Contract N°: EIE/07/159/SI2. 466845 · executive agency for competitiveness and innovation...

EXECUTIVE AGENCY FOR COMPETITIVENESS AND INNOVATION

Contract N°: EIE/07/159/SI2. 466845

STORIES

1 STORIES REFERENCE: STORIES 01 0102 ON 01022 6/30/2010 12:33:00

PM Internal partner reference: Issued by: WP Doc. Type: Order N°: Date:

Deliverable D2.3:

COST-BENEFIT ANALYSIS



STORIES



DOCUMENT NOTE

YES NO

Distribution List: Centre for Renewable Energy Sources

National Technical University of Athens

Canary Islands Institute of Technology

Instituto de Engenharia Mecanica – Polo IST

Regulatory Authority for Energy of the Hellenic Republic

Western Isles Council – ISLENET

European Renewable Energy Council

SOFTECH Energia Tecnologia Ambiente s.r.l.

University of Zagreb

Cyprus Energy Regulatory Authority

European Commission

E

D

C

B

A

22/12/09 O. Parissis A. Tsikalakis G. Caralis S. Suarez

M. Zoulias M. Zoulias P

Rev. Date Drafted Checked Approved Status (C-P)* * C: Confidential; P: Public



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REVISION First issue: Revision A:



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TABLE OF CONTENTS 1 EXECUTIVE SUMMARY ............................................................................................. 6 2 INTRODUCTION ........................................................................................................... 7

2.1 Aim ........................................................................................................................... 7 2.2 Objectives and scope................................................................................................. 7 2.3 Methodology ............................................................................................................. 8

2.3.1 Financial analysis ............................................................................................... 8 2.3.2 Economic analysis ............................................................................................. 9 2.3.3 Sensitivity analysis........................................................................................... 10

3 BATTERY STORAGE .................................................................................................. 11 3.1 Overview ................................................................................................................. 11 3.2 Case Study 1 – La Graciosa .................................................................................... 11

3.2.1 Financial Analysis ............................................................................................ 11 3.2.2 General Economic Perspective ........................................................................ 14

3.3 Case Study 2 - San Pietro........................................................................................ 21 3.3.1 Financial analysis ............................................................................................. 21 3.3.2 General Economic Perspective ........................................................................ 24

4 PUMP HYDRO STORAGE .......................................................................................... 33 4.1 Overview ................................................................................................................. 33 4.2 Case Study 1 – Ios................................................................................................... 33

4.2.1 Financial analysis ............................................................................................. 33 4.2.2 Economical-Social Cost Benefit analysis ........................................................ 37

4.3 Case Study 2 – Cyprus ............................................................................................ 39 4.3.1 Financial analysis ............................................................................................. 39 4.3.2 Economical-Social Cost Benefit analysis ........................................................ 42

4.4 Case Study 3 – Corvo ............................................................................................. 45 4.4.1 Financial analysis ............................................................................................. 45 4.4.2 Economical and Social Cost Benefit analysis .................................................. 48

4.5 Conclusions ............................................................................................................. 50 5 HYDROGEN STORAGE .............................................................................................. 51

5.1 Overview ................................................................................................................. 51 5.2 Case Study 1 – Milos .............................................................................................. 51

5.2.1 Introduction ...................................................................................................... 51 5.2.2 Financial analysis ............................................................................................. 52 5.2.3 Economic results & analysis ............................................................................ 59 5.2.4 Sensitivity analysis........................................................................................... 65 5.2.5 Summary .......................................................................................................... 72

5.3 Case Study 2 – Corvo ............................................................................................. 73 5.3.1 Introduction ...................................................................................................... 73 5.3.2 Financial analysis ............................................................................................. 73



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5.3.3 Economic results & analysis ............................................................................ 77 5.3.4 Sensitivity analysis........................................................................................... 81 5.3.5 Summary .......................................................................................................... 90

5.4 General Conclusions for hydrogen storage ............................................................. 91 6 DESALINATION .......................................................................................................... 92

6.1 Overview and General Data .................................................................................... 92 6.2 Case study 1 –Milos ................................................................................................ 92

6.2.1 Financial Analysis ............................................................................................ 93 6.2.2 Economic results & analysis ............................................................................ 94 6.2.3 Sensitivity analysis........................................................................................... 98 6.2.4 Conclusions from CBA in Milos ................................................................... 111

6.3 Case study 2-Mljet ................................................................................................ 112 6.3.1 Scenario 1....................................................................................................... 112 6.3.2 Scenario 2....................................................................................................... 123 6.3.3 Summary of the analysis for Mljet................................................................. 142

6.4 Case study 3-Cyprus ............................................................................................. 143 6.4.1 Financial Analysis .......................................................................................... 143 6.4.2 Economic Analysis & Results ....................................................................... 146 6.4.3 Sensitivity Analysis ....................................................................................... 153 6.4.4 General Conclusions for Cyprus .................................................................... 163

6.5 General conclusions for desalination .................................................................... 164 7 GENERAL SYNOPSIS ............................................................................................... 165 8 REFERENCES ............................................................................................................ 167

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1 EXECUTIVE SUMMARY Environmental and social issues are often considered as the weak point when the extensive deployment of large Renewable Energy Sources (RES) installations at a local level is concerned and are thoroughly questioned by the relevant authorities prior to the approval of any such investment. Therefore, it is crucial to suggest solutions that will create economic growth that benefits from and is consistent with sustainable natural resource and social capacities of communities. Hence, the examination of the environmental and social impacts and benefits of RES projects it is crucial to be investigated thoroughly. In the context of Work Package 2 of STORIES project simulations of selected case studies of islands had been performed. Specifically, modelling the operation of island power systems under various RES penetration scenarios through the introduction of three different energy storage technologies (batteries, pump hydro, hydrogen) and one demand side management methodology for desalination plants had been carried out. The results (Deliverable 2.1) suggest possible solutions that can contribute to an increase of RES penetration through energy storage technologies. The examination of these solutions with respect to their community compatibility and economic and environmental sustainability constitutes the goal of Task 2.3. Deliverable 2.3 presents the economic, environmental and social costs and benefits of the proposed actions for large scale

deployment of hybrid RES-energy storage power systems. More specifically, a financial and economic analysis have been performed aiming to assess the net economic impact to society as a whole of the proposed RES-energy storage system scenarios. The former analysis examines the financial benefits, costs and profitability of the selected RES-energy storage system from the investor’s perspective while the latter analysis investigates the environmental and social implications of each technology aiming to identify and assess the benefits and costs of the RES-energy storage system from the perspective of the environment and the society. Moreover, a sensitivity analysis is performed to investigate the influence of parametric variations on the results. The report provides results from the analysis of 11 case studies. These include 7 different islands, three different energy storage technologies and one demand side management methodology. The results are divided in 4 sections according to the type of energy storage method used in each case study.

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2 INTRODUCTION

2.1 Aim This report (Deliverable 2.3) focuses on the economic, environmental and social aspects of RES & energy storage installations. More specifically, the aim of the present report is the estimation of the social, economic and environmental benefits and costs of the proposed actions for a high scale deployment of hybrid RES-energy storage power systems for the island communities of STORIES project. In the framework of this report, the

results of the simulations presented in Deliverable 2.1 are the starting point of the cost-benefit analysis. All the resulted scenarios that propose an increase in RES penetration through the introduction of different energy storage methods in selected islands are individually examined with respect to their economic and environmental impacts and benefits as well as to the social impacts the project implementation may have on the local communities. The following table presents the selected islands and energy storage technologies that are used as case studies in this analysis.

Table 2-1 Selected islands and energy storage technologies

Country

Battery system

Pump- hydro

Hydrogen

Desalination

Spain La Graciosa

Greece Ios Milos Milos Croatia Mljet Portugal Corvo Corvo Italy San Pietro Cyprus Cyprus Cyprus

2.2 Objectives and scope The environmental and social issues related to the deployment of RES have recently gained increasing attention and are usually questioned by the local authorities prior to approval of any such investment. For this reason, it is crucial to evaluate a RES investment from the perspective of the environment, the society and the economy in order to suggest attractive solutions to all beneficiaries. This report examines the net economic impact of the proposed RES & energy storage power systems for selected islands on the society as a whole. The objectives that deliver this aim can be summarized as follows:

• To assess the financial viability of the proposed RES & energy storage power system from the investor’s perspective;

• To identify the environmental and social benefits and costs of the proposed RES & energy storage power system;

• To monetize the environmental and social benefits and costs of the proposed RES & energy storage power system (where applicable);

• To determine the economic viability of the proposed RES & energy storage power system from the perspective of the environment, the society and the economy by calculating the benefit-to-cost (BC) ratio;

• To perform a sensitivity analysis examining the influence of parametric variation on the results.

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The report includes 4 different energy storage methods that have been applied in the power system of 7 different islands. More specifically, the energy storage options involve batteries, pump hydro, hydrogen and desalination processes. The first 2 options provide only electricity, while the third may also be used for heating or in transport applications. The latter alternative provides potable water. The results are divided in 4 sections according to the type of energy storage method used in each case study.

2.3 Methodology In order to achieve the objectives of the present report a methodology was necessary to be followed. This section provides an overview of this methodology that was applied to all case studies aiming to examine the economic, environmental and social aspects of the most suitable energy storage technologies in combination to RES installations. The methodology consists of three stages: • the financial analysis that examines the

financial benefits, costs and profitability of the selected RES-energy storage system from the investor’s perspective,

• the economic analysis that examines the environmental and social implications of each technology aiming to identify and assess the benefits and costs of the RES-energy storage system from the perspective of the environment and the society, and

• the sensitivity analysis that investigates the influence of parametric variations on the results.

2.3.1 Financial analysis Financial analysis is used to examine the financial benefits, costs and profitability of a project from the investor’s perspective. The analysis is primarily focused on money aspects of a project, rewards and profitability to the investors. In order to evaluate the financial attractiveness of a project there is a number of appraisal techniques that can be used. The most common techniques are [1]:

• the Net Present Value (NPV), which is the difference in the present value of the cash flows and the outflows associated with a project. The NPV is a valuable indicator as it recognizes the time value of money.

• the Internal Rate of Return (IRR) that is defined as the discount rate which equates the present value of cash inflows to the present value of cash outflows. The advantage of IRR, unlike NPV, is that its percentage results allow projects of vastly different sizes to be easily compared.

• the payback period which is the time required to recover the original investment. This indicator is generally used to analyze retrofit opportunities offering incremental benefits and end-user applications.

• the Accounting Rate of Return (ARR) that measures the return of a project in terms of income, as opposed to using a project cash flow, and

• the Benefit-to-cost ratio, which is the ratio of the present value of the cash inflows to the present value of the cash outflows associated with a project.

The choice of the appraisal techniques often depends on the purpose of the analysis. However, the starting point of the analysis is the estimation of the project’s investment cost, the operational cost, the projected power output, and annual revenues. Generally, there are two approaches most commonly used to evaluate investments, NPV and IRR. Both techniques emphasize the central importance of the concept of the time value of money and are regarded as more complete than the traditional techniques of payback and ARR. The present analysis focuses on the financial evaluation of the proposed RES & energy storage technology installations for each case study based on NPV and IRR. The NPV is calculated by using the standard

formula:

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01 )1(

FFNPVN

n

n

r n∑+=

+=

where F0 = cash flow at time zero (t0), Fn = cash flow at year n (tn), r = discount rate, and n = number of years The IRR technique describes by how much the cash inflows exceed the cash outflows on an annualized percentage basis, taking into account the timing of those cash flows. IRR is the rate of return, r, that equates the discounted future cash outflows with initial inflow:

001 )1(

=+∑+=

FFN

n

n

r n

where F0 = cash flow at time zero (t0), Fn = cash flow at year n (tn), r = IRR, and n = number of years

2.3.2 Economic analysis When the activity of an individual affects another person’s welfare negatively or positively and the person affected is not recompensated for the damage caused or is not asked to pay for the benefit gained, environmental externalities arise. The production and use of energy, apart from the beneficial consequences to society, causes some unwanted side effects that damage the human health, the ecosystems, the built environment and the agriculture. The costs due to these effects are referred to as external costs, as they are not reflected in the market price of energy goods. External costs can be either benefits or costs arising during the production and consumption of a product or good. The existence of externalities is a market failure, since it prevents the market from evaluated efficiently (form a social point of view). Energy has been the focus of research for the assessment of environmental externalities as it comprises a significant

production factor in all industrial activities and a fundamental consumer good. The expansion of RES installations in combination to the most suitable energy storage technologies leads to electricity substitution and hence a significant avoidance of environmental damage and its resulting external costs. External costs of electricity generation represent the uncompensated monetary value of environmental damages it causes. These costs are imposed on the society and the environment and are not accounted for by the producers or the consumers of electricity. Thus, in order to obtain a more realistic electricity price the internalisation of the external costs is necessary. This is also essential for a fair economic comparison of different electricity generation technologies. The concept of external costs is introduced in the economic theory, but in spite of considerable research over the past decades externalities quantification still involves uncertainties. Although the quantification of the external costs is not an easy work and is not a goal in itself it helps toward to internalize them into the energy decision making process. The present economic analysis aims to identify and assess the costs and benefits of the proposed RES & energy storage technologies of each case study from the perspective of the national economy and the environment. The analysis includes a description of the environmental and social attributes of the proposed RES & energy storage technology installations for each case study followed by an attempt to quantify these impacts in order to determine the net economic impact on the society as a whole. In order to assess the net economic impact of the RES & energy storage technology installations on society a social cost-benefit analysis (CBA) was undertaken. The classical CBA estimates the equivalent money value of the benefits and costs of projects to the community to determine its viability and justification of the allocation of

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investment funds. When in this type of analysis the external costs are incorporated the CBA can act as an extension of a typical financial analysis and is capable to indicate actions or policy decisions with the lowest environmental or social impact. The benefit-cost (BC) ratio is the most widely used indicator of the profitability of a project from a social point of view. The BC ratio is defined as the total benefits divided by the total costs of a project:

CB =

CostsTotalitsTotalBenef

When calculating the BC ratio the value 1 represents the threshold for an acceptable project. The benefits and costs of the RES & energy storage technology installations were expressed in terms of equivalent money value. Moreover, the time value of money was also incorporated and thus the present values of the benefits and costs were included. Although it is not so easy to identify and monetize all the costs and benefits (especially the external costs) this work is worthwhile as it gives even in qualitative terms somehow the most appropriate solutions and perspectives. Although several methodologies have been proposed for the estimation of costs related to pollutant emissions from different electricity generation technologies, the ExternE method is a well known process which allows the damages assessment in a transparent, comprehensive and consistent way. ExternE project [2] is based in a bottom-up methodology which uses the “impact pathway” approach and was applied in representative technologies for the participant countries, based on the existing power systems, or on the expected development of these systems. It is worth mentioning that the project assess the damages specifically for each technology and site (eg. in Greece the unit examined was a new steam power plant with a total capacity of 120MW which was

scheduled to be constructed in the island of Crete in southern Greece) thus, it is somehow difficult to aggregate these marginal values to another power plant or system. Thus, the Ecosence model, an integrated software tool for environmental impact pathway assessment, was developed within ExternE project series and the issue was solved in part as the model gives ex-post results and can’t be used for electricity production optimization. Nevertheless Ecosence, assess impacts on health, crops, building materials, forests and ecosystems and for the purposes of STORIES analysis EcoSenceLE was used. EcoSenseLE is an online tool for estimating costs due to emissions of a typical source (e.g. power plant, industry, transport) or all sources of a sector in an EU country or group of EU countries. It is a parameterised version of EcoSense, based on European data for receptor (population, crops, building materials) distribution, background emissions (amount and spatial distribution), and meteorology. The input required is annual emissions of NOx, SO2, PM10, NMVOC, CO2, N2O, CH4; the pollutants considered are O3, SO2, PM10, sulfates, nitrates and greenhouse gases. The cost calculation is based on ExternE exposure-response function and monetary values. Moreover, user defined valuation of mortality and greenhouse gas emissions is possible (http://www.externe.info).

2.3.3 Sensitivity analysis The results of the financial and economic analysis are subject to a sensitivity analysis. In some situations the data in the analyses are not known with absolute certainty. In order to deal with the uncertainties a sensitivity analysis was carried out to investigate the influence of parametric variation on the results.

http://www.externe.info/�

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3 BATTERY STORAGE

3.1 Overview Isolated electric systems power by renewable energies needs to store excess energy to regulate the difference between energy supply and the electric demand curve (to level the peak and valleys of the demand curve). Energy storage capacity is a key issue for distributed generation based on high RES penetration microgrids proposed for the two European islands, La Graciosa and San Petro. One possibility is to use rechargeable batteries. Different suitable battery technologies exist, but for the present analysis lead acid batteries have been chosen, which is the primary battery choice in most of today’s off grid applications. These batteries have a relatively low initial investment cost and maintenance cost, and their useful life, for the sake of the analysis, has been estimated in 4 to 5 years (depending on the charge-discharge cycles). Batteries will be integrated with photovoltaic, wind and diesel, to support electric demand from the loads connected to the microgrids. The battery integration requires of rectifiers to adapt the current supplied to the batteries connected to the AC microgrid, and inverters convert DC to AC power demanded by the loads. For the simulations, the lead-acid batteries where modelled using manufactures data, which is available in the HOMER simulation software. And they include: • Round Trip Efficiency: DC-Storage-DC

energetic efficiency of the battery • Maximum Capacity: Total capacity of

the battery • Rate Constant k : Rate at which

available energy can be converted to bound energy and vice-versa

• Maximum Discharge Current: The maximum output current that can be drawn out of the batteries

• Maximum Charge Current: The maximum charge current

• Maximum Power: The Maximum power that can be drawn from the battery stack in an emergency situation

• Maximum Charge Rate: Maximum allowable charge rate, measured in Amps per Amps-hour of unfilled capacity

• Minimum State of Charge: Relative state of charge below which the battery should never be drawn

• Float Life: Maximum lifetime of the battery, regardless of usage

• Lifetime Throughput: Energy that can be cycled through the battery before it needs replacement

• Capacity curve or table: Describing the capacity of the battery at different discharge current rates

• Lifetime curve: Describing the longevity of the battery (cycles to failure) at different levels of discharge (depths of discharge)

3.2 Case Study 1 – La Graciosa

3.2.1 Financial Analysis La Graciosa is a small island located in the north of Lanzarote. The island has a small resident population of 658 people, and during the summer the island population increases due to tourism, which together with fishing represents the main economic activities. Currently it is being provided of electric power and water from neighbouring Lanzarote through a submarine cable with capacity for 1.3 MW, and a submarine water pipe. The island yearly electricity consumption is 3,641,028 kWh, and a peak electric power demand of 668 kW. La Graciosa, as happens with the rest of the Canary Islands, is exposed to the Trade winds that blow predominantly from the northeast. Strong constant winds throughout the year, although in the summer months the mean average speed is higher than in the winter. Solar radiation is also high most of the year. Wind and solar radiation gives an important potential for renewable energy

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electricity production. The microgrid proposed for La Graciosa would include a photovoltaic system, a wind farm, a diesel engine and batteries for energy storage. The system has been simulated using HOMER “Hybrid Optimization Model for Electric Renewables” developed by NREL (National Renewable Energies Laboratory, USA). It assumes that it is an isolated grid, where the submarine cable connecting La Graciosa to the neighbouring island of Lanzarote does not exist. From the simulation carried out with HOMER, we obtained that the optimal system should have a total installed photovoltaic power of 300 kWp, and 6 wind turbines for a total of 1,500 kW. Although sun and conditions in La Graciosa are excellent, the photovoltaic system and the wind farm would not be able by themselves to guarantee 100 % electricity supply to the island. On the hourly energy balance there are moments of excess electricity production from the RES systems, and there are other moments when there is a power deficit which has to be supplied by conventional energy power system, namely a diesel genset. We see that the optimum solution for La Graciosa is a microgrid with 78 % RES penetration. Higher penetrations could be possible, but this will increase the investment cost, primarily due to the need for energy storage capacity. The diesel generator installed in the island will have to be supplied 22 % of electricity demand. The proposed solution has a cost of 3,740.000 €,

Table 3-1 Initial costs of the components of the system

Components Initial Capital PV Array 1,000,000 € Wind farm 1,500,000 € Diesel Genset 600,000 € Battery 600,000 € Converter 40,000 € Totals 3,740,000 €

Electricity production, when compared to actual energy consumption, gives excess of electricity production on the yearly bases 1,311,431 kWh/yr

Table 3-2 Energy data of the proposed solution

Total electricity production

4,952,459 kWh/yr

Electricity demand 3,641,028 kWh/yr

Excess electricity 1,311,431 kWh/yr

Clean electricity produced is:

Table 3-3 Electricity production per technology

Component Production Fraction PV array 335,430

kWh/yr 9%

Wind turbines

3,426,194 kWh/yr

69%

Total RES 3,761,624 kWh/yr

78 %

Diesel Gen. 1,190,835 kWh/yr

22%

Total 4,952,459 kWh/yr

100%

A total of 3,761,624kWh/yr of clean electricity from RES generation systems integrated into the microgrid. We see that for every euro spent in the microgrid, we produce 1.01 kWh-yr of RES electricity (1.01 kWh-yr/€). Assuming a price of 0.1 €/kWh, the PAYBACK would be 10 years. This also assumes that all electricity, not just the one to cover electric demand from the island (there is an excess electricity of 1,311,431 kWh/yr), is sold at this price (excess electricity has a market for sea water desalination or for hydrogen production). Considering the specific consumption of the Canary Islands thermal plants of 0.25 kg of fuel oil per kWh, 3,761,624 kWh/yr of RES represents a reduction of yearly consumption of 940,406 kg of fuel oil. Associated to this

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consumption of fossil fuels there are 1,050 tons of CO2. When compared emission reductions with the investment cost of the microgrid, we have that for every euro spent

in the microgrid we will be reducing 0.28 kg CO2-yr/€ (0.28 kg CO2-yr/€).

Table 3-4 Results of the financial analysis for basic Scenario

Initial investment cost 3,740,000 € Useful economic life 20 yr Recurrent investment cost (battery 10 yrs) 600,000 € Life of recurrent investment 10 yr Fuel consumption 398,605 lt/yr Cost of fuel 1 €/lt Variable cost (fuel) 398,605 €/yr Electricity production for primary load 3,485,023 kWh/yr Price of kWh 0.10 €/kWh Sales of electricity 348,502 €/yr Inflation rate (electricity prices) 4.00% Interest rate (for discounting cash flow) 7.00% NPV 994,006 € IRR 9.81% DISCOUNTED PAYBACK 15 yrs

The following graph shows the sensitivity of Net Present Value (NPV) to changes in the Discount Interest Rate applied to the project cash flows, under different inflation scenarios (inflation affecting the price of electricity, from 1 % to 6 %)

0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18-2.000x106

-1000000

0

1000000

2.000x106

3.000x106

4.000x106

5.000x106

6.000x106

7.000x106

8.000x106

9.000x106

Interest Rate

NPV

Inf 5%Inf 4%Inf 3%Inf 2%Inf 1%

Inf 6%

IRRinf,1%IRRinf,6%

Fig. 3.1 Sensitivity of NPV to changes in the Discount Interest Rate

From the graph above we see that for increments in the inflation affecting the price of electricity, the NPV increases. The Internal Rate of Return (IRR) is the value of the Interest Rate which gives a NPV=0. In the graph above it is indicated the IRR when the price of electricity has an inflation of 1% (IRR 6.8 %) and the IRR for a value of inflation of 6 % (IRR 11,8%). The following graph shows how the initial investment cost affects the Internal Rate of Return under different scenarios of electricity price Inflation. As the Investment cost increases, the IRR of the project decreases. We see increments in the IRR due to the increase in the inflation affecting the price of electricity (colour curves from 1 % Inflation to 6 % Inflation).

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2.000x106 4.000x106 6.000x106 8.000x106 1.000x1070

0.025

0.05

0.075

0.1

0.125

0.15

0.175

0.2

0.225

Investment

IRR

Inf 5%Inf 4%

Inf 3%Inf 2%

Inf 1%

Inf 6%

3,740,000 €

9.81 %

Fig.3.2 Impact of the initial investment cost on IRR

From the graph we see that for an initial investment cost of 3,740,000 €, for the basic scenario of Inflation of 4 % (increment in electricity price), we would get a 9.81 % IRR for the project. Water or hydrogen production with excess electricity has not been considered, but the

selling prices of these commodities would have significant positive impacts on the NPV and IRR of the microgrid project foreseen for La Graciosa, and can reduced the PAYBACK period down to 10 years.

3.2.2 General Economic Perspective Private investor’s perspective The profitability of the project will be heavily dependent on the total investment cost need for installing the microgrid in La Graciosa, and the evolution on the price of electricity along the lifespan of the project. From the results of the financial parameters analyzed, it can be seen that the project is profitable under the basic scenario that assumes an investment cost for the microgrid of 3,740,000 €, and a yearly inflation affecting the price of electricity of 4%.

Table 3-5 Basic scenario Initial investment cost 3,740,000 € Useful economic life 20 yrs Recurrent investment cost (battery) 600,000 € Life of recurrent investment (life span of batteries 10 yrs) 10 yrs Fuel consumption 398,605 lt/yr Cost of fuel 1 €/lt Variable cost (fuel) 398,605 €/yr Electricity production for primary load 3,485,023 kWh/yr Price of kWh 0.10 €/kWh Sales of electricity 348,502 €/yr Inflation rate 4.00% Interest rate (for discounting cash flow) 7.00% NPV 994,006 € IRR 9.81% DISCOUNTED PAYBACK 15 yrs

The sensibility analysis performed shows that under that inflation scenario, the investor could still obtain a profitability measure in terms of the IRR of 5 % , even when the investment cost rises to 6.000.000 €.

Social benefits Besides the private benefits accrued from the investment project, important benefits will be generated for La Graciosa society in general. These benefits include new employment opportunities, reduction of emissions,

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substitution of imported fossil fuels, improvement in health, etc. The proposed microgrid has the potential to produce the following energy:

Table 3-6 Characteristics of the proposed system

Energy production PV array 335,430 kWh/yr Wind turbines 3,426,194 kWh/yr

Total RES 3,761,624 kWh/yr Diesel Genset 1,190,835 kWh/yr

Total 4,952,459 kWh/yr Primary load 3,485,023 kWh/yr Excess electricity 1,311,431 kWh/yr Annual Fuel substituted

398,605 €/yr

RES penetration PV 9.00% Wind 69.00%

Total RES penetration 78.00% Diesel generation 22.00% There are important opportunities for developing projects such as a microgrid for La Graciosa. Not only the Regional Canary Islands Government is committed to support projects that can reduce that promote the use of RES to reduce consumption of fossil fuels and contribute to the reduction of CO2, but also the EC policy supporting the scientific and technological development of the outermost regions. The following table estimates the benefits in terms of gas emissions and health impact:

Table 3-7 Avoided emissions and health impact

Avoided Emission values NOx (kg/year) 23,119 kg/yr SO2 (kg/year) 2,108 kg/yr PM10 (kg/year) 195 kg/yr CO2 (kg/year) 1,049,657 kg/yr

Assumptions Mortality value

(€/Life Year Lost) 75,000 €/yr life

lost Abatement cost per

tonne of CO2(€/t) 19 €/Tn

Summary Results Human Health

Mortality (€/year) 35,800.00 €/yr

Human Health Morbidity (€/year)

20,400.00 €/yr

Crops (€/year) 11,900.00 €/yr Materials (€/year) 507.00 €/yr CO2 (€/year) 19,900.00 €/yr

Total External Costs (€/year)

91,300.00 €/yr

Table 3-8 Indicators RES production / RES investment cost 1.01 kWh-yr/€ Avoided CO2 / RES investment cost

0.28 kg CO2-yr/€

PAYBACK (Assuming 0.1 €/kWh) 9.9 yrs The expected increment of the prices of the fossil fuels is a key issue for developing the RES microgrid project in La Graciosa. The high external energy dependence, favours the development of systems that make use of available solar and wind indigenous renewable energy sources resources. Besides the installation, operation and maintenance of these systems will favour the creation of local employment. The following table assesses the project benefits in terms of employment creation in La Graciosa:

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Table 3-8 Project benefits in terms of employment

Technology Employment Persons Number Days

Wind turbines

Engineers 4 30

Technicians 3 90 Operators 3 30 Workers 4 30 PV system Engineers 2 60 Technicians 3 30 Operators 1 60 Workers 3 30 Diesel generators

Engineers 1 15

Technicians 1 15 Operators 1 30 Workers 2 30 Batteries Engineers 2 60 Technicians 1 30 Operators 1 30 Workers 1 30

Men Years

Cost (€/yr)

Man-years engineers

1.0 30,000 30,822 €

Many-ears technicians

1.1 18,000 19,973 €

Man-years operators

0.6 14,400 8,285 €

Man-years workers

0.8 12,000 9,863 €

Total Employment

3.5 68,942 €

Excess electricity – water and hydrogen production The high penetration RES microgrids will generate daily excess electricity from the wind farm and photovoltaic systems, at the valley hours of the electricity demand curve. The following graphs show examples for January of RES production in La Graciosa microgrid (wind in green and PV in yellow) compared to electricity demand (in blue), both for the whole month of January and the detailed production-consumption for January the 2nd.

0

5

10

15

20

January1 4 7 10 13 16 19 22 25 28

0100200300400500

600

Powe

r (kW

)

Wind

Spee

d (m/

s) Wind SpeedAC Primary LoadPV Pow er

Fig.3.3 RES production in La Graciosa microgrid for January

0

1

2

3

4

5

January 20 6 12 18 24

0

100

200

300

400

500

Powe

r (kW

)

Wind

Spee

d (m/

s) Wind SpeedAC Primary LoadPV Pow er

Fig.3.4 RES production in La Graciosa microgrid for the 2nd of January

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On the yearly balance La Graciosa microgrid will produce an excess of 1,311,431 kWh/yr of electric energy.



4,952,459 kWh/yr

Electricity demand 3,641,028 kWh/yr Excess electricity 1,311,431 kWh/yr

The following graph shows on the yearly basis the excess of electricity for La Graciosa.

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

400

800

1,200

1,600

Pow

er (k

W)

Fig.3.5 Yearly excess electricity production for La Graciosa Part of the excess energy produced at valley hours of the electrical demand curve will be used to charge batteries, but still an important amount of surplus energy would have to be wasted in dissipating loads, if no alternative use for this energy is found. This excess energy from the RES microgrid can be used in RO desalination plants that can contribute to mitigate the scarcity of water resources of La Graciosa. An alternative option is to use the excess energy to power electrolysers. Hydrogen obtained from electrolysis could be used for transport fuel production for both the small fleet of vehicles in the island, as well as for the boats used in the fishing activities. Desalinated water production Currently water is being supplied to La Graciosa from neighbouring Lanzarote. Lanzarote does not dispose of fresh water resources, so almost all water consumed has

to be produced from desalination of sea water. The specific consumption of the reverse osmosis water desalination plants is approximately 4 kWh/m³ H2O. If pressure recovery systems are introduced, specific consumption of the RO process could be reduced to 2.5 kWh/m³. Considering this specific consumption, the excess electricity from the RES microgrid solution for La Graciosa could be used to produce 524,572 m³/yr of water. Assuming a cost of 1 €/m³ of water, the sales of water would produce an extra income of 524,572 €/yr. Using the excess electricity for water desalinization would save around 546 tons of fuel. The savings of this fuel would reduce emissions of 1,970 tons of CO2 every year.

Table 3-10 Water production using the excess electricity

Excess Electricity

Specific Consumption

Water Production

1,311,431 kWh/yr

2,5 kWh/m³ H2O

524,572 m³/yr

Nevertheless associated to the water production capacity of La Graciosa that will make use of excess electricity, there is an investment cost on Reverse Osmosis plants. The cost of an RO plant can be estimated at 24,000 €/m³-hr of desalination capacity (1,000 €/m³-day). Before estimating the size of the needed RO plant it is important to see the variations in the production of excess electricity.

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Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec0

6

12

18

24

Hou

r of D

ay

Excess Electrical Production

Day of Year

03206409601,2801,600

kW

Fig.3.6 Excess electrical production

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Ann0

400

800

1,200

1,600

Ave

rage

Val

ue (k

W)

Excess Electrical Production Monthly Averages

Month

maxdaily highmean

daily lowmin

Fig.3.7 Excess electrical production monthly averages

0 400 800 1,200 1,6000

20

40

60

Freq

uenc

y (%

)

Excess Electrical Production PDF

Value (kW) Fig.3.8 Excess electrical production PDF

The RO desalination plant will not be designed considering water demand, but based on available excess electricity, since the idea is to dispose of a programmable load to help regulate the operation of the microgrid. The mean excess electrical power is at around 300 kW. Considering this value, as well as the frequency distribution of the excess electricity, to make maximum use of available excess electricity we will take the value of 300 kW as criteria for dimensioning the RO system power. Nevertheless this will be the maximum power, and the RO plant should be able to work at partial loads, adjusting water production as a function of available power of excess electricity at every

moment. The best approach would be to have a modular designed, allowing for partializing step by step production. If the desalination system is made up of 6 independent RO plants (or modules), then each module will have a nominal power of 50 kW. Each “step” or module should also be able to be regulated production according to available electric power, allowing continuous partial operation in each one of the desalination modules.

1 50 kW

20 m³/hr

2 50 kW

20 m³/hr

3 50 kW

20 m³/hr 4

50 kW 20 m³/hr

5 50 kW

20 m³/hr

6 50 kW

20 m³/hr

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The module should partialized down to 10 % of its nominal power, being able to run even

with 5 kW input.

0 12 240

300Jan

0 12 240

300Feb

0 12 240

300Mar

0 12 240

300Apr

0 12 240

300May

0 12 240

300Jun

0 12 240

300Jul

0 12 240

300Aug

0 12 240

300Sep

0 12 240

300Oct

0 12 240

300Nov

0 12 240

300Dec

In terms of power consumption, the RO process will consume around 2.5 kW/m³ of desalination capacity. A 300 kW RO, working at nominal conditions, will have a maximum desalination capacity of 120 m³/hr. If the RO plant was to be built by 6 modules, each module would have a maximum power of 50 kW and a desalination capacity of 20 m³/hr working at nominal power. Total installed desalination capacity = 120 m³/hr Total electric power demand = 300 kW Number of RO modules = 6 Nevertheless these RO modules should be designed allowing them to work at partial loads, with capacity to partialize down to 10 % of nominal power, which essentially means that the RO plant will run even with input power of 5 kW, in which case production the minimum water production capacity of the system would be 2 m³/hr. Assuming an investment cost of 24,000 €/m³-hr of installed water desalination capacity, the cost of the RO plant to be installed in La Graciosa to make use of excess electricity from its microgrid would be 2,880,000 €. 120 m³/hr * 24,000 €/m³-hr = 2,880,000 €

Yearly operation and maintenance will be assumed to be 10 % of the investment cost, approximately 288,000 €/yr. If we assume that this water production installed capacity can make use of al the 1,311,431 kWh/yr excess electric energy, and considering an specific consumption of 2.5 kWh/m³, then the yearly water production would be 524,572 m³/yr. If desalinated water was sold at a price of 1 €/m³, the income from the water production activity with excess electricity would be 524,572 €/yr. Considering the cost (investment + O&M), and the income from selling water locally, we shall proceed to do an economic analysis to estimate the Net Present Value (NPV) of the de desalination investment project. This NPV represents the financial resources that will be available for paying for the excess electricity of the microgrid, and will therefore contribute to improve the profitability of the global microgrid investment project. Investment Cost of RO plant

2,880,000 €

O&M cost 288,000 €/yr Income 524,572 €/yr Inflation affecting price of water

2 %

Discount Interest Rate 7 % Project lifetime 20 years

IRR= 7.4 % NPV = 930,000 € Dividing the NPV by the total excess electricity over the 20 years of the project.

RO module Max.Capac = 20 m³/hr 50 kW Min.Capac = 2 m³/hr 5 kW

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Value of Excess Electricity = NPV . Excess Electricity (20 yr) Value of Excess Electricity =

930,000 € . 1,311,431 kWh/yr * 20 yr

Value of Excess Electricity = 0.07 €/kWh This is the maximum price that the desalinated water production activity could pay for a kWh of excess electricity, that will be used in the RO process, to break even (not losing money in this activity). The following graph shows how the price of water sold can affect the NPV of the water desalination project, under different scenarios of Discount Interest Rate.

0.6 0.8 1 1.2 1.43− 106×

1− 106×

1 106×

3 106×

5 106×

7 106×7000000

3000000−

NPV.6%

NPV.7%

NPV.8%

1.50010.6 PrWater

6%

7%

8%

Fig.3.9 Impact of the selling price of water on NPV Using the excess electricity for water desalination would save around 546 tons of fuel. The savings of this fuel would reduce emissions of 1,970 tons of CO2 every year. Hydrogen production In the future the excess electricity could be also used to produce hydrogen for its use as a transport fuel. If the excess electricity were to be used for H2 production instead than for water desalination, 26,020 kg H2/yr could be produced, to substitute about 80.000 litres/yr

of transport fuel. Assuming a cost of 1 €/litre, this could contribute to 80.000 €/yr of extra income for the project, plus a contribution to CO2 emissions reductions of 320 tons of CO2.

Table 3-11 Hydrogen production using the excess electricity

Excess

Electricity Specific

Consumption

H2 Produc

tion

H2 Producti

on kg 1,311,431

kWh/yr 4.5

kWh/Nm³ H2

291,429 Nm³H2/

yr

26,020 kg H2/yr

The proposed microgrid project for La Graciosa will promote the use of renewable energy to contribute to the sustainable development of this European island, to its energy self-sufficiency, and to achieve the commitments of the Kyoto protocol. The project could also be seen as a testing platform that will contribute to advance in the understanding of small and weak grids exposed to high RES penetration, experience and knowledge that can later be transferred to other European island facing similar problems. Benefit – Cost Ratio If we look at the microgrid project by itself, without considering possible benefits from the sale of excess electricity to other activities, such as water desalination, we would have: Electricity consumed by regular loads connected to the microgrid

3,485,023 kWh/yr

Price of electricity 0.10 €/kWh Income from sales of electricity

348,502 €/yr

If we add the possible incomes derived from the sale of excess electricity, the we would have an extra 91,800 €/yr Excess Electricity 1,311,431kWh/yr Price of excess electricity (for desalination)

0.07 €/kWh

Income from sales of excess electricity

91,800 €/yr

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These two amounts represent financial benefits associated to the commercialisation of the electric power produced by the microgrid. Nevertheless there are also other externalities that have been valued positively, in terms of the social impact they might have on health improvement, the creation of local employment, or the reduction of emissions of greenhouse gases that contribute to the mitigation of global warming. Social benefits Human Health Mortality (€/year)

35,800 €/yr


20,400 €/yr

Crops (€/year) 11,900 €/yr Materials (€/year) 507 €/yr CO2 (€/year) 19,900 €/yr Total Employment 68,942 €/yr

External Benefits 157,449 €/yr If we add-up all the benefits we will have Income from sales of electricity (€/yr)

348,502

Income from sales of excess electricity (€/yr)

91,800

External Benefits (€/yr) 157,449 TOTAL BENEFITS (€/yr) 597,751

Benefit-cost ratio, which is defined as the division between the benefits and the costs is then calculated as: CB = TOTAL BENEFITS COST CB = 597,751 3,740,000 CB = 0.16

3.3 Case Study 2 - San Pietro

3.3.1 Financial analysis San Pietro is a volcanic Island located approximately at 7 km off the South western Coast of Sardinia. Has a resident population of 6,660 inhabitants which are mostly concentrated in the fishing town of Carloforte, that more than triples in the summer months, growing to 15-20,000 people. The island electricity demand experiences high seasonal variation due to tourist activity. The island electrical system is interconnected to Sardinia, through a submarine cable, with a capacity of 5.5 MW (at 15 kV). An analysis for a microgrid with maximum RES penetration has been made for San Pietro, assuming that no interconnection through submarine cable exists, and that all electric energy is produced from renewable energies and a diesel system backup installed in the island. The optimum looks for maximum penetration is terms of investment cost, and an 82 % penetration was estimated. A 100 % RES penetration objective is not consider, given the high investment cost of the solution, specially associated to necessary battery energy storage capacity. The generation systems will be based on a wind and solar photovoltaic energy, with diesel back-up system installed in the island, and battery for energy storage. The system has been simulated using HOMER “Hybrid Optimization Model for Electric Renewables” developed by NREL (National Renewable Energies Laboratory, USA). It assumes that it is an isolated grid, where the submarine cable connecting San Pietro to other grids does not exist. The simulations performed with the HOMER software gave a microgrid with 82 % RES penetration (PV 5 %, and wind 77 %). The investment cost for the microgrid is estimated at 23,800,000 €, and would produce a total of 23 136 261 kWh/yr of clean RES produced electricity to supply the demand of the island.

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The relation of RES electricity produced to investment cost is 0.97 kWh-yr. Nevertheless it is a good value, which in the case of assuming a cost of 0.1 €/kWh, could give a PAYBACK period of around 10 years. The high RES penetration microgrid proposed for San Pietro would avoid the emission of 4,531 tons of CO2/yr. If we look at it in relation to the investment cost, we would have that for every euro spent in the microgrid a reduction emission of 0.19 kg CO2 could be obtained (0.19 kg CO2-yr/€). Finally, excess electricity could be use to generate economic resources for the island agriculture and tourist industry in the form of desalinated water of hydrogen to be used as a transport fuel. In the case of using the excess electricity for water production, 5.000,000 m³/yr of water could be obtained. Assuming a price of 1 €/m³ water production could bring 5,000,000 €/yr to the project. RO processes powered by RES energy instead of by fossil fuel generated electricity could reduce emissions by 18,000 tons of CO2/yr. From the simulation carried out with HOMER, we obtained that the total investment cost was estimated at 23,800,000 €. It included a hybrid system made up of 900 kWp photovoltaic, 9,240 kW wind and 2,000 kW diesel genset. The need to meet as much as possible from RES even at moments of low wind speeds and low solar radiation, creates excess electricity at valley hours of the demand curve. To try to adjust the electricity demand curve and the supply of the RES electricity generation system, battery storage is considered. Nevertheless battery storage is expensive, so enough capacity for all the excess electricity is not a suitable option. The proposed solution has a cost of 23,800,000 €.

Table 3-10 1 Initial costs of the components of the system

Components Initial Capital PV Array 4,500,000 € Wind farm 13,800,000 € Diesel Genset 3,000,000 € Battery 2,400,000 € Converter 100,000 € Totals 23,800,000 €

Electricity production, when compared to actual energy consumption, gives excess of electricity production on the yearly bases of 12,002,370 kWh/yr



28,075,482 kWh

Electricity demand 15,620,034 kWh/yr

Excess Electricity 12,002,370 kWh/yr

Clean electricity produced is:

Table 3-12 Electricity production per technology

Component Production Fraction PV array 1,484,555

kWh/yr 5 %

Wind turbines

21,651,706 kWh/yr

77 %

Total RES 23,136,261 kWh/yr

82 %

Diesel Gen. 4,939,221 kWh/yr

18 %

Total 28,075,482 kWh/yr

100 %

A total of 23,136,261 kWh/yr of clean electricity from RES generation systems integrated into the microgrid. We see that for every euro spent in the microgrid, we produce 0.97 kWh-yr of RES electricity (0.97 kWh-yr/€). Assuming a price of 0.1 €/kWh, the PAYBACK would be 10 years.

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Assuming a specific consumption in the conventional thermal plants of 0.25 kg of fuel per kWh, 23,136,261 kWh/yr of RES represents a reduction of yearly consumption of 5,784,065 kg of fuel oil. Associated to this consumption of fossil fuels there are 20,822 tons of CO2. When compared emission reductions with the investment cost of the microgrid, we have that for every € spent in the microgrid we will be reducing 0.87 kg CO2-yr/€ (0.87 kg CO2-yr/€). The excess electricity from the RES solution for San Pietro could be used to produce 3.000,000 m³/yr of desalinated water, assuming a specific consumption of 4 kWh/m³ of water. Assuming a cost of 1 €/m³ of water, the sales of water would produce an

extra income of 3,000,000 €/yr. Using the excess electricity for water desalinization would save around 3,000 tons of fuel. The savings of this fuel would reduce emissions of 2,700 tons of CO2 every year. In the future the excess electricity could be also used to produce hydrogen for its use as a transport fuel. If the excess electricity were to be used for H2 production instead than for water desalination, 218,225 kg H2/yr could be produced, to substitute about 655,000 litres/yr of transport fuel. Assuming a cost of 1 €/litre, this could contribute to 655,000 €/yr of extra income for the project, plus a contribution to CO2 emissions reductions of 2,620 tons of CO2.

Table 3-13 Results of the financial analysis for Basic Scenario

Initial investment cost 23,800,000 € Useful economic life 20 yr Recurrent investment cost (battery 10 yrs) 2,400,000 € Life of recurrent investment 10 yr Fuel consumption 1,720,725 lt/yr Cost of fuel 1 €/lt Variable cost (fuel) 1,720,725 €/yr Electricity production for primary load 15,620,034 kWh/yr Price of kWh 0.10 €/kWh Sales of electricity 1,562,003 €/yr Inflation rate (electricity prices) 4.00% Interest rate (for discounting cash flow) 7.00% NPV -2,435,000 € IRR 5,80 % DISCOUNTED PAYBACK 23 yrs (> 20 yr)

The following graph shows the sensitivity of Net Present Value (NPV) to changes in the Discount Interest Rate applied to the project cash flows, under different inflation scenarios (inflation affecting the price of electricity, from 1 % to 6 %).

From the graph below we see that for increments in the inflation affecting the price of electricity, the NPV increases. The Internal Rate of Return (IRR) is the value of the Interest Rate which gives a NPV=0. In the graph above it is indicated the IRR when the price of electricity has an inflation of 1%

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(IRR 2.9 %) and the IRR for a value of inflation of 6 % (IRR 7.7 %).

0,02 0,03 0,04 0,05 0,06 0,07 0,08 0,09 0,1

-8,000x106

-4,000x106

0

4,000x106

8,000x106

1,200x107

1,600x107

Discount Interest Rate

NP

V

Inf 1 %Inf 2 %

Inf 3 %

Inf 4 %

Inf 5 %

Inf 6 %

IRRInf 2.9 % IRRInf 7.7 %

Fig.3.3 Sensitivity of Net Present Value to changes in the Discount Interest Rate The following graph shows how the initial investment cost affects the Internal Rate of Return under different scenarios of electricity price Inflation. As the Investment cost increases, the IRR of the project decreases. We see increments in the IRR due to the increase in the inflation affecting the price of electricity (colour curves from 1 % Inflation to 6 % Inflation).

2,000x107 2,200x107 2,400x107 2,600x107 2,800x1070,01

0,02

0,03

0,04

0,05

0,06

0,07

0,08

0,09

0,1

Investment

IRR

Inf 1 %

Inf 2 %

Inf 3 %

Inf 4 %

Inf 5 %

Inf 6 %

23,800,000 €

5,8 %

Fig.3.4 Impact of the initial investment cost on IRR

From the graph we see that for an initial investment cost of 23,800,000 €, for the basic scenario of Inflation of 4 % (increment in electricity price), we would get a 5.8 % IRR for the project. Since the discount rate we are using to estimate the Present Value of future

cash flows is 7 %, we get a negative value of the NPV of -2,435,000 €. Water or hydrogen production with excess electricity has not been considered, but the selling prices of these commodities would have significant positive impacts on the NPV and IRR of the microgrid project foreseen for San Pietro, and can reduced the PAYBACK period.

3.3.2 General Economic Perspective Private investor’s perspective The profitability of the project will be heavily dependent on the total investment cost need for installing the microgrid in San Pietro, and the evolution on the price of electricity along the lifespan of the project. From the results of the financial parameters analyzed, it can be seen that the project is profitable under the basic scenario that assumes an investment cost for the microgrid of 23,800,000 €, and a yearly inflation affecting the price of electricity of 4%.

Table 3-14 Basic scenario Initial investment cost 23,800,000 € Useful economic life 20 yrs Recurrent investment cost (battery) 2,400,000 € Life of recurrent investment (life span of batteries 10 yrs) 10 yrs

Fuel consumption 1,720,725

lt/yr Cost of fuel 1 €/lt

Variable cost (fuel) 1,720,725

€/yr Electricity production for primary load

15,620,034 kWh/yr

Price of kWh 0.10 €/kWh

Sales of electricity 1,562,003

€/yr Inflation rate 4.00% Interest rate (for discounting cash flow) 7.00% NPV -2,435,000 € IRR 5.80% DISCOUNTED PAYBACK 23 yrs

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The sensibility analysis performed shows that under that inflation scenario, the investor could still obtain a profitability measure in terms of the IRR of 4 % , even when the investment cost rises to 28,000,000 €. Social benefits Besides the private benefits accrued from the investment project, important benefits will be generated for San Pietro’s society in general. These benefits include new employment opportunities, reduction of emissions, substitution of imported fossil fuels, improvement in health, etc. The proposed microgrid has the potential to produce the following energy:

Table 3-15 Characteristics of the proposed system

Energy production PV array 1,484,555 kWh/yr Wind turbines 21,651,706 kWh/yr Total RES 23,136,261 kWh/yr Diesel Genset 4,939,221 kWh/yr Total 28,075,482 kWh/yr Primary load 15,620,034 kWh/yr Excess electricity 12,002,370 kWh/yr Annual Fuel substituted

1,720,725 €/yr

RES penetration PV 5.00% Wind 77.00% Total RES penetration 82.00% Diesel generation 18.00% The following table estimates the benefits in terms of gas emissions and health impact:

Table 3-16 Avoided emissions and health impact

Avoided Emission values NOx (kg/year) 99,802 kg/yr SO2 (kg/year) 9,100 kg/yr PM10 (kg/year) 843 kg/yr CO2 (kg/year) 4,531,237 kg/yr

Assumptions Mortality value

(€/Life Year Lost) 75,000 €/yr life

lost Abatement cost

per tonne of CO2(€/t) 19 €/Tn

Summary Results Human Health

Mortality (€/year) 254,000.00 €/yr


126,000.00 €/yr

Crops (€/year) 8,860.00 €/yr Materials

(€/year) 6,530.00 €/yr

CO2 (€/year) 86,093.50 €/yr Total External Costs (€/year)

481,100.00 €/yr

Table 3-17 Indicators RES production /

RES investment cost 0.97 kWh-yr/€ Avoided CO2 /

RES investment cost 0.19 kg CO2-yr/€ PAYBACK

(Assuming 0.1 €/kWh) 10.3 yrs The expected increment of the prices of the fossil fuels is a key issue for developing the RES microgrid project in San Pietro. The high external energy dependence, favours the development of systems that make use of available solar and wind indigenous renewable energy sources resources. Besides the installation, operation and maintenance of these systems will favour the creation of local employment. The following table assesses the project benefits in terms of employment creation in La Graciosa:

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Table 3-18 Project benefits in terms of employment Technology Employment

Persons Number Days Wind turbines Engineers 8 180 Technicians 6 180 Operators 5 90 Workers 4 90 PV system Engineers 2 60 Technicians 4 60 Operators 2 180 Workers 5 90 Diesel generators Engineers 2 90 Technicians 2 60 Operators 2 120 Workers 2 30 Batteries Engineers 3 120 Technicians 2 30 Operators 3 90 Workers 3 90

Men Years Cost Man-years engineers 5.8 30,000 €/yr 172,603 € Many-ears technicians 4.1 18,000 €/yr 73,973 € Man-years operators 3.6 14,400 €/yr 52,077 € Man-years workers 3.1 12,000 €/yr 37,479 € Total Employment 16.6 336,132 € Excess energy from the RES microgrid can be used RO desalination plants that can contribute to mitigate the scarcity of water resources of San Pietro, and that can also be used to produce hydrogen from electrolysis for the production of transport fuel.

Table 3-19 Potential application of excess energy

Water production 5,000,000 m³/yr Hydrogen production 238,142 kg H2/yr The proposed microgrid project for San Pietro will promote the use of renewable energy to contribute to the sustainable development of this European island region, to its energy self-sufficiency, and to achieve the commitments of the Kyoto protocol. The

project could also be seen as a testing platform that will contribute to advance in the understanding of small and weak grids exposed to high RES penetration, experience and knowledge that can later be transferred to other European island facing similar problems. Excess Electricity – Water and Hydrogen Production The high penetration RES San Pietro microgrid is expected to produce daily excess electricity from the wind farm and photovoltaic systems, at the valley hours of the electricity demand curve. The following graphs show examples of expected RES production (wind in green and PV in yellow) for January in San Pietro if the microgrid was implemented, and compares it to electricity

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demand (in blue), both for the whole month of January and the detailed production-

consumption for January the 2nd

Fig. 3.12: RES production in San Pietro microgrid for January

Fig. 3.13: RES production in San Pietro microgrid for the 2nd of January

On the yearly balance, the microgrid at San Pietro will produce an excess of 12,002,370 kWh/yr of electric energy.



28,075,482 kWh/yr

Electricity demand 15,620,034 kWh/yr Excess Electricity 12,002,370 kWh/yr

The following graph shows on the yearly basis the excess of electricity for San Pietro

Fig. 3.14: Yearly excess electricity production

for San Pietro Part of the excess energy produced at valley hours of the electrical demand curve will be used to charge batteries, but still an important amount of surplus energy would have to be

STORIES Project

28

wasted in dissipating loads, if no alternative use for this energy is found. This excess energy from the RES microgrid can be used in RO desalination plants that can contribute to mitigate the scarcity of water resources of San Pietro. An alternative option is to use the excess energy to power electrolysers. Hydrogen obtained from electrolysis could be used for transport fuel production for both the small fleet of vehicles in the island, as well as for the boats used in the fishing activities. Desalinated water production Excess electricity could be used for water production. The specific consumption of the reverse osmosis water desalination plants is approximately 4 kWh/m³ H2

O. If pressure recovery systems are introduced, specific consumption of the RO process could be reduced to 2.5 kWh/m³.

Considering this specific consumption, the excess electricity from the RES microgrid solution for San Pietro could be used to produce 524,572 m³/yr of water. Assuming a cost of 1 €/m³ of water, the sales of water

would produce an extra income of 524,572 €/yr. Using the excess electricity for water desalinization would save around 546 tons of fuel. The savings of this fuel would reduce emissions of 1,970 tons of CO2 every year.

Table3-21 Water production using the excess electricity

Excess

Electricity Specific

Consumption Water

Production 12,002,370

kWh/yr 2,5 kWh/m³

H2O 4,800,948

m³/yr Nevertheless associated to the water production capacity of San Pietro that will make use of excess electricity, there is an investment cost on Reverse Osmosis plants. The cost of an RO plant can be estimated at 24,000 €/m³-hr of desalination capacity (1,000 €/m³-day). Before estimating the size of the needed RO plant it is important to see the variations in the production of excess electricity.

Fig.3.15 Excess electrical production

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29

Fig.3.16 Excess electrical production monthly averages

Fig.3.17 Excess electrical production PDF

considering water demand, but based on available excess electricity, since the idea is to dispose of a programmable load to help regulate the operation of the microgrid. The mean excess electrical power is at around 2,000 kW. Considering this value, as well as the frequency distribution of the excess electricity, to make maximum use of available excess electricity we will take the value of 2,000 kW as criteria for dimensioning the RO system that should use the excess electric power of the San Pietro microgrid. Nevertheless this will be the maximum power, and the RO plant should be able to work at partial loads, adjusting water production as a function of available power of the excess electricity at every moment. The best approach would be to have a modular designed of the desalination plant, allowing for partializing step by step production. If the desalination system is

made up of 10 independent RO modules, then each module would have a nominal power of 200 kW. Each “step” or module should also be able to be regulated production according to available electric power, allowing continuous partial operation in each one of the desalination modules. The module should partialized down to 10 % of its nominal power, being able to run even with 20 kW input. As pointed out before, in terms of power consumption, the RO process will consume around 2.5 kW/m³ of desalination capacity. A 2,000 kW RO, working at nominal conditions, will have a maximum desalination capacity of 800 m³/hr. If the RO plant was to be built by 10 modules, each module would have a maximum power of 200 kW and a desalination capacity of 80 m³/hr working at nominal power.

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RO module Max.Capac = 80 m³/hr 200 kW Min.Capac = 8 m³/hr 20 kW

Total installed desalination capacity = 800 m³/hr Total maximum electric power demand = 2,000 kW Number of RO modules = 10

1 200 kW 80 m³/hr

2 200 kW 80 m³/hr

3 200 kW 80 m³/hr

4 200 kW 80 m³/hr

5 200 kW 80 m³/hr

6 200 kW 80 m³/hr

7 200 kW 80 m³/hr

8 200 kW 80 m³/hr

9 200 kW 80 m³/hr

10 200 kW 80 m³/hr

Nevertheless these RO modules should be designed allowing them to work at partial loads, with capacity to partialize down to 10 % of nominal power, which essentially means that the RO plant will run even with input power of 20 kW, in which case production the minimum water production capacity of the system would be 8 m³/hr. Assuming an investment cost of 24,000 €/m³-hr of installed water desalination capacity, the cost of the RO plant to be installed in San Pietro to make use of excess electricity from its microgrid would be 19,200,000 €.

800 m³/hr * 24,000 €/m³-hr = 19,200,000 € Yearly operation and maintenance will be assumed to be 10 % of the investment cost, approximately 1,920,000 €/yr. If we assume that this water production installed capacity can make use of al the 12,002,370 kWh/yr excess electric energy, and considering an specific consumption of 2.5 kWh/m³, then the yearly water production would be 4,800,948 m³/yr. If desalinated water was sold at a price of 1 €/m³, the income from the water production activity with excess electricity would be 4,800,9 kWh

DESALINATION SYSTEM (6 RO modules)

Max.Capac = 800 m³/hr 10 x 200 kW Min.Capac = 8 m³/hr 1 x 20 kW

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Considering the cost (investment + O&M), and the income from selling water locally, we shall proceed to do an economic analysis to estimate the Net Present Value (NPV) of the de desalination investment project. This NPV represents the financial resources that will be available for paying for the excess electricity of the microgrid, and will therefore contribute to improve the profitability of the global microgrid investment project. Investment Cost of RO plant

19,200,000 €

O&M cost 1,920,000 €/yr Income 4,800,948 €/yr Inflation affecting price of water

2 %

Discount Interest Rate 7 % Project lifetime 20 years IRR= 15.8 % NPV =

16,000,000 € The return on investment was estimated under an scenario of tax exemption for energy sold from the project. Dividing the NPV by the total excess electricity over the 20 years of the project. Value of Excess Electricity =

= NPV . Excess Electricity (20 yr)

Value of Excess Electricity = = 16,000,000 € . 12,002,370 kWh/yr * 20 yr Value of Excess Electricity = 0.067 €/kWh This is the maximum price that the desalinated water production activity in San Pietro could pay for a kWh of excess electricity produced by the RES microgrid that will be used in the RO process, to break even (not losing money in the water production economic activity).

The following graph shows how the price of water sold can affect the NPV of the water desalination project, under different scenarios of Discount Interest Rate (6 %, 7% and 8%).

0.6 0.7 0.8 0.9 1 1.1 1.2 1.3 1.4 1.56− 10 6×

5 10 6×

1.6 10 7×

2.7 10 7×

3.8 10 7×

4.9 10 7×

6 10 7×60000000

6000000−

NPV .6%

NPV .7%

NPV .8%

1.50.6 Pr .H2O

6 %

7 %

8 %

Fig.3.18: Impact of the selling price of water on NPV Using the excess electricity for water desalination would save around 3,000 tons of fuel/yr. The savings of this fuel would reduce emissions of 10,800 tons of CO2 every year. Hydrogen production In the future the excess electricity could be also used to produce hydrogen for its use as a transport fuel. If the excess electricity were to be used for H2 production instead than for water desalination, 239,856 kg H2/yr could be produced, to substitute about 737,449 litres/yr of transport fuel. Assuming a cost of 1 €/litre, this could contribute to 737,449 €/yr of extra income for the project, plus a contribution to CO2 emissions reductions of 2,950 tons of CO2. The proposed microgrid project for San Pietro will promote the use of renewable energy to contribute to the sustainable development of this European island, to its energy self-sufficiency, and to achieve the commitments of the Kyoto protocol. The project could also be seen as a testing platform that will contribute to advance in the understanding of small and weak grids exposed to high RES penetration, experience and knowledge that can later be transferred to other European island facing similar problems.

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Table 3-22: Hydrogen production using the excess electricity

Excess Electricity Specific Consumption

H2 Production Nm³H2 H2 Production kg

12,002,370 kWh/yr 4.5 kWh/Nm³ H2 2,667,193 Nm³H2/yr 239,856 kg H2/yr Benefit – Cost If we look at the microgrid project by itself, without considering possible benefits from the sale of excess electricity to other activities, such as water desalination, we would have: Electricity consumed by regular loads connected to the microgrid

15,620,034 kWh/yr

Price of electricity 0.10 €/kWh Income from sales of electricity

1,562,000 €/yr

If we add the possible incomes derived from the sale of excess electricity, then we would have an extra 804,160 €/yr Excess Electricity 12,002,370 kWh/yr Price of excess electricity (for desalination)

0.067 €/kWh


804,160 €/yr

These two amounts represent financial benefits associated to the commercialization of the electric power produced by the microgrid. Nevertheless there are also other externalities that have been valued positively, in terms of the social impact they might have on health improvement, the creation of local employment, or the reduction of emissions of greenhouse gases that contribute to the mitigation of global warming.

Social benefits Human Health Mortality 254,000 €/yr Human Health Morbidity (€/year)

126,000 €/yr

Crops (€/year) 8,860 €/yr Materials (€/year) 6,530 €/yr CO2 (€/year) 86,093 €/yr Total Employment 336,132 €/yr External Benefits 817,615 €/yr

If we add-up all the benefits we will have Income from sales of electricity

1,562,000 €/yr


804,160 €/yr

External Benefits 817,615 €/yr TOTAL BENEFITS 3,183,775 €/yr Benefit-cost ratio, which is defined as the division between the benefits and the costs is then calculated as: CB = 3,183,775 = 0.13 23,800,000 CB = 0.13

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4 PUMP HYDRO STORAGE

4.1 Overview This methodology has been applied in the past in several cases for the comparison of different RES technologies [3] or the evaluation of the whole action plans for the implementation of RES [4], [5], [6], [7]. Additionally, it has been applied for the evaluation of the large scale wind energy development in Greece [8], and the evaluation of solar thermal systems [9]. Finally, it has been used as a tool for the decision making and the promotion of RES [10]. Here, the combined use of wind energy with pumped storage was examined as an option to increase the renewable energy contribution for the power system of three islands. The

first one is the Greek island Ios, which is a part of Paro-Naxia autonomous system in the Aegean Sea, the second one is Cyprus and the last one is the Portuguese island Corvo in the Azores Archipelago. For all the case studies, the simulation was performed via the PSU simulation tool [11]. The cost-benefit analysis presented in the following sections aims to consider the environmental and social parameters of these systems. More specifically, for each case study, the analysis is carried out in three steps:

• financial analysis • economic analysis - social analysis • sensitivity analysis

4.2 Case Study 1 – Ios

4.2.1 Financial analysis

Table 4-1 Basic energy results – Parameters – Assumptions Investment cost (1000€) 18804 Cost of wind farms in the hybrid stations (1000€) 12000 Cost of the hydro pumped storage units (1000€) 6804 Wind energy absorbed from the grid (GWh) 6.85 Turbine's energy production (GWh) 14.6 Grid energy used for pumping (GWh) 6.3 Price for the wind energy (€/kWh) 0.10 Price for the turbine's energy production (€/kWh) 0.15 Price for guaranteed power provided (€/kW) 94 Price for grid energy used for pumping (€/kWh) 0.120 Subsidy for wind farms (%) 30% Subsidy for the hydro pumped storage system (%) 30% Own capitals for the wind farms (%) 25% Own capitals for the hydro pumped storage system (%) 25% Lifetime of the project 20 Residue value 35% Annual operational and maintenance cost (1000€) 376.08 Annual cost for grid energy used for pumping 755 Tax rate (%) 35% Annual depreciations (1000€) 1097 Years of depreciation 12 Loan

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Interest rate (%) 6% grace period - years 1 pay back period 10

Table 4-2 Production Cost Production cost (1000€) 1 2 … 10 … 19 20

total (O&M cost + Depreciation) 2228 2228 … 2228 … 1131 1131

Table 4-3 Profit calculation Years 1 2 … 10 … 19 20 Incomes from sales 3611 3611 3611 3611 3611 minus the production cost

2228 2228 2228 1131 1131

mixed profit 1382 1382 1382 2479 2479 mixed result 1382 1382 1382 2479 2479 minus loan interests 538 491 0 0 0

Profit before taxes 844 891 1382 2479 2479 minus taxes 296 312 484 868 868 net profit 549 579 899 1612 1612 Cumulative net profits 549 1128 7102 20180 21792

Table 4-4 Cash flows years 0 1 2 … 5 6 … 10 … 20 Inflows 18804 1646 1676 1779 1817 1996 10058 Own capitals 4701 Subsidy 5641 Loan 8462 Net profits (after taxes) 549 579 682 720 899 1612

Depreciation 1097 1097 1097 1097 1097 1097 Residue value 0 7350 Outflows 21000 781 827 985 1045 0 0 Investment cost 21000 Amortization (without interest) of loan 781 827 985 1045 0 0

Annual net flow (net result) -2196 865 849 793 773 1996 10058

Cumulative net cash flows 865 1714 4152 4924 9101 42110

Then the typical financial indexes are calculated:

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Table 4-5 Results of financial analysis Price of hydro electricity sold to the grid (€/kWh) 0.15 IRR 22.32% PBP (years) 5.6 NPV(i=9%) (1000€) 8931

-5000

0

5000

10000

15000

20000

25000

30000

35000

40000

45000

0% 5% 10% 15% 20% 25% 30%

discount rate (%)

NPV

(100

0€)

Fig. 4.1 Impact of discount rate on Net Present Value

Price for the hydro turbine's electricity (€/kwh) - IRR

0,000,020,040,060,080,100,120,140,160,180,20

0% 5% 10% 15% 20% 25% 30%

IRR (%)

Pri

ce f

or

the h

yd

ro t

urb

ine's

ele

ctr

icit

y

(EU

RO

)

Fig. 4.2 Impact of IRR on the price of hydro turbine electricity There is an uncertainty on the definition of the price. Then the dependence of the IRR to the price is presented in the following figure.

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Sensitivity analysis of the investment cost and loan’s interest rate on the feasibility of the investment (IRR and PBP indexes)

Ios

0%5%

10%15%20%

25%30%

80% 100% 120% 140% 160%

rate of the basic value

IRR investment

cost

interestrate

Fig. 4.3 Impact of investment cost and interest rate on IRR

Ios

0

2

4

6

8

10

12

80% 100% 120% 140% 160%


PB

P (y

ears

)

investmentcost

interestrate

Fig.4.4 Impact of investment cost and interest rate on Payback Period

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4.2.2 Economical-Social Cost Benefit analysis

Table 4-6 Parameters used in the derivation of the BC ratio Initial data

Rated power of wind farm (MW) 8.00 Number of wind turbines 8.00 Number of plants 1.00 Rated power of hydro-turbines (MW) 8 Rated power of the pumps (MW) 6.5 Total investment cost (thousand euros) 18804 Subsidy (thousand euros, %) 5641 Own capitals 13163 Lifetime of the investment (years) 20 Discount rate (%) 5%

Phase: Equipment construction Cost of equipment's construction (thousand €) 14732 Percentage of local contribution 20% Employment - Mechanicals 1.7 Employment - Technicians 20.4 Employment - Jockeys 0.0 Employment - Workers 0.0 Total employment during equipment's construction phase (manyears) 22.1

Installation phase Cost of installation (wind, hydro and desalination) 4071.8 Percentage of local contribution 80% Employment - Mechanicals 4.65 Employment - Technicians 6.39 Employment - Jockeys 4.23 Employment - Workers 10.58 Total employment during installation phase (manyears) 26

Phase: Operation and Maintenance Cost of operation and maintenance (thousand €/year) 376.0797171 PV of O&M cost (thousand €) 4687 Percentage of local contribution 80% Employment (permanent jobs) - Mechanicals 1 Employment (permanent jobs) - Technicians 3 Employment (permanent jobs) - Jockeys 0 Employment (permanent jobs) - Workers 0 Total employment created 4 spin off effect 33% Total employment per year (manyears) 5

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DATA Electricity Tarrifs Ios Price of the electricity sold to the grid by the wind farm (€/kWh) 0.08 Price of hydro electricity sold to the grid (€/kWh) 0.15 price of electricity sold to the consumer (€/kWh) 0.086 Price of the electricity bought by the grid for pumping 0.12

Economical-Social Cost Benefit Analysis Public Inflows during construction and installation (thousand €) 3320 Public Inflows during O&M (thousand €/year) 63 PV of Public Inflows during O&M (thousand €) 786 Avoided Unemployment payment due to the created employment (thousand €) 24.8

Cumulative Public inflows (thousand €) 4131 Ios Losses in Public Inflows (thousand €) 8.4 Ios Avoided fuel cost (thousand €/year) 3209 PV of Avoided fuel cost (thousand €) 39995 Benefit due to the amount of electricity produced (thousand €/year) 1845.1 PV of electricity benefit (thousand €) 22994 Investment cost (domestic part) 6272 shadow price for imported part 1.2 Real value of imported investment 15038 PV of O&M (domestic part) 3749 Real PV of O&M cost (imported part) 1125 Ios External cost of CO2 emissions avoided (thousand €/year) 472 External cost of PM10 emissions avoided (thousand €/year) 13 External cost of SO2 emissions avoided (thousand €/year) 117 External cost of NΟx emissions avoided (thousand €/year) 26 Cumulative external cost by the avoided emissions (thousand €/year) 627 Cumulative external cost of emissions per cumulative installed capacity (thousand €//MW/year) 78

PV of the external cost by the avoided emissions (thousand €) 7819 PV of the external cost by the avoided emissions (thousand €/MW) 977 Ios B/CΝ,S 3.29

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4.3 Case Study 2 – Cyprus


Table 4-7 Basic energy results – Parameters - Assumptions Investment cost (1000€) 888091 Cost of wind farms in the hybrid stations (1000€) 675000 Cost of the hydro pumped storage units (1000€) 213091 Wind energy absorbed from the grid (GWh) 295.5 Turbine's energy production (GWh) 456.3 Grid energy used for pumping (GWh) 288.3 Price for the wind energy (€/kWh) 0.13 Price for the turbine's energy production (€/kWh) 0.15 Price for guaranteed power provided (€/kW) 94 Price for grid energy used for pumping (€/kWh) 0.100 Subsidy for wind farms (%) 30% Subsidy for the hydro pumped storage system (%) 30% Own capitals for the wind farms (%) 25% Own capitals for the hydro pumped storage system (%) 25% Lifetime of the project 20 Residue value 35% Annual operational and maintenance cost (1000€) 17761.83 Annual cost for grid energy used for pumping 28832 Tax rate (%) 20% Annual depreciations (1000€) 51805 Years of depreciation 12

Loan Interest rate (%) 6% grace period - years 1 pay back period 10

Table 4-8 Production Cost Production cost (1000€) 1 2 … 10 … 19 20 total (operation and maintenance cost + Depreciation 98399 98399 98399 46593 46593

Table 4-9 Profit calculation Years 1 2 … 10 … 19 20 Incomes from sales 128806 128806 128806 128806 128806 minus the production cost 98399 98399 98399 46593 46593 mixed profit 30407 30407 30407 82212 82212 mixed result 30407 30407 30407 82212 82212 minus loan interests 25417 23205 0 0 0 Profit before taxes 4990 7201 30407 82212 82212 minus taxes 998 1440 6081 16442 16442 net profit 3992 5761 24325 65770 65770

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Cumulative net profits 3992 9753 133723 642762 708532

Table 4-10 Cash flows Years 0 1 2 … 9 10 … 20 Inflows 888091 55797 57567 73310 76131 428407 own capitals 222023 subsidy 266427 loan 399641 net profits (after taxes) 3992 5761 21505 24325 65770

depreciation 51805 51805 51805 51805 51805 residue value 0 310832 Outflows 888091 36864 39076 58756 0 0 investment cost 888091 amortization (without interest) of loan 36864 39076 58756 0 0

Annual net flow (net result) 0 18933 18490 14554 76131 428407

Cumulative net cash flows 18933 37423 152026 228157 1631851


Table 4-11 Results of financial analysis Price of hydro electricity sold to the grid (€/kWh) 0.15 IRR 16% PBP (years) 10 NPV(i=9%) (1000€) 256655

-400000

-200000

0

200000

400000

600000

800000

1000000

1200000

1400000

1600000

0,00 0,05 0,10 0,15 0,20 0,25 0,30

%

NPV

(100

0€)

Fig. 4.5 Impact of discount rate on Net Present Value

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There is an uncertainty on the definition of the price. Then the dependence of the IRR to

the price is presented in the following figure.

Price for the hydro turbine's electricity (€/kWh) - IRR

0,00

0,05

0,10

0,15

0,20

0,25

0% 5% 10% 15% 20% 25% 30%

IRR (%)

Pri

ce f

or

the

hyd

ro t

urb

ine'

s el

ectr

icit

y (

€/kW

h)

Fig. 4.6 Impact of IRR on the price of hydro turbine electricity Sensitivity analysis of the investment cost and loan’s interest rate on the feasibility of the investment (IRR and PBP indexes)

Cyprus

0%

5%

10%

15%

20%

25%

80% 100% 120% 140% 160%


IRR investment

cost

interestrate


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42

Cyprus

02468

10121416

80% 100% 120% 140% 160%


PB

P (y

ears

)

investmentcost

interestrate


4.3.2 Economical-Social Cost Benefit analysis


Rated power of wind farm (MW) 450.00 Number of wind turbines 450.00 Number of plants 2.00 Rated power of hydro-turbines (MW) 250 Rated power of the pumps (MW) 360.0 Total investment cost (thousand euros) 888091 Subsidy (thousand euros, %) 63927 Own capitals 824164 Lifetime of the investment (years) 20 Discount rate (%) 5%

Phase: Equipment construction

Cost of equipment's construction (thousand €) 700732 Percentage of local contribution 15% Employment - Mechanicals 59.0 Employment - Technicians 709.8 Employment - Jockeys 0.0 Employment - Workers 0.0 Total employment during equipment's construction phase (manyears) 768.9

Installation phase

Cost of installation (wind, hydro and desalination) 187359.6 Percentage of local contribution 80% Employment - Mechanicals 205.53 Employment - Technicians 306.44

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Employment - Jockeys 184.94 Employment - Workers 462.35 Total employment during installation phase (manyears) 1159

Phase: Operation and Maintenance

Cost of operation and maintenance (thousand €/year) 17761.82703 PV of O&M cost (thousand €) 221352 Percentage of local contribution 80% Employment (permanent jobs) - Mechanicals 26 Employment (permanent jobs) - Technicians 135 Employment (permanent jobs) - Jockeys 0 Employment (permanent jobs) - Workers 0 Total employment created 161 spin off effect 33% Total employment per year (manyears) 214

DATA Electricity Tarrifs Cyprus Price of the electricity sold to the grid by the wind farm (€/kWh) 0.125 Price of hydro electricity sold to the grid (€/kWh) 0.15 price of electricity sold to the consumer (€/kWh) 0.086 Price of the electricity bought by the grid for pumping 0.1

Economical - Social Cost Benefit Analysis Public Inflows during construction and installation (thousand €) 157270 Public Inflows during O&M (thousand €/year) 2974 PV of Public Inflows during O&M (thousand €) 37066 Avoided Unemployment payment due to the created employment (thousand €) 187.3

Cumulative Public inflows (thousand €) 194523 Cyprus Losses in Public Inflows (thousand €) 43.0 Cyprus Avoided fuel cost (thousand €/year) 45761 PV of Avoided fuel cost (thousand €) 570282 Benefit due to the amount of electricity produced (thousand €/year) 64654.3 PV of electricity benefit (thousand €) 805736 Investment cost (domestic part) 256279 shadow price for imported part 1.2 Real value of imported investment 758174 PV of O&M (domestic part) 177081 Real PV of O&M cost (imported part) 53124

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Cyprus External cost of CO2 emissions avoided (thousand €/year) 5595 External cost of PM10 emissions avoided (thousand €/year) 190 External cost of SO2 emissions avoided (thousand €/year) 1879 External cost of NΟx emissions avoided (thousand €/year) 457 Cumulative external cost by the avoided emissions (thousand €/year) 8120 PV of the external cost by the avoided emissions (thousand €) 101197 Cyprus B/CΝ,S 1.42

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4.4 Case Study 3 – Corvo


Table 4-13 Basic energy results – Parameters - Assumptions Investment cost (1000€) 3700 Cost of wind farms in the hybrid stations (1000€) 1350 Cost of the hydro pumped storage units (1000€) 2350 Wind energy absorbed from the grid (GWh) 0,0000 Turbine's energy production (GWh) 1.2557 Grid energy used for pumping (GWh) 0.0 Price for the wind energy (€/kWh) 0.10 Price for the turbine's energy production (€/kWh) 0.40 Price for guaranteed power provided (€/kW) 0.260 Price for grid energy used for pumping (€/kWh) 0.015 Subsidy for wind farms (%) 30% Subsidy for the hydro pumped storage system (%) 30% Own capitals for the wind farms (%) 25% Own capitals for the hydro pumped storage system (%) 25% Lifetime of the project 20 Residue value 35% Annual operational and maintenance cost (1000€) 74.00 Annual cost for grid energy used for pumping 0 Tax rate (%) 35% Annual depreciations (1000€) 216 Years of depreciation 12

Loan Interest rate (%) 6% grace period - years 1 pay back period 10

Table 4-14 Production cost Production cost (1000€) 1 2 … 10 … 20 total (operation and maintenance cost + Depreciation) 290 290 290 74

Table 4-15 Profit calculation Years 1 2 … 10 … 19 20 Incomes from sales 502 502 502 502 502 minus the production cost 290 290 290 74 74 mixed profit 212 212 212 428 428 mixed result 212 212 212 428 428 minus loan interests 106 97 0 0 0 Profit before taxes 107 116 212 428 428 minus taxes 37 41 74 150 150 net profit 69 75 138 278 278 Cumulative net profits 69 144 1010 3235 3513

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Table 4-16 Cash flows Years 0 1 2 … 9 10 … 20 Inflows 3700 285 291 344 354 1789 own capitals 925 subsidy 1110 loan 1665 net profits (after taxes) 69 75 129 138 278 depreciation 216 216 216 216 216 residue value 0 1295 Outflows 3700 154 163 245 0 0 investment cost 3700 amortization (without interest) of loan 154 163 245 0 0 Annual net flow (net result) 0 131 128 100 354 1789 Cumulative net cash flows 131 260 1049 1403 7360


Table 4-17 Results of financial analysis Price of hydro electricity sold to the grid (€/kWh) 0.40 IRR 19% PBP (years) 8 NPV(i=9%) (1000€) 1404

-1000

0

1000

2000

3000

4000

5000

6000

7000

0% 5% 10% 15% 20% 25% 30%

discount rate (%)

NPV

(100

0€)

Fig. 4.9 Impact of discount rate on Net Present Value There is an uncertainty on the definition of the price. Then the dependence of the IRR to the price is presented in the following figure

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Price for the hydro turbine's electricity - IRR

0,0

0,1

0,2

0,3

0,4

0,5

0,6

0% 5% 10% 15% 20% 25% 30%

IRR (%)

Pri

ce fo

r th

e hy

dro

turb

ine'

s el

ectr

icity

(€/k

Wh)

Fig. 4.10 Impact of IRR on the price of hydro turbine electricity Sensitivity analysis of the investment cost and loan’s interest rate on the feasibility of the investment (IRR and PBP indexes)

Corvo

0%

5%

10%

15%

20%

25%

30%

80% 100% 120% 140% 160%


IRR investment

cost

interestrate


Corvo

0

2

4

68

10

12

14

80% 100% 120% 140% 160%


PBP

(yea

rs)

investmentcost

interestrate


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4.4.2 Economical and Social Cost Benefit analysis


Rated power of wind farm (MW) 0.90 Number of wind turbines 0.90 Number of plants 1.00 Rated power of hydro-turbines (MW) 0.24 Rated power of the pumps (MW) 0.9 Total investment cost (thousand euros) 3700 Subsidy (thousand euros, %) 1110 Own capitals 2590 Lifetime of the investment (years) 20 Discount rate (%) 5%

Phase: Equipment construction

Cost of equipment's construction (thousand €) 2853 Percentage of local contribution 43% Employment - Mechanicals 0.6 Employment - Technicians 7.1 Employment - Jockeys 0.0 Employment - Workers 0.0 Total employment during equipment's construction phase (manyears) 7.7

Installation phase

Cost of installation (wind, hydro and desalination) 847.5 Percentage of local contribution 83% Employment - Mechanicals 1.04 Employment - Technicians 1.22 Employment - Jockeys 0.97 Employment - Workers 2.43 Total employment during installation phase (manyears) 6

Phase: Operation and Maintenance Cost of operation and maintenance (thousand €/year) 74.00341947 PV of O&M cost (thousand €) 922 Percentage of local contribution 80% Employment (permanent jobs) - Mechanicals 0 Employment (permanent jobs) - Technicians 1 Employment (permanent jobs) - Jockeys 0 Employment (permanent jobs) - Workers 0 Total employment created 1 spin off effect 33% Total employment per year (manyears) 1

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DATA Electricity Tarrifs Corvo Price of the electricity sold to the grid by the wind farm (€/kWh) 0.26 Price of hydro electricity sold to the grid (€/kWh) 0.40 price of electricity sold to the consumer (€/kWh) 0.12 Price of the electricity bought by the grid for pumping 0.26

Economical and Social Cost Benefit Analysis

Public Inflows during construction and installation (thousand €) 683 Public Inflows during O&M (thousand €/year) 13 PV of Public Inflows during O&M (thousand €) 161 Avoided Unemployment payment due to the created employment (thousand €) 3.6

Cumulative Public inflows (thousand €) 848 Corvo Losses in Public Inflows (thousand €) 0,6 Corvo Avoided fuel cost (thousand €/year) 1155 PV of Avoided fuel cost (thousand €) 14396 Benefit due to the amount of electricity produced (thousand €/year) 150.7 PV of electricity benefit (thousand €) 1878 Investment cost (domestic part) 1939 shadow price for imported part 1.2 Real value of imported investment 2113 PV of O&M (domestic part) 738 Real PV of O&M cost (imported part) 221 Corvo External cost of CO2 emissions avoided (thousand €/year) 29 External cost of PM10 emissions avoided (thousand €/year) 1 External cost of SO2 emissions avoided (thousand €/year) 6 External cost of NΟx emissions avoided (thousand €/year) 1 Cumulative external cost by the avoided emissions (thousand €/year) 38 PV of the external cost by the avoided emissions (thousand €) 471 Corvo B/CΝ,S 4.10

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4.5 Conclusions In the framework of the current work, the indexes for the three levels of analysis (financial, economical and social) are calculated and comparably presented for the three islands.

Table 4-19 Summary of results B/CF B/CΝ,S Ios 1.25 3.29 Cyprus 0.93 1.42 Corvo 1.78 4.10

In the first level of the analysis, results show that the development of wind energy with hydro pumped storage seems to be attractive for the private investors in the two of the three case studies examined. The wide range of the cost benefit indexes (0.93-1.78) is justified by the several differences of the examined cases: different wind potential different cost of hydro pumped storage

systems due to the different size of the proposed systems and of the electrical systems.

different benefit due to the different prices for the hydro turbine’s production

different current cost of electricity production

Cyprus represents the lower attractiveness for the development of wind with pumped storage systems. In Ios and Corvo, such systems seem to be more attractive.

In the second level of the analysis, results show that in all the case studies this storage technology appears to be attractive for the national economy and the society. In the case studies of Ios and Corvo, the associated benefits from the wind with pumped storage development are much more times higher than the engaged financial resources. These results are very positive for the prospects of wind with pumped storage in autonomous islands and show that governments, local authorities and societies should strive for substantially increasing the share of RES using this technology. It is namely shown that such a shift is compatible with the market’s major aspirations, but is also justified from a broader perspective reflecting the short and long term interests of the national economy and the society as a whole. The results show that these benefits are large enough to fully cover any subsidies that the decision makers could provide for such investments in order to encourage private investors to undertake the technical and financial risks associated with these projects.

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5 HYDROGEN STORAGE

5.1 Overview The hydrogen energy storage was examined as an energy storage option for the power system of two islands. The first one is the Greek island Milos in the Aegean Sea and the second one is the Portuguese island Corvo in the Azores Archipelago. The storage system under examination includes a water electrolysis unit, a hydrogen storage tank and a fuel cell. Electrolytic hydrogen is produced when excess energy generated by renewable electricity-generating technologies is available. Hydrogen is then stored in gaseous form and can be used as a feedstock for the fuel cell in order to produce electricity when is needed. For both islands, HOMER was used to simulate and optimize the proposed RES & hydrogen-based power systems. The optimal configurations were compared to the existing power systems of the islands in terms of cost of power generation, Renewable Energy (RE) penetration and emissions produced locally. The analysis presented in the following sections aims to consider the environmental and social parameters of the RES & hydrogen-based power systems, that are excluded from HOMER, and their effects on the cost of energy. More specifically, for each case study a financial and economic analysis is carried out followed by the identification of the environmental and social impacts of the proposed system. Moreover, a sensitivity analysis is performed.

5.2 Case Study 1 – Milos

5.2.1 Introduction The annual electricity demand of Milos island is approximately 39,729 MWh with peak demand equal to 8.5 MW. In order to meet this demand, the existing power system includes 8 thermal generator sets with a total

capacity of around 11.25 MW and a small wind park comprising 3 wind turbines with a total installed capacity of 2.05 MW. Based on the simulation results, the existing power system delivers electricity at a cost equal to 113 €/MWh. According to the simulation results, the components of the optimum RES & hydrogen-based power system when hydrogen is introduced as an energy storage medium in the power system are depicted in Table 5-1.

Table 5-1 The proposed RES & hydrogen-based power system for Milos island

Component Type Number Size

Wind Turbine

V-52 28 850 kW (each)

V-44 2 600 kW (each)

Thermal Generator

Sulger 2 1750 kW (each)

Man 2 700 kW (each)

Rental 1 1032 kW Fuel Cell PEM 1 1 MW

Electrolyser Alkaline 1 2 MW Hydrogen

storage tank Compressed

gas 1 4000 kg

The cost of energy of the proposed power system decreases to 112 €/MWh. The costs of energy for the existing and the proposed power system have been derived including a 30% subsidy for renewable electricity-generating technologies, a 50% subsidy for hydrogen technologies and a cost of CO2 emission equal to 21 €/t. The analysis presented hereafter includes the financial and economic analysis of the proposed RES & hydrogen-based power system.

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5.2.2.1 Investment Costs The costs of a project can be divided into the investment and the operational costs. The former include the initial and replacement costs and are presented in this section. Initial costs referred to as the first cost that usually includes cost elements that do not recur after an activity is initiated. Generally, the initial cost is the major component of a renewable energy project and is usually higher than in non-renewable energy projects. The replacement costs involve the cost of equipment and installations procured during the operating phase of a project to maintain its original productive capacity. The

investment costs of the proposed RES & Hydrogen-based power system for Milos are illustrated in Table 5-2.

Table 5-2 The investment costs of the proposed RES & hydrogen-based power system for Milos island

Technology Type Unit Cost Initial Cost Replacement Cost

Wind Turbine V-52 1,200

€/kW 19,992,000 € 0 €

V-44 1,200 €/kW 1,008,000 € 0 €

Thermal Generator

Sulger 251 €/kW 880,000 € 88,000 €

Man 286 €/kW 400,000 € 40,000 €

Rental 145 €/kW 150,000 € 0 €

Fuel Cell PEM 3,000 €/kW 1,500,000 € 450,000 €

Electrolyser Alkaline 2,000 €/kW 2,000,000 € 0 €

Hydrogen storage tank Compressed gas 800 €/kg 1,600,000 € 0 €

Total 27,530,000 € The initial costs shown in Table 5.2 are calculated by multiplying the unit cost of each technology of Table 2.2 with the number of necessary units shown in Table 5.1. The initial costs of the wind turbines and the hydrogen technologies are presented reduced, as a subsidy of 30% and 50%

respectively has been included in the simulation. According to the simulation results, during the 20-year lifetime of the project 3 diesel generators and the fuel cell are replaced. The first diesel generator replacement takes place at the 12th year and is one of the Sulger generators. The

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Man generators are both replaced one during the 13th year and the other during the 19th year. The fuel cell is replaced twice during the project’s lifetime during the 7th and the 14th year. Table 2.2 presents only the replacement costs of the equipments that are replaced during the lifetime of the project.

5.2.2.2 Operational Costs Unlike investments costs, operational costs of RE projects are usually low. Operational costs include fixed and variable costs that recur continually over the lifetime of a

project. The former remain relatively constant and are independent of the activities of the project while the latter vary with the level of operational activity. The operational costs for the proposed power system are given in Table 5-3.

Table 5-3 The operational costs of the proposed RES & hydrogen-based power system for Milos island

Parameter Type Unit Cost Operational Cost

Wind Turbine V-52 17,340 €/year 485,520 €/year V-44 12,240 €/year 24,480 €/year

Thermal Generator Sulger 6.5 €/hour 44,948 €/year Man 5.5 €/hour 36,636 €/year

Rental 5.5 €/hour 5,478 €/year Fuel Cell PEM 1.02 €/hour 4,418 €/year

Electrolyser Alkaline 50,000 €/year 50,000 €/year Hydrogen storage tank Compressed gas 4,000 €/year 4,000 €/year

Fuel Diesel 0.68 €/L 105,336 €/year Heavy oil 0.34 €/L 1,038,654 €/year

Emissions CO2 21 €/t 206,677 €/year Total 2,006,147 €/year

As it can be witnessed in Table 5-3 a major contribution to the operational cost of the entire system is the cost of the fuels (57%) indicating the advantage of renewable electricity-generating technologies that use fuel of zero cost, such as wind or solar (with exception in the case of biomass). The investment and operational costs of all the necessary components of the proposed RES & Hydrogen-based power system were derived form previous studies carried out by members of the consortium of STORIES project [12] and from personal communications with equipment manufacturers.

5.2.2.3 Revenues The revenues are derived from the sale of the electricity produced by the proposed power system. The proposed RES & Hydrogen power system is a hybrid system that contains both renewable energy technologies and conventional technologies. The price at which electricity is sold is different for different electricity-generating technologies. More specifically, for the proposed power system three different prices are considered. The first is the price of electricity that is generated from the wind turbines and is directly fed into the grid. The second is the electricity price for the energy produced by the diesel generators and the

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third is the price of the electricity that is fed into the grid from the storage system. For the electricity of renewable and conventional energy sources the price is straightforward. According to the Greek Regulatory Authority of Energy (RAE), the price of wind-based electricity for non-interconnected islands is approximately 0.092 €/kWh [13]. The price of electricity from conventional sources was considered around 0.1 €/kWh [14]. The price of the electricity supplied from the storage system is more complicated. Usually, the pricing of electricity from the storage system of a hybrid system is case-specific and is done for each case distinctively. In this analysis, a price of 0.15 €/kWh was assumed based on the electricity prices of other hybrid systems in other islands [13]. Generally, the price of electricity escalates every year and thus in the 20-year lifetime of the project a 3% annual increase is considered. In Greece, the municipality that a wind park is installed receives 3% of the revenues of the investor. This percentage is also included in the analysis. The following Table summarizes the revenues of the proposed RES & Hydrogen-based power system for a 20-year time horizon.

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Table 5-4: Revenues of the RES & Hydrogen-based power system

Year Technology Electricity consumption Revenues 2 Wind Turbines 24,894,794 kWh 2,281,793 € Diesel Generators 12,304,077 kWh 1,267,320 € Fuel Cell 2,353,161 kWh 363,563 €

4 Wind Turbines 24,894,794 kWh 2,420,754 € Diesel Generators 12,304,077 kWh 1,344,500 € Fuel Cell 2,353,161 kWh 385,704 €









Total 791,040,640 kWh 102,337,822 € The total amount of electricity consumption and revenues is the sum of the consumption and the revenues of all the years of the project’s lifetime, however due to space reasons only half of the years are presented in Table 5-4. As it can be viewed in Table 5-4 the annual electricity consumption is the same for every year. This is also true for the annual electricity production from all the technologies. Of course, this is not realistic especially in the case of wind energy due to the variability of the wind speed. However,

the effect of this simplification on the results due to the linear problem solving approach of HOMER is believed that is not significant and thus this limitation of the approach was accepted. It is worthwhile to mention that the wind turbines produce a considerably greater amount of energy than the amount that is absorbed by the grid. More specifically, the wind turbines produce annually 69,124,688 kWh out of which the 7,352,470 kWh are fed into the electrolyser, the 24,894,794 kWh go directly into the grid and around 36,877,424 kWh are the surplus electricity

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that the system cannot use. So, the investor out of the total annual amount of energy that the wind turbines produce profits only from the 56% (32,247,264 kWh). The effect of the excess electricity on the economic attractiveness of the project is showed in the subsequent section.

5.2.2.4 Project Appraisal In order to calculate the NPV it is necessary to use a discounted cash flow. Table 5-5 shows the discounted cash flow for the RES & Hydrogen-based power system.

Table 5-5 NPV of RES & Hydrogen-based power system for Milos island

Year Cash flows Discount factor Present values 0 - 27,530,000 € 1 - 27,530,000 € 1 - 2,006,147 € + 3,798,715 € 0.943 + 1,690,391 € 2 -2,006,147 € + 3,912,676 € 0.890 + 1,696,811 € 3 -2,006,147 € + 4,030,057 € 0.840 + 1,700,084 € 4 -2,006,147 € + 4,150,958 € 0.792 + 1,698,690 € 5 -2,006,147 € + 4,275,487 € 0.747 + 1,695,197 € 6 -2,006,147 € + 4,403,752 € 0.705 + 1,690,311 € 7 -2,456,147 € + 4,535,864 € 0.665 + 1,383,012 € 8 -2,006,147 € + 4,671,940 € 0.627 + 1,671,452 € 9 -2,006,147 € + 4,812,098 € 0.592 + 1,661,123 €

10 -2,006,147 € + 4,956,461 € 0.558 + 1,646,275 € 11 - 2,006,147 € + 5,105,155 € 0.527 + 1,633,177 € 12 - 2,094,147 € + 5,258,310 € 0.497 + 1,572,589 € 13 - 2,046,147 € + 5,416,059 € 0.469 + 1,580,489 € 14 - 2,456,147 € + 5,578,541 € 0.442 + 1,380,098 € 15 - 2,006,147 € + 5,745,897 € 0.417 + 1,559,476 € 16 - 2,006,147 € + 5,918,274 € 0.394 + 1,541,378 € 17 - 2,006,147 € + 6,095,822 € 0.371 + 1,517,269 € 18 - 2,006,147 € + 6,278,697 € 0.35 + 1,495,392 € 19 - 2,046,147 € + 6,467,058 € 0.331 + 1,463,321 € 20 - 2,006,147 € + 6,661,069 € 0.312 +1,452,336 €

NPV + 4,198,873 € For the calculations of the NPV a discount rate of 6% has been used. As Table 5-5 shows the project has a positive NPV. According to the NPV decision rules, the positive NPV demonstrates the financial viability of the project. However, the results of the NPV method, and in general of all the project appraisal methods, can be quite relative because although the NPV in this case is positive the value taking into account the initial investment is not quite high. More specifically, on a €27,5m investment the surplus generated beyond the opportunity cost of the investor is approximately €4m. Thus, by implementing the proposed system

the investor would increase his wealth by this amount. So, a general conclusion that can be drawn is that the project is not a loss-making investment but also not quite profitable. From the results of the NPV method the effect of the excess electricity on the project’s financial viability can be seen. The excess electricity is responsible for a 44% reduction in the revenues of the investor. So, although the investor purchases equipment for the production of 83,781,928 kWh/yr, only 46,904,136kWh/yr are sold. If the excess electricity was significantly smaller the NPV of the project would have been

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considerably greater making the investment more economically attractive. An option to increase the profitability of the investment is to use the excess energy for the production of hydrogen in order to be used locally as a fuel in the transport sector. Another option is the use of this energy for heating purposes. In both cases the investor would have an additional source of revenues making the investment more profitable. The financial viability of the proposed system was also examined by the IRR technique. Table 5-6 shows the NPV for different values of discount rate. The discount rate for which the NPV is equal to zero is the IRR.

Table 5-6: The relationship between the NPV and the discount rate for the RES &

Hydrogen-based power system

Discount rate NPV 0% 33,351,949 € 1% 0 € 2% 20,653,580 € 4% 11,254,900 € 6% 4,198,873 €

It can be witnessed in Table 5-6 that the IRR for the proposed RES & Hydrogen-based power system is 1%. According to the IRR decision rules, when the opportunity cost of capital is greater than the IRR on a project then the investor is better not to implement the project. Thus, under the IRR method the investment is not financially viable. The results of the financial analysis have produced conflicting decision outcomes, which depend on the project appraisal method employed. Based on the NPV method the investment should be accepted on the other hand based on the IRR method the investment should be rejected. A reasonable question that may arise at this point is which method should be preferred. To answer that question it should be firstly pointed out that the results of both methods are not absolutely

contradicting each other. According to both methods, the investment is not quite profitable. This is evident directly based on the 1% IRR, which characterizes the investment financially unviable, and indirectly based on a positive yet small NPV that indicates that investor would not lose any money but also would not increase greatly his capital. So, the general conclusion that the investment would not return most to the investor can be drawn from both methods. However, the NPV has the advantage of showing that although the profitability of the project is not satisfactory the investor would not actually lose any money. NPV is the better decision-making technique because it measures on absolute amounts of money. It gives the increase in investor’s wealth by accepting a project. In contrast, IRR expresses its return as a percentage which may result in an inferior low-scale project being preferred to a higher-scale project. Based on the cash flow analysis the payback period can be derived. The simple payback period is around 11,5 years. As the analysis includes discounted cash flows, an improvement on the simple payback method that excludes discounted cash flows can be calculated taking into account the time value of money. The discounted payback period based on the present values of Table 5-5 for the RES & Hydrogen-based power system is approximately 17 years.

5.2.2.5 Sources of Finance In order for renewable energy sources to significantly penetrate the energy market substantial funds at a European and national level are required. The required investments may be financed from both public and private sectors in the form of financial incentives from government, loans and capital investment from banks, private investors and venture capital funds. Sources of finance include banks, venture capital, equity capital, Government funds and European funds.

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Project finance is a relatively new term of financing projects in the Greek banks and in any case is not a common practice of the Greek not so risky banking system. A typical project finance deal is created by an industrial corporation providing some equity capital for a separate legal entity to be formed to build and operate a project. The project finance loan is then provided as bank loans or through bond issues direct to the separate entity. The important characteristic of this method is that the source of funds for repayment is tied to the cash flows of the project. The project is a stand-alone investment with its own financing [1]. Venture capital funds provide finance for high-growth-potential unquoted firms. It is a medium-to long-term investment and can consist of a package of debt and equity finance. Venture capitalists take high risks by investing in the equity of small, new companies often with a limited or any track record. Usually, high risk goes with high return and venture capitalists expect to see returns of at least 29% from their investments but accept that some of them will fail. In Greece, there are two principal financial support instruments: the National Development Law and the National Operational Programme “Competitiveness”. The former is an investment law that covers all economic sectors under which investments in RES installations are eligible for a subsidy. This subsidy ranges from 20% to 60% of the total investment cost. The latter is one of the eleven National and the thirteen Regional Operational Programmes in which the Third Community Support Framework for Greece is divided. The Measure 2.1 of Priority Axis 2 of the National Operational Programme “Competitiveness” supports by investing in RES, rational use of energy and small-scale (<50 MWe ) cogeneration. The total budget of this Measure amounts to 1.07billion Euro, of which 382 million Euro is the public subsidy devoted to the aforementioned investments [15].

In the European Union, the Directorate General for Transport & Energy is responsible for the energy policy. One of the main European tools for funding renewable energy projects is the Intelligent Energy Europe II (IEE2) Programme. IEE2 is one of the three pillars under the Competitiveness and Innovation Programme (CIP) and provides financial support to local, regional and national initiatives in the fields of renewable energies, energy efficiency, energy aspects of transport and their international promotion. IEE2 runs from 2007 to 2013 and has a budget of 727 million Euro. The programme is structured into three areas. The first (SAVE subprogramme) aims to address improvements in energy efficiency and the rational use of energy and it mainly focuses on building and industry sectors. The second (ALTENER subprogramme) aims to promote the use of RES and facilitate their integration into the local environment and energy systems. The third (STEER subprogramme) supports initiatives relating to all energy aspects of transport, including the diversification of fuels and the more efficient use of energy in transport [16]. Another subprogramme that has been launched under IEE is the COOPENER programme. This programme aimed at strengthening local capacities in energy planning, energy efficiency and renewable energy. It has now moved to become a Thematic Programme for Environment and Sustainable Management of Natural Resources and addresses the market and regulatory conditions for the provision of sustainable energy services. The Union’s main instrument for the funding of the whole spectrum of research is the Seventh Framework Programme for Research and Development (FP7). FP7 commenced on 1 January 2007 and will run for 7 years. The programme has a total budget of over 50 billion Euro and is broken down to five Specific Programmes: Capacities, People, Ideas, Cooperation and Nuclear Research. The energy section within the FP7 attempts to accelerate the development of energy

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technologies towards cost-effectiveness for a more sustainable European energy economy. The budget of the Energy section, excluding nuclear energy, amounts to 2.3 billion Euro. The Energy section is divided into four main themes: sustainable development, security of supply, climate change and competitiveness. Emphasis will be given to activities such as hydrogen and fuel cells, renewable fuel production, renewable electricity generation, CO2 capture and storage, smart energy networks, energy efficiency and savings and knowledge for energy policy making. Another European source of finance is the EU LIFE Programme that supports activities that they cannot be financed from the aforementioned instruments. LIFE co-finances environmental (LIFE-Environment) and nature conservation (LIFE-Nature) projects in the EU, as well as in some candidate, acceding and neighbouring countries (LIFE-Third Countries). The latest EU LIFE Programme, LIFE+, provides financial support for projects that reinforce the development and implementation of European environmental policy and legislation, particularly the objectives of the 6th Environmental Action Programme and resulting thematic strategies. It came into force on 9 June 2007 and has a budget of 2.143 billion Euro between 2007-13 [16]. For hydrogen technologies, there is also the Joint Technology Initiative for Fuel Cells and Hydrogen (FCH JTI) that is part of the new European approach to foster technology innovation and accelerate commercialisation of fuel cell and hydrogen technologies. The Programme aims to increase EU competitiveness in fuel cell and hydrogen technologies, achieve mass-market roll-out by 2020, for transport applications and provide the technology base to initiate market growth for stationary fuel cell domestic and commercial (CHP) and portable applications from 2010-15. EC has committed to contribute up to 900 million Euro in fuel cell and hydrogen technology development between 2008 and 2013 [17].

A new source of financing may originate from the sale of environmental attributes such as greenhouse gas emission reduction credits, renewable energy (green) certificates or energy efficiency (white) certificates.

5.2.3 Economic results & analysis In the preceding section the project has been financially evaluated from the perspective of the investor. However, the implementation of the project has also effects on the national economy and the environment. For this reason, the identification and assessment of the benefits and costs from the perspective of the national economy and the environment are necessary in order for the project evaluation to be more realistic and to better reflect the total benefits and costs to the society as a whole. In this section an economic evaluation is carried out taking into account the environmental and social attributes of the project. The section begins with a qualitative description of the environmental and social impacts of the project followed by an attempt to quantify these impacts in order to assess the net economic impact on the environment and the society.

5.2.3.1 Environmental and Social Impacts Renewable energy sources are more environmental benign than fossil fuels that damage air, climate, water, land and wildlife. Despite their acknowledged advantages, the deployment of renewable energy sources has also adverse environmental and social impacts. The substitution of conventional energy technologies with renewable energy technologies leads to environmental and social costs and benefits. These costs and benefits vary widely depending on the renewable energy sources and the technologies used. Although the majority of studies focuses on the technical and economic aspects of renewable energy projects, there are a few that examine the

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social and environmental effects of such projects [5] and [6]. In the case study of Milos, part of the conventional energy technologies has been replaced with wind energy and hydrogen technologies. Wind energy is one of the most benign sources of energy. It has the major advantage of producing electricity without the emission of several greenhouse gases including carbon and sulphur dioxides. The prevention of harmful emissions assists in the amelioration of air quality that is damaged by the continuous use of fossil fuels. The production of electricity from wind energy does not deplete natural resources as the wind, which is the production feedstock, is inexhaustible. However, wind energy may also have a number of unfavourable effects. The main environmental concerns about wind energy are the noise pollution, the interference with bird flight and the aesthetic degradation. There are two principle sources of noise in the wind turbine: the machinery in the nacelle and the swishing sound from the rotating blades. The former has been largely eliminated through improved engineering and the latter is unavoidable. Nevertheless, the noise level of a wind farm at 350m is around 35-45 dB, while a car at 40 m/h at 100m has 55 dB. Considering that a wind farm is generally at least 300m away from houses, the noise of the wind turbines is lower than that of road traffic, trains and aircraft [18]. Like with other tall structures, birds sometimes collide with wind turbines. Detailed studies have indicated that this issue is site-specific and may not affect wind turbines generally. Wind energy developments may also have positive impacts on birds. Wind farms offer natural habitant and provide birds with an environment safe from human harassment. The visual impact of wind turbines is a quite disputable issue as to some people wind turbines spoil the landscape and to others they constitute a pleasant addition to the rural scene.

The large-scale deployment of wind energy may lead in other environmental impacts such as the reduction of wind speeds causing stress to ecosystems or the increase of soil moisture. However, these impacts are not usually of great consequence except in certain sensitive areas and thus wind energy may be considered to be one of the most ecologically benign sources of energy for electricity production. From a social perspective, the use of wind energy and hydrogen technologies for the production of electricity provides a number of considerable benefits. The exploitation of wind energy for power purposes may assist in reducing imported fuel dependency and securing supply. These issues are of particular importance especially in the case of remote regions and islands that face problems with the supply of fuels due to a number of reasons, such as bad weather conditions. Since renewable energy sources are more evenly distributed among the world than conventional energy sources, their deployment secures the supply of electricity as a consumer good to isolated regions. Wind power, though, is an intermittent source of energy and its power output exhibits daily and seasonal fluctuations. The significant penetration of intermittent renewable energy sources may create problems in matching supply with demand and technical issues associated with weak grids. The introduction of hydrogen storage is one of the options that may ameliorate the incorporation of intermittent sources into power generation systems. Hydrogen storage has the benefits of providing a buffer between the grid and the unstable grid power, load leveling conventional power sources like diesel engine power and enabling the use of intermittent energy sources to supply power-on-demand. The introduction of wind energy and hydrogen storage into the power system also entails employment benefits. During the manufacturing and installation of the technologies and the operation and maintenance phase of the project a number of

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temporary and permanent jobs may be created. The employment in manufacturing of wind turbines is generally concentrated in a few countries for instance in Europe Germany, Denmark and Spain account for more than 90%. Thus, in the case of Milos island the effect on employment during installation, operation and maintenance was considered. The same approach was followed for hydrogen technologies. Apart from the direct work opportunities, indirect jobs may also be created as a result of the implementation of the RES & Hydrogen project. This effect is often described as the spin-off effect. In terms of human safety hazards, wind energy industry involves similar risks with the building industry, such as the risk of falling from a high building during construction and maintenance. Normally, wind turbines are installed in sparsely populated areas and thus the risk of human incidents is small. Tax revenues constitute an important source of revenues for the national economy. The introduction of wind energy and hydrogen storage into the power system results in a positive impact on this source of revenues. The creation of new jobs has a dual effect on the national economy. The country is benefited from the income tax and the allowances of unemployment that are avoided due to the additional jobs that are created. The valued added tax (VAT) of the equipments comprises another benefit for the national economy. Apart from the environmental attributes of wind energy, local authorities are also economically benefited from wind energy developments. Wind-based electricity producers are obliged to pay 3% of their revenues to the local authorities of the regions in which the wind parks are installed. The idea behind this contribution is that this percentage offsets the

negative environmental impacts of wind energy on the local community.

5.2.3.2 Monetization of Costs and Benefits As the environmental and social impacts of a project constitute a crucial component of a project’s assessment, the proposed RES & Hydrogen power system for Milos island has been evaluated taken into account the environmental and social costs and benefits arisen from the implementation of the project in order to estimate the total costs and benefits to the society as a whole. In order to assess the net value of the RES & Hydrogen power system to society a social cost-benefit analysis was undertaken. The following Table presents the cost of the technologies used in the RES & Hydrogen power system of Milos and the work opportunities during the purchase and installation phase of the project.

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Table 5-7 Cost and employment during purchase and installation phase of the RES & Hydrogen power system of Milos

Technology Cost Greek Participation

Employment Persons Number Days

Wind turbines 21,000,000€ 30% Engineers 8 365 Technicians 7 730 Operators 7 365 Workers 16 365

Diesel generators 1,430,000 € 30% Engineers 6 30 Technicians 3 30 Operators 3 30 Workers 6 30

Storage system Engineers 3 60 Electrolyser 2,000,000 € 30% Technicians 1 90

Hydrogen tank 1,600,000 € 100% Operators 0 0 Fuel cell 1,500,000 € 30% Workers 1 30

Total cost 27,530,000€ Greek participation 34% Manyears engineers 8.99

Manyears technicians 14.49 Manyears operators 7.25 Manyears workers 16.58

Total Employment 47.3 (MY) It has been considered that some equipments are imported from abroad and thus the cost of the equipments consists of two components, the domestic and the imported. Table 5-7 shows the percentage of the Greek participation for the purchase and installation cost. The imported cost of the investment has been multiplied by a shadow factor in order to incorporate the principle that it is preferred to utilize local suppliers and domestic expertise than to import goods and services. The subsequent Table shows the operation and maintenance cost the technologies of the RES & Hydrogen power system of Milos and the ensuing work opportunities during this phase.

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Table 5-8 Cost and employment during operation and maintenance phase of the of the RES & Hydrogen power system of Milos

Technology Cost Greek Participation


Wind turbines 510,000€/yr 80% Engineers 1 365 Technicians 4 365 Operators 0 0 Workers 0 0

Diesel generators(DG) 87,062 €/yr 90% Engineers 1 365 Technicians 2 365 Operators 1 365 Workers 0 0

Storage system Engineers 1 365 Electrolyser 50,000€/yr 60% Technicians 2 365

Hydrogen tank 4,000 €/yr 60% Operators 0 0 Fuel cell (FC) 4418 €/yr 60% Workers 0 0

Diesel fuel 105,336€/yr 100% Heavy oil fuel 1,038,654€/yr 100% CO2 emissions 206,677€/yr 100%

FC Replacement cost 450,000€/yr 40% DG 1750kW

Replacement cost 88,000€/yr 100%

DG 700kW Replacement cost 40,000€/yr 100%

Total cost 2,006,147€/yr 7th year 2,186,147 €

12th year 2,094,147 € 13th year 2,046,147 € 14th year 2,186,147 € 19th year 2,046,147 €

PV of total cost 23,285,380€ Greek participation 93% Permanent jobs for

engineers 3

Permanent jobs for technicians 8

Permanent jobs for operators 1

Permanents job for workers 0

Total permanent jobs 12 Spin off effect 33%

Total Employment per year 15.96 (MY)

As it can be witnessed in Table 5-8, the impact on the employment has been calculated both for direct and indirect jobs.

The creation of new jobs in a given sector may create new indirect jobs in other sectors and regions. This effect is known as the spin off effect. Table 5-8 presents the total O&M

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cost per year. Moreover, since some technologies are replaced during the lifetime of the project Table 5-8 also presents the total O&M costs of the years that a replacement had taken place. The derivation of the BC ratio has been based in a number of additional parameters. Table 5-9 shows these parameters along with their corresponding values. For the social parameters a number of assumptions have been made based on personal communications with members of the consortium of STORIES project.

Table 5-9 Parameters used in the derivation of the BC ratio

Parameter Value Wind energy consumption 24,894,794 kWh/year

Fuel cell energy consumption 2,353,161 kWh/year

DG energy consumption 12,304,077 kWh/year

Price of wind electricity 0.09174 €/kWh

Price of fuel cell electricity 0.15 €/kWh

Price of DG electricity 0.1 €/kWh

Price of buying electricity 0.1 €/kWh

Income Tax 20% Average period of

unemployment 12 months

Average unemployment

allowance 430.75 €/month

Average annual net salary 12240 €/year

VAT 19% Net Gross

Engineer salary 19,600 €/year

27,048 €/year

Technician salary 10,800 €/year

15,012 €/year

Operator salary 10,000 €/year

13,900 €/year

Worker salary 8,000 €/year

11,120 €/year

The benefit from the avoided CO2, SO2, NOx and PM10 emissions caused by the proposed RES & Hydrogen power system are derived by applying the EcoSenceLE tool. Table 5-10 displays the basic inputs, assumptions and the total external benefit from the avoided emissions due to the proposed power system in Milos.

Table 5-10 Avoided emissions due to the proposed RES & Hydrogen power system in

Milos island

Milos proposed power system Avoided Emission values NOx 317,722 kg/year SO2 328,536 kg/year PM10 2,684 kg/year CO2 17,120,117 kg/year Assumptions

Mortality value 75,000 €/Life Year Lost

Abatement cost per tonne of CO2

19 €/t

Summary Results Human Health Mortality 629,000 €/year

Human Health Morbidity 332,000 €/year

Crops 293,000 €/year Materials 44,500 €/year CO2 325,000 €/year Total External Benefit 1,623,500 €/year

PV of total external benefit

18,621,417 €

Based on the aforementioned data the BC ratio for the society and the environment has been calculated. Table 5-11 presents the social and environmental costs and benefits in monetary values and the BC ratio.

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Table 5-11 Socio-environmental BC ratio for the RES & Hydrogen power system of

Milos island

Socio-environmental benefit or cost Monetary value

Benefit from the purchase & installation phase

1,778,438 €

Benefit from the O&M phase 355,706 €/year

PV of benefit from the O&M phase 3,911,385 €

Benefit from the creation of new jobs 325,647 €

Benefit from public contributions 575,885 €

Benefit from the operation of the wind park

1,841,036 €/year

PV of the benefit from the operation of the wind park

997,690 €

Benefit from the production of electricity 3,955,203 €/year

PV of benefit from the production of electricity 45,365,869 €

Cost of domestic investment 9,360,200 €

Cost of imported investment 21,803,760 €

Cost of domestic O&M 1,872,136 €/year PV of cost of domestic O&M 21,713,606 €

Cost of O&M imported 168,516 €/year PV of cost of O&M imported 1,955,972 €

Total external benefit 1,623,500 €/year PV of total external benefit 18,621,417 €

Total benefits 68,786,149 € Total costs 54,833,538 € BENEFIT-COST RATIO 1.25

As it can be witnessed from Table 5-11 the BC ratio of the proposed RES & Hydrogen power system for Milos island is greater than

unity. This means that from a social perspective the proposed project is a profitable investment. Comparing the outcomes of the financial analysis for the investor, presented in earlier section, with the outcome of the cost-benefit analysis it may be concluded that sometimes there is a considerable divergence between the financial the social profitability indicating conflicts between private and social interests. Moreover, it can be argued from the results of the cost-benefit analysis that the subsidy for the implementation of the proposed power system in Milos is paid back to society because of the project’s ensuing benefits.

5.2.4 Sensitivity analysis A sensitivity analysis has been conducted on a number of parameters that may affect the economic viability of the proposed RES & Hydrogen power system. Table 5-12 includes the parameters that have been varied over a range of values and have caused a large or small variation. The table presents the absolute and relative variation.

Table 5-12 Parameters of sensitivity analysis and their range

Parameter Min. Original Max.

Wind turbine

capital cost

1000 €/kW

1200 €/kW

1500 €/kW

Fuel Cell capital cost

2000 €/kW

3000 €/kW

3000 €/kW

Electrolyser capital cost

1500 €/kW

2000 €/kW

2000 €/kW

Diesel price -20% 0.68 €/L +30% Heavy oil

price -20% 0.34 €/L +30%

CO2 emission trading

allowance

-30% 21 €/t +5%

Fuel cell electricity

price -20% 0.15

€/kWh +20%

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The results of the sensitivity analysis presented in this section include the effect on the cost of energy, NPV, IRR, Payback Period and BCR of the parameters that cause a significant variation.

5.2.4.1 Change in wind turbine capital cost The capital cost of the wind turbine is a parameter that affects considerably the economics of the proposed RES & Hydrogen

power system. As the wind turbine capital cost raises, the cost of energy and Payback Period increase. Moreover, the increase in turbine’s capital cost negatively affects the NPV, IRR and BCR as it can be witnessed in Fig. 5.13-Fig. 5.17. It is worthwhile to mention that for the highest value of the capital cost (1,500 €/kW) the proposed system is not financially viable and the investment is not paid back within the 20-year time horizon.

102104106108110112114116118120122124126

900 1000 1100 1200 1300 1400 1500 1600

Wind turbine capital cost (€/kW)

Cos

t of e

nerg

y (€

/MW

h)

Fig. 5.13 Impact of wind turbine capital cost on cost of energy

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NPV

-1.10E+06-1.00E+059.00E+051.90E+062.90E+063.90E+064.90E+065.90E+066.90E+067.90E+068.90E+06

900 1000 1100 1200 1300 1400 1500 1600


Euro

Fig. 5.14 Impact of wind turbine capital cost on NPV

IRR

0

1

2

3

4

5

6

7

900 1000 1100 1200 1300 1400 1500 1600


%

Fig. 5.15 Impact of wind turbine capital cost on IRR

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Payback Period

10

11

12

13

14

15

16

17

18

19

20

900 1000 1100 1200 1300 1400 1500


Year

s

Fig. 5.16 Impact of wind turbine capital cost on Payback Period

BCR

0

0.5

1

1.5

2

2.5

3

3.5

900 1000 1100 1200 1300 1400 1500 1600

Wind turbine capital cost (€/kWh)

Fig. 5.17 Impact of wind turbine capital cost on BCR

5.2.4.2 Change in heavy oil price Similar behaviour has been recorded for the variation of the heavy oil price. This price is proportional with the cost of energy and thus as the former increases the latter increases as well. It should be noted that although the variation of heavy oil price greatly affects the economics of the proposed system the

variation of diesel price has a minor impact on the results. This may be explained considering that only one diesel generator, which operates only 6 months, runs on diesel while four generators use heavy oil as a fuel. The changes in the economics of the proposed system are shown in Fig. 5.18-Fig.5.21.

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100

102

104

106

108

110

112

114

116

118

120

122

124

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35

Change (%)

Cost

of e

nerg

y (€/M

Wh)

Fig. 5.18 Impact of heavy oil price on cost of energy

NPV

0.00E+00

1.00E+06

2.00E+06

3.00E+06

4.00E+06

5.00E+06

6.00E+06

7.00E+06

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35

Change (%)

Euro

Fig. 5.19 Impact of heavy oil price on NPV

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IRR

0

1

2

3

4

5

6

7

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35

Change (%)

%

Fig. 5.20 Impact of heavy oil price on IRR

Payback Period

10

12

14

16

18

20

22

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35

Change (%)

Year

s

Fig. 5.21 Impact of heavy oil price on Payback Period

5.2.4.3 Change in fuel cell electricity price In the financial analysis, the price the fuel cell-produced electricity is sold was assumed to be 0.15 €/kWh. This price is an assumption that was made based on the electricity prices of other hybrid systems in other Greek islands. As this value has not been known with absolute certainty and also

the energy tariff scheme changes, the impact of the variation of the electricity price over a wide range has been studied. As the electricity price increases the NPV and IRR increase and the Payback Period decreases enhancing the financial viability of the investment. Fig. 5.22-Fig. 5.24 show the results of the fuel cell electricity price variation.

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NPV

0.00E+00

1.00E+06

2.00E+06

3.00E+06

4.00E+06

5.00E+06

6.00E+06

-25 -20 -15 -10 -5 0 5 10 15 20 25

Change (%)

Euro

Fig. 5.22 Impact of fuel cell electricity price on NPV

IRR

0

1

2

3

4

5

6

7

-25 -20 -15 -10 -5 0 5 10 15 20 25

Change (%)

%

Fig. 5.23 Impact of fuel cell electricity price on IRR

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Payback period

16.4

16.6

16.8

17

17.2

17.4

17.6

17.8

18

-25 -20 -15 -10 -5 0 5 10 15 20 25

Change (%)

Year

s

Fig. 5.24 Impact of fuel cell electricity price on Payback Period

5.2.5 Summary In order to increase RES penetration in the Greek island Milos a RES & hydrogen storage power supply system was proposed. The proposed system was examined from an economic, environmental and social perspective. The financial viability of the proposed system was investigated based on the NPV and IRR technique. According to both methods, the investment is not quite profitable as it has 1% IRR, which characterizes the investment financially unviable, and a positive yet small NPV that indicates that the investor would not lose any money but also would not increase greatly his capital. So, the general conclusion that the investment would not return most to the investor can be drawn from both methods. The main reason why the proposed system was characterized financially unviable is the excess electricity produced by the system. Excess electricity is responsible for a 44% reduction in the revenues of the investor. If the excess electricity was significantly smaller the investment would have been

more economically attractive. It is worthwhile to mention that an option to increase the profitability of the investment is to use the excess energy for the production of hydrogen in order to be used locally as a fuel in the transport sector or for heating purposes. However, the proposed system was also examined in terms of its environmental and social implications. A CBA was carried out and the benefits and costs of the proposed system were identified aiming to calculate the net economic impact of the proposed system on the society as a whole. The benefits of the proposed system, such as the creation of new jobs and the reduction of harmful emissions outweighed the costs resulting in a BC ratio greater than unity that indicates that from a social perspective the proposed system is a profitable investment. Thus, although the proposed RES & hydrogen storage power system for Milos is not a profitable investment from the investor’s perspective it shows social profitability as the society would be benefited by its implementation.

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5.3 Case Study 2 – Corvo

5.3.1 Introduction The existing power system of Corvo includes four diesel generators with total capacity of 560kW. The annual electricity demand of Corvo island is approximately 1,084 MWh with peak demand equal to 182 kW. This demand is met by two generators, one of 120 kW capacity and the other of 160 kW capacity. Based on the simulation results, the existing power system delivers electricity at a cost equal to 259 €/MWh. According to the simulation results, the components of the optimum RES & hydrogen-based power system when hydrogen is introduced as an energy storage medium in the power system are depicted in Table 5-25.

Table 5-25: The proposed RES & hydrogen-based power system for Corvo island

Component Type Number Size

Wind Turbine

Fuhrlander 100 2

100 kW

(each)

Thermal Generator

Diesel generator 1

120 kW

(each)

Diesel generator 1

160 kW

(each) Fuel Cell PEM 1 50

kW

Electrolyser Alkaline 1 80 kW

Hydrogen storage tank

Compressed gas 1 200

kg

The cost of energy of the proposed power system decreases to 145 €/MWh. The costs of energy for the existing and the proposed power system have been derived including a 30% subsidy for renewable electricity-generating technologies, a 50% subsidy for hydrogen technologies and a cost of CO2 emission equal to 21 €/t. The analysis presented hereafter includes the financial and economic analysis of the proposed RES & hydrogen-based power system.

5.3.2 Financial analysis As in the case of Milos, the financial viability of the proposed RES & Hydrogen power system for Corvo island was examined using the NPV, the IRR and the payback period method.

5.3.2.1 Investment Costs The investment costs of the proposed power system of Corvo include the initial and replacement costs. These costs are illustrated in Table 5-26.

Table 5-26: The investment costs of the proposed RES & hydrogen-based power system for Corvo island

Technology Type Unit Cost Initial Cost Replacement Cost Wind Turbine Fuhrlander 100 1,500 €/kW 210,000 € 0 €

Thermal Generator DG (120kW) 300 €/kW 36,000 € 7,200 € DG (160kW) 300 €/kW 48,000 € 0 €

Fuel Cell PEM 3,500 €/kW 87,500 € 35,000 € Electrolyser Alkaline 4,000 €/kW 160,000 € 0 €

Hydrogen storage tank Compressed gas 800 €/kg 80,000 € 0 € Total 621,500 €

The initial costs shown in Table 5-26 are calculated by multiplying the unit cost of each technology of Table 5-26 with the

number of necessary units shown in Table 5-25. The initial costs of the wind turbines and the hydrogen technologies are presented reduced, as a subsidy of 30% and 50%

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respectively has been included in the simulation. According to the simulation results, during the 20-year lifetime of the project the 120 kW diesel generator and the fuel cell are replaced. The diesel generator replacement takes place at the 11th year. The fuel cell is replaced twice during the project’s lifetime during the 7th and the 14th year. Table 5-26 presents only the replacement costs of the

equipments that are replaced during the lifetime of the project.

5.3.2.2 Operational Costs The operational costs of the proposed power system are given in Table 5-27. A cost of allowances in the Emission Trading Systems was also included in the O&M costs of the system.

Table 5-27: The operational costs of the proposed RES & hydrogen-based power system for Corvo island

Parameter Type Unit Cost Operational Cost

Wind Turbine Fuhrlander 100 2,000 €/year 4,000 €/year

Thermal Generator DG (120 kW) 1.88 €/hour 8,797 €/year DG (160 kW) 1.88 €/hour 1,564 €/year

Fuel Cell PEM 0.38 €/hour 1,707 €/year Electrolyser Alkaline 6,667 €/year 6,667 €/year

Hydrogen storage tank Compressed gas 200 €/year 200 €/year Fuel Diesel 0.816 €/L 72,644 €/year

Emissions CO2 21 €/t 4,922 €/year Total 100,500 €/year

As it can be witnessed in Table 5-27 a major contribution to the operational cost of the entire system is the cost of the fuels (72%) indicating the advantage of renewable electricity-generating technologies that use fuel of zero cost, such as wind or solar (with exception in the case of biomass). The investment and operational costs of all the necessary components of the proposed RES & Hydrogen-based power system were derived form previous studies carried out by members of the consortium of STORIES project (Zoulias et al., 2007) and from personal communications with equipment manufacturers.

5.3.2.3 Revenues The revenues are derived from the sale of the electricity produced by the proposed power system. The proposed RES & Hydrogen power system is a hybrid system that contains both renewable energy

technologies and conventional technologies. The price at which electricity is sold is different for different electricity-generating technologies because of the feed-in-tariffs. In Portugal, the Decree-Law 189/88 established the legal basis for the feed-in of electricity from independent power producers. According to the revised Decree Law 225/2007, the price of wind-based electricity ranges between 0.26 and 0.54 €/kWh depending on the annual working hours of the park [19]. In this analysis, the average price of 0.4 €/kWh was used. The price of electricity from conventional sources was considered around 0.12 €/kWh [19]. In Portugal, feed-in-tariffs for hybrid systems have not yet been incorporated into the feed-in regulation. For this reason, the price of electricity from the storage system was assumed to be 0.15 €/kWh as in the case of Milos island.

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Generally, the price of electricity escalates every year and thus in the 20-year lifetime of the project a 3% annual increase is considered. In Portugal, the municipality that a wind park is installed receives 2.5% of the revenues of the investor. This percentage

is also included in the analysis. The following Table summarizes the revenues of the proposed RES & Hydrogen-based power system for a 20-year time horizon.

Table 5-28: Revenues of the RES & Hydrogen-based power system Year Technology Electricity consumption Revenues

2 Wind Turbines 664,399 kWh 266,889 € Diesel Generators 315,932 kWh 39,049 € Fuel Cell 104,086 kWh 16,081 €










Total 21,688,340 kWh 8,400,763 € The total amount of electricity consumption and revenues is the sum of the consumption and the revenues of all the years of the project’s lifetime, however due to space reasons only half of the years are presented in Table 5-28. As it can be shown in Table 5-28 the annual electricity consumption is the same for every

year. This is also true for the annual electricity production from all the technologies. Of course, this is not realistic especially in the case of wind energy due to the variability of the wind speed. However, the effect of this simplification on the results due to the linear problem solving approach of HOMER is believed that is not significant and thus this limitation of the approach was accepted. Unlike Milos, the excess

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electricity of the RES & Hydrogen power system of Corvo is small. The surplus electricity is around 153,472 kWh/yr (9.84%).

5.3.2.4 Project Appraisal In this section the financial viability of the proposed RES & Hydrogen power system for Corvo is examined. The first project

appraisal method presented is the NPV method. In order to calculate the NPV it is necessary to use a discounted cash flow. Table 5-29 shows the discounted cash flow for the RES & Hydrogen-based power system.

Table 5-29: NPV of RES & Hydrogen-based power system for Corvo island Year Cash flows Discount factor Present values

0 - 621,500 € 1 - 621,500 € 1 - 100,500 € + 312,640 € 0.943 + 200,048 € 2 - 100,500 € + 322,020 € 0.890 + 197,152 € 3 - 100,500 € + 331,680 € 0.840 + 194,191 € 4 - 100,500 € + 341,631 € 0.792 + 190,975 € 5 - 100,500 € + 351,880 € 0.747 + 187,780 € 6 - 100,500 € + 362,436 € 0.705 + 184,665 € 7 - 135,500 € + 373,309 € 0.665 + 158,143 € 8 - 100,500 € + 384,508 € 0.627 + 178,073 € 9 - 100,500 € + 396,043 € 0.592 + 174,962 €

10 - 100,500 € + 407,925 € 0.558 + 171,543 € 11 - 107,700 € + 420,163 € 0.527 + 164,668 € 12 - 100,500 € + 432,767 € 0.497 + 165,137 € 13 - 100,500 € + 445,750 € 0.469 + 161,922 € 14 - 135,500 € + 459,123 € 0.442 + 143,041 € 15 - 100,500 € + 472,897 € 0.417 + 155,289 € 16 - 100,500 € + 487,084 € 0.394 + 152,313 € 17 - 100,500 € + 501,696 € 0.371 + 148,844 € 18 - 100,500 € + 516,747 € 0.35 + 145,686 € 19 - 100,500 € + 532,249 € 0.331 + 142,909 € 20 - 100,500 € + 548,217 € 0.312 +139,688 €

NPV + 2,735,532 € For the calculations of the NPV a discount rate of 6% has been used. As Table 5-16 shows the project has a positive NPV. According to the NPV decision rules, the positive NPV demonstrates the financial viability of the project. From the investor’s perspective, the proposed RES & Hydrogen power system is a quite profitable investment as on a 621,500 € investment the surplus generated beyond the opportunity cost of the investor is approximately €2,7m. Thus, by implementing the proposed system the investor would increase his wealth by this amount.

The financial viability of the proposed system was also examined by the IRR technique. Table 5-29 shows the NPV for different values of discount rate. The discount rate for which the NPV is equal to zero is the IRR.

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Table 5-29: The relationship between the NPV and the discount rate for the RES &

Hydrogen-based power system

Discount rate NPV 6% 2,735,532 € 10% 1,760,426 € 15% 1,047,613 € 20% 628,066 € 25% 363,138 € 30% 0 €

It can be witnessed in Table 5-29 that the IRR for the proposed RES & Hydrogen-based power system is 30%. According to the IRR decision rules, when the opportunity cost of capital is greater than the IRR on a project then the investor is better not to implement the project, otherwise the project shall be accepted. Thus, under the IRR method the investment is financially viable as it has a very high IRR. In the case of Corvo island, the outcomes of the NPV and IRR method result in the same conclusion. According to the financial analysis results, the proposed RES & Hydrogen power system may be considered as a quite profitable investment. Based on the cash flow analysis the payback period can be derived. The simple payback period is around 3 years. As the analysis includes discounted cash flows, an improvement on the simple payback method that excludes discounted cash flows can be calculated taking into account the time value of money. The discounted payback period based on the present values of Table 5-16 for the RES & Hydrogen-based power system is approximately 3 years and 2 months.

5.3.2.5 Sources of Finance As Corvo island is a European island the aforementioned European sources of finance that were described for Milos island are also valid in the case of Corvo. At a national

level, a source of finance in Portugal specifically for the Azores is the Program Proenergia. Proenergia is a system of incentives for the production of energy from renewable sources and aims to stimulate the use of endogenous resources for the production of energy, mainly for the consumption of the private sector (SME), cooperatives, domestic households. The incentive has an upper limit of 250,000 € for projects promoted by SME, cooperatives and non-profit organizations and 1,000 € for projects promoted by persons or condominiums. For the investments located at Corvo a 35% rate is applied to the eligible project.

5.3.3 Economic results & analysis In this section the proposed RES & Hydrogen power system for Corvo is assessed from the perspective of the national economy and the environment. The environmental and social costs and benefits of the project are presented and the net economic impact on the society as a whole is determined.

5.2.3.1 Environmental and Social Impacts The proposed RES & Hydrogen power system of Corvo resembles in terms of technologies used with the proposed system of Milos. In both systems wind energy was used as a renewable energy source for power generation and hydrogen storage system as an energy storage means. In the aforementioned case study of Milos the environmental and social impacts of the proposed system were described and thus due to space reasons are not presented again in this section.

5.2.3.2 Monetization of Costs and Benefits For the calculation of the BC ratio that indicates the profitability of the proposed RES & Hydrogen power system of Corvo

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from a social point of view all the project’s costs and benefits need to be monetized. The following Table presents the cost of the technologies used in the proposed power system and the work opportunities during the purchase and installation phase of the project. It has been considered that some equipments are imported from abroad and thus the cost of the equipments consists of two components, the domestic and the imported. The subsequent Table shows the percentage of the Portuguese participation for the purchase and installation cost. The imported cost of the

investment has been multiplied by a shadow factor in order to incorporate the principle that it is preferred to utilize local suppliers and domestic expertise than to import goods and services. Table 5-31 shows the operation and maintenance cost the technologies of the RES & Hydrogen power system of Corvo and the ensuing work opportunities during this phase.

Table 5-30 Cost and employment during purchase and installation phase of the RES & Hydrogen power system of Corvo

Technology Cost Portuguese Participation


Wind turbines 210,000€ 5% Engineers 1 365 Technicians 1 730 Operators 1 365 Workers 2 365

Diesel generators 84,000 € 5% Engineers 2 30 Technicians 2 30 Operators 2 30 Workers 2 30

Storage system Engineers 3 60 Electrolyser 160,000 € 2% Technicians 1 90

Hydrogen tank 80,000 € 2% Operators 0 0 Fuel cell 87,500 € 2% Workers 1 30

Total cost 621,500€ Port. participation 6.84% Manyears engineers 2

Manyears technicians 2.41 Manyears operators 1.16 Manyears workers 2.25

Total Employment 7.48 (MY)

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Table 5-31 Cost and employment during operation and maintenance phase of the of the RES & Hydrogen power system of Corvo

Technology Cost Portuguese Participation


Wind turbines 4,000 €/yr 80% Engineers 0 0 Technicians 1 365 Operators 0 0 Workers 0 0

Diesel generators(DG) 10,361 €/yr 70% Engineers 1 365 Technicians 1 365 Operators 1 365 Workers 0 0

Storage system Engineers 1 365 Electrolyser 6,667 €/yr 70% Technicians 2 365

Hydrogen tank 200 €/yr 90% Operators 0 0 Fuel cell (FC) 1,707 €/yr 70% Workers 0 0

Diesel fuel 72,644 €/yr 100% CO2 emissions 4,922 €/yr 100%

FC Replacement cost 35,000 €/yr 40% DG 120kW

Replacement cost 7,200 €/yr 100%

Total cost 100,500 €/yr 7th year 135,500 €

11th year 2,094,147 € 14th year 135,500 €

PV of total cost 1,195,278 € Port. participation 94% Permanent jobs for

engineers 2

Permanent jobs for technicians 4

Permanent jobs for operators 1

Permanents job for workers 0

Total permanent jobs 7 Spin off effect 33%

Total Employment per year 9.31 (MY)

As it can be witnessed in Table 5-31, the impact on the employment has been calculated both for direct and indirect jobs. The creation of new jobs in a given sector may create new indirect jobs in other sectors and regions. Table 5-31 presents the total O&M cost per year. Moreover, since some

technologies are replaced during the lifetime of the project Table 5-31 also presents the total O&M costs of the years that a replacement had taken place. The derivation of the BC ratio has been based in a number of additional parameters. Table 5-32 shows these parameters along with their

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corresponding values. For the social parameters a number of assumptions have been made based on personal communications with members of the consortium of STORIES project.

Table 5-32 Parameters used in the derivation of the BC ratio

Parameter Value Wind energy consumption 664,399 kWh/year

Fuel cell energy consumption 104,086 kWh/year

DG energy consumption 315,932 kWh/year

Price of wind electricity 0.4 €/kWh

Price of fuel cell electricity 0.15 €/kWh

Price of DG electricity 0.12 €/kWh

Price of buying electricity 0.12 €/kWh

Income Tax 24% Average period of

unemployment 12 months

Average unemployment

allowance 550 €/month

Average annual net salary 11700 €/year

VAT 15% Net Gross

Engineer salary 14,400 €/year

19,944 €/year

Technician salary 11,400 €/year

18,789 €/year

Operator salary 11,000 €/year

18,635 €/year

Worker salary 10,800 €/year

18,558 €/year

The benefit from the avoided CO2, SO2, NOx and PM10 emissions caused by the proposed RES & Hydrogen power system are derived by applying the EcoSenceLE tool. Table 5-33 displays the basic inputs, assumptions and the total external benefit from the avoided emissions due to the proposed power system in Corvo.

Table 5-33 Avoided emissions due to the proposed RES & Hydrogen power system in

Corvo island

Corvo proposed power system Avoided Emission values NOx 11,170 kg/year SO2 1,052 kg/year PM10 94.2 kg/year CO2 524,209 kg/year Assumptions

Mortality value 75,000 €/Life Year Lost

Abatement cost per tonne of CO2

19 €/t

Summary Results Human Health Mortality 16010 €/year Human Health Morbidity 8300 €/year Crops 10110 €/year Materials 157.5 €/year CO2 9950 €/year Total External Benefit 44,528 €/year PV of total external benefit 510,727 €

Based on the aforementioned data the BC ratio for the society and the environment has been calculated. Table 5-34 presents the social and environmental costs and benefits in monetary values and the BC ratio.

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Table 5-34 Socio-environmental BC ratio for the RES & Hydrogen power system of

Corvo island

Socio-environmental benefit or cost Monetary value

Benefit from the purchase & installation phase

6,375 €

Benefit from the O&M phase 14,109 €/year

PV of benefit from the O&M phase 167,804 €

Benefit from the creation of new jobs 112,200 €

Benefit from public contributions 250,970 €

Benefit from the operation of the wind park

178,527 €/year

PV of the benefit from the operation of the wind park

96,747 €

Benefit from the production of electricity 130,130 €/year

PV of benefit from the production of electricity 1,492,581 €

Cost of domestic investment 42,500 €

Cost of imported investment 694,787 €

Cost of domestic O&M 94,061 €/year PV of cost of domestic O&M 1,119,533 €

Cost of O&M imported 7,236 €/year PV of cost of O&M imported 86,060 €

Total external benefit 44,528 €/year PV of total external benefit 510,727 €

Total benefits 2,637,403 € Total costs 1,942,880 € BENEFIT-COST RATIO 1.36

As it can be witnessed from Table 5-34 the BC ratio of the proposed RES & Hydrogen power system for Corvo island is greater than

unity. This means that from a social perspective the proposed project is a profitable investment. Comparing the outcomes of the financial analysis for the investor, presented in earlier section, with the outcome of the cost-benefit analysis it may be concluded that the proposed power system for Corvo is a profitable investment both from the investor’s and the society’s perspective. Contrary to the case study of Milos, in Corvo there is a convergence between financial and social profitability showing and alignment of private and social interests. Finally, it may be maintained that the subsidy of the wind and hydrogen technologies of the proposed power system in Corvo is paid back to society because of the project’s ensuing benefits.

5.3.4 Sensitivity analysis A sensitivity analysis has been conducted on a number of parameters that may affect the economic viability of the proposed RES & Hydrogen power system. Table 5-35 includes the parameters that have been varied over a range of values and have caused a large or small variation. The table presents the absolute and relative variation.

Table 5-35 Parameters of sensitivity analysis and their range

Parameter Min. Original Max.

Wind turbine capital cost

1200 €/kW

1500 €/kW

1800 €/kW

Fuel Cell capital cost

2500 €/kW

3500 €/kW

3400 €/kW

Electrolyser capital cost

2000 €/kW

4000 €/kW

3800 €/kW

Diesel price -20% 0.816 €/L +40% CO2 emission trading allowance

-30% 21 €/t +5%

Fuel cell electricity price

-20% 0.15 €/kWh +20%

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The results of the sensitivity analysis presented in this section include the effect on the cost of energy, NPV, IRR, Payback Period and BCR of the parameters that cause a significant variation.

5.3.4.1 Change in wind turbine capital cost The capital cost of the wind turbine is a parameter that affects considerably the economics of the proposed RES & Hydrogen power system. As the wind turbine capital cost raises, the cost of energy and Payback

Period increase. Moreover, the increase in turbine’s capital cost negatively affects the NPV, IRR and BCR as it can be witnessed in Fig. 5.36-Fig. 5.40. It is worthwhile to mention that even for the highest value of the capital cost (1800 €/kW) the proposed system is financially viable and comprises a considerably attractive investment with IRR equal to 28% and payback period around 3.5 years.

141

142

143

144

145

146

147

148

149

1000 1100 1200 1300 1400 1500 1600 1700 1800 1900


Cos

t of e

nerg

y (€

)

Fig. 5.36 Impact of wind turbine capital cost on cost of energy

NPV

2.68E+062.69E+062.70E+062.71E+062.72E+062.73E+062.74E+062.75E+062.76E+062.77E+062.78E+062.79E+06

1000 1100 1200 1300 1400 1500 1600 1700 1800 1900


Euro

Fig. 5.37 Impact of wind turbine capital cost on NPV

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IRR

27

28

29

30

31

32

33

34

1000 1100 1200 1300 1400 1500 1600 1700 1800 1900


%

Fig. 5.38 Impact of wind turbine capital cost on IRR

Payback period

2

2.5

3

3.5

4

4.5

5

5.5

6

1000 1100 1200 1300 1400 1500 1600 1700 1800 1900


Year

s

Fig. 5.39 Impact of wind turbine capital cost on Payback Period

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BCR

0

0.5

1

1.5

2

2.5

3

1100 1200 1300 1400 1500 1600 1700 1800 1900


Fig. 5.40 Impact of wind turbine capital cost on BCR

5.2.4.2 Change in electrolyser capital cost The effect of the electrolyser capital cost on the results is similar to that of the wind turbine capital cost. The increase in the capital cost increases the cost of energy and

the Payback Period and decreases the NPV, IRR and BCR. As it can be witnessed in the following graphs the investment is quite profitable and thus even the maximum value of this variation does not make the project unattractive both from the investor’s and the society’s perspective.

138

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140

141

142

143

144

145

146

147

148

2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000 4200

Electrolyser capital cost (€/kW)

Cos

t of e

nerg

y (€

)

Fig. 5.41 Impact of electrolyser capital cost on cost of energy

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NPV

2.73E+06

2.74E+06

2.75E+06

2.76E+06

2.77E+06

2.78E+06

2.79E+06

2.80E+06

2.81E+06

2.82E+06

2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000


Euro

Fig. 5.42 Impact of electrolyser capital cost on NPV

IRR

2627282930313233343536

2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000


%

Fig. 5.43 Impact of electrolyser capital cost on IRR

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Payback period

2

2.5

3

3.5

4

4.5

5

5.5

6

2000 2200 2400 2600 2800 3000 3200 3400 3600 3800 4000


Year

s

Fig. 5.44 Impact of electrolyser capital cost on Payback Period

BCR

0

0.5

1

1.5

2

2.5

3

1900 2100 2300 2500 2700 2900 3100 3300 3500 3700 3900 4100


Fig. 5.45 Impact of electrolyser capital cost on BCR

5.2.4.3 Change in diesel price The price of diesel fuel is another parameter that affects considerably the results. Naturally, as the fuel becomes more expensive the cost of energy increases. Moreover, the increase in diesel price results

in lower NPV and IRR and higher Payback Period. The changes in the economics of the proposed system are shown in Fig. 5.46-Fig.5.49. From the results of the variations it may be concluded that although the proposed system provides a nearly 80% RES penetration scenario the price of diesel still affects considerably the economics of the

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system. This indicates the importance of the introduction of RES coupled with energy storage especially in communities like the

island of Corvo that are exclusively based on a fuel that its price is highly volatile.

110

120

130

140

150

160

170

180

-20 -15 -10 -5 0 5 10 15 20 25 30 35 40 45

Change (%)

Cos

t of e

nerg

y (€

)

Fig. 5.46 Impact of diesel price on cost of energy

NPV

0.00E+00

5.00E+05

1.00E+06

1.50E+06

2.00E+06

2.50E+06

3.00E+06

3.50E+06

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35 40 45

Change in diesel price (%)

Euro

Fig. 5.47 Impact of diesel price on NPV

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IRR

25

27

29

31

33

35

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35 40 45


%

Fig. 5.48 Impact of diesel price on IRR

Payback period

2

2.5

3

3.5

4

4.5

5

5.5

6

-25 -20 -15 -10 -5 0 5 10 15 20 25 30 35 40 45


Yea

rs

Fig. 5.49 Impact of diesel price on Payback Period

5.2.4.4 Change in fuel cell electricity price In the financial analysis, the price the fuel cell-produced electricity is sold was assumed to be 0.15 €/kWh. As this value has not been known with absolute certainty and also the energy tariff scheme changes, the impact of

the variation of the electricity price over a wide range has been studied. As the electricity price increases the NPV and IRR increase and the Payback Period decreases enhancing the financial viability of the investment. Fig. 5.50-Fig. 5.52 show the results of the fuel cell electricity price variation.

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NPV

2.68E+06

2.70E+06

2.72E+06

2.74E+06

2.76E+06

2.78E+06

2.80E+06

-25 -20 -15 -10 -5 0 5 10 15 20 25

Change (%)

Euro

Fig. 5.50 Impact of fuel cell electricity price on NPV

IRR

26

27

28

29

30

31

32

33

-25 -20 -15 -10 -5 0 5 10 15 20 25

Change (%)

%

Fig. 5.51 Impact of fuel cell electricity price on IRR

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Payback period

2

2.5

3

3.5

4

4.5

5

5.5

6

-25 -20 -15 -10 -5 0 5 10 15 20 25

Change (%)

Yea

rs

Fig. 5.52 Impact of fuel cell electricity price on Payback Period

5.3.5 Summary The introduction of RES and hydrogen as a storage means in Corvo may assist in tackling issues such as fossil fuel import dependency and security of supply. The proposed RES & hydrogen storage power system for Corvo includes the introduction of hydrogen as a storage means and wind energy as an additional electricity production source in order to replace in a great extent conventional fuel. The financial viability and the net economic impact on society of the proposed system were examined. The financial viability of the proposed system was investigated based on the NPV and IRR technique and the results showed that the proposed system is a quite profitable investment. Moreover, a cost-benefit analysis was performed and the results indicated that an 80% penetration of wind energy into the power system of Corvo island coupled with the introduction of hydrogen energy storage is profitable both from the perspective of the investor and the society. Thus, the proposed RES & hydrogen storage power system for Corvo is an attractive proposal that shows private and social interest.

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5.4 General Conclusions for hydrogen storage Hydrogen was examined as a storage means in order to facilitate higher penetration of RES in islands. Two case studies, the Greek island Milos and the Portuguese island Corvo, were examined in order to investigate the financial viability of a proposed RES & hydrogen storage power system from the investor’s perspective and the net economic impact of the proposed system from the society’s perspective. According to the results of the analyses, in both cases the corresponding proposed RES & hydrogen storage system is a profitable investment from the perspective of the society. As the results of the CBA showed, in both cases the benefits of the system outweighed the costs proving a social profitability. It may be also argued that the subsidy for the implementation of the proposed power system is paid back to society because of the

project’s ensuing benefits. From the investor’s point of view, in Milos island the proposed RES & hydrogen power system is not a profitable investment mainly due to the production of a large amount of excess electricity. However, the proposed system may become more economically attractive if the produced excess energy is used to generate hydrogen in order to be used locally as a fuel in the transport sector or for heating purposes. On the contrary, the proposed system for Corvo is a quite profitable investment and thus the RES & hydrogen power system shows private and social interest. In conclusion, the use of hydrogen as a storage means aiming to assist in increasing the penetration of RES in islands may be considered as a socially attractive and profitable solution to tackle issues of particular importance to islands such as fossil fuel import dependency and security of supply.

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6 DESALINATION

6.1 Overview and General Data For the desalination plants co-operating with RES three case studies were simulated Milos, Mljet and Cyprus. The parameters used for the socio-economics analysis are provided in

Table 6-1 while for RES considered the participation of domestic economy is as described in Table 6-2. For desalination plant installation, Table 6-3provides the percentage considered for country participation for the desalination plant. Shadow price is considered 20% while the spin off effect is 33%.

Table 6-1 Description of Socio-economic parameters per country for desalination plant

Island Unemployment allowance (€/month)

Public Health Cost SO2

Public Health Cost NO(€/tn) x

Public Health Cost PM-10(€/tn) (€/tn)

VAT (%)

Taxes (%)

Milos 430.75 2054 1233 2054 19 20 Mljet 490 2054 1233 2054 22 20 Cyprus 667 2054 1233 2054 15 20

Table 6-2 Domestic participation per country for RES and desalination

Island Wind Installation (%)

Wind Operation (%)

PV Installation (%)

PV Operation (%)

Milos 34 93 83 99.5 Mljet 15 96 83 99.5

Table 6-3 Domestic participation for desalination

Country Milos Mljet Cyprus Desalination Installation (%) 42 42 15 Desalination Operation (%) 96 99.5 95

6.2 Case study 1 –Milos For Milos, it is assumed that the owner of the existing wind park is willing to invest on Desalination and RES. The various scenarios studied are: • Addition of one wind turbine -SCE 1

• Addition of one wind turbine +desalination with independent scheduling-SCE 2

• Addition of one wind turbine +desalination with co-operation in scheduling SCE 3

• Addition of desalination plant only-SCE 4

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The additional wind turbine is a Vestas V 52 –850kW like the one of the existing wind turbines installed on the island. Regarding the desalination plant, 4 identical units with total capacity of water production 84m3/h and electrical demand 150kW each, are assumed to be installed. These will co-operate with storage tanks of 3000m3. This plant will meet double of the water transported to the island by boat, with total yearly production 406,000 m3. More details on the algorithm followed for the simulations and the results on the impact on the power system operation are provided in Deliverable D2.1.

6.2.1 Financial Analysis

6.2.1.1 Investment & Operation Costs

The investment cost for the wind turbine is 1200€/kW. This means that the cost for the

wind turbine is 1,020,000€. Taking into account the subsidy by the ”Competitiveness” program, 30%, the investor should have to pay 714,000€. The desalination investment cost is analyzed as presented in Table 6-4. Regarding the desalination plant apart from energy, operational costs comprise chemicals labours etc, as presented in Table 6-5 The owner of the desalination plant is charged according to B1B tariff of the PPC as described in Table 6-6 The energy cost for each of the scenarios cost as well as the final O&M cost is provided in Table 6-7.

Table 6-4: Analysis of the investment cost for the desalination power plant

Base case Cost (€) Multiplier Investment Cost (€)

Desalination Units 117,187.5 2016/300 787,500 Civil works 541,695 2 1,083,390 Total Capital cost 1,870,890

Table 6-5 Analysis of the O&M cost for the desalination power plant

Base case Cost Multiplier Annual O&M cost (€) Chemicals 0.031€/m3 406,000m3 12586 Membranes 13.5€/m3/d 2016 m3/d 27216 O&M labor 9.3€/m3/d 2016 m3/d 18748.8 Total 58550.8

Table 6-6: Power And energy Charge for the owner of the desalination plant.

Power charge 8.4351€/kW

Εnergy Charge

First 400kWh/kW

0.04990€/kWh

Rest kWh 0.03310€/kWh

Table 6-7: Final annual O&M cost for the desalination power plant

Energy Cost (€)

Total O&M cost (€)

Scenario 1 0 0 Scenario 2 173,410.91 231,961.71 Scenario 3 196707.3 255,258.10 Scenario 4 173,410.91 231,961.71

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Regarding wind turbine it is assumed that the annual operational cost is 1.8% of the installation cost of the wind turbine. In this case the owner of the wind turbine will have to pay 18360€/year.

6.2.1.2 Revenues The revenues for the potential investor comes from the water sold to the Municipality of Milos at fixed price of 1.8€/m3. Moreover, the additional wind power sales will bring additional income of 84.6€/MWh to the investor. It should be noted, that even if there is no installation of a wind turbine, increase of the demand leads to reduction of the wind power curtailment, as explicitly described in Deliverable D2.1, and thus to additional income for the owner of the wind park. Table 6-8 summarizes the expected income for each of the scenarios studied, taking also into account the fee paid to the municipality, 3% of the annual income of the energy sold.

Table 6-8: Expected income for the investor per year

Water

income (€)

Wind Income

(€)

Total Income

(€) Scenario 1 0 132,193.7 132193.7 Scenario 2 733,068 158,691.5 891759.5 Scenario 3 731,845.8 176,474.3 908320.1 Scenario 4 733,068 12,957.5 746025.6

6.2.1.3 Project Appraisal The most important parameter is the annual cost flow for the project which in this scenario is given by the equation (1). This amount of money is assumed constant and the same for all the years of the studied period and is provided in Table 6-9. According to this table, the indices described in Table 6.9 have been calculated and are presented in Table 6-10.

Table 6-9: Expected cost for the investor per year

Fi Scenario 1 -130,474.90 Scenario 2 -623,879.33 Scenario 3 -624,262.51 Scenario 4 -472,175.88

Table 6-10: Evaluation indices for the investment

NPV (€) IRR (%)

Pay back

periods (years)

Scenario 1 782,536.8 17.55 6.83 Scenario 2 4,570,957 23.80 4.91 Scenario 3 4,575,352 23.81 4.90 Scenario 4 3,544,930 24.94 4.67

IncomeRESrIncomewateMRESOMDesalOFi −−+= && (1)

6.2.1.4 Sources of Finance The sources of finance can be similar to Hydrogen storage in Chapter 5. Additional funds can be claimed from the municipality of Milos for securing the island water supply. Moreover, as will be examined in the next subsection, the wind park owners will have some benefits from the operation of the

desalination plant. Therefore, they can provide some part of their additional income to finance the desalination plant operation.

6.2.2 Economic results & analysis In this section the impact on the rest of the stakeholders on the island and the society are discussed

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6.2.2.1 Cost of energy The impact for the power system of Milos is explicitly discussed in Deliverable D2.1. A summary on the impact of the fuel cost is presented also here. Since no additional unit is required to meet the demand of the combination of RES and desalination plant, no additional capital cost is foreseen for the operator of the island. Moreover, the rest of the materials used will remain practically intact, because the same personnel is required to make the services to the units etc. A summary of the impact on the operating cost and the cost of energy in terms of fuel cost is provided in Table 6-11.

Table 6-11: Impact in the operating cost of the operator of the island

Fuel Cost (k€)

Estimated Fuel Cost of Energy

(COE)- €ct/kWh

Current situation 2778.9 6.993

Scenario 1 2672.2 6.725 Scenario 2 2925.7 6.86 Scenario 3 2883.3 6.762 Scenario 4 3052.5 7.158

6.2.2.2 Environmental and social impacts

The impact on the emissions of the island compared to current operation is shown in Fig. 6.1. The additional demand of the desalination plant, which is higher than RES production, leads to increase of the emissions. The difference between the studied scenarios is significant, showing that different management of the desalination units can have significant impact on the emissions of the system.

Fig. 6.1 Comparison of the various scenarios with current operation regarding emissions

Till now Municipality of Milos needs water to be transferred at the price of 8€/m3. Table 6-12 summarizes the cost for meeting the water demand. The additional amount of money received as a fee from the owner of the wind park has been added in the same column. It is obvious that Scenarios 2-4 are much profitable for the Municipality for the same amount of water compared to the current situation. The additional income due to RES helps in reducing somewhat the cost for the municipality. The most profitable scenario is Scenario 3

Table 6-12: Cost-Benefit for the Municipality of Milos

Water cost

(€) Total

Cost(€) Current situation 3,248,000 3,248,000

Scenario 1 3,248,000 3,243,911.5 Scenario 2 733,068 728,160.0 Scenario 3 731,845.8 726,387.8 Scenario 4 733,068 732,667.3

Transfer of water via a ship produces some emissions as well which according to OECD are 40g CO2/km-tn. Milos distance from Piraeus is 87n.miles. This means that for each m3 of water transferred 6.445kg CO2 are emitted. For various scenarios of transportation and change ion the emissions of the power systems, Table 6-13. It is obvious that the most “clean” method of production of water for the island is the one of producing water with as close co-operation of the desalination plant as possible with the production from the RES. RES help in reducing the emissions to such an extent, that

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the CO2 emissions are lower when water is transported to the island and one wind turbine is installed, rather than installing a desalination plant without RES units.

Table 6-13: CO2 emissions for the scenarios studied in terms of water produced

CO2 (g/m3)

Current situation 6445 Scenario 1 4488 Scenario 2 2053 Scenario 3 1223 Scenario 4 4898

Fig. 6.2 presents a summary for the rest of the emissions for each m3 of water consumed on the island. Marine transportation when combined with installation of wind turbine

manages only to decrease SO2 emissions. Unless desalination schedule is according to wind power estimations, SO2 emissions will be increased compared to the current situation. This is the only case where the current situation can be more profitable. For the rest of the pollutants the emissions are reduced if water is produced locally via a desalination plant.

Fig. 6.2 Comparison of the rest pollutants for each m3 consumed on the island

6.2.2.2.1 Social Benefits Social benefits come from increasing the employment during the construction phase of the project and during the operational phase plus the impact on public health due to emissions avoidance. Construction phase The employment during the construction phase for each of the scenarios studied is

provided per category and period as described in Table 6-14. Operation: Since there is already a wind park on the island no increased employment due to its operation will be created, especially for Scenario 1. For scenarios 2-4, one operator to be responsible on call for any problems with the desalination plant and frequent travels perhaps from Athens to Milos for any monthly or regular maintenance will be required.

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Table 6-14: Employment matrix for the construction phase per scenario

SC1 SC2 SC3 SC4 Engineers Number 1 4 4 4 Engineers Human-months 3 14 14 12 Technicians Number 3 6 6 4 Technicians Human-months 9 20 20 16 Operators Number 0 0 0 0 Operators Human-months 0 0 0 0 Workers Number 4 12 12 8 Workers Human-months 12 56 56 48 Total Employment (Human months 24 90 90 76

6.2.2.3 Monetization of costs and benefits

Clearly there are two phases, the installation phase and the operation phase. The various costs and benefits during the installation

phase for all the scenarios studied are provided in Table 6-15. The benefits for each year are described in Table 6-16 while the costs are provided in Table 6-17. It should be noted that without RES there is increase in the emissions which creates an additional cost.

Table 6-15: Monetization of benefits during installation phase

SC 1 SC 2 SC 3 SC 4 Installation VAT(€) 193,800 549,269 549,269 355,469 Unemployment installation benefit (€) 10,338 38,768 38,768 32,737

Employment Installation tax (€) 5,828 21,694 21,694 18,309 Investment Domestic cost (€) 346,800 1,562,879 1,562,879 1,216,079 Investment Imported (€) 807,840 1,593,614 1,593,614 785,773 Sum Installation benefits (€) 209,966 609,731 609,731 406,515 Sum Installation Costs (€) 1,154,640 3,156,492 3,156,492 2,001,852

Table 6-16: Analysis of annual benefits per scenario studied-Milos

SC 1 SC 2 SC 3 SC 4 Unemployment benefit (€) 0 6,875 6,875 6,875 Employment TAX (€) 0 2780 2780 2780 O&M VAT(€) 3,488 47,561 51987 44,073 Municipality Benefit (€) 4,089 2,519,840 2,521,612 2,515,333 Emission Social Benefits (€) 34,080 56,702 79,463 0 Sum Annual benefits (€) 41,658 2,633,758 2,662,717 2,569,060

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Table 6-17: Analysis of annual costs per scenario studied-Milos

SC 1 SC 2 SC 3 SC 4 O &M cost (€) 17,074.8 239,758.04 262,122.6 222,683.2 O&M Imported(€) 1,542.24 12,676.402 13,794.63 11,134.16 Emission Social cost (€) 0 0 0 6,911.73

Electricity cost (€) 29,645.14 137,030.57 89,678.3 113,591.7 SUM costs Annual (€) 48,262.18 389,465.012 365,595.5 354,320.9

All the cost and benefits are represented in NPV in Table 6-18, where the Benefit to cost ratio (BCR) for the society is also provided.

Table 6-18: Summary of cost-benefit analysis

Benefits

NPV (x1000€)

Cost NPV

(x1000€) BCR

Scenario 1 687.78 1,708.2 0.403 Scenario 2 30,818.73 7,623.63 4.043 Scenario 3 31,150.9 7,349.84 4.234 Scenario 4 29,873.4 6,065.88 4.925

Clearly, even if only one wind turbine is installed the society does not have significant benefits because water is still transported to the island. For all the other cases the BCR is significant. Scenarios with wind power have slightly lower BCR than the case of adding desalination plant only. The co-operation of wind power and desalination increases the value for the society.

6.2.3 Sensitivity analysis The Parameters than can affect the financial results of the installation and the ranges of different values considered are provided in Table 6-19.

Table 6-19: Parameters of sensitivity Analysis and their range

Water selling price

-10% to +10% with steps 2.5%

Wind power selling price to the grid. Peak charge Energy charge CO2 emissions trading price

-15% -50% with step 5%

Capital cost of the W/T

1000 €/kW-1500€/kW

Cost of Desalination Installation

-10% +10% with steps 2.5%

6.2.3.1 Change in water selling price In this case the economics of Scenario 1 are not affected since no water is sold to the island. Fig. 6.3- Fig. 6.5 show that SCE4 is more affected on this parameter and for 10% decrease in the selling price the IRR and pay back periods are similar for the scenarios with water production. Even in this case the evaluation indices are very favorable. Fig. 6.6 shows the BCR for the scenarios affected for the change considered. Clearly, BCR for SCE4 is a bit more sensitive compared to the other scenarios.

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NPV

10000001500000200000025000003000000350000040000004500000500000055000006000000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

€

SCE2 SCE3 SCE4

Fig. 6.3 Impact of water selling price on Net Present Value

IRR

1012141618202224262830

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

%

SCE2 SCE3 SCE4

Fig. 6.4 Impact of water selling price on IRR

Pay back period

3

3.5

4

4.5

5

5.5

6

6.5

7

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs

SCE2 SCE3 SCE4

Fig. 6.5 Impact of water selling price on Pay Back period

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BCR

3.6

3.9

4.2

4.5

4.8

5.1

5.4

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

SCE2 SCE3 SCE4

Fig. 6.6 Impact of water selling price in Cost Benefit Ratio Another parameter that affects the benefit for the society due to desalination plant is the one of the transportation price of the potable water. Easily can be inferred that the higher this price, the higher the benefit by the installation of the desalination plant. This is

quantified in Fig. 6.7. SCE4, desalination plant only, reduces its value much more rapidly than the other two scenarios engaging desalination.

BCR

0

1

2

3

4

5

6

5 5.5 6 6.5 7 7.5 8 8.5 9

Transportation price(€/m3)SCE 1 SCE2 SCE3 SCE 4

Fig. 6.7 Impact of water transportation price in Cost Benefit Ratio

6.2.3.2 Change in wind power selling price

In this case the economics of Scenario 4 are the least affected since the additional energy sold is limited. Fig. 6.8- Fig. 6.10 show that SCE1 is much more affected by this parameter. If the selling price of wind power

increases, then IRR and pay-back periods for the rest scenarios converge. It should be noted something that is not very apparent from the graphs, that SCE3 is more sensitive on this parameter than SCE2. IRR for SCE3 is lower than for SCE2 if the wind power selling price decreases.

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NPV

5.00E+05

1.00E+06

1.50E+06

2.00E+06

2.50E+06

3.00E+06

3.50E+06

4.00E+06

4.50E+06

5.00E+06

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

€

SCE2 SCE3 SCE4 SCE1

Fig. 6.8 Impact of wind power selling price on Net Present Value

IRR

10.00

12.00

14.00

16.00

18.00

20.00

22.00

24.00

26.00

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

%

SCE2 SCE3 SCE4 Sce1

Fig. 6.9 Impact of wind power selling price on IRR

Pay back period

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs

SCE2 SCE3 SCE4 Sce 1

Fig. 6.10 Impact of wind power selling price on Pay Back period

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6.2.3.3 Change in Peak charge The energy tariff scheme may change. First the impact of the change in the peak charge is studied. As the peak charge is increased from

the base case scenario, SCE3 presents lower IRR compared to SCE2. The change in the evaluation indices is shown in Fig. 6.11-Fig. 6.13.

NPV

3000000

3250000

3500000

3750000

4000000

4250000

4500000

4750000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

€

SCE2 SCE3 SCE4

Fig. 6.11 Impact of Peak charge on Net Present Value-Milos

IRR

22.00

22.50

23.00

23.50

24.00

24.50

25.00

25.50

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

%

SCE2 SCE3 SCE4

Fig. 6.12 Impact of Peak charge on IRR-Milos

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Pay back period

4.4

4.5

4.6

4.7

4.8

4.9

5

5.1

5.2

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs

SCE2 SCE3 SCE4

Fig. 6.13 Impact of Peak charge on Pay Back period-Milos

6.2.3.4 Change in Energy charge Subsequently, the impact of the energy charge change is studied in Fig. 6.14-Fig. 6.16. The impact is greater than the peak charge since the minimum and maximum

value of IRR is by 0.5% higher and 0.5% lower respectively compared with the case of sensitivity analysis of peak charge. SCE 4 is much more sensitive than the other two scenarios.

NPV

2500000

3000000

3500000

4000000

4500000

5000000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

€

SCE2 SCE3 SCE4

Fig. 6.14 Impact of Energy charge on Net Present Value-Milos

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IRR

22.00

22.50

23.00

23.50

24.00

24.50

25.00

25.50

26.00

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

%

SCE2 SCE3 SCE4

Fig. 6.15 Impact of Energy charge on IRR

Pay back period

4

4.2

4.4

4.6

4.8

5

5.2

5.4

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs

SCE2 SCE3 SCE4

Fig. 6.16 Impact of Energy charge on Pay Back period

6.2.3.5 Change in CO2 emission trading prices

In this case more emphasis is given on the event of increasing these prices, the step of change is larger 5%. Only SCE 1 and SCE 4 are depicted since these are more affected. SCE 2 and SCE3 present similar behaviour with SCE4 since their emissions are slightly

decreased. However, the difference among the lowest and the highest value is rather small. It should be noted that the evaluation indices for SCE 3 are more favourable even if the prices of CO2 trading fall by 5%. Fig. 6.17-Fig. 6.19 show the impact on evaluation indices.

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NPV

5.00E+05

1.00E+06

1.50E+06

2.00E+06

2.50E+06

3.00E+06

3.50E+06

4.00E+06

-15 -10 -5 0 5 10 15 20 25 30 35 40 45 50

Change (%)

€

SCE4 SCE1

Fig. 6.17 Impact of CO2 emission trading price on Net Present Value

IRR

10

12

14

16

1820

22

24

26

28

-15 -10 -5 0 5 10 15 20 25 30 35 40 45 50

Change (%)

%

SCE4 Sce1

Fig. 6.18 Impact of CO2 emission trading price on IRR

Pay back period

4

4.5

5

5.5

6

6.5

7

7.5

8

-15 -10 -5 0 5 10 15 20 25 30 35 40 45 50

Change (%)

Yea

rs

SCE4 Sce 1

Fig. 6.19 Impact of CO2 emission trading price on Pay Back period

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6.2.3.6 Installation cost of Wind Turbines

The installation cost of wind turbines is an important parameter which affects Scenarios 1-3 only. The most sensitive scenario is

SCE1 since wind turbine is the only capital cost that should be paid back. Fig. 6.20-Fig. 6.22 show the corresponding results. Fig. 6.23 presents the impact on BCR.

NPV

500000

1000000

1500000

2000000

25000003000000

3500000

4000000

4500000

5000000

1000 1100 1200 1300 1400 1500

Instal lation Cost (€/kW)

€

SCE2 SCE3 SCE1

Fig. 6.20 Impact of wind turbines installation cost on Net Present Value-Milos

IRR

10

12

14

16

18

20

22

24

26

1000 1100 1200 1300 1400 1500Instal lation Cost (€/kW)

%

SCE2 SCE3 SCE1

Fig. 6.21 Impact of wind turbines installation cost on IRR-Milos

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Pay back period

4

5

6

7

8

9

10

1000 1100 1200 1300 1400 1500

Instal lation Cost (€/kW)

Yea

rs

SCE2 SCE3 SCE1

Fig. 6.22 Impact of wind turbines installation cost on Pay Back period-Milos

BCR

00.5

11.5

22.5

33.5

44.5

5

1000 1100 1200 1300 1400 1500

Instal lation cost (€/kW)

SCE 1 SCE2 SCE3

Fig. 6.23 Impact of wind turbines installation cost on BCR-Milos

6.2.3.7 Installation cost of the desalination plant

The installation cost for the desalination plant is a sensitivity parameter for SCE2-4. Mostly affected is the SCE4 since no other

installation cost is foreseen. Both IRR and the pay back period converge with the other two scenarios. Fig. 6.24- Fig. 6.26 present these results. Finally, Fig. 6.27 presents the impact for the society.

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NPV

1000000

1500000

2000000

2500000

3000000

3500000

4000000

4500000

5000000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

€

SCE2 SCE3 SCE4

Fig. 6.24 Impact of Desalination installation cost on Net Present Value-Milos

IRR

14.00

16.00

18.00

20.00

22.00

24.00

26.00

28.00

30.00

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

%

SCE2 SCE3 SCE4

Fig. 6.25 Impact of Desalination installation cost on IRR-Milos

Pay back period

3.00

3.50

4.00

4.50

5.00

5.50

6.00

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs

SCE2 SCE3 SCE4

Fig. 6.26 Impact of Desalination installation cost on Pay Back period-Milos

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BCR

3.6

3.9

4.2

4.5

4.8

5.1

5.4

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

SCE2 SCE3 SCE4

Fig. 6.27 Impact of Desalination installation cost on BCR-Milos

6.2.3.8 Impact of interest rate Change in Interest rate means change in the NPV and the payback period of the investment. An increase of interest rate means decrease of the NPV and increase of the payback time. Fig. 6.28 and Fig. 6.29

show the impact of interest rate for both the NPV and the payback period respectively. The interest rate also affects the cost-benefit ratio because of the different value of the cost and benefits when amortized as shown in Fig. 6.30

NPV

500000

1500000

2500000

3500000

4500000

5500000

6500000

4 5 6 7 8 9

Interest Rate (%)

€

SCE2 SCE3 SCE4 SCE1

Fig. 6.28 Impact of Interest rate on Net Present Value-Milos

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Pay back period

4

4.5

5

5.5

6

6.5

7

7.5

8

4 5 6 7 8 9

Interest Rate (%)

Yea

rs

SCE2 SCE3 SCE4 SCE 1

Fig. 6.29 Impact of Interest rate on Pay Back period-Milos

BCR

0

1

2

3

4

5

6

4 5 6 7 8 9

Interest Rate (%)

SCE 1 SCE2 SCE3 SCE4

Fig. 6.30 Impact of Interest rate on BCR for the society-Milos

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6.2.3.9 Summary of Sensitivity Analysis

Table 6-20: Sensitivity Analysis Matrix per parameter studied

Sensitivity Parameter Most

Sensitive Scenario

Water selling price SCE 4 Wind power selling price SCE 1 Peak Charge SCE 3 Energy Charge SCE 4 CO2 emissions trading prices SCE 4

Wind turbines installation cost SCE1

Desalination installation cost SCE 4

Interest Rate SCE 1

6.2.4 Conclusions from CBA in Milos

All the scenarios studied present satisfactory Project Appraisal indices. Desalination helps so that the Project Appraisal indices (NPV, IRR and pay back periods) of wind power investment only are further improved. Wind power and desalination co-operation mitigate the impact of changing wind power and water selling price and the impact of the installation cost compared to the case of wind power only or desalination plants only. Scheduling of desalination according to wind power estimations helps greatly in reducing the emissions for meeting the water needs without change in the project appraisal indices. All the investments have significant sensitivity on interest rate but mainly the wind power only investment is affected. Regarding the employment during the construction phase, clearly combination of wind and desalination will increase employment. In none of the scenarios however, significant employment will be created due to the existing wind park on the island. The local population will be supplied at much lower prices and with lower emission levels for each m3 of water delivered to them compared to the current practice of transporting water. This is the main reason for the significantly high Benefit to Cost Ratio (BCR) for the society for all the scenarios involving desalination. Both transportation price decrease and water selling increase price from the desalination plant will decrease BCR. The BCR will improve also as much as the desalination plant schedule is closer to wind turbines.

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6.3 Case study 2-Mljet In accordance to the description of Deliverable D 2.1 the two main scenarios for the desalination plants in Croatia have been studied. In Scenario 1 the evaluation has to do with the installation of RES units only in order to meet the demand of the desalination plants. In scenario 2 the Hotel Odissej is assumed to install RES and a desalination plant in order to avoid transporting water. In this case the combination will be evaluated. The energy cost for the considered customers on the island is provided in Table 6-21 and remuneration of RES- wind and PV in our case are summarized in Table 6-22 Table 6-23 presents the considered installation costs

Table 6-21: Energy costs for the customers

Hotel

Odissej and Sobra

Rest small desalination

plants Peak Charge (€/kW) 9.5905 0

Peak hours energy Charge (€ct/kWh)

7.027 10.13514

Off peak hours Charge (€ct/kWh)

3.5135 5.135135

Table 6-22: Remuneration of RES in Croatia

Hotel Odissej and Sobra

Wind power (€ct/kWh) 8.81 10kW<PV (€ct/kWh) 46.81 10kW<PV<30kW (€ct/kWh) 41.3

PV>40kW (€ct/kWh) 28.91

Table 6-23: Analysis of the investment cost for the RES units considered

Unsubsi

dized Unit cost

€/kW

Considered

capacity (kW)

Investment Cost

Wind power 2000 35.6 71,200

PV 7000 73.9 517,300

6.3.1 Scenario 1 In this scenario, the existing desalination plants decide to install RES to meet their own demand. In the first case, wind power, 3 wind turbines of 33kW are assumed to be installed, one for each of the existing desalination plants. The total wind power production is 262.07MWh all on the eastern part of the island. Using HOMER software, the optimal sizing of PV plants to meet the demand of each desalination plant has been made. The installed capacity, the installation slope and the Azimuth Angle for each case is provided in Table 6-24. The total capacity is 95.12kW.

Table 6-24: Characteristics of the PV installations at each Desalination plant

Blato Sobra Kozarica

Installed Capacity (kW) 44.9 40.8 9.42

Installation Slope (South) (o) 36 35 43

Azimuth Angle (o)(West) 12 1 10

6.3.1.1 Financial Analysis The change in the operating cost is due to the significant reduction of electricity bought, the energy sold to the upstream network and the peak reduction. However, due to the intermittence of wind power and in order to

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calculate the minimum benefits due to wind power installation the peak reduction is excluded in the following calculations. Two potential tariff schemes have been investigated, the owner of the desalination to act as an auto-producer, which means that if the total monthly energy bought is negative, i.e. excess of RES electricity, this excess is charged according to Table 6-21.If there is energy bought from the upstream network, this lack of energy is charged according to Table 6-21. The other tariff scheme is the one of the independent producer where the charge for energy is the same and the energy produced by RES is remunerated as Table 6-22 describes. The results from the former case are summarized in Table 6-25 and the latter in Table 6-26 for Wind power. For PV installations the corresponding tables are Table 6-27 and Table 6-28, respectively. Being an auto-producer is generally more profitable for wind power. The total benefits for auto-producers are by 7% higher

compared to the case of independent producer. Only for the owner of the Kozarica power plant is more profitable being an independent producer. For the other two and especially for Sobra, it is more profitable being an auto-producer than an independent producer. Taking into account that the installed capacity remains the same for all the cases, the highest value of wind turbine installation is for the case of Sobra and reaches 291€/kW-year. Regarding PV, it is far more profitable to be an independent producer than an autoproducer, since the remuneration of PV production is significantly higher than the wind power. The value of PV is higher than the wind, above 370€/kW-year and especially for Kozarica, due to much higher remuneration price, the value reaches 720€/kW. Which investment is the most profitable is given in the following subsection.

Table 6-25: Economic Impact of Wind turbine installation as auto-producer

Desalination Plant

Energy purchase charge (before) (€)

Energy purchase charge (€)

Energy sold

income (€)

Total Income (€)

Total Annual

benefit (€) Kozarica 1008.76 0 6313.33 6313.33 7322.09 Blato 5669.03 0 2190.21 2190.21 7859.25 Sobra 7247.794 0 2353.90 2353.90 9601.70 Total 13925.584 0 10857.44 10857.44 24783.04

Table 6-26: Economic Impact of Wind turbine installation as independent producer

Desalination Plant

Energy purchase charge (before)

(€)


Energy sold

income (€)

Total Income (€)

Total Annual

benefit (€) Kozarica 1008.76 1008.76 7696.06 6687.3 7696.06 Blato 5669.03 5669.03 7696.06 2027.03 7696.06 Sobra 7247.794 7247.794 7696.06 448.266 7696.06 Total 13925.584 13925.584 23088.18 9162.596 23088.18

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Table 6-27: Economic Impact of PV installation as autoproducer

Desalination Plant


(€)


Energy sold

income (€)

Total Income (€)

Total Annual benefit (€)

Kozarica 1008.76 0 1405.36 1405.36 2414.12 Blato 5669.03 0 2661.45 2661.45 8330.48 Sobra 7247.794 0 2904.73 2904.73 10152 Total 13925.584 0 6971.54 6971.54 20896.6

Table 6-28: Economic Impact of PV installation as independent producer

Desalination Plant


(€)


Energy sold

income (€)

Total Income (€)

Total Annual benefit (€)

Kozarica 1008.76 1008.76 6791.16 5782.24 6791.16 Blato 5669.03 5669.03 17423.203 11754.043 17423.203 Sobra 7247.794 7247.794 15537.21 8289.42 15537.21 Total 13925.584 13925.584 39751.573 25825.703 39751.573

Table 6-29: The maximum value of PV installation cost in €/kW for 15 years

depreciation time without subsidy

Kozarica Blato Sobra Autoproducer 2262 1653 1752 Independent producer 5418 2296 2238

6.3.1.2 Project Appraisal Table 6-30 presents the various indices for the evaluation of the investment without externalities. It is obvious that under no circumstances can an autoproducer with PV pay back his investment with the interest rate assumed. For this purpose the interest rate at which an autoproducer can pay back his

investment after many many years is provided for this case. For Kozarica the greatest value is the one of being an independent producer with PV due to the low O&M costs compared to wind and the fact that the low capacity PV receives much higher remuneration than higher capacity values. For the other two desalination plants the most profitable investment is installation of wind power as an autoproducer. Investment from Sobra owner in wind power is the most profitable of all the scenarios investment studied. Externalities for CO2 emissions however play a vital role in improving the investment indices in this case, especially for wind power installations, improving pay back time up to 5 years as Table 6-30 provides.

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Table 6-30: Various Depreciation indices with and without externalities Without Externalities With Externalities

NPV(€) IRR (%) Pay

Back (yrs)

NPV(€) IRR (%) Pay Back (yrs)

Kozarica

Wind –autoproducer 4357.53 6.801 17.80 20479.65 9.60 12.78

Wind -Independent 8646.94 7.569 16.09 24769.06 10.30 11.91

PV autoproducer -38823.7 N/A 61 (3%) -36447.85 NaN 66(3.5%)

PV-Independent 11380.6 8.05 15.17 13756.45 8.46 14.46

Blato Wind – autoproducer 10518.7 7.9 15.45 26640.83 10.61 11.57


PV autoproducer -219323 N/A 114 (2.5%) -207,999.2 N/A 60(2.5%)

PV-Independent -115031 0.975 42.21 -103706.36 1.53 61.93

Sobra Wind autoproducer 30504.48 11.231 10.9 46626.59 13.75 8.86


PV autoproducer -169730.9 N/A 88.3

(2.5%) -159,440.6 N/A 87(4%)

PV-Independent -107963 0.786 104 (5.2%) -97672.68 1.35 52.89

6.3.1.3 Economic results & analysis The reduction of the requested energy from the upstream network has as impact reduction in the losses of the network especially for wind that is going to be installed on the eastern part. The impact in the losses and the estimated cost reduction (at 49.16 €/MWh production cost) are provided in Table 6-31. Due to the very low change in the demand

not only for the whole Croatian power system but also for the Mljet power system, the effect on the cost of energy is negligible.

Table 6-31: Impact on the power system Wind

power PV

power Losses Avoidance (MWh) 6.66 3.3

Estimated O&M cost Avoidance (€) 11824.1 5800.08

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6.3.1.3.1 Environmental and social impacts

The impact on the emissions avoided is provided in Table 6-32.

Table 6-32 Impact on emissions -reduction Wind

power PV

power CO2 Avoided (tn) 200.8 99.6 NOx Avoided (kg) 365.41 176.9 SO2 Avoided (kg) 1212.59 600.32 Particulate Avoided (kg) 97.64 48.8

6.3.1.3.1.1 Social Impact Construction phase Here the construction time is only the one for constructing the PVs or the wind turbines and the required human month hours are provided in Table 6-33.

Table 6-33 Employment matrix for the construction phase per scenario

Wind PV Engineers Number 2 1 Engineers Human Months

5 2

Technicians Number 2 2 Technicians Human Months

6 4

Operators Number 0 0 Operators Human Months

0 0

Workers Number 3 2 Workers Human Months

10 4

Total Employment (Human months)

21 10

Operation phase For maintenance, visit from experts from mainland at service fee will provide the necessary quality of service required. Regarding operation for PV is considered zero while for wind turbines a technician on call may be required.

6.3.1.3.2 Monetization of costs and benefits

Clearly there are two phases, the installation phase and the operation phase. The various costs and benefits during the installation phase for all the scenarios studied are provided in Table 6-34.

Table 6-34 Monetization of benefits during installation phase-Mljet

Scenario 1W

Scenario 1PV

Installation VAT(€) 43,560 146,484.8

Unemployment installation benefit (€)

10,290 4,900

Employment Installation tax (€)

5,130 2,500

Investment Domestic cost (€)

19,800 532,672

Investment Imported (€) 213,840 159,801.6

Sum Installation benefits (€) 58,980 153,884.8

Sum Installation Costs (€) 233,640 692,473.6

The benefits for each year are described in Table 6-35 while the costs are provided in Table 6-36. It should be noted that without RES there is increase in the emissions which creates an additional cost. All the cost and benefits are represented in NPV in Table 6-37, where the Benefit to cost ratio (BCR) for the society is also provided.

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Table 6-35 Analysis of annual benefits per scenario studied-Mljet

Scenario 1W

Scenario 1PV

Unemployment benefit (€) 3910.2 0

Employment TAX (€) 870 0

O&M VAT(€) 784.08 11 Municipality Benefit (€) 0 0

Emission Benefits Social (€) 10100 4990

Sum Annual benefits (€) 15664.28 5001

Table 6-36 Analysis of annual costs per scenario studied-Mljet

Scenario 1W

Scenario 1 PV

O &M cost (€) 3385.8 49.5 O&M Imported(€) 213.84 0.6

Emission cost (€) 0 0

Electricity cost (€) 11264.08 33951.57

SUM costs Annual (€) 14863.72 34001.67

Table 6-37 Summary of cost-benefit analysis Benefits

NPV (x1000€)

Cost NPV (x1000€) BCR

Scenario 1W 238.65 404.13 0.591

Scenario 1PV 211.25 1082.47 0.195

Clearly, even if only one wind turbine is installed the society does not have significant benefits because water is still transported to the island.

6.3.1.4 Sensitivity Analysis The parameters than can affect the financial results of the installation and the ranges of different values considered are provided in Table 6-38. Moreover, a new PV tariff scheme is also investigated for Blato and Sobra case study. Table 6-40 summarizes which scenario is more sensitive to the change of parameters.

Table 6-38 Parameters of sensitivity Analysis and their range

Interest Rate 4-9% with step 1% CO2 emissions trading price

15-40€/tn with step 5 €/tn

Capital cost of RES installation

-30% +5% with steps 5%

6.3.1.4.1 Impact of Interest Rate The impact of interest Rate on NPV and payback period for RES installation is shown in Fig. 6.31 and Fig. 6.32, respectively. The impact on BCR is shown in Fig. 6.33 where wind power is installation is more sensitive.

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NPV

-50000

5000100001500020000250003000035000400004500050000

4 5 6 7 8 9

Interest Rate (%)

€

PV_indep Wind Indep Wind Auto

Fig. 6.31 Impact of Interest rate on Net Present Value for Kozarica

Pay back period

8

10

12

14

16

18

20

22

24

4 5 6 7 8 9

Interest Rate (%)

Yea

rs

PV_Indep Wind Auto Wind Indep

Fig. 6.32 Impact of Interest rate on Pay Back period

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BCR

0.1

0.2

0.3

0.4

0.5

0.6

0.7

4 5 6 7 8 9

Interest Rate (%)

SCE 1 W SCE 1 PV

Fig. 6.33 Impact of Interest rate on BCR for wind and PV-Scenario 1-Mljet

6.3.1.4.2 Impact of RES Installation cost

Here, change in the installation cost, mainly decrease, as expected by the technology development of both small wind turbines and PVs is studied and the impact on NPV, IRR and Pay back period for the most representative case is shown in Fig. 6.34-Fig. 6.36.

It should be noted that for the case of Kozarica and auto-producer operation decrease of PV installation cost by 25% brings positive IRR values but the project pay back period exceeds 22 years even with this reduction. If all the cases were finally implemented, then the BCR would be affected mainly for wind power as Fig. 6.37 shows.

NPV

-120000-100000

-80000-60000-40000-20000

020000400006000080000

-30 -25 -20 -15 -10 -5 0 5

Change (%)

€

PV_kozarica Wind Indep Sobra Autoproducer Sobra PV

Fig. 6.34 Impact of Installation cost on Net Present Value –Mljet Scenario 1

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IRR

0

5

10

15

20

-30 -25 -20 -15 -10 -5 0 5

Change (%)

%


Fig. 6.35 Impact of Installation cost on IRR –Mljet-Scenario 1

Pay back period

4

6

8

10

12

14

16

18

-30 -25 -20 -15 -10 -5 0 5

Change (%)

Yea

rs

PV_kozarica Wind Indep Sobra Autoproducer

Fig. 6.36 Impact of Installation cost on Pay Back period

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BCR

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

-40 -35 -30 -25 -20 -15 -10 -5 0 5

Change (%)

Sc1PV Sc1W

Fig. 6.37 Impact of Installation cost on Pay Back period

6.3.1.4.3 Impact of CO2 emissions trading price

The impact of CO2 emissions trading price is studied next for various prices other than the base of 21 €/tn. The results are presented in Fig. 6.38-Fig. 6.40. PV evaluation indices are less affected than the ones for wind due to lower emissions avoided especially for the Kozarica case with the smallest PV

installation. Unlike installation cost for PVs, doubling the emissions trading price does not affect significantly the evaluation indices. Payback period is significantly high and practically the investment needs lower investment rate so that can be paid back at more reasonable project lifetime periods. That’s the reason for not depicting “SobraPV” series in Fig. 6.40.

NPV

-105000-90000-75000-60000-45000-30000-15000

01500030000450006000075000

15 20 21 25 30 35 40

Price CO2(€/tn)

€


Fig. 6.38 Impact of CO2 emissions trading price on Net Present Value

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IRR

0

3

6

9

12

15

18

15 20 21 25 30 35 40

Price CO2(€/tn)

%


Fig. 6.39 Impact of CO2 Emissions trading price on IRR

Pay back period

6

8

10

12

14

16

15 20 21 25 30 35 40

Price CO2(€/tn)

Yea

rs

PV_kozarica Wind Indep Sobra Autoproducer

Fig. 6.40 Impact of CO2 emissions trading price on Pay Back period

6.3.1.4.4 Impact of PV prices From the previous analysis it is clear that the PV installation for Kozarica is much more profitable than the other PV to be installed on the rest desalination plants. A significant cause is the much higher price of remuneration according to Table 6-22, almost 0.2€/kWh. Unfortunately, the owners of the other desalination plant do not have much higher installed capacity than 30kW, which would provide them around 13€ct higher price. Therefore, they do not have incentive to meet all their demand via PV. In order to

give them an incentive we assume that the feed-in tariff for such a case is given by a simple formula like (2), at least till the PV installation prices are reduced by 30%.

CapFIT

CapFITFIT

bCapbcb

)( 22 −⋅+⋅=

(2)

In this case if b and c are two successive ranges of installation capacity according to Table 6-22.Cap is the installed capacity and b2 is the upper limit of capacity for applying the previous Feed In Tariff (FIT) scheme, then this linear regressions formula would give the

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new fixed FIT price for the PV owner. Thus, the largest the PV, the lower the remuneration. If (2) is applied for Blato and Sobra the feed-in tariffs are 37.18 and 38.02 €ct/kWh respectively. The evaluation indices in such a case are provided in Table 6-39. In this case the pay back time for autoproducers is much more reasonable and the IRR may not be very satisfactory but is much higher than the previous case. The only competent case from the ones in the sensitivity analysis and PV installation is the one of reducing the installation cost by more than 25%.

Table 6-39 Changing Feed In Tariffs for Higher capacity installations

NPV(€) IRR(%)

Pay Back (yrs)

Blato PV autoproducer -196060 NaN 116

(3.5%) PV-Independent -46539.3 4.11 28.30

Sobra PV autoproducer -141563 NaN 49(4%)

PV-Independent -41515.8 4.14 28.08

Table 6-40 Sensitivity Analysis Matrix per parameter studied for Scenario 1

Sensitivity parameter

Most sensitive scenario

Interest rate PV Independent Installation cost PV Autoproducer CO2 emissions trading price

Wind power Independent

PV selling prices PV scenarios

mainly autoproducer

6.3.2 Scenario 2 In this scenario, the combination of RES and desalination plant are evaluated. Namely these sub-scenarios are: • Adding only a desalination plant (Sc2)

• Adding wind power with capacity 35.6kW which operates independently from the desalination plant. (Sc2aW)

• Wind power production helps in determining the desalination plant schedule. (Sc2bW)

• Adding 73.9kW PV which operates independently from the desalination plant (Sc2aPV).

• PV production helps in determining the desalination plant schedule (Sc2bPV).

6.3.2.1 Financial Analysis

6.3.2.1.1 Investment Costs The desalination investment cost is analysed as presented in Table 6-41 Regarding the RES units, the cost for wind power is significantly higher than the larger wind turbine used in Milos due to the generally higher cost of small wind turbines. A summary is provided in Table 6-23.

6.3.2.1.2 Operational Costs

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Regarding the desalination plant apart from energy, operational costs comprise chemicals

labours etc, as presented in Table 6-42

Table 6-41 Analysis of the investment cost for the desalination power plant Base case Cost(€) Multiplier Investment Cost

(€) Desalination Units 117,187.5 310.6/300 121,359.37 Civil works 541,695 1.05 568,779.75 Total Capital cost 690,139

Table 6-42 Analysis of the O&M cost for the desalination power plant Base case Cost Multiplier Annual O&M cost (€)

Chemicals 0.031€/m3 22015m3 682.47 Membranes 13.5€/m3/d 310.6 m3/d 4194.18 O&m labor 9.3€/m3/d 310.6 m3/d 2889.32 Total 7765.97

The O&M cost for the wind turbines is assumed again 1.8% of the installation cost, i.e. 1280€ and for PVs is considered 50€. The charge of energy is assumed the same with Table 6-21 while RES production is remunerated at the prices of Table 6-22. According to the Croatian tariffs, the most profitable scenario for the owner of the hotel is to have one common bill for the hotel and the desalination system and act as an independent produced for the production of the Renewable Energy Sources. Since, the demand of the hotel is much higher than the production of the PV, the hotel owner has to pay money to the distribution company. Table 6-43 summarizes the operational cost for the hotel. In the do nothing scenario the owner of the hotel should also pay money for transporting water. This cost is 4.1€/m3 which leads to cost of about 90,300€.

Table 6-43 Expected cost for the investor for energy

Energy cost (€)

Do nothing Scenario 60172.15 Scenario 2-No RES 66424.56 Scenario 2-Wind without co-operation 58047.13

Scenario 2-Wind turbine with co-operation 60055.69

Scenario 2-PV without co-operation 37717.24

Scenario 2- PV with co-operation 40884.18

6.3.2.1.3 Revenues Since the water is consumed on site, there is no sell of water to anyone else other than the Hotel. The revenue, if any, comes from the reduction in water cost and the increase, if any, in the energy cost. The cost before the installation of desalination is provided by (3) while after the installation the cost is provided by (4). If the quantity in (3) is higher than (4) the investment may be profitable as explained in Project Appraisal. Table 6-44 presents a summary for the annual expected benefit for the hotel Odissej. In the following subsection it is examined

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whether such an investment may be beneficial.

Table 6-44 Expected annual benefit for the Hotel Odissej

Annual benefit(€)

Scenario 2-No RES 74,619.13 Scenario 2-Wind without co-operation 83,241.63

Scenario 2-Wind turbine with co-operation 81,252.01

Scenario 2-PV without co-operation 104,813.8

Scenario 2- PV with co-operation 101,669.9

bWaterCostbEnergyCost __ + (3)

tCORESMOdesalMOaEnergyCost cos__&_&_ 2+++ (4)

6.3.2.1.4 Project Appraisal Based on the expected annual benefits for the various scenarios studied presented in Table 6-44, and the installation costs described in section 6.1, the various depreciation indices can be calculated.

Table 6-45 Various Depreciation indices NPV IRR Payback

periods NO RES 165,736 8.82 13.89 Wind W/O Co-operation

193,436 8.97 13.66

Wind with Co-operation

170,615 8.64 14.18

PV W/O Co-operation

-5,233 5.95 20.17

PV with Co-operation

-41,292.

9 5.58 21.40

6.3.2.1.5 Sources of Finance As in the previous cases, bank loan can be used as part of the capital required. Moreover, subsidies from Croatian Government or other International institutions can be sought for. Part of the income for RES production can be used for the payback of the investment since IRR is relatively satisfactory.

6.3.2.3 Economic results & analysis Fig. 6.41 presents a summary of the results for the Croatian power system for the various sub-scenarios studied. Due to the very low change in the demand not only for the whole Croatian power system but also for the Mljet power system, the effect on the cost of energy is negligible. The increase in the annual operational cost is provided in Table 6-46. Table 6-46 Change in the operational cost of the Croatian Power system NO RES 4900.23€

No Co-operation

With co-operation

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Wind power 42.56€ 46.08€ PV -85.81€ -21.87€

Fig. 6.41 Summary of the Impact on the Mljet part of the Croatian power system for various sub-scenarios studied.

6.3.2.3.1 Environmental and social impacts

The impact on the emissions is provided in Table 6-47. The emissions are increased due to the slight increase in the demand, the change in the operational losses and the change in the demand pattern of the demand from Croatia mainland. The emissions for producing 1 m3 of potable water are compared for the various scenarios in Fig. 6.42 and the emissions for transporting by ship for 10 nautical miles from Croatia. RES have already helped so that the emissions for each m3 produced are significantly decreased Moreover, Fig. 6.43 summarizes the value of each kWh produced by RES for each one of the scenarios studied. Clearly scenarios which promote co-operation of RES and desalination increase the value of RES production in terms of emissions avoidance.

Table 6-47 Increase on the emissions of the Croatian power system CO2

(tn) NOx (kg)

SO2 (kg)

PM –10

(kg) NO RES 79.17 140.9 550.1 44.16 Wind W/O Co-operation

6.54 9.56 115.2 9.04

Wind with Co-operation

5.64 5.84 105.9 8.53

PV W/O Co-operation

5.96 10.5 121.2 9.25

PV with Co-operation

4.86 5.21 102.1 8.13

Table 6-48 presents the total change in the emissions for Croatia when both transportation avoidance and change in electricity demand are taken into account. RES can help so that potable water is provided the hotel reducing CO2 and NOX emissions of the upstream network compared to current practice

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0400800

12001600200024002800320036004000

SC2 Sc 2aW Sc 2bW Sc2aPV Sc2bPV Transport

CO

2 em

issi

ons

(g/m

3 )

Fig. 6.42 Summary of the emissions for each m3 produced, compared also with current practice of water transportation

725

730

735

740

745

750

755

760

Sc 1W Sc1PV Sc 2aW Sc 2bW Sc2aPV Sc2bPV

CO

2 av

oida

nce

(kg/

MW

h)

Fig. 6.43 Summary of the value of each produced kWh by RES for all the scenarios studied for Mljet

Table 6-48 Total emissions avoidance for Croatia when both transportation and power system impact are taken into account

CO2 (tn) NOx (kg) SO2 (kg) PM -10(kg) NO RES -79.06 -140.85 -550.12 -37.56 Wind W/O Co-operation 2.262 100.52 -104.20 -2.43 Wind with Co-operation 3.164 104.24 -94.91 -1.93 PV W/O Co-operation 2.848 99.58 -110.22 -2.65 PV with Co-operation 3.946 104.87 -91.06 -1.53

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6.3.2.3.1.1 Social Analysis Construction phase There is no difference in the construction face for the cases with and without co-operation. Therefore 3 sub-scenarios are studied for this scenario, Sc2 (without RES) Sc2W and SC2PV. The employment created is shown in Table 6-49..Clearly RES installation can take place in parallel with the desalination plant installation and PV requires lower human resources. Operation phase Perhaps the technicians existing on the hotel can help in minimizing the labour cost. Perhaps hiring one operator for the summer months would help in this operation. So the employment months can be 10 months/year. For maintenance, visit from experts from mainland at service fee will provide the necessary quality of service required.

6.3.2.3.2 Monetization of costs and benefits

Clearly there are two phases, the installation phase and the operation phase. The various costs and benefits during the installation phase for all the scenarios studied are provided in Table 6-50. The benefits for each year are described in Table 6-51 while the costs are provided in Table 6-52. It should be noted that the owner of the combination of Desalination plant and PV has income in O&M instead of cost because of the tariff scheme which is higher than the cost for running the desalination plant and buying electricity from the grid. However, in the VAT calculations the remuneration of RES is neglected since the state due to separate bills will receive VAT from electricity sold to the client. The most favorable is the scenario with wind power than adding desalination plant only.

Table 6-49 Employment matrix for the construction phase per scenario Sc 2 Sc2W Sc2PV Engineers Number 2 3 3 Engineers Human Months 3 5 4 Technicians Number 2 2 2 Technicians Human Months 4 6 5 Operators Number 0 0 0 Operators Human Months 0 0 0 Workers Number 3 5 4 Workers Human Months 6 10 7 Total Employment (Human months) 13 21 16

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Table 6-50 Monetization of benefits during installation phase

Scenario 2

Scenario 2aW

Scenario 2bW

Scenario 2aPV

Scenario 2bPV

Installation VAT(€) 151830.6 167494.6 167494.6 265636.6 265636.6 Unemployment installation benefit (€) 6370 10290 10290 7840 7840

Employment Installation tax (€) 4740 7660 7660 6000 6000

Investment Domestic cost (€) 289858.38 300538.4 300538.4 719217.4 719217.4

Investment Imported (€) 480336.7 552960.7 552960.7 585865.9 585865.9 Sum Installation benefits (€) 162,940.6 185,444.6 185,444.6 279,476.6 279,476.6

Sum Installation Costs (€) 770195.1 853499.1 853499.1 1305083.3 1305083.3

Table 6-51 Analysis of annual benefits per scenario studied-Mljet Scenario

2 Scenario

2aW Scenario

2bW Scenario

2aPV Scenario

2bPV Unemployment benefit (€) 3128.16 4692.24 4692.24 3206.36 3206.36 Employment TAX (€) 960 1440 1440 984 984 O&M VAT(€) 3084.04 1990.11 1990.1134 1719.51 1719.51 Electricity Benefits (€) 1352.18 0 0 0 0 Emission benefits (€) 0 733 735 783 745 Sum Annual benefits (€) 8524.38 8855.35 8857.35 6692.88 6654.88

Table 6-52 Analysis of annual costs per scenario studied-Mljet Scenario 2 Scenario

2aW Scenario

2bW Scenario

2aPV Scenario

2bPV O &M cost (€) 14018.38 6869.7496 6869.7496 -14639.193 -14639.193 O&M Imported(€) 0 61.44 61.44 0.3 0.3 Emission cost (€) 4180 0 0 0 0 Electricity cost (€) 0 2167.5804 2171.1 22369.1 22433.04 SUM costs Annual (€) 18198.38 9098.77 9102.29 7730.21 7794.15

All the cost and benefits for the society are represented in NPV in Table 6-53, where the Benefit to cost ratio (BCR) is also provided. None of the scenarios is profitable for the society since BCR is below 1.

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Table 6-53 Summary of cost-benefit analysis-Scenario 2-Mljet

Benefits NPV

(x1000€)

Cost NPV

(x1000€) BCR

Scenario 2 260.715 978.929 0.266 Scenario 2aW 287.015 957.861 0.300

Scenario 2bW 287.038 957.902 0.300

Scenario 2aPV 356.243 1393.748 0.256

Scenario 2bPV 355.808 1394.482 0.255

6.3.2.4 Sensitivity Analysis The Parameters than can affect the financial results of the installation and the ranges of different values considered are provided in Table 6-54. Moreover, a new PV tariff scheme is also investigated for Blato and Sobra case study. summarizes which scenario is more sensitive to the change of parameters.

Table 6-54 Parameters of sensitivity Analysis and their range

Interest Rate 4-9% with step 1% CO2 emissions trading price

15-40€/tn with step 5 €/tn

Capital cost of RES installation

-40 to 5% with steps 5%

Energy prices -10% to +10% with steps 2.5%

Water Transfer Price to the Hotel -5% +15% with

steps 2.5% Capital cost of Desalination installation

6.3.2.4.1 Impact of Interest Rate Fig. 6.44 and Fig. 6.45 show respectively the impact of interest rate on NPV and the pay back period. Wind power performs much better than PV for all the cases. The PV investment cannot be paid back for interest rate higher than 6% within the lifetime. Moreover, above 8% the investment cannot be paid back at all. Co-operation in the scheduling of the desalination plant with the estimations of wind power have higher NPV than the Desalination plant without RES for interest rate lower than 6%. Impact on BCR is shown in Fig. 6.46.

NPV

-300000-250000-200000-150000-100000-50000

050000

100000150000200000250000300000350000400000

4 5 6 7 8 9

Interest Rate (%)

€

Sc2 Sc2aW SC2bW SC2aPV SC2bPV

Fig. 6.44 Impact of Interest rate on Net Present Value

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Pay back period

8

12

16

20

24

28

32

36

40

4 5 6 7 8 9

Interest Rate (%)

Yea

rs


Fig. 6.45 Impact of Interest rate on Pay back Period

BCR

0.24

0.250.26

0.270.28

0.29

0.30.31

0.32

4 5 6 7 8 9

Interest Rate (%)SC2 SC2aW Sc2bW SC2aPV Sc2bPV

Fig. 6.46 Impact of Interest rate on BCR

6.3.2.4.2 Impact of CO2 emission trading price

This impact is significantly lower than for the case of Scenario 1. The highest emissions value is for the scenario without RES (Sc2) whose NPV and IRR are reduced as this price gets higher. Then clearly investment on wind power either with or without co-operation with the scheduling of the desalination plant becomes more profitable. Fig. 6.47-Fig. 6.49 depict this difference.

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NPV

-60000-40000-20000

020000400006000080000

100000120000140000160000180000200000

15 20 21 25 30 35 40

Prices CO2 (E/tn)

€


Fig. 6.47 Impact of CO2 emissions trading price on NPV

IRR

55.5

66.5

77.5

88.5

99.5

15 20 21 25 30 35 40

Change (%)

%

Sc2 Sc2aW SC2bW SC2bPV SC2aPV

Fig. 6.48 Impact of CO2 emissions trading price on IRR

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Pay back period

1213141516171819202122

15 20 21 25 30 35 40

Prices CO2 (E/tn)

Yea

rs


Fig. 6.49 Impact of CO2 emissions trading price on Pay back Period

6.3.2.4.3 Impact of water transfer price

The value at which the hotel buys water is a crucial parameter on the investment analysis. Increase in water price, means that the

proposed solution becomes more attractive. How much more attractive is shown in Fig. 6.50-Fig. 6.52. With slight increase in the water cost, less than 5%, investment on PV becomes also profitable.

NPV

-100000

-50000

0

50000

100000

150000

200000

250000

300000

350000

-5 -2.5 0 2.5 5 7.5 10 12.5 15

Change(%)

€


Fig. 6.50 Impact of water transfer price on NPV

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Pay back period

8

10

12

14

16

18

20

22

24

-5 -2.5 0 2.5 5 7.5 10 12.5 15

Change (%)

Yea

rs


Fig. 6.51 Impact of water transfer price on Pay back Period

IRR

5

6

7

8

9

10

11

12

-5 -2.5 0 2.5 5 7.5 10 12.5 15

Change (%)

%


Fig. 6.52 Impact of water transfer price on IRR

6.3.2.4.4 Impact of Desalination Installation cost

The desalination installation cost affects more the scenario with desalination only without any RES. Adding RES the additional capital cost, especially for PV, alleviates the change of the desalination installation cost. Clearly as the desalination plant cost becomes lower the more profitable the

investment becomes. If the desalination cost decreases below the assumed value then PV also becomes profitable. As the desalination cost becomes higher, co-operation with wind, reduces the impact on NPV and IRR. Fig. 6.53-Fig. 6.55 present these results. The BCR is not affected drastically by this change. The scenarios with PV are the least affected as Fig. 6.56 shows.

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NPV

-150000

-100000

-50000

0

50000

100000

150000

200000

250000

300000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change(%)

€


Fig. 6.53 Impact of desalination installation cost on NPV

Pay back period

10

12

14

16

18

20

22

24

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs


Fig. 6.54 Impact of desalination installation cost on Pay back period

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IRR

4

5

6

7

8

9

10

11

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

%


Fig. 6.55 Impact of desalination installation cost on IRR

BCR

0.240.250.260.270.280.29

0.30.310.32

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10Change (%)

sce2 Sc2aW Sc2bW Sc2aPV Sc2bPV

Fig. 6.56 Impact of desalination installation cost on BCR-Scenario 2 Mljet

6.3.2.4.5 Impact of RES Installation cost

In this case SC2 remains intact but is kept in the graphs for comparisons. The trend of increasing significantly the NPV for the scenarios with PV was the motivation for analyzing cases with 40% reduction in the installation cost. In such a case PV combinations present higher NPV than

Desalination plant only as Fig. 6.57 shows. The PV for 40% reduction in the installation cost becomes competitive with wind power taking advantage of the higher correlation of the solar resource with the load compared to wind. BCR for the society however, depicted in Fig. 6.60, is slightly modified by the installation cost.

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NPV

-90000-60000-30000

0300006000090000

120000150000180000210000240000

-40 -35 -30 -25 -20 -15 -10 -5 0 5

Change(%)

€


Fig. 6.57 Impact of RES installation cost on NPV-Mljet However, the rest evaluation indices IRR and pay back period shown in Fig. 6.58 and Fig. 6.59 respectively, competitive though for PVs, are not as impressive as NPV. From all

these graphs is apparent that PV installation cost is a very sensitive parameter in the viability of the investment.

IRR

4

5

6

7

8

9

10

11

-40 -35 -30 -25 -20 -15 -10 -5 0 5Change (%)

%


Fig. 6.58 Impact of RES installation cost on IRR-Mljet

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Pay back period

10

12

14

16

18

20

22

24

-40 -35 -30 -25 -20 -15 -10 -5 0 5

Change (%)

Yea

rs


Fig. 6.59 Impact of RES installation cost on Payback period-Mljet

BCR

0.24

0.25

0.26

0.27

0.28

0.29

0.3

0.31

-40 -35 -30 -25 -20 -15 -10 -5 0 5

Change (%)

Sc2aPV Sc2aW Sc2bW Sc2bPV

Fig. 6.60 Impact of RES installation cost on BCR

6.3.2.4.6 Impact of RES Prices If formula (2) is applied for the specific case, the suggest value is 33.93 €ct/kWh, slightly less than 15% higher. For reasons of simplicity common sensitivity analysis for RES prices is performed. As in the case of RES installation, the values depicted in Fig. 6.61-Fig. 6.63 show that the evaluation indices are much more sensitive to PV, here prices. The suggested price according to formula (2) corresponds to the

15% of these graphs are summarized in Table 6-55. Clearly the investment can be timely paid back within the project lifetime.

Table 6-55 Changing Feed In Tariffs for Higher capacity installations

NPV(€) IRR(%)

Pay Back (yrs)

Sc2aPV 44157.77 6.45 18.71 Sc2bPV 8097.572 6.08 19.75

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Even with lower increase, around 6% in the PV price, the investment can be paid back within 20 years when there is the desalination

schedule and the PV are considered independent.

NPV

-60000

-30000

0

30000

60000

90000

120000

150000

180000

210000

-3 0 3 6 9 12 15

Change(%)

€


Fig. 6.61 Impact of RES price on NPV-Mljet

Pay back period

12

14

16

18

20

22

24

-3 0 3 6 9 12 15

Change (%)

Yea

rs


Fig. 6.62 Impact of RES prices on Payback period-Mljet

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IRR

55.5

66.5

77.5

88.5

99.5

-3 0 3 6 9 12 15Change (%)

%


Fig. 6.63 Impact of RES Prices on IRR-Mljet

6.3.2.4.7 Impact of Energy Prices The results for PVs are not very optimistic. Reducing solely the energy prices is not enough for the PV scenarios to be more profitable. It requires 7.5% reduction in the energy prices as Fig. 6.64-Fig. 6.66 show so that the PV without co-operation with the

desalination plant to manage to be paid timely back. More affected by the change of the energy prices are the scenarios with desalination co-operation and the scenario without RES due top higher exchange with the grid. If any other tariff scheme can be applied in favour of the investor due to energy prices change is an issue described in more detail in Task 3.3.

NPV

-60000

-30000

0

30000

60000

90000

120000

150000

180000

210000

-7.5 -5 -2.5 0 2.5 5 7.5 10

Change(%)

€


Fig. 6.64 Impact of Energy prices on NPV-Mljet

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Pay back period

12

14

16

18

20

22

24

-7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)

Yea

rs


Fig. 6.65 Impact of Energy prices on Payback period-Mljet

IRR

55.5

66.5

77.5

88.5

99.5

-7.5 -5 -2.5 0 2.5 5 7.5 10Change (%)

%


Fig. 6.66 Impact of Energy Prices on IRR-Mljet

6.3.2.4.8 Summary of Sensitivity Analysis

Table 6-56 presents a summary of the sensitivity analysis. More often the scenarios with PVs are more affected by the change of the parameters studied.

Table 6-56 Sensitivity Analysis Matrix per parameter studied

Sensitivity parameter

Most sensitive scenario

Interest rate Sc2bPV CO2 emissions trading price Sc2

Water transfer price SC2PV Desalination installation cost SC2

RES installation cost Sc2aPV, Sc2bPV RES prices Sc2aPV, Sc2bPV Energy prices Sc2aPV, Sc2bPV

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6.3.3 Summary of the analysis for Mljet

Two main groups of scenarios were studied for Mljet. The first one studying the impact of simply adding RES on the network meeting the needs of the existing desalination plants and the other group installation of desalination plant along with RES at a major consumer of water and power on Hotel Odissej. Installation of wind power is more profitable if the owner is an auto-producer rather than an independent producer, especially when consumption is comparable with the wind power production. If there is significant amount of excess energy, like the case of Kozarica, then being an independent producer is more profitable. No matter whether the owner is an auto-producer or an independent producer, the project appraisal indices are satisfactory. For PVs it is clearly more profitable to be an independent producer due to the relatively high feed in tariff, otherwise the investment would not be able to be paid back. Unsatisfactory IRR are recorded for all the cases studied expect for the small installation for Kozarica. The main reason is the significantly lower feed-in tariff price for installations above 30kW, although the simulated scenarios are not significantly higher than this value. The proposed here tariff scheme is more fair for not much higher capacity than 30kW PV and can help in more acceptable, though not very high, IRR levels. Clearly wind power is a much more profitable as investment than PVs for the island. Reduction of installation price either by subsidy or by reduction of prices for PV installations will make PVs more competitive. Even though, RES capacity

considered is small, the impact of wind power value for the same installed capacity is higher for both the losses and the emissions reduction. Therefore, a reconsideration of forbidding wind power installations on Croatian islands should be considered again. Using small wind turbines and carefully sited with techniques that use Geographical Information Systems (GIS) can help in sitting wind power on these islands in compliance with the restrictions that should be set for this purpose and not simply by forbidding it. The other group of scenarios included addition of a desalination plant for the Hotel Odissej, either with or without RES. It was examined also the case where the desalination plant schedule was based on the RES estimations. There was not difference in the project appraisal indices that would justify such an operation and the additional socio-environmental benefits were limited. Installation of both desalination plant and wind power present satisfactory project appraisal indices while for PV the investment can be marginally paid back within the life time of the project. The indices are however much better than the ones for the smaller desalination plants studied in Scenario 1. Water transfer price is the crucial parameter for the viability of the investment and slight increase has significant impact of the viability of PV and Desalination combination. Interest rate and Installation price are other important parameters which affect the project appraisal especial for PVs. More proportional PV tariff scheme would help as well in the quicker pay back of the investment of both desalination and PV system. Since the desalination plant increases consumption on the island and serves the needs of a private entity, the hotel, the Benefit to cost ratio for the society is rather small.

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6.4 Case study 3-Cyprus In this case, the desalination plants are to be added in order not only to provide potable water but also to reduce the wind power curtailment, if significant capacity of wind is to be installed on the island. Therefore the analysis aims to evaluating the following scenarios in terms of water cost: • Scenario 1 : Do nothing and buy water

with water transfer boats-Addition of wind power only

• Scenario 2: Add 14 desalination units of 1MW to produce water mainly during periods when curtailment is foreseen. The expected water production is around 7.6million m

• Scenario 3: Add 4 desalination units of 1MW which will operate all year round to produce 7.6 million m

3

• Scenario 4: Add 7 desalination units of 1MW which will produce 7.6 million m

3

3

• Scenario 5: Add 7 desalination units of 1MW which will produce 7.6 million m

taking into account the fluctuation of the wind power curtailment.

3

6.4.1 Financial Analysis

taking into account the fluctuation of the wind power curtailment and increase the number of operating units when wind power curtailment is foreseen.

The additional cost for the investors comes from the installation of the desalination plants. Therefore, the cost parameters for the desalination plant should be evaluated.

6.4.1.1 Investment Costs Two factors affect the investment costs the cost of the machines and the civil works cost. Due to the size of the units, it is assumed that the civil works costs for scenarios 4 and 5 are 150% higher than scenario 3 and for scenario

2 this cost is by 250% higher. Table 6-57 summarizes the investment costs for Cyprus.

Table 6-57 Expected installation cost for the desalination units

Desalination Units Cost (k€)

Civil Works

(k€)

Total Investment costs

(€)

Scenario 2 19,110 16,250.85 35,360.9

Scenario 3 5,460 6,500.34 11,960.3

Scenario 4 9,555 9,750.51 19,305.5

Scenario 5 9,555 9,750.51 19,305.5

6.4.1.2 Operational Costs Using the typical charge for MV customers in Cyprus, provided in Table 6-58. The expected energy cost can be calculated as described in Table 6-59. The O&M costs for the desalination plants are provided in Table 6-60 for each scenario. In order to calculate the value of this table the base data of other island studied have been used for the chemicals according to water production. Regarding Membranes and labour cost, scenario 3 is the one with constant operation of the desalination units. For this scenario the actual capability is taken into account for the calculations of these costs. For scenarios 4 and 5 the utilization of the units is quite smaller, and thus the water capacity and thus these costs are by 50% than the case of scenario 3. Scenario 2 presents even lower utilization of the operational units, thus the equivalent water production is considered 3 times higher than the case of scenario 3.

Table 6-58 MV tariff system in Cyprus Peak Charge

Energy Charges Off-peak 38.7€/MWh

3.82€/kW On peak 41.1€/MWh RES charge 2.2€/MWh

Fuel Oil 60.04€/MWh

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charge

Table 6-59 Expected energy cost for the studied scenarios in Cyprus

Energy cost (€)

Do nothing Scenario 0 Scenario 2 4,622,667 Scenario 3 3,774,960 Scenario 4 3,653,045 Scenario 5 3,754,940

Table 6-60 Analysis of the annual O&M cost for the desalination power plant

Chemicals Cost €

Water production Equivalent( m3/d)

Membranes & Labour costs (€)

Total Annual

O&M cost (€)

Scenario 2 274,474 64800 1477440 1,751,914 Scenario 3 241,387 21600 492480 733,867 Scenario 4 235,848 32400 738720 974,568 Scenario 5 236,013 32400 738720 974,733

6.4.1.3 Revenues The income for the owners of the desalination plants come from selling water at 1.1 €/m3 as Table 6-61 describes.

Table 6-61 Expected income for the investor Water Selling Income (€) Scenario 2 9,739,400 Scenario 3 8,565,333 Scenario 4 8,368,800 Scenario 5 8,374,666

6.4.1.4 Project Appraisal The project under study is the installation for the desalination plant. The Cypriot financing scheme provides some subsidy for installations of RES co-operating with Desalination plants. This subsidy ranges from 15-35% increasing as the size of the company decreases to smaller enterprises and cannot exceed 175.000€. The scenarios studied here are not directly linked to RES production but can help in increasing it. Thus the assumed amount of subsidy is provided per scenario in Table 6-62, taking into

account which scenario helps in better exploiting RES production.

Table 6-62 Assumed subsidy per scenario Subsidy (%) Do nothing Scenario 0 Scenario 2 15 Scenario 3 0 Scenario 4 5 Scenario 5 10

The most important parameter is the annual cost flow for the project which in this scenario is given by the equation (5). This amount of money is assumed constant and the same for all the years of the studied period and is provided in Table 6-63. According to this table, the indices described in section 6.1 have been calculated and are presented in Table 6-64.

Table 6-63 Expected income for the investor per year.

Fi Scenario 2 2,883,037 Scenario 3 3,538,667 Scenario 4 3,241,891 Scenario 5 3,180,221

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incwaterMDesalOEnergyCostCostCOFi _&2 −++= (5)

Table 6-64 Evaluation indices for the investment

NPV (k€)

IRR (%)

Pay back periods (years)

Scenario 2 -2117.6 5.25 22.62 Scenario 3 28627.9 29.42 3.89 Scenario 4 18053.7 16.09 7.50 Scenario 5 17346.4 15.72 7.68

6.4.1.5 Sources of Finance As sources of finance can be bank loans for the installation. Moreover, subsidies can be provided either by the government by national funds or funds from the European Union. Municipalities can co-finance the desalination plant installation.

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6.4.2 Economic Analysis & Results

6.4.2.1 Impact on the Economics of the Electricity Authority of Cyprus

Table 6-65 summarizes the impact of these scenarios in the operation and the economic of the Electricity Authority of Cyprus (EAC). Scenario 1 is the operation with 289MW of wind power while current situation is no

addition of wind power at all. Fig. 6.67 shows the impact in the operation of the thermal station and the impact on the fuel cost. The cost per kWh is reduced with the desalination scenarios due to the fact that the additional cost for the desalination plant demand is lower than the average fuel cost. The higher RES share on Desalination costs has as impact even higher reduction in the expected fuel cost. The summary of adding desalination systems compared to RES only scenario is provided in Fig. 6.68.

Fig. 6.67 Reduction in Production of units per type and the fuel cost for EAC.

Fig. 6.68 Summary of the impact on the power system of Cyprus compared to wind power addition only.

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Table 6-65 Comparative table of all the scenarios studied for Cyprus Current

situation Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5

Demand (MWh) 4354381 4354381 4394224 4389421 4388617 4388641 Peak Demand (kW) 849.9 850.9 853.9 851.9 851.9 RES Production (MWh) 0 639342.6 649175.6 641751.2 641961.2 644012.6 RES penetration (%) 0 14.68 14.77 14.62 14.63 14.67 RES curtailment (MWh) 0 34066.43 24233.46 31657.84 31447.83 29396.47 RES curtailment share(%) 0 5.06 3.6 4.7 4.67 4.37 Thermal units production (MWh) 4354381 3715038 3745049 3747670 3746656 3744629

Peak Thermal Station (MW) 849.9 841.47 842.47 845.47 843.47 843.47

Vasilikos units (MWh) 2939044 2641484 2658867 2661907 2661820 2661043 Dekheleia Units (MWh) 1262575 1015389 1027510 1027144 1026324 1025217 Moni steam Units (MWh) 151243 58016 58528 58469 58362 58219 Gas Turbines (MWh) 1520 148 142 148 148 148 Estimated Fuel cost (k€) 266132.483 224453.5 225567.1 226300.5 226236.8 225991.7 Estimated Fuel Cost of Energy (COE)- €ct/kWh 6.112 6.042 6.023 6.038 6.038 6.035

Additional Cost for meeting the desalination demand €ct/kWh 2.795 5.271 5.208 4.49

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6.4.2.2 Impact on wind park owners economics

Fig. 6.69 presents the impact on RES operation. This impact affects also the

economics of the wind power owners since they sell more wind power to the grid. The additional wind power sales and their value are provided in Table 6-66

Fig. 6.69 Comparison of various scenarios regarding RES shares

Table 6-66 Expected benefits for the wind park owners due to increased sales

Additional wind power

sales (MWh)

Additional Income for Wind park owners (€)

Scenario 2 9,883 621,625.1 Scenario 3 2,459 152,229.6 Scenario 4 2,670 165,505.4 Scenario 5 4,721 295,229.2

Therefore, the wind park owners have significant increase on their annual profits. In order to give incentive to desalination plants owners to operate in a way that increases their sales, perhaps the wind park owners should provide some part of their profit to the desalination plant owners. The base case scenario is Scenario 3 since the increase in sales is due to the increase on the demand

and not due to co-operation with RES. So the incentive provided is a percentage of the additional benefit of Scenarios 2, 4 and 5 when compared to Scenario 3. The impact on the project appraisal indices for various percentage values is provided in Fig. 6.70-Fig. 6.72 Scenario 2 starts to have payback at 6% within 20 years if the wind park owners provide 40% of their benefits to the desalination plant owners, i.e. 187758.2 €/year. SCE 5 becomes more profitable than SCE4 if the 50% of the benefits of the wind park owners is provided to the desalination plant owners, i.e.71499.8€/year. The IRR for SCE 5 increases by 0.41% as the percentage reaches 50%. In scenario 4 this difference is negligible. The figures below also correspond to the economic analysis if the owner of the a% of the wind power capacity decides, as the case of Milos, to invest on desalination plants.

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NPV

-5000

0

5000

10000

15000

20000

25000

30000

35000

0 5 10 15 20 25 30 35 40 45 50

Wind farm owners profits to desalination (%)

(k€)

SCE 2 SCE 3 SCE 4 SCE 5

Fig. 6.70 Impact of providing percentage of the wind power owners profit to desalination plants on Net Present Value

Pay back period

0

5

10

15

20

25

0 5 10 15 20 25 30 35 40 45 50

Wind farm owners profits to desalination (%))

Yea

rs


Fig. 6.71 Impact of providing percentage of the wind power owners profit to desalination plants on pay back period

IRR

0

5

10

15

20

25

30

35

0 5 10 15 20 25 30 35 40 45 50

Wind farm owners profits to desalination (%)

(%)


Fig. 6.72 Impact of providing percentage of the wind power owners profit to desalination plants on IRR

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6.4.2.3 Environmental and social impacts

Fig. 6.73 presents the increase in emissions due to increased demand for the electricity power system of Cyprus. It is obvious that as the percentage of RES in meeting the desalination load is increased, the emissions increase becomes lower. An additional

benefit is the fact that the transported water for minimum 100 nautical miles leads to significantly increased emissions compared to any of the proposed operations. The impact on the emissions avoided is depicted in Fig. 6.74.

Fig. 6.73 Comparison of the various scenarios with operation with wind power only-power system

22.5

33.5

44.5

55.5

66.5

77.5

8

SCE 2 SCE 3 SCE 4 SCE 5 Trans

kg

/m3

Trans

Fig. 6.74 Summary of the impact on the emissions compared to transportation, CO2 on the left Therefore, implementing one of the scenarios 2-5 will also affect the emissions due to marine transportation to the island. This should be taken into account when evaluating the value of these scenarios. As Fig. 6.75 shows there is further reduction in the emissions compared to the case with RES units only, due to marine transportation avoidance. The percentages are expressed as

additional emissions avoided compared to SCE1 emissions avoidance. For the Municipalities of Cyprus, the benefit comes from the difference in the cost of water and the additional sales from wind park owners due to 3% fee. According to information from Cyprus, the price for providing potable water is 5€/m3 while from the desalination plant the cost is 1.1€/m3. Therefore, the benefit for each scenario is

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provided in Table 6-67. The annual benefits can be significant and this has crucial impact on BCR as Table 6-73 shows and is analyzed in more detail when performing sensitivity analysis on both water transportation and selling price.

Table 6-67 Expected benefits for the municipalities due to water difference cost

and increased wind power sales Revenues (€) Scenario 2 34,549,249 Scenario 3 30,372,564 Scenario 4 29,676,165 Scenario 5 29,700,856

Fig. 6.75 Reduction of emissions for the scenarios with desalination when transportation emissions are taken into account compared to RES only operation

6.4.2.3.1 Social Benefits Construction phase The employment numbers during the construction phase vary according to the scenario studied. Since the installation of wind turbines has been almost already decided and people are already working on, focus is given on the scenarios that employ desalination plants. Clearly the numbers are

much higher compared to the previous case studies due to the much larger size of the plants. Table 6-68 presents these results. Operation Phase Due to the size of the Desalination plants considered more employees will be required compared to the smaller islands studied till now. The number of employees per category is given in Table 6-69.

Table 6-68 Employment matrix for the construction phase per scenario SC 2 SC 3 SC 4 SC 5 Engineers Number 15 14 14 14 Engineers HumanMonths 50 40 42 42 Technicians Number 12 10 10 10 Technicians HumanMonths 100 50 60 60 Operators Number 12 8 8 8 Operators HumanMonths 22 12 16 16 Workers Number 40 30 32 32 Workers HumanMonths 190 150 160 160 Total Employment (Human months) 362 252 278 278

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Table 6-69 Employment matrix for the operation per scenario SC 2 SC 3 SC 4 SC 5 Engineers Number 1 1 1 1 Technicians Number 6 4 4 4 Operators Number 12 8 8 8 Workers Number 4 2 3 3 Total Employment 25 18 20 21

6.4.2.4 Monetization of costs and benefits

Clearly there are two phases, the installation phase and the operation phase. The various costs and benefits during the installation phase for all the scenarios studied are provided in Table 6-70. The benefits for each

year are described in Table 6-71 while the costs are provided in Table 6-72. It should be noted that without RES there is increase in the emissions which creates an additional cost. All the cost and benefits are represented in NPV in Table 6-73, where the Benefit to Cost Ratio (BCR) for the society is also provided

Table 6-70 Monetization of benefits during installation phase SC 2 SC 3 SC 4 SC 5 Installation VAT(€) 5304128 1794051 2895827 2895827 Unemployment installation benefit (€) 242540 168840 186260 186260

Employment Installation tax (€) 114280 78880 86840 86840

Investment Domestic cost (€) 5304128 1794051 2895827 2895827

Investment Imported (€) 36068067 12199547 19691620 19691620 Sum Installation benefits (€) 5,660,948 2,041,771 3,168,927 3168927

Sum Installation Costs (€) 41,372,195 13,993,598 22,587,447 22,587,447

Table 6-71 Analysis of annual benefits per scenario studied-Cyprus SC 2 SC 3 SC 4 SC 5 Unemployment benefit (€) 245943.6 160398 171091.2 171091.2 Employment TAX (€) 78480 53520 55920 55920 O&M VAT(€) 956187.15 676324.05 694141.95 709450.95 Municipality Benefit (€) 34,549,249 30,372,564 29,676,165 29,700,856 Electricity benefits (€) 2,887,442 1775730 1704239 1921511 Emission Benefits (€) 3,680,000 3047000 2999000 3091000 Sum Annual benefits (€) 42,396,200.11 36,084,818.25 35,299,791.27 35,649,062.87

Table 6-72 Analysis of annual costs per scenario studied-Cyprus SC 2 SC 3 SC 4 SC 5 O &M cost (€) 6,199,389.60 4,435,440.30 4,530,156.20 4,632,199.70 O&M Imported(€) 210229.68 88064.04 116948.2 116968 SUM costs Annual (€) 6,409,619.28 4,523,504.34 4,647,104.36 4,749,167.66

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Table 6-73 Summary of cost-benefit analysis Benefits

NPV (x1000€)

Cost NPV (x1000€) BCR

Scenario 2 491940.9 114890.02 4.28 Scenario 3 415931 65877.84 6.31 Scenario 4 408053.9 75889.37 5.38 Scenario 5 412060 77060.03 5.35

6.4.3 Sensitivity Analysis

6.4.3.1 Impact of Interest Rate Fig. 6.76 and Fig. 6.77 show respectively the impact of interest rate on NPV and the pay back period which does not change the

sequence of the scenarios. SCE 3 has pay back period below 5 years. NPV is below zero for SCE2 when the interest rate is above 6% and when the interest rate exceeds 8% the investment cannot be paid back at all, even if the lifetime of the project was not an issue. For 8%, the pay back period for scenario 2 is about 50 years, clearly above the lifetime of the project. The impact of interest rate on BCR is shown in Fig. 6.78. Clearly increase of interest rate reduces the impact on the investment for the society but the BCR is still high.

NPV

-15000-10000-5000

05000

10000150002000025000300003500040000

4 5 6 7 8 9

Interest Rate

(k€)


Fig. 6.76 Impact of Interest rate on Net Present Value .

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Pay back period

05

101520253035404550

4 5 6 7 8 9

Interest rate

Year

s


Fig. 6.77 Impact of Interest rate on Pay back Period

BCR

33.5

44.5

55.5

66.5

7

4 5 6 7 8 9Interest Rate (%)


Fig. 6.78 Impact of Interest rate on Benefit Cost Ratio

6.4.3.2 Impact of CO2 emission trading price

Since in all cases there is increase in the CO2 emissions compared to the proposed operation with wind power only, the project appraisal indices become worse as shown in

Fig. 6.79-Fig. 6.81 as the trading price increases. SCE 4 and SCE 5 converge since SCE 5 presents lower emission values. The IRR is still high for scenarios 3-5 and their pay back time is still within reasonable time.

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NPV

-10000-5000

05000

100001500020000250003000035000

15 20 21 25 30 35 40

Price (€/tn)

(k€)


Fig. 6.79 Impact of CO2 emissions trading price on NPV-Cyprus

IRR

0

4

8

12

16

20

24

28

32

15 20 21 25 30 35 40

Price( €/tn)

(%)


Fig. 6.80 Impact of CO2 emissions trading price on IRR-Cyprus

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Pay back period

048

12162024283236

15 20 21 25 30 35 40

Price (€/tn)

Year

s


Fig. 6.81 Impact of CO2 emissions trading price on Pay back period-Cyprus

6.4.3.3 Impact of water selling price This parameter affects significantly the pay back period of the proposed operation as Fig. 6.82-Fig. 6.84 show here. Prices between 0.8-1.3 €/m3 have been studied with step of 5 €ct/m3.No scenario can be paid back at prices lower than 0.85€/m3 unless additional subsidy is provided. Table 6-74 describes the water selling prices for each case.

Table 6-74 Minimum for Water selling prices

Minimum

Water Selling Price

€/m3

Water Selling Price for

reasonable pay back

period (20 years) €/m3

SCE 2 1.1 1.25 SCE 3 0.85 0.9 SCE 4 0.95 1 SCE 5 0.95 1

NPV

-50000-40000-30000-20000-10000

01000020000300004000050000

0.8 0.85 0.9 0.95 1 1.05 1.1 1.15 1.2 1.25 1.3

Water Price(€/m3)

(k€)


Fig. 6.82 Impact of water selling price on NPV-Cyprus

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Pay back period

0

10

20

30

40

50

60

0.8 0.85 0.9 0.95 1 1.05 1.1 1.15 1.2 1.25 1.3 1.35

Water Price(€/m3)

Year

s


Fig. 6.83 Impact of water selling price on Pay back Period-Cyprus

IRR

0

5

10

15

20

25

30

35

40

0.8 0.85 0.9 0.95 1 1.05 1.1 1.15 1.2 1.25 1.3

Water Price(€/m3)

(%)


Fig. 6.84 Impact of water selling price on IRR -Cyprus This parameter is very important for the cost benefit analysis, since significant amount of benefits for the society comes from the avoidance of importing water. Thus, the selling price from the desalination plant influences the BCR as Fig. 6.85 shows. Clearly, the selling price can be increased if there is problem in paying back the investment, e.g. at 1.25€/m3 since the BCR

remains rather high. Even more important is the parameter of the price of the transported water as Fig. 6.86, with the most sensitive being Scenario 3 where increase of the transportation price by 1.25€/m3 increases BCR by 0.68.

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BCR

33.5

44.5

55.5

66.5

7

0.8 0.95 1.1 1.25 1.4 1.55 1.7 1.85 2Water Selling price (€/m3)

SCE2 SCE 3 SCE 4 SCE 5

Fig. 6.85 Impact of water selling price on BCR -Cyprus

BCR

2

3

4

5

6

7

8

3 3.5 4 4.5 5 5.5 6Transportation price (€/m3)


Fig. 6.86 Impact of water transportation price on BCR -Cyprus

6.4.3.4 Impact of Desalination Installation cost

Fig. 6.87-Fig. 6.89 show the impact of the installation cost for the desalination power plant. 10% change is not so important for SCE 3-5. However, if the installation cost is

decreased by minimum 7.5% for the scenario with the largest number of units, SCE2, then the NPV becomes positive, however the payback period remains still above 20 years. Fig. 6.90 presents the impact of desalination cost on BCR, clearly this is not as significant as the interest rate change.

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NPV

-10000-5000

05000

10000

1500020000250003000035000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change(%)

(k€)


Fig. 6.87 Impact of desalination installation cost on NPV-Cyprus

Pay back period

0

5

10

15

20

25

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change(%)

Year

s


Fig. 6.88 Impact of desalination installation cost on Pay back period-Cyprus

IRR

0

5

10

15

20

25

30

35

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change(%)

(%)


Fig. 6.89 Impact of desalination installation cost on IRR-Cyprus

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BCR

4

4.5

5

5.5

6

6.5

7

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)


Fig. 6.90 Impact of desalination installation cost on BCR-Cyprus

6.4.3.5 Impact of Energy Prices The energy charge prices for the desalination plant depend on the following parameters:

a) Peak Charge

b) Off peak energy charge

c) Day time energy charge

d) Additional charges for fuel compensation.

Fig. 6.91-Fig. 6.93 show the impact of the additional energy charges for fuel price compensation which are the highest part of the energy cost provided in Table 6-59. If these charges are reduced by at least 7.5% then SCE2 can also become profitable, although not as profitable as the other ones studied. The difference in the project

appraisal indices exceeds 10% when comparing increase by 10% of the energy charge parameter (d) with decrease by 10% of this parameter. For the rest energy charges the impact decreases from c to a energy charge parameter. It should be noted, that SCE4 and SCE 5 which have quite similar energy costs converge as the day time charges increase or as the peak charges decrease. Energy prices increase, increases the electricity income for the public company as well but increase the O&M cost. O&M cost has much greater impact on the annual costs than the electricity benefit has on the annual benefits for the society. Thus increase on energy prices reduces BCR as Fig. 6.94 shows.

NPV

-10000-5000

05000

1000015000

2000025000

3000035000

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change(%)

(k€)


Fig. 6.91 Impact of Energy prices(fuel charge) on NPV-Cyprus

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Pay back period

0

5

10

15

20

25

30

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10Change(%)

Yea

rs


Fig. 6.92 Impact of Energy prices (fuel charge) on Pay back period-Cyprus

IRR

0

5

10

15

20

25

30

35

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10Change(%)

(%)


Fig. 6.93 Impact of Energy Prices (fuel charge) on IRR-Cyprus

BCR

4

4.5

5

5.5

6

6.5

7

-10 -7.5 -5 -2.5 0 2.5 5 7.5 10

Change (%)


Fig. 6.94 Impact of Energy Prices (fuel charge) on BCR-Cyprus

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6.4.3.6 Sensitivity analysis summary

Table 6-75 Sensitivity Analysis Matrix per parameter studied

Sensitivity parameter Most sensitive scenario

Interest rate SCE 3 CO2 emissions trading price SCE 3

Water transfer price SCE 2 Desalination installation cost SCE 2

Water selling price SCE 2 Energy prices SCE 2

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6.4.4 General Conclusions for Cyprus

The expected wind power curtailment for Cyprus could lead to producing significant amount of water for Cyprus if exploited. Exploitation of the total quantity of wind power curtailment would lead to significant installed capacity with low capacity factor. Thus, the scenarios run were rather a compromise. The one which uses the highest percentage of wind power curtailment, scenario 2, is the least profitable for the investor among the scenarios studied. Under current capital and O&M costs, the project appraisal indices are not favorable for this scenario within the life time of the project. However, decrease of the installation cost and the interest rate would help in paying back even this investment timely. This scenario, however, presents the highest benefit for both the wind park owners and the Electricity Authority of Cyprus since not only does it manage to reduce wind power curtailment significantly but also reduces the additional fuel cost required for meeting the desalination electricity needs. Producing the same quantity of water with Scenario 2 with constant production, clearly

is the most profitable solution for the investor of the desalination plant. The reduction of wind power curtailment though is very limited and is considered a side effect of the increase in demand. Following partly the expected monthly wind power curtailment with more installed desalination units, would decrease wind power curtailment, improving economics of wind park owners. These benefits would be higher especially if the operator of the island had the right to ask increase of water production during the hours when wind power curtailment is expected. Project appraisal indices are deteriorated compared to no constant operation of desalination and wind power but still remain satisfactory. Desalination plants combined with wind power, help in all cases so that the emissions for partly meeting the population water needs are lower than transporting the same amount of water for about 100 miles despite the increase on the island demand. And this is made at significantly lower cost for the Municipalities. Moreover, significant employment will be created during both the construction and the operation phase of these power plants. All these reasons justify the high Cost benefit ratio achieved for all the scenarios studied

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6.5 General conclusions for desalination

Desalination may not be a direct storage method but can provide significant aid in managing RES providing also a valuable good for the inhabitants and visitors of the islands. From the three case studies islands it can be concluded that desalination can be a viable investment when combined with RES, especially wind power. In islands where wind power curtailment is expected, as close as possible co-operation of wind power and desalination plants will lead to significant benefits to both wind park owners and the power system providing also benefits to the owners of the desalination plants. These benefits are higher if some of the wind park owners decide to build the desalination plant. The wind power

penetration in such a case remains at least equal to the case with wind power only. In the vast majority of the cases studied, the water demand was met at lower emission level than the current practice of transporting water even if RES are added. Thus, environmental benefits are achieved especially when desalination plant schedule is based on RES production or even curtailment estimations. The viability of the desalination investment is much linked to the water selling price and the installation cost without however leading to non paying back the investment. The value of the desalination for the society is as much as higher as the water production substitutes water transportation for public use. As this transfer price is higher the use of desalination plants gets higher. If there is private use of the water produced the benefits for the society are rather limited as the analysis for Mljet island has shown.

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7 GENERAL SYNOPSIS The results of the simulations of selected island power systems with relatively high RES penetration and energy storage technologies of Task 2.1 were examined with respect to their economic, environmental and social aspects. All the resulted scenarios that propose an increase in RES penetration through the introduction of four different energy storage methods in selected islands were evaluated in terms of their economic and environmental costs and benefits as well as of the social impacts the project implementation may have in the local communities. In the case of batteries two islands were examined: La Graciosa and San Pietro. The analysis of the former indicates that an 80% RES penetration is a scenario that shows financial profitability. From the investor’s perspective the proposed power system for La Graciosa is a profitable investment. On the contrary, the proposed power system for San Pietro that also includes an 80% RES penetration is not a profitable investment. However, in both cases water or hydrogen production with excess electricity has not been considered, but the selling prices of these commodities might have significant positive impacts on the financial profitability of the proposed power supply system. As far as pump hydro storage is concerned, the results are very positive for the prospects of wind with pumped storage in autonomous islands and show that governments, local authorities and societies should strive for substantially increasing the share of RES using this technology. More specifically, such a shift is compatible with the market’s major aspirations, but is also justified from a broader perspective reflecting the short and long term interests of the national economy and the society as a whole. The results showed that these benefits are large enough to fully cover any subsidies that the decision

makers could provide for such investments in order to encourage private investors to undertake the technical and financial risks associated with these projects. The analysis for the introduction of wind energy coupled with hydrogen energy storage showed that the benefits of the hybrid RES-hydrogen storage system outweighed the costs proving a social profitability. It may be also argued that the subsidy for the implementation of the proposed power system is paid back to society because of the project’s ensuing benefits. From the investor’s point of view, in Milos island the proposed RES & hydrogen power system is not a profitable investment mainly due to the production of a large amount of excess electricity. However, the proposed system may become more economically attractive if the produced excess energy is used to generate hydrogen in order to be used locally as a fuel in the transport sector or for heating purposes. On the contrary, the proposed system for Corvo is a quite profitable investment and thus the RES & hydrogen power system shows private and social interest. In conclusion, the use of hydrogen as a storage means aiming to assist in increasing the penetration of RES in islands may be considered as a socially attractive and profitable solution to tackle issues of particular importance to islands such as fossil fuel import dependency and security of supply. From the three case studies that desalination was examined it can be concluded that desalination can be a viable investment when combined with RES, especially wind power. In islands where wind power curtailment is expected, as close as possible co-operation of wind power and desalination plants will lead to significant benefits to both wind park owners and the power system providing also benefits to the owners of the desalination plants. These benefits are higher if some of the wind park owners decide to build the desalination plant. The wind power penetration in such a case remains at least equal to the case with wind power only. In

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the vast majority of the cases studied, the water demand was met at lower emission level than the current practice of transporting water even if RES are added. Thus, environmental benefits are achieved especially when desalination plant schedule is based on RES production or even curtailment estimations. The viability of the desalination investment is much linked to the water selling price and the installation cost

without however leading to not paying back the investment. The value of the desalination for the society greatly depends on the need for water transportation for public use. As this transfer price is higher the use of desalination plants gets higher. If there is private use of the water produced the benefits for the society are rather limited as the analysis for Mljet island has shown.

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8 REFERENCES [1] Arnold G., Handbook of Corporate Finance: a

Business Companion to Financial Markets, Decisions and Techniques, 2004, Pearson Education Limited, UK

[2] ExternE Project, http://www/externe.info/ [3] Zervos A., Caralis G., Zografakis N. (1999)

“The effect of RES to the increase of employment in the islands. Case study: The island of Crete”, Workshop in Ikaria.

[4] Zervos A., Caralis G., Gorgoulis M., Zografakis N. (2000) “Implementation plan for the large scale deployment of RES in Crete-Greece”, Altener 2000 conference, Toulouse-France.

[5] Mirasgedis S., Diakoulaki D., Papayannakis L., Zervos A. (2000). The impact of social costing on the competitiveness of renewable energies in Crete. Energy Policy, 28/1, 65-73.

[6] Diakoulaki D., Caralis G., Zervos A. (2000) “Strategies for communities aiming at 100% RES supply”, Altener 2000 conference, Toulouse-France.

[7] G.Panaras, G.Caralis, A.Zervos, P.Garofallis (2003) “Towards 100%RES supply in the island of Lemnos-Greece” International Conference: RES for island tourism and water, Crete, Greece.

[8] Zervos A., Caralis G., Kaltsa I. (2001) “Socio-economic and environmental evaluation of the wind energy penetration in Greece” National Conference of RES, Greece.

[9] Diakoulaki D., Zervos A., Sarafidis J. (2001). Cost-Benefit analysis of solar water heating systems in Greece. Energy Conversion & Management, 42/14, 1727-1739.

[10] Sarafidis Υ., Diakoulaki D., Zervos A., Papayannakis L. (1999). A regional planning approach for the promotion of renewable energies. Renewable Energy, 18/3, 317-330.

[11] Caralis, G. ‘Analysis of wind energy with pumped storage systems’, PhD thesis, National Technical University of Athens, March 2008.

[12] E.I. Zoulias, N. Lymberopoulos, “Techno-economic Analysis of the Integration of Hydrogen Energy Technologies in Renewable Energy-based Stand-Alone Power Systems”, Renewable Energy Journal, 2007, Vol. 32 (4), pp. 680-696.

[13] RAE, Regulatory Authority of Energy, http://www.rae.gr/

[14] PPC, Public Power Corporation, http://www.dei.gr/

[15] GSRT, General Secretariat for Research and Technology, http://www.gsrt.gr

[16] IEE, Intelligent Energy for Europe, http://ec.europa.eu/energy/intelligent/index_en.html

[17] JTI, Joint Technology Initiative, http://cordis.europa.eu/fp7/jtis/

[18] BWEA, British Wind Energy Association, www.bwea.com

[19] Rei P., Fonseca J.P., Duic N., Carvalho M.G., “Inetgration of Renewable Energy Sources and Hydrogen Storage in the Azores Archipelago”,CD Proc. of the International Conference on New and Renewable Technologies for Sustainable Development, Ponta Delgada, Azores, 24 pp.,2002.

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Contract N°: EIE/07/159/SI2. 466845 · executive agency for competitiveness and innovation...

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