Options appraisal of alternatives to conventional grid connection for River Avich hydroelectric scheme
Prepared for Dalavich Improvement Group
Version 3.0 January 2015
Analysts: Julia Gutierrez Brian Troddyn Anthony Browne Michael Diderich
Issued by Community Energy Scotland 2b Fodderty Way Dingwall Business Park Dingwall, IV15 9XB, United Kingdom
Tel: (+44) 01349860120 [email protected] www.communityenergyscotland.org.uk
© 2014 Community Energy Scotland is a Registered Scottish Charity (No. SC039673), and a company limited by guarantee, registered in Scotland (No. SC333698).
Issue and Review Record
Issue Date Author(s) Approver Summary J. Gutierrez 1 5/1/15 B.Troddyn F. Wight First Draft A. Browne J. Gutierrez 2 14/01/15 F. Wight Final Draft B.Troddyn J. Gutierrez 3 2/2/15 F. Wight Final document B.Troddyn
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Executive Summary
The communities of Inverinan, Dalavich, Lochavich and Kilmaha, which form the Dalavich Improvement Group, are planning to build a 350kW run of river hydroelectric scheme on the River Avich. Connection of the hydroelectric scheme to the National Grid represents a significant financial cost, and the need for grid upgrades in the Dalavich area mean that the connection would be limited to 50kW of power export until 2021.
Based on previous feasibility work undertaken by Gregor Cameron Consultancy, estimates show that the hydroelectric scheme would generate approximately 1084MWh per year. Given the 50kW grid connection limit, an estimated 261MWh of generation would be exported to the grid and 823MWh would be ‘curtailed’ i.e. not generated. This high level of curtailment is equivalent to a revenue loss of £144,800 per year. This report details five potential options to maximise local energy use and minimise the impacts of curtailment. These options are divided into ‘on-site’ and ‘off-site’ solutions.
On-site solutions create new demand in a close proximity to the hydroelectric turbine location or grid connection point. The hydroelectric scheme will connect to the grid with an export limit of 50kW until 2021. Generation is primarily sent to the grid, however when generation exceeds 50kW limit, the power will be diverted to the on-site demand until that demand reaches its consumption capacity. These on-site options often involve creation of a new business or revenue stream. The on-site options reviewed are woodchip production, wood pellet production, glasshouse/polytunnel heating, and an electric vehicle charging point.
Off-site solutions aim to utilise existing or potential demand that is located in the nearby area. In situations where the use of the public grid is limited, it is possible to use a private wire system known as a microgrid to link local generation directly to the nearby demand. This report includes an analysis of a microgrid servicing local domestic properties, to supply electricity and heat.
The potential benefits of the on-site and off-site options are reviewed. A key consideration is the level of curtailment experienced by the hydroelectric scheme, this is the total power which cannot be used or exported and therefore has no financial value. The table below gives the estimated annual curtailment of the generator after implementation of each option on an individual basis:
Option Annual curtailment (MWh) Base case (50kW export only) 823 Wood-chip production 495 Wood-pellet production 458 Polytunnel heating 749 Electric vehicle charging 786 Microgrid 402
The estimates given above illustrate that numerous options could successfully reduce curtailment, allowing Dalavich Improvement Group to maximise the benefit of the hydroelectric scheme for the communities of Inverinan, Dalavich, Lochavich and Kilmaha. Below are the key next steps that Community Energy Scotland has proposed in order to investigate options further.
Key next steps: Further analysis on the hydroelectric scheme including acquisition of historic river data, detailed technical design, and budget costings Obtain detailed historic energy consumption for residents and confirm specification of current heating systems Detailed technical design and financial modelling for the microgrid option Consultation with potential business operators for the on-site use options
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Contents
Issue and Review Record ...... 2 Executive Summary ...... 3 Contents ...... 4 List of Tables...... 5 List of Figures ...... 6 List of Appendix Tables ...... 7 List of Appendix Figures ...... 8 1. Introduction ...... 9 2. Project Background ...... 10 2.1. Dalavich Improvement Group: Community Interests ...... 10 2.2. Nature of Grid Constraint ...... 10 2.3. Generation and Curtailment Profiles ...... 11 3. Local Energy Use Options ...... 13 3.1. On-Site Solutions ...... 13 3.1.1. Woodchip Drying and Production...... 13 3.1.2. Heated Glasshouse/Polytunnel ...... 17 3.1.3. Wood Pellet Production ...... 19 3.1.4. Sustainable Community Transport – Infrastructure and Vehicles Options ...... 23 3.2. Off-Site Solutions ...... 25 3.2.1. Microgrid ...... 25 3.2.2. Community Hall, Options for Future Development ...... 30 4. Financial Analysis ...... 32 4.1. Unconstrained Scenario ...... 32 4.2. Constrained Scenario: 50 kW Export Limit ...... 33 4.3. On-site Options: Woodchip and Polytunnel...... 34 4.4. Off-Site Options: Microgrid ...... 35 5. Summary and Recommendations ...... 36 Works Cited ...... 37 Appendix A: Assumptions for production of estimated domestic annual demand ...... 39 Appendix B: Assumptions for production of estimated demand for each property cluster ...... 40 For Both Clusters ...... 40 For Cluster A ...... 40 For Cluster B ...... 42 Appendix C: Estimated Demand Curves ...... 44
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List of Tables
Table 1. Energy demand and potential curtailment reduction using L-ENZ ...... 14 Table 2. Woodchip facility set up scenarios ...... 14 Table 3. Main CAPEX & OPEX for a woodchip production and drying facility ...... 15 Table 4. Skills required for the drying unit ...... 17 Table 5. Energy demand of polytunnel and potential curtailment reduction ...... 17 Table 6. Capital outlay for a 108m2 community greenhouse ...... 18 Table 7.Energy demand and potential curtailment reduction from raw material drying in wood pellet production ...... 20 Table 8. Estimated costs for a wood pellet processing plant, including chipping and drying...... 21 Table 9. Skills required to set up the wood pellet processing plant ...... 23 Table 10. Types of electric vehicles' in the market ...... 23 Table 11. Energy demand of electric vehicles’ and potential level of curtailment ...... 24 Table 12. Lease options ...... 24 Table 13. Estimated domestic annual demand based on survey data (per household) ...... 26 Table 14. Estimated domestic annual demand based on survey data (per household) ...... 26 Table 15. Demand and available supply for 350kW hydroelectric scheme serving Cluster A ...... 27 Table 16. Generation available (assumed Cluster A load only, and grid connection of 50kW)...... 28 Table 17. Main costs microgrid system for Cluster A (Dalavich) ...... 29 Table 18.Current energy use vs. best practice for a mixed-use building ...... 30 Table 19. Annual energy use of a mix of activities within community hall ...... 31 Table 20. Leisure activities and potential energy consumption ...... 31 Table 21. Options summary ...... 36
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List of Figures
Figure 1. Schematic of Taynuilt-Dalavich distribution network...... 11 Figure 2. Estimated power generation profile for a 350kW hydroelectric scheme, 2012 flow estimates ...... 12 Figure 3. Generation duration curve based on the estimated power generation profile, 2012 flow estimates .. 12 Figure 4. Woodchip drying operational model ...... 14 Figure 5. Large biomass users on a 15-mile radius from Dalavich, ©http://www.argyll-bute.gov.uk ...... 16 Figure 6. Space requirements for woodchip drying at old bus depot ...... 16 Figure 7. Farmers’ Markets near Dalavich ...... 18 Figure 8. Polytunnel on open land near turbine powerhouse identified as potentially suitable during community consultation ...... 19 Figure 9.Woodpellet manufacturing models ...... 21 Figure 10. 50-mile radius for wood pellet delivery ...... 22 Figure 11. Space requirements for wood pellet production ...... 22 Figure 12. Electric vehicle infrastructure ...... 23 Figure 13. Map of potential microgrid locations ...... 26 Figure 14. Level of local power demand (non-heating) and supply for Cluster A ...... 27 Figure 15. Level of heating demand and supply for Cluster A ...... 27 Figure 16. Chart illustrating end use of hydroelectric generation assuming no energy storage, but with all oil heat converted to electric ...... 28 Figure 17. Community Hall plan ...... 30
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List of Appendix Tables
Table B-1: Estimated biomass hourly demand by month for the average property in Dalavich Village ...... 41 Table B-2: Estimated oil hourly demand by month for the average property in Dalavich Village ...... 41 Table B-3: Estimated biomass hourly demand by month for the average holiday chalet North of Dalavich Village ...... 42 Table B-4: Estimated biomass hourly demand by month for the average home in Inverinan ...... 42 Table B-5: Estimated oil hourly demand by month for the average home in Inverinan ...... 43 Table B-6: Estimated LPG hourly demand by month for the average home in Inverinan ...... 43
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List of Appendix Figures
Figure B-1: Seasonality factor for domestic electric heating ...... 40 Figure C-1: Average hourly load curve, Cluster A, January ...... 44 Figure C-2: Average hourly load curve, Cluster A, February...... 44 Figure C-3: Average hourly load curve, Cluster A, March ...... 45 Figure C-4: Average hourly load curve, Cluster A, April ...... 45 Figure C-5: Average hourly load curve, Cluster A, May ...... 45 Figure C-6: Average hourly load curve, Cluster A, June ...... 46 Figure C-7: Average hourly load curve, Cluster A, July ...... 46 Figure C-8: Average hourly load curve, Cluster A, August ...... 46 Figure C-9: Average hourly load curve, Cluster A, September ...... 47 Figure C-10: Average hourly load curve, Cluster A, October ...... 47 Figure C-11: Average hourly load curve, Cluster A, November ...... 47 Figure C-12 Average hourly load curve, Cluster A, December ...... 48 Figure C-13: Average hourly load curve, Cluster B, January ...... 48 Figure C-14: Average hourly load curve, Cluster B, February ...... 48 Figure C-15: Average hourly load curve, Cluster B, March ...... 49 Figure C-16 Average hourly load curve, Cluster B, April ...... 49 Figure C-17 Average hourly load curve, Cluster B, May ...... 49 Figure C-18 Average hourly load curve, Cluster B, June ...... 50 Figure C-19 Average hourly load curve, Cluster B, July ...... 50 Figure C-20 Average hourly load curve, Cluster B, August ...... 51 Figure C-21: Average hourly load curve, Cluster B, September...... 51 Figure C-22 Average hourly load curve, Cluster B, October ...... 51 Figure C-23: Average hourly load curve, Cluster B, November ...... 52 Figure C-24. Average hourly load curve, Cluster B, December ...... 52
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1. Introduction
The communities of Inverinan, Dalavich, Lochavich and Kilmaha, which form the Dalavich Improvement Group (DIG), are planning to build a 350kW run of river hydroelectric scheme on the River Avich. However, the grid connection cost is high and the need for transmission network upgrades mean the connection would be limited to 50kW until 2021.
In order to explore alternative uses for the energy generated, Community Energy Scotland has prepared this report, which outlines six potential options to maximise local energy use from the hydroelectric scheme. These are: 1. Supply of electricity/heat via a ‘private wire’ network (Microgrid) 2. Woodchip drying and production 3. Wood pellet production 4. Crop production via polytunnel/heated glasshouse 5. Sustainable community transport 6. Community Hall, options for future development
By understanding the advantages and disadvantages, along with financial and technical requirements of each option, Community Energy Scotland believes DIG will be in a better position to make an informed decision to maximise the local use of energy from the hydroelectric scheme leading to a more sustainable community and more financially viable scheme.
Section 2 shows the local grid analysis and Section 3 presents the six different options for maximising local energy use and mitigating the effects of curtailment. Each of the options is explained in terms of potential energy demand and level of curtailment reduction. Information on estimated development costs, capital and operational costs, potential markets for the products and the space and skill requirements are included for each option. Please note that these are high level estimates and more detailed analysis and research will be required to confirm more accurate cost estimates.
This report completes the outcome of Activity 3: Review of innovation options as outlined in the work plan agreed by Community Energy Scotland and DIG, in fulfilment of their grant offer from the CARES fund.
Throughout this report we have tended to use kWh (kilowatt hours) where the amount of energy is less than 1000kWh, and MWh (megawatt hours) where the amount of energy is greater than 1000kWh (1 MWh is 1000kWh). The exception is where we have discussed domestic energy demand, as most people are familiar with the use of kWh in this context, as it is how electricity bills are measured.
To put this in context, the amount of electrical energy used in an UK average home over the course of one year is c.3300kWh (3.3MWh). The amount of heat energy in the same period is c16,500kWH (16.5MWh). kW and MW measure the instantaneous power of energy generation or demand, kWh and MWh measure power over time. As such generator and demand ratings are provided in kW and MW, but energy consumption is provided in kWh and MWh.
Finally Community Energy Scotland would like to thank Dalavich Improvement Group for all their input and enthusiasm in the preparation of this report, which reflects a significant contribution of time and energy from members of the community.
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2. Project Background
2.1. Dalavich Improvement Group: Community Interests
This subsection reflects the feedback from two community focus groups held between Community Energy Scotland and DIG on November 5th and December 14th.
The main concerns for the community are: The value of generation from the hydroelectric for FIT and export tariffs is decreasing The constrained output of the generation due to the 50kW grid export limit The indicated lost revenue of £756,050 over five years if the curtailed generation is not utilised
Options presented in this report aim to decrease lost revenue while at the same time addressing the community’s main interests. These are: Job creation Increasing the population Increasing levels of tourism
In that sense, income from any option pursued will be an important factor. The options presented in this report received the following feedback: The microgrid option is important, with further investigation required Community members are willing to facilitate monitoring equipment in their home for this matter Woodchip drying was favoured over wood pellet production as a viable new business development Community owned electric vehicles are something that could benefit members of the community The old bus depot was generally agreed to be a good site for any new industry in the area
2.2. Nature of Grid Constraint
The hydroelectric scheme is proposed to be connected to the 11kV distribution line between Kilchrenan Substation and Inverinan/Dalavich on Pole 161 as shown in Figure 1.
Following Figure 1, the 33kV line to Kilchrenan is one of the distribution branches coming out of Taynuilt Substation. Currently this substation is undergoing major upgrading works including the distribution line Taynuilt – Cruachan (in red) and the transmission line Inveraray –Taynuilt (in red). These works delay any connection of new generators that will depend on the Taynuilt Substation until 2021 when the upgrade works will be completed.
The Dalavich hydroelectric scheme has a firm connection with an export limit of 50kW. Currently there are nine other projects also affected by these works with a total capacity up to 2.7MW.
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Figure 1. Schematic of Taynuilt-Dalavich distribution network
2.3. Generation and Curtailment Profiles
Given the grid constraints mentioned above, it is necessary to analyse the profiles of generation and curtailment. Curtailment is the electricity that could have been generated by the hydroelectric scheme but couldn’t be sold to the grid due to the limited connection, this is measured as a percentage (the higher the percentage, the more potential generation isn’t being exploited).
Figure 2 shows the power generation profile for a hypothetical 350kW hydroelectric scheme on the River Avich. The estimates were produced using historical data for similar scale hydroelectric installations, but are ultimately hypothetical due to the variations between individual watercourses. The calculations have the following assumptions: Hydroelectric turbine with a rating of 350kW at maximum flow (estimated to be at 2.12m3/s) The hydrostatic head available at the site is 20m The turbine is a Francis design and has an operating flow range of 0.32 – 2.12 m3/s, turbine efficiencies are taken from literature (Ahmed, 2012) The generator is assumed to have an efficiency of 95%
According to the estimated generation profile, the scheme would generate 1084MWh per year. This gives a capacity factor of 35% for the hydroelectric turbine.
Given the nature of the constraint, it is necessary to consider the impact on the overall productivity of the proposed hydroelectric scheme. Figure 3 gives the generation duration curve for the above data set and shows the 50kW constraint level.
As can be seen from Figure 3 the hydroelectric turbine would be subject to significant constraint (approximately 4650 hours of the year). Around 76% (823MWh) of the estimated potential electricity production of 1084MWh per year will be constrained. Assuming a post April 2015 Feed in Tariff rate (12.63p/kWh) and export tariff (4.77 p/kWh) levels, this represents an annual loss in revenue of £144,800
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(£724,002 across five years).This lost income would be even higher if it considered that in practice generators of this size normally secure a Power Purchase Agreement (PPA) to sell electricity to a licensed supplier, whose average market price is 5.5p/kWh (rather than 4.7p/kWh).
400
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Power [kW] Power 150
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0 0 1000 2000 3000 4000 5000 6000 7000 8000 Time [hours]
Figure 2. Estimated power generation profile for a 350kW hydroelectric scheme, 2012 flow estimates
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300 250 200 Power [kW] Power 150 100 50 0 0 1000 2000 3000 4000 5000 6000 7000 8000 Time [hours]
Generation Grid Connection
Figure 3. Generation duration curve based on the estimated power generation profile, 2012 flow estimates
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3. Local Energy Use Options
In order to maximise the local consumption of energy produce by the hydroelectric scheme, various options are detailed here. These options can be broadly categorised as On-site and Off-site solutions.
3.1. On-Site Solutions
On-site solutions create new demand as close as physically possible to the hydroelectric turbine location or to the grid connection point. The generator will still be connected to the grid with an export limit of 50kW until after 2021. When generation exceeds this limit, the power will be automatically diverted to the On-site demand until it reaches its consumption capacity. The amount of power diverted is determined by the level of on-site demand and the maximum output of the generator, which can be temporarily altered to minimise the cost of the export control equipment required.
The on-site demand will only run with excess energy (over 50kW) and it doesn’t need to remove 100% of the constraint as any level of demand will have a positive impact on income levels. The on-site options explored in this section are woodchip production, wood pellet production, glasshouse/polytunnel, and an electric vehicle charging point.
3.1.1. Woodchip Drying and Production
With the recent introduction of the Renewable Heat Incentive (RHI), there is growing demand for wood fuel for domestic and industrial heating.
The usable heating energy (calorific value) of wood chips depends on water content of the woodchips. Fresh wood chips with a water content of 55% (W55) provide around 2MWh in energy per tonne. By drying the wood chips to 20% water content (W20), the calorific value is increased sign to around 4MWh per tonne.
3.1.1.1. Potential Energy Demand
Commercial active woodchip drying involves high temperature flash-dryers and drum-dryers or lower temperature conveyor-dryers to remove moisture from piles.
The energy required to dry woodchip is difficult to estimate, as it depends on the initial and target moisture content (MC) of the woodchip, the storage temperature, the amount of woodchip stored, the chip size and the depth of the pile. It also varies significantly according to the equipment used to dry, the drying temperature, the airflow rate and the use of ambient air.
A woodchip drying study completed on behalf of the Forestry Commission (Price, 2011) suggests that commercial dryers use about 0.950–1.4 MWh per tonne of water evaporated from woodchip. A German supplier of small scale woodchip dryers (L-ENZ) estimates a use of 1.5–2 MWh per tonne of water evaporated. For example, drying 2 Tonnes of woodchip from 60% to 20% MC (1Tonne of water evaporated) would require in the region of 1.75 MWh.
Table 1 shows the potential energy demand and curtailment reduction from using a woodchip dryer like the L- ENZ unit for half-year production. In Table 1 a moisture content reduction from 60% to 20% is assumed. Since the drying facilities will not be operational 100% of the time, a conservative estimate is given in Table 1, which assumes 6 months of operation per year, based on the weekly loads that could be feasible for this size of drying system. The drying unit would create an average peak new demand of 100kW (equivalent to 328MWh p.a.) which translates into a reduction in curtailment of around 34%. This is shown in Table 2.
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L-ENZ 80 – Woodchip Drying Unit Variable Units Value Storage capacity Tonnes 7.5 Approx. water evaporated 60 - 20 % MC Tonnes 3.75 Drying time per load Days 2 - 3 Loads per week - 2 Dry woodchip per load Tonnes 3.75 Energy consumption per load MWh 6.56 Energy consumption per Week MWh 13.12 Annual energy consumption MWh 328.12 Curtailment level after option % ≈ 45.6%1 Table 1. Energy demand and potential curtailment reduction using L-ENZ
The service could be set up either as a new woodchip supply company owned and run by DIG, or as a heat provider to a third party woodchip provider. Note that under both scenarios DIG would still keep the FiT income. Figure 4 shows the process and two operational models DIG could consider.
Figure 4. Woodchip drying operational model
Equipment Business FiT Rate Woodchip Sale Annual Heat Sale Ownership Management (p/kWh) Price (£/tonne) Production ( p/kWh) (tonnes) Scenario A DIG DIG 14.03 1001 187.5 N/A Scenario B DIG 3rd Party 14.03 N/A N/A 12 Table 2. Woodchip facility set up scenarios
1 Note that this includes the energy that can be exported via the 50kW grid connection 2 Note that this price is lower than for heat supplied by the Microgrid as the value of the heat is lower than for domestic heat consumption, and the low price is intended to act as an incentive for the business location
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3.1.1.2. Estimated Set Up Costs
Table 3 details the main capital and operational costs for a woodchip drying facility. These costs are only indicative.
Item Cost Drying unit including buffer tank £ 50,0003 Woodchipper £ 28,0004 Civil works (≈ 50 m2) £ 1,5005 Installation £ 10,0001 Export control unit £ 36,0006 Sourcing wood (60%MC) £26/ tonne Table 3. Main CAPEX & OPEX for a woodchip production and drying facility
3.1.1.3. Potential Markets (Local / National)
Demand for woodchip in the immediate DIG area would be insufficient to meet the output of the drying facility. As customers outside the local area are needed, transport, shipping, unloading and delivery costs of woodchip must be factored in a further market analysis. A typical transport rate per tonne of dry woodchip delivered is £12.57.
A potential way to connect to local end users would be through local wood fuel forums, such as the Argyll Woodfuel Forum8.
Woodfuel is most cost effective and low carbon when sourced and supplied locally. For dried woodchip to be economical and sustainable, transport distances should to be kept within a 30 mile limit by road, which roughly equates to a 15-mile radius (as the crow flies). Figure 5 shows biomass installations within 15 miles of Dalavich. Three medium sizes biomass installations have been identified totalling 1000kW of installed capacity:
o Inveraray Primary School – 199kW o Lochgilphead Campus – 400kW o Kilmory Castle – 400kW
Assuming these installations are running half the year they will consume on average 4,325MWh p.a. The annual production of dry woodchip at DIG’s facility is 187.5 tonnes, assuming a calorific value of 4MWh/tonne; DIG could supply around 15% (750MWh) of the annual local demand. This does not take into account domestic biomass installations. According to the Forestry Commission, between November 2011 and May 2014, 840 woodfuel installations have been developed across Scotland representing a capacity of 179MW. This has increased demand for both raw material and processed woodfuel.
3 Private communication with approved installer (Thermotec Ecosystems Ltd.) 4 Private communication with approved installer (Fuelwood (Warwick) Ltd ) 5 Taken from Woodchip drying feasibility Study ( Buccleuch Woodland, 2014) 6 Estimate adjusted from private communication with approved installer, based on 100kW of controllable demand (Solar and Wind Applications Ltd) 7 Private communication with approved installer January 2014 (3R Energy) 8 http://www.usewoodfuel.co.uk/news,-events-woodfuel-forums/woodfuel-forums/argyll-woodfuel- forum.aspx
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©http://www.argyll-bute.gov.uk Figure 5. Large biomass users on a 15-mile radius from Dalavich,
3.1.1.4. Space Requirements
The L-ENZ 80 drying unit has an area of 7.7m2 and comes with an outdoor housing unit. It also comes with a container of 7.5 tonnes (32m3) capacity. This is roughly the size of a standard shipping container. The old bus depot just outside of Dalavich could be a suitable site for this type of operation. This site is owned by the Forestry Commission and is currently leased by two local people from Dalavich village. Figure 7. show these spaces.
Figure 6. Space requirements for woodchip drying at old bus depot
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3.1.1.5. Skills Requirements
The skills required by DIG to undertake this option will depend on the operation model chosen. Table 4 provides a breakdown of skills needed taking into account the two scenarios proposed earlier in this chapter.
COMPLETE OWNERSHIP COMPLETE OWNERSHIP AND THIRD AND MANAGEMENT PARTY MANAGEMENT Scenario A Scenario B Trained and certified staff for operation of Technical Skills Limited skills required the drying unit. Experienced staff required to run the Administrative Skills Limited skills required business. The business requires at least a part time The facilities would need to be Management Skills manager. managed as a letting business. Table 4. Skills required for the drying unit
Woodchip drying 50m2 3.1.2. Heated Glasshouse/Polytunnel
Crop growing is an energy intensive activity and thus, a good alternative for usage of constrained renewable energy. Among the advantages of setting up a dedicated greenhouse as an on-site demand are: High and constant energy consumption through the growing period (it could be all year round) Ease of technology installation (standard water heating technology) High efficiency (potentially 100% - minus heat losses) Business opportunity for the community (job creation, economic boost) Revenue streams (from FiTs and crop selling)
3.1.2.1. Potential Energy Demand
Transport Turning space 220m2 According to the Carbon Trust, the typical energy consumption for intensive crop growing (i.e. vegetable and fruits) is 675kWh/m2 for heat and 15kWh/m2 for electricity use (Carbon Trust, 2012). Although proportions of energy use always vary according to the type of business, heating typically accounts for 90% of the energy used in a greenhouse. The other 10% accounts for a mixture of lighting, ventilation and cooling. According to a UK supplier9 of polytunnels, a small-scale one suitable for a community is around 108m2. The energy demand for that size growing fruits and vegetables would be as follows:
Activity Annual Energy Demand (MWh)* Weekly Energy Demand (MWh) Curtailment after option (%) 108m2 Polytunnel 74.52 1.43 ≈6910 Table 5. Energy demand of polytunnel and potential curtailment reduction
*assumes all year round production
9 Private consultation with approved vendor and installer (www. kedergreenhouse.co.uk) 10 Note that this includes the energy that can be exported via the 50kW grid connection
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3.1.2.2. Estimated Set Up Cost
There are important economies of scale when developing a greenhouse. Indicative costs11 for the greenhouse suggested earlier are shown in Table 6.
Capital Cost Cost (£) Greenhouse structure and 8,800 ventilation system Heating system 4,900 Irrigation and water tanks 1,700 Roof screens 900 Export control unit 10,00012 Total cost 26,300 Table 6. Capital outlay for a 108m2 community greenhouse
3.1.2.3. Potential Local Markets
Local produce is often in demand and with the growing popularity of farmers markets; there is increased opportunity for local producers to reach local markets. As listed by VisitScotland, some local farmers markets around the Argyll region are (VisitScotland, 2014): Ardrishaig Farmers’ Market Craignure Producers’ Market Benderloch Food and Crafts’ Market Cairndow and Loch Fyne Market
Figure 7. Farmers’ Markets near Dalavich
11 Private consultation with approved vendor and installer (www. kedergreenhouse.co.uk). Costs are 2014 rates. 12 Estimate adjusted from private communication with approved installer, based on 20kW of controllable demand (Solar and Wind Applications Ltd)
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3.1.2.4. Space Requirements
The growing space is determined by land availability, investment capital available, market research and growing expectations. As a rule of thumb (Robbins, 2013) a minimum of 2 acres (≈ 8000 m2) is needed to allow for facilities, possible outdoor growing area, material storage, access, parking and buffers. The option outlined in this report could be scaled up our down depending on the community’s needs and available space and resources.
Figure 8. Polytunnel on open land near turbine powerhouse identified as potentially suitable during community consultation
3.1.2.5. Skills Required
Knowledge of growing crops of different types and seasons will be required. Management skills and market knowledge will also be required as well as part time/volunteer staff.
3.1.3. Wood Pellet Production
Wood pellets are mainly made from compressed sawdust and wood shavings. Agricultural crop residue, energy crops, switchgrass and animal feed can be also densified into pellets. To make wood pellets from raw timber, the wood would need to be chipped first.
As described in (Świgoń & Longauer, 2005), a typical wood pellet production process includes raw material supply and storage, drying, size reduction through a mill, separation (cyclone), densification (granulation), cooling and storage. The highest energy consumption during this process comes from drying the raw material as a moisture content of 10 -12 % is needed before granulation. Heat could be obtained from a rotary drum, superheated steam, flash, spouted bed, or belt dryer (Mani, Sokhansanj, Bi, & Turhollow, 2006).
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3.1.3.1. Potential Energy Demand
Energy consumption from drying and therefore curtailment reduction will heavily depend on the type of raw material, particle size, moisture content, technology used and plant scale. According to a comparative study done in Austria and Sweden, (Theka & Obernbergera, 2004) dryers used for wood pelleting (tube bundle dryer) consume around 1MWh per ton of water evaporated, to reduce MC in raw material from 55% to 10%. Table 7 below shows the estimated values for a small-scale wood pellet production plant (Coed Cymru Cyf, 2011), assuming 7 days per week, one shift per day and half-yearly operation.
Wood Pellet Production : Raw Material Drying Parameter Unit Value Plant scale - Small Production rate Tonnes/h 0.25 Heat consumption MWh/tonne of e.w. 1 Approx. raw material supply rate Tonnes/h 0.50 Days of operation per week - 7 Hours per day - 7 Annual operational hours - 1278 Wood pellets annual production Tonnes ≈ 319.5 Average annual demand for drying MWh 319.5 Curtailment after option - ≈46%13 Values adjusted from (Theka & Obernbergera, 2004) Table 7.Energy demand and potential curtailment reduction from raw material drying in wood pellet production
Note that while the pellet production process is more energy intensive than woodchip production (because of the increased drying and processing), the assumed annual operating hours for pellet production are lower, due to the need for constant staff supervision. This means that the annual energy demand is in fact similar to woodchip drying.
As with the woodchip analysis, 6 months has been assumed for the effective annual operation period, based on the weekly schedule in the table above.
Energy consumption from other stages of the wood pellet processing including milling, grinding and cooling add up to 140kWh per tonne produced (Świgoń & Longauer, 2005) This equals to an additional 45MWh yearly energy demand.
3.1.3.2. Estimated set up and operational costs
PelHeat provided a detailed quotation from for a pellet plant that could process 250kg/h of wood pellets. Operational costs for staffing are factored in at £10 per hr. Discussions with suppliers indicate that current market price of wood pellets is c£260 per tonne.
Table 8 shows an estimate of main costs for setting up a wood pellet plant. These costs are only indicative. The set up and operational cost analysis in Figure 9 assumes the following scenarios: Scenario 1: DIG buy, manage and run whole business Scenario 2: DIG buy equipment and allow other third party producers use facility, DIG could charge for heat at a nominal rate but it may hinder attractiveness to users. Under this scenario DIG would still keep the FiT income arising from the generation
13 Note that this includes the energy that can be exported via the 50kW grid connection
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Main Capital Costs Woodchipper £ 28,00014 Drying unit including buffer tank £50,000 Pellet plant with ancillary equipment £82,000 Civil work £1,500 Installation £16,000 Export control unit £72,00015 Total £249,500
Table 8. Estimated costs for a wood pellet processing plant, including chipping and drying
Figure 9.Woodpellet manufacturing models
3.1.3.3. Potential Markets (Local/National)
A study done by (SCHULLER, 2004) on wood pellet supply and transport chain suggests a 50-mile radius as the farthest delivery distance a local producer could be competitive with big scale national and international producers. This area around Dalavich is shown in Figure 10, and covers most of Argyll, Glasgow and Fort William, which represents a sizeable potential market.
14 Private communication with approved installer (Fuelwood (Warwick) Ltd ) 15 Estimate adjusted from private communication with approved installer (Solar and Wind Applications Ltd) based on 200kW of controllable demand (Solar and Wind Applications Ltd)
Community Energy Scotland 21
Figure 10. 50-mile radius for wood pellet delivery
(SCHULLER, 2004) also points out that the estimated size of the UK wood pellets for domestic use is 150,000 tonnes and the Scottish market is about 25,000 tonnes a year. Wood pellets are predominantly used in domestic scale biomass boilers and are delivered in bags or as loose material.
3.1.3.4. Space Requirements
The pellet plant is about 70m2 (16), the L-ENZ drying unit suggested for woodchip drying is 7.7m2 and a standard small scale tube bundle dryer17 (380kg/h – evaporation capacity) covers approximately 11m2. The drying container scoped in last section has an area of 32m2. The total minimum manufacturing space needed would be around 115m2. Additional space for storing of raw and finished material and space for transport such as an articulated lorry must be accounted for. Figure 11 highlights the area of the old bus depot in Dalavich, this area meets the space requirements.
Figure 11. Space requirements for wood pellet production
3.1.3.5. Skills Requirements
The skills required by DIG to undertake this option will depend on the operation model chosen. Table 9 provides a breakdown of skills needed taking into account the two scenarios proposed earlier in this section.
16 Private communication with approved installer (www.PelHeat.com) 17 Private communication with approved installer (www.verttertec.de)
Community Energy Scotland 22
Skills COMPLETE OWNERSHIP AND COMPLETE OWNERSHIP AND THIRD PARTY MANAGEMENT Scenario A MANAGEMENT Scenario B Technical Trained and certified staff for operation of Limited skills required wood pellet plant Administrative Experienced staff required to run the Limited skills required business Management The business requires at least a part time The facilities would need to be managed as manager a letting business. Table 9. Skills required to set up the wood pellet processing plant
3.1.4. Sustainable Community Transport – Infrastructure and Vehicles Options
Sustainable transport refers to transport that incorporates social, environmental, climate impacts, and the ability to supply a source of energy indefinitely. To evaluate the sustainability of a transport system three main components need to be looked at, energy source, vehicles used and the infrastructure used to accommodate the transport. The implementation of a charging point for electric vehicles (Figure 12.) is an option that meets both the sustainable transport need and the use of constrained renewable energy from the hydroelectric scheme.
3.1.4.1. Potential Energy Demand
For any proposed electric vehicles to be practical within a community, suitable charging points need to be put into place. There are three main types of charging points available for electric vehicles; are given in Table 10.
Type Power Rating Charge Times Slow Charging Up to 3kW 6-8 hrs Fast Charging 22kW 3-4hrs Rapid Charging 43-50kW 30 min, AC & DC available © (Next Green Car Ltd., 2014) Table 10. Types of electric vehicles' in the market
Figure 12. Electric vehicle infrastructure
Community Energy Scotland 23
A full charge over four hours for an electric vehicle at a fast charging point would use 88kWh. According to survey statistics from the department of transport, (Department for Transport , 2013) people in rural areas make an average of 526 trips by private car per year. Most trips from DIG community members are within 15 miles (Taynuilt) and 26 miles (Oban), so an average mileage is around 40 miles per return trip.
An example of an electric vehicle currently in the market is the Nissan E-NV200 Combi people carrier. This car is able to do 106 miles per single charge (Nissan Motor Ltd). This means that the car would have to be fully charged at least every second day to meet the requirements of an average member of the community.
The energy demand for an electric vehicle is given in Table 11.
EV NISSAN E-NV200 Average # of trips/year 526 Average miles/trip –DIG area 40 Miles per single charge ≈100 Average # trips per single charge 2.5 Average # of charging times/year 210 Frequency of charging needed ≈Every second day Weekly energy consumed ≈ 176 kWh Annual energy consumed ≈36.74 MWh Curtailment after option ≈72%18 Table 11. Energy demand of electric vehicles’ and potential level of curtailment
3.1.4.2. Estimated Set Up Cost and Operational Costs
The cost of charging points can range from £2,000 for a slow charger to £35,000 for a rapid charger19. The most suitable charging point for DIG would be a fast charging point that costs £5,000. The current market price for a Nissan E-NV200 Combi people carrier is £23,000.
Note that there are grants available from ChargePlace Scotland for charging point installations up to £10k and from the government’s Plug-in Car Grant Scheme up to £5k towards the purchase of an electric vehicle.20 Leasing options are also available. Table 12 lists the costs for a 36 month leasing agreement21 of a Nissan Leaf Hatchback Acenta 5dr Auto.
Electric Vehicle Nissan Leaf Contract mileage 45,000 Payment profile 1 Initial Payment followed by 35 monthly payments Initial payment £1,492.19 Monthly payments (ex VAT) £248.70 Table 12. Lease options
18 Note that this includes the energy that can be exported via the 50kW grid connection 19 Private consultation with approved charging point installer (www.Rbgrant.co.uk) 20 Grant eligibility and Terms & conditions apply. (www.gov.uk/government/publications/plug-in-car- grant/plug-in-car-grant-vehicles) 21 Private consultation with approved vendor (arnoldclark.co.uk)
Community Energy Scotland 24
3.1.4.3. Space Requirements
Although the space needed for a fast charging point is relatively small, ChargePLace Scotland grant terms & conditions requires organisations to provide a free parking space and access to the public using the charging point. Possible suitable area for this type of installation would be the old bus depot, community hall car park or possibly outside the post office in the village centre.
3.1.4.4. Skills Required
Electric vehicles and charging points don’t require specific skills to be driven/manage, however DIG do have to set up a payment system for the electricity used at the charging point. This will be tied in with the hiring/usage system of the electric vechicles and for which at least a part time staff will be required.
3.2. Off-Site Solutions
Off-site solutions aim to take advantage of existing demand available away from the hydroelectric turbine location. It requires the building and installation of a private electrical network between the generation and the demand. Unless there is no public grid available, this network will usually be connected to the public one, so that surplus power can be exported and any shortfall imported. This option is known as a microgrid and will be explained in the following section.
3.2.1. Microgrid
This analysis is focused on whether a ‘microgrid’ could reduce the level of curtailment by providing power and heat to local properties. There are a number of practical and regulatory issues relating to microgrids which are not considered in detail here. However it is important that these are considered in a more detailed business model and design, including consideration of the establishment of a new subsidiary or sister company to operate the microgrid and supply heat and power to local users.
Distribution and supply of electricity in the UK is a regulated activity where licences must be obtained in order to operate. However, exemptions are available for small distributors and suppliers of up to 5MW (provided they do not sell more than 1MW of their own generations to domestic customers). In practice, this 1MW limit could service up to 1000 domestic customers. Renewable energy generators supplying off-grid or private networks can also be eligible for the FITs scheme.
Note that in response to a recent ruling from the European Court of Justice (Citiworks case) private wire networks in the UK are still required to ensure that there is access for third party suppliers should the customers wish to switch.
In order to assess the microgrid option it is necessary to consider not only power generation but also the local demand. Figure 13 shows the properties considered for inclusion in a microgrid scheme operated by the Dalavich Improvement Group. These areas are Dalavich village, the holiday chalets north of Dalavich village and Inverinan village.
Community Energy Scotland 25
Figure 13. Map of potential microgrid locations
3.2.1.1. Potential Energy Demand
In order to evaluate the local energy demand a survey was distributed to local residents. The survey received 28 responses. The average annual energy use taken from the survey is given in Table 13.
Location Electricity Oil Biomass LPG (kWh/year) (kWh/year) (kWh/year) (kWh/year) (kWh/year) Dalavich Village 6,649 10,938 1,000 0 Holiday Chalets 3,005 0 4,333 0 Inverinan Village 5,487 9,400 4,160 350 Table 13. Estimated domestic annual demand based on survey data (per household)
Analysis of the survey results given above indicated that electricity consumption is high and fuel use is low when compared with national statistics. As such a second set of demand estimates were calculated using a combination of national statistics (Zimmermann, Evans, & Griggs, 2012) (Prime, Khan, & Wilkes, 2014) and assumptions derived from the survey responses, the estimates are given in Table 14 with the assumptions listed in the appendix.
Location (kWh/year) Electricity Oil Biomass LPG (kWh/year) (kWh/year) (kWh/year) (kWh/year) Dalavich Village 4,290 13,935 1,276 0 Holiday Chalets 3,005 0 4,333 0 Inverinan Village 4,352 10,291 4,554 383 Table 14. Estimated domestic annual demand based on survey data (per household)
Estimation of total local demand has been completed based on two ‘clusters’ of properties. Cluster A includes Dalavich village and the holiday chalets north of Dalavich village. Cluster B includes Inverinan village. Cluster A represents a significantly larger load and is considerably closer to the hydroelectric site, as such the focus of the remainder of this report will relate to Cluster A only (estimated load profiles for Cluster A and Cluster B are given in the appendix).
Community Energy Scotland 26
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total Power Demand met by 21 13 12 9 5 0 0 3 20 21 10 15 131 (MWh) turbine Demand not met 0 1 3 5 16 21 21 19 0 0 4 0 92 by turbine Heat Demand met by 81 65 38 21 7 0 0 1 31 42 35 60 382 (MWh) turbine Demand not met 21 20 53 47 32 20 21 21 11 6 23 1 276 by turbine Total Overall demand 102 78 50 31 13 0 0 3 51 64 46 75 513 (MWh) met by turbine Overall demand 22 22 57 53 48 41 42 39 11 6 27 1 368 not met by turbine Table 15. Demand and available supply for 350kW hydroelectric scheme serving Cluster A
Table 15 shows the estimated demand for Cluster A and the generation available from the hydroelectric scheme to meet that demand. Note that the local demand is met in order of use, with local power (electricity used for purposes other than heating) being supplied as priority with heat demand secondary. This is an important financial consideration as heat and power are charged at different rates. Figure 14 and Figure 15 give a graphical representation of the demand and supply matching values given in Table 15.
120 Unmet
100 Met 80
60
40
Power Demand (MWh)Demand Power 20
0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 14. Level of local power demand (non-heating) and supply for Cluster A
120 Unmet 100 Met 80
60
40 Heat Demand (MWh)Demand Heat 20
0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Figure 15. Level of heating demand and supply for Cluster A
Community Energy Scotland 27
Note that the demand figures given in Table 15 includes electricity, electric heating, and oil heating as it is assumed that the oil-fired systems will be supplemented with new electric heating systems (oil systems would be retained as back up). It has been assumed that electric heating would not be used to displace heat from biomass, because biomass is already a sustainable and affordable fuel. In order to create the estimates of total demand further assumptions have been made as detailed in the appendix. Also included in the appendix are the monthly estimated demand curves for both Cluster A and Cluster B.
On numerous occasions throughout the year it is likely that supply from the hydroelectric scheme will exceed demand from within the cluster, this excess will be exported to the grid where possible (up to a maximum of 50kW). Any power generated above the local demand plus the grid export is excess which cannot be utilised and will be subject to curtailment (i.e. the generator output would be automatically limited).
Based on the assumption of a private wire scheme, which only serves Cluster A, the excess generation available is summarised in Table 16 and graphically represented in Figure 16. Note that the excess category in Table 16 represents an opportunity to deploy energy storage systems. Modelling energy storage is complex, but a significant proportion of the excess generation could be stored in thermal heat stores and deployed when suitable.
Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total Total generation (MWh) 174 136 73 46 26 0 0 4 116 165 123 221 1084 Generation used by 21 13 12 9 5 0 0 3 20 21 10 15 131 Cluster A for power (MWh) Generation used by 81 65 38 21 7 0 0 1 31 42 35 60 382 Cluster A for heat (MWh) Generation exported to 24 20 9 6 5 0 0 0 21 28 20 35 168 grid (MWh) Excess generation (MWh) 49 37 14 9 8 0 0 0 44 73 57 111 402 Table 16. Generation available (assumed Cluster A load only, and grid connection of 50kW).
250
200
150
100
Power End USe(MWh) End Power 50
0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Power Heat Grid Curtailment
Figure 16. Chart illustrating end use of hydroelectric generation assuming no energy storage, but with all oil heat converted to electric
From Table 16 it can be seen that the estimated excess (curtailed) generation is 402MWh per year. Compared with the base case scenario this represents a curtailment reduction of 51%.
Community Energy Scotland 28
3.2.1.2. Estimated Set Up Cost and Operational Costs
Set up costs for a microgrid will heavily depend on the design chosen, as it will likely be a bespoken solution. There are however, two main approaches based on how the back-up supply is managed: Individual Switching: Each house will be supplied with a switching system to be automatically powered by the mains when there is a hydroelectric shortfall Integrated Switching: The houses will only be supplied via the microgrid even when the hydro is not generating. At these times, the required electricity will be imported from the DNO grid. There will be no switching system required; however, this does require the generator to secure an import agreement allowing it to import up to the maximum household demand from the national grid. It also means that the generator or new community supply company would be responsible for maintaining supply to customers on the microgrid at all times
Estimated costs for main equipment and installation of a microgrid obtained from G2 Energy consultants22 are given in Table 17.
Item Cost (£) Microgrid (turbine house to cluster) 400V/11 kV Transformer 15,000 GRP Transformer housing & concrete 15,000 foundations 11kV 95mm2 Aluminium cable 8 x 250m Cable drum Purchase Cost (£20/m) 40,000 Joints kit (Labour inclusive) (1 x # cable 12,000 drums) Trenching & Restoration ( £12/m) 24,000 Dig, prepare & reinstate Laying 16,000 Microgrid in cluster Option A: Individual Switching 2 X Step down Transformer 11kV/415V 20,000 160kVA 2 x GRP Transformer housing & concrete 30,000 foundations 90 X Meter (1 per house) 76,500 90 X Automatic Transfer Switch (ATS) - 1 per 27,000 house 415V Cable (4 X Cable drum) (£15/m) 15,000 Export control unit £100,00023
GRAND TOTAL £ 390,500
Adjusted G2Energy Quote; AECOM Table 17. Main costs microgrid system for Cluster A (Dalavich)
*Costs above are only indicative and exclusive of peripheral costs such as management, design, health and safety studies, permits & consents and suppliers profit. They are also exclusive of management and operational costs arising from the customers end when distributing electricity and/or heat.
22 Private consultation with G2 Energy Consultants (www.g2energy.co.uk) 23 Estimate adjusted from private communication with approved installer (Solar and Wind Applications Ltd), based on 300kW of export control. Note that there is a slight cost reduction assumed compared to the other options, because of the scale.
Community Energy Scotland 29
3.2.2. Community Hall, Options for Future Development
A potentially large energy demand could come from the community hall in Dalavich, which could be connected to the microgrid. It consists of a main hall, bar and restaurant area, a laundry room, toilet facilities, storerooms and an office. A plan of the hall is given in Figure 17.
Currently it is understood that this hall is underemployed, as it is only in use 2-3 times a year for social events. With the close proximity of the holiday lodges to the building there is potential to develop more services within the building.
Current annual energy use of the building (based on bills) is 33.5 MWh (87kWh/m2). This equates to about 3% of the overall projected energy output of the hydroelectric system.
The current heating system within the building is a mix of a wood burning stove in the main hall and an air source heat pump in the bar with electric infrared heaters as a back-up.
Figure 17. Community Hall plan
The Chartered Institute of Building Services Engineers (CIBSE) provides best practise energy benchmarks24 for different uses of buildings and different building services. It is then possible to estimate the overall energy use of the building for different types of scenarios of building use. The current usage of the building can be deemed as a mixed-use building. Table 18 compares the current energy use of this building against typical use for this type of building.
Current Typical for Mixed Use Building Annual Energy Use per sq. meter( kWh/m2) 87 143 Annual Energy Use ( MWh) 33.5 55.05 Table 18.Current energy use vs. best practice for a mixed-use building
To increase the annual energy usage of the community hall two-usage scenarios were assumed where the building is in use 8 hours a day, seven (7) days a week. This represents building use of 33% of overall time in the year.
The mixture of uses for the building given in Table 19 adds up to an overall annual energy consumption of 104.37 MWh. This increases the energy utilisation of the building from 87kWh/m2 to 271kWh/m2, which represents a 66% increase in energy consumed over the present level. This scenario could potentially consume 10% of the projected annual energy generation from the hydroelectric scheme.
24 Benchmark figures adapted from CIBSE Guide F-Energy Efficiency in Buildings, 2004 (www.Cibse.org)
Community Energy Scotland 30
3.2.2.1. Scenario 1: Mix of Activities
Activity Type* % of Building Used Energy Use Intensity - Total Annual Energy EUI (kWh/m2) Consumption (kWh) Sauna/Steam room 3 Based on equipment 1,752 Gym with (5) exercise machines 9 Based on equipment 5,256 Restaurant with bar 25 600 60,000 Offices x 2(Air conditioned) 8 226 1,808 Location for post office & shop 7% shop, 3% PO 550 shop, 140 PO 17,080 Laundry (2x Dryers and 2 x 4 Based on equipment 6,935 Washing Machines) Air Conditioned conference room 6 76 1,520 Multipurpose Exhibition Space 10 60 2,340 (Arts, conference, social clubs) Main hall with modifications for 25 80 7,680 wedding, corporate events Total 100 n/a 104,371 Figures adapted from CIBSE Guide F-Energy Efficiency in Buildings Table 19. Annual energy use of a mix of activities within community hall
3.2.2.2. Scenario 2: Sports, Recreation and Fitness Centre
Table 20 assumes that the whole building will be converted into different types of leisure or sports uses.
Type of Activity Layout Facilities Potential Annual Energy Use Swimming Pool - Swimming pool - 237 kWh/m2 electricity Centre - Changing rooms (up to25 - 1.3 MWh/m2 heating people) - Seating/viewing area with Total: 456.7 MWh vending - Snack bar as optional feature Curtailment reduction: 42%
Fitness Centre - Fitness studio with exercise - 194 kWh/m2 stations - General purpose exercise Total: 75 MWh studios - (2) dedicated system studios Curtailment Reduction: 7% - Health suite with six-person sauna - Solarium for four persons - Licensed bar and café/restaurant Sports ground - Floodlit* football pitch, with - 164 kWh/m2 changing unlit sports and practice pitches facilities - Changing/shower building Total: 63 MWh - Drinks vending in social area Curtailment reduction: 6%
Figures adapted from CIBSE Guide 78-Energy in spots and recreation centres (www.cibse.org) Table 20. Leisure activities and potential energy consumption
Community Energy Scotland 31
4. Financial Analysis
Basic financial analysis has been undertaken for the scenarios below. The key indicator is the net cashflow line at the bottom of each spreadsheet. Note that project lifetime extends to year 20 but this is not shown here. Land leasing/land purchasing costs have not been included here, nor have additional planning or licensing costs, apart from the £150k development cost allocated to the hydroelectric scheme itself.
4.1. Unconstrained Scenario
Hydro Electric Generation £,000 Feed in Tarrifs rate (£/kWh) 0.126
Power Purchase Agreement (PPA) Development Costs 150 0.055 (£/kWh) Capital Costs 700 Installed capacity (MW) 0.35
Working Capital 50 Capacity Factor 35% Total Cost 900 Unconstrained Output (MWh) 1,084
FINANCIAL ANALYSIS
Equity 300 33% Grant 0 0% Loan / Bond (15 year term) 600 67% Loan 2 (10 year term) 0 0% 10 year Preference shares 0 0% 900 Loan / Bond 1 rate 7.00% Loan / Bond 2 rate 7.00%
Inflation (RPI) 0.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 Income (£,000) 196.50 196.50 196.50 196.50 196.50 196.50 196.50 196.50 196.50 196.50
Operating Expenses 25% 49.12 49.12 49.12 49.12 49.12 49.12 49.12 49.12 49.12 49.12 Depreciation (years) 8% 56.00 51.52 47.40 43.61 40.12 36.91 33.96 31.24 28.74 26.44
Operating Profit (Profit Before 91.37 95.85 99.98 103.77 107.26 110.47 113.42 116.13 118.63 120.93 Financing costs)
Less Bank Loan Interest 1 41.26 39.56 37.74 35.79 33.70 31.46 29.06 26.48 23.71 20.75 Less Bank Loan Interest 2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Net Profit/Loss (PAFC) 50.12 56.29 62.23 67.97 73.55 79.01 84.36 89.66 94.92 100.18 Less Preference shares 0.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Assumed proportion (Net Profit -pref 33% 16.54 18.58 20.54 22.43 24.27 26.07 27.84 29.59 31.32 33.06 shares dividends paid) to equity Retained profit 33.58 37.72 41.70 45.54 49.28 52.93 56.52 60.07 63.60 67.12
Cashflow Profit + depreciation 106.12 107.81 109.63 111.58 113.67 115.91 118.32 120.90 123.66 126.62 Less bank loan 1 capital 23.46 25.15 26.97 28.92 31.01 33.26 35.66 38.24 41.00 43.97 bank loan 2 capital 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Repayment of pref shares - year 11-15 0.00 Dividends (pref & ordinary) 16.54 18.58 20.54 22.43 24.27 26.07 27.84 29.59 31.32 33.06 Opening cash 0.00 66.12 130.20 192.32 252.55 310.93 367.52 422.34 475.41 526.75 Closing cash 66.12 130.20 192.32 252.55 310.93 367.52 422.34 475.41 526.75 576.34 Interest on overdrafts 8.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Net cashflow 66.12 64.08 62.12 60.23 58.39 56.59 54.82 53.07 51.33 49.60
Community Energy Scotland 32
4.2. Constrained Scenario: 50 kW Export Limit
Hydro-Electric Generator £,000 Feed in Tarrifs rate (£/kWh) 0.126
Power Purchase Agreement (PPA) Development costs 150 0.055 (£/kWh)
Capital costs 750 Installed capacity (MW) 0.35
Hydro 700 Capacity factor 35%
Working capital 50 Unconstrained Output (MWh) 1,084
Grid Output with Export limit Total cost 950 261 (MWh)
FINANCIAL ANALYSIS
Equity 300 32% Grant 0 0% Loan / Bond (15 year term) 600 63% Loan 2 (10 year term) 50 5% 10 year Preference shares 0 0% 950 Loan / Bond 1 rate 7.00% Loan / Bond 2 rate 8.00%
Inflation (RPI) 0.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 Income (£,000) 47.32 47.32 47.32 47.32 47.32 196.50 196.50 196.50 196.50 196.50
Operating Expenses 25% 11.83 11.83 11.83 11.83 11.83 49.12 49.12 49.12 49.12 49.12 Depreciation (years) 8% 60.00 55.20 50.78 46.72 42.98 39.54 36.38 33.47 30.79 28.33
Operating Profit (Profit Before Financing -24.51 -19.71 -15.29 -11.23 -7.49 107.83 110.99 113.90 116.58 119.04 costs)
Less Bank Loan Interest 1 41.26 39.56 37.74 35.79 33.70 31.46 29.06 26.48 23.71 20.75 Less Bank Loan Interest 2 3.88 3.59 3.59 3.59 3.59 3.59 3.59 3.59 3.59 3.59 Net Profit/Loss (PAFC) -69.64 -62.87 -56.63 -50.62 -44.79 72.77 78.34 83.83 89.27 94.70 Less Preference shares 0.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Assumed proportion (Net Profit -pref 33% -22.98 -20.75 -18.69 -16.70 -14.78 24.02 25.85 27.66 29.46 31.25 shares dividends paid) to equity Retained profit -46.66 -42.12 -37.94 -33.91 -30.01 48.76 52.49 56.17 59.81 63.45
Cashflow Profit + depreciation -9.64 -7.67 -5.85 -3.90 -1.81 112.32 114.72 117.30 120.07 123.03 Less bank loan 1 capital 23.46 25.15 26.97 28.92 31.01 33.26 35.66 38.24 41.00 43.97 bank loan 2 capital 3.40 3.69 3.99 4.32 4.68 5.07 5.49 5.95 6.44 6.97 Repayment of pref shares - year 11-15 0.00 Dividends (pref & ordinary) -22.98 -20.75 -18.69 -16.70 -14.78 24.02 25.85 27.66 29.46 31.25 Opening cash 0.00 -13.52 -29.28 -47.41 -67.84 -90.57 -40.59 7.13 52.59 95.75 Closing cash -13.52 -29.28 -47.41 -67.84 -90.57 -40.59 7.13 52.59 95.75 136.59 Interest on overdrafts 8.00% -1.08 -2.34 -3.79 -5.43 -7.25 -3.25 0.00 0.00 0.00 0.00
Net cashflow -13.52 -15.76 -18.12 -20.44 -22.72 49.98 47.72 45.45 43.16 40.84
Community Energy Scotland 33
4.3. On-site Options: Woodchip and Polytunnel
Main assumptions: Woodchip drying and polytunnel operation are combined to share on export control costs Heat (as electricity) is sold to a third party woodchip drying facility The community runs a polytunnel. Sales of product are not accounted for here. Opex of woodchip & polytunnel is assumed 5% of gross income. Includes maintenance and insurance.
Hydro-Electric Generator £,000 Feed in Tarrifs rate (£/kWh) 0.126
Development costs 150 Power Purchase Agreement (PPA) (£/kWh) 0.055
Capital costs 752.3 Heat sales (£/kWh) 0.010 Hydro 700 Installed capacity (MW) 0.35 Export Control Unit 36 Capacity factor 35% Polytunnel 16.3 Unconstrained Output (MWh) 1,084 Working capital 50 Grid Output with Export limit (MWh) 261 Total cost 952 Polytunnel Energy Demand (MWh) 74.520 Woodchip Drying Energy Demand (MWh) 328
FINANCIAL ANALYSIS
Equity 350 37% Grant 50 5% Loan / Bond (15 year term) 580 61% Loan 2 (10 year term) 50 5% 10 year Preference shares 0 0% 1,030 Loan / Bond 1 rate 7.00% Loan / Bond 2 rate 8.00%
Inflation (RPI) 0.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 Income (£,000) 101.44 101.44 101.44 101.44 101.44 196.50 196.50 196.50 196.50 196.50
Hydro Operating Expenses 25% 25.36 25.36 25.36 25.36 25.36 49.12 49.12 49.12 49.12 49.12 Woodchip & Polytunnel Operating 5% 2.71 2.71 2.71 2.71 2.71 0.00 0.00 0.00 0.00 0.00 Expenses Depreciation (years) 8% 60.18 55.37 50.94 46.86 43.12 39.67 36.49 33.57 30.89 28.42
Operating Profit (Profit Before 13.19 18.00 22.43 26.51 30.26 107.71 110.88 113.80 116.49 118.96 Financing costs)
Less Bank Loan Interest 1 39.88 38.24 36.48 34.60 32.58 30.41 28.09 25.60 22.92 20.06 Less Bank Loan Interest 2 3.88 3.59 3.59 3.59 3.59 3.59 3.59 3.59 3.59 3.59 Net Profit/Loss (PAFC) -30.57 -23.83 -17.65 -11.69 -5.92 73.70 79.20 84.61 89.97 95.30 Less Preference shares 0.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Assumed proportion (Net Profit -pref 33% -10.09 -7.87 -5.82 -3.86 -1.95 24.32 26.14 27.92 29.69 31.45 shares dividends paid) to equity Retained profit -20.48 -15.97 -11.82 -7.83 -3.96 49.38 53.06 56.69 60.28 63.85
Cashflow Profit + depreciation 29.61 31.54 33.29 35.18 37.20 113.37 115.69 118.18 120.86 123.72 Less bank loan 1 capital 22.68 24.32 26.07 27.96 29.98 32.15 34.47 36.96 39.64 42.50 bank loan 2 capital 3.40 3.69 3.99 4.32 4.68 5.07 5.49 5.95 6.44 6.97 Repayment of pref shares - year 11-15 0.00 Dividends (pref & ordinary) -10.09 -7.87 -5.82 -3.86 -1.95 24.32 26.14 27.92 29.69 31.45 Opening cash 0.00 13.62 25.02 34.07 40.83 45.32 97.15 146.74 194.10 239.19 Closing cash 13.62 25.02 34.07 40.83 45.32 97.15 146.74 194.10 239.19 281.98 Interest on overdrafts 8.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Net cashflow 13.62 11.40 9.05 6.75 4.49 51.83 49.59 47.35 45.09 42.80
Community Energy Scotland 34
4.4. Off-Site Options: Microgrid
Main assumptions: Note that the financial benefit to householders of more affordable heat and electricity relative to standard tariffs and fuels is not included in this analysis, which is undertaken from the generator’s point of the view Grant is included in capex as it is eligible for certain costs (not the hydroelectric generator itself) Opex for the microgrid are assumed to be 15% of income. This accounts for maintenance, metering and billing.25
Hydro-Electric Generator £,000 Feed in Tarrifs rate (£/kWh) 0.126
Development costs 150 Power Purchase Agreement (PPA) (£/kWh) 0.055 Installed capacity (MW) 0.35
Capital costs 1090.5 Microgrid Electricity Price (£/kWh) 0.120 Capacity factor 35% Hydro 700 Microgrid Heat price (£/kWh) 0.060 Unconstrained Output (MWh) 1,084 Export Control Unit 100 Supply Prioritasion per Price Microgrid 290.5 1. Microgrid Electricity Demand (MWh) 131 Working capital 50 2. Microgrid Heat Demand (MWh) 382 3. Grid Output with Export limit (MWh) 168 Total cost 1,291 4. Excess Output post 2021 (MWh) 402
FINANCIAL ANALYSIS
Equity 450 35% Grant 400 31% Loan / Bond (15 year term) 450 35% Loan 2 (10 year term) 100 8% 10 year Preference shares 0 0% 1,400 Loan / Bond 1 rate 7.00% Loan / Bond 2 rate 8.00%
Inflation (RPI) 0.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 £,000 Income (£,000) 133.89 112.67 112.67 112.67 112.67 206.77 206.77 206.77 206.77 206.77
Hydro Operating Expenses 25% 33.47 28.17 28.17 28.17 28.17 51.69 51.69 51.69 51.69 51.69 Microgrid Operating Expenses 15% 15.51 15.51 15.51 15.51 15.51 15.51 15.51 15.51 15.51 15.51 Depreciation (years) 8% 87.24 80.26 73.84 67.93 62.50 57.50 52.90 48.67 44.77 41.19
Operating Profit (Profit Before Financing -2.34 -11.27 -4.85 1.06 6.49 82.07 86.67 90.90 94.79 98.37 costs)
Less Bank Loan Interest 1 30.94 29.67 28.31 26.84 25.28 23.59 21.79 19.86 17.79 15.56 Less Bank Loan Interest 2 7.75 7.19 7.19 7.19 7.19 7.19 7.19 7.19 7.19 7.19 Net Profit/Loss (PAFC) -41.03 -48.13 -40.35 -32.98 -25.97 51.28 57.69 63.85 69.82 75.62 Less Preference shares 0.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Assumed proportion (Net Profit -pref 33% -13.54 -15.88 -13.31 -10.88 -8.57 16.92 19.04 21.07 23.04 24.96 shares dividends paid) to equity Retained profit -27.49 -32.25 -27.03 -22.09 -17.40 34.36 38.65 42.78 46.78 50.67
Cashflow Profit + depreciation 46.21 32.13 33.49 34.96 36.52 108.78 110.58 112.52 114.59 116.81 Less bank loan 1 capital 17.59 18.87 20.23 21.69 23.26 24.94 26.74 28.68 30.75 32.97 bank loan 2 capital 6.81 7.37 7.98 8.64 9.36 10.14 10.98 11.89 12.88 13.95 Repayment of pref shares - year 11-15 0.00 Dividends (pref & ordinary) -13.54 -15.88 -13.31 -10.88 -8.57 16.92 19.04 21.07 23.04 24.96 Opening cash 0.00 35.35 57.12 75.72 91.22 103.69 160.47 214.29 265.17 313.09 Closing cash 35.35 57.12 75.72 91.22 103.69 160.47 214.29 265.17 313.09 358.03 Interest on overdrafts 8.00% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Net cashflow 35.35 21.78 18.60 15.50 12.47 56.78 53.82 50.88 47.92 44.94 25 Costs obtained from private communication with an existing small-scale hydro-powered microgrid. (www.knoydart-foundation.com)
Community Energy Scotland 35
5. Summary and Recommendations
This report has outlined six options to maximise the use of constrained renewable energy from the proposed hydroelectric scheme on the River Avich. Table 21 summarises each option, its contribution to the overall curtailment reduction, its main capital costs, its yearly income and the preference ranking within Dalavich Improvement Group community members.
Options Curtailment Main Capital Average Yearly Community Comments Level after Costs (£,000) Income (£,000) Preference Option Export Only 76% -- 47.3 -- This is the current situation for DIG Microgrid 37% 290.5 133.89 *** This option is aimed to continue working post 2021 full connection Electric 72.5% Lease -- ** This option can be mixed with Vehicles monthly fee others. Polytunnel 69% 16.3 101.44 ** This option can be mixed with others. Woodchip 45.6% 89.5 * This option is aimed to be Drying temporary. Pre 2021 only. Woodpellets 46.4% 138.5 -- - This option was not favoured by Production DIG. No further analysis is given. Export Control Unit Variable -- -- This unit is required regardless of the option chosen Table 21. Options summary
The financial analysis assumes all the options except the microgrid are temporary and once the full connection is in place (after 2021) they will no longer be used. The microgrid is assumed permanent due to the level of investment required and to the more profitable results arising from selling energy locally as opposed to exporting to the national grid.
Based on the results obtained, Community Energy Scotland suggests further exploring the microgrid option. DIG could also look into the possibility of including electric vehicles and polytunnel as part of the microgrid, as well as expanding the use of the community hall. The woodchip drying option also appears to be viable if operated by a third party.
Community Energy Scotland recommends the following next steps: Acquire detailed flow data for River Avich facilitating detailed modelling of the hydroelectric scheme Detailed design and outline budget of hydroelectric scheme by specialist consultants, including evaluation of turbine size options in light of grid constraint and FiT levels Door to door detailed survey of heating systems, consumer units and metering in potential microgrid properties and collection of historic billing data for residents with 12 month records Installation of data loggers in sample of properties to record detailed energy usage for benchmarking demand Confirmation of ownership of land crossed by the proposed microgrid Detailed technical design and outline budget of Microgrid by specialist consultants Financial modelling of hydroelectric and Microgrid following design work Further community consultation when results are available
Community Energy Scotland 36
Works Cited
(n.d.). Retrieved from Thermotec Ecosystems Ltd.: http://www.thermotec.co.uk/
Buccleuch Woodland. (2014). Examining the Oportunities for Establishement of a New Kiln Drying Facility in the Scottish Borders. Scottish Borders Council .
3R Energy. (n.d.). Retrieved from 3R Energy Wind & Biomass: http://www.3renergy.co.uk/
Ahmed, A. (2012). Energy Conservation. Rijeka, Croatia: inTech Europe.
Carbon Trust. (2012). Agriculture and Horticulture: Introducing Energy Saving Opportunities for Farmers and Growers. London: www.carbontrust.com.
Coed Cymru Cyf. (2011). Innovation:Pellets. Retrieved January 4, 2015, from Coed Cymru Website: http://www.coedcymru.org.uk/pellets.html
Department for Transport . (2013). National Travel Survey: Statistical Realease. Department for Transport .
EUBIA. (2012). About Biomass: Economics, applications and standards. Retrieved January 4, 2015, from European Biomass Industry Association: http://www.eubia.org/index.php/about-biomass/biomass- pelleting/economics-applications-and-standards
Forestry Commision Scotland. (n.d.). Supplying Woodfuel : Market Demand. Retrieved from Usewoodfuel Scotland: http://www.usewoodfuel.co.uk/supplying-woodfuel/market-demand.aspx
Fuelwood (Warwick) Ltd . (n.d.). Retrieved from Fuelwood: http://www.fuelwood.co.uk/
Mani, S., Sokhansanj, S., Bi, X., & Turhollow, A. (2006). Economics Of Producing Fuel Pellets From Biomass. Applied Engineering in Agriculture, 421 - 426.
Next Green Car Ltd. (2014). Zap- Map. Retrieved January 8, 2015, from www.Zap-Map.com
Nissan Motor Ltd. (n.d.). Nissa e-NV200. Retrieved January 8, 2015, from www.nissan.co.uk
Price, M. (2011). Woodchip Drying. Centre for Forest Resources & Management . Delamere: Forestry Commision Scotland.
Prime, J., Khan, S., & Wilkes, E. (2014). Energy Consumption in the UK. Department of Energy and Climate Change.
Robbins, J. (2013). Starting a Greenhouse Business . Fayetteville: University of Arkansas.
SCHULLER, A. L. (2004). Developing A Wood Pellet Fuel Sector In South Yorkshire. South Yorkshire Forest Partnership - SYFP - Community Forest.
Solar and Wind Applications Ltd. (n.d.). Retrieved from Solar&Wind Applications: www.solarwindapplications.com
Świgoń, J., & Longauer, J. (2005). Energy Consumption In Wood Pellets Production. Folia Forestalia Polonica, 77-83.
Community Energy Scotland 37
Theka, G., & Obernbergera, I. (2004). Wood pellet production costs under Austrian and in comparison to Swedish framework conditions. Biomass and Bioenergy, 671–693.
Uasuf, A., & Becker, G. (2011). Wood pellets production costs and energy consumption under. biomass and bioenergy , 1357 - 1366.
VisitScotland. (2014). Farmers' markets in Argyll & The Isles. Retrieved January 11, 2015, from Visit Scotlan: Scotland's NAtional Tourism Organisation: http://www.visitscotland.com/about/food-drink/farmers- markets/argyll-isles/
Zimmermann, J., Evans, M., & Griggs, J. (2012). Household Electricity Survey: A study of Electrical Product Usage. www.gov.uk.
Community Energy Scotland 38
Appendix A: Assumptions for production of estimated domestic annual demand
For Dalavich Village: 75% of homes in Dalavich have no electric heating as indicated in the survey 25% of homes in Dalavich use secondary electric heating as indicated in the survey Electricity consumption of homes in Dalavich is based on national statics from reference given in main body text1 (4.2MWh per household per year) Non-electric heating consumption of homes in Dalavich is based on national statics from reference given in main body text2 (non 15.29MWh per household per year) For homes in Dalavich 92% of non-electric heating is oil-fired as indicated in the survey For homes in Dalavich 8% of non-electric heating is biomass/wood as indicated in the survey
For Holiday Chalets North of Dalavich Village: 17% of holiday chalets have no electric heating as indicated in the survey 50% of holiday chalets use secondary electric heating as indicated in the survey Electricity consumption of holiday chalets is based on national statics from reference given in main body text1 (3.0MWh per household per year) Non-electric heating consumption of holiday chalets is based taken from the survey as seasonal variations for holiday homes mean national statistics cannot be used (4.333MWh per household per year) For holiday chalets 100% of non-electric heating is biomass/wood
For Inverinan Village: 50% of homes in Inverinan have no electric heating as indicated in the survey 25% of homes in Inverinan use secondary electric heating as indicated in the survey Electricity consumption of homes in Inverinan is based on national statics from reference given in main body text1 (4.35MWh per household per year) Non-electric heating consumption of homes in Inverinan is based on national statics from reference given in main body text2 (non 15.29MWh per household per year) For homes in Inverinan 67% of non-electric heating is oil-fired as indicated in the survey For homes in Inverinan 30% of non-electric heating is biomass/wood as indicated in the survey For homes in Inverinan 3% of non-electric heating is LPG as indicated in the survey
Community Energy Scotland 39
Appendix B: Assumptions for production of estimated demand for each property cluster
For Both Clusters
Seasonality of electric heating follows the relationship given in Figure B-1.
3.00
2.50
2.00
1.50
1.00
Heating Seasonality Seasonality Factor Heating 0.50
0.00 0 10 20 30 40 50 Weeks
Figure B-1: Seasonality factor for domestic electric heating
For Cluster A
Only domestic properties have been considered 45 end-terrace type houses in Dalavich 45 detached holiday chalets North of Dalavich Houses in Dalavich occupied for 100% of the year Holiday Chalets occupied for January and May-October inclusive Only 60% of Holiday Chalets used Estimated biomass hourly consumption by month for Dalavich homes given in Table B-1 Estimated oil hourly consumption by month for Dalavich given in Table B-2 Biomass hourly consumption by month for Holiday Chalets homes given in Table B-3
Time Demand (kWh) Start Finish Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 00:00 01:00 0.19 0.19 0.19 0.16 0.09 0.06 0.06 0.06 0.06 0.07 0.10 0.10 01:00 02:00 0.14 0.14 0.14 0.11 0.05 0.01 0.01 0.01 0.02 0.03 0.05 0.05 02:00 03:00 0.17 0.17 0.17 0.14 0.07 0.02 0.02 0.02 0.05 0.06 0.07 0.07 03:00 04:00 0.21 0.21 0.21 0.18 0.09 0.04 0.04 0.04 0.08 0.08 0.09 0.09 04:00 05:00 0.23 0.23 0.23 0.19 0.11 0.05 0.05 0.05 0.09 0.09 0.10 0.10 05:00 06:00 0.23 0.23 0.23 0.20 0.12 0.06 0.06 0.06 0.09 0.10 0.10 0.10 06:00 07:00 0.24 0.24 0.24 0.21 0.12 0.05 0.05 0.05 0.10 0.10 0.10 0.10 07:00 08:00 0.34 0.34 0.34 0.30 0.19 0.11 0.11 0.11 0.18 0.19 0.18 0.18 08:00 09:00 0.46 0.46 0.46 0.40 0.25 0.15 0.15 0.15 0.26 0.27 0.28 0.28 09:00 10:00 0.33 0.33 0.33 0.27 0.16 0.10 0.10 0.10 0.17 0.18 0.22 0.22 10:00 11:00 0.15 0.15 0.15 0.12 0.08 0.07 0.07 0.07 0.09 0.10 0.14 0.14 11:00 12:00 0.13 0.13 0.13 0.09 0.05 0.04 0.04 0.04 0.07 0.07 0.12 0.12 12:00 13:00 0.11 0.11 0.11 0.08 0.04 0.03 0.03 0.03 0.06 0.06 0.12 0.12 13:00 14:00 0.10 0.10 0.10 0.07 0.03 0.03 0.03 0.03 0.05 0.05 0.12 0.12 14:00 15:00 0.10 0.10 0.10 0.06 0.02 0.02 0.02 0.02 0.04 0.05 0.11 0.11
Community Energy Scotland 40
15:00 16:00 0.09 0.09 0.09 0.06 0.02 0.02 0.02 0.02 0.04 0.05 0.11 0.11 16:00 17:00 0.09 0.09 0.09 0.06 0.02 0.01 0.01 0.01 0.04 0.05 0.11 0.11 17:00 18:00 0.10 0.10 0.10 0.06 0.02 0.02 0.02 0.02 0.05 0.06 0.11 0.11 18:00 19:00 0.34 0.34 0.34 0.24 0.11 0.06 0.06 0.06 0.16 0.18 0.24 0.24 19:00 20:00 0.48 0.48 0.48 0.35 0.16 0.07 0.07 0.07 0.22 0.24 0.31 0.31 20:00 21:00 0.46 0.46 0.46 0.34 0.15 0.06 0.06 0.06 0.21 0.22 0.30 0.30 21:00 22:00 0.39 0.39 0.39 0.31 0.16 0.07 0.07 0.07 0.19 0.20 0.25 0.25 22:00 23:00 0.37 0.37 0.37 0.30 0.17 0.10 0.10 0.10 0.19 0.20 0.23 0.23 23:00 00:00 0.37 0.37 0.37 0.31 0.19 0.12 0.12 0.12 0.20 0.20 0.23 0.23 Table B-1: Estimated biomass hourly demand by month for the average property in Dalavich Village
Time Demand (kWh) Start Finish Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 00:00 01:00 2.12 2.12 2.12 1.73 1.01 0.62 0.62 0.62 0.71 0.73 1.07 1.07 01:00 02:00 1.53 1.53 1.53 1.17 0.50 0.11 0.11 0.11 0.26 0.28 0.52 0.52 02:00 03:00 1.87 1.87 1.87 1.52 0.74 0.22 0.22 0.22 0.56 0.60 0.80 0.80 03:00 04:00 2.29 2.29 2.29 1.92 1.03 0.41 0.41 0.41 0.82 0.87 1.01 1.01 04:00 05:00 2.48 2.48 2.48 2.11 1.20 0.57 0.57 0.57 0.97 1.01 1.10 1.10 05:00 06:00 2.56 2.56 2.56 2.20 1.29 0.64 0.64 0.64 1.04 1.08 1.14 1.14 06:00 07:00 2.59 2.59 2.59 2.24 1.28 0.56 0.56 0.56 1.07 1.13 1.12 1.12 07:00 08:00 3.71 3.71 3.71 3.28 2.07 1.16 1.16 1.16 1.99 2.08 1.98 1.98 08:00 09:00 5.02 5.02 5.02 4.33 2.75 1.66 1.66 1.66 2.86 2.99 3.05 3.05 09:00 10:00 3.64 3.64 3.64 2.96 1.73 1.04 1.04 1.04 1.88 1.99 2.41 2.41 10:00 11:00 1.67 1.67 1.67 1.36 0.91 0.71 0.71 0.71 1.02 1.07 1.55 1.55 11:00 12:00 1.39 1.39 1.39 1.03 0.60 0.49 0.49 0.49 0.75 0.80 1.35 1.35 12:00 13:00 1.23 1.23 1.23 0.83 0.42 0.36 0.36 0.36 0.62 0.67 1.29 1.29 13:00 14:00 1.15 1.15 1.15 0.74 0.34 0.32 0.32 0.32 0.54 0.59 1.27 1.27 14:00 15:00 1.08 1.08 1.08 0.68 0.27 0.23 0.23 0.23 0.48 0.53 1.24 1.24 15:00 16:00 1.03 1.03 1.03 0.65 0.25 0.19 0.19 0.19 0.45 0.50 1.22 1.22 16:00 17:00 1.03 1.03 1.03 0.63 0.21 0.15 0.15 0.15 0.47 0.53 1.23 1.23 17:00 18:00 1.07 1.07 1.07 0.67 0.24 0.17 0.17 0.17 0.55 0.61 1.23 1.23 18:00 19:00 3.67 3.67 3.67 2.64 1.23 0.69 0.69 0.69 1.78 1.93 2.68 2.68 19:00 20:00 5.26 5.26 5.26 3.85 1.72 0.77 0.77 0.77 2.36 2.57 3.43 3.43 20:00 21:00 5.01 5.01 5.01 3.77 1.69 0.61 0.61 0.61 2.24 2.45 3.23 3.23 21:00 22:00 4.26 4.26 4.26 3.34 1.71 0.81 0.81 0.81 2.07 2.23 2.72 2.72 22:00 23:00 4.09 4.09 4.09 3.30 1.88 1.09 1.09 1.09 2.07 2.19 2.57 2.57 23:00 00:00 4.09 4.09 4.09 3.39 2.10 1.36 1.36 1.36 2.14 2.24 2.54 2.54 Table B-2: Estimated oil hourly demand by month for the average property in Dalavich Village
Time Demand (kWh) Start Finish Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 00:00 01:00 1.58 0.00 0.00 0.00 0.76 0.43 0.43 0.43 0.54 0.56 0.00 0.00 01:00 02:00 1.17 0.00 0.00 0.00 0.41 0.10 0.10 0.10 0.23 0.25 0.00 0.00 02:00 03:00 1.42 0.00 0.00 0.00 0.60 0.20 0.20 0.20 0.46 0.50 0.00 0.00 03:00 04:00 1.73 0.00 0.00 0.00 0.82 0.36 0.36 0.36 0.68 0.71 0.00 0.00 04:00 05:00 1.86 0.00 0.00 0.00 0.95 0.50 0.50 0.50 0.78 0.82 0.00 0.00 05:00 06:00 1.91 0.00 0.00 0.00 1.02 0.56 0.56 0.56 0.83 0.87 0.00 0.00 06:00 07:00 1.93 0.00 0.00 0.00 1.00 0.49 0.49 0.49 0.85 0.89 0.00 0.00 07:00 08:00 2.70 0.00 0.00 0.00 1.55 0.90 0.90 0.90 1.49 1.55 0.00 0.00 08:00 09:00 3.62 0.00 0.00 0.00 2.01 1.21 1.21 1.21 2.12 2.22 0.00 0.00 09:00 10:00 2.63 0.00 0.00 0.00 1.25 0.72 0.72 0.72 1.40 1.48 0.00 0.00 10:00 11:00 1.18 0.00 0.00 0.00 0.63 0.47 0.47 0.47 0.75 0.79 0.00 0.00 11:00 12:00 0.98 0.00 0.00 0.00 0.41 0.31 0.31 0.31 0.54 0.58 0.00 0.00 12:00 13:00 0.88 0.00 0.00 0.00 0.29 0.22 0.22 0.22 0.44 0.48 0.00 0.00 13:00 14:00 0.82 0.00 0.00 0.00 0.24 0.20 0.20 0.20 0.38 0.42 0.00 0.00 14:00 15:00 0.78 0.00 0.00 0.00 0.18 0.14 0.14 0.14 0.34 0.38 0.00 0.00 15:00 16:00 0.74 0.00 0.00 0.00 0.16 0.11 0.11 0.11 0.32 0.36 0.00 0.00 16:00 17:00 0.74 0.00 0.00 0.00 0.14 0.10 0.10 0.10 0.32 0.37 0.00 0.00 17:00 18:00 0.76 0.00 0.00 0.00 0.15 0.10 0.10 0.10 0.37 0.42 0.00 0.00 18:00 19:00 2.55 0.00 0.00 0.00 0.80 0.41 0.41 0.41 1.22 1.33 0.00 0.00 19:00 20:00 3.72 0.00 0.00 0.00 1.14 0.46 0.46 0.46 1.63 1.79 0.00 0.00 20:00 21:00 3.60 0.00 0.00 0.00 1.14 0.38 0.38 0.38 1.56 1.71 0.00 0.00 21:00 22:00 3.03 0.00 0.00 0.00 1.17 0.52 0.52 0.52 1.45 1.57 0.00 0.00 22:00 23:00 2.91 0.00 0.00 0.00 1.32 0.73 0.73 0.73 1.47 1.56 0.00 0.00
Community Energy Scotland 41
23:00 00:00 2.93 0.00 0.00 0.00 1.49 0.95 0.95 0.95 1.54 1.61 0.00 0.00 Table B-3: Estimated biomass hourly demand by month for the average holiday chalet North of Dalavich Village
For Cluster B
Only domestic properties have been considered 15 detached type houses in Inverinan Houses in Inverinan occupied for 100% of the year Estimated biomass hourly consumption by month for Inverinan homes given in Table B-4 Estimated oil hourly consumption by month for Inverinan hourly given in Table B-5 Estimated LPG hourly consumption by month for Inverinan homes given in Table B-6
Time Demand (kWh) Start Finish Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 00:00 01:00 0.71 0.71 0.71 0.58 0.34 0.20 0.20 0.20 0.25 0.25 0.37 0.37 01:00 02:00 0.53 0.53 0.53 0.41 0.19 0.05 0.05 0.05 0.10 0.11 0.19 0.19 02:00 03:00 0.64 0.64 0.64 0.53 0.27 0.09 0.09 0.09 0.21 0.23 0.29 0.29 03:00 04:00 0.78 0.78 0.78 0.66 0.37 0.16 0.16 0.16 0.30 0.32 0.37 0.37 04:00 05:00 0.84 0.84 0.84 0.72 0.43 0.22 0.22 0.22 0.35 0.37 0.39 0.39 05:00 06:00 0.86 0.86 0.86 0.75 0.46 0.25 0.25 0.25 0.38 0.39 0.40 0.40 06:00 07:00 0.87 0.87 0.87 0.76 0.45 0.22 0.22 0.22 0.38 0.40 0.39 0.39 07:00 08:00 1.22 1.22 1.22 1.08 0.70 0.40 0.40 0.40 0.67 0.70 0.66 0.66 08:00 09:00 1.63 1.63 1.63 1.42 0.91 0.55 0.55 0.55 0.95 1.00 1.00 1.00 09:00 10:00 1.18 1.18 1.18 0.97 0.56 0.32 0.32 0.32 0.63 0.67 0.78 0.78 10:00 11:00 0.53 0.53 0.53 0.44 0.29 0.21 0.21 0.21 0.34 0.36 0.50 0.50 11:00 12:00 0.44 0.44 0.44 0.33 0.18 0.14 0.14 0.14 0.25 0.26 0.43 0.43 12:00 13:00 0.39 0.39 0.39 0.27 0.13 0.10 0.10 0.10 0.20 0.22 0.41 0.41 13:00 14:00 0.37 0.37 0.37 0.24 0.11 0.09 0.09 0.09 0.17 0.19 0.41 0.41 14:00 15:00 0.35 0.35 0.35 0.22 0.08 0.06 0.06 0.06 0.15 0.17 0.40 0.40 15:00 16:00 0.33 0.33 0.33 0.21 0.07 0.05 0.05 0.05 0.14 0.16 0.39 0.39 16:00 17:00 0.33 0.33 0.33 0.20 0.06 0.04 0.04 0.04 0.15 0.17 0.39 0.39 17:00 18:00 0.34 0.34 0.34 0.21 0.07 0.05 0.05 0.05 0.17 0.19 0.40 0.40 18:00 19:00 1.15 1.15 1.15 0.82 0.36 0.19 0.19 0.19 0.55 0.60 0.85 0.85 19:00 20:00 1.68 1.68 1.68 1.21 0.51 0.21 0.21 0.21 0.74 0.81 1.10 1.10 20:00 21:00 1.62 1.62 1.62 1.21 0.52 0.17 0.17 0.17 0.70 0.77 1.04 1.04 21:00 22:00 1.37 1.37 1.37 1.06 0.53 0.23 0.23 0.23 0.66 0.71 0.88 0.88 22:00 23:00 1.31 1.31 1.31 1.06 0.59 0.33 0.33 0.33 0.66 0.70 0.83 0.83 23:00 00:00 1.32 1.32 1.32 1.10 0.67 0.43 0.43 0.43 0.69 0.73 0.83 0.83 Table B-4: Estimated biomass hourly demand by month for the average home in Inverinan
Time Demand (kWh) Start Finish Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 00:00 01:00 1.61 1.61 1.61 1.32 0.77 0.44 0.44 0.44 0.55 0.58 0.84 0.84 01:00 02:00 1.19 1.19 1.19 0.93 0.42 0.10 0.10 0.10 0.24 0.26 0.43 0.43 02:00 03:00 1.44 1.44 1.44 1.19 0.61 0.20 0.20 0.20 0.47 0.51 0.65 0.65 03:00 04:00 1.76 1.76 1.76 1.49 0.84 0.37 0.37 0.37 0.69 0.73 0.83 0.83 04:00 05:00 1.89 1.89 1.89 1.63 0.97 0.51 0.51 0.51 0.80 0.83 0.89 0.89 05:00 06:00 1.95 1.95 1.95 1.69 1.04 0.57 0.57 0.57 0.85 0.88 0.91 0.91 06:00 07:00 1.97 1.97 1.97 1.72 1.02 0.50 0.50 0.50 0.87 0.91 0.89 0.89 07:00 08:00 2.75 2.75 2.75 2.44 1.58 0.91 0.91 0.91 1.52 1.58 1.50 1.50 08:00 09:00 3.69 3.69 3.69 3.20 2.05 1.24 1.24 1.24 2.16 2.26 2.25 2.25 09:00 10:00 2.68 2.68 2.68 2.19 1.27 0.73 0.73 0.73 1.42 1.51 1.77 1.77 10:00 11:00 1.20 1.20 1.20 0.99 0.65 0.48 0.48 0.48 0.76 0.80 1.13 1.13 11:00 12:00 1.00 1.00 1.00 0.74 0.42 0.32 0.32 0.32 0.55 0.59 0.98 0.98 12:00 13:00 0.89 0.89 0.89 0.61 0.29 0.23 0.23 0.23 0.45 0.49 0.93 0.93 13:00 14:00 0.83 0.83 0.83 0.54 0.24 0.21 0.21 0.21 0.39 0.43 0.92 0.92 14:00 15:00 0.79 0.79 0.79 0.49 0.18 0.14 0.14 0.14 0.35 0.39 0.90 0.90 15:00 16:00 0.76 0.76 0.76 0.47 0.17 0.12 0.12 0.12 0.32 0.36 0.88 0.88 16:00 17:00 0.75 0.75 0.75 0.46 0.15 0.10 0.10 0.10 0.33 0.37 0.89 0.89 17:00 18:00 0.77 0.77 0.77 0.47 0.15 0.11 0.11 0.11 0.38 0.43 0.89 0.89 18:00 19:00 2.60 2.60 2.60 1.85 0.82 0.42 0.42 0.42 1.25 1.36 1.92 1.92
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19:00 20:00 3.79 3.79 3.79 2.74 1.16 0.47 0.47 0.47 1.67 1.82 2.48 2.48 20:00 21:00 3.67 3.67 3.67 2.72 1.17 0.38 0.38 0.38 1.59 1.74 2.36 2.36 21:00 22:00 3.09 3.09 3.09 2.41 1.19 0.53 0.53 0.53 1.48 1.60 1.99 1.99 22:00 23:00 2.97 2.97 2.97 2.40 1.34 0.74 0.74 0.74 1.50 1.59 1.88 1.88 23:00 00:00 2.99 2.99 2.99 2.48 1.52 0.97 0.97 0.97 1.57 1.64 1.87 1.87 Table B-5: Estimated oil hourly demand by month for the average home in Inverinan
Time Demand (kWh) Start Finish Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 00:00 01:00 0.06 0.06 0.06 0.05 0.03 0.02 0.02 0.02 0.02 0.02 0.03 0.03 01:00 02:00 0.04 0.04 0.04 0.03 0.02 0.00 0.00 0.00 0.01 0.01 0.02 0.02 02:00 03:00 0.05 0.05 0.05 0.04 0.02 0.01 0.01 0.01 0.02 0.02 0.02 0.02 03:00 04:00 0.07 0.07 0.07 0.06 0.03 0.01 0.01 0.01 0.03 0.03 0.03 0.03 04:00 05:00 0.07 0.07 0.07 0.06 0.04 0.02 0.02 0.02 0.03 0.03 0.03 0.03 05:00 06:00 0.07 0.07 0.07 0.06 0.04 0.02 0.02 0.02 0.03 0.03 0.03 0.03 06:00 07:00 0.07 0.07 0.07 0.06 0.04 0.02 0.02 0.02 0.03 0.03 0.03 0.03 07:00 08:00 0.10 0.10 0.10 0.09 0.06 0.03 0.03 0.03 0.06 0.06 0.06 0.06 08:00 09:00 0.14 0.14 0.14 0.12 0.08 0.05 0.05 0.05 0.08 0.08 0.08 0.08 09:00 10:00 0.10 0.10 0.10 0.08 0.05 0.03 0.03 0.03 0.05 0.06 0.07 0.07 10:00 11:00 0.04 0.04 0.04 0.04 0.02 0.02 0.02 0.02 0.03 0.03 0.04 0.04 11:00 12:00 0.04 0.04 0.04 0.03 0.02 0.01 0.01 0.01 0.02 0.02 0.04 0.04 12:00 13:00 0.03 0.03 0.03 0.02 0.01 0.01 0.01 0.01 0.02 0.02 0.03 0.03 13:00 14:00 0.03 0.03 0.03 0.02 0.01 0.01 0.01 0.01 0.01 0.02 0.03 0.03 14:00 15:00 0.03 0.03 0.03 0.02 0.01 0.01 0.01 0.01 0.01 0.01 0.03 0.03 15:00 16:00 0.03 0.03 0.03 0.02 0.01 0.00 0.00 0.00 0.01 0.01 0.03 0.03 16:00 17:00 0.03 0.03 0.03 0.02 0.01 0.00 0.00 0.00 0.01 0.01 0.03 0.03 17:00 18:00 0.03 0.03 0.03 0.02 0.01 0.00 0.00 0.00 0.01 0.02 0.03 0.03 18:00 19:00 0.10 0.10 0.10 0.07 0.03 0.02 0.02 0.02 0.05 0.05 0.07 0.07 19:00 20:00 0.14 0.14 0.14 0.10 0.04 0.02 0.02 0.02 0.06 0.07 0.09 0.09 20:00 21:00 0.14 0.14 0.14 0.10 0.04 0.01 0.01 0.01 0.06 0.06 0.09 0.09 21:00 22:00 0.12 0.12 0.12 0.09 0.04 0.02 0.02 0.02 0.06 0.06 0.07 0.07 22:00 23:00 0.11 0.11 0.11 0.09 0.05 0.03 0.03 0.03 0.06 0.06 0.07 0.07 23:00 00:00 0.11 0.11 0.11 0.09 0.06 0.04 0.04 0.04 0.06 0.06 0.07 0.07 Table B-6: Estimated LPG hourly demand by month for the average home in Inverinan
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Appendix C: Estimated Demand Curves
500
400 300 200
Power (kW) Power 100
0
05:30 13:30 22:30 00:30 01:30 02:30 03:30 04:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 14:30 15:30 16:30 17:30 18:30 19:30 20:30 21:30 23:30 Hours
Electricity Electric Heating Oil Biomass Mean Generation
Figure C-1: Average hourly load curve, Cluster A, January
500
400 300 200
Power (kW) Power 100
0
01:30 14:30 00:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 15:30 16:30 17:30 18:30 19:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-2: Average hourly load curve, Cluster A, February
500
400 300 200
Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
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Figure C-3: Average hourly load curve, Cluster A, March
500
400
300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-4: Average hourly load curve, Cluster A, April
500
400 300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-5: Average hourly load curve, Cluster A, May
500
400
300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
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Figure C-6: Average hourly load curve, Cluster A, June
500
400 300 200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-7: Average hourly load curve, Cluster A, July
500
400 300 200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-8: Average hourly load curve, Cluster A, August
500
400 300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
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Figure C-9: Average hourly load curve, Cluster A, September
500
400
300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-10: Average hourly load curve, Cluster A, October
500
400
300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-11: Average hourly load curve, Cluster A, November
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500
400
300
200 Power (kW) Power 100
0
03:30 10:30 17:30 23:30 00:30 01:30 02:30 04:30 05:30 06:30 07:30 08:30 09:30 11:30 12:30 13:30 14:30 15:30 16:30 18:30 19:30 20:30 21:30 22:30 Hours Electricity Electric Heating Oil Biomass Mean Generation
Figure C-12 Average hourly load curve, Cluster A, December
500 450 400 350 300 250 200
Power (kW) Power 150 100 50
0
01:30 10:30 19:30 00:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 11:30 12:30 13:30 14:30 15:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-13: Average hourly load curve, Cluster B, January
500
400
300
200 Power (kW) Power 100
0
02:30 06:30 15:30 19:30 00:30 01:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-14: Average hourly load curve, Cluster B, February
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500
400
300
200 Power (kW) Power 100
0
01:30 06:30 15:30 20:30 00:30 02:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 19:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-15: Average hourly load curve, Cluster B, March
500
400
300
200 Power (kW) Power 100
0
02:30 06:30 15:30 19:30 00:30 01:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-16 Average hourly load curve, Cluster B, April
500
400
300
200 Power (kW) Power 100
0
02:30 06:30 15:30 19:30 00:30 01:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-17 Average hourly load curve, Cluster B, May
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500
400
300
200 Power (kW) Power 100
0
01:30 06:30 15:30 20:30 00:30 02:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 19:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-18 Average hourly load curve, Cluster B, June
500
400
300
200 Power (kW) Power 100
0
01:30 06:30 15:30 20:30 00:30 02:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 19:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-19 Average hourly load curve, Cluster B, July
500
400
300
200 Power (kW) Power 100
0
17:30 18:30 19:30 20:30 00:30 01:30 02:30 03:30 04:30 05:30 06:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 15:30 16:30 21:30 22:30 23:30 Hours
Electricity Electric Heating Oil Biomass LPG Mean Generation
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Figure C-20 Average hourly load curve, Cluster B, August
500
400
300
200 Power (kW) Power 100
0
02:30 06:30 15:30 19:30 00:30 01:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours
Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-21: Average hourly load curve, Cluster B, September
500
400
300
200 Power (kW) Power 100
0
02:30 06:30 15:30 19:30 00:30 01:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-22 Average hourly load curve, Cluster B, October
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500
400
300
200 Power (kW) Power 100
0
02:30 06:30 15:30 19:30 00:30 01:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 20:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-23: Average hourly load curve, Cluster B, November
500
400
300
200 Power (kW) Power 100
0
01:30 06:30 15:30 20:30 00:30 02:30 03:30 04:30 05:30 07:30 08:30 09:30 10:30 11:30 12:30 13:30 14:30 16:30 17:30 18:30 19:30 21:30 22:30 23:30 Hours Electricity Electric Heating Oil Biomass LPG Mean Generation
Figure C-24. Average hourly load curve, Cluster B, December
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