7 Costs, Financing and Benefits Assessment for Deep Geothermal Energy Developments
In considering how best to take forward the commercialisation of geothermal energy in Scotland, it is important to identify the potential benefits that geothermal energy could deliver to Scotland, but also make an assessment of the likely costs, consider the potential risks, and review the requirement for financial support mechanisms.
These have been considered with options for unlocking the possible range of potential geothermal developments in Scotland.
7.2 The Benefits of Developing the Deep Geothermal Energy Potential
There are many direct and indirect benefits to utilising geothermal energy including the following:
(a) As a potential source of energy, geothermal energy -
- Is a low-carbon source of energy and could help Scotland reduce carbon emissions and build a sustainable low carbon economy in order to meet the legislative requirements for emissions reductions.
- Could increase the use of renewable heat to help exceed the targets set out in the 2020 Routemap for Renewable Energy in Scotland.
- Could help to exceed the targets for renewable electricity production.
- Could become a viable alternative source of energy, improving local and national energy security and reducing reliance on external sources of energy.
- Holds the potential for developing relatively small-scale energy supplies close to demand, reducing transmission losses.
- Has low visual impacts and the majority of the surface plant can be accommodated below ground level if necessary to reduce visual impact further.
- Is relatively quiet with no visual emissions meaning that it can be sited un-obtrusively in mixed-use or even residential areas.
- Has a low impact on the water environment, with water extracted and re-injected in a cycle.
(b) Specifically as a potential source of heat, geothermal energy -
- Can provide heat directly to homes, businesses and industry via a heat network.
- Does not suffer from conversion inefficiencies.
- In central Scotland, mine water resources may be present close to areas of fuel poverty, a key area that the Scottish Government wishes to address.
(c) As a potential source of power, geothermal energy -
- Can almost uniquely provide base-load from a renewable resource.
- Is always and consistently available - excluding time for maintenance and repair - but with more than one plant this could be scheduled and coordinated.
- Is switchable to the load (the output can be adjusted up or down) within the operation parameters of the generating plant.
- Its conversion can be switched on and off.
- Co-produces heat which can be utilised.
(d) The key indirect potential benefits of developing the geothermal energy sector in Scotland include:
- Regeneration of brownfield sites, including in former mining and industrial areas.
- Provision skilled employment opportunities, with potential cross-over and skills transfer from the oil and gas, manufacturing and traditional energy-generation sectors.
- It could push Scotland towards the forefront in the technology required for exploiting deep geothermal resources, particularly in areas previously considered as marginal or even not viable.
- Presents the opportunity to provide environmental benefits, for instance treating poor quality abstracted groundwater before re-injection.
7.3 Skills Transfer and The Existing Scottish Skills Base
In their report for Scottish Enterprise, SKM carried out a high-level review of the potential for development of a Scottish supply chain from existing industry skills, notably the oil and gas sector ( SKM, 2012b).
These included scientific, engineering (oil & gas), design engineering, construction, operations and non-technical. SKM also highlighted that geothermal energy technology is unique, with unique risks, and recommended that a further more detailed study should be carried out.
To the author's knowledge, there are currently no Scottish-based specialist deep geothermal energy development companies. It is acknowledged that there are a number of Scottish-based companies, or companies with a presence in Scotland, operating in the GSHP market. It is considered that some of these companies could up-scale in the future to meet a demand for geothermal heat production schemes, many of which would utilise heat pump technology.
To date the international geothermal industry has concentrated on developing easily accessible high-temperature resources. It is considered that there is a significant opportunity for Scotland to develop unique skills in developing low temperature geothermal resources, and then exporting these skills internationally, to countries with similar types of geothermal resource.
Costs should reduce over time with increasing resource knowledge, technical experience and competition in the industry. Conversely costs may increase if there is increased international demand for geothermal skills and specialist equipment.
7.4 Assessment of Typical Costs for Deep Geothermal Energy
Geothermal energy developments cover a very wide range of scales with orders of magnitude difference in outputs, from relatively shallow single boreholes which also utilise heat pumps (typical outputs from 0.02kWth to 0.05kWth per metre of installed borehole) to potentially 10's MWth and 10's MWe for a very deep petrothermal system (say 5km).
The range of costs for exploring, appraising, developing, operating and decommissioning the various scales of development is correspondingly also very wide.
Cost data on the capital and operating ( CAPEX and OPEX) costs for geothermal energy has been taken from various sources.
7.4.1 The Quality of Available Cost Data
The current availability of cost data relating to geothermal energy in Scotland and / or the wider UK is low. This is for a number of reasons:
- Geothermal developments are not currently common in Scotland or the UK.
- There is only one existing operating deep geothermal development in the UK; part of the Southampton district heating scheme which has been operational since the 1980s and was largely publically funded.
- True actual outturn costs (both CAPEX and OPEX) are generally commercially sensitive and are not widely published. This is particularly true where there has been significant overspend due to the high risks involved.
- Globally, figures are more widely available for traditional high-temperature power schemes, as opposed to a range of lower temperature heat only and moderate temperature heat and power schemes as envisaged in Scotland.
Detailed costs and risks analysis is not currently possible based on the available data, however, estimation of costs has been made to illustrate likely magnitude of CAPEX costs and cost per installed Megawatt (MW).
Caution needs to be exercised when reviewing the benefits of geothermal energy in other countries, including capacity factors and levelised costs for power production, as the vast majority of developments across the globe have been developed for electricity generation using high temperature resources (>150°C) that are relatively close to the surface. Costs increase significantly per MWe generated for lower temperatures resources and with increasing depth to resources. Binary technology can be used to generate electricity theoretically down to geothermal fluid temperatures of <100°C. However, the efficiency of such systems decreases significantly with reducing temperatures.
Scotland does not have any high temperature resources close to the surface. Such resources may exist at depths of circa 5km (or more) but this has not been proven to date. High temperature resources may be at a depth beyond the current limit of commercially available technology.
There is also a lack of suitable data available for shallower resources, i.e. those at less than 200m depth.
7.4.2 Review of Costs and Estimated Costs
For this study, AECOM has undertaken a high-level review of available costs for geothermal energy projects to provide an understanding of the scale and range of costs involved.
Costs and estimated costs were gathered from the following sources:
- Internet search for published costs associated the geothermal energy globally.
- Review of costs provided for various deep geothermal schemes in England from presentations at the EGS Energy 2012 UK Geothermal Symposium, London (15 October 2012).
- Review of estimated costs in SKM's 2012 report for Scottish Enterprise.
- AECOM internal enquiries for projects in Asia and New Zealand.
7.4.3 Costs for Heat-Only Projects
Table 7.1 summarises reported available costs data for heat-only projects and these are illustrated in Figure 7.1.
Table 7.1 Published and reported CAPEX costs for geothermal energy developments: heat-only projects
|Location||Company||Size||Nr. of production wells||Depth of production wells||Approx. Cost / Estimated Cost||Description &Source|
|Shiremoor, North Tyneside, UK||Cluff Geothermal Ltd||3-5 MWth||2||2.0km||£ TBC||Proposed heat-only. Presentation by Cluff Geothermal Ltd at the EGS Energy UK Geothermal Symposium, 15 October 2012.|
|Manchester, UK||GT Energy||9.5 MWth||2||3.2km||£ TBC||Proposed heat-only. Presentation by GT Energy Ltd at the EGS Energy UK Geothermal Symposium, 15 October 2012.|
|Szentlorinc, Hungary||PannErgy||3 MWth||1||1.8km||£2.8m||Hungary's largest operational geothermal heating facility from a very complex geology. PannErgy May 2012, Geothermal Energy.|
|Madrid, Spain||Petratherm Limited||8 MWth||Unknown||2.2 - 2.8km||£7.9m||At least 75°C; Flow rate of 200 cubic metres per hour. Petratherm, 2008, "Geo-Madrid District Heating Project - Well Re-entry Yields 30% Cost Savings" http://www.petratherm.com.au/projects/mainland-spain|
|Cheshire||Unknown||11.5||Unknown||3.4||£18m||Conceptual. Hydrothermal direct heat. From SKM 2012a.|
|Wessex||Unknown||10||Unknown||3.0||£16m||Conceptual. Hydrothermal direct heat. From SKM 2012a.|
|Lough Neagh||Unknown||5||Unknown||2||£10m||Conceptual. Hydrothermal direct heat. From SKM 2012a.|
|Newcastle||Unknown||4||Unknown||1.5||£8m||Conceptual. Hydrothermal heat pump. From SKM 2012a.|
|Herleen, NL||Unknown||0.7 MWth heating / 1.0 MWth cooling||5||0.8||£16m||http://ec.europa.eu/environment/ecoap/about-eco-innovation/good-practices/netherlands/328_en.htm. The costs are thought to include a district heating system and back-up gas boilers for peak demand.|
Figure 7.1 Heat-Only Projects (a) CAPEX Cost versus Thermal Production Capacity and versus Depth, and (b) Thermal Production Capacity versus Depth
Figure 7.1 demonstrates that based on the available reported and estimated CAPEX costs for heat-only developments, there is an apparent relationship of both increasing costs and increasing capacity with increasing depth, as would be expected. Relative capacity appears to increase at a slightly greater rate than costs with depth. Relative capacity appears to significantly increase with depth. It appears therefore that increasing the depth of the geothermal well increases the efficiency for this type of project.
Caution is required in drawing too firm conclusions from this due to the potential unreliability of the data from a limited number of examples, and they should not be used for assessing likely CAPEX costs due to the high number of variables involved. They are, however, considered to provide a preliminary indication of the general trends.
The costs for the Herleen mine water project of circa £16m are thought to include a district heating system and back-up gas boilers for peak demand. The system serves approximately 200 houses, shops, offices, a library and a supermarket. All the buildings contain heating and cooling systems designed to run on energy from the mine water. Calculations estimate that the concept offers a 55% CO 2 reduction.
7.4.4 Costs for Combined Electricity Generation and Heat Projects (Petro and Hydrothermal Resources)
Table 7.2 summarises the available costs data for combined electricity generation and heat projects. These are illustrated in Figures 7.2 and 7.3, for hydrothermal and petrothermal resources respectively.
Table 7.2 Published and reported costs for geothermal energy developments: Electricity Generation and Heat projects (Petrothermal and Hydrothermal)
|Location||Company||Size||Nr. of production wells||Depth of production wells||Approx. Cost / Estimated Cost||Description &Source|
|NE Scotland ( TBC)||SKM/ SE||0.7 MWe||4||5km||£50.5m||Proposed conceptual deep geothermal demonstrator project for Scottish Enterprise using a petrothermal source with stimulation, ' EGS'. Estimated additional £27.5 million OPEX costs ( SKM, 2012a).|
|United Downs, Redruth, Cornwall, UK||Geothermal Engineering Ltd||7 MWe 50 MWth||3||4.5km||£50m||Proposed power & heat, petrothermal ( EGS) scheme. Geothermal Engineering Ltd at the EGS Energy UK Geothermal Symposium, 15 October 2012|
|The Eden Project, Cornwall, UK||EGS Energy Ltd / The Eden Project||3-4 MWe||2||4.0km||£ TBC||Proposed power & heat, petrothermal ( EGS). Presentation by EGS Energy Ltd at the EGS Energy UK Geothermal Symposium, 15 October 2012.|
|Wessex||Unknown||0.75 MWe 5.5 MWth||Unknown||2.5||£14m||Conceptual. Hydrothermal heat and power. From SKM 2012a.|
|Wessex||Unknown||1.5 MWe 11 MWth||Unknown||2.5||£27m||Conceptual. Hydrothermal heat and power. From SKM 2012a.|
|Cheshire||Unknown||0.75 MWe 5.5 MWth||Unknown||4.3||£22m||Conceptual. Hydrothermal heat and power. From SKM 2012a.|
|Cheshire||Unknown||1.5 MWe 11 MWth||Unknown||4.3||£43m||Conceptual. Hydrothermal heat and power. From SKM 2012a.|
|Lake District||Unknown||5 MWe 10 MWth||Unknown||5.0||£59m||Conceptual. Petrothermal heat and power. From SKM 2012a.|
Figure 7.2 Combined Electricity Generation and Heat Production Projects for Hydrothermal and Petrothermal Sources (a) CAPEX Cost versus Total Production Capacity and versus Depth, and (b) Total Production Capacity versus Depth.
Figure 7.2 demonstrates that based on the available reported and estimated CAPEX costs for combined electricity generation and heat-producing developments, there is an apparent relationship of both increasing costs and increasing capacity with increasing depth, as would be expected. Costs appear to increase at a slightly greater rate than relative capacity with depth.
Relative capacity appears to increase linearly with depth. It appears therefore that increasing the depth of the geothermal well increases the capacity but also disproportionately increases the costs for this type of project. This may be due to the effect of the rate of drilling costs increasing with depth.
The proposed conceptual deep geothermal demonstrator project for Scottish Enterprise has been excluded from Figure 7.2 as no output for heat is provided and it is non-commercial project. The proposed United Downs project has also been excluded from Figure 7.2 as the output for heat of circa 50MW significantly skews the graph. The proposed development at the Eden Project has been excluded as estimated costs are not available. This means that only one proposed combined electricity generation and heat-producing development for a petrothermal source is represented on the graph; the proposed Lake District scheme.
Caution is required in drawing too firm conclusions from this due to the potential unreliability of the data from a limited number of examples, and they should not be used for assessing likely CAPEX costs due to the high number of variables involved (note the scattered nature of the data). They are, however, considered to provide an indication of the general trends.
7.4.5 Costs from the German FiT Review for Geothermal Energy
A recent review carried out in Germany examined the costs of six power producing projects, which were all <5MWe. The drilling costs were in the range of £17m to 24m per project. Development and plant costs for the six projects ranged from £19m to 27m.
7.4.6 Typical Costs from New Zealand and South East Asia
AECOM's operations in New Zealand have been responsible for installation of over 4500MWe over 30 years. The costs provide a contrast for comparison; these costs are from a mature market in south east Asia and New Zealand, with a plethora of high temperature resources available. Table 7.3 indicates costs for typical
Table 7.3 Published and reported costs for geothermal energy power developments in New Zealand and South-East Asia from AECOM
|Company||Size||Nr. of production wells||Depth of production wells||Approx. Cost / Estimated Cost||Description &Source|
|AECOM||40 MWe||14||2.0 - 2.5 km||£41.1m||Typical example only, high temperature (steam).|
|AECOM||60 MWe||18||2.0 - 2.5 km||£50.4m||Typical example only, high temperature (steam).|
|AECOM||10 MWe||-||-||£26m||Typical example only, 'low' temperature 100% brine plant. Note 'low' is classified as circa 230°C in NZ.|
|AECOM||60 MWe||-||-||£109m||Typical example only, 'low' temperature 100% brine plant. Note 'low' is classified as circa 230°C in NZ.|
These figures clearly demonstrate the significant difference in typical costs for developing geothermal between what is classified regionally as high temperature (300°C) and geothermal resources that are defined in this high-temperature context as 'low' temperature (230°C).
7.4.7 Summary of Costs for Installed Capacity for Geothermal Energy
From the information gathered, Table 7.4 summarises the estimated CAPEX costs per MW for installed capacity for deep geothermal energy.
Table 7.4 - Estimated Costs per MW for installed capacity for deep geothermal energy
|Scenario||Typical Cost Installed Capacity|
|Heat only ( UK / Europe), <1km||Data unavailable|
|Heat only ( UK / Europe), >1km||£0.93M to £2.00M/MW|
|Power & heat - hydrothermal ( UK / Europe)||£4.12M to 28.67M/MW|
|Power & heat - petrothermal ( UK / Europe)||£7.14M to 28.67M/MW|
|Power & heat - German FiT review||£7.2M to £10.2M/MW|
|Power - Steam (New Zealand)||£0.8M to £1.0M/MW|
|Power - Brine (New Zealand)||£1.8M to £2.6M/MW|
|Onshore wind ( UK) - for comparison (1)||£1.4M/MW|
|Offshore wind ( UK) - for comparison (1)||£3.0M/MW|
(1) based on figures on figures from BWEA (now Renewables UK) in the Scottish Enterprise, Energy Market Forecast Costs for The Wind Market, 2009 to 2014, published in 2010.
It can be seen that relative to other available and established renewables in the UK, deep geothermal energy is currently relatively expensive per installed MW for combined electricity and heat developments, but that the costs of heat-only developments may be similar to the current costs of onshore wind.
It is anticipated that costs would decrease and with market development and maturity and as the resources are proved.
7.4.8 Estimated Levelised Costs of Geothermal Energy
The European Geothermal Energy Council ( EGEC) published a policy paper in June 2013 regarding financing geothermal energy which contains the a summary of levelised costs of geothermal energy and predicts costs for 2030, on a Europe-wide basis (see Table 7.5).
Table 7.5 - Levelised Costs for Geothermal Energy (quoted in EGEC, 2013)
|Type||Source / Use||Levelised Costs Range 2012 (€/kWh)||Average Levelised Costs 2012 (€/kWh)||Predicted Average Levelised Costs 2030 (€/kWh)|
|Electricity Generation||Electricity Conventional - high T||0.05 to 0.09||0.07||0.03|
|Low temperature and small high T plants||0.10 to 0.20||0.15||0.07|
|Enhanced Geothermal Systems||0.20 to 0.30||0.25||0.07|
|Heat Production||Geothermal HP||0.05 to 0.30||0.08||0.05|
|Geothermal DH||0.02 to 0.20||0.06||0.04|
|Geothermal direct uses||0.04 to 0.10||0.05||0.04|
7.4.9 Drilling Costs versus Total Project Costs for Geothermal Energy
For deep geothermal energy, the cost of drilling exploratory and production wells is high and is also a high percentage of the capital costs for the project. In addition, the size of the available resource is not known until the initial exploratory well is drilled.
The typical cost split for deep geothermal from the German FiT review is illustrated in Figure 7.4 and, for comparison, the cost split for onshore wind is also shown. It can be seen that the costs for proving the resource are much higher for deep geothermal than for wind relative to other costs.
This makes geothermal appear to be a relatively high risk for investors and can make project funding difficult without grant support.
Figure 7.4 - Typical Percentage Cost Split for Resource Establishment versus Other Costs
7.4.10 Operation and Maintenance Costs and Decommissioning costs
It has not been possible to establish independent operation and maintenance ( OPEX) and decommissioning costs for deep geothermal projects as suitable data is not readily available.
SKM estimate (based on knowledge and previous experience) that the OPEX for
For decommissioning it is anticipated that various scenarios exist, including:
- Declining production (depleted resource) to below economic levels and plant at the end of its operational life - decommission and remove plant, grout production wells over full depth.
- Non-depleted or only partially depleted resource to operating at economic levels but plant at the end of its operational life - decommission and replace plant, renovate production wells.
For the existing Southampton geothermal well, comprising a single 1800m deep extraction well (with discharge to surface water), the turbine-driven pump operated from the mid 1980s to 2006 (approximately 20 years). The pump is currently being replaced with grant assistance from DECC and is scheduled to be operational again in 2013.
7.4.11 Predicted Capacity Factors and Base-load from Geothermal Energy
To be regarded as providing base-load, energy sources generally need to have a capacity factor of 70% or greater.
Capacity factors for geothermal energy power production are often quoted at rates of 85% or more, and these figures are used in finance models, including when seeking investment in proposed projects, and determining revenue from projects.
In October 2011, Bloomberg New Energy Finance ( BNEF) released a report on Geothermal Plant Performance and comparing the performance of 71 geothermal fields globally (source http://www.thinkgeoenergy.com). The purpose of the study was to determine the actual level of capacity factors. For a global average, BNEF quotes a capacity factor of 73% which is below the figures often quoted and used in financial models.
Of potential concern in a Scottish context is that the majority of the geothermal resources included in the study are high temperature resources and it was reported by BNEF that statistically capacity factors were found to decrease at a rate of around 1% per decrease in temperature of 10°C. It was also noted that there was evidence of decreasing productivity of geothermal fields over time in older plants, possibly due to depletion of the resource and ageing infrastructure.
If capacity factors are actually lower than initially estimated it may lead to issues with fulfilling power supply agreements and decrease revenues, which could lead to difficulties meeting servicing debt and interest payments.
7.5 Financing Assessment
7.5.1 Risk / Benefit Imbalance
There is considered to be a current a risk / benefit imbalance for determining the level of support required for deep geothermal projects. Revenue support levels are set at the limit of what is financeable at the point of financial close. However, the revenue level can only be projected when resource is fully understood. For the deeper geothermal projects in the Scotland (or the UK) the resource is poorly understood. It is therefore difficult to set an appropriate revenue level.
For geothermal energy, as for oil and gas, there is a high level of risk in early phase of resource evaluation. However, in the oil and gas industry the cost levels are driven by well understood and competitive contracting rates.
A key challenge is how to encourage or incentivise early stage exploration of deep geothermal resources. Without this early stage exploration the deep geothermal energy industry will not develop in Scotland.
7.5.2 Current Support Mechanisms for Geothermal Energy
In the UK, electrical power production from deep geothermal energy is currently supported at a level of 2.0 ROCs (Renewable Obligation Certificates), this is approximately equivalent to 13.5p/kW. It was announced by DECC in October 2012 that they propose to reduce this to 1.8 ROCs in 2017.
For comparison, the following are the ROCs available for other forms of renewable energy:
- Onshore Wind (reducing to 0.9 in 2017)
- Geothermal (reducing to 1.8 in 2017)
- Offshore Wind (reducing to 1.8 in 2017)
- PV (reducing to 1.5 in 2017)
- Tidal (increasing to 5 in 2017)
- Wave (change to5 in 2017)
Of these renewable energy technologies, only geothermal is capable of supplying base-load.
The current RHI (Renewable Heat Incentive) is set at a level of 3p/kWth for >100kWth capacity.
7.5.3 Comparison with Support Mechanisms in Other Countries
Other European nations with establishing deep geothermal industries have the following levels of support available for power generation:
- Germany FiT (all sizes):
- Current ~20p/kWh (Up from ~12.5p in 2007)
- Bonus of 3.5p for using EGS
- Belgium, Slovakia, Croatia, Czech:
It is evident that the levels of support available in Germany, where similar geothermal resources are available to the UK, have stimulated significant development of the geothermal industry.
7.5.4 Current Proposed Support Mechanisms
It was announced by DECC in October 2012 that this would reduce from 2.0 in 2012 to 1.8 by 2017. Levels of proposed future FiT's have not currently been announced.
DECC are currently consulting on a proposed a RHI (Renewable Heat Incentive) level of support of 5p/kWh for 'deep' geothermal (categorised by DECC as >500m depth).
7.5.5 Effectiveness of Support Mechanisms
From the project stakeholder workshop it was generally considered that ROCs are a good support mechanism for development of the deep geothermal (power and heat) industry if they are pitched at right level.
It is questioned whether geothermal, as a developing market, would realistically be able to take advantage of the current UK level of support of 2 ROCs, as it is likely that much activity will take place post-2013 (with support reducing to 1.8 ROCs in 2017). A ROC level of 4 to 5 was considered to be more reasonable and realistic for deep geothermal as an emerging technology, similar to wave / tidal, but that has the potential to provide base-load.
Another concern for potential developers of geothermal energy in Scotland is that ROCs should be compatible with other countries, particularly European countries (including Germany), as projects are competing in the international market for investment.
Proposed Renewable Heat Incentive
It is considered that the RHI level of 5p/kWh currently proposed by DECC could make the business case for deep geothermal heat developments (>500m depth) sustainable.
Exploration Risk Insurance
Schemes in other countries, generally backed by exploration risk insurance, can also receive grant-funding without affecting the receipt of support mechanisms, making them more attractive to investors. Additionally, the industry and definition of resources is significantly more advanced reducing the risks further for investors.
7.5.6 Future Support Mechanisms Structure
The UK Government announced in its Electricity Market Reform ( EMR) white paper in July 2012 that it was replacing the existing Renewable Obligation Certificate ( ROC) system for subsidising low carbon electricity sources.
From 2017/18 new projects will instead use feed in tariffs (FiT's), similar to other countries but combined with a concept called Contracts for Difference (CfD) . Under FiT's, electricity producers will be paid for each MWh of renewable power that they produce (the 'strike price'), the rates for which are yet to be decided, with an adjustment to ensure the producer does not lose out from changes in the actual price of electricity. The UK government predicts this will save 4% from consumer bills by 2030.
In essence, therefore, the ongoing legislation development related to renewables support can and will have an uncertain and significant impact on how cost/benefits are estimated at any given time for geothermal power schemes, which at this stage in the development of the technology depend to a large extent on government support mechanisms to become a commercially viable option.
7.5.7 Interventions used in Germany
In Germany, the MAP (Marktanreizprogramm) provides Federal and State-backed grants and reduced-rate loans to lower the early-stage risks of deep geothermal projects. It is focused on heat but is also available for power. The aim of the MAP is to stimulate the use of renewable heat and lay the foundations for more private investment.
Also available in most countries with a developing geothermal industry is state-backed exploration (drilling) risk insurance. This is insurance against failure to prove the resource. In Germany, exploration risk insurance is available from the federal / state development bank (KfW Bankengruppe) but is also backed by the German insurance industry.
7.6 Proposed Interventions to Encourage Increased Activity in Scotland
Revenue support has a track record of success in UK in developing renewable technologies. It is possible that with appropriate revenue support mechanisms in place that the market will lead to the development of the deep geothermal industry in Scotland but this may be at a rate that is slower than desirable. There is a risk that if deep geothermal cannot establish itself then it will be seen as non-viable and not be prioritised for support in future.
In contrast to the UK, Germany has increased its revenue support and also introduced other supports mechanisms which have kick-started activity. The following key potential support interventions have been identified from Germany:
- Provide Grants / Loans to Fund Early Stages - this would provide funding to assist with covering the risky exploration drilling phase. In the case of grants these could be repayable when resource is established (through re-financing) or repaid over the life of the project out of generated revenues.
- State-Backed Exploration Risk Insurance to Cover Early Stage Drilling - Pays out if the predicted resource is not proven.
It is noted that all intervention (beyond ROC/FiT/ RHI) may be technically and contractually complex to implement.
It is noted that any Scottish or UK state interventions or support must be considered in the context of European State Aid regulations and must not infringe these.
Figure 7.5 is a schematic illustration of the anticipated inter-relationship between cost, resource and technical knowledge (and experience) over time, comparing geothermal energy from mine workings and HDR sources, and indicating the theoretical point of viability. This illustrates that geothermal energy from mine workings sources is likely to become viable a significant amount of time before geothermal energy from geothermal energy from HDR sources.
Figure 7.5 Schematic illustration of the anticipated relationships between cost, knowledge and viability over time, comparing geothermal energy from mine workings and HDR sources.
As the geothermal resource evidence base increases, the potential risks will be reduced, and it will be easier to get private funding without the requirement for intervention. It is anticipated that the required revenue support mechanisms and interventions could reduce as the cost of financing reduces.
A significant point to note is that developing geothermal resources for heat-only is much less risky than for power production. Heat-only schemes should be advanced as the priority. The experience gained in developing these schemes will help establish the skills required and investor confidence before tackling the much deeper power and heat schemes.
7.7 Exploration Risk Insurance
7.7.1 The Requirement for Exploration Risk Insurance
The provision of exploration risk insurance is considered to be a necessary requirement for the early stages of the development of the deep geothermal energy industry in Scotland, to attract investment and to be able to compete at an international level.
Its usefulness for shallower and / or lower-risk heat-only schemes is less clear. A view expressed by a developer at the project stakeholder workshop stated that it was not required for the type of schemes that they were developing and actually added cost onto the bottom line of the project.
7.7.2 Potential State Aid Issues Relating to Exploration Risk Insurance
The Scottish Government's State Aid Unit ( SAU) were consulted on the issue of whether or not a Government-backed exploration risk insurance scheme would constitute State Aid. The SAU stated that the provision of risk insurance would essentially entail the Scottish Government 'guaranteeing' the cost of such an investment, therefore the guidelines which would appear to provide the best fit with such an aim are those on State Aid in the form of Guarantees (Ref. 2008/C 155/02).
Section 3.2 of this provides the basic rules on guarantees, including "(c) The guarantee does not cover more than 80% of the outstanding loan or other financial obligation" and part (d) then explains the need to set a market-oriented price for the guarantee and how this should be done.
The SAU concluded that if these guidelines are followed, then the (European) Commission considers that there will be no State Aid present as the beneficiary is not being conferred an advantage beyond that which the market might reasonably provide.
It therefore appears that the Scottish Government would potentially be able to offer an exploration risk insurance scheme (in the form of a guarantee) up to the value of 80% of the cost without infringing State Aid rules.
7.7.3 Potential State Funding of Exploration Risk Insurance
The funding of risk insurance scheme by the Scottish Government is however a complex issue. The Scottish Government have advised that, under the existing financing system, the value of the exploration risk insurance would need to be set aside within their budget, whether or not it needed to pay out. This would almost certainly impact on capital support for other technologies and initiatives (not just renewable technologies).
It is a matter of choice and priority for the Scottish Government whether they would support deep geothermal in this manner, for example instead of supporting another form of renewable energy in some way. It is anticipated that this would most likely be decided on the predicted return for the level of 'investment' which may appear to be less favourable for deep geothermal energy projects (at least in the short term), due to the high costs and risks involved, than for other renewable technologies. It may therefore be difficult for the Scottish Government to justify 'support' of deep geothermal energy projects by providing exploration risk insurance.
7.7.4 Proposed European Geothermal Risk Insurance Fund ( EGRIF)
The European Geothermal Energy Council ( EGEC) have recognised that the lack of commercially affordable exploration risk insurance, either public or private, is holding back development of geothermal resources in Europe. This is partly due to the current lack of the knowledge of the resource which leads to a view by insurers of it being high risk.
In their policy paper on Financing Geothermal Energy ( EGEC, 2013). EGEC propose a European Geothermal Risk Insurance Fund ( EGRIF) to help encourage investments in geothermal electricity projects. The EGRIF is intended to work through a pooling of the resource risk among geothermal electricity projects across the European Union. The intention of the insurance would be to cover the cost of a geothermal well in case of partial or total failure. It is intended by EGEC that the EGRIF would be financed by a combination of public funds, private funds and project developers funding. It is intended that the EGRIF would cover short and long term risks.
7.8 Geothermal Resource Definition
A programme of exploration and data gathering was undertaken in Australia between 2006 and 2011, by Geoscience Australia, to improve the existing knowledge about the type and location of geothermal resources in Australia on a national scale ('Geothermal Energy Project') as part of a wider investigation to identify onshore energy resources (the 'Onshore Energy Security Program'). It aimed to encourage investment, exploration and exploitation of this energy source through provision of pre-competitive geoscience datasets relevant to geothermal energy.
The programme was The exploration has stimulated commercial geothermal activity in Australia, including projects in the Cooper basin.
7.9 Advances in Technology
Advances in technology have the potential to reduce costs in the future.
In their report for Scottish Enterprise, SKM (2012) highlight the development of Resonance Enhanced Drilling by Aberdeen University and the potential this has for increasing drilling rates, including those for geothermal energy. This has the potential to significantly reduce the drilling programme and therefore costs. From the overview provided, it appears that the technology is in its infancy but may be useful and important in the future.
Also of potential interest is the PLASMABIT plasma drilling technology concept currently being developed by Geothermal Anywhere as a "deep drilling system and rock disintegration method" by a special system based on electric plasma and offering the potential for high drilling progress rates at depth (high temperature and high pressure environments).
Other technological advances in drilling are also under development.
7.10 Discussion & Conclusions
Relative Levels of Risk
There is a clear and significant technological, risk and cost differential between those geothermal developments that generate power (and produce subsidiary heat) - requiring boreholes to significant depth (5km), and those that produce only heat.
There is an increasing risk with depth for geothermal developments:
- Least risk - shallow to moderate depth (say <1km deep) hydrothermal heat-only developments, e.g. in former mine workings.
- Low / Moderate risk - deep (say 1km to 3km deep) heat-only hydrothermal developments, e.g. in Hot Sedimentary Aquifers.
- Moderate / High risk - deep (say 3km deep) power-generating hydrothermal projects developments, e.g. in Hot Sedimentary Aquifers.
- Highest risk - deep (say 4km to 5km+) power-generating petrothermal projects, potentially requiring EGS.
The temperature and properties (permeability flow rates, etc) of a resource can only be confirmed by exploratory drilling.
Shallow to Moderate Depth Heat-Only Geothermal Developments
These projects are considered to be the least risky. If used for domestic or commercial heating purposes it is anticipated that they would be used in conjunction with heat pumps (dependent on the application), makes them slightly less attractive in terms of energy efficiency and carbon production. There are industrial or horticultural processes that could use the 'warm' water without the requirement for heat pumps.
There is a reasonable understanding and comprehensive range of information available for mine workings in central Scotland as a potential geothermal energy source. These have the advantage of often being located near centres of population and in particular heat poverty. The use of mine water with heat pumps has been proved in Scotland at a small scale in the schemes at Lumphinnans and Shettleston.
The geothermal mine water project at Herleen in the Netherlands is a positive demonstration the technology and integration with a heat network. Herleen's originally proposed sister project at the Shawfair development in Midlothian, based on extracting heat from the former Monktonhall colliery, did not go ahead.
Consideration should be given to creating a geothermal demonstrator with a heat network, at Shawfair (as previously proposed) or within another suitable proposed development. If located at Shawfair it could bring benefits to the proposed development and would also benefit from the previous research. It could also be used as a demonstrator for a mixed-source heat network (a heat engine was also proposed for the Shawfair project).
Deep Heat-Only Hydrothermal Developments(say 500m to 3km deep)
These projects would use the geothermal heat resource as a direct source for domestic or commercial heating purposes or industrial use. The increased drilling costs make these projects riskier than shallower projects.
There is some geological understanding of the properties of Hot Sedimentary Aquifer sources in Scotland form exploratory drilling for hydrocarbons. Similar schemes are currently being proposed in Manchester using the Cheshire Basin aquifer as a source, at circa 3km depth.
It is considered that some further exploration would be required to define the potential of the resources, including the temperature and permeability of the resource.
Power-Generating Geothermal Developments (Hydrothermal & Petrothermal)
It may be possible to generate power from the hydrothermal HSA in Scotland, however, generating efficiency decreases rapidly with decreasing resource temperature.
For the deeper Petrothermal resources, based on the current understanding of the resource (low confidence level), power generation may need to rely on EGS to access the resource and a binary-process to generate electricity. EGS is yet to be widely proved as a commercially viable technique.
There is significant doubt over heat flow and therefore the resources available from buried granites in Scotland. Until drilling takes place to investigate the resource this doubt will remain.
At present there is little prospect of commercialisation of deep geothermal power generation in Scotland in the short-term. This is due to the current lack of information on the location of resources at sufficiently high temperatures that are at technically and economically feasible depths.
It is noted that the current proposed geothermal projects in Cornwall (including those at United Downs in Redruth and at the Eden Project) have benefited from the (higher) certainty provided by high recorded heat flows and the long-running Hot Dry Rock Geothermal Project at Rosemanowes. Both of these projects have been awarded substantial grant support but it is understood that they have not yet secured the full finances required for deep drilling to prove the resource.
To define the likely geothermal resources that may be suitable for power generation, and also to significantly benefit the accuracy and spatial distribution for heat production, a national programme of exploration is required.
In addition, there is no publicly-backed exploration risk insurance scheme and private insurance is unlikely to be affordable to potential developers.
As the geothermal resource evidence base increases, the potential risks will be reduced, and it will be easier to get private funding. It is anticipated that the required support mechanisms could reduce as the cost of equity reduces.
It is noted that, amongst others, the German government has stimulated activity in the deep geothermal sector by providing a range of support measures, including a generous FiT (with bonuses for HDR projects), exploration risk insurance and grants.
Two sets of recommendations are made; one set for heat-only developments and one for power-generating developments.
Geothermal heat is much less risky than deep geothermal electricity production and it is recommended that it should be targeted as a priority for development.
Geothermal power is dependent on better definition of the resource. An exploration programme should be commenced, in parallel with developing the shallower resources.
Unlocking the Potential of Shallow Geothermal Heat-Only Projects
The development of heat networks is considered essential to the deployment of geothermal heat resources. Identification of initial anchor heat load(s), most likely from public buildings, is a key element in establishing the viability of heat networks. It is recommended that the opportunities for development where resource and demand coincide should be identified by combining the geothermal resource potential maps from this study and heat mapping.
It is recommended that a geothermal demonstrator with a heat network should be developed, for example at Shawfair (as previously proposed) near Edinburgh, Clyde Gateway in eastern Glasgow, or within another suitable and suitably-located proposed development / area. It could provide a focus to encourage development and help build a sustainable community and or commercial or industrial park (or mixed-use development).
It is considered that the RHI level of 5p/kWh currently proposed by DECC could make the business case for deep geothermal heat developments (>500m depth) sustainable.
The experience gained from developing progressively deeper projects will aid in establishing confidence in the sector and reducing costs.
Unlocking the Potential of Deep Geothermal Power Projects
It is recommended that a programme of data gathering and exploration is undertaken, with a similar scope to the recent exploration programme in Australia that has stimulated commercial geothermal activity. This will help to reduce the uncertainty and therefore the risks to help encourage commercial development.
This would include:
- Collating available data from all public sources, and potentially private sources, into a national geothermal information database and making it freely available to for the benefit of all.
- A national exploration programme of investigation specifically to identify the location of deep buried granites.
- A targeted programme of deep drilling to prove deep resources and research the potential.
A key element is proving or disproving the theory that the geothermal temperature gradient in Scotland was suppressed by the last ice age to a significant depth and has not fully rebounded. If this theory is correct then substantial undiscovered resources may exist at depth.
Dependent on further definition of the resource, ROCs are considered a good support mechanism for development of the deep geothermal power generation, if it is pitched at right level. It is recommended that a level of 4 to 5 ROCs be adopted for deep geothermal as an emerging technology that has the potential to provide baseload. This is also to provide more parity with other countries, specifically European countries.
Additional funding support is also likely to be required to attract developers. It should be noted that any state funding would be subject to State Aid regulations.
Consideration should be given to a Scottish Government backed deep geothermal exploration risk insurance scheme similar to the schemes that are in place in most other countries that are developing geothermal resources. It is acknowledged that this is a complex issue and it may be difficult for the Scottish Government to justify 'support' of deep geothermal energy projects by providing exploration risk insurance at the expense of support of other renewable technologies.
It is recommended that the Scottish Government investigates how it can offer or encourage some form of exploration risk insurance.
As an alternative or in addition to direct funding from the Scottish Government, it is recommended that it should be investigated whether other institutions could provide exploration risk insurance (for example the Green Investment Bank or the commercial insurance sector). The European Geothermal Risk Insurance Fund proposed by EGEC may also provide an alternative but is currently only a proposal.