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The World Bank Group Vanuatu: Efate Geothermal Power and Island-Ring Grid Development Framework

Inception Report 17 June 2011

The World Bank Vanuatu: Efate Geothermal Power and Island-Ring Grid Development Framework

Inception Report

17 June 2011

Prepared for: Prepared by:

The World Bank Group Castlerock Consulting Pte Ltd

Castlerock Consulting Pte Ltd

1 Fullerton Road, #02-01 One Fullerton

Singapore 049213 Tel: +65 6832 5171Fax: +65 6408 3801

www.castlerockasia.com

Version: 1.0

ii

World Bank – 17 June 2011

TABLE OF CONTENTS

1. Assignment Background & Objectives 1-1 1.1 Background 1-1 1.2 Objectives 1-3

2. Assignment Work Plan 2-4 2.1 Key Features of the Approach 2-4 2.2 Activity Flow 2-4 2.3 The Inception Mission 2-7 2.4 Updated Work Plan 2-8

3. The Load Forecast 3-1 3.1 Load Forecast within the Area Served by UNELCO 3-1 3.2 Load Forecast for the Unserved Area 3-4 3.3 The Infill Demand Forecast 3-8 3.4 Demand Forecast Summary 3-9

4. Geothermal Resource Scenarios 4-1 4.1 Characteristics of Geothermal Power 4-1 4.2 The Efate Geothermal Resource 4-4

5. System Considerations 5-1

6. Geothermal Development Scenarios 6-1

7. Network Development Scenarios 7-1 7.1 Line Routes 7-1 7.2 Transmission Considerations 7-2 7.3 Distribution Considerations 7-2 7.4 Ring Road Line Design 7-3 7.5 Fiber Telecommunications 7-6 7.6 Consumer Connections and Network Loading 7-6 7.7 Cost Modelling 7-7

8. Is the Efate Geothermal Prospect a “Game Changer”? 8-1 8.1 Economic Analysis 8-1 8.2 Decision Analysis 8-4 8.3 Looking Ahead 8-6

APPENDIX A: Terms of Reference A-1

APPENDIX B: Kick-Off Presentation B-1

APPENDIX C: Data Requests C-1

TABLE OF CONTENTS…

iii

Ministry of Finance – 17 June 2011

APPENDIX D: Geothermal Plant Cost Format D-1

APPENDIX E: Network Cost Inputs E-1

APPENDIX F: Conversion Factors Used for Economic Analysis F-1

APPENDIX G: Inputs to the Economic Model G-1

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1. ASSIGNMENT BACKGROUND & OBJECTIVES

1.1 BACKGROUND

Electricity in Vanuatu is supplied via concessions granted by the Government to private utilities. Three concessions, on the islands of Efate, Malekula and Tanna, are operated by UNELCO, a subsidiary of GDF Suez. The fourth concession, serving Luganville on the island of Santo, was taken over at the beginning of 2011 by Pernix, a US-based company, based on a competitive process following the end of UNELCO’s concession there. A uniform national tariff is in place across all concessions.

The concession on Efate is by far the largest, accounting for 87% of total generation of 64,716 MWh, and 73% of the 12,645 consumers in the country. The concession area extends to 15 kms from the city limits of the capital city, Port Vila. UNELCO holds the concession until 2031. The rest of Efate outside of the Port Vila concession is currently unserved by grid electricity.

Electricity supply in Vanuatu is characterized by high tariffs and a low electrification ratio:

The relatively small scale of the Efate system and reliance on diesel fuel makes electricity expensive. Moreover, the high reliability of the Efate system is the result of additional investment such that electricity rates are high relative to other island power systems around the world. Even taking into account the 6.8% reduction in tariffs expected for most consumers under the May 2010 tariff review, the base tariff for January 2011 is 52 vatu per kWh (about 56.5 US cents per kWh). This compares, for example, to a current tariff yield of about 23 US cents per kWh in the Seychelles, a somewhat larger system. Relatively high tariffs have been a chronic phenomenon in Vanuatu. Exhibit 1.1 shows how Vanuatu’s electricity prices compared to other island nations in 2004, based on a study financed by the Public-Private Infrastructure Advisory Facility (PPIAF) through the World Bank.

Vanuatu’s national electrification ratio is only some 27%, reflecting low affordability. Within urban concession areas such as Port Vila and Luganville it reaches approximately 75%. About 30% of Vanuatu’s population lives on Efate, and about half of Efate’s population reside in Port Vila. Based on these numbers, it appears that out of a total population of some 75,000 people on Efate, only about 25,000 enjoy the benefits of electricity in their households.

Though reliability and quality of supply is excellent on Efate relative to other island nation utility peers, the high price of electricity and its limited reach has profound, adverse socio-economic impacts on the country.

The Government of Vanuatu established the Utilities Regulatory Authority (URA) in 2008 following the URA Act No. 11 of 2007. The URA regulates prices, service standards and market conduct, as well as protects consumers in the electricity and water sectors. It also investigates and advises the Government on regulatory matters that affect Vanuatu's essential utilities.

Under the concession agreement, the Government may review tariffs every five years. URA, on behalf of the Government, conducted its first tariff review for the Port Vila concession in 2010. This resulted in the URA’s proposed 6.8% reduction in the base tariff. UNELCO has contested the reduction, and initiated arbitration with the Government, as provided for by the concession agreement. An arbitration decision was to have been issued at the end of April 2011, but the result is not known.

1. Assignment Background & Objectives

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Exhibit 1.1: Comparing 2004 Electricity Prices in Vanuatu to Other Island Nations

While rigorous regulation might be expected to achieve further tariff reductions in future years, the long term impact is likely to be marginal at best. The only development that could yield the quantum reduction in tariffs needed to significantly improve electricity affordability and the electrification ratio would be introduction of new, lower cost generation technologies that pass savings through to the power supply tariff.

Efate’s geothermal power potential offers such a prospect. Vanuatu has been the subject of geothermal prospecting since the 1970’s. Hydrothermal surface manifestations are present in several locations around Efate. And with the commercialization of smaller scale binary power systems, geothermal power generation sizing and performance is suitable for conditions expected on Efate.

In April 2009 an Australian geothermal developer, KUTh Energy, obtain two prospecting licenses on Efate, as provided for under the Geothermal Energy Act No. 6 of 1987. Under the Electricity Supply Act No. 21 of 2000, a person who is not a concessionaire can generate and supply electricity outside of concession areas, and can also sell that electricity to a concessionaire. In October 2009, KUTh announced agreement with UNELCO on a memorandum of understanding (MOU) for the sale of 4 MW of baseload geothermal power to the Port Vila concession. The power would be priced at UNELCO’s “avoided cost”.

Following the signature of the MOU, KUTh initiated magneto telluric (MT) surveys and further geochemical work. In May 2010, KUTh announced encouraging results from the MT surveys, and engaged Sinclair Knight Merz (SKM), an engineering firm, to assist with interpreting the results. In October 2010, KUTh presented results of SKM’s work indicating three targets with a combined power generation potential of 32 MW with a probability of 90%. Exhibit 1.2 shows the location of these targets and associated prospect license areas (Takara and Teouma) relative to Port Vila and the recently completed island ring road.

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Exhibit 1.2: Target Geothermal Sites

Source: KUTh Energy

Source: “Infrastructure Regulatory Review for Government of Vanuatu”, Castalia for the World Bank/PPIAF, 2004

1. Assignment Background & Objectives

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Though these results are very promising, significant risks remain with respect to the commercial development potential of these sites, as discussed further in Section 4.4.3 below.

KUTh has selected Takara (Site C in Exhibit 4.2) for initial development because of ease of access, strong indicators of a commercially viable resource and the ability to support the proposed project development of an initial 4 MWe net off-take, with the possibility of further expansion to a second similar unit in the near future. Target B (Central) is the preferred secondary target to support production at Takara.

The next step would be for KUTh to complete additional geophysical surveys and conduct exploration drilling at Takara. However, before committing the necessary funds, the company presumably requires greater certainty regarding power offtake and price. In January 2011 KUTh cited delays in proceeding with exploration drilling resulting from:

Because of UNELCO’s arbitration with the Government regarding the appropriate tariff formula, the draft power purchase agreement between KUTh and UNELCO cannot be finalized.

KUTh also cannot finalize tariffs with URA pending the results of this World Bank assignment and the UNELCO arbitration process.

1.2 OBJECTIVES

Vanuatu has a unique opportunity to develop an environmentally friendly, less costly source of power generation. As noted in the terms of reference (TOR) for this assignment as presented in Appendix A, together with grid development along the recently completed Efate ring road, this could indeed be a “game changer” for the country.

The objectives of the assignment are therefore to:

Define and cost at a conceptual level the principal technical options for geothermal power generation and associated transmission and distribution.

Determine the economically optimal option, taking into account both the potential for displacing diesel generation in the Port Vila concession as well as new service to areas outside the concession.

Formulate commercial and regulatory arrangements to facilitate financially least-cost development of this option.

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2. ASSIGNMENT WORK PLAN

2.1 KEY FEATURES OF THE APPROACH

Geothermal potential on Efate will not be known with a level of confidence required for investment decision-making until exploration drilling and appraisal is complete. And drilling exploration will not take place until after completion of this study, which will provide stakeholders with a clear picture of the commercial and regulatory framework under which geothermal development and power production will be carried out.

Consequently, our approach entails:

1. Defining various scenarios of geothermal power potential

2. Identifying network and geothermal development options corresponding to these geothermal resource scenarios

3. Evaluating which development option is economically optimal taking into account the uncertainty in key parameters

4. Assessing the impacts of the economically optimal development option on retail tariffs and on the financial performance of the Port Vila concessionaire

5. Formulating a framework for geothermal development, and associated changes to policies, regulations and concession agreements that facilitate implementation of the optimal approach taking into account the uncertainty in key parameters.

The approach focuses on geothermal potential and development options. It considers grid extension and improved electricity access only to the extent that these may affect the attractiveness of geothermal development. Hence the assignment does not consider the costs and benefits of grid extension or improved access in the event that geothermal resources fail to materialize.

The approach also explicitly recognizes the uncertain environment in which policy and investment decisions must be made. Some of the key uncertainties that may affect the attractiveness of the geothermal project include:

Load growth

Geothermal resource size and quality

Geothermal well, field and generating plant costs

Diesel fuel prices

Finally, the principal project stakeholders, including the Government of Vanuatu, the URA, UNELCO, KUTh, and others must be consulted from the outset of the assignment to ensure that recommendations regarding the nature or structure of any geothermal development will ultimately be acceptable to all parties. Any proposed arrangements must acknowledge the existing rights, obligations and authorities of each of these parties.

2.2 ACTIVITY FLOW

Exhibit 2.1 shows the principal activities that will be undertaken over the course of the assignment, with color coding indicating whether the an activity is undertaken around the inception mission, the interim mission, or the final mission of the consultant team to Vanuatu. These various activities are summarized below:

2. Assignment Work Plan. . ..

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Exhibit 2.1: Activity Flow

1. Prepare load forecast. The load to be served determines the potential market for geothermal power. Given that geothermal power offers significant economies of scale and assuming a sufficiently large geothermal resource, the more load to serve, the cheaper geothermal power can be. The load forecast is disaggregated into three components: (i) load forecast for the area currently served by UNELCO; (ii) a load forecast for new distribution outside the currently served area that may be developed as part of the geothermal project; and (iii) additional load growth in both the currently served area and currently unserved areas resulting from a Government program to enhance households’ access to electricity. The load forecast is discussed further in Chapter 3 of this report.

2. Develop geothermal resource scenarios. Though initial geophysical and geochemical studies indicate that significant geothermal resources may exist on Efate, these resources can only be confirmed through exploration drilling and ultimately flow testing of wells. An offtake commitment and commercial arrangements including risk allocation must be established prior to any investment in exploration drilling. This activity therefore defines possible exploration drilling outcomes so that geothermal resource uncertainty can be explicitly considered when evaluating the economic value of geothermal under various development options. This is discussed in Chapter 4.

3. Assess system considerations. In addition to load and resource considerations, a third technical factor affecting geothermal potential on Efate is how a potential geothermal plant fits into the existing generation mix, bearing in mind that geothermal will typically be operated as a base load resource. These three factors (load to be served, geothermal resource size, and system planning considerations) determine the size of geothermal plants to be economically evaluated. These system considerations are discussed in Chapter 5.

2. Develop geothermal

resource scenarios

5. Define & assess network options

6. Prepare economic model

1. Prepare load forecast

3. Assess system considerations

7. Deliver Interim Presentation

8. Confirm optimal

configuration

4. Assess geothermal

development costs

13. Prepare Draft Final Report

11. Assess tariff & concessionaire

impacts

15. Submit Final Report

10. Assess transaction feasibility

9. Formulate development framework

12. Formulate policy & regulatory

changes

14. Draft Final Presentation

Final Stage

Interim Stage

Inception Stage


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4. Assess geothermal development options. Once particular plant sizes have been established based on resource size, load and system considerations, other assumptions about geothermal resource quality are defined as the basis for a notional plant design and costing. This is discussed in Chapter 6.

5. Define & assess network options. Network options to connect the geothermal plant to the existing UNELCO system and to extend distribution to areas outside the UNELCO concession are assessed in parallel. This includes evaluation of costs down to connections, as well as the configuration and cost of a fiber optic link. This is discussed in Chapter 7.

6. Prepare the economic model. The recommended policy decisions will be those that yield the highest expected economic net present value. We utilize a decision analysis framework to explicitly take into account the uncertainty in key parameters such as geothermal resource size as well as policy decisions regarding exploration drilling risk allocation and load building. The results of this economic analysis are used to determine whether despite uncertainty in key parameters the Government should promote geothermal development on Efate, and if so, the principal policy decisions it should take. This is discussed in Chapter 8.

7. Deliver interim presentation. The results of the economic analysis constitute a major “check point” in the project, since they represent the foundation upon which commercial and regulatory arrangements for geothermal development will be formulated. The assumptions and findings up to this point shall be presented to the principal stakeholders for their consideration and feedback.

8. Confirm optimal configuration. Based on feedback received from stakeholders, the analysis may be updated and findings refined. This will confirm whether the Government should proceed with efforts to promote geothermal development, and if so, steps it should take with respect to exploration risk allocation and the technical configuration of the project (including components for grid extension and improved access).

9. Formulate development framework. We will then identify the principal institutional and commercial models that can be considered to facilitate development of the geothermal project. These models will be defined in terms of the ownership and operation of the principal components of the project, and the commercial arrangements between the parties involved.

10. Assess transaction feasibility. A principal consideration for evaluating these framework options is the likelihood that the financial transactions required to implement each are feasible. There is likely to be some iteration between the definition of the geothermal development framework options and these transaction considerations.

11. Assess impacts on tariffs and the concessionaire. We will specifically investigate how the selected framework would affect retail tariffs as well as the financial performance of the concessionaire. These considerations are of course inter-related with the feasibility of the financial transactions associated with each framework option.

12. Formulate policy and regulatory changes. Once the optimal development framework has been determined, we will formulate any changes in policy, laws, or regulations required to facilitate implementation of that framework.


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13. Prepare Draft Final Report. We will then prepare a draft final report compiling the analysis and findings of the study….

14. Present Draft Final Report….and present that report for review and feedback from stakeholders.

15. Submit Final Report. Based on the feedback of stakeholders, we will update and submit the Final Report.

The rest of this report discusses the analysis and findings of Activities (1) through (6) described above.

2.3 THE INCEPTION MISSION

The Inception Mission was conducted from April 12 to 23, 2011. During this mission initial meetings were held with all principal stakeholders, including:

Government of Vanuatu o Ministry of Lands & Natural Resources (Energy Unit) o Ministry of Finance & Economic Management (Treasury Unit and National

Statistics Office, NSO) o Ministry of Infrastructure & Public Works (Public Works Department and

Met Service) o Vanuatu Investment Promotion Authority (VIPA)

UNELCO URA The Telecommunications & Radiocommunications Regulator (TRR) KUTh Energy Other development partners

o AusAid o Millennium Challenge Corp.

Engineering and construction firms Household and commercial consumers (as part of field visits)

Appendix B contains the kick-off presentation attended by representatives from several of these stakeholders.

Appendix C contains the formal data requests made to Lands Department, UNELCO and the NSO. While some of this data has been compiled, two essential pieces of data remain outstanding:

Average hourly wind speed for the average day in each month (to assess the correlation between windfarm output and load; better yet if actual hourly windfarm output for an entire year could be obtained from UNELCO, as requested in Appendix C.

The GIS file from NSA with the 2009 census data showing the location, family member composition, and source of electricity and cooking fuel for all households in Efate (to determine how many new households can be served from distribution extension and access promotion programs, as well as the costs of these programs.

One of the priorities of the interim mission will be to follow up on availability of this data. In addition, though not essential, household level data from the Household Income and


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Expenditure Survey (HIES) as described in Appendix C would help to confirm the analysis using the summary cross tabulations from the HIES report.

2.4 UPDATED WORK PLAN

Referring to the activities described in Section 2.2, Exhibit 2.2 shows the expected timing of remaining activities.

Exhibit 2.2: Schedule of Remaining Activities

Week 1 6 5 4 32 7 8 9

Aug 26Aug 12 Aug 19 Sep 2 Sep 23Sep 9 Sep 16Jun 3Week ending Friday

Jun 17Jun 10 Jun 24 Ju1 1 Jul 15Jul 8 Jul 22 Ju1 29 Aug 5

5. Define & assess network options

6. Prepare economic model

7. Deliver Interim Present.

8. Confirm optimal

configuration

4. Assess geothermal

development costs

13. Prepare Draft Final Report

11. Assess tariff & concessionaire impacts

15. Submit Final Report

10. Assess transaction feasibility

9. Formulate development framework

12. Formulate policy & regulatory changes

14. Draft Final

Present.

10 15 14 13 1211

3. The Load Forecast…

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3. THE LOAD FORECAST

Electricity demand is driven by: The price of electricity National income (GDP) Consumers’ access to electricity ie connections.

As noted in Section 2.2, the load forecast is disaggregated into three components: A forecast for the area currently served by UNELCO A forecast for the unserved areas of Efate as part of the distribution extension

expected under the geothermal project A forecast reflecting the impact of a Government program to improve access by

subsidizing connections, which would apply to both currently served and currently unserved areas.

Each forecast is discussed in turn below, highlighting the assumptions about price, income and availability used for that forecast.

3.1 LOAD FORECAST WITHIN THE AREA SERVED BY UNELCO

Exhibit 3.1 shows UNELCO electricity sales on Efate by tariff class.

Exhibit 3.1: 2010 UNELCO Electricity Sales (MWh) by Tariff Class

Note: “Other” consumption is thought to be largely residential in nature.

The electrical energy sales forecasts prepared by UNELCO as part of its “Electricity Tariff Review” submission of March 2010 and the URA’s own review of the same adopted a top down approach that does not disaggregate load growth by tariff class, but rather is based on overall economic growth. Both URA and UNELCO noted the close correlation between real GDP and energy growth rates from 1999 to 2009 (R2 = 0.98) and concluded that growth in energy sales within the UNELCO concession will continue to track real GDP growth rates. Both URA and UNELCO therefore anticipate load growth of between 3 to 4% per annum in the 2010 to 2014 period based on forecasts of GDP growth, under “business as usual” conditions.


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The introduction of geothermal could reduce electricity tariffs. The actual impact of changing power prices on energy sales over the period 1994 to 2009 indicates relatively price inelastic demand (-0.2). The introduction of geothermal energy should however lead to increased price elasticity reaching -0.3 to -0.4 as consumers adjust to the ongoing long term impact of lower (and less volatile) power prices. We have therefore adjusted the UNELCO/URA load forecast to account for this potential price impact by assuming the project’s geothermal power is supplied at its projected “real” cost of service for base load duties in preference to diesel generation and that UNELCO serves the balance of the load at its current “real” cost of service. Our preliminary calculations show that a 4MW geothermal power plant could reduce the current cost of service of 54 VT / kWh by 6% to 51 VT per kWh and by a further 10% to 46 VT per kWh when a second 4MW unit comes into service.

UNELCO’s concession area encompasses large areas that are currently not served. Exhibit 3.2 shows the extent of the concession area (based on information provided by UNELCO).

Exhibit 3.2: The UNELCO Concession Area

UNELCO has not released its future distribution investment program, so it is unknown whether UNELCO plans to extend its grid to currently unserved areas within the concession area (e.g. Port Havannah). We have therefore prepared separate forecasts for the currently served areas and the currently unserved areas. However, even within the areas served by UNELCO, there are a significant number of unconnected households. UNELCO’s 2010 Annual Technical Report indicates that it has some 8,017 consumers in the domestic and other low voltage categories, which is likely dominated by higher income households. This compares to the 2009 census which indicates there are 9,477 households on Efate that enjoy grid-supplied electricity, out of a total of some 13,186. (To the extent that consumers in the other low voltage tariff class are non-residential, this discrepancy would be greater).

Based on discussions with consumers in Port Vila, this discrepancy can be explained by the fact that due to the high cost of “official” electricity connections, the purchase of electricity


3-3


from neighbors or the sharing of a metered connection among several households is common. (In one case, a consumer reported that he had lived in an area in which 20 households were served from a single meter).

The 2009 census reports shows that 7,551 of the 9,054 households in the Port Vila urban area, have access to electricity and approximately 1,500 households don’t. The census also shows that out of a total of 3,700 households outside Port Vila only 423 have access to grid electricity. Exhibit 3.3 shows the 2009 distribution of unconnected households within the current service area and the households outside the existing service area.

The unserved households will be targeted under the distribution extension and infill programs described below – including with due allowance for continuation of the current 5% per annum growth rate in the number of houses on Efate.

Exhibit 3.4 shows the resulting demand forecast for the currently served area, and the impacts of the infill and geothermal components of the project.

Exhibit 3.4: Demand Forecast for Currently Served Area

Exhibit 3.3: 2009 Household Grid Connections on Efate


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The algorithm for calculated load with geothermal and infill components has been developed from the actual energy sales for the period 1994 to 2009 with price and GDP as the independent variables plus consumption by infill connections.

The chart shows that the Infill program would have a limited impact on total demand given that new consumers in the low to average income bracket consume modest amounts of electricity. (However, as noted in the cost / benefit analysis there is nevertheless significant economic benefits from the Infill program as households substitute kerosene and diesel with electricity).

3.2 LOAD FORECAST FOR THE UNSERVED AREA

In the unelectrified areas of Efate there are established and potential new demands for energy from consumers, which can be characterized as follows:

1. Village Residences – households of varying socio-economic circumstances with demands for energy services being met by small petrol generator sets, LPG, kerosene lamps for light, and charcoal and wood for cooking.

2. Potential New Residential Developments – coastal areas that have been sold (leased) by villagers have created a potential demand for electricity from both cashed up vendors and buyers (developers) who build housing for foreigners.

3. Resorts – from the sizeable developments serviced by captive (in –house) diesel generators and potential smaller establishments that could be set up by villagers.

4. Institutions – schools, health clinics, and churches.

5. Commercial organizations - shops and small businesses.

Other potential loads of significance could be imagined, such as if the defunct Forari manganese mine were to restart operations. However, there is no indication that such loads will materialize, and hence they have been excluded from the analysis.

The approach for forecasting demand involves estimating the number of potential consumers, the demand for each class of consumer, and then aggregating the different consumers’ demands into a comprehensive forecast.

In the residential sector the level of demand for electricity from newly connected households depends on household income, the price of electricity, and the availability of substitutes such as wood or charcoal for cooking. The impact of these variables on willingness to pay for the energy services from which demand for electricity is derived can be illustrated by charting demand curves for low income, average income, and high income households, as shown in Exhibit 3.5.

Consumers are prepared to pay highly for the first few units of energy services, but their willingness to pay declines markedly as their consumption increases giving the classic concave demand curve1. As shown in Exhibit 3.6, energy consumption continues to rise as price declines until the demand curve meets the x axis (abscissa) at Qα that is determined by a household’s ability to purchase appliances and pay for house wiring.

1 Refer Report No. 53963-GLB “A New Slant on Slopes: Measuring the Benefits of Increased Electricity Access in Developing Countries”, (World Bank)


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Exhibit 3.5: Demand Curves by Household Type

Exhibit 3.6: Impacts of Changing Price on Household Electricity Consumption

We have therefore developed profiles of household energy consumption needed to meet demands for energy services for high, average, and low income households. The sources used to develop the consumption profiles by household include information on consumption gleaned from discussions with villagers in Efate, from Household and Income Expenditure Survey (HIES) data on the reported income and consumption patterns of households at different income levels throughout Efate, and by synthesizing estimates using data from other similar countries that have gone through the electrification process. This information on energy use has been combined with information from the local market on the prices / costs of the energy sources used by local householders and with information on the efficiency of the appliances used by householders to obtain the energy services they need.

The results for average households in both the three highest and the three lowest deciles are summarized in Exhibit 3.7.

0

200

400

600

800

1000

1200

1400

1600

0 5 10 15 20 25 30 35 40 45 50

Willingness to Pay / Vatu per kWheq

Composite Demand for Outputs of Energy Services / kWheq per household per month

P1

Cost Savings P0Qo - P1Q1

P0

Q1 Q0

Incremental Benefit

∫Willingness to Pay Q0 to Q1


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Exhibit 3.7: Estimated Impact of Access to Electricity on Household Consumers

Consumption for an average household in the middle income brackets has been taken as the average of the high and low income averages.

Consumption Unit Unit Cost Energy Content Energy UseRelative

Efficiency 1 /

Energy Services (Q)

HH's Effective Cost (P)

Expenditure

Units / Month Vatu / Unit kWh / Unit kWh / Month % kWheq / Month Vatu / kWheq Vatu / Month

Charcoal / Wood 54 kg 40 7.00 379.17 1.00% 3.79 571 2,167

Petrol (Generator) 22 litre 281 9.00 193.50 6.53% 12.63 478 6,042

Kerosene 4 litre 280 9.58 38.31 0.47% 0.18 6,265 1,120

Dry Cell Battery 3 No 100 1.53 4.59 60.00% 2.75 109 300

Gas 6 kg 200 12.70 76.20 10.00% 7.62 157 1,200

PV Electricity 0 Unit 95 1.53 0.00 93.3% 0.00 0 0

Total 26.98 401 10,828

Charcoal / Wood 45 kg 40 7.00 315.00 1.00% 3.15 571 1,800

Petrol (Generator) 0 litre 281 9.00 0.00 6.53% 0.00 0 0

Kerosene 2 litre 280 9.58 19.16 0.47% 0.09 6,265 560


Gas 3 kg 200 12.70 38.10 10.0% 3.81 157 600


Total 11.23 299 3,355

Charcoal / Wood 20 kg 40 7.00 140.00 1.00% 1.40 571 800

Petrol (Generator) 0 litre 281 9.00 0.00 6.53% 0.00 0 0

Kerosene 1 litre 280 9.58 9.58 0.47% 0.04 6,265 280


Gas 3 kg 200 12.70 38.10 10.00% 3.81 157 600


Grid Electricity 72 kWh 21 1.00 72.00 54.4% 39.20 39 1,545

Total 45.37 73 3,325Charcoal / Wood 40 kg 40 7.00 280.00 1.00% 2.80 571 1,600Petrol (Generator) 0 litre 281 9.00 0.00 6.53% 0.00 0 0Kerosene 1 litre 280 9.58 9.58 0.47% 0.04 6,265 280Dry Cell Battery 1 No 100 1.53 1.53 60.00% 0.92 109 100Gas 3 kg 200 12.70 38.10 10.00% 3.81 157 600PV Electricity 0 Unit 95 1.53 0.00 93.33% 0.00 0 0Grid Electricity 25 kWh 17 1.00 25.00 54.44% 13.61 31 416

Total 21.18 141 2,996

Household Energy Consumption - Per Month

Upper 3 Deciles w/o Access

Lower 3 Deciles Grid Connected

Upper 3 Deciles Grid Connected

Lower 3 Deciles w/o Access

Energy Source

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Prior to electrification the high income households tend to utilize petrol generators to meet their needs for lighting, cell phones, and TV/DVD players among other items, and LPG for cooking. At low levels of household income the householders rely mainly on kerosene and candles for lighting, and wood or coconut shells for cooking, although some have a PV (solar) lighting system.

Electrification (in the currently unserved areas) will affect a mix of households from high, average, and low income groups; the weighted average household demand has been estimated by using the proportions of household income reported in the HIES and is expected to be 50 kWh per month per newly connected household. Total demand is then dependent upon the number of households that are connected and the growth in total residential demand. Annual growth in total residential demand will be subject to the same influences as in other developing countries that have been electrified. Namely, growth in demand is driven by growth in national GDP (income elasticity of 0.8 and is subject to impacts of changes in the tariff (price elasticity of -0.4).

Exhibit 3.8 shows how demand would develop if the first 31% of the houses (those lying within 500 m of the distribution network) in the currently un-served areas are electrified over a three year period from 2012 to 2015, together with progressive steady on going electrification of rural households as: (i) new houses are built (household growth rate in rural areas is currently almost 6% per year), and (ii) the distribution facilities are extended sufficiently to reach 80% of houses by 2020. These assumptions will be refined as the assignment progresses and more detailed electrification plans are developed.

Exhibit 3.8: Growth in Demand by Distribution Extension

Growth in non-residential demands of all types is initially expected to come from electrification of public facilities, such as schools and health clinics, with demand from commercial businesses (SMEs, shops, guest houses, and some major resort loads) accelerating from a small base. By 2025 non-residential demand could account for a one-third of total new demand, based on experiences in Samoa when Savai’i (which in many ways is very similar to Efate) was electrified following the development of a new ring road.


3-8


3.3 THE INFILL DEMAND FORECAST

Costs of connection in Efate (house wiring costs of the order of USD 1,000 plus connection fees etc.) are exceptionally high and helps explain why many households in the existing electrified areas do not have a connection or share a connection. The following table developed from the data in Exhibit 3.9 shows households’ cost savings and benefits from a grid connection - for the average high income and the average low income household.

Exhibit 3.9: Financial Affordability of House Wiring

Household High Income Low Income

USD / Month USD / Month

Energy costs before connection 127.39 39.47

Energy costs after connection 39.11 35.25

Cost savings 88.28 4.23

Incremental benefits 46.73 24.40

Wiring cost 1,000.00 1,000.00

Months Months

Payback from savings 11.33 236.53

Payback from benefits + cost savings

7.41 34.93

Note: The payback from savings is the time taken to recover the costs from the household’s reduced payments for energy once connected. The payback from benefits + cost savings includes the benefits of increased energy to a connected household.

The long paybacks show that electricity connections are generally unaffordable for all but high income households. The infill program will be designed to address this by combining competitive procurement / tendering procedures to reduce costs with funding and subsidies that will help households fund their costs of connection.

The “infill program” will affect average and low income houses within the existing service areas and all houses in the newly electrified areas. The expected distribution of houses by income that will benefit is based on the HIES and is summarized in Exhibit 3.10.

Exhibit: 3.10: Income Profiles of Houses for Infill Program

Households Low Income Average Income High Income

Current Service Area 53% 47% 0%

Distribution Extension 44% 25% 31%

The infill demand forecast assumes that all high income houses in the current service area are already connected. Demand from the average to low income houses (at the first block price of the tariff) would therefore be 30 kWh per month per household.

Unless income testing is adopted then all houses in the “to be electrified areas” could benefit from the support provided by the infill program. Average demand from houses in rural areas is expected to be 50 kWh per month (including high income households).


3-9


The resulting impact of the Infill Program on residential demand is summarized in Exhibit 3.11.

Exhibit 3.11: Demand Forecast for the Infill Program

3.4 DEMAND FORECAST SUMMARY

Exhibit 3.12 compiles all three forecasts into a single forecast. The “Geothermal Power” demand is the incremental demand due to the price impacts of geothermal on the base demand forecast. The principal observation is that the contributions to demand growth from grid extension and infill programs are insignificant relative to the UNELCO demand. These programs are therefore virtually irrelevant to the attractiveness of the geothermal project; had the demand growth associated with this programs been larger, it may have enable a larger geothermal plant to be developed, which may have further reduced electricity prices due to economies of scale. In addition, this exhibit demonstrates clearly the geothermal project’s dependence on UNELCO demand. There is no alternative other than to sell the power to UNELCO.

Exhibit 3.12: Consolidated Demand Forecast for Efate

4-1


4. GEOTHERMAL RESOURCE SCENARIOS

4.1 CHARACTERISTICS OF GEOTHERMAL POWER

There is more than 10,000 MW of geothermal power installed around the world. While geothermal energy offers an environmentally friendly source of electric power that can reliably serve base load power needs, it does have characteristics that must be addressed for successful development:

Geothermal resources are uncertain. Although geothermal energy potential is frequently indicated by surface manifestations such as hot springs, the quantity of geothermal power available at any particular site cannot be reliably estimated until extensive exploration activities have been performed. This uncertainty creates risks for geothermal developers, as their investment in geothermal exploration is lost if it does not prove a commercially viable resource leading to a project.

Exhibit 4.1 shows how developers typically address exploration risk by making incrementally larger investments in exploration based on successful results from the previous stage of exploration. While the cost of initial geological surveys and subsequent geochemical and geophysical studies are on the order of hundreds of thousands of dollars, exploration drilling costs on the order of millions of dollars.

However, even after exploration results indicate a commercial viable resource, there have been well documented instances where geothermal resources decline precipitously after the start of production, resulting in wasted capacity and investment. Exhibit 4.2 shows power output profiles for two well-known cases of this, The Geysers in California, and the Ohaaki field in New Zealand. Resource risk remains through the geothermal project lifecycle.

Exhibit 4.1: The Geothermal Development Process

4. Geothermal Resource Scenarios…

4-2


Exhibit 4.2: Resource Risk Remains after Plant Commissioning

Example: Ohaaki, New Zealand

Example: The Geysers, California

Geothermal resources are diverse. Even if we knew with certainty the amount of energy available from any particular geothermal prospect, the characteristics of each geothermal field are unique. Reservoir volume and temperature, phase, porosity, recovery factors, problems of scaling or acidity all vary from field to field, required careful engineering and specialized technologies. One size does fit all for geothermal power development.

Geothermal energy is non-tradable. Geothermal energy in the form of brine or steam can only be transported short distances. So while geothermal exploration shares some risks similar to oil & gas development (e.g. exploration risk), the risks of geothermal development are compounded by the credit risk associated with the buyer of geothermal power, since there are no alternative buyers. Offtaker creditworthiness & conditions of the power purchase agreement (PPA) are critical.


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Geothermal exploration risk cannot be reduced, only allocated. Because of the resource risks they assume, geothermal developers typically seek higher returns on their investments than, for example, developers of conventional power projects. Higher returns make for higher tariffs. Unfortunately, there is no way around the need to conduct exploration and assume the associated risks of failure. However, governments in many parts of the world have sought to promote geothermal development and to reduce geothermal power tariffs by sharing exploration risks with developers. Numerous schemes have been used, including government-financed exploration, concessional lending to developers by governments for exploration activities, and insurance type schemes that can compensate developers for the costs of unsuccessful exploration.

Exhibit 4.3 shows how uncertainty of project success at various stages of geothermal development affects the nature of financing.

Exhibit 4.3: Risk and Financing Throughout the Geothermal Development Cycle

These characteristics affect how geothermal power is developed. In this particular case, the Government of Vanuatu will need to decide whether it will share any of the exploration risk with the developer of the Efate prospects in advance of knowing whether development of these fields will be successful. This is discussed further in Chapter 8.

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Identification Exploration Drilling Production

0.5 ‐ 1 5 ‐ 10 4 130 ‐ 140

Equity Financing Mezzanine Debt

Bridging Financing

Construction Financing Project Financing

Development Phase

Typical costs for 50 MW plant (US$ million)

Probability of success (%)

Souce: Deloitte, Geothermal Risk Mitigation Strategies Report, USDOE, February 2008

Current stage for Efate

prospects


4-4


4.2 THE EFATE GEOTHERMAL RESOURCE

As noted in Section 1.1, based on the geochemical and geophysical studies it has conducted in its license areas, KUTh has identified three targets and reported net power production estimates for each as shown in Exhibit 4.4. For each prospect, the table indicates probability that the prospect will yield power indicated. A value of probability P10, P50 or P90 indicates that there is a 10%, 50% or 90% probability that the resource contains that amount of heat. A P90 value is more conservative than a P10 value and represents a conservative assumption for development purposes.

Exhibit 4.4: KUTh Estimates of Power Output Distributions at Each Prospect

In its press release of 5 October 2010, KUTh further designates the Takara prospect as its initial target:

Target C (Takara) has been selected for initial development because of ease of access, strong indicators of a commercially viable resource and the ability to support the proposed project development of an initial 4 MWe net off-take, with the possibility of further expansion to a second similar unit in the near future. Target B (Central) is the preferred secondary target to support production at Takara because of the ease of supplying a single plant at Takara from that location.

Based on a review of materials KUTh made available to the consultant team, including primary magneto telluric data covering the prospects, we concur that Takara is the best candidate for initial development. This is not to say there is no exploration risk at Takara; even though these results are encouraging, there remains a non-zero probability that the prospect might not support a commercially viable power station.

We also concur with KUTh’s plan to target a 4 MWe net capacity plant, with the possibility of expanding capacity. Staging of geothermal plant capacity is a common (and prudent) strategy to better understand the characteristics and behavior of the geothermal reservoir prior to further investment in drilling, field facilities and power plant. Once the prospect is proven through the operation of the initial power station, it can then be expanded as the resource, power demand and commercial arrangements allow.

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5. SYSTEM CONSIDERATIONS

It is important to determine how the proposed geothermal generation can be integrated into the existing Port Vila system and the diesel and wind generation operated by UNELCO. Regarding system operation, there do not appear to be major problems. With the first geothermal unit, some diesel generation will always be required and if diesel generators are operated at loads in the region of 20 to 30%, they should be able to supply the extra power needed while also backing up the geothermal generation. One factor that should be considered regarding backup is the fact that geothermal generation is normally extremely reliable and, as indicated by data provide by the Met Department as well as observations about UNELCO’s distribution designs, there is not much of a problem with lightning on power lines in Efate. Therefore, power supply from the geothermal station should be very reliable indeed. If, instead of always keeping reserve diesel generation online to provide for loss of the transmission system, UNELCO installs under-frequency relays that would shed load in the event of a loss of the transmission line, a very large saving in operating costs would be achieved with very little reduction in overall reliability. Because diesel engines can be started very rapidly, it would only be a few minutes before the load that had been shed was restored. A further complication is the possible effect of the wind farm. It has a maximum rated output of just over 3025 kW but it seldom operates at outputs above about 2700 kW. Based on 2010 data, its output appears to be less than 300 kW for half the time. Its annual capacity factor appears to be around 20%. Most wind farms around the world operate at between 25 and 30%. (Note that these statistics are based on a short period of operation and higher figures may result from a longer period of operation.) The best windfarms sometimes achieve 40%. Though the first three years operating data from the wind farm does not indicate a clear seasonal pattern, the Vanuatu Meteorological Services note that the dry season (May to October) is characterized by persistent winds, whereas during the wet season (November to April) winds are light and variable. However, during its relatively short period of operation, it appears that the highest average monthly wind speeds occurred during the wet season. Of potentially greater importance though are the diurnal patterns of wind As shown in Exhibit 5.1, the minimum system demand for 2010 was about 3.5 MW (18 July 2010) and the maximum peak demand was 11.2 MW (22 January 2010). To get some idea of the shape of the load curve in 2016, by which time the first geothermal unit is expected to commence operation, the 2010 loads from the UNELCO report were escalated by a factor of 1.27 (approximately 4% per annum). Because the load duration curves in the 2010 UNELCO Annual Technical Report suggest that the base load is increasing at a more rapid rate than the peak demand, the escalation factor during the early hours of the morning was increased slightly. When the 4 MW expected from the first geothermal unit is plotted on this curve, it appears there would not be any periods when the UNELCO load on Efate was less than 4 MW. It appears that the system could absorb all the output available from the 4 MW generator. One thing that should be kept in mind is that electrification of the areas outside the present UNELCO concession is unlikely to produce much additional early-morning load. Rural load tends to concentrate in a short morning peak for cooking and a longer evening peak for cooking lighting and maybe television.

5. System Considerations…

5-2


Exhibit 5.1: 2010 Minimum & Maximum Day System Load Curves for Efate

Source: UNELCO 2010 Annual Technical Report Assuming that a second 4 MWe net unit commenced generation in 2018, a similar analysis shows that even after allowing for a new rural loads, a small amount of power available in the early hours of the morning could not be absorbed in the cool season. This effect was only likely to last for a few years and so would not have a significant effect on the overall economics of the second unit. Even if 10% of generation could not be absorbed initially, the second geothermal unit would still be delivering electricity at a cost well below that of diesel generation. Exhibit 5.2 shows the analysis for 2016 and 2018.

Exhibit 5.2: Forecast Minimum and Maximum Day Load Shapes for Efate

It does not appear than the system could absorb another 4 MWe net unit over the time horizon considered by this study. Therefore, for the purposes of this study, the largest geothermal plant capacity scenario is 8 MWe net.

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6. GEOTHERMAL DEVELOPMENT SCENARIOS

Based on Chapters 4 and 5, we consider three geothermal development scenarios:

A scenario in which exploration at Takara fails to prove a commercial viable geothermal resource, i.e. a 0 MWe capacity scenario. As discussed in Section 4.2, though unlikely, this remains a non-zero probability.

A scenario in which exploration proves a commercially viable resource that can support a 4 MWe net geothermal power plant, but no more than that. Assuming binary technology, we refer to this as the 5 MWe gross scenario. This corresponds to KUTh’s initial development plan for Takara as discussed in Section 4.2.

A scenario in which the maximum capacity allowed by the system over the time horizon of this study can be implemented. Based on the discussion in Chapter 5, we refer to this as the 10 MWe gross scenario (which assuming binary technology would be roughly 8 MWe net power capacity).

To explicitly account for the uncertainty in the size of a commercially viable geothermal generator that could materialize, we have assigned probabilities to these scenarios as follows:

It is more likely that there is a commercially viable prospect than not, i.e. P5 + P10 > 50%

A 5 MWe gross prospect is more likely than a 10 MWe gross prospect, which is more likely than no plant at all, i.e. P5 > P10 > P0

The probability of a 5 MWe gross resource is twice as great as a 10 MWe gross resource, i.e. P5 = 2 * P10

There is nonetheless a non-zero probability that the Takara prospect might not be commercially viable, i.e. P0 > 0%

We have rounded the probabilities for P5 to multiples of 10% for ease of reference and since there is no reason to ascribe greater accuracy than that to these estimates.

These assumptions allow for two different permutations of resources and probabilities:

P0 = 10%, P5 = 60%, P10 = 30%; or

P0 = 25%, P5 = 50% and P10 = 25%

For the initial economic analysis, we will use the more conservative of the two possible permutations.

We further assume that if 10 MWe gross case materializes, it will be implemented as 5 MWe to be installed first, followed by an additional 5 MWe gross plant two years later.

For costing purposes, we assume the following conditions:

Binary cycle assumed

6. Geothermal Development Scenarios…

6-2


Hot brine resource. We assume a base case mean reservoir temperature of 150 degC and a base case drilling depth of 1.5 km. We will also assess a sensitivity case to reflect a mean reservoir temperature of 190 degC, and the depth +/- 0.5 km.

Sea water cooling system

Flow characteristics. The Takara Springs near the target prospect flow at an estimated 110 li/s. We will consider two cases should be for sensitivity: a “best case” of fully artesian flow, and a “worst case” of pumped flow.

Climate conditions are based on data from the Vanuatu Meteorological Services website.

We will prepare a notional process flow diagram (including heat and mass balance), an indicative plant lay out, a preliminary sizing of equipment and component costing in the format of Appendix D.

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7. NETWORK DEVELOPMENT SCENARIOS

7.1 LINE ROUTES

7.1.1 The Ring Road

From observation of the ring road corridor during the field visit of April 2011 and information later obtained from the Public Works Dept it is clear that the construction of a pole line is feasible within the existing road corridor. The roadway has been well formed with an 8m sealed carriage way centered on a 15m wide road reserve corridor. No vegetation exists in the road reserve corridor and vegetation trimming has been undertaken on land approx 3m bordering the road corridor to ensure that no vegetation overhangs or encroaches the 15m wide road reserve.

Concrete drainage channels exist parallel to the road in some stretches. These occupy the space up to 2m out from the edge of seal. There is 1.5m remaining between the drainage channel and the road reserve boundary. It will be possible to install poles against the outer edge of the drainage ditch incorporating pole head designs that do cross the roadway boundary.

The Public Works Dept noted that soils along the roadway corridor were generally of sufficient strength upon which to safely construct the road. It is expected that these soils will be suitable for installing poles without the need for special pole footing enhancement techniques or major soil replacement. Two stretches of swampy soils were identified in “Section 1” of the road between Mele and Napkoa Creek, and in “Section 3” between Napara and Baofatu. Pole footing enhancements are likely to be required for poles installed in these sections.

It is generally expected that the powerline could be constructed without large scale encroachment of conductors into private land. Some encroachments will be unavoidable however. The winding nature of the road corridor in certain areas will necessitate generally short spans with many angle poles. Angles beyond approx 15 degrees deviation will require side guy supports. Guy wires will encroach into private land in almost all cases.

Additional vegetation removal beyond that which has been undertaken to construct the road will be required in many areas along the route. The standard of vegetation clearance should be fall distance clearance. This is to ensure the reliable performance of the line particularly during cyclones.

Vegetation clearance for utility works is allowed under Vanuatu legislation. Compensation of landowners for lost vegetation may be required in some cases under this legislation.

7.1.2 An Interior Route

A transmission line route across the interior of the island has been considered.

However, there are no existing foot tracks through the interior and the vegetation is very dense and in its indigenous state.

A contour map of Efate Island has been reviewed. There is potentially a low elevation (below 280m) line route through a geological trench feature (the Teuma Graben) which runs north-south and extends two thirds of the way into the interior from the southern coast. This trench is approximately 1.6km wide. The trench is suspected to be fault

7. Network Development Scenarios…

7-2


trench. Such trenches are apparently common on the sea floor along the edge of the Pacific tectonic plate. The Pacific tectonic plate edge runs right up through Vanuatu.

Aside from the inherent risks of building a transmission line close to a fault line, the route is densely vegetated with virgin tropical forest.

A pre-requisite for a transmission line is the establishment of a 60-80m wide clear corridor through the vegetation, incorporating an all-weather four wheel drive access track. There is little scope to ridge hop on the interior route to avoid corridor establishment.

The incremental distance to go around the island road is approx 30km. It is expected that incremental costs of running the transmission circuit over the distribution on the same poles for 43km will be significantly less than the cost of establishing the 20km long corridor and transmission line through the interior.

7.2 TRANSMISSION CONSIDERATIONS

Loadflow modelling of a roadside transmission circuit has revealed that injection of the proposed geothermal energy into a 20kV distribution circuit is limited by voltage rise constraint to approximately 4 MW at peak generation. Line losses at this level of generation however are significant at approx 300kW. Whilst this may be acceptable for short term peak load generation, it is expected that the geothermal plant will be generating with a very high plant factor. Lost energy would therefore accrue to around 2.6 GWh each year at an approx cost to the people of Vanuatu of US$500,000.

Given that even under the smallest geothermal development scenario, geothermal plant capacity at the busbar is approximately 4 MW. Therefore, the energy from the geothermal plant should be transmitted to Vila via a dedicated transmission system. Information from UNELCO is that 60kV is a standard French transmission voltage. This would be a suitable voltage level for Vanuatu. At such a transmission voltage the interconnecting line would have capacity for continuous injection of geothermal power up to 20MW.

The transmission system would comprise a 3.3/60kV generation substation, a single 60kV transmission circuit and 60/20kV interconnection substation at Tagabe.

Conductor for a 60kV transmission line is recommended to be of minimum csa of 60mm. This minimum is specified to avoid corona discharge from the conductor in the humid air conditions prevalent in Vanuatu. Corona discharge can create radio frequency interference in moist air conditions and cause corrosion of energized conductors and line hardware.

7.3 DISTRIBUTION CONSIDERATIONS

Loadflow modelling of a 20kV overhead line distribution circuit up to 102km long has been undertaken. Load distribution along the line was aligned with the positioning of existing villages around the ring road route from Mele to Teuma.

The loadflow modelling establishes the following limits for total distributed load for two aluminum conductor sizes as shown in Exhibit 7.1. The circuits do not include any auxiliary voltage support such as distributed capacitors.


7-3


Exhibit 7.1: Candidate Distribution Conductors

CONDUCTOR CSA (sq mm) Line Loading Limit

Mink ACSR 62.2 1.2MW

Dog ACSR 103.8 1.8MW

It is recommended that Dog ACSR or an equivalently rated AAAC conductor is deployed. This is the likely optimal conductor size given the expected load, the expected load growth and the type of line that can be cost effectively constructed in the ring road corridor.

7.4 RING ROAD LINE DESIGN

7.4.1 Principal Characteristics

Line Design using software programs has been undertaken to establish the optimal parameters for a separate and combined joint transmission and distribution lines.

Suitable poles for the lines are either treated softwood or tubular galvanized steel type. Concrete poles despite having the benefit of high strength and long life are not expected to be an economic option due the high mass and resulting high shipping cost to Vanuatu from either New Zealand or Australia. There are termites in Vanuatu that will attack untreated wood poles.

Vanuatu is subject to regular tropical cyclones. These cyclones regularly pack winds of speeds up to and exceeding 120km/hr. The line will be designed to withstand winds of 180km/hr.

The line design must incorporate a degree of lightning surge protection. It has been observed that UNELCO fit lightning arrestors at all pole mounted substations and high voltage cable to overhead line terminations. There are no isolating fuse links at pole substations however, indicating that transformer insulation failure from lightning surge is infrequent or rare. The surge arrestors are therefore doing a good job in Vanuatu. Analysis of the fault outage information requested from UNELCO may verify this.

There appears to be no risks of outage to overhead lines from either bird life or climbing animals.

Due to the high wind speed specification required for all lines, the line designs are high strength. The line design process has identified that designing the ring road pole line to be strong enough to carry LV distribution as well as HV conductors would be not be cost effective. Villages tended to be centred away from the road, therefore LV distribution along the ring road will be intermittent. This would result in very intermittent use of the strength provisioning. It is expected that the majority of LV circuits would not be run along the ring road but out from substations within the villages. All LV distribution lines are therefore proposed to be run as dedicated pole lines.

Given that the lines are also to be built within a fairly narrow and winding road corridor, then short spans (up to 75m) using readily available and cost effective moderate strength poles is the most appropriate design solution.


7-4


The ultimate generation of 20MW sets the optimum transmission circuit conductor size at 100 sq mm. DOG ACSR conductor has the necessary aluminium csa but given the short spans, the equivalent sized but lower strength all aluminium WEKE conductor could also be used (slightly lower cost conductor and less resistance giving slightly higher capacity).

The use of 100 sq mm conductor for the 20kV distribution circuit would allow the circuit to be extended to meet the entire island ring at the expected and short term foreseeable load.

Therefore the joint transmission and distribution line has been designed assuming DOG or WEKE conductor for both transmission and distribution. When the load reaches the point that the long distribution circuit is voltage constrained, then the circuit would be extended into Port Vila (underground cable required) and made into two circuits with an open point at the halfway mark (Ekipe). One circuit then fed from Port Vila, the other from Tagabe.

A single circuit 60kV transmission only option has been separately costed. This is based on 11m 12kN wood poles. Vertical high pollution rated polymeric post insulators on steel crossarms are proposed. Earthing of crossarms at each wood pole is required to avoid pole fires in the event of insulator failures. This increases the wood pole cost but not to the point that steel poles become more cost effective.

A single circuit 20kV distribution only line has been designed and costed. This is also based on 11m 12kN wood poles. Pin insulators on earthed steel crossarms are also used in this design.

A double circuit 60V transmission and 20kV distribution line has been designed and costed. The optimum pole to attain necessary line strength in this case is a 12.5m Steel 24kN pole.

For lightning protection of the distribution line, the existing practice of UNELCO to install arrestors at every distribution transformer and HV cable termination would be adopted.

For surge protection of the transmission circuit an overhead earth wire over the transmission circuit for the last 2km from the ends of the circuit would be installed. The transmission circuit would terminate at Mele and at the geothermal plant substation. This overhead earth wire would act to attenuate surges induced into the transmission line. Poles used for the two 2km end sections would be 14m 24kN steel poles.

Protection of the transmission circuit would consist of earth fault detection at the 60kV transformer at the geothermal station, with an intertrip over fiber to the circuit breaker at the Tagabe station. Protection of the distribution circuit would consist of reclosers positioned approx every 30km along the line, all possibly linked via the fiber. The design also allows for an air break isolator every 10km along the distribution line to assist with fault isolation.

7.4.2 Envisaged Structures

For the joint transmission/distribution line, a single pole double circuit line of open wire 60kV transmission over open wire 20kV distribution will be the basis of the design, as shown in Exhibit 7.2. Poles of approx length 13m will be required.

For the HV distribution, a single pole single circuit of open wire 20kV is the basis of design, as shown in Exhibit 7.3. Poles of length 11m will be required.

All LV circuits will be run on single circuit 11m wood poles, as shown in Exhibit 7.4.


7-5


Exhibit 7.2: Joint Transmission & Distribution Pole

7.4.3 Distribution Spur Lines and SWER

From observation of GIS records, almost all villages are located within 4km of the ring road. This means that spur lines to the villages will be relatively short. Some villages are small enough to be supplied from single phase HV supplies.

Exhibit 7.3: 20 kV Distribution Pole

Exhibit 7.4: LV Distribution Pole


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Single Wire Earth Return (SWER) HV systems could be considered for the smaller villages that are more remote from the ring road.

Each SWER system requires an isolating transformer substation at the take-off point from the main line. The major cost advantage in a SWER line system with respect to a two wire single phase HV system is that only one conductor is required. This cost saving is offset however by the cost of the isolating transformer substation. SWER systems are generally only economic over two wire systems when the length of the spur line is greater than approximately 3km. There is one village that is more than 3km from the ring road (from GIS records). This is Malarip village. Further information on the size and layout of Malarip village is required before it can be determined that a SWER spur line would be suitable for this spur line extension.

7.5 FIBER TELECOMMUNICATIONS

Fiber optic cable can be run around the ring road and supported on the HV circuit pole lines. Consideration has been given to the use of fiber cable which is embedded with LV conductors along the ring road line. This option has been rejected for the reason that LV distribution will not be continuous along the line route.

It is recommended that the fiber cable is run as a separate cable with its own catenary member, which is a high strength tube typically containing 12, 24 or 48 fibers. The proposed fiber cable is a high strength Kevlar tube containing the fibers and oversheathed with a PVC outer. The fiber is run along the pole line but dropped to a connection pit at each village so that all fiber cable joints and connections are made at ground level. If electronics are used, interconnecting local fiber distribution with main trunk line fibers, then a ground mounted cabinet would be installed next to the pit. Catenary Fiber distribution of this type is in common use in electricity distribution networks in New Zealand.

There are 37 Villages along the line route of the proposed ring road distribution line. A 48 fiber cable is recommended in order that a single fiber linking each village directly with Port Vila is provided.

For fiber runs along LV only pole lines within the village, the use of LVABC cable with an embedded fiber cable may be considered.

One or two of the fibers would be dedicated to transmission and distribution circuit protection.

7.6 CONSUMER CONNECTIONS AND NETWORK LOADING

Distribution network loads have been built up from the GIS data provided in terms of villages, schools, health centres and resorts around the ring road. A map of Efate showing the locations of these principal points of interest is given in Exhibit 7.5. The village data was provided in four size classifications. There are 37 villages in total around the ring road that are positioned outside of the UNELCO reticulation. The villages are mainly centred close to the ring road but some are up to 4km away from it.

It has been assumed that the average Class 4 village has 120 households, Class 3 has 97, Class 2 has 73 and Class 1 has 40. This sums to 3,000 households potentially. At 0.5kW ADMD per household at the distribution transformer, and allowing 1.2kW ADMD for the Health Centres and Schools and including 200kW ADMD for two large resorts, the total peak distributed feeder load is 1790kW. The single end feed 20kV ring road WEKE


7-7


conductor line has capacity for 1.8MW evenly distributed. There is therefore likely to be sufficient capacity in this line. If the ADMD turned out to be higher than this then the double end feed extension could be completed before all loads were connected. The double end feed two circuit system has an evenly distributed load peak capacity of 2 x 3.5MW.

Exhibit 7.5: Location of Principal Points of Interest

7.7 COST MODELLING

A capital cost model has been developed from consideration of the information collected in Vanuatu and from information and experience in NZ. Excerpts from the model are given in Appendix E.

The model is a building blocks model with worksheets that cost out individual components of lines and substations etc and bring these costs together. The worksheet entitled “Line Details” contains the quantities of each of the building blocks. The worksheet entitled “Component Costs” combines building block costs and quantities to provide overall costs for each of the major system components. Finally the system components are brought together in the front worksheet entitled “Summarised Scheme Costs” to give the overall costs off various scheme options. A single line diagram is provided to outline each scheme option.


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Unless otherwise stated, all figures in the spreadsheet model are in New Zealand dollars (NZD).

Labour rates are based on expected chargeout rates from New Zealand contracting companies working in Vanuatu. A relocation, travel and accommodation overhead of NZD 380 per day per person has been assumed. A nine hour working day has also been assumed. The assumption is that this project would be tendered out to companies from NZ and Australia.

House and Institution connection and wiring rates are reduced to reflect the local ex patriat labour rates

Materials costs are based on costs in NZ plus about 15%. This could be a little pessimistic because many items used in NZ come across from Australia, and probably could be delivered to Vanuatu for similar costs.

In the costing model a 25% connection rate has been assumed across the island initially. It is not possible to accurately model further without more solid information on the number of houses and their spatial layout in a typical village. At 25% each village could be supplied from a single centrally positioned distribution substation.

Beyond this more substations and LV distribution may be required. Connection costs include building wiring costs for houses and village institutions. No allowance is made for the connection and wiring of resorts. It assumed that resorts would fund all of their connection costs back to the ring road 20kV distribution line.

A 48 fiber self supporting cable together with an in-ground connection pit at every village has been allowed for and separately costed. No allowance has been made for local fiber distribution as yet.

Three scheme options have been analysed for costing in the model. These are:

1. Distribution Only – This scheme is a 20kV single pole distribution line from Mele in the northwest of the island to Teouma in the southeast. This scheme assumes that no geothermal generation operates. The scheme is single end fed distribution from Mele via an interconnection with UNELCO’s existing 20kV cable.

2. Transmission Only – This scheme is a 60kV transmission system consisting of an interconnecting substation at Tagabe Substation, an underground 60kV cable, single circuit overhead line to a generator transformer substation at the Geothermal generation site.

3. Full Scheme – This is a combined geothermal generation with 60kV transmission to Tagabe substation, and 102km ring road 20kV distribution line from Mele to Teouma.

All of the 3 schemes costed assume that 25% of rural households are connected.

The capital costs of these scheme options are summarised in Exhibits 7.5 to 7.7.


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Exhibit 7.5: The Distribution Only Configuration

DISTRIBUTION ONLY SCHEME

SUMMARISED DISTRIBUTION ONLY SCHEME COSTS

Units Cost NZ$ Cost US$ Cost US$/UnitMele to Quoin Hill Distribution Line with Fibre 43 5,310,462$ 4,248,369$ 98,799$ Mele 20kV Interconnection Station 1 224,600$ 179,680$ 179,680$ Quoin Hill to Epao Distribution Line with Fibre 15 1,845,510$ 1,476,408$ 98,427$ Epao to Teouma Distribution Line with Fibre 44 5,298,496$ 4,238,796$ 96,336$ 20kV 2 Phase Spur Lines 5 284,780$ 227,824$ 44,066$ 20kV 3 Phase Spur Lines 15 870,774$ 696,619$ 47,486$ 20kV Line Air Break Switches and Reclosers 12 190,501$ 152,401$ 12,700$ LV Distribution Lines (25% of Households Connected) 22 1,646,918$ 1,317,534$ 59,348$ Distribution Substations (25% Households Connected) 39 481,617$ 385,294$ 9,879$ NETWORK TOTAL 16,153,658$ 12,922,926$

Consumer Connections (25% Uptake and including Building Wiring) 825 2,790,983$ 2,232,787$ 2,708$ OVERALL DISTRIBUTION ONLY SCHEME TOTAL (25% HOUSEHOLDS CONNECTED) 18,944,641$ 15,155,713$


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Exhibit 7.6: The Transmission Only Scheme

Exhibit 7.7: The Full Scheme (Transmission & Distribution)

TRANSMISSION ONLY SCHEME

SUMMARISED TRANSMISSION ONLY SCHEME COSTSUnits Cost NZ$ Cost US$ Cost US$/Unit

Mele to Quoin Hill Transmission Line and Fibre 43 6,916,240$ 5,532,992$ 128,674$ Mele to Tagabe 60KV Underground Cable and Fibre 5 2,388,750$ 1,911,000$ 382,200$ Tagabe Substation Extension 25MVA 60/20kV 1 1,125,000$ 900,000$ 900,000$ Quoin Hill Geothermal Plant Substation 25MVA 60/3.3kV 1 1,380,000$ 1,104,000$ 1,104,000$ TOTAL 11,809,990$ 9,447,992$

FULL SCHEME

SUMMARISED FULL SCHEME COSTSUnits Cost NZ$ Cost US$ Cost US$/Unit

Mele to Quoin Hill Transmission and Distribution Line with Fibre 43 10,128,439$ 8,102,751$ 188,436$ Mele to Tagabe 60KV Underground Cable with Fibre 5 2,388,750$ 1,911,000$ 382,200$ Mele 20kV Interconnection Station 1 224,600$ 179,680$ 179,680$ Tagabe Substation Extension 25MVA 60/20kV 1 1,125,000$ 900,000$ 900,000$ Quoin Hill Geothermal Plant Substation 25MVA 60/3.3kV 1 1,380,000$ 1,104,000$ 1,104,000$ Quoin Hill to Epao Distribution Line with Fibre 15 1,845,510$ 1,476,408$ 98,427$ Epao to Teouma Distribution Line with Fibre 44 5,298,496$ 4,238,796$ 96,336$ 20kV 2 Phase Spur Lines 5 284,780$ 227,824$ 44,066$ 20kV 3 Phase Spur Lines 15 870,774$ 696,619$ 47,486$ 20kV Line Air Break Switches and Reclosers 12 190,501$ 152,401$ 12,700$ LV Distribution Lines (25% of Households Connected) 22 1,646,918$ 1,317,534$ 59,348$ Distribution Substations (25% Households Connected) 39 481,617$ 385,294$ 9,879$ NETWORK TOTAL 25,865,385$ 20,692,308$

Consumer Connections (25% Uptake and including Building Wiring) 825 2,790,983$ 2,232,787$ 2,708$ OVERALL FULL SCHEME TOTAL (25% HOUSEHOLDS CONNECTED) 28,656,368$ 22,925,095$

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8. IS THE EFATE GEOTHERMAL PROSPECT A “GAME CHANGER”?

The consultant team has developed and applied an economic model to determine whether geothermal development is in the best interests of Vanuatu. The model utilizes the preliminary cost and performance estimates for the network and geothermal development options discussed in the preceding chapters. This model has been integrated within a decision analysis framework to explicitly reflect uncertainty in key parameters that affect the costs and benefits of geothermal development. These are preliminary results that that will be further refined in the next stage of the assignment.

8.1 ECONOMIC ANALYSIS

The economic evaluation has analyzed the costs and benefits of the following components of the project:

1. Geothermal Power Generation Project: to utilize Efate’s geothermal resource(s). This includes the associated transmission line to bring power to Port Vila.

2. Infill Connection Project: to assist low to average income households finance their costs of connecting to the distribution system (house-wiring, connection fees, and appliances). This includes many households lying within the areas serviced by the current distribution network, who cannot afford a connection.

3. Grid Extension Project (to electrify areas in Efate that lie outside of the existing distribution network), and

The model calculates the costs & benefits in “economic” terms for each sub project. The recognition of these costs and benefits is summarized in Exhibit 8.1. Benefits are recognized with respect to existing and/or new consumers who may be connected under the infill and distribution extension components. The annual net benefits of these streams of costs and benefits are then discounted at the economic cost of capital (12%) and summed to determine the economic net present value of each scenario.

Exhibit 8.1: Recognition of Economic Costs and Benefits

Component Cost Benefit

Exploration

by developer If successful = Cost excluding taxes & duties, plus economic cost of capital If unsuccessful = 0

No benefit

by Government If fungible = Cost excluding taxes & duties, plus economic cost of capital If non‐fungible = 0

Downstream benefit of additional economic surplus from lower prices, if exploration is successful

Geothermal Plant & Transmission

Cost excluding taxes & duties, plus economic cost of capital

1. Operating costs of displaced diesel generation 2. Additional economic surplus due to lower prices

Distribution extension

Cost excluding taxes & duties, plus economic cost of capital

1. Costs of displaced energy for new connections resulting from grid extension

2. Additional economic surplus for new connections resulting from grid extension

Infill Program Cost excluding taxes & duties, plus economic cost of capital

1. Cost of displaced energy for new connections resulting from lower cost access

2. Additional economic surplus for new connections resulting from lower cost access

8. Is the Efate Geothermal Prospect a “Game Changer”?…

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The detailed conversion factors used in the model are presented in Appendix F, and Appendix G shows the main sheets of the model.

The model does not consider the:

Benefits of energy security associated with geothermal power

The benefits of price stability associated with geothermal power

The environmental costs and benefits (both local and global) related to both diesel and geothermal power supply.

In this respect the analysis is conservative.

The results of the economic analysis are shown in Exhibits 8.2 and 8.3 for 5 and 10 MWe gross projects respectively. In economic terms, the impact of Government exploration support is relatively small since the cost under these scenarios is the same as no Government support, while the benefit is due only to the economic impacts of the lower cost of electricity that can be expected.

Exhibit 8.2: ENPV of a 10 MWe gross Geothermal Plant on Efate

“High oil price” is 20% higher than May 2011 prices. “E&A” refers to “exploration & appraisal”, refering to the exploration drilling efforts. The Government’s share of these costs in the scenarios in which it shares exploration cost is 50%.

(1,000)

(500)

‐

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Current Oil Price High Oil Price Current Oil Price High Oil Price

No E&A Share No E&A Share With E&A Share of 50 %

With E&A Share of 50 %

VT Million

Grid Extension

Infill

Geothermal 10 MW


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Exhibit 8.2: ENPV of a 5 MWe gross Geothermal Plant on Efate

In addition to ENPV, the team calculated the levelized cost of electricity (LCOE) produced by geothermal and diesel power. Whereas ENPV assess benefits and costs and thereby suggests whether the project should be supported from a national perspective, LCOE is the single “price” such that present value of production equals present value of total life-cycle costs. It is purely a measure of costs, and does not capture any benefits. LCOE can be used to:

Help identify the least cost generation option for new generation When stated in financial terms, can be used to estimate the impact on cost of

service relative to generation alternatives Exhibit 8.4 shows the LCOE for diesel and geothermal under various scenarios.

Exhibit 8.4: LCOE of Diesel and Geothermal Generation under Various Scenarios

In the most favorable case, the power generated from a geothermal station would be roughly half the price of diesel power. Geothermal could certainly be a “game changer” in Efate’s energy future, especially since geothermal would “lock in” these savings regardless of the trajectory of future diesel prices. But in so far as certain key parameters such as the size of the geothermal plant that could be developed remain uncertain, so too does the potential contribution of geothermal power to Efate’s development.

Generation Costs Diesel kWhs 1*4MW Geo 2*4MW Geo

Economic

LCOE Economic US¢ [2011] / kWh 29.4 28.5 22.5

Financial

LCOE w/no GoVexploration support

US¢ [2011] / kWh 34.1 27.9 21.5

LCOE with GoVexploration support

US¢ [2011] / kWh 34.1 19.9 16.3


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8.2 DECISION ANALYSIS

The economic model tells us the ENPV of any given scenario. However:

The value of some key input parameters are uncertain

The Government needs to make certain decisions prior to the resolution of these uncertainties. For example, the Government needs to decide whether it will share exploration risk in some form as part of the arrangements that will allow exploration drilling to proceed. If it decides to share this risk, and the geothermal resource does not materialize, then it would lose the value of its exploration support.

Decision analysis is a tool to support decision-making under uncertainty. For example Exhibit 8.5 shows a simplified version of the decision the Government faces with respect to exploration risk sharing. The square green node indicates a Government decision (whether or not to share exploration risk). The round red node represents the uncertainty in the geothermal resource; probabilities can be ascribed to each of the potential outcomes (whether or not there is a commercially viable resource). Finally the blue triangles represent the potential outcomes from the Government’s perspective, as measured by the ENPV.

If the Government shares exploration risk, and a commercially viable geothermal resource materializes, then it achieves the best possible outcome: the lowest possible electricity prices and the highest ENPV. However, if the resource does not materialize, it loses the value of the exploration risk that it has taken. This is the worst possible outcome, since not only do electricity prices remain high, but it has also lost the value of its exploration support.

On the other hand, it if does not share exploration risk and commercially viable resource materializes, then it receives a good outcome: a high ENPV, but not as high as if it had shared the exploration risk, since the developer will be entitled to earning higher returns on a higher capital base, recognizing the additional risk it has taken. And finally, if it does not share exploration risk, and a commercially viable resource fails to materialize, then the Government is no worse off. It has not lost any money, but there is no positive ENPV; the developer simply bears the entire loss.

Exhibit 8.5: Simplified Decision Tree Example

GOV shares exploration cost

no GOV exploration cost sharing

Commercial resource

No resource

Commercial resource

No resource

Best outcome

Worst outcome

Neutral outcome

Good outcome


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Decision analysis takes into account the probabilities of uncertain events and the value of possible outcomes to help decision makers select options that yield the highest expected value. In this respect, decision analysis distinguishes between good outcomes and good decisions. We can never guarantee good outcomes, but we can make good decisions that reflect our knowledge of potential costs, benefits and likelihood of uncertain events occurring. In the case presented in Exhibit 8.5, the Government’s optimal decision will depend upon the values of each of the potential outcomes, and the probabilities we ascribe to the likelihood of the two geothermal outcomes. Decision analysis helps the government to decide where to place its wagers.

All three subprojects (geothermal/transmission, distribution extension, and infill) would become integral components of the Efate supply system. The configuration, costs and benefits of these depends on the following decisions and uncertainties:

Decisions regarding: o Whether the Government shares exploration risk with the geothermal

developer o Whether the Government proceeds with the Infill Program

Uncertainties regarding: o The size of a commercially viable geothermal resource o The future cost of diesel fuel

The economic model is integrated within a decision analysis framework using “Precision Tree2”, and Excel modeling tool. As a first step we have structured the decision tree based on two decision nodes (whether or not to share exploration risk, and whether or not to proceed with the infill program) and two chance nodes (the size of the geothermal development, and the future price of diesel fuel). Exhibit 8.6 shows the conceptual model.

Exhibit 8.6: The Preliminary Decision Model

This analysis will be refined during the interim mission based on discussion and feedback with principal stakeholders.

2 Palisade Corporation

Two options:• Government takes exploration risk

• All exploration risk left to developer

Government Exploration Support

Decision

Geothermal Resource

Uncertainty

Three possible outcomes:• No resource• 5 MWe gross• 10 MWe gross

Two options:• Government undertakes program

• Government does not undertakeprogram

Infill Program

Decision

Fuel Prices

Uncertainty

Three possible outcomes:• Low escalation• Baseline• High escalation

Outcome

Economic Net Present

Value


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8.3 LOOKING AHEAD

There are several immediate tasks to be completed in the next stage of the assignment, the interim mission. These include:

Collect remaining data o average hourly wind farm output by month (UNELCO), or o average hourly wind speeds by month (Met Service); and o GIS data of households locations, composition, and sources of lighting and

cooking energy for Efate (NSO)

Finalize network and geothermal plant designs & costings

Refine economic and decision analysis

In addition, the consultant team will start to address several strategic issues:

Confirm Government’s commitment based on these preliminary findings

Gain a better understanding of the costs and benefits from UNELCO’s perspective of different geothermal development scenarios, since UNELCO would be the only possible offtaker for the geothermal electricity

Identify principal development options in terms of commercial and regulatory packaging and structure.

Exhibit 2.2 showed our updated workplan for the remainder of the assignment, bearing in mind these immediate and strategic tasks.

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APPENDIX A: TERMS OF REFERENCE

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VANUATU

Pre-feasibility study of Efate geothermal power plant and island ring

grid development program (2011-2025) Scope of Work

Study Context The Republic of Vanuatu is an archipelago of 82 volcanic islands. It covers a total area of about 12,200 square km - of which about a third is land, the rest ocean. While the population of about 243,000 is spread over the 65 inhabited islands, about 30% of the inhabitants are concentrated on Efate Island. The national capital city - Port Vila on Efate Island - accounts for approximately 14% of the national population; and access rates in the main urban city centre and immediate environs are about 75%, dropping off sharply just a few kilometres distance.

The Government of Vanuatu (GOV) has among its top priorities, improving infrastructure access and lowering the cost of doing business in Vanuatu. As part of the approach to addressing these priorities Efate island has recently undergone a marked improvement in road infrastructure with completion of a circle ring road around Efate island. The increased accessibility to markets made possible by this new road will help stimulate agriculture and tourism outside the immediate environs of Port Vila. The Government is also interested to facilitate expansion of main grid electricity service along the newly opened ring road corridors, while aggressively seeking to promote low cost renewable energy base load electricity generation, such as from geothermal and hydro resources where feasible. UNELCO, a subsidiary of the Suez Energy Group, has the sole right to generate and distribute electricity within the four mainly urban concession areas on the islands of Efate, Espirito du Santo, and parts of the islands of Malekula and Tanna. In Port Vila, the concession is in force until 2031 and provides for exclusive rights to generate and supply electricity within a 15 km radius of the city boundaries. UNELCO’s Port Vila concession serves

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about 9,000 consumers. The system has an installed capacity of about 23.5 MW (20.4MW diesel) and a peak load of about 11 MW. Generation is predominantly diesel (over 14 million liters of diesel fuel consumption annually), and is currently being blended with approximately 10% coconut oil (CNO). UNELCO currently has 3MW installed wind capacity. Due to grid integration issues, no further wind generation capacity can be considered at the current load. UNELCO is currently considering a grid-connected solar PV option as well. Electricity retail tariff levels are high in the concession areas, due to the monopolistic nature of the concession and due to the high costs of fuel (both diesel and coconut oil). The high cost electricity supply is imposing an unduly high expenditure burden on poorer household budgets and results is real hardship (very limited lighting, refrigeration, water pumping), inadequate health facilities (very limited electrical health equipment and vaccine refrigeration), disadvantaged learning environment (very limited evening classes and computers), poor communications (very limited radio and internet), and fewer economic activities (very limited cool rooms and electrical equipment). These tariff levels contribute as well to a high cost of doing business for the private sector. Geothermal energy resource on Efate A number of promising geothermal sites have been identified in the course of geo-scientific studies undertaken by a private company under an exploration license. The most promising resource identified to date is the prospect on the north side of Efate Island. MT scans have been completed and indicate a potentially attractive resource. The company is in the process of raising financing for the drilling of the initial holes for resource confirmation and delineation. Subject to further confirmation, it is anticipated that a largely commercially-financed power plant would be developed on the basis of a power off-take agreement with UNELCO. The GOV would like to employ a framework – policy, regulatory, financing – appropriate for the high cost high risk upstream phase of resource drilling for confirmation and delineation; suited for the subsequent phase – lower risk high capital costs – of geothermal power plant staged development. Such a public-private-partnership framework should be designed at the outset in accordance with good practice principles that steer the development in a transparent manner to least cost outcome as measured by the bulk supply tariff charged to UNELCO as the off-taker. Additionally the GOV’s priority is to endure that that UNELCO customers benefit to the

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fullest extent from savings from the least cost geothermal electricity generation (compared to diesel) via the retail tariff setting mechanism. This would help address the biggest issues for the Efate grid electricity sector: increased security of supply by replacing to the maximum extent high cost imported diesel and substituted by clean indigenous energy resource; lowering tariffs to improve affordability to households and businesses; and expansion of the grid service to increase access as widely as possible. Further, the Government recognizes that the structuring of the project would impact the overall benefits of the project for Vanuatu. Geothermal resource development for base load power generation coupled with electricity grid development along the circle road potentially offers a “game changer” opportunity for the energy sector on Efate, provided the framework for implementing development and financing the power plant and network is effectively structured. Several issues need to be carefully considered in order for the geothermal resource be effectively and efficiently developed and in a timely manner. These include designing and orchestrating a public-private partnership framework for risk-sharing and financing to ensure timely and transparent development and at least cost, while ‘crowding in’ private financing. Related investment needs include transmission, distribution and connection costs to maximize the access expansion aspect of the geothermal development, and could potentially include costs associated with resettlement compensation.

Study Objectives The objective of the study is to determine whether the Efate Geothermal resource and associated interconnection and ring grid network lines are the long term least cost electricity generation option for Efate, consistent with the GOV’s goal of enhancing security of supply on Efate and expanding affordable access island-wide. The study is to recommend an approach, based on the necessary review and analysis, and considering institutional, regulatory, technical, reliability, existing concession agreements and safeguard aspects, for developing the Efate Geothermal resource to achieve the least cost bulk power supply to UNELCO as well as for supplying new demand growth projected on account of lower cost generation and associated transmission and distribution network. The ultimate developmental objective is to lower the cost of power supply – bulk and retail – to the extent economically feasible, while also expanding grid access island-wide.

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Scope of Work Task 1 - Load forecast for Efate Island. The objective of this task is to develop the Efate island-wide electricity forecast – energy and peak demand and number of connections - for the planning horizon 2011-2025. For the existing UNELCO concession area the consultant shall primarily review available information and load forecast data from UNELCO and the Utilities Regulator (URA) including annual reports, submissions to the Utilities Regulator; and review and take into consideration economic data and demographic trends. Based on this information, the consultant shall; (i) develop the load forecast disaggregated by major consumer/tariff

category; (ii) Develop a connection forecast disaggregated by consumer/tariff

categories; and (iii) Determine the sensitivity of connections and electricity demand to

price – consistent with the extent to which lower cost bulk power supply is likely available from the geothermal power generation - and connection charge policy.

Load forecast outside the UNELCO concession area - This component comprises potentially new loads arising from development of an extended grid outside the concession area along the new coastal ring road encircling the island. This component of the forecast should be disaggregated by residential connections, small and medium commercial consumers, and should identify discreet big loads separately. The load forecast methodology and analysis, while commensurate with a pre-feasibility level analysis, should be sensitive to key drivers of electricity influencing demand in Vanuatu; in particular, affordability of electricity price, connection charge/subsidy policy. Uncertainty in future demand growth along the ring shall be considered by the consultant; by defining alternate scenarios of load development consistent with current plans and prospects and under a scenario of accelerated load growth linked to aggressive promotion on a pro-active basis. Task 2 - Dimensioning, preliminary design, and least cost MV and LV network reticulation outside UNELCO concessional area

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The outputs of this task are: (i) the analysis, options assessment and preliminary design and cost of

the recommended, technically appropriate, least cost option for extending the MV network reticulation along the island ring road; and

(ii) Analysis, options assessment and preliminary design of the associated LV network – including SWER spurs inland - for maximizing the number of economically-viable new connections to the network;

(iii) Technical feasibility and incremental costs of utilizing MV bundled

conductor together with an integrated fiber-optic cable. The specifications for the fiber optic bandwidth capacity will be determined in consultations with the telecoms regulator.

In particular for the green field ring MV grid development, the Consultant shall evaluate the option of a single phase MV reticulation upgradeable to three- phase subsequently if load growth merits such upgrading in future. Additionally to maximize the number of new connections at least cost, the consultant shall also assess the technical option of utilizing single wire earth return reticulation as spurs off the ring MV grid to connect smaller load clusters that are otherwise not economically/technically feasible to serve with single phase MV lines and LV reticulation. The analysis should indicate the most effective application of subsidy, should this be available. Task 3 - Comparative cost analysis of Efate geothermal base load power plant generation and other generation alternatives - The consultant shall conduct a levelized cost analysis of Efate geothermal power option compared with existing generation - diesels of UNELCO, a wind plant of UNELCO - and any other prospective generation options under consideration, such as grid connected solar PV. In this task the Consultant shall also analyze the dispatching profile and compatibility of the proposed Efate power plant and its operating characteristics, within the daily dispatch and merit order stacking of UNELCO’s existing and planned generating stations (2011 and beyond over the planning horizon). Data on typical day load curves (differentiated by weekday and weekend, and season if appropriate), on the UNELCO system

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shall be obtained from UNLELCO with assistance of the URA and the GOV. Task 4 - Least cost Efate generation expansion program and geothermal power plant sizing and staging (2011-2025) The consultant shall conduct appropriate system expansion planning modeling and analysis, taking into account the load forecast developed, as well as the merit order dispatch and variable operating costs of existing UNELCO generation plant, and system stability and reliability considerations. This task shall develop recommendations for the optimal initial sizing of the Efate geothermal power plant; taking into consideration the available information on the quality and technical characteristics of the geothermal resource and best technological option for converting the steam resource into electricity. In addition, the analysis shall develop recommendations for the optimal staged expansion of the Efate geothermal power plant in appropriate increments to match load growth, and retiring diesel plant and considering the economics of geothermal power plant modules readily available on the market. An integral output of this task shall be the identification of any generation “stranded assets” on account of the least cost system expansion plan identified with the Efate plant optimally sized. Specifically, this analysis of the least cost system expansion plan with and without the Efate plant option, shall consider among other factors: the generation from all power stations of UNELCO at present and projected, based on a production simulation costing analysis to determine the least cost merit order dispatch and stacking profile by generation plant (s). The system expansion plan and optimal sizing and time staging of the geothermal power plant shall take into consideration the reliability criteria relevant to the Efate grid system ; such as generation planning reserve margin (or LOLP), and any other planning reliability criteria used such as N-1contingency.

Key data inputs for this analysis - for example for each generating unit the incremental heat rates, forced outage rates, maintenance down times, fuel and non-fusel variable costs and fixed O&M costs - shall be obtained from UNELCO with the assistance of the URA and GOV.

Task 5 – Interconnection configuration, design, and costing for evacuating geothermal power generation. The geothermal resource is located on the north side of Efate Island while the main load center of

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UNELCO concession around Port Vila is in the southern area of Efate. In this task, the consultant shall develop recommendations for the interconnection option (s) appropriate to supply to the UNELCO grid system; as well as supplying power for the ring grid outside UNELCO area; taking into account system stability, voltage and other operating considerations, costs and significant environmental considerations. Among the options to be reviewed and considered are direct transmission links through the interior of Efate to a suitable delivery point(s) in the UNELCO concession network. Task 6 – Financial and tariff related issues analysis The consultant shall determine, based on analysis under the above tasks and explicit assumptions where necessary, the financial cost-based price of bulk supply from Efate power plant consistent with the least cost expansion program dimensioning and staging, and delivered to UNELCO at a suitable delivery point; and estimate the impact on UNELCO’s “reference price” per URA’s building block tariff methodology. Task 7 – Commercial analysis The consultant shall analyze key factors – such as power purchase tariff for UNELCO, implications thereof for base retail tariff, treatment of stranded assts - which could limit or discourage UNELCO from entering into a Power Purchase Agreement for a lower-cost source of supply and any elements which could limit the pass-through of the benefit of lower cost supply via the retail tariff to UNELCO’s customers. The consultant should recommend solutions to address any constraints identified. In this analysis, the consultant should consider a situation in which of financing new generation includes some public funding. Task 8 - Options for structuring ownership, legal framework, bidding arrangements, management, and risk-sharing and financing structure, for the geothermal drilling, power plant and ring grid development under a PPP framework and other appropriate alternative. The consultant shall analyze suitable options and develop recommendations for various ownership structures with specific analysis of a PPP structure suitable and workable for Vanuatu, to ensure a transparently-determined least cost development of electricity generation which may include the Efate geothermal power plant and bulk supply tariff while extending grid access to the maximum extent that is technically feasible and economically viable.

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Task 9 - Review of Geothermal Act, Electricity Supply Act, Utilities Regulatory Authority Act, existing concession agreements and current terms of licenses and / or other agreements with the prospective geothermal developer. The consultant shall undertake a review of the current Act and its provisions. The objective is to identify key ambiguities and major gaps in coverage and substance that need to be addressed and strengthened to ensure that GOVs policy and regulatory framework for geothermal resource development – exploration, exploitation - is on par with good relevant practices, and can support effective and efficient development of the geothermal resource for the maximum benefit of the nation. The consultant should recommend any adjustments to address deficiencies. The consultant should review the existing license and any other agreements, including Heads of Agreement or similar or MOU between the prospective geothermal developer and UNELCO and identify any issues or constraints the GoV should be aware of and recommend actions to address these. Task 10 - Global Environmental Benefits The consultant shall conduct the requisite analysis to estimate the carbon reduction benefits projected from the Efate geothermal power plant development program reommended in this study. Schedule and deliverables The work is expected to be undertaken over a four month period starting about January 25, 2011. The inception report would be due four weeks after the start of the assignment The draft final report no later than three months from start date. Final report within two weeks of receipt of comments on draft final report. Consultant Qualifications The project team must have demonstrable relevant and substantial expertise and experience in the following areas that are required to successfully undertake this assignment:

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Team leader: at least a Masters’ Degree or equivalent with extensive experience in one or more of the key areas identified below – PPP frameworks, geothermal resource development, system planning – and preferably including in Pacific island contexts. The team leader must have demonstrably substantial track record of project management experience leading teams.

Geothermal resource and policy specialist (a) technical specialist to review resource potential data and risk analysis to date, review heat extraction and power generation plant technology options and key technical and cost performance parameters thereof , and specification of key data inputs for the production costing and simulation analysis and long term least cost generation epsilon (b) international expert highly knowledgeable with first hand working familiarity and versed in geothermal national policy and regulatory frameworks for resource development in relevant good practice situations worldwide.

Institutional expert on PPP framework options appropriate for the Efate geothermal power development program for the three major components: upstream resource confirmation and delineation, power plant development, and the island grid development.

System planner well versed with island grid systems planning and an expert in production costing and simulation of merit order dispatching of generating units _ diesels, wind, solar PV, geothermal caseload.

Network power engineer for design and costing of the MV, LV and reticulation, and interconnection of the Efate geothermal power station to the island grid fro bulk power delivery to UNELCO. He/she must have demonstrated expertise in design and costing of MV network reticulation – including especially single phase MV network reticulation upgradable to three phases, Single Wire Earth Return - and LV network and connections rollout.

Legal and regulatory expertise to provide advice on impact of exisiting concession agreement, Acts etc and tariff setting methodology.

Load forecasting for small network systems and financial and economic analysis;

10

Excellent quantitative modeling skills.

Experience in developing country contexts, and preferably relevant experience and expertise in Pacific island electricity sector context; as well as with geothermal projects on the scale relevant for Vanuatu.

Since the assignment will require visits to Vanuatu, and Sydney, Australia, proximity to these locations will be a benefit. (this will be captured in the price)

B-1


APPENDIX B: KICK-OFF PRESENTATION

1

Vanuatu: Pre‐feasibility Study for Efate

Geothermal Power Plant and Island Ring

Network Development

Kick‐off Presentation14 April 201114 April 2011

Agenda

• Current situation

• Assignment objectives

• What makes geothermal different?g

• Preliminary work plan

• Data needs

• Next steps

2

2

Current situation

• Dependence on diesel for power generation– Relatively small island systems

– Results in high costs and low affordability

• A low electrification ratio– Efate is 87% of generation and 73% of customers

– Only about half of Efate’s population lives within the Port Vila concession

– About 75% of those have electricity perhaps only 25,000 out of 75,000 have electricity on Efate

• UNELCO holds the concession for Port Vila• UNELCO holds the concession for Port Vila

• The Utilities Regulatory Authority (URA) established to:– regulate prices, standards and market conduct

– protect electricity and water consumers

3

The promise of geothermal

• Introduction of new, less costly generation could significantly improve affordability & the electrification ratio

• Efate’s geothermal power potential offers such a prospect– Prospecting since 1970s

– KUTh obtains two prospecting licenses on Efate in April 2009

– October 2009 KUTh announces MoU with UNELCO to sell geothermal power

– KUTh estimates P90 potential of:

• Mt Fatmalapa (A): 15 MWe

• Central (B): 7 4 MWe• Central (B): 7.4 MWe

• Takara (C): 9.6 MWeh

4

• Similar sized systems have been contracted elsewhere for ~20 US¢/kWh

3

Governing legislation & contracts

Geothermal Energy Act

Electricity Supply Act

(and Amendments)

Efate Geothermal Development

Utilities Regulatory Authority

A

Geothermal Energy

(Prospecting Licenses)

5

ActRegulations

Port Vila Concession Agreement

Assignment objectives

• A unique opportunity to develop an environmentally friendly, less costly source of power generation a potential “game changer”

• The objectives of the assignment are therefore to:– Define and cost the principal technical options outside Port Vila

concession

• geothermal power generation

• associated network

– Determine the economically optimal option, taking into account :

• the potential for displacing diesel generation in the Port Vilathe potential for displacing diesel generation in the Port Vila

• new service to areas outside the concession

– Identify commercial and regulatory solutions to achieve these benefits in a manner that considers all stakeholder interests

6

4

What makes geothermal energy different?

• Geothermal resources are uncertain– Although it decreases as exploration & development progress,

uncertainty remains throughout the geothermal project lifecycleuncertainty remains throughout the geothermal project lifecycle

• Geothermal resources are diverse– volume, temperature, phase, porosity, recovery, scaling, acidity, etc.

• Geothermal energy is non‐tradable– Can only be transported relatively short distances

– There is no “international market” for geothermal power; not like oil

– Offtaker creditworthiness & conditions of the power purchase– Offtaker creditworthiness & conditions of the power purchase agreement (PPA) are critical

7

Not all geothermal resources are worth developing

The geothermal development process

• Development is staged to minimize risk

• Investment is incremental as uncertainty is reduced

8

5

Uncertainty remains after exploration

The Geysers, California

Ohaaki,

New Zealand

9

Risk and financing through the development cycle

• Exploration costs are similar for both large and small fields50

60

70

80

90

100

of success (%)

• How are risks allocated?

• When is a price set?

• How is the benefit of competitive tendering balanced

0

10

20

30

40

50

De

skto

p

Re

co

nn

ais

san

ce

Ge

op

hys

ics

Exp

lora

tio

n D

rill

ing

De

lin

ea

tio

n D

rill

ing

Fe

asi

bil

ity

Pro

du

cti

on

Dri

llin

g

Fin

an

cia

l Clo

sin

g

Pro

du

cti

on

Dri

llin

g

Inje

cti

on

Dri

llin

g

Co

nst

ruc

tio

n

Probab

ility o

Current stage for Efate against the need

for financial commitment?

10

E D

Init

ial P P

Identification Exploration Drilling Production

0.5 ‐ 1 5 ‐ 10 4 130 ‐ 140

Equity Financing Mezzanine Debt

Bridging Financing

Construction Financing Project Financing

Development Phase

Typical costs for 50 MW plant (US$ million)

Souce: Deloitte, Geothermal Risk Mitigation Strategies Report, USDOE, February 2008

Efate prospects

6

The analysis will distinguish between two questions

• Utilizes decision analysis • Project packagingh l l

What is the economically optimal configuration?

How does GoV best implement it?

y

• Takes into account uncertainties in future events– geothermal resource

– fuel prices

– others?

• Recognizes the sequential nature of development

• Determines the optimal risk

– Separate geothermal exploration and development?

– Separate geothermal power generation from network development?

• PPP modality for each package– Management contract– BOOT– etc.

• Consider the roles for• Determines the optimal risk mitigation framework and network configuration

• To be addressed on first mission

11

• Consider the roles for competitive procurement and/or rate of return regulation

• To be addressed on the second mission

Policy issues arise for GoV in addressing each question

Determining economically optimal configuration

1. Define development scenariosa. size of geothermal development

b. network configuration: island ring vs. direct connection

2 Forecast demand2. Forecast demanda. identify drivers of demand under each development scenario

b. estimate hourly load shapes by tariff class

c. scale load shapes by demand drivers to estimate future load shapes

d. takes into account UNELCO demand forecast

3. Determine future system costa. calculate load duration curve for each development scenario

b conduct merit order stack taking into impact of windb. conduct merit order stack, taking into impact of wind

c. calculate corresponding capital and operating costs for each development scenario

4. Determine economic benefits of each development scenario

5. Calculate NPV of economic benefits minus cost under each decision path.

12

7

Develop geothermal resource scenarios

Apr 29Apr 15 Apr 22 May 6 May 27May 13 May 20 Jun 3Week ending

Jun 17Jun 10 Jun 24 Ju1 1 Jul 15Jul 8 Jul 22 Ju1 29 Aug 5

AssessAssess

financing

Preliminary work plan

1. Define initial options

Define & assess network

2. Develop Decision Tree Model

Finalize decision model

3. Prepare load

forecast

Assess geothermal development costs

Prepare interim

presentation

Deilverinterim prsntn.

Assess tariff impact

Assess concessn. impact

Assess concessn. impact

Develop Framework

financing options

Week 1 6 5 4 32 7 8 9

Define & assess network options

4. Define least cost gen mix

Prepare DFR

Defining the initial options

• Purpose to forecast load load forecasting

• 3 network options– island ring alone (or western

feeder alone?)

– direct connection alone

– island ring + direct

• 3 or 4 geothermal options– adopt KUTh/SKM work

14

Generation Scenarios

MV island ring with LV reticulation

MV direct to Port Vila & LV near geothermal

plant

MV direct to Port Vila & island ring,

LV reticulation

No geothermal assumes additional diesel gen)

4 MW geothermal

15 MW geothermal

Network Scenarios

8

Data needs

1. CIF and retail costs of kerosene and LPG

2. Industrial, commercial and tourism development plans on Efate

3. One year hourly load data

– diesel generation at busbardiesel generation at busbar

– wind generation at busbar

4. Network design parameters (climatic conditions, bird life, lightning frequency & intensity, climbing animal life, ground conditions, etc.)

5. Other rural electrification studies or analysis, e.g. populations outside concession area

6. Update of UNELCO 2009 Technical Report

7. Land ownership & acquisition

8. Investment promotion environment

9. Information on energy consumption patterns, e.g. household income & expenditure surveys

10. KUTh exploration license

11. Port Vila concession agreement

15

Next steps

• Follow up on data needs

• Schedule next meeting

16

C-1


APPENDIX C: DATA REQUESTS

1

Mike Crosetti

From: Mike Crosetti [[email protected]]Sent: Monday, April 18, 2011 4:24 AMTo: '[email protected]'Cc: '[email protected]'Subject: Data request

Dear Tony, Thanks for your voice mail on Friday. Per your request, I’ve attached below a list of information that we hope to obtain from UNELCO. I will give you a call this morning to confirm our meeting tentatively scheduled for 3 PM today. General

1. UNELCO’s views on how Efate geothermal potential should be developed 2. Soft copy of UNELCO 2009 and 2010 Annual Technical Reports

Generation

1. Hourly total diesel generation (outgoing from station) for 2010 for Port Vila concession (8760 hourly data) in a spreadsheet

2. Hourly total wind farm generation (outgoing from wind farm) for 2010 for Port Vila concession (8760 hourly data) in a spreadsheet

3. UNELCO’s generation expansion plan for Port Vila 4. Wind farm (pre)feasibility study

Distribution

1. UNELCO’s distribution and connection standards applied in Port Vila concession 2. Single line diagram of network 3. Geographic layout of network 4. End‐use customer delivered voltage and frequency standards and tolerances and if these are

mandated by regulation. 5. Annual outage statistics and breakdown of outages by cause. 6. Lightning storm frequency and intensity. 7. Prevailing wind direction 8. Wind storm frequency and intensity – peak wind speeds experienced. 9. Soil strengths and resistivity 10. Climbing animal life 11. Bird life that can clash lines or bypass insulators. 12. Any issues for timber poles e.g termites.

Customer and Load Data

1. Tariff class definitions 2. 1994 to 2010 annual sales (in both Vatu and MWh) with number of customers by tariff class for

Port Vila – for energy delivered to customers (includes those not invoiced) 3. For the lowest residential tariff block ‐ average monthly consumption for newly connected

households during 2009 and 2010 and the average consumption of all residential consumers in the lowest tariff block for 2009 and 2010.

4. UNELCO’s most recent forecast of peak system demand and energy generated for Port Vila 5. Number of households on connection waiting list and aging of applications in the Port Vila

concession.

2

6. Number of households that are neither connected nor on a waiting list of for service in the Port Vila concession.

7. Available information on current actual connection and house wiring costs, especially for the type of consumers who would have similar socio‐economic status to householders living outside Vila.

Thank you for consideration. Hope to meet you later today. best regards, mike Castlerock Consulting Graha Iskandarsyah, 7th floor Jl. Iskandarsyah Raya No.66C Jakarta 12160, Indonesia Switchboard: +62 21 270 2404 Fax: +62 21 270 2405 www.castlerockasia.com

1

Mike Crosetti

From: Mike Crosetti [[email protected]]Sent: Tuesday, April 19, 2011 5:01 AMTo: '[email protected]'Cc: 'Arun P. Sanghvi'; 'bruce smith'; '[email protected]'Subject: GIS data request

Hi Chris, Following our meetings yesterday, we would be grateful if you could request the following GIS data, to be provided as .shp files:

1. Population/households 2. Topography 3. Soil type 4. Roads and tracks, especially the new Efate ring road 5. Administrative boundaries, including Area Councils 6. Cadastral data 7. Boundary of the UNELCO concession on Efate 8. UNELCO network (even if this is just a raster file converted from a .pdf or other drawing) 9. Statistics enumeration areas 10. Schools and educational facilities 11. Clinics and other health facilities 12. Markets 13. Tourist resorts and commercial enterprises

We recognize that not all of this data may be available, but we hope you can get as much as possible. best regards, mike Castlerock Consulting Graha Iskandarsyah, 7th floor Jl. Iskandarsyah Raya No.66C Jakarta 12160, Indonesia Switchboard: +62 21 270 2404 Fax: +62 21 270 2405 www.castlerockasia.com

DATA REQUEST TO NSO We would kindly request your assistance in getting the following information from NSO in the electronic formats specified. There are three sources of data we are interested in:

2009 Census of Population and Housing

2006 Household Income and Expenditure Survey (HIES)

2010 HIES. We understand that this data is currently being processed. However if the data we are requesting for 2006 HIES is available for the 2010 HIES, we would like to get that information as well.

2009 Census We seek a .shp file (or files) with the following information:

Location and number of people in each household

Data from Table 9.11 of the Census report “Household’s main source of lighting”

Data from Table 9.12, “Households main source of cooking” 2006 HIES We seek the following information in the following four electronic formats (i.e. as multiple files):

CSPro

Stata

SAS

Text To be safe, it would be best to receive the entire dataset with all household identifiers and variables. However, if that is not possible, then we would seek the following excerpt of data, with reference to the 2006 HIES questionnaire. Please note, however, that there is no single variable for total household expenditure in the questionnaire, which is a key variable of interest. As is usually the practice, this is probably a variable calculated from other variables in the dataset. Therefore, if an excerpt is provided, we would kindly request that a variable for total household expenditure be created and included in the dataset.

Household Identifiers 1. Province 2. Island 3. Area Council 4. Enumeration area 5. Village Name 6. Household Number

Part I: 1. Dwelling Characteristics

1. 1.10 (main lighting fuel) 2. 1.11 (if electricity, source) 3. 1.12 (main cooking fuel)

Part I: 3. Transport and Communications

1. 3.1 (usual means of communications) 2. 3.2 (access to information) 3. 3.4 (distance to nearest road) 4. 4.1 (distance to usual market)

Part II (HH Expenditure): 1. Dwelling Tenure

1. 1.8 (payments related to dwelling in past 12 months), payment code 2 Part II (HH Expenditure): 6. Household Operation

1. 6.2 (appliances purchased in past 12 months), payment codes 1 through 27 2. 6.3 (bill amounts), accounts 5 and 7

Part III (Income & Production):

1. 2.5 (home made produce), type codes 1 through 7, (a) and (b) (sales and expenses) 2. 2.6 (handicrafts) 3. 3.1 (other self‐employed business), with detail (2), type of industry by 3‐digit ISIC

Whether we receive the entire data set, or just the subset, we will also require a catalogue defining the variable names for all data provided to us. If neither the entire data set nor subset are available, then please advise whether we may submit specific analytical requests to NSO for processing, e.g. cross‐tabulations by expenditure quartile etc.

D-1


APPENDIX D: GEOTHERMAL PLANT COST FORMAT

WORKSHEET 1: CAPITAL COST ESTIMATE PRIVILEGED AND CONFIDENTIAL

Project Name: Vanuatu 5 MW Binary Plant

6/11/2011 5:58 PM GDA

j yProject Size: 5 MWj

Project Length: 18 Monthsj g

1.0 PROJECT ADMINISTRATION COSTS DESCRIPTION Units Unit Rate Shipping COST pp g

1.1 Project Management j gHome Office Project management, administration 24 months $0j gSite Office Construction management, construction monitor 24 months $0g

1.2 Insurance Public Liability, Property Damage, Umbrella 24 months $0y p y g1.3 Permitting GDA technical support for permitting activities 24 months $0g pp p g1.4 Legal/Accounting Contract preparation, review, negotiations 24 months $0g g p p g1.5 Communications Long distance telephone, telefax, courier 24 months $0g p1.6 Travel & Per Diem Round trips between Home Office and Site Office 24 months $0p1.7 Local Transportation Local car and driver; security 24 months $0p y1.8 Public Relations Local support for schools, library, water, etc. 24 months $0pp y

SUBTOTAL PROJECT DEVELOPMENT $0

2.0 WELLFIELD DEVELOPMENT DESCRIPTION Units Unit Rate Shipping COSTg

2.1 Geotechnical Management Senior geotechnical manager 18 months $02.2 Geologic Services Purchase existing data, base maps, field mapping 18 months $02.3 Geophysical Services Geophysical Surveys 6 months $02.4 Geochemical Services Geochemical testing, including chemicals, equipment, a 6 months $02.5 Roads, Pads, Water, and Camp Access roads, drill pads, water well & pump, offices & h 18 months $02.6 Well Drilling and Testing

Mob/Demob/Moves/Standby Moving rig to/from Vanuatu; in-field moves; standby cha 2 months $0Exploration Holes Shallow wells and slim holes to locate and define reserv 4 holes $0Production Wells 13-3/8" wells; includes drilling, logging, rig tests, and co 4 wells $0Injection Wells 10-3/4" wells; includes drilling, logging, rig tests, and co 2 wells $0

2.7 Reservoir Testing Long term test of production and injection wells, w/ che 2 months $02.8 Travel and Per Diem Round trips between Home Office and Site Office 18 trips $02.9 Direct Expenses Local office, telephone, transportation, per diem, etc. 18 months $0

WELLFIELD DEVELOPMENT COST $0

3.0 ENGINEERING DESCRIPTION Units Unit Rate Shipping COST

3.1 Engineering Management 18 months $03.2 Project Scheduling/Expediting 18 months $03.3 Design

Civil/Structural 8 months $0Electrical/Mechanical 14 months $0Travel & Per Diem 12 trips $0

3.4 Procurement SupportLegal (Contracts) 1 months $0Technical (Specs & Witnessing) 8 months $0Travel & Per Diem 12 trips $0

3.5 Construction SupportCivil/Structural 4 months $0Electrical/Mechanical 6 months $0Travel & Per Diem 12 trips $0

3.6 Training 1 months $03.7 Startup 1 months $03.8 Performance Testing 1 months $03.9 Direct Expenses Local office, telephone, transportation, per diem, etc. 18 months $0

SUBTOTAL FOR ENGINEERING $0

4.0 SITE DEVELOPMENT DESCRIPTION Units Unit Rate Shipping COST

$4.1 Purchase of Land Powerplant, support facilities, and substation m2 $0$4.2 Survey Work Local firm to survey, stake, and provide maps 30 days $0$4.3 Soils Testing and Report Local firm to sample, analyze, write report 10 days $0$4.4 Clear, Grub, Compact Local contractor, level site, compact, dispose of waste 20 days $0$4.5 Septic System Local contractor, turnkey, including all material and labo 1 lot $0$4.6 Road Improve existing road into site 0 m $0$4.7 Civil Finish Gravel, drainage, walkways, parking area, signage 1 lot $0$4.8 Fencing and Landscaping Chain link fence, local shrubs and trees 1 lot $0$4.9 Domestic Water System Duplex pumps & filters, RO unit, pressure tank, and pip 1 lot $0

$SUBTOTAL FOR SITE DEVELOPMENT $0

6/11/2011 5:58 PM GDA


6/11/2011 5:58 PM GDA

5.0 POWERHOUSE AND COOLING TOWE DESCRIPTION Units Unit Rate Shipping COSTpp g

5.1 Excavation Local Contractor, backhoe, loader, 2 trucks, with operat 60 days $0p y5.2 Footings and Foundations Concrete, steel, forms, finish 300 m3 $0g5.3 Powerhouse Prefabricated building, aluminum roof and siding, erecte 1 ea $0g g5.4 Turbine-Generator Set Binary turbine generator set including oil systems 1 lot $0y g g y5.5 Condenser Air cooled condenser 1 ea $05.6 Feed Pumps Goulds, vertical can pumps 2 ea $0p p p5.7 Heat Exchangers Vaporizers and preheaters 1 ea $0g p p5.8 Auxilary systems Plant air, working fluid storage and transfer 1 ea $0y y g g5.9 Control and Instrumentation DCS console hardware and software, transmitters and 1 lot $05.10 Main Switchgear 11 KV metal enclosed vacuum, main, generators, statio 1 lot $0g g5.11 Motor Control Centers 415 V indoor, control for all motors 1 lot $05.12 Electrical Material SS transformers, panelboards, lighting, conduit, wire 1 lot $0p g g5.13 Mechanical Material Pumps, piping, valves, insulation, HVAC 1 lot $0p p p g5.14 General Contractor General Contractor's profit and overhead, bonding and 1 lot $0p g5.15 Electrical Labor Subcontract Electricians and instrument technicians 240 days $0y5.16 Mechanical Labor Subcontract Welders, fitters, millwrights 240 days $0g y5.17 General Labor Subcontract Equipment operators, laborers 240 days $0y5.18 Structural Steel Pipe racks, grating 1 lot $0g g5.19 Paint and Waterproofing Paint for structural steel 1 lot $05.20 Fire Suppression Diesel pump, electric pumps, priming tank 1 lot $05.21 Emergency Generator 1 MW diesel genset, fuel tank, electrical interconnection 1 lot $0

SUBTOTAL FOR POWERHOUSE $0

6.0 GATHERING SYSTEM DESCRIPTION Units Unit Rate Shipping COST

6.1 Steam Piping Above ground steel piping, from wellheads to powerhou 500 m $06.2 Steam Separators N/A 2 ea $06.3 Demisters N/A 1 ea $06.4 Vent System N/A 1 ea $06.5 Transfer Pumps Miscellaneous canned turbine and centrifugal pumps 2 ea $06.6 Metering Brine flow metering equipment 2 ea $06.7 Acid Injection System N/A 1 ea $06.8 Insulation Insulation and jacket for pipeline 500 m $06.9 Injection Piping Above ground steel piping, from plant to injection wells 500 m $0

SUBTOTAL FOR GATHERING SYSTEM $0

7.0 SUBSTATION AND INTERCONNECTI DESCRIPTION Units Unit Rate Shipping COST

7.1 Main Transformer 6 MVA 11/20 kV - by others 1 ea $07.2 Circuit Breakers 25 kV reclosers - by others 1 lot $07.3 Disconnects Manual isolation/bypass for breakers - by others 1 lot $07.4 Structures DE structure, insulators, and hardware - by others 1 lot $07.5 Metering and Relaying Revenue metering, PT's and CT's - by others 1 lot $07.6 Lightning Protection Rods, arrestors, and static wire - by others 1 lot $07.7 Communications Radios system - by others (could be fiber) 1 lot $07.8 Fencing and Grounding 2 m cyclone fence, gates, cadweld grid and ground wel 1 lot $07.9 Transmission System Improvementsby others 1 lot $0

SUBTOTAL FOR SUBSTATION $0

8.0 HEADQUARTERS DESCRIPTION Units Unit Rate Shipping COST

8.1 Office Building Offices for superintendant and staff, conference room 1 lot $08.2 Operator Housing Housing for regular and visiting O&M staff 1 lot $08.3 Common Facilities Kitchen, dining, laundry, recreation 1 lot $08.4 Fresh Water/Utilities Water treatment, power, and communication systems 1 lot $08.5 Roads, walkways Pavement and gravel 1 lot $0

$8.6 Landscaping Local shrubs and trees 1 lot $0

$SUBTOTAL FOR HEADQUARTERS $0

9.0 SPARE PARTS, TOOLS, VEHICLES DESCRIPTION Units Unit Rate Shipping COST

$9.1 Turbine-Generator Spares Spare turbine/generator parts, including bearings, seals 1 lot $0$9.2 Other Critical Spares Motors, valves, controls, instruments 1 lot $0$9.3 Initial Stock of Consumables Lube-oil, gaskets, filters, fuel, chemicals, supplies 1 lot $0$9.4 Tools Shop equipment, hand tools, power tools 1 lot $0$9.5 Vehicles Utility trucks, boomtruck, forklift 1 lot $0

$SUBTOTAL SPARE PARTS, TOOLS, VEHICLES $0

6/11/2011 5:58 PM GDA


6/11/2011 5:58 PM GDA

10.0 TOTAL TURNKEY PRICE Shipping COSTpp g

10.1 Subtotal $0 $0 $010.2 Taxes and Duties Exempt - by others $0p y10.3 Developer's Fee Based on Subtotal 10.1 - by others $0p y10.4 Financing Costsg

Lender's Fees Front-end fees $0Lender's Counsel Legal feesgLender's Engineers Technical due diligence on resource and power plant g g p pEquity Partner's Counsel Legal and accounting feesq y g gOwner's Counsel Legal and accounting feesg gEscrow Fees $0Commitment Fees #REF!

10.5 InterestResource Development IDC Interest only paid during development period #REF!p y p g p pConstruction Loan IDC Interest only paid during construction period #REF!y p g p

10.6 Working Capitalg p10.7 Debt Service Reserve Six months reserve, principal and interest payments #REF!y10.8 Subordinate Debt Retirement $010.9 Contingencyg y

Wellfield Development Based on Section 2.0 Subtotal $0Gathering System Based on Section 6.0 Subtotal $0Engineering Based on Section 3.0 Subtotal $0Site Development Based on Section 4.0 and Section 8.0 Subtotals $0Powerhouse and Cooling Tower Based on Section 5.0 Subtotal $0Substation & Interconnection Based on Section 7.0 Subtotal $0Spare Parts, Tools, Vehicles Based on Section 9.0 Subtotal $0Administration and Soft Costs Based on Section 1.0 Subtotal, 10.2, 10.4, and 10.5 #REF!

POWER PLANT TURNKEY COST 5,000 #REF! per kW #REF!

6/11/2011 5:58 PM GDA

E-1


APPENDIX E: NETWORK COST INPUTS

SCHEME COMPONENTS

Mele to Quoin Hill Transmission and Distribution Line Units Rate CostOHEW 4 2,000$ 8,000$ Conductor 43 15,552$ 668,736$ In lIne Poles 390 7,602$ 2,964,970$ In lIne Poles with OHEW 44 8,618$ 379,187$ Angle Poles 234 11,632$ 2,721,983$ Angle Poles with OHEW 28 12,528$ 350,779$ Termination Poles 39 13,770$ 537,047$ Termination Poles with OHEW 4 15,434$ 61,736$ Conductor Installation 43 20,000$ 860,000$ OHEW Installation 4 2,000$ 8,000$ Vegetation Clearance and Compensation 43 15,000$ 645,000$ Overhead Fibre 43 11,000$ 473,000$ Fibre Pits 18 25,000$ 450,000$ TOTAL 10,128,439$

Mele to Tagabe 60KV Underground Cable Units Rate CostCable 5000 167$ 833,750$ Installation 5000 230$ 1,150,000$ Joints 20 10,000$ 200,000$ Terminations 2 15,000$ 30,000$ Termination Structures 1 20,000$ 20,000$ Underground Fibre 5 21,000$ 105,000$ Fibre Pits 2 25,000$ 50,000$ TOTAL 2,388,750$

Mele 20kV Interconnection Station Units Rate Cost20kV 3 way Switch 1 60000 60,000$ 20kV Regulator 1 121600 121,600$ 20kV Isolator + Stand 1 7000 7,000$ 20kV Cable to Line Termination 1 10000 10,000$ Earthing 1 1000 1,000$ Fenced Enclosure Pad 1 25000 25,000$ TOTAL 224,600$

Tagabe Substation Extension Units Rate Cost60kV Line Isolator 1 50,000$ 50,000$ 20kV CB 1 35,000$ 35,000$ 60/20kV Transformer 1 900,000$ 900,000$ 20kV VT (Metering Grade) 1 15,000$ 15,000$ CT (Protection) 1 5,000$ 5,000$ Transformer Pad and Oil Bund 1 120,000$ 120,000$ TOTAL 1,125,000$

Quoin Hill Geothermal Plant Substation 25MVA 60kV Units Rate CostArrestor 1 20,000$ 20,000$ 60kV Line Isolators 1 50,000$ 50,000$ 3.3kV CB 1 25,000$ 25,000$ Generator Transformer 25MVA 1 900,000$ 900,000$ Transformer Pad and Oil Bund 1 120,000$ 120,000$ 60kV VT (Metering Grade) 1 60,000$ 60,000$ 60kV CT (Metering Grade) 1 60,000$ 60,000$ E/F Protection CT 1 15,000$ 15,000$ Switchyard 1 100,000$ 100,000$ Earthmat 1 30,000$ 30,000$ TOTAL 1,380,000$

Quoin Hill to Epau Distribution Line Units Rate CostConductor 15 7,776$ 116,640$ In lIne Poles 150 3,401$ 510,084$ Angle Poles 90 4,870$ 438,315$ Termination Poles 15 6,031$ 90,471$ Conductor Installation 15 10,000$ 150,000$ Vegetation Clearance and Compensation 15 15,000$ 225,000$ Overhead Fibre 15 11,000$ 165,000$ Fibre Pits 6 25,000$ 150,000$ TOTAL 1,845,510$

Epau to Teouma Distribution Line Units Rate CostConductor 44 7,776$ 342,144$ In lIne Poles 440 3,401$ 1,496,246$ Angle Poles 264 4,870$ 1,285,725$ Termination Poles 44 6,031$ 265,380$ Conductor Installation 44 10,000$ 440,000$ Vegetation Clearance and Compensation 44 15,000$ 660,000$ Overhead Fibre 44 11,000$ 484,000$ Fibre Pits 13 25,000$ 325,000$ TOTAL 5,298,496$

20kV 2 Phase Spur Lines Units Rate CostConductor 5.17 2,640$ 13,649$ In lIne Poles 26 2,560$ 66,172$ Angle Poles 21 4,044$ 83,625$ Termination Poles 5 3,469$ 17,934$ Conductor Installation 5.17 5,000$ 25,850$ Vegetation Clearance and Compensation 5.17 15,000$ 77,550$ TOTAL 284,780$

20kV 3 Phase Spur Lines Units Rate CostConductor 15 3,960$ 58,093$ In lIne Poles 73 2,726$ 199,920$ Angle Poles 59 4,285$ 251,454$ Termination Poles 15 3,629$ 53,237$ Conductor Installation 14.67 6,000$ 88,020$ Vegetation Clearance and Compensation 14.67 15,000$ 220,050$ TOTAL 870,774$

Air Break Switches and Reclosers Units Rate Cost20kV ABS 9 9,360$ 84,240$ 20kV Reclosers 3 35,420$ 106,261$ TOTAL 190,501$

LV Distribution Lines Units Rate CostABC Conductor 22.2 22800 506,160$ In Line Poles 421.8 1230 518,603$ Guyed Angle Poles 133.2 1887 251,348$ Guyed Termination Poles 66.6 1901 126,607$ Conductor Installation 22.2 6000 133,200$ Vegetation Clearance and Compensation 22.2 5000 111,000$ TOTAL 1,646,918$

Distribution Substations Units Rate Cost3 phase 200kVA Groundmount 2 39,021$ 78,042$ 3 Phase 50kVA Polemount 20 13,303$ 266,056$ 1 Phase 30kVA Polemount 17 8,089$ 137,519$ Total 481,617$

Consumer Connections Units Rate Cost2 phase Institution 74 8,898$ 658,434$ 1 phase Household 3002 3,500$ 10,505,499$ Total 11,163,933$

Mele to Quoin Hill 60kV Transmission Only Units Rate CostOHEW 4 2,000$ 8,000$ Conductor 43 7,776$ 334,368$ In lIne Poles 390 4,821$ 1,880,291$ In lIne Poles with OHEW 44 5,701$ 250,855$ Angle Poles 234 7,502$ 1,755,367$ Angle Poles with OHEW 28 9,497$ 265,904$ Termination Poles 39 9,428$ 367,708$ Termination Poles with OHEW 4 11,937$ 47,746$ Conductor Installation 43 10,000$ 430,000$ OHEW Installation 4 2,000$ 8,000$ Vegetation Clearance and Compensation 43 15,000$ 645,000$ Overhead Fibre 43 11,000$ 473,000$ Fibre Pits 18 25,000$ 450,000$

6,916,240$

Mele to Quoin Hill Distribution Line Only Units Rate CostConductor 43 7,776$ 334,368$ In lIne Poles 430 3,401$ 1,462,241$ Angle Poles 258 4,870$ 1,256,504$ Termination Poles 43 6,031$ 259,349$ Conductor Installation 43 10,000$ 430,000$ Vegetation Clearance and Compensation 43 15,000$ 645,000$ Overhead Fibre 43 11,000$ 473,000$ Fibre Pits 18 25,000$ 450,000$ TOTAL 5,310,462$

VILLAGES RESORTS

Name Village Size Households

Spur Distance to Village Centre Line Section

2Phase Spur Dist for Section

3Phase Spur Dist for Section kVA

Emua 1 40 100 1 Havannah 200Paonangisu 1 40 80 1 Baofatu 100

Saama 1 40 180 1Sifiri 1 40 780 1

Takara Landing 1 40 650 1Tanoliu 1 40 130 1

Laonkarai 2 73 50 1Malakesa 2 73 480 1Mangaliu 2 73 1600 1 4.1Malafau 3 97 1500 1Malassa 3 97 0 1Maritao 3 97 3100 1Nasinu 3 97 0 1Takara 3 97 120 1

Lakenasua 4 120 300 1Laklupualor 4 120 0 1

Maolapa 4 120 60 1Safaki 4 120 250 1 5.3Ekipe 1 40 100 2Epau 1 40 80 2Epule 1 40 220 2

Matarisu 2 73 0 2 0.4Sara 3 97 60 2

Ngustap 4 120 0 2 0.1Erontapou 1 40 320 3

Vielou (Eton) 1 40 0 3Pang - Pang 2 73 0 3

Poi 2 73 400 3 0.7Earkol 3 97 1800 3

Etok 3 97 0 3Malair 3 97 1880 3

Malarip 1 3 97 220 3Malarip 2 3 97 4100 3

Orasfiu 3 97 420 3Buraoloa 4 120 0 3

Elkuk 4 120 160 3Pounaie 4 120 700 3 9.3TOTAL 3002 19840

EFATE LINE SECTIONS

DistanceIn Line Pole

Guyed Angle Pole

Guyed Term Pole

In Line Pole with OHEW

Guyed Angle Pole with OHEW

Guyed Term Pole with OHEW

2Phase 20kV Spur Line Dist

3Phase 20kV Spur Line Dist

Main Line Vegetation Line ABS Line Recloser

Underground 60kV (km)

Class 1 Villages

Class 2 Villages

Class 3 Villages

Class 4 Villages Households Institutions Resorts

Distribution Subs 200kVA

Distribution Subs 50kVA

Distribution Subs 30kVA Fibre UG Fibre OH Fibre Pits

Togabe to Mele 60kV Underground Cable 5 0 0 0 0 0 0 0 0 0 0 0 5 0 0 0 0 0 0 0 0 5 0 2Mele to Quoin Hill Transmission +Dist Overhead Line 43 390 234 39 44 28 4 4.1 5.3 43 4 1 0 6 3 5 4 1424 36 2 2 9 9 0 43 18Quoin Hill to Epao Distribution Line 15 150 90 15 0 0 0 0.4 0.1 15 1 1 0 3 1 1 1 410 12 0 0 2 4 0 15 6Epao to Teouma Distribution Line 44 440 264 44 0 0 0 0.7 9.3 44 4 1 0 2 2 6 3 1168 26 0 0 9 4 0 44 13Total Main Line 107 980 588 98 44 28 4 5.2 14.7 102 9 3 5 11 6 12 8 3002 74 2 2 20 17 5 102 39

2 Phase HV Spur Lines 5.2 26 21 5 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 03 Phase HV Spur Lines 14.7 73 59 15 0 0 0 0LV Distribution 22 422 133 67 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Institutions 15Households 150

Mele to Quoin Hill Transmission Only Overhead Line 43 390 234 39 44 28 4 43 0 0 0 0 0 0 0 0 0 0 0 0 0 0 43 18Mele to Quoin Hill Distribution Only Overhead Line 43 430 258 43 0 0 0 4.1 5.3 43 4 1 0 6 3 5 4 1424 36 2 2 9 9 0 43 18

HOUSEHOLD CONNECTION COSTSUnit Rate Cost

30m 16mm 1Phase +NS Service Cable 30 7$ 216$ Trenching and Reinstatement 20 50$ 1,000$ Service Cable Termination Fittings 2 35$ 69$ IPC Connector 2 17$ 35$ Fuse 1 70$ 70$ Meter Box and Meter 1 150$ 150$ Transport and Installation 16 45$ 720$ House Wiring 1 1,000$ 1,000$ Survey and Design 2 120$ 240$ Total 3,500$

SCHOOL/HEALTH INSTITUTION CONNECTION COSTSUnit Rate Cost

30m 16mm 2Phase +NS Service Cable 30 11$ 324$ Trenching and Reinstatement 20 50$ 1,000$ Service Cable Termination Fittings 2 46$ 92$ IPC Connector 3 17$ 52$ Fuse 2 70$ 140$ Meter Box and Meter 1 250$ 250$ Transport and Installation 40 45$ 1,800$ Building Wiring 1 5,000$ 5,000$ Survey and Design 2 120$ 240$ Total 8,898$

DISTRIBUTION SUBSTATION COSTS

3 Phase 200kVA Groundmount Units Rate CostTransformer Base 1 3,600$ 3,600$ Earthing 1 500$ 500$ Transformer 1 16,872$ 16,872$ HV Cable Termination, Arrestors and Drop Out Fuses 1 2,519$ 2,519$ HV Cable 20 120$ 2,400$ LV Fuseboard and cable terminations 1 3,500$ 3,500$ Transport and Installation 86 105$ 9,030$ Survey and Design 5 120$ 600$ Total 39,021$

3 Phase 50kVA Polemount Units Rate CostDrop Out Fuse Arm Assembly 1 519$ 519$ Arrestors 3 193$ 580$ Transformer 1 7,517$ 7,517$ LV Crossarms 2 83$ 167$ LV Fuses 3 60$ 180$ Earthing 1 500$ 500$ Transport and Installation 32 105$ 3,360$ Survey and Design 4 120$ 480$ Total 13,303$

2 Phase 30kVA Polemount Units Rate CostDrop Out Fuse Arm Assembly 1 394$ 394$ Arrestors 2 193$ 386$ Transformer 1 3,312$ 3,312$ LV Crossarms 2 83$ 167$ LV Fuses 2 60$ 120$ Earthing 1 500$ 500$ Transport and Installation 26 105$ 2,730$ Survey and Design 4 120$ 480$ Total 8,089$

LV DISTRIBUTIONIn Line Pole Units Rate CostStandard 9m Wood Pole 9kN 1 345.00$ 345.00$ ABC Suspension Fitting 1 34.50$ 34.50$ Earth wire and earthing 0 250.00$ -$ Transport and Installation 7 105.00$ 735.00$ Survey and Design 1 115.00$ 115.00$ Total 1229.5

Guyed Angle PoleStandard 9m Wood Pole 9kN 1 345.00$ 345.00$ ABC Termination Fitting 2 46.00$ 92.00$ Earth wire and earthing 0 250.00$ -$ Transport and Installation 7 105.00$ 735.00$ Guys 2 300.00$ 600.00$ Survey and Design 1 115.00$ 115.00$ Total 1,887.00$

Guyed Terminal PoleStandard 9m Wood Pole 9kN 1 345.00$ 345.00$ ABC Termination Fitting 1 46 46.00$ Earth wire and earthing 1 250.00$ 250.00$ Transport and Installation 8 105 840.00$ Guys 1 300 300.00$ Survey and Design 1 120 120.00$ Total 1,901.00$

TRANSMISSION ONLYIn Line Pole Units Rate CostStandard 11m Wood Pole 12kN 1 521$ 521$ 60kV Single Pin Crossarm 1 612$ 612$ 60kV Vertical Line Post Insulators 3 413$ 1,238$ Earth wire and earthing 1 500$ 500$ Transport and Installation 14 105$ 1,470$ Survey and Design 4 120$ 480$ Total 4,821$

Guyed Angle PoleStandard 11m Wood Pole 12kN 1 521$ 521$ 60kV Double Pin Crossarm 1 1,225$ 1,225$ 60kV Vertical Line Post Insulators 6 413$ 2,476$ Earth wire and earthing 1 500$ 500$ Guys 1 500$ 500$ Transport and Installation 16 105$ 1,680$ Survey and Design 5 120$ 600$ Total 7,502$

Guyed Termination StructureStandard 11m Wood Pole 12kN 1 521$ 521$ 60kV Strain Insulators 6 187$ 1,125$ 60kV Vertical Post Insulators 3 413$ 1,238$ 60kV Double Termination Crossarm Assembly 1 1,225$ 1,225$ Earth wire and earthing 3 500$ 1,500$ Guys 2 500$ 1,000$ Transport and Installation 20 105$ 2,100$ Survey and Design 6 120$ 720$ Total 9,428$

In Line Pole with OHEWStandard 11m Wood Pole 12kN 1 521$ 521$ Steel Extension and OHEW clamp 1 450$ 450$ Vertical Line Post Insulators 3 413$ 1,238$ 60kV Single Crossarm 1 612$ 612$ Earth wire and earthing 1 600$ 600$ Transport and Installation 16 105$ 1,680$ Survey and Design 5 120$ 600$ Total 5,701$

Guyed Angle Pole with OHEWStandard 11m Wood Pole 12kN 1 521$ 521$ Steel Extension and OHEW clamp 1 450$ 450$ Vertical Line Post Insulators 6 413$ 2,476$ 60kV Double Pin Crossarm 1 1,225$ 1,225$ Earth wire and earthing 1 600$ 600$ Guys 2 500$ 1,000$ Transport and Installation 25 105$ 2,625$ Survey and Design 5 120$ 600$ Total 9,497$

Guyed Termination Structure with OHEWStandard 11m Wood Pole 12kN 1 521$ 521$ Steel Extension and OHEW clamp 1 450$ 450$ 60kV Strain Insulators 6 150$ 900$ 60kV Vertical Post Insulators 6 413$ 2,476$ 60kV Double Termination Crossarm Assembly 1 1,225$ 1,225$ Earth wire and earthing 1 600$ 600$ Guys 4 500$ 2,000$ Transport and Installation 29 105$ 3,045$ Survey and Design 6 120$ 720$ Total 11,937$

CROSSARM ASSEMBLIES

Shipping Overhead 15%

20kV 3 Phase Single Pin Unit Rate CostPins, Ins and Line Guards 3 60.72$ 182.16$ 2.6m Steel Arm 1 287.50$ 287.50$ Brace Straps 2 7.48$ 14.95$ Bolts 1 50.00$ 50.00$ Assembly 1 105.00$ 105.00$ Total 639.61$

20kV 3 Phase Double Pin Unit Rate CostPins Ins and Line Guards 6 60.72$ 364.32$ 2.6m Steel Arm 2 287.50$ 575.00$ Brace Straps 4 7.48$ 29.90$ Bolts 2 50.00$ 100.00$ Assembly 2 105.00$ 210.00$ Total 1,279.22$

20kV 3 Phase Single Termination Unit Rate CostPins Ins and Line Guards 0 60.72$ -$ Strains Eye Bolts and Deadends 3 55.20$ 165.60$ 2.6m Steel Arm 1 287.50$ 287.50$ Brace Straps 2 7.48$ 14.95$ Bolts 1 50.00$ 50.00$ Assembly 1 105.00$ 105.00$ Total 623.05$

20kV 3 Phase Double Termination Unit Rate CostPins Ins and Line Guards 6 60.72$ 364.32$ Strains Eye Bolts and Deadends 6 55.20$ 331.20$ 2.6m Steel Arm 2 287.50$ 575.00$ Brace Straps 4 7.48$ 29.90$ Bolts 2 50.00$ 100.00$ Assembly 2 105.00$ 210.00$ Total 1,610.42$

20kV 2 Phase Single Pin Unit Rate CostPins, Ins and Line Guards 2 60.72$ 121.44$ 2.6m Steel Arm 1 287.50$ 287.50$ Brace Straps 2 7.48$ 14.95$ Bolts 1 50.00$ 50.00$ Assembly 1 105.00$ 105.00$ Total 578.89$

20kV 2 Phase Double Pin Unit Rate CostPins Ins and Line Guards 4 60.72$ 242.88$ 2.6m Steel Arm 2 287.50$ 575.00$ Brace Straps 2 7.48$ 14.95$ Bolts 2 50.00$ 100.00$ Assembly 2 105.00$ 210.00$ Total 1,142.83$

20kV 2 Phase Single Termination Unit Rate CostPins Ins and Line Guards 0 60.72$ -$ Strains Eye Bolts and Deadends 2 55.20$ 110.40$ 2.6m Steel Arm 1 287.50$ 287.50$ Brace Straps 2 7.48$ 14.95$ Bolts 1 50.00$ 50.00$ Assembly 1 105.00$ 105.00$ Total 567.85$

20kV 2 Phase Double Termination Unit Rate CostPins Ins and Line Guards 2 60.72$ 121.44$ Strains Eye Bolts and Deadends 4 55.20$ 220.80$ 2.6m Steel Arm 2 287.50$ 575.00$ Brace Straps 4 7.48$ 29.90$ Bolts 2 50.00$ 100.00$ Assembly 2 105.00$ 210.00$ Total 1,257.14$

60kV Single Termination Unit Rate Cost2.6m Steel Arms 1 287.50$ 287.50$ Brace Straps 2 7.48$ 14.95$ Bolts 1 100.00$ 100.00$ Assembly 2 105.00$ 210.00$ Total 612.45$

60kV Double Termination Unit Rate Cost2.6m Steel Arms 2 287.50$ 575.00$ Brace Straps 4 7.48$ 29.90$ Bolts 2 100.00$ 200.00$ Assembly 4 105.00$ 420.00$ Total 1,224.90$

AIR BREAK SWITCH COSTSUnits Rate Cost

Side Acting 20kV ABS 1 4,600$ 4,600$ Misc Materials 1 200$ 200$ Transport and Installation 40 105$ 4,200$ Survey and Design 3 120$ 360$ TOTAL 9,360$

RECLOSER COSTSUnits Rate Cost

20KV Recloser 1 28,750$ 28,750$ Misc Materials 1 2,110$ 2,110$ Transport and Installation 40 105$ 4,200$ Survey and Design 3 120$ 360$ TOTAL 35,420$

F-1


APPENDIX F: CONVERSION FACTORS USED FOR ECONOMIC ANALYSIS

G-1


APPENDIX G: INPUTS TO THE ECONOMIC MODEL

Economic Surplus (Incremental Benefit) for Households by Income

Demand Function for Energy Services Average Rural HH Demand Function for Average HH in Lower 3 Deciles Demand Function for Average HH in Upper 3 DecilesGrid Extension Lower 3 Deciles Data Points Upper 3 Deciles

With Project p1 VT / kWh 108 With Project p1 VT / kWh 144 With Project p1 VT / kWh 77With Project q1 kWh / Month 34.10 With Project q1 kWh / Month 21 With Project q1 kWh / Month 45.37

HH Cost 3,694 HH Cost 3,050 HH Cost 3,504Without Project p0 VT /kWh 343 Without Project p0 VT /kWh 299 Without Project p0 VT /kWh 380Without Project qo kWh / month 19.64 Without Project qo kWh / month 11.23 Without Project qo kWh / month 27

HH Cost VT per month 6,730 HH Cost VT per month 3,363 HH Cost VT per month 10,260Increased kWhs 14.46 Increased kWhs 9.95 Increased kWhs 18.40Calculations Calculations Calculations

β = -0.002 34.10 β = -0.004 21.18 β = -0.002 45.37α = 3.78 19.64 α = 3.64 11.23 α = 3.95 26.98

For Benefit Calculations - alpha and beta fixed For Benefit Calculations For Benefit Calculationsβ = -0.002 34.10 β = -0.004 21.18 β = -0.002 45.37α = 3.77 19.64 α = 3.64 11.23 α = 3.94 26.98

Data for Chart (Based on Average Income HH) Lower Decile HH Upper Decile HHQ P=(α -ln(Q))/-β Q P=(α -ln(Q))/-β Q P=(α -ln(Q))/-β

kWheq / Month VT [2011]/ kWh kWheq /Month VT [2011]/ kWh kWheq /Month VT [2011]/ kWh43.48 0.0 38.12 0.0 51.34 0.038.79 51 29.65 61 48.36 3736.45 78 25.42 99 46.86 57

Grid Connect 34.10 108 Grid Connect 21.18 144 Grid Connect 45.37 7730.49 158 18.70 174 40.77 14426.87 214 16.21 209 36.17 21823.26 278 13.72 250 31.58 303

No Access 19.64 354 No Access 11.23 299 No Access 26.98 40116.70 426 9.69 335 22.81 50612.78 545 7.64 393 17.26 68010.82 619 6.62 428 14.49 7897.88 760 5.08 493 10.33 1,0004.94 968 3.54 581 6.16 1,3222.00 1,370 2.00 721 2.00 2,024

Ave HH Ave HH Ave HHBeta -0.002 Beta -0.004 Beta -0.002

Off grid Po 342.65 Off grid Po 299.45 Off grid Po 380.32Off grid Qo 19.64 Off grid Qo 11.23 Off grid Qo 26.98On grid P1 108.31 On grid P1 143.96 On grid P1 77.22On grid Q1 34.10 On grid Q1 21.18 On grid Q1 45.37Econ Benefit Q1(P1-1/β)-Q0(P0-1/β) Econ Benefit Q1(P1-1/β)-Q0(P0-1/β) Econ Benefit Q1(P1-1/β)-Q0(P0-1/β)

VT / Mnth VT / Mnth VT / MnthIncremental Benefit 3,399 Incremental Benefit 2,120 Incremental Benefit 4,720

Average Income HH's Benefits from Electrification (Incremental Benefit of Induced Demand)

Low Income HH's Benefits from Electrification (Induced / Incremental Benefit)

High Income HH's Benefits from Electrification (Induced / Incremental Benefit)

Resource Cost Saving by Households by Income

Resource Cost Savings from Electrification of High Income HH (excluding added cost of electricity)Per Month Unit Reduction Fin Cost CF Econ Cost Saving Fin Cost Subsidy

Units Vatu / Unit Vatu / MonthCharcoal / Wood kg 34.17 40.00 1.00 1366.7 1366.7 0.00Petrol (Generator) litre 21.50 253.82 0.80 4375.3 5457.2 -1081.93Kerosene litre 3.00 280.50 0.80 674.7 841.5 -166.83Dry Cell Battery No 2.00 100.00 1.00 200.0 200.0 0.00Gas kg 3.00 202.30 0.90 546.2 606.9 -60.69PV Electricity Unit 0.00 95.37 1.00 0.0 0.0 0.00Total 7,162.8 8,472 (1,309)

Grid Extension Component: Resource Cost Savings from Electrification of the Average HH (excluding added cost of electricity)Per Month Unit Reduction Fin Cost CF Econ Cost Saving Fin Cost Subsidy

Units Vatu / Unit Vatu / MonthCharcoal / Wood kg 20.58 40.00 1.00 823.1 823.1 0.00Petrol (Generator) litre 11.48 253.82 0.80 2336.8 2914.6 -577.84Kerosene litre 2.07 280.50 0.80 465.1 580.1 -115.01Dry Cell Battery No 2.00 100.00 1.00 200.0 200.0 0.00Gas kg 1.60 202.30 0.90 291.7 324.1 -32.41PV Electricity Unit 0.47 95.37 1.00 44.4 44.4 0.00Total 4,161.1 4,886 (725)

UNELCO In Fill Component: Resource Cost Savings from Electrification of median HH (excluding added cost of electricity)Per Month Unit Reduction Fin Cost CF Econ Cost Saving Fin Cost Subsidy

Units Vatu / Unit Vatu / MonthCharcoal / Wood kg 11.30 40.00 1.00 451.9 451.9 0.00Petrol (Generator) litre 4.64 253.82 0.80 944.7 1178.3 -233.60Kerosene litre 1.43 280.50 0.80 322.0 401.6 -79.63Dry Cell Battery No 2.00 100.00 1.00 200.0 200.0 0.00Gas kg 0.65 202.30 0.90 117.9 131.0 -13.10PV Electricity Unit 0.78 95.37 1.00 74.8 74.8 0.00Total 2,111.3 2,438 (326)

Upper 3 Deciles Grid Connected Energy Costs per HHPer Month Unit Consumption Fin Cost CF Econ Cost Fin Cost Subsidy

Vatu / unit Vatu / MonthCharcoal / Wood kg 20.00 40.00 1.00 800.0 800.0 0.00Petrol (Generator) litre 0.00 253.82 0.80 0.0 0.0 0.00Kerosene litre 1.00 280.50 0.80 224.9 280.5 -55.61Dry Cell Battery No 1.00 100.00 1.00 100.0 100.0 0.00Gas kg 3.00 202.30 0.90 546.2 606.9 -60.69PV Electricity Unit 0.00 95.37 1.00 0.0 0.0 0.00Grid Electricity kWh 72.00 23.84 1.89 3239.7 1716.2 1523.45Total 4,911 3,504 1,407

Lower 3 Deciles Grid Connected Energy Costs per HHUnit Consumption Fin Cost CF Econ Cost Fin Cost Subsidy

Per Month Vatu / unit Vatu / MonthCharcoal / Wood kg 40.00 40.00 1.00 1,600.0 1,600.0 0.00Petrol (Generator) litre 0.00 253.82 0.80 0.0 0.0 0.00Kerosene litre 1.00 280.50 0.80 224.9 280.5 -55.61Dry Cell Battery No 1.00 100.00 1.00 100.0 100.0 0.00Gas kg 3.00 202.30 0.90 546.2 606.9 -60.69PV Electricity Unit 0.00 95.37 1.00 0.0 0.0 0.00Grid Electricity kWh 25.00 18.49 2.43 1,124.9 462.2 662.66Total 3,596 3,050 546

Upper 3 Deciles w/o Access Energy Costs per HHUnit Consumption Fin Cost CF Econ Cost Fin Cost Subsidy

Charcoal / Wood kg 54.17 40.00 1.00 2,166.7 2,166.7 0.00Petrol (Generator) litre 21.50 253.82 0.80 4,375.3 5,457.2 -1081.93Kerosene litre 4.00 280.50 0.80 899.6 1,122.0 -222.44Dry Cell Battery No 3.00 100.00 1.00 300.0 300.0 0.00Gas kg 6.00 202.30 0.90 1,092.4 1,213.8 -121.38PV Electricity Unit 0.00 95.37 1.89 0.0 0.0 0.00

7,742 9,046 (1,304)

Lower 3 Deciles w/o Access Energy Costs per HHUnit Consumption Fin Cost CF Econ Cost Fin Cost Subsidy

Charcoal / Wood kg 45.00 40.00 1.00 1,800.0 1,800.0 0.00Petrol (Generator) litre 0.00 253.82 0.80 0.0 0.0 0.00Kerosene litre 2.00 280.50 0.80 449.8 561.0 -111.22Dry Cell Battery No 3.00 100.00 1.00 300.0 300.0 0.00Gas kg 3.00 202.30 0.90 546.2 606.9 -60.69PV Electricity Unit 1.00 95.37 1.89 180.0 95.4 84.66

2,550 2,661 (111)

Generation Cost Assumptions

Geothermal Power Assumptions First 5 MW UnitUnit Size (Net) MW 4Time to build new genset yrs 3

Capital Costs Economic Financial GoV share Developer ShareCost of preparatory work $000 11,000 12,222 0% 11,000 Cost of drilling $000 18,000 20,000 0% 18,000 Cost of generating plant $000 3,000 3,333 0% 3,000 Other costs $000 2,000 2,222 0% 2,000 Transmission or Trans + Dist Facilities $000 9,524 10,582 0% 9,524 Total Capital Cost $000 43,524 48,360 43,524

Operating AssumptionsOperating cost $000 pa $2,000 $2,000 $2,000Capacity factor 0.80Transmission Losses 1%

Assumptions 2nd 5 MW unit Financial EconomicMultiplier 1.11Cost of drilling $000 16,667 15,000 Cost of generating plant $000 3,333 3,000 Other costs $000 1,111 1,000 Tranmission Reconfiguration $000 - - Total cost $000 21,111 19,000

Cost of generating plant $ / MW 5,278 Time to build new genset yrs 2 Capacity factor 0.80Supply to Distribution 27,752 Operating cost $000 $500Transmission Losses 1.0%

Economic Costs & Benefits of Distribution Extension (Household Sector)

Assumptions 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Connection Ratio 25%Number of Houses Connected # 0 0 0 1,002 63 67 71 75 80 85 90 Number of Institutions ConnectedConsumption of Electricity kWh / year 652 652 652 652 652 652 652 652 652 652 652Resource Cost Savings / HH Vt 000 [2011] 66 66 66 66 66 66 66 66 66 66 66Incremental Benefits per HH per year Vt 000 [2011] 43 43 43 43 43 43 43 43 43 43 43Economic Cost of Electrical Energy Vt [2011] / kWh del. 45.00 45 45 45 45 45 45 45 45 45 45 House Wiring Cost USD [2011] / HH 400.00 400 400 400 400 400 400 400 400 400 400 Conusmer Connection Cost USD [2011] / HH 1,871.13 1,871 1,871 1,871 1,871 1,871 1,871 1,871 1,871 1,871 1,871 Fixed Distribution Facilities Cost / USD 13,884,237 One time incremental costs over and above the costs of a transmission only lineVariable Costs (LV Lines & SSs) Cost / USD 1,702,828 NB Not finalSystem Technical Losses % 8%Investment Schedule Dist. Facilities 10% 20% 30% 30% 10%O&M Cost % Investment 2.00%

Opearations Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Household Consumption Vt 000 [2011]Benefits of Grid SupplyBenefits ENPVIncremental Benefits 346,892 0 0 0 42,741 45,440 48,300 51,331 54,542 57,945 61,550 65,370Cost Savings 535,666 0 0 0 66,000 70,168 74,585 79,265 84,223 89,478 95,045 100,944Total Benefits 882,558 0 0 0 108,741 115,609 122,885 130,596 138,765 147,422 156,595 166,314

Costs Connection + House Wiring 177,708 0 0 0 193,518 12,221 12,950 13,721 14,539 15,406 16,324 17,297Variable Distribution Facilities 0 0 0 144,740 9,141 9,686 10,263 10,874 11,523 12,209 12,937Fixed Distribution Facilities (i) 837,509 118,016 236,032 354,048 354,048 118,016 0 0 0 0 0 0O&M (ii) 27,858 0 0 0 0 3,870 4,115 4,374 4,648 4,939 5,247 5,574Electrical Energy 238,840 0 0 0 29,428 31,286 33,256 35,342 37,553 39,896 42,378 45,008Total Costs 1,414,830 118,016 236,032 354,048 721,735 174,535 60,006 63,700 67,615 71,763 76,159 80,816Net Benefits (532,272) (118,016) (236,032) (354,048) (612,993) (58,926) 62,880 66,895 71,150 75,659 80,436 85,498

Note: Calculations extend to 2042 in worksheet.Excludes impact of non-residential sector

Vanuatu Project - Distribution Extension ComponentEconomic Costs and Benefits in [2011] Vt 000

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