncertainties, such as unpredictable minewater chemistry over time. Risks and opportunities have been recognised in all aspects of the project and organised by three categories: geothermal supply (Table 5.3); district heating network (DHN) (Table 5.4) and other (Table 5.5). Risks have been ranked relatively from Low to High, where the ranking indicates both the potential impact on the project value if the risk materialises and the probability of the risk occurring. Risks are also ranked relatively according to the ability of the project to manage the risk, again from Low to High.

Mitigating actions are described, and the point at which the project will need to address the risk is identified. For the geothermal supply the project stages during which to address the risk are either Licensing, Testing, Design or Operation. For the DHN they are Engagement, Design or Operation. For Other they could be any of the above.

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Geothermal Supply Risk = Prob * When to Risk after # Risk Manageability Mitigating actions Impact address risk mitigation Probability of fault bisecting the mine being sealed is 50:50 due to lack of knowledge of regional fault behaviour. There are at least 6 major faults which bisect the WRSM and WNMA worked seams. Fluid migration across the faults Faults are sealed 1 Low Moderate can be avoided by designing system so that production and injection wells are Design Low ie fluids will not migrate across or along the fault on the same side of the main fault. Impact depends on which side of the major fault is selected, because if the faults are sealed this will limit the volume and depth of mine from which heat is extracted. Aquifer transmissivity is quite speculative, as it is unknown where the source of water flooding the mine is. Monitor production well for temperature and flow Recharge from aquifers to the mine is low, limiting rate with submersible pump power requirements. Can be mitigated in medium 2 Moderate Low Operation Moderate sustainability of minewater and therefore heat extraction. term with reinjection. If no aquifer recharge impact on longevity of geothermal resource without reinjection is catastrophic, so reinjection well would need to be drilled. Produce from deepest portion of mine. Select heat pumps based on known minewater temperature following testing, to ensure COP >2.9. Monitor Design & 3 Minewater temperature at low end of range ie <15°C Moderate High Low temperature during operation and test chemistry at intervals to assess Operation whether there is mixing with shallower or surface waters. Deliberately over-size treatment facility or ensure that land available to expand Design & 4 Unpredictable water chemistry over time Moderate Moderate Moderate treatment facility at later stage if desired. Operation

Utilise prophylactic heat exchanger. Maintain sealed, anoxic conditions in 5 High Fe concentrations in minewater High High abstraction-heat exchange- reinjection system. Dose with benign reducing Design Low agents to maintain Fe in solution. Utilise prophylactic heat exchanger. Maintain sealed, anoxic conditions in abstraction-heat exchange- reinjection system. Dose with benign reducing 6 High Mn concentrations High Moderate agents to maintain Mn in solution (if reinjected). Design Moderate Increase size of treatment plant and consider active chemical dosing (alkali addition) to remove Mn (if treated)

If reinjection practised, maintain sealed system. If minewater treated, ensure 7 High H2S concentrations High Moderate Design Moderate H2S is vented or scrubbed from minewater to prevent odour issues.

Assess water chemistry during well test. If engineering solutions can resolve Minewater quality dramatically reduces lifespan of Testing & 8 Moderate High any prohibitive chemistry issues schedule annual maintenance with deep clean Low submersible pump and heat exchanger Design and possible replacements scheduled. Accounted for in financial model.

//Continued

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Geothermal Supply (cont.) Risk = Prob * When to Risk after # Risk Impact Manageability Mitigating actions address risk mitigation Difficult to manage if the ground level at the drilling site is below 200 m OD. 9 Artesian conditions below 200 m OD Moderate Moderate Can be addressed with high injection pumping capacity and multiple, injection Design Moderate wells, but this will increase costs.

Withdraw bit and deviate to re-attempt to encounter roadway. Careful quality Production (or injection) well fails to encounter permeable control of mine plans and drilling process. May be worth testing for 10 High Moderate Testing Moderate roadway permeability and yield before drilling again as naturally permeability may match required geothermal supply requirements.

This is unlikely. A contingency plan which involves planning to drill a second Testing & 11 Extraction flow rate is not achievable from mine roadway Moderate Moderate Moderate production well should be considered. Design

Option 1 only Producing water from mine where matrix likely to hold up bedrock, although this may be challenging to predict prior to drilling. Monitoring surface Design & 12 Mine subsides on minewater extraction Moderate High Low seismicity (if deemed necessary in design stage). Reinjection well may be Operation required to inject some minewater to retain pressure within the mine system.

Treatment facility is not deemed better than business as 13 Moderate Low System will be designed with injection wells Design Low usual by SEPA

Option 2 only Risk can be mitigated through installation of multiple injection wells, a minimum of two are suggested for one production well. Risk unknown until 14 Insufficient permeability to allow reinjection of minewater Moderate Low injection tested. Injection test and core samples collected from test well may Design Moderate be advised to collect aquifer transmissivity, porosity and permeability data. Installing a passive treatment facility will avoid this risk. Perform hydraulic testing and modelling of mine system prior to designing injection well doublet. Maximise fluid flow pathway between injection well and 15 Thermal breakthrough occurs High Moderate production well. Avoid direct roadways linking wells. Potentially avoid Design Moderate injection, although in this case be careful of changing pressures within the mine. Table 5.3: Risk Register - Risks and mitigating actions associated with geothermal supply

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District Heating Network Risk = Prob * When to # Risk Impact Manageability Mitigating actions address risk Risk after mitigation Ensure long lead time (up to 18 months) to consult with Network Rail to agree 16 District heating network requires railway line crossing Moderate High suitable crossing point, negotiate wayleave agreement and liaise as necessary Engagement Low to secure acceptable design solution. Engage private householders early in project design. Make connecting to 17 Private heat customers do not connect to network High Moderate Engagement Moderate network economically and socially attractive. Select the design option with highest heat density for least pipework and largest feasible network. Structure delivery model ESCo willing to make a low Engagement 18 Heat demand too low, so cost of heat is too high per kWh High Moderate Low return or not for profit. Engage with NLC. Assess national value of minewater & Design geothermal as demonstrator project. Drilling test well is fundamentally riskiest part of project development. Sunk 19 Testing of production well results in "no go" High Moderate Testing Moderate costs of c. £500k potentially lost if well is unused for heat supply. Design not optimised and integrated across generation/ Clearly defined basis of design that forms the technical specifications and network/supply to reflect key operating conditions (such as delivery by a competent contractor. Generation, network and customer 20 High High Design Moderate compatibility of network flow/return temps with operating interface must be integrated in the delivered solution with suitable supporting temperatures in secondary heating systems) investment. Development trajectory of network and connections is Focus on customer engagement and planning of network installation and Engagement 21 delayed and installation and connections resulting in Moderate High connections. High priority on customer satisfaction in contract specification Moderate & Design oversized plant and lower than predicted efficiency and performance requirements. Poor customer satisfaction due to mismanaged customer service - particularly relating to installation of heat Focus on customer engagement and planning of network installation and 22 connection and heat interface unit: poor customer Moderate High connections. High priority on customer satisfaction in contract specification Engagement Moderate communication at planning stage; disruption to customers; and performance requirements. quality of service; quality of finishing/making good Model economic benefit of alternative heat sources to supply district heating in next phase. Will be a greater risk to future projects following establishment Alternative heat sources developed that outcompete 23 Moderate Moderate of geothermal demonstrator. Design Moderate geothermal on cost of supply DHN is “energy agnostic” so energy centre could run on alternative fuel source, retaining value for installed infrastructure. Table 5.4: Risk Register - Risks and mitigating actions associated with the district heating network.

Other Risk = Prob * When to # Risk Impact Manageability Mitigating actions address risk Risk after mitigation 24 Renewable Heat Incentive reduced or eradicated by High Moderate Continue to engage with DECC and Scottish Government in the first instance Engagement Moderate government 25 Work closely with SEPA during application. Do not commit to any CAPEX Well licensing delays project Low High Licensing Low expenditures until license granted. 26 Housing stock upgrades and minewater geothermal system High High Keep open dialogue with NLC regarding timing of housing upgrades Engagement Low timescale are out of sync Table 5.5: Risk Register - Risk and mitigating actions associated aspects of the project other than geothermal supply and the district heating network.

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5.7 OPPORTUNITIES

Many of the key opportunities have already been mentioned, the potential wide-ranging benefits of installing a passive minewater treatment facility. These include:

• The Limestone Coal (LSC) mined seam reaches depths greater than 500 m, meaning temperatures above 18°C may be present, and may allow the system to access the Geothermal RHI tariff. • The fractured bedrock above the long-wall workings is likely to be productive, which increases the area through which minewater can migrate to the well, increasing the heat potential of the system from “mined-area only” estimates. • Working closely with SEPA throughout the well design process could reduce the 2’’ grouting annulus illustrated in the well designs in Appendix A3.7 in turn reducing the cost of the wells from the current estimates. • The Allanton community are enthusiastic about renewables and very enthusiastic about any prospect of mitigating current surface leakage of minewater. • The Allanton community has extensive local knowledge and experience of the mines. • Shotts has an economically attractive heat market for district heating, and should be explored in more detail in future studies. • The downturn in the oil industry may result in lower costs for services and potentially drilling.

5.8 CARBON AUDIT

Switching from domestic gas boilers to a minewater geothermal district heating network will reduce carbon emissions. The carbon emissions are compared to a business as usual (BAU) case assuming that existing heat is supplied from individual gas boilers. The carbon emissions are based on DECC figures and assume that the Gas Carbon Emissions Factor is 0.18407 kgCO2/kWh and the Electricity Carbon Emissions Factor is 0.46219 kgCO2/kWh. The BAU is compared to the heat pump scenario based on the gas boiler supplying 5% of the annual load and the heat pump supplying 95% of the annual demand. These are the same figures that have been used in the financial model. The analysis is based on a heat pump COP of 3.5 and gas boiler efficiency of 90% that are also used in the model.

Table 5.6 shows the BAU emissions, Table 5.7 shows emissions with minewater geothermal system installed, and Table 5.8 shows the emissions saved.

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Option Total Heat Demand Gas Consumption tCO2 for Gas Boilers (MWh) (kWh)

1A 3,860 4,541,176 836 1B 5,713 6,721,176 1,237 1C/2 9,670 11,376,471 2,094 Table 5.6: The BAU carbon emissions with 100% of heat generated from domestic gas heating systems.

Option Total Heat Gas tCO2 for Electrical tCO2 for Demand Consumption Gas Consumption of WSHP (MWh) (kWh) Boilers WSHP (kWh) 1A 3860 214,444 39 1,047,714 595 1B 5713 317,389 58 1,550,671 880 1C/2 9670 537,222 99 2,624,714 1490 Table 5.7: The projected carbon emissions associated with electricity consumption of the minewater geothermal WSHP system (providing 95% of heat) and gas consumption of the back-up gas boiler (providing 5% of heat) in the heat centre serving the district heating network.

Option Carbon emission savings (tCO2/year)

1A 312 1B 462 1C/2 782 Table 5.8: A low estimate of the carbon emissions savings associated with the four different design options based on the 2015 UK electricity mix. Carbon savings will increase further as the UK electricity mix becomes less carbon intensive.

These figures are approximate as they only take into account the emissions saved from replacement of the heating gas with electricity to run the minewater-source heat pumps. In addition, the electricity carbon emissions factor is based on the 2015 UK electricity mix, which is projected to become less carbon intensive over time. Therefore, the CO2 emissions from the minewater geothermal DHN will decrease significantly over the projects lifetime, whereas emissions from gas heating will only marginally decrease if a 100% efficient boiler is installed in every house.

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Chapter 6 – Delivery Model

6.1 SUMMARY

The Delivery Model chapter has been prepared as part of the report into the Fortissat Community Minewater Geothermal District Heating Network to provide:

• An overview of the different candidate delivery structures; • A consideration of the different metering and tariff options for the heat market; • Recommendations for the proposed delivery model; • Results from financial modelling; and • A discussion of longer-term opportunities.

In addition to forming part of the report, the chapter has been written to allow it to be read as a standalone document, and therefore includes an overview of the main processes and outcomes from the initial strategy development and feasibility work.

6.2 OVERVIEW OF PROPOSAL

The Fortissat Minewater Geothermal proposal is one of four projects awarded funding from the Scottish Government’s Geothermal Energy Challenge Fund (GECF), for the ‘Catalyst Stage’ which is intended to cover initial strategy development and feasibility work. These projects have been funded to explore the potential of Scotland’s geothermal resource to meet the energy needs of local communities.

The aim of this project has been to assess the feasibility and define the initial strategy to develop Scotland’s first minewater geothermal scheme in a rural area with social deprivation. While focused on the specifics of the location, the site itself was selected in part for potential replicability and scalability. Our hope is that an operational minewater geothermal district heating system demonstrator project at Fortissat might act as proof of concept for Scotland-wide duplication.

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housing energy efficiency, reducing heating costs, and reducing carbon from heat in their Council homes.

The resource mapping has identified that the worked coal seams of the Kingshill Colliery are by far the largest geothermal resource in the area of interest and these have been the main focus of this study, following a geothermal systems option appraisal which considered the various mine systems in the study area. Kingshill Colliery is one of Scotland’s largest historical mine systems and the mine seams partly underlie the southern area of the James Hutton Institute’s Hartwood Home Research Farm, and extend southwards under the village of Allanton. The former Kingshill Colliery No. 1 site lies to the south of Allanton, and is in the ownership of North Lanarkshire Council. Following its decommissioning, reclamation works included forestry planting, the creation of grassland habitat, lagoon reclamation and surface water drainage improvements. It is now designated as a Site of Importance for Nature Conservation, and a Local Nature Reserve. However, the drainage maintenance presents an ongoing financial burden to the Council, and minewater resurgence issues continue to affect homes in Allanton. The development of a geothermal minewater system in this location therefore simultaneously presents environmental constraints and benefits which need to be addressed as the project progresses.

In parallel with the geothermal system options appraisal, an appraisal of the district heating network (DHN) design options and associated heat market has been undertaken. The initial focus for assessing the energy needs of local communities in the area encompassed the town of Shotts, the villages of Hartwood, Allanton and Salsburgh, and residential and non-residential development within the area, roughly equivalent to the Fortissat Ward of North Lanarkshire (Figure 1.1). The feasibility study identified constraints and opportunities in relation to using the available geothermal energy to provide heat in this area, to inform the identification of potentially viable heat networks. Balancing the risks and opportunities, a medium term potential has been identified which connects Allanton and Hartwood to a DHN; and a longer term potential to extend the network to Shotts. Due to the separation distance, a DHN in Salsburgh would be more effective as a standalone system, and an alternative energy source would be required as there is not a viable minewater geothermal resource in the vicinity of Salsburgh.

The two options appraisals have formed the basis for determining two main development options each in a differing location, and each with differing methods for discharging the minewater. The two options are compared, risks and opportunities identified, and a preliminary carbon audit undertaken. The preferred option locates the production well at or close to the site of the Kingshill shaft, with a passive minewater treatment system discharging the water at surface. This has the

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potential to alleviate existing minewater resurgence that affects properties in the village of Allanton and are an ongoing maintenance burden to NLC and residents. Alternative sizes of the district heat network are considered for this option. An alternative geothermal design option has also been considered, which locates the production well and two reinjection wells within Hartwood Home Farm. The medium term development potential for the DHN is focused on the villages of Allanton and Hartwood, with potential future extension to Shotts identified as a long term development potential. The primary direct beneficiaries of the project will be the local communities at Allanton and Hartwood. Hartwood has no access to the gas grid, with many families heating their homes using electricity, oil or coal, while around 40% of the homes in Allanton are Council owned and occupied by tenants, many on low incomes.

The project therefore has the potential for multiple benefits – social, environmental, carbon reduction, financial – and the priorities placed on each of these has the potential to affect the way in which the business is structured and managed.

6.3 PROJECT EVOLUTION

The Case Studies in the Scottish Futures Trust Report, Delivery Structures for Heat Networks (March 2015), demonstrate that while there are common characteristics between different heat networks developed to date, the structure which is right for each individual project needs to reflect its own particular circumstances. It will also need to evolve over time, and chosen business model and legal structure need to accommodate this.

The project evolution, also reflected in UK case studies, would follow a particular development trajectory4:

• Project drivers – identification of strategic drivers for the project; whether internal / external; whether aligned across organisations; how any conflicts will be resolved. • Project objectives – what is the project setting out to achieve? • Definition of initial project – what is the scale and scope of the initial project / phase? • Initial delivery structure o Rationale for initial delivery structure, e.g. response to finance / funding opportunity, market pressure, availability of heat source etc. • Governance – what governance arrangements will be put in place for the project?

4 Scottish Futures Trust Report, Delivery Structures for Heat Networks (March 2015)

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• Finance – how will the project be funded, and how will the delivery structure taken into account the availability of funding? • Contracting route – how will the project be contracted? Which risks will the authority retain / share / transfer? What main contracts will be let? Will a special purpose vehicle be established? If so, what will be the ownership structure and what risks transferred to the SPV? • Procurement route - how will the project be procured? Under what procurement procedure(s) will the main contracts be let (open, restricted, negotiated, competitive dialogue)? • Subsequent expansion o How could the delivery structure evolve and what are the potential drivers for change? o How will changes to available finance and risk perception, and wider market awareness, impact on the delivery structure? • Future proposed changes – are any future changes to the delivery structure envisaged?

6.4 METERING AND TARIFF OPTIONS

6.4.1 Metering Heat metering and billing regulations have been introduced to implement the requirements of the European Energy Efficiency Directive in the UK. All new heat networks are required to install meters and controls so that customers can manage their heating. There are also requirements to provide customers with transparent billing information.

The heat network is fundamentally different to the gas or electricity markets, in that as a closed loop network, rather than a national grid, there is only one ‘supplier’. Appropriate governance structures need to be put in place for all heat customers to provide safeguards that the heat tariff is equivalent, if not discounted, against other forms of energy supply. This is also necessary to provide the incentive for heat users to sign up in the first place – particularly given the potential for up-front connection costs, and the inevitability of construction disturbance caused by the implementation of building efficiency measures, internal wet system upgrades (upsized radiators), and boiler replacement with Heat Interface Units to enable connection to a low temperature network.

Voluntary guidance on heat networks is contained in the recently published (November 2015) Heat Networks: Code of Practice for the UK, prepared jointly by the Association for Decentralised Energy (ADE) and the Chartered Institution of Building Services Engineers (CIBSE). Amongst the areas covered is heat metering, to inform choices on how to select metering, prepayment and billing systems that are accurate and cost effective.

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6.4.2 Tariffs The revenue for heat sales was modelled as 6 p/kWh which offers a 2% saving to Council tenants compared to an assumed price of heat from gas of approximately 6.13 p/kWh5. Owner-occupiers would benefit from a higher alternative price if the cost of boiler replacement is factored in, however this could be handled through a connection charge to customers wishing to connect to the network.

Specific decisions on heat prices will need to be further considered in order to offer an incentive to customers to connect. The issues to consider will be:

• How investment cost of heat interface unit (HIU) and branch connection are shared between the network operator and the customer; • Standing/capacity charges for heat (£/kW) supplied to customers and whether this cost varies between customers; and • Unit cost of heat (£/kWh) supplied to customers: o Whether this cost varies between different types of off-takers; o Whether or not cost varies with time of day, season, etcetera; o Whether or not the tariff rates be linked to gas-prices, for instance through a % discount or offset and floor-price.

6.5 OVERVIEW OF BUSINESS MODELS AND LEGAL STRUCTURES

There are a number of different factors that need to be taken into consideration in selecting a preferred structure to deliver and run the project. These include, but are not necessarily limited to:

• The preferred technical scenario; • The delivery structure; • The procurement strategy; • The Council’s strategic priorities for the project;

5 This figure is based on the gas supply cost from supplier quotes as well as DECC published average annual domestic gas bills (last updated 22 December 2015).

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• The willingness of the Council to work with a joint venture partner(s) or to enter long term supply contracts with a 3rd party; • Longer term transition and exit strategy (if any); • Tax considerations; • EU State Aid considerations.

To provide a reference point for these factors, a review of existing heat networks has been undertaken.

6.5.1 Aberdeen Heat and Power Aberdeen Heat and Power was created by Aberdeen City Council in response to the need to combat fuel poverty, reduce carbon emissions and reduce running costs. The Council Housing Stock (2002 Housing Audit) comprised some 23,500 homes, which included 4,500 flats in 59 multi-storey blocks with all-electric heating and poor thermal efficiency. 70% of these residents lived in fuel poverty, and underheating contributed to damp conditions.

Aberdeen Heat and Power was therefore established in 2002 as an independent, not-for-profit company, limited by guarantee – the Council retained walk-in rights on its assets to provide security of supply for its tenants. Its five members include 3 individual members, Aberdeen City Council and Energy Action Scotland. As a separate development / management company, the company was able secure funding for an initial 200kW standalone energy centre at Stocket Hill, through a 40% grant from Energy Savings programmes and secured by a 50 year framework agreement with the Council.

Aberdeen City Council already had a heat with rent programme in place, and this is the mechanism by which the district heating network operates. There are three heat usage tariffs, reviewed annually - heat network, gas and electric - with the heat network tariff bench-marked against gas and electric, and set to avoid fuel poverty. Partly due to the cost of heat meters at the point of inception, and partly due to the need for meters needing funding, monitoring and replacement, heat from the network is not metered. Instead, there are links with SCARF to encourage energy efficiency. As current building regulations require heat meters to be installed, when new build properties are connected (as is planned for new council housing development in 2017/18), AHP will need to design and run a new administrative service. Where individual flats within the multi-storey were privately owned, the homeowner buys the installation and then AHP charges the owner the same rate it charges the Council. For non-Council assets, a subsidiary company (District Energy Aberdeen Ltd - DEAL) has been established.

Ian provided a detailed history of the phased roll-out of the different networks, and some of the issues and benefits encountered. The design of new energy centres take into account the potential

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for future expansion, as well as identifying existing buildings with capacity in their boiler houses at strategic points in the network. The company continues to be successful in securing grants to extend the network, and operates with a trading surplus to cover CAPEX replacements, OPEX and loan repayments.

One issue of particular relevance to the Fortissat project was the process of securing the wayleave and agreeing the detail design for the network crossing the railway line. This process took around 18 months, and required a design study to be agreed, and clerk of works on site during construction. Notably, however, there was no requirement for a deposit or annual payment for the wayleave.

6.5.2 Gateshead Council Heat and Power Network Gateshead Council is in the process of constructing a heat and private wire network to initially connect mainly large scale public and commercial buildings (Further Education College, Council Offices, Sage Gateshead, the Baltic Gallery, a hotel, and an office block and high-rise council flats). Commercial contracts have been secured for periods of a minimum of ten years and up to 20 years. Construction commenced in June 2015 and is due to become operational in June 2016.

The concept goes back at least 5 years, and has been led and resourced by the Council, with the Council procuring services as necessary for the detail design and construction contract. The procurement process itself took around 18 months. The £20M investment required has covered costs of around £9M for the energy centre (including a 4MW gas powered CHP system and back-up), around £1m in consultancy fees and around £10M for roughly 3km of heat and private wire networks. This has been 100% publicly funded.

Figure 6.1: Gateshead Energy Centre, Gateshead Council / WSP Parsons Brinckerhoff.

In discussing the operating structure of the company with Jim Gillon, Energy Services Manager in the Council Housing Design and Technical Services department, he outlined the Council’s approach has been to focus on the project first, and consider the operating structure thereafter. This reflects the powers that Councils have to supply heat and electricity. These powers do not extend to buying and selling electricity, which may be required to ensure continuity of supply when it is not being generated by the CHP system. Therefore, the Council is in the process of establishing a commercial company limited by shares (with a single share owned by the Council) that will have a 40 year

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contract to re-pay the capital cost of the infrastructure, and operate as an independent trading company to manage the heat and electricity contracts.

The decision to proceed with a private wire network was based on the need to make the project financially viable, and the balance of income between heat and electricity is approximately 25%/75% respectively, and 70% revenue from public sector connections. Income would have been substantially less if the electricity were simply sold to the grid. The project will deliver an 8% pre- financing IRR over a 40-year term (the lifetime of the pipe infrastructure) with a positive cashflow from year one.

In addition to providing an income source to the Council and reducing carbon emissions, the scheme is part of wider regeneration objectives, and planned to help attract new businesses to the area, due to lower energy prices and green credentials.

6.5.3 Further Case Studies In addition to a site visit to Aberdeen Heat & Power and consultation with the Energy Services Manager at Gateshead Council, members of the project team visited the operational minewater geothermal system at Shettleston Housing Association, which provides heat for 18 homes. The site visit summaries are contained in Appendix A6.1 and A6.2.

The Scottish Future Trust report “Guidance on Delivery Structures for Heat Networks” (March 2015) provides further detailed case studies of existing UK systems of relevance when considering potential delivery structures.

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6.6 DELIVERY STRUCTURE OPTIONS

Based on this review, there are a range of delivery structure options for the Fortissat Geothermal proposition:

Figure 6.2 Commercial structure options (source DECC6, public sector information licensed under Open Government Licence v3.0 www.nationalarchives.gov.uk/doc/open-government-licence/).

Each of these structures has a different risk profile. In considering the most appropriate structure, it is important to recognise that risk generally goes hand in hand with control: the more control required by the local authority over a heat network, the more risk it must accept. Conversely, a risk- averse approach is likely to result in some loss of control over the authority’s ability to achieve its strategic objectives for the network7. DECC’s Investor guide to Heat Networks8 includes the following graphic illustrating the relationship between control and risk.

6 DECC, Investing in the UK’s Heat Infrastructure: Heat Networks, November 2015 7 Scottish Futures Trust, Guidance on Delivery Structures for Heat Networks, March 2015. 8 DECC, Investing in the UK’s Heat Infrastructure: Heat Networks, November 2015

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Figure 6.3: Relationship of control to risk (source DECC9, public sector information licensed under Open Government Licence v3.0 www.nationalarchives.gov.uk/doc/open-government-licence/).

6.7 PROS AND CONS OF COMMERCIAL STRUCTURES

For the Fortissat Community Minewater Geothermal Energy District Heating Network, the advantages and disadvantages are set out in Table 6.1:

9 DECC, Investing in the UK’s Heat Infrastructure: Heat Networks, November 2015

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Council provision - no ESCO 100% Council owned ESCO Joint Venture (“JV”) ESCO Concession arrangement Administration • No management of project • Administration of ESCO may • Relationship between partners • Council will need to monitor level entities required impose an administrative governed by a Joint Venture compliance with concession burden on Council Agreement (“JVA”) or agreement • Council will need to ensure that Shareholders’ Agreement it maintains oversight of ESCO (“SA”), meaning that decision making can be complicated • Deadlock is possible Resourcing • Council must resource project • ESCO will have own Board of • Council will need to monitor JV • Organising and managing on an ongoing basis, including Directors, management team and ensure compliance with competition for concession operations, maintenance, and employees JVA or SA could require significant billing, etc. • JV partners can pool resources Council resources • Council resources required to monitor compliance with concession agreement • ESCO resourcing managed by service provider Stakeholder • Limited scope for stakeholder • Opportunity for stakeholder • Potential opportunity for • Limited scope for stakeholder involvement involvement involvement stakeholder involvement involvement Funding options • Council resources and existing • Council resources and existing • Costs can be shared between • External finance such as project public sector routes remain public sector routes may the partners finance available open remain open • Public sector routes may not be • External finance such as project • External finance such as project available finance unlikely to be possible finance available • External finance such as project finance available Delivery risk • Entirely borne by Council • Borne by ESCO rather than • Borne by ESCO rather than • Borne by service provider Council Council • Shared between JV partners Funding risk • Entirely borne by Council • Borne by ESCO rather than • Borne by ESCO rather than • Borne by service provider Council Council • Shared between JV partners Operational risk • Entirely borne by Council • Borne by ESCO rather than • Borne by ESCO rather than • Borne by service provider Council Council • Risk that service levels may • Shared between JV partners deteriorate near the end of the concession period

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Council provision - no ESCO 100% Council owned ESCO Joint Venture (“JV”) ESCO Concession arrangement Operational • Council can adapt services as its • Council and other stakeholders • JV partners can align ESCO • Service provide will most likely flexibility objectives evolve can align ESCO objectives with objectives with their own be operating “for profit” and so their own • ESCO can contract with may act counter to the public • ESCO can contract with multiple counterparties for interest multiple counterparties for Energy Centre, DHN, etc. • May be difficult to amend Energy Centre, DHN, etc. • ESCO could eventually provide concession agreement if • ESCO could eventually provide additional services Council objectives change additional services • Decision making structure means that ESCO could potentially act counter to the public interest Exit options • Difficult to sell or spin off • Flexibility around exit strategy • Ability to exit will depend on • May be difficult to change project in the future provisions contained within the service provider in the event of JVA or SA substandard performance Table 6.1: Summary of the advantages and disadvantages of potential ESCO structures.

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6.8 STRUCTURE OF SPV

We believe that the project would be most effectively delivered via an SPV, as it involves a number of different technologies and a range of infrastructure lifetimes. The contractual structure for delivery of the project and the ongoing operation of the project is likely to be complex and will need to be designed carefully.

There are various potential legal structures for the SPV, including a company limited by shares or by guarantee; a limited liability partnership; a community interest company; a co-operative or a community benefit society. The choice of the appropriate vehicle will depend on a range of factors including:

• Council objectives • Desire for stakeholder involvement • Whether the project is going to be run “for profit” or “not for profit” • The ownership structure and the number and identities of the stakeholders • The stakeholders’ requirements for flexibility, particularly around the exit strategy • The sources of finance that are being targeted • The risk appetite of the stakeholders • The allocation of any potential liabilities amongst the stakeholders • State Aid considerations • Tax and accounting considerations

For the purposes of the preliminary financial model we have assumed that the project is delivered using a company limited by shares.

A key work stream during the next phase of the project will be to identify the preferred structure for the project.

It should be noted that North Lanarkshire Council is currently considering the most appropriate business model for the development of a community heating network at high-rise flats in Motherwell. During our discussion with the Council there is the potential that the same operating model may be applicable for the Fortissat geothermal project. Using the same model may result in some cost savings but care will need to be taken in determining whether the model will require adjustment for a rural DHN connected to a geothermal system and dealing with both privately owned and social housing. This will need to be investigated in the next phase.

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6.9 FINANCIAL MODEL – MEDIUM TERM

A financial model has been built to describe and evaluate the first 40 years of the project life as per the DECC Heat Network Project Metric Template. The financial model has intentionally been designed to be flexible and adaptable so that it can be used throughout the development process, including for the ultimate financing of the project construction. The structure of the financial model allows additional functionality to be added easily as the project continues to take shape.

The financial model evaluates multiple scenarios based around a heating network that comprises:

The following preferred design options have been considered:

Design option Description

1A 700 kW heat pump, 173 council houses, 155 private houses, low temperature DHN, passive treatment facility

1B 1 MW heat pump, 197 council houses, 240 private houses, low temperature DHN, 1 school, passive treatment facility

1C 2 MW heat pump, 201 council houses, 415 private houses, low temperature DHN, 1 school, passive treatment facility 2 2 MW heat pump, 201 council houses, 415 private houses, low temperature DHN, 1 school, injection wells

Table 6.2: District Heating Network Options

The preferred design options are discussed in more detail in Chapters 4 and 5.

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The model assumes that approximately 60% of the project capital expenditure is financed via a debt facility with a 20 year term (straight line amortisation) at an interest rate of 3.5% per annum. This is clearly not realistic for a commercial loan facility: the implicit assumption is that, as a demonstrator project with potentially wide applications throughout Scotland, the Fortissat project will attract preferential financing terms and/or an element of grant funding.

6.10 REVENUE STREAMS

The revenue is composed of two elements: heat sales to customers and income from the Renewable Heat Incentive.

6.10.1 Heat Sales While there are examples of existing heat networks using a fixed monthly tariff approach, the requirement to install heat meters in new heat networks determines that a variable tariff approach is necessary for new schemes.

We have assumed a price to the end user of 6 p/kWh. This tariff level is intended to be lower than the current cost of using a gas boiler to provide space and hot water heating (as the lowest cost option widely deployed in the area), taking into account the cost in p/kWh of gas and the efficiency of a typical boiler.

Total heat consumption for each scenario has been calculated using the total heat demand of the buildings connected to the network. Further information is contained in Chapter 4.

6.10.2 Renewable Heat Incentive The other major source of revenue will be from the Non Domestic Renewable Heat Incentive, which is based on the amount of usable heat produced and is payable for the first 20 years of the project’s operational life. Due to the depth of the production well (which is slightly less than 500m) we have prudently assumed that the system will not qualify for the deep geothermal flat rate tariff of 5.08p/kWh and have instead used the Water/Ground-source heat pump tariff. This is a two-tiered tariff with a higher payment for heat generated until the system has operated up to 15% of its annual rated output (the equivalent of 1,314 operating hours per annum) and a lower payment above this output level. The tariffs (in p/kWh) are shown below.

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Eligible Tariff name Eligible sizes Tariffs technology

Ground-source heat all capacities Tier 1 Water/Ground-source heat 8.84 pumps & Water- Tier 1 pumps source heat pumps Tier 2 2.64

Table 6.3: Water/Ground-source heat pump RHI Tariffs as of December 2015

To be eligible for the Water/Ground-source heat pump tariff the heat pump must perform with a coefficient of performance (‘COP’) of 2.9 or greater. In the high temperature DHN scenarios that we have modelled the COP is close to but below the required level. However, there is scope for design improvements and we have therefore assumed that the required COP will be reached for the purposes of the financial model only. In addition, we have shown the impact of removing the RHI as a sensitivity.

The project economics would be improved if the project qualified for the deep geothermal tariff, and establishing whether this will be possible will be a priority in the next phase of the development of the project.

6.10.3 Capex and Opex assumptions The following table summarises the capital and operating expenditure assumptions that have been used in the preliminary financial model. The development is still at a very early stage and the detailed design process has not yet begun. Some of the costs may change substantially as the project progresses and as additional studies are undertaken, for example test well procurement, well testing, minewater geochemistry analysis, community engagement, detailed system design, etc. Where significant uncertainty exists we have intentionally used conservative estimates.

The cost of the passive minewater treatment facility is particularly difficult to predict until the minewater geochemistry has been analysed, as explained in Chapter 3. The initial scoping exercise resulted in an extremely broad capex range of £0.6-2.0m, and for the purposes of this preliminary financial model we have assumed a cost of £1.2m for this item. We have included the high and low points of the passive treatment capex range in our sensitivity analysis.

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Option 1a Option 1b Option 1c Option 2 700 kW Pump 1 MW Pump 2 MW Pump 2 MW Pump Low Temp Low Temp Low Temp Low Temp (75°C) (75°C) (75°C) (75°C) Small Network Medium Large Network Large Network Network

Capex (£ real) Production well(s) 460,000 460,000 460,000 500,000 Energy centre and DHN 2,730,823 3,995,080 6,781,253 6,976,623 Gas grid connection 21,566 21,566 21,566 122,366 Electricity grid connection 245,750 245,750 245,750 331,000 Heating system upgrades 590,400 786,600 1,108,800 1,108,800 Fabric energy efficiency 29,450 45,600 78,850 78,850 measures Passive treatment system 1,200,000 1,200,000 1,200,000 - Injection wells - - - 1,000,000 Injection well downhole - - - 15,000 pumps Total capex 5,277,990 6,754,597 9,896,220 10,132,640 (£ real) Opex (£ real per annum) Operating expenditure 74,278 96,799 167,227 182,867 Employee costs 17,500 17,500 35,000 35,000 Passive treatment system 30,000 30,000 30,000 - Total opex 121,778 144,299 232,227 217,867 (£ real per annum) Table 6.4: CAPEX and OPEX figures as input to the financial model, for Options 1A, 1B, 1C and 2 low Temp.

The majority of the costs increase as the network size increases. The exceptions are the production wells, gas and electrical grid connections, and the cost of the passive treatment system.

It should be noted that the capex and opex estimates above do not include the costs of administration, billing, etc. These depend upon the ESCO structure which is selected and will therefore need to be defined more fully at the next stage of the project.

6.11 INITIAL RESULTS OF FINANCIAL ANALYSIS

The figures in Table 6.5 below show the key financial metrics for the four design options. For the time being we have elected to use the 20 year aggregate cash flow rather than net present value. This is due to the current uncertainty around the ESCO structure and the resultant difficulty in determining an appropriate discount rate.

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20 year Design Option: Project CAPEX Descriptor net cash COP % Debt HP Size, Temp IRR (%) (£m) (£m)

1A: 700kW LT small network + Pump, 75°C passive treatment -3.1 0.0 5.7 3.34 50

1B: 1MW Pump, LT medium network + 75°C passive treatment -0.8 0.0 7.2 3.39 50

1C: 2MW Pump, LT large network + 75°C passive treatment 3.2 1.6 10.6 3.58 60

2: 2MW Pump, LT large network + 75°C injection wells 3.4 1.7 10.8 3.58 60

Table 6.5: Headline results for design options 1A, 1B, 1C and 2.

The obvious conclusion to draw from these figures is that the number of users connected to the network is critically important. The higher the network demand, the better the returns for investors. Only the largest network options (1C and 2) have positive IRRs and positive aggregate net cash flows over the first 20 years. However, in neither case is the Project IRR sufficiently high to attract external investors. This indicates that the project structure will be a not-for-profit ESCO which is 100% owned by the Council. This preliminary conclusion may change as the capex and opex estimates are refined further in the next phase of development.

It is important to note that the above results are very preliminary. There is a lot of work still to be undertaken in order to refine the assumptions that have been used in the financial model. However, initial indications are that a larger network is more likely to be financially viable than a smaller one. This is not in itself a surprising result and it reflects the experience with DHNs elsewhere.

6.11.1 Minewater Treatment The figures in Table 6.5 above take no account of the cost savings to the Council arising from the new passive minewater treatment facility. The Council currently spends an average of £50,000 per annum on mitigating and cleaning up minewater surface leakage in Fortissat as described in Technical Appendix A3.5.

If this saving is taken into account in options 1A, 1B and 1C then the figures in Table 6.6 would be as follows:

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20 year Design Option: Project CAPEX Descriptor net cash COP % Debt HP Size, Temp IRR (%) (£m) (£m)

1A: 700kW LT small network + Pump, 75°C passive treatment -1.7 0.0 5.7 3.34 50

1B: 1MW Pump, LT medium network + 75°C passive treatment 0.6 0.0 7.2 3.39 50

1C: 2MW Pump, LT large network + 75°C passive treatment 4.6 2.7 10.6 3.58 60

Table 6.6: Improvements in project IRR and aggregate 20 year cash flow when accounting for potential cost saving to NLC of £50,000 per annum through implementation of a passive minewater treatment facility integrated with the geothermal DHN

There is clearly a material improvement in the financial metrics if this cost saving is taken into account. This indicates that the passive treatment facility merits further consideration in light of the Council’s ongoing expenditure to mitigate the impact of minewater seepage from the Kingshill Colliery.

6.12 SENSITIVITY ANALYSIS

The preliminary financial model is based upon numerous estimates and assumptions. The precise results are therefore of limited relevance as they are unlikely to be accurate. The value of the financial model lies in its use as a tool to identify the capex and opex items that are likely to have the greatest impact on the financial viability of the project. This will help the project team to focus on the areas of highest potential value during the next phase of development.

For the sake of simplicity we have used design option 1C as the basis of the sensitivity analysis. We have excluded the impact of the potential £50,000 per annum cost saving to the council resulting from the passive minewater treatment facility.

The results of the sensitivity analysis are summarised in the tables and charts below.

IRR Sensitivity High Low Base Passive minewater treatment CAPEX range: £2m to £0.6m 2.1% 0.8% 1.6% OPEX: 20% higher and 20% lower 2.5% 0.4% 1.6% RHI: No tariff or Geothermal tariff (5.08 p/kWh) 2.6% 0.0% 1.6% Usage tariff: +1 p/kWh or -1 p/kWh 3.4% 0.0% 1.6% CAPEX: 20% higher and 20% lower 3.6% 0.0% 1.6% Table 6.7: Sensitivity testing on Option 1C for impact of key parameters on project IRR

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IRR sensitivities for Option 1C

Capex: 20% higher or 20% lower

Usage tariff: +1p/kWh or -1p/kWh

RHI: No tariff or Geothermal tariff 5.08p/kWh

OPEX: 20% higher and 20% lower

Passive minewater treatment CAPEX range: £2m to £0.6m

0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0%

Low High

Figure 6.4: Tornado diagram illustrating the results of Table 6.7

20 year total NCF Sensitivity High Low Base (£million) (£million) Passive minewater treatment CAPEX range: £2m to £0.6m 3.9 2.2 3.2 OPEX: 20% higher and 20% lower 4.5 1.9 3.2 RHI: No tariff or Geothermal tariff (5.08 p/kWh) 4.6 -8.3 3.2 Usage tariff: +1 p/kWh or -1 p/kWh 5.5 0.6 3.2 CAPEX: 20% higher and 20% lower 5.5 0.6 3.2 Table 6.8: Sensitivity testing on Option 1C for impact of key parameters on 20 year aggregate cash flow (NCF)

20 year total net cash flow sensitivities for Option 1c

Capex: 20% higher or 20% lower

Usage tariff: +1p/kWh or -1p/kWh

RHI: No tariff or Geothermal tariff 5.08p/kWh

OPEX: 20% higher and 20% lower

Passive minewater treatment CAPEX range: £2m to £0.6m

-10.0 -8.0 -6.0 -4.0 -2.0 0.0 2.0 4.0 6.0 8.0

Low (£million) High (£million)

Figure 6.5: Tornado diagram illustrating the results of Table 6.8

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As would be expected, the key sensitivities are the heat tariff and the capital expenditure. These will be a key focus of the next phase of the project. The impact of a reduction in capital expenditure is particularly interesting given that the project is intended to be a demonstrator project with the potential to be replicated in other parts of Scotland. It is reasonable to expect that geothermal DHN projects would become less expensive on a per-kWh basis as the level of expertise in constructing them increased.

Finally, the RHI tariff has a significant impact on the project economics. It is recommended that discussions are held with the relevant government entities at the next stage of the project in order to ensure that the higher geothermal tariff can be secured.

6.13 FINANCIAL MODEL – LONG TERM

This section of the Delivery Model report briefly considers the potential longer term opportunities for increasing the geothermal supply and expanding the network to connect Shotts; and how the delivery structure might transition over time to provide greater community stakeholder involvement.

The RHI applies for the first 20 years of the project’s operational life. After 20 years the project’s borrowings have been repaid and the project is essentially break-even at an operating cash flow level on an ongoing basis.

For the purposes of the financial model we have assumed that the key items of capital equipment are overhauled or replaced on a regular cycle, as follows:

Capital item % of initial cost Frequency

Water source heat pump 50% 15 years Thermal store 50% 15 years Gas boilers 25% 15 years Balance of plant 10% 10 years Table 6.9: Capital equipment overhaul costs

This ongoing capital expenditure is based upon fairly broad assumptions and the actual figures will clearly depend upon the exact type of equipment installed, warranty terms, operating hours, minewater chemistry, etc.

The ongoing capital expenditure assumptions mean that the model shows a small annual loss for the final 20 years of the project life, of the order of £17,500 per annum in the case of Option 1C. This can be seen in Table 6.10 below.

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Option 1C Cash Flow Yrs 0-10 Yrs 11-20 Yrs 21-30 Yrs 31-40 Revenue 6,734,913 8,608,962 9,836,093 9,836,045 RHI 5,156,104 6,370,025 - - Operating costs (6,485,021) (8,301,375) (9,544,956) (9,551,612) Operating cash flow 5,405,996 6,677,613 291,137 284,433 Corporation tax - - - - Capital expenditure (9,915,303) (717,714) (898,295) (27,131) Equity investment 4,000,000 - - - Senior debt drawdown 5,937,732 - - - Senior debt interest (1,709,278) (545,913) - - Senior debt repayment (2,968,866) (2,968,866) - - Net cash flow 750,281 2,445,119 (607,158) 257,302

Table 6.10: Long term cash flow model

If the minewater treatment cost saving of £50,000 per annum (described in section 6.11.1 above) is taken into account then the project operates at break-even at a net cash flow level, as shown in the table below:

Option 1C Cash Flow Yrs 0-10 Yrs 11-20 Yrs 21-30 Yrs 31-40 Revenue 6,734,913 8,608,962 9,836,093 9,836,045 RHI 5,156,104 6,370,025 - - Operating costs (5,870,492) (7,514,726) (8,641,148) (8,647,249) Operating cash flow 6,020,525 7,464,261 1,194,945 1,188,796 Corporation tax - (35,357) (210,595) (127,952) Capital expenditure (9,915,303) (717,714) (898,295) (27,131) Equity investment 4,000,000 - - - Senior debt drawdown 5,937,732 - - - Senior debt interest (1,709,278) (545,913) - - Senior debt repayment (2,968,866) (2,968,866) - - Net cash flow 1,364,809 3,196,410 86,055 1,033,713

Table 6.11: Long Term cash flow incorporating minewater treatment cost savings

Any forecasts of the financial performance of the project in 20 years’ time are inevitably somewhat uncertain. However, it is undoubtedly the case that the removal of RHI revenue after 20 years will have an adverse impact on the project economics. It is therefore prudent to consider what options exist for either reducing operating costs or increasing revenue so that the necessary flexibility can be built into the project at the outset.

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6.13.1 Potential Opportunities to Increase Revenue The removal of the RHI revenue following year 20 will have a significant negative impact on the project economics. There are however a number of ways in which this reduction in revenue could be addressed, including:

• The expansion of the network into Shotts would increase the Linear Heat Density and therefore the potential revenue, as illustrated in Table 4.4 in Chapter 4. • Setting up a trading arm as a subsidiary, in-line with District Energy Aberdeen Ltd. (‘DEAL), to connect non-Council off-takers on a commercial basis. • DECC expects gas prices to increase in the future (DECC, 2014). This will drive up the costs of alternative sources of heating and allow higher tariffs to be used at Fortissat, while still offering customers a discount compared to the alternatives. • Given the extremely ambitious UK and Scottish targets for decarbonising heat, it is possible that new policies could be implemented to either (i) reform or extend the RHI, or (ii) replace the RHI with another support mechanism. • Direct carbon taxes may become more prevalent following the Paris Treaty of COP21. This would have the impact of increasing the price of gas and heating oil, which in turn would allow the Fortissat project to charge a higher tariff while still offering customers a discount.

6.13.2 Potential Opportunities to Decrease Operating Costs There are a number of factors which may in future reduce the project’s operating costs. It is difficult to predict at this stage the likelihood of any of these occurring, or the impact that they may have on the project economics. These factors include:

• The project relies on electricity to power the heat pumps, and downhole and network pumps. It is possible that electricity cost will reduce over time as increased penetration of renewable energy in the UK lowers the marginal cost of generation. • It may be possible in the future to install on-site electricity generation (e.g. solar PV) in order to lower the electricity cost for the project. • A gradual improvement in minewater chemistry may reduce maintenance costs for the equipment. • Maintenance and infrastructure costs may decrease as heat networks become more common in the UK.

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6.14 CONCLUSIONS FROM FINANCIAL MODELLING

As stated above, due to the early stage of development of the project, the preliminary financial model is based upon numerous estimates and assumptions. Its value lies in its ability to help to identify the key factors that will determine the financial viability of the project. This will help the project team to focus on the areas of highest potential value during the next phase of development. The general conclusions arising from this exercise are as follows:

• A larger heat network generates a healthier return on investment. Even in low heat density rural areas economies of scale are apparent. • A low temperature (< 75 °C) network is preferable despite the higher cost of housing upgrades because the low COP of the heat pumps in a high temperature (> 80 °C) network results in considerable electricity consumption, and most importantly may mean that the project is ineligible for the RHI. This may not be the case for systems that do not depend on RHI revenue or which have incompatible housing upgrades. • If the project can qualify for the geothermal RHI tariff rather than the Water/Ground source heat pump tariff then returns are significantly enhanced. It will be important to determine whether the project will qualify for the geothermal tariff during the next phase. In addition, this consideration will help in the targeting of subsequent geothermal DHN projects as those with mines deeper than 500m are likely to be more attractive. • The cost of a passive treatment facility is highly uncertain until the minewater geochemistry has been analysed.

The specific conclusions drawn for the Fortissat geothermal project are:

• The rural setting and low heat density result in, at best, a marginal economic case for a district heating network. However, a Council-owned “not-for-profit” ESCO should still be viable. Given that this is intended to be a demonstrator project, there is the possibility of grant or other low- cost funding being made available as the drivers of value are not purely financial. • An additional large point heat consumer on the network would significantly improve the financial return, and future developments for the area should be explored. • The network is unlikely to be viable without private sector customers. Engagement with the local community will therefore be critical to the success of the project.

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Chapter 7 – Next Steps

7.1 INTRODUCTION

This chapter sets out the programme and scope of works which form the next steps in evaluating and developing the Fortissat Minewater Geothermal District Heat Network.

There are two fundamental components to this: (i) confirming the heat resource through testing and using the data on flow rates, minewater chemistry and temperature to design how the geothermal energy system will be built and maintained; and (ii) confirming the heat market, and how the required building efficiency measures and connections will be programmed and financed, and how the operational system will be managed. These are distinct, but interdependent, and need to be progressed in parallel. In order to proceed, there will need to be increasing levels of confidence and certainty for both the supply and demand as the knowledge and understanding of how the system will be built and operated is refined.

As with the feasibility stage of the project, the success of the next steps will require an effective partnership approach, involving all the key stakeholders – landowners, the local authority, regulators and the community.

The project stages are divided into ‘Catalyst’, ‘Development’ and ‘Demonstrator’ stages, with the main focus for this ‘Next Steps’ Chapter on the Development Stage. This Report itself represents the culmination of the ‘Catalyst’ stage.

7.2 GEOTHERMAL RESOURCE – CONFIRMING THE HEAT SUPPLY

7.2.1 Landowner Permission A key next step in evaluating the characteristics of the geothermal resource is to drill a test borehole. This requires all interested parties in the proposal to agree on the preferred final location for the test borehole (as the likely location for the production well), and subject to levels of investor security required, potentially the need for an access and exclusivity legal agreement to secure permission for the testing and operational infrastructure. This could also agree outline terms for fees (if any) to the landowner for the option, base rent and any royalty.

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7.2.2 Complex CAR Licence for Test Borehole The depth of the borehole and the duration of the testing period (as well as the potential for the temporary borehole to become the production well should the resource be confirmed) means that a complex CAR licence (relating to deep borehole construction) will be required from SEPA. This requires supporting environmental and technical information (see Technical Appendix A2 for further information). In outline, the CAR licence will require the following supporting information to be prepared: • Details of the proposal o Purpose and use o Construction details • Baseline conditions o Hydrogeology o Receptors • Environmental Monitoring and Contingency Plans • Integrity Testing • Decommissioning and Sealing It is anticipated that a minimum 6 month period will be required to allow for pre-application discussions to define the scope, for the project team to prepare, and for SEPA to review, the supporting information to secure the CAR licence. Taking a conservative approach, the Gantt Chart (See Figure 7.2) allows 12 months.

The initial testing period would have a one month duration, to establish flow rates, minewater temperature and hydrogeochemistry. If at the end of this period the minewater resource was established to be unsuitable for a geothermal system, the borehole would be decommissioned. This would form a project break point.

If the initial testing provides a positive result, further testing would need to be undertaken to design the passive treatment system, over a period of 6 to 12 months (the Gantt Chart (Figure 7.2) allows 12 months). At the end of the testing period, the test borehole would be temporarily sealed, with allowance to permanently decommission and seal in the event the Demonstrator Stage does not proceed.

7.2.3 Complex CAR Licence for Abstraction and Discharge Activities It may be possible, subject to confirming the viability of the minewater as a geothermal resource, for the test borehole to be re-commissioned and put into use as the production well. A complex CAR Licence would be required for this, to control the abstraction and discharge activities.

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A 6 month period is allowed for in the project programme for preparing the licence application, including pre-application engagement with SEPA, during the Development Stage; and a further 4 month period for SEPA to approve the licence in the Demonstrator Stage.

Analysis of minewater chemistry The minewater testing will need to establish the minewater temperature, flow rates, and minewater chemistry, to inform the system design. While some testing has been undertaken of the Kingshill minewater discharge at surface as part of the feasibility study, it is very common for the groundwater contained in flooded mine workings to develop a hydrochemical stratification. The characteristics of the surface minewater may therefore be different to that at the depth which would be used for the geothermal system, and this can only be confirmed through analysis of minewater abstracted at depth from the test borehole. If hydrochemical stratification is found to be present, it is likely that this would be disturbed if active discharge (pumping) commences, resulting in further changes in minewater chemistry. This may suffer initial deterioration with higher sulphate and iron concentrations, which then over a scale of decades progressively improve. It will therefore be necessary, to monitor the minewater chemistry on an ongoing basis during the operation of the geothermal system. This is particularly relevant to the passive minewater treatment scheme, to ensure that the operation and maintenance of the scheme continually provides the levels of minewater treatment required by the terms of the discharge licence.

Minewater discharge – alternatives There are significantly different information requirements at the next steps whether the minewater is to be discharged through re-injection or through a passive minewater treatment system.

a) Passive treatment system Discussions with North Lanarkshire Council, SEPA and the local community, as well as review of previous technical studies and field surveys, have established the complex history and character of existing surface water discharges to the south of Allanton associated with Kingshill No. 1 colliery. The area suffers from complex minewater resurgence issues leading to flooding of land and properties, and there is no CAR licence in place to regulate the discharge to watercourses.

The key stakeholders have recognised that abstraction of minewater and treatment at surface has the potential to alleviate some of these issues, but further evidence would need to be gathered to

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demonstrate this. The evidence would need to address both water quality (regulated by SEPA) and water quantity (regulated by the Local Authority Flood Officer).

Information would need to be submitted to SEPA to demonstrate that the treated minewater discharge shall not exceed the Environmental Quality Standards in the immediate receiving waters for any of the pollutants that may be present in the minewater, and that the Water Framework Directive classification in the South Calder will not be put at risk of deterioration. This will require the early and ongoing engagement between the hydrogeologists on the project team and SEPA to agree the scope and format of the information required.

A Flood Risk Assessment may also be required to demonstrate to the Local Authority that the proposed levels of discharge will not lead to unacceptable potential increases in flood risk. This can be confirmed through early consultation between project team hydrologists and the Local Authority Flood Officer to agree the scope and format of the information required. b) Reinjection A better understanding of the minewater system and potential can be determined through the collection of additional data such as temperature in the mines, flow rates, porosity and permeability of the mines and the surrounding aquifer. In addition, numerical fluid flow modelling can be used to understand better the flow regimes within the mines from the preliminary modelling undertaken at the feasibility stage. Future modelling work would build on these models and entail construction of more complex and realistic fluid flow models of the mine system in order to test parameters, scenarios and geothermal potential. Software is available from the US Environmental Protection Agency which models the hydraulic and water quality behaviour of water distribution piping systems through a network of pipes, nodes (junctions), pumps, valves and storage tanks or reservoirs. Each aspect is conceptually equivalent to elements in the aquifer/minewater system. While designed for water quality, modifications allow for the substitution of water quality elements with water temperature. This will allow flow pathways to be modelled to inform thermal breakthrough calculations and capacity rates for reinjection to determine the preferred locations for the reinjection wells.

Once constructed the model can be continually improved as more data is collected and used to test possible future extraction scenarios and potential future expansion of the minewater geothermal district heating network throughout the lifetime of the project.

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7.3 COMMUNITY ENGAGEMENT – HEAT DEMAND

7.3.1 Engagement Strategy As with any geothermal heat project, the key to unlocking the resource is creating a market for the heat. In the Fortissat ward communities which are potentially accessible to a district heat network powered by the minewater geothermal resource, the main heat users are the local residents. These currently use gas, oil or coal as their primary heat source, and within Allanton (and Shotts) there are a substantial number of properties, both residential and non-residential, in Council ownership. Transitioning a significant proportion of these heat consumers onto a single higher efficiency heat network is the crux of this project, and has the potential to both reduce fuel costs and carbon emissions. The passive minewater treatment option also has the potential for socio-economic and environmental benefits through reducing or preventing the adverse minewater resurgence issues which currently lead to flooding of land and properties.

Therefore, the first and most important next step to developing the local geothermal resource is establishing with key stakeholders that a district heating network is desirable.

The key next steps in establishing a heat network are:

• Engage with NLC elected members and Officers on the findings of this study to identify the most attractive district heating network design option, accounting for financial, social, and environmental benefits; • Develop draft ESCO model, secure draft ownership structure, and ensure ESCO provides affordable heat to willing customers; • Secure ongoing commitment from NLC to the development of the minewater geothermal district heating network. • Define a realistic project programme and develop a consultation strategy which balances the need to keep the community informed of progress but also avoids “consultation fatigue”. As the viability of the network is dependent on achieving a high proportion of connections to maximise the linear heat density of the network, it will be necessary to develop an engagement strategy which reaches every member of the community. As this is so critical to the success of the project, it needs to be carefully considered, but is likely to require face-to-face contact through knocking on every door, followed by direct mail outs and public meetings at key work stages. Identifying ‘local champions’ in each local area who can promote the scheme, and establishing and supporting a community liaison group who can have more regular information

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exchanges with the project team, may be other elements of the engagement strategy which will help secure the success.

This may take some time, but there is no purpose in progressing the development of the geothermal system without a market for the heat.

7.4 DISTRICT HEAT NETWORK (DHN)

7.4.1 Detail design

Heat Network Further detail design will be required on the DHN once the heat customers and programme of building upgrades has been determined. This will need to confirm the detailed alignment of the super-insulated pipe network, taking into account land ownership and existing utilities, and confirm initial calculations on pipe sizing based on further modelling of heat supply requirements.

As the system is designed in detail, the phasing will need to be developed, and integrated with the detailed programme of works for housing stock improvements and installation of Heat Interface Units. Further householder engagement will be necessary to keep individuals informed.

Energy Centre The technical specification of the energy centre (i.e. internal space requirements, access, noise insulation, ventilation, etc.) can be determined by the appointed engineer. In addition, an architect will be required to design the building envelope. As a demonstrator project, the majority of the system is underground, and the design of the building provides the opportunity to be the public image of the development. There are numerous interesting examples of good design, with the energy centres in Aberdeen and Gateshead representing two recent precedents. Further, as the energy centre may well be located at the edge of the village of Allanton, at the gateway to the Kinsghill Local Nature Reserve, there is the potential to integrate visitor facilities or information boards at the energy centre which cover both the geothermal system and the natural and cultural heritage interest.

A 6 month period has been allowed for to procure architectural services, and prepare the design during the Development Stage. A further 2 month period should be allowed for at the Demonstration Stage to secure planning permission.

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Utility Connections for Gas and Electricity to the Energy Centre Utility connections for gas and electricity to the energy centre will be required, and this will require early liaison with the utility providers to confirm connection points, timescales and costs. This process can take several months, so a 6 month period has been allowed for.

Network Rail The proposed DHN extends across north of the railway line to connect housing in this part of Hartwood. This is not necessarily a constraint, but a long-lead time should be accounted for in securing permissions – in principle and for the detail design – from Network Rail. It is therefore recommended that early engagement takes place to ensure this does not disrupt the proposed development programme – the whole process took around 18 months for Aberdeen Heat and Power, and it is recommended a similar timeline be allowed for this project.

7.5 BUSINESS PLAN

7.5.1 ESCO Model Development As detailed in the Business Model Chapter (Chapter 6), it will be important to clarify the business structure of the Special Purpose Vehicle (SPV) which will be used to deliver the project (or alternatively to confirm that the Council will develop, own and operate the project itself). While the advantages and disadvantages of the potential structures are set out in the Business Model Chapter (Chapter 6), further detail will be required on the options and these will then need to be considered internally by the Council (probably both by management staff and elected members), prior to a decision being made. The James Hutton Institute, as the grantee of the Catalyst Stage of the project, will need to engage to establish whether it wishes to remain a partner at the Development and Demonstrator Stages.

The legal structure for the SPV can only be determined once there is clarity from the key stakeholders on the objectives and priorities for the project. While the project has the potential to deliver social, environmental and financial benefits, the priorities for each of these, along with other factors such as risk appetite and duration of commitment, will need to be defined to shape the business model. This process should be complete prior to the preparation of the final business case, and the company constituted prior to commencing the Demonstrator Stage. In this way, project finance, planning permissions, licences and construction contracts can be secured by the intended operating company.

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An 18 month period has been allowed for in the project programme to develop the business model, providing time for the Council to consider and define priorities at both Officer and Member levels; for JHI to consider its role and provide input; and for participation with all other potential stakeholders.

7.5.1 Renewable Heat Incentive To be eligible for the renewable heat incentive (RHI) heat pumps must perform with a COP of 2.9 or greater. In the High Temperature scenarios this is not achieved and the sensitivity of this has been tested in the financial model. It is likely that qualification as a Deep Geothermal heat source and the resultant RHI tariff will influence the economic viability of the project.

7.6 INDICATIVE PROGRAMME

The indicative programme can be viewed on the Gantt chart (Figure 7.2) on the next page.

The Gantt chart indicates the estimated timescale of delivery of the project. The project is anticipated to become operational before Q3 of 2021.

This is a cautious timescale, providing substantial lead time to procure funding for each stage, and taking a precautionary approach to the timescales required for each task. The range is necessary as it is dependent on external factors, the most variable of which will be the ongoing stakeholder engagement to secure commitment to the DHN, and the acquisition of funding.

Only the key tasks are indicated. If a passive minewater treatment facility is planned for construction, a well testing phase of 6 to 12 months is required, with 12 months being preferable, as indicated by the dotted chart in the Gantt chart. If a passive treatment facility is not planned, then the testing phase can be reduced significantly to as little as a few weeks.

The programme has identified key ‘break points’, which will be critical decision points in the development phase.

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Figure 7.1: Indicative project timeline with a focus on the Development Stage

Figure 7.1: Indicative project timeline with a focus on the Development Stage.

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7.7 FUNDING REQUIREMENTS

Given that there are significant variables at this stage, reflecting, amongst other components, the different development options and the need to clarify the scope of engagement, budgets for the Development Stage may vary significantly.

7.7.1 Financing Options The project team will liaise with JHI and NLC to confirm their commitment to the proposal and agree the preferred option for development. Discussions will take place with NLC Housing to clarify the scope and responsibilities for the engagement strategy, and the scope and programme for any building improvements planned in Allanton. This process will quantify the funding commitment (in time and/or money) from North Lanarkshire Council, and determine whether any other funding may be available to cover costs during the development stage. Competitive tenders will be obtained from suitably qualified contractors for key work stages, to provide further clarity on Development Stage budgets.

It is recommended that the Development Stage be funded separately from the Demonstrator Stage. This could mean that an SPV is set up to progress the Development Stage which will bear the majority of the project risk. On completion of the Development Stage, the SPV can then be refinanced as part of the ESCO formation which will need to acquire the remaining funds for construction.

Several funding sources might be approached to support the Demonstrator stage. These include the Low Carbon Infrastructure Transition Programme, District Heating Loan Fund, Renewable Energy Investment Fund and European Infrastructure Funds. Procurement would need to be subject to the proposed delivery vehicle constituted for the delivery of the programme and take in to account all consenting and potential planning restrictions arising within the proposed area.

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