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Feasibility Report of Fortissat Community Minewater Geothermal Energy District Heating Network

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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.

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.

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 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 trajectory[4]:

  • 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
    • 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?
  • 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
    • How could the delivery structure evolve and what are the potential drivers for change?
    • 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.

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/kWh[5]. 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:
    • Whether this cost varies between different types of off-takers;
    • Whether or not cost varies with time of day, season, etcetera;
    • 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 higher unit cost than the Business as Usual alternative while offering customers a reduction in their annual energy bill.

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;
  • 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 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 / Parsons Brinckerhoff.

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 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.

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 DECC[6], 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 network[7]. DECC's Investor guide to Heat Networks[8] includes the following graphic illustrating the relationship between control and risk.

Figure 6.3: Relationship of control to risk (source DECC[9], public sector information licensed under Open Government Licence v3.0 www.nationalarchives.gov.uk/doc/open-government-licence/).

Figure 6.3: Relationship of control to risk

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:

Table 6.1: Summary of the advantages and disadvantages of potential ESCO structures.

Council provision - no ESCO

100% Council owned ESCO

Joint Venture ("JV") ESCO

Concession arrangement

Administration

  • No management of project level entities required
  • Administration of ESCO may impose an administrative burden on Council
  • Council will need to ensure that it maintains oversight of ESCO
  • Relationship between partners governed by a Joint Venture Agreement ("JVA") or Shareholders' Agreement ("SA"), meaning that decision making can be complicated
  • Deadlock is possible
  • Council will need to monitor compliance with concession agreement

Resourcing

  • Council must resource project on an ongoing basis, including operations, maintenance, billing, etc.
  • ESCO will have own Board of Directors, management team and employees
  • Council will need to monitor JV and ensure compliance with JVA or SA
  • JV partners can pool resources
  • Organising and managing competition for concession could require significant Council resources
  • Council resources required to monitor compliance with concession agreement
  • ESCO resourcing managed by service provider

Stakeholder involvement

  • Limited scope for stakeholder involvement
  • Opportunity for stakeholder involvement
  • Potential opportunity for stakeholder involvement
  • Limited scope for stakeholder involvement

Funding options

  • Council resources and existing public sector routes remain open
  • External finance such as project finance unlikely to be possible
  • Council resources and existing public sector routes may remain open
  • External finance such as project finance available
  • Costs can be shared between the partners
  • Public sector routes may not be available
  • External finance such as project finance available
  • External finance such as project finance available

Delivery risk

  • Entirely borne by Council
  • Borne by ESCO rather than Council
  • Borne by ESCO rather than Council
  • Shared between JV partners
  • Borne by service provider

Funding risk

  • Entirely borne by Council
  • Borne by ESCO rather than Council
  • Borne by ESCO rather than Council
  • Shared between JV partners
  • Borne by service provider

Operational risk

  • Entirely borne by Council
  • Borne by ESCO rather than Council
  • Borne by ESCO rather than Council
  • Shared between JV partners
  • Borne by service provider
  • Risk that service levels may deteriorate near the end of the concession period

Operational flexibility

  • Council can adapt services as its objectives evolve
  • Council and other stakeholders can align ESCO objectives with their own
  • ESCO can contract with multiple counterparties for Energy Centre, DHN, etc.
  • ESCO could eventually provide additional services
  • JV partners can align ESCO objectives with their own
  • ESCO can contract with multiple counterparties for Energy Centre, DHN, etc.
  • ESCO could eventually provide additional services
  • Decision making structure means that ESCO could potentially act counter to the public interest
  • Service provide will most likely be operating "for profit" and so may act counter to the public interest
  • May be difficult to amend concession agreement if Council objectives change

Exit options

  • Difficult to sell or spin off project in the future
  • Flexibility around exit strategy
  • Ability to exit will depend on provisions contained within the JVA or SA
  • May be difficult to change service provider in the event of substandard performance

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.

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:

  • 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 minewater 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:

Table 6.2: District Heating Network Options

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

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

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.

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

Tariff name

Eligible technology

Eligible sizes

Tariffs

Water/Ground-source heat pumps

Ground-source heat pumps & Water-source heat pumps

all capacities Tier 1

Tier 1

8.84

Tier 2

2.64

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.

Table 6.4: CAPEX and OPEX figures as input to the financial model, for Options 1A, 1B, 1C and 2 low Temp.

Option 1a

700 kW Pump

Low Temp (75°C)

Small Network

Option 1b

1 MW Pump

Low Temp (75°C)

Medium Network

Option 1c

2 MW Pump

Low Temp (75°C)

Large Network

Option 2

2 MW Pump

Low Temp (75°C)

Large 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 measures

29,450

45,600

78,850

78,850

Passive treatment system

1,200,000

1,200,000

1,200,000

-

Injection wells

-

-

-

1,000,000

Injection well downhole pumps

-

-

-

15,000

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 annum)

121,778

144,299

232,227

217,867

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.

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

Design Option: HP Size, Temp

Descriptor

20 year net cash (£m)

Project IRR (%)

CAPEX (£m)

COP

% Debt

1A: 700kW Pump, 75°C

LT small network + passive treatment

-3.1

0.0

5.7

3.34

50

1B: 1MW Pump, 75°C

LT medium network + passive treatment

-0.8

0.0

7.2

3.39

50

1C: 2MW Pump, 75°C

LT large network + passive treatment

3.2

1.6

10.6

3.58

60

2: 2MW Pump, 75°C

LT large network + injection wells

3.4

1.7

10.8

3.58

60

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:

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

Design Option: HP Size, Temp

Descriptor

20 year net cash (£m)

Project IRR (%)

CAPEX (£m)

COP

% Debt

1A: 700kW Pump, 75°C

LT small network + passive treatment

-1.7

0.0

5.7

3.34

50

1B: 1MW Pump, 75°C

LT medium network + passive treatment

0.6

0.0

7.2

3.39

50

1C: 2MW Pump, 75°C

LT large network + passive treatment

4.6

2.7

10.6

3.58

60

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.

Table 6.7: Sensitivity testing on Option 1C for impact of key parameters on project IRR

Sensitivity

IRR

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%

Figure 6.4: Tornado diagram illustrating the results of Table 6.7

Figure 6.4: Tornado diagram illustrating the results of Table 6.7

Table 6.8: Sensitivity testing on Option 1C for impact of key parameters on 20 year aggregate cash flow (NCF)

Sensitivity

20 year total NCF

High (£million)

Low(£million)

Base

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

Figure 6.5: Tornado diagram illustrating the results of Table 6.8

Figure 6.5: Tornado diagram illustrating the results of Table 6.8

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:

Table 6.9: Capital equipment overhaul costs

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

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.

Table 6.10: Long term cash flow model

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

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:

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

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

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.

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.

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.