59459 Caribbean Regional Electricity Supply Options Toward Greater Security, Renewables and Resilience Franz Gerner Megan Hansen 59459-LAC © 2011 The International Bank for Reconstruction and Development / The World Bank 1818 H Street, NW Washington DC 20433 Telephone: 202-473-1000 Internet: www.worldbank.org Email: feedback@worldbank.org All rights reserved This volume is a product of the staff of the International Bank for Reconstruction and Development / The World Bank. The findings, interpretations, and conclusions expressed in this volume do not necessarily reflect the views of the Executive Directors of The World Bank or the governments they represent. The World Bank does not guarantee the accuracy of the data included in this work and accepts no responsibility whatsoever for any consequence of their use. 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All other queries on rights and licenses, including subsidiary rights, should be addressed to the Office of the Publisher, The World Bank, 1818 H Street, NW, Washington, DC, 20433, USA; fax: 202-522-2422; email: pubrights@worldbank.org. ii Contents Foreword ....................................................................................................................................................... v Acknowledgements...................................................................................................... vi Acronyms................................................................................................................. vii Map........................................................................................................................ ix Overview ....................................................................................................................................................... x Executive Summary ................................................................................................................................... xiii Chapter 1 Introduction .................................................................................................................................. 1 1.1 Objective of the study ......................................................................................................................... 1 1.2 Methodology ....................................................................................................................................... 2 1.3 This Report.......................................................................................................................................... 3 Chapter 2 The Caribbean Context ................................................................................................................. 4 2.1 The Caribbean ..................................................................................................................................... 4 2.2 Electricity Market Overview ............................................................................................................... 7 2.3 Fuels and Generation Technologies: Usage and Potential in the Region ........................................... 8 2.3.1. Liquid Fuels (Distillate, Heavy Fuel Oil) ................................................................................. 10 2.3.2. Coal ........................................................................................................................................... 11 2.3.3. Petroleum coke.......................................................................................................................... 11 2.3.4. Natural Gas (LNG, Mid-Scale LNG, CNG, Pipeline Gas) ....................................................... 12 2.3.5 Solar Photovoltaic (PV) and Concentrating Solar Power (CSP)................................................ 14 2.3.6 Wind........................................................................................................................................... 14 2.3.7 Geothermal ................................................................................................................................. 15 2.3.8 Hydro ......................................................................................................................................... 15 2.3.9 Biomass ...................................................................................................................................... 15 2.3.10 Other Technologies .................................................................................................................. 16 2.4 Conclusion ........................................................................................................................................ 16 Chapter 3 Individual Countries' Energy Options ....................................................................................... 18 3.1 Methodology and Assumptions ........................................................................................................ 18 3.1.1. Fossil Fuel Analysis .................................................................................................................. 19 3.1.2. Renewable Energy Resource Analysis...................................................................................... 21 3.2 Country-specific Results ................................................................................................................... 24 3.2.1 Antigua and Barbuda, Grenada, and St. Vincent and the Grenadines ....................................... 24 3.2.2 Barbados .................................................................................................................................... 25 3.2.3 Dominica and Nevis ................................................................................................................... 25 3.2.4 Dominican Republic (DR) ......................................................................................................... 26 3.2.5 Guadeloupe ................................................................................................................................ 27 3.2.6 Haiti............................................................................................................................................ 28 3.2.7 Jamaica ....................................................................................................................................... 28 3.2.8 Martinique .................................................................................................................................. 29 3.2.9 St. Kitts ...................................................................................................................................... 30 3.2.10 St. Lucia ................................................................................................................................... 30 3.3 Conclusions ....................................................................................................................................... 31 Chapter 4 Regional Energy Options ........................................................................................................... 33 4.1 Natural Gas Pipeline ......................................................................................................................... 33 iii 4.1.1 Technical Feasibility of the Pipeline .......................................................................................... 33 4.1.2 Economics of the Pipeline.......................................................................................................... 34 4.2 Fuel Storage and Transshipment Options ......................................................................................... 38 4.2.1 Current Situation of Regional Storage ....................................................................................... 38 4.2.2 Storage Options for the Future ................................................................................................... 39 4.3 Regional Electricity Market Interconnections .................................................................................. 40 4.3.1 Submarine Cable Technologies and Costs ................................................................................. 40 4.3.2 Evaluation of Interconnections/Markets .................................................................................... 42 4.4 Challenges and Risks ........................................................................................................................ 52 4.4.1 Financial and Economic Issues .................................................................................................. 52 4.4.2 Commercial and Regulatory Issues ............................................................................................ 53 4.4.3 Security of Supply...................................................................................................................... 54 4.4.4 Environmental Concerns ............................................................................................................ 54 4.5 Conclusions ....................................................................................................................................... 54 Chapter 5 Regional Scenario Analysis........................................................................................................ 57 5.1 Methodology ..................................................................................................................................... 57 5.2 The Scenarios .................................................................................................................................... 58 5.2.1 The Base Case Scenario ............................................................................................................. 58 5.2.2 Fossil Fuel Scenario ................................................................................................................... 59 5.2.3 Interconnection/Renewables Scenario ....................................................................................... 61 5.2.4. Comprehensive Integrated Scenario ......................................................................................... 62 5.3 Cost Comparison of Scenario Results ............................................................................................... 63 5.3.1 Net Present Value....................................................................................................................... 63 5.3.2 Investment Requirements and Production Costs........................................................................ 65 5.4 Country-specific Results and Options............................................................................................... 67 5.5 Conclusions ....................................................................................................................................... 72 Chapter 6 Conclusions and Looking Forward ............................................................................................ 74 6.1 Key Conclusions ............................................................................................................................... 74 6.2 Limitations and Challenges ............................................................................................................... 75 6.3 Next Steps ......................................................................................................................................... 76 Annex 1 Forecasted Demand and Supply Tables..................................................................78 Annex 2 Nexant Country Overviews..................................................................................80 iv Foreword The Caribbean region continues to be plagued by high and volatile fuel prices, with limited economies of scale or diversity in electricity supply. Although several studies have examined alternative resource options for the region, they often only consider solutions for individual countries in isolation. When one looks at the Caribbean, however, it is apparent that the short distances between islands and market sizes present opportunities to benefit from regional solutions. Indeed, increasing interconnection in the Caribbean could pave the way for greater energy security, a larger use of renewables, and enhanced climate resilience. Given the dearth of research comparing regional solutions with individual country ones, the potential benefits of pursuing an integrated approach for the Caribbean were not clear. Thus, this report, Caribbean Regional Electricity Supply Options: Toward Greater Security, Renewables and Resilience for the Region, serves to explore at a concept level the alternative of multicountry-based energy development paths that could be implemented by countries to diversify their electricity mix, improve reliability and access cleaner resources. The idea of regional interconnections is not new: gas pipelines are widely used to interconnect gas supply with gas demand, and electricity market interconnections have become the norm around the world. However, this option does not appear to have received the attention it merits in the specific context of the Caribbean. While this study analyzes a small subset of the imaginable regional energy options for the Caribbean, it shows that regional solutions warrant further study. This synthesis report builds from the technical report that the World Bank commissioned from Nexant, entitled Caribbean Regional Electricity Generation, Interconnection, and Fuels Supply Strategy. It analyzes a range of regional options. Although further analysis is required, the hope is that this synthesis report will help to fuel the conversation about interconnected development pathways for the Caribbean. Philippe Benoit Sector Manager, Energy Latin America and the Caribbean World Bank v Acknowledgements This synthesis report was written by Franz Gerner and Megan Hansen (Junior Professional Associate, LCSEG). Members of the World Bank study team included Franz Gerner (Senior Energy Economist and Task Team Leader, ECSS2), Michael Levitsky (Lead Energy Economist, ENV), Alan Townsend (Senior Energy Specialist, EASIN) and Fowzia Hassan (Operations Analyst, MNSEG).The report was prepared under the direction of Philippe Benoit (Sector Manager, LCSEG). Special thanks are due to Susan Bogach (Senior Energy Economist, LCSEG) for reviewing drafts of the report. Peer reviewers for the study included Charles Feinstein (Sustainable Development Leader, EASNS), Mark Lambrides (Chief, Energy and Climate Change Mitigation, Organization of American States) and Tonci Bakovic (Chief Energy Specialist, IFC). The synthesis report is based on a technical report, prepared by Nexant. The team was composed of Peter Hindley (Power Generation Expert and Team Leader), Bruce Degen (Natural Gas Expert), Graham Lawson (Power Transmission/Submarine Interconnection Expert), Babul Patel (Renewables Expert) and Miljenko Bradaric (Financial/Economic Expert). Valuable comments on the Nexant technical report were provided by Trevor Byer (Chairman of the Board of LUCELEC, St. Lucia), Greg Rich (CEO, Eastern Caribbean Gas Pipeline Company, ECGPC), Nigel Hosein (Executive Director, Caribbean Electric Utility Services Corporation, CARILEC) and Joseph Williams (Energy Program Manager, Caribbean Community, CARICOM). The report also benefitted from the Energy and Climate Change Partnership (ECPA) pre- ministerial meetings held in April 2010 and organized by the Organization of American States (OAS) and the US Department of Energy (DOE). The authors express their appreciation to the governments and utilities of Antigua and Barbuda, Grenada, St. Vincent and the Grenadines, St. Kitts and Nevis, St. Lucia, Dominica, Barbados, Guadeloupe, Martinique, Haiti, Jamaica, Dominican Republic and Trinidad and Tobago for providing their full cooperation to the World Bank and Nexant teams during the study. The study was financed by the World Bank and the Public-Private Infrastructure Advisory Facility (PPIAF). PPIAF is a multidonor technical assistance facility which provides support to governments in developing countries for improving the quality of infrastructure through private sector involvement. vi Acronyms AC alternating current bbl barrel CC combined cycle CCGT combined cycle gas turbine CCT simple cycle combustion turbines CDEEE Corporación Dominicana de Empresas Eléctricas Estatales CFB circulating fluidized bed CNG compressed natural gas CO2 carbon dioxide CSP concentrated solar power DC direct current DR Dominican Republic ECGP Eastern Caribbean Gas Pipeline ECGPC Eastern Caribbean Gas Pipeline Company EIA Energy Information Agency ft foot/feet GDP gross domestic product GJ gigajoule GNI gross national income GT gas turbine GW gigawatt GWh gigawatt hour HFO heavy fuel oil HZ Hertz ICGPL Intra Caribbean Gas Pipeline Limited IEDOM Institut d'Emission D'Outre-mer (French Overseas Statistics Agency) IFIs International Financial Institutions IGCC integrated gasification combined cycle IPP independent power producers km kilometer kV kilovolt kW kilowatt kWh kilowatt-hour LCL least cost line LNG liquefied natural gas LSD low-speed diesel m meter MMscfd million standard cubic feet per day mph miles per hour MSD medium--speed diesel MVA million volt-amperes MW megawatt MWh megawatt-hour NG natural gas vii NGC National Gas Company of Trinidad & Tobago NOx nitrogen oxide NPV net present value O&M operation and maintenance PC pulverized coal PDVSA Petroleos de Venezuela PV photovoltaic SOx sulfur oxide UK United Kingdom US United States USVI United States Virgin Islands viii Map of the Caribbean ix Overview Toward an Interconnected Caribbean: Paving the Way for Greater Energy Security, More Renewables and Improved Resilience he Caribbean region faces some of the world's highest electricity tariffs. It is plagued by T high and volatile fuel prices, with limited economies of scale or diversity of electricity supply. Paramount among the region's challenges is managing the dependence on imported oil and oil products, mainly diesel and heavy fuel oil (HFO), for electricity generation. In addition, over the next 20 years electricity demand in the region is expected to double. This will pose greater fuel supply and financial challenges for countries. There is already significant load shedding in some countries, while others face deteriorating equipment and high technical and nontechnical losses. At the same time, the Caribbean islands are especially vulnerable to climate change, and it is in the nations' interests to develop their electricity sectors in a climate-sustainable manner by setting an example for low-carbon growth and enhancing resilience to climate events. In terms of resilience, the countries of the Caribbean must better prepare for the impacts of climate change, such as increased storm intensity and frequency, in their planning for the electricity sector. As the World Bank's World Development Report 2010 states, countries must act now, act together, and act differently. The Caribbean region has a unique opportunity to tackle its local electricity challenges while at the same time being a world leader in transformative energy planning. While the Caribbean region has traditionally considered single-island solutions for the electricity sector, this report, the Caribbean Regional Electricity Supply Options: Toward Greater Security, Renewables and Resilience for the Region, explores at a concept level the alternative of multicountry-based energy solutions that could be implemented bi- or multilaterally. The report analyzes the prospects for moving toward an interconnected Caribbean in order to increase supply, improve reliability and provide access to cleaner local energy resources. A potential tool for achieving this goal is the use of electrical interconnections, notably through the use of submarine cables to connect different islands. The idea of interconnections is not new: there are benefits from economies of scale, and numerous regional electricity interconnections already exist worldwide. However, electrical interconnections have often been overlooked as a solution for the Caribbean, even though they could provide significant benefits, in part because the region includes numerous nations on different islands. The study examines a number of potential interconnections and demonstrates the potential viability of this instrument, from both an economic and technical perspective, to help the Caribbean improve efficiency and increase security in the electricity sector. x Electricity interconnections can also unlock the potential of various large-scale renewable energy resources in the Caribbean. Many countries are blessed with abundant renewable energy potential, such as the geothermal resources on Dominica and Nevis. At the same time, the demand for electricity in these countries is small, and the local market cannot absorb the full resource potential. Through interconnections with other islands, such as Puerto Rico, Guadeloupe or Martinique, there is the possibility of gaining access to the needed markets in order to transform these investments into viable options. Similarly, some islands have large wind or solar potential, but intermittency has the potential to disrupt a small grid, and large amounts of reserves would be needed. Interconnections may allow for the increased penetration of intermittent renewables by increasing the market size, thus reducing reserve requirements and improving efficiency. Interconnections may also enhance a country's resilience to hurricanes and the vagaries of climate change, allowing it to receive emergency support in the face of natural disasters or shortages. For some countries access to emergency reserve power alone may provide significant justification for further pursuing interconnections. The potential climate-resilience benefits of interconnections could also open a window to access climate finance funds in order to support electricity sector development. Given the scale of projects in the Caribbean, even small amounts of money have the potential to be transformative. By increasing the role of local renewable resources, thereby diversifying the generation matrix and providing a means to access emergency reserve power, interconnections would also strengthen the security of the region's electricity sector. Diversification and decreased dependence on imported oil will not only reduce costs, but countries will be less affected by swings in oil prices. Furthermore, through reliance on local regional resources and support for energy trade among countries, the use of interconnections has the potential to improve the stability of intraregional cooperation. The proposed Eastern Caribbean Gas Pipeline (ECGP) is another regional solution. It would supply natural gas from Trinidad and Tobago through a pipeline to Barbados, Guadeloupe, Martinique and St. Lucia. The pipeline gas is potentially a cheap fuel option for these countries which could cut electricity generation costs by half when compared to diesel-based generation. Although this project has faced various implementation delays, it may still be worth pursuing in light of the large expected benefits. While regional solutions offer the potential to reduce electricity costs and increase renewable energy penetration, efficiency, security and climate resilience, a number of factors may present obstacles to implementation. Interconnections, particularly in the context of large-scale renewables development, require larger amounts of upfront capital than traditional single-island- based diesel generation. Interconnections could help reduce the unit capital costs of renewable plants through economies of scale, but private financing, public/private partnerships and support from international financial institutions (IFIs) and the international donor community will likely be of key importance. In addition, countries may need improved legal, regulatory and institutional frameworks for cross-country cooperation and electricity trade. In the Caribbean, as elsewhere in the world, individual countries may be hesitant to rely on another country for power xi or gas, but this hesitancy has been overcome in many parts of the world (including Europe, Asia and other parts of Latin America) with important benefits to the participating countries. There are opportunities over the next decade for Caribbean countries to move toward a more integrated and diverse energy mix, one that would increase the security and efficiency of the electricity sector, catalyze greater use of renewables, and help the Caribbean improve its resilience to a changing climate. To support this vision, the Bank commissioned a technical analysis of regional supply options, which are summarized in this report. The report provides an overview of the electricity sector of many of the countries of the Caribbean, and provides some preliminary findings regarding the potential to interconnect various islands, and the potential to catalyze certain large-scale renewables investments. These findings are summarized in the following Executive Summary, with a fuller description provided in the body of this report. The study represents an initial phase in the process of exploring regional options by providing a concept-level analysis; each project would need additional in-depth technical, financial, and economic prefeasibility and feasibility studies before it moves forward. Through this effort, the World Bank hopes to contribute to the discussion of finding stronger paths for electricity development in the Caribbean and to explore a shift in paradigm to a more integrated Caribbean. xii Executive Summary T he countries of the Caribbean region face numerous energy challenges. Most urgently, they must manage their high and growing dependence on the imported oil and oil products that fuel their domestic economies. Although the total installed capacity of the Caribbean is around 20 gigawatts (GW), this is fragmented among the small islands, and currently no interconnections exist between island states. Diseconomies of scale have a major impact on the cost of power generation. This, in combination with high fuel prices, causes customers in the Caribbean to face some of the world's highest electricity tariffs. Regional solutions, such as electricity market interconnections and gas pipelines, could offer countries economies of scale in fuel supply as well as in power plant and system operations. The objective of the study is to conduct a "concept-level" analysis of the potential for technically and financially sound regional electricity supply options to help match future supply and demand. These regional energy solutions involve new fuels or fuel transport methods (pipeline gas, liquefied natural gas), new and renewable energy resources for power generation (primarily wind and geothermal), and new electrical interconnections through submarine power cables among islands. Although the study explores selected alternative electricity development paths for the Caribbean islands, it is not meant to be a comprehensive analysis of all options or a prefeasibility study. It is hoped that the study of these options will give rise to ideas that could reduce electricity costs, decrease environmental impacts from energy production and increase grid reliability. Overall, this study provides evidence that regional electricity solutions in the Caribbean merit further research and investigation. Many countries may have significant potential to gain from developing new resources and exploring interconnections. However, this study uses a simplified approach; future work is needed to identify the optimal options for each country. It is recommended that individual countries or sets of countries use these preliminary high-level findings to conduct more in-depth prefeasibility and feasibility studies of individual, subregional and regional solutions, and related institutional/regulatory assessments. Methodology The World Bank commissioned Nexant to conduct a technical analysis of regional supply options for the Caribbean. This analysis consisted of four main steps: market analysis, individual country analysis, regional solution analysis, and a scenario analysis to measure the aggregate regional impacts and savings from different development paths. The results are presented in its report entitled Caribbean Regional Electricity Generation, Interconnection, and Fuels Supply Strategy (the Nexant Report).1 1 The Nexant Report can be downloaded at www.worldbank.org/reference/ under Documents & Reports. xiii First, current and future electricity markets were analyzed. This analysis consisted of a country-by-country examination of the current and planned energy infrastructure, a projection of future demand growth (based on forecasts and historical data), and an overview of the available technologies to meet this growth. Second, a comparison of fuel supply and generation technologies was completed to explore the least-cost options for individual countries in order to later compare these results to regional options. The results were presented as screening curves for each country. These curves plot a simplified representation of costs (cents/kilowatt-hour [kWh]) against the relevant capacity factors. The cost was calculated using capital costs, operating and maintenance costs, fuel costs, estimated costs for transmission upgrades, the heat rate (or fuel efficiency), and the capacity factor. The study focuses on the nine Caribbean countries eligible for support from the World Bank (St. Lucia, St. Vincent and the Grenadines, Grenada, Antigua and Barbuda, St. Kitts and Nevis, Dominica, Haiti, the Dominican Republic and Jamaica) and a few other countries relevant to the Caribbean gas pipeline (Martinique, Guadeloupe and Barbados). The third step focused on analyzing a gas pipeline to serve four countries, three regional fuel storage options and eleven electricity market interconnections. In addition to those countries on which this study focused in detail, this step involved a cursory analysis of the energy markets of various other countries that would be instrumental in regional solutions (Trinidad and Tobago, Cuba, the United States and Puerto Rico). These results were compared with single-country solutions in order to assess their economic benefits. Fourth and finally, a multicountry scenario analysis was conducted to provide a preliminary assessment of the aggregate economic benefits of four illustrative scenarios. This analysis built on the previous steps but involved a more detailed system analysis that simulated yearly expansion and production, based on characteristics of the existing systems, future conditions, and characteristics of new power plants. Based on the net present value (NPV) of investment and production costs, an estimated scale of the benefit of diverging from the business-as-usual path was identified for each country. This synthesis report builds on the findings of the Nexant Report. The benefits of regional-based solutions that notably promote the use of renewables provide a potential opportunity for the Caribbean as a region to increase the security of energy supply, to reap the benefits of larger- scale renewables and to improve its resilience to climate. The Caribbean Electricity Sector Overall, the Caribbean is a diverse region with disparate energy needs, ranging from large island nations with millions of people, such as the Dominican Republic and Puerto Rico, to extremely small ones with a few thousand inhabitants, such as Anguilla and St. Kitts and Nevis. The sizes of the economies range from multibillion dollars to a few million. Given this disparity in size and wealth, the energy access and demand vary. Most countries have near- universal access, while others, such as Haiti, struggle to provide coverage. Some have installed capacities of 5 GW, and others only reach a few megawatts (MW). xiv However, the main challenge of these countries is similar: supplying a growing energy demand in a reliable and efficient manner. Most countries depend on diesel and heavy fuel oil (HFO) which are expensive and lead to extremely high electricity tariffs, although a few also use natural gas, coal, bagasse and hydro. Since the region's electricity demand is projected to double by 2028, large new investments must be made. It is useful to consider what options may be a part of meeting the challenge of supplying cheaper energy to the Caribbean. Given the distinct nature of the countries and the energy needs, no single development path will be suitable for all countries, and it is important to consider the various options. As summarized in Table 1, numerous resources are available in the region. The resources with the most potential are natural gas (pipeline and liquefied natural gas [LNG]), geothermal, wind, hydro and biomass. The Nexant Report concludes that all renewable resources (except solar) are viable, even without subsidies. It is important to note that the report only examines large-scale grid-connected systems, and does not look at the economics or viability of distributed systems. Moreover, it does not consider emerging technologies, such as wave, tidal and Ocean Thermal Energy Conversion (OTEC), all of which may be relevant for the Caribbean in the longer term. Table 1: Technology Options for the Caribbean Usage in the Fuel Type Technology Potential Region Distillate (MSD, LSD, Wide Wide usage likely to continue without intervention. Oil GT) HFO (MSD, LSD, GT) Wide Wide usage likely to continue without intervention. Potentially viable for many islands, but environmental Coal Coal (PC, CFB) Limited externalities should be considered before implementation. LNG Limited Potential limited to countries with high demand. Potential for many countries, but not studied in detail Mid-Scale LNG None since it is a nascent technology. Natural Gas Potential limited to countries with high demand, but not CNG None studied in detail since the technology is nascent. Trinidad and Potential for other countries is limited to those few that Pipeline Gas Tobago a pipeline (not yet developed or agreed to) could reach. Solar Photovoltaics Very limited Potential, but capital costs are still high. Concentrating Solar None Potential limited by solar influx and land availability. Power Wind Limited Large potential on most islands. Geothermal Very limited Large potential on certain islands with resources. Renewable Large potential limited to a few countries with rivers of Hydro Limited note. Large potential, but further assessments are needed to Biomass Very limited identify specific sites. Emerging technologies (wave, tidal, OTEC, None Potentially large, but not examined in this study. etc). xv Individual Country Solutions In order to understand the additional benefit of regional options for the Caribbean, it is important to first recognize what options exist for an individual country's development. Individual country means that each country is considered to be isolated, without connection to another country by gas pipeline or submarine cable electrical interconnection. Some Caribbean countries have numerous alternative energy options, while others are limited to only a few. Which fossil fuel technologies are appropriate on which island are most influenced by the island's size, while the competitiveness of renewable technologies is impacted by both the resources available and the cost of competing fossil fuels (see Table 2). Table 2: Summary of Individual Countries' Viable Future Options2 Country Distillate Coal LNG Wind Geothermal Hydro* Biomass* Antigua and Barbuda Grenada St. Vincent and the Grenadines St. Kitts St. Lucia Dominica Nevis Barbados Guadeloupe Martinique Haiti Jamaica Dominican Republic = viable option * The resources are site specific and need to be studied further. Notably, the smallest islands, including Antigua and Barbuda, Grenada3, St. Vincent and the Grenadines, St. Kitts, and St. Lucia, have limited fossil fuel options, with the cost of coal being comparable to distillate, due to the high costs of delivering to and serving a small market. In addition, coal may require deep sea ports which may not be available on every island. As a result, renewable options, such as wind, hydro and biomass, are highly competitive where 2 Although mid-scale LNG may be viable options for many countries, it is not included in the Nexant Report due to the nascent nature of the technology. Mid-scale LNG may be a low-cost option for Barbados, Jamaica, Martinique, Guadeloupe, Dominican Republic (DR), and possibly Haiti. In addition, compressed natural gas (CNG) may also be viable for Barbados, Jamaica, Martinique, Guadeloupe, DR, and possibly Haiti, but it has additional risks because it is a new technology, and was not studied in detail in this analysis. In this analysis the geothermal energy for Martinique and Guadeloupe was not examined, though potential exists. 3 Grenada has a large estimated geothermal resource, the development of which was not examined in this study. The government recently announced plans to explore the potential of development, which could impact the country's energy options. xvi suitable sites can be identified. Since coal is an environmentally more damaging resource relative to many other sources, and could lead to future financial liabilities in a carbon-constrained world, countries may choose to pursue renewable options. Dominica and Nevis have an array of choices similar to those of other small nations, but their options are augmented by large geothermal potential. In both countries geothermal energy is the cheapest option at capacity factors at which geothermal power plants would operate. However, it is important to consider the ratio of the size of the potential resource to the size of the market. In both countries a plant could supply 100 percent of the islands' demand with excess at the time of installation, which would increase the requirements for operational reserves. The countries may be better able to utilize the full geothermal resource with interconnections. In the slightly larger markets of Barbados, Guadeloupe and Martinique, LNG appears to be the most economical fossil fuel option, and in all countries wind energy could also be viable and competitive if good sites are identified. Compressed natural gas (CNG) and mid-scale LNG may also be lower-cost options for these countries, but they were not studied in detail in this study since they are nascent technologies (see footnote 2). Finally, in the three largest markets (Haiti, Jamaica and the Dominican Republic), alternative fossil fuels are competitive. In Haiti, LNG fuels the cheapest power at nearly all capacity factors. Due to the low cost of fossil fuels in Jamaica and the Dominican Republic, renewables, such as wind, lose the large Figure 1: Schematic of the Eastern competitive advantage that they have in Caribbean Gas Pipeline smaller countries unless the environmental costs of fossil fuels are factored in. However, renewables are still competitive at good sites. Regional Solutions Regional solutions may be an appealing option for the Caribbean, because they could help countries benefit from economies of scale and indigenous resources on neighboring islands and offer lower-cost options than individual development. The regional solutions examined are the construction of a gas pipeline, the enlargement of regional fuel storage and transshipment facilities, and the interconnection of electricity markets by xvii means of submarine cables or land transmission lines. From the analysis, it appears that gas pipelines and submarine cables have the potential to significantly reduce power prices for many countries. The proposed Eastern Caribbean Gas Pipeline (ECGP) would supply natural gas by means of a pipeline to four countries: Barbados, Guadeloupe, Martinique and St. Lucia (see Figure 1). Based on Nexant's analysis, pipeline gas could potentially be the cheapest fossil fuel option for these countries, with the potential to cut electricity generation costs by half when compared to diesel-based generation, and to provide cheaper fuel than coal Table 3: Summary of Gas Pipeline or natural gas through other delivery Interconnection Savings methods. For Martinique and Country Estimated Savings (cents/kWh)* Guadeloupe, the cost of pipeline gas is 11.7/ compared to distillate comparable to potential imports of Barbados 4.3/ compared to coal electricity based on geothermal power 4.0/ compared to LNG generation from Dominica. Thus, 9.0/ compared to distillate despite the barriers to implementation, Guadeloupe 2.5/ compared to LNG pipeline gas should continue to be -3.0/ compared to geothermal imports considered a viable option for the 10.5/ compared to distillate region. Table 3 shows the potential Martinique 3.0/ compared to LNG -1.5/ compared to geothermal imports cost savings when compared with other options for each country. 9.3/ compared to distillate St. Lucia 3.2/ compared to coal *All savings are quoted assuming plants are running at an 80 Interconnections of electricity percent capacity factor. markets may also reduce costs of electricity. Interconnections involve connecting one country to another by means of submarine cables or, in the case of Haiti and Dominican Republic, by land transmission lines. Although land interconnections are most common, the interconnections discussed in this study rely mostly on submarine cables due to the region's geography. Submarine cables are advanced technologies that are widely used for underwater electricity interconnections. However, the use of alternating current (AC) and direct current (DC) submarine cables is limited by the interconnection length and route depth. Another limitation to submarine cables is that it is beyond the scope of current technology to have a main line carrying bulk power with spliced spurs delivering smaller amounts of power to a series of islands along the main line's length. Therefore, with current technologies interconnecting several islands can only be accomplished by going from island to island, with terminals on each island, or by delivering all the power to a single central island with interconnections to other islands. Electricity market interconnections may be an attractive option for the Caribbean, particularly when geothermal-based electricity can be exported. Many of the electricity market interconnections studied appear to be both economically viable and technically feasible. The Nevis­Puerto Rico, Nevis­St. Kitts, Saba­St. Maarten, and Florida­Cuba interconnections offer large savings due to the availability of low-cost geothermal power in Nevis and Saba and coal and natural gas in Florida. Dominica interconnections also have potential to bring significant earnings to Dominica and savings to Martinique and Guadeloupe. Savings for the Dominican Republic­Haiti interconnection would depend on the generation source of exported electricity, while the interconnection between Nevis and the US Virgin Islands shows small xviii savings, due to the long distance and small amount of energy transported. All submarine interconnections from Haiti appear to be technically unviable with current technology since paths with a maximum depth of less than 1,500 meters could not be found; further studies may identify better routes, or more expensive technologies might be used. These preliminary results are laid out in Table 4. In addition to potentially large Table 4: Summary of Electricity Interconnection economic benefits for some Savings for the Country Receiving Power countries, interconnections Interconnection Estimated Savings (cents/kWh)** also may allow countries to 13.3/ compared to distillate receive emergency support in Dominica­Martinique* 1.5/ compared to pipeline gas the face of natural disasters 13.3/ compared to distillate (thereby enhancing resilience Dominica­Guadeloupe* 3.0/ compared to pipeline gas to climate change) or other 14.5/ compared to HFO shortages and, in many cases, Nevis­Puerto Rico* -0.7/ compared to LNG can also unlock access to Nevis­US Virgin certain large and renewable Islands* 1.5/ compared to distillate energy resources, which is a Nevis­St. Kitts* 13.4/ compared to distillate key to reducing carbon Saba­St. Maarten* 12.2/ compared to distillate emissions in the region. For some countries, even if only 13/ coal export compared to HFO Florida­Cuba* 15.4/ gas export compared to HFO high-cost fuels are available, these reasons alone may provide -2.3/ HFO export compared to distillate DR­Haiti* 9.6/ gas export compared to distillate significant justification for further pursuing Puerto Rico­DR N/A interconnections through Technically questionable with current Haiti­Cuba prefeasibility studies. technology Technically questionable with current Haiti­Jamaica Three regional fuel storage and technology transshipment facilities are also Technically questionable with current Florida­Haiti examined. These options focus technology on creating regional or * Country receiving power. **All savings are quoted assuming plants are running at an 80 percent subregional facilities to store capacity factor, and both capital and operation and maintenance (O&M) petroleum product such as costs are included for each option. gasoline, diesel and heavy fuel oil. By having sufficient fuel storage, the larger ship size can be used to deliver the refined products to the regional storage facility, thereby reducing the cost of fuel. The three expansion options examined are one facility in St. Lucia, one in Antigua, and another in Martinique, although none appears to offer significant economic benefits. It is important to note that the interconnection and regional solutions described in this section are by no means an exhaustive set of possible interconnections for the region. This report is intended as a high-level overview to determine whether submarine cable interconnections and gas pipelines are worth considering--which they appear to be--and which interconnections among those examined might be technically and economically feasible. xix Illustrative Scenario Analysis of Combined Regional Options Building from the exploration of possible regional supply options, four scenarios are analyzed to compare the impact of different fuel and supply development paths at a regional level. These scenarios are: (i) the Base Case Scenario, assuming continued use of distillate and HFO; (ii) the Fossil Fuel Scenario, assuming the use of potential alternative fossil fuels; (iii) the Interconnection/Renewables Scenario, analyzing the potential for renewable energy development and island integration; and (iv) the Comprehensive Integrated Scenario, combining options from the Fuel and Interconnection/Renewables Scenarios. Based on the analysis, it appears that regional benefits from developing a combination of renewables, alternative fossil fuels and interconnections could be substantial (see Table 5). When the NPV of cost savings compared to the Base Case is estimated, the Comprehensive Integrated Scenario offers the largest savings at US$4.37 billion through 2028, followed by the Interconnection/Renewables Scenario at US$2.57 billion, and the Fossil Fuel Scenario at US$2.56 billion (see Table 5). In addition to accounting for savings within the nine countries studied, the results factor in fuel savings from displaced fuel from energy exports to Guadeloupe, Martinique and Puerto Rico and the costs of these interconnections. The analysis indicates that a number of countries have the potential for large energy savings from following development paths that include interconnections (gas and electricity) when compared to the Base Case. These countries are Barbados, Haiti, St. Kitts, Nevis, Dominica and St. Lucia. The savings in Barbados and St. Lucia result from fuel savings from the gas pipeline, while savings for Dominica, Nevis and St. Kitts are attributed in part to low-cost geothermal power generated and used on Dominica and Nevis that substitute for diesel/HFO generation. However, a large amount of savings in the Comprehensive Integrated Scenario comes from exports that displace higher-cost fossil fuel generation in Guadeloupe, Martinique and Puerto Rico. The savings are attributed to Dominica and Nevis in Table 5. Haiti shows the most significant benefits from diversifying its energy sources independently, with estimated savings of 24 percent. It is also interesting to note that Dominica is the only country with higher costs in the Comprehensive Integrated Scenario compared to the Interconnection/Renewables Scenario. This is because the Comprehensive Integrated Scenario assumes that the gas pipeline is constructed, and cost savings comparing geothermal to pipeline gas are smaller than comparing geothermal to distillate. However, geothermal and gas may not be in direct competition, as there may be a place for both as demand on Martinique and Guadeloupe continues to grow.4 All other countries without potential for a gas pipeline or submarine interconnection showed some expected benefit from diversifying fossil fuels by pursuing renewable energy options on their own, but the savings are predicted to be relatively small. Most notably, the small islands with limited alternative fuel options have small potential savings. These include Antigua and Barbuda, Grenada, and St. Vincent and the Grenadines. Moreover, the analysis 4 As mentioned in Guadeloupe's and Martinique's power system master plans, for the time being EDF has agreed to convert existing diesel plants to gas if a gas supply emerges. Geothermal imports from Dominica, on the other hand, are seen as one of the supply options for the additional near term baseload needs. xx indicates that while the absolute savings for the Dominican Republic and Jamaica are large, the savings relative to the total cost to meet demand in the Base Case are small. Table 5: Scenario NPV Cost Savings (US$ million) Interconnection/ Comprehensive Comprehensive Fuel Base Case Renewables Integrated Integrated Country Scenario Total Costs Scenario Scenario Scenario % Savings Savings Savings Savings Antigua and 708 12 20 31 4% Barbuda Barbados 2,266 906 39 912 40% Dominica 157 0 >500 (Note 1) 10 (Note 1) (Note 1) Dominican 16,357 444 350 721 4% Republic Grenada 489 32 17 45 9% Haiti 1,955 433 76 476 24% Jamaica 8,488 500 138 628 7% St. Kitts 308 0 159 159 52% Nevis 188 0 >1,000 (Note 1) >1,000 (Note 1) (Note 1) St. Lucia 670 216 18 221 33% St. Vincent and 400 18 14 29 7% the Grenadines Total 31,986 2,561 2,570 4,367 14% Note 1: See main text for details on basis for calculations. Source: Nexant Therefore, the analysis suggests that the largest potential savings exist in countries that can either interconnect through submarine cables (where one country has low-cost generation) or through the Eastern Caribbean Gas Pipeline. Other countries may experience savings from diversifying their fuel mix or developing indigenous renewable energy, but these savings are likely to be comparatively small (estimated at less than 10 percent for the countries studied). Limitations and Challenges The analysis is based on a purely economic and technical comparison of fuels, renewable technologies, and interconnections. It does not include an assessment of environmental, political, institutional, regulatory or financial risks. Issues such as energy security (security of fuel supply as well as energy dependency) or environmental concerns may present obstacles to implementation. The analysis is preliminary in nature; more detailed feasibility studies must be conducted on a project-by-project basis to develop a deeper understanding of their potential technical, financial, commercial, economic and regulatory viability. There are many financial risks and challenges associated with pursuing renewable, interconnection and fossil fuel options. The higher capital investments required for alternative generation when compared to diesel and HFO make financing projects a challenge. Local xxi utilities may have difficulty funding such large investments and some countries may opt for more expensive operating costs to reduce upfront financing. There are also many unknowns when future cash flows and risks associated with high fuel cost assumptions are projected. As a result, utilities may be hesitant to invest in technologies with which they are not familiar, particularly if the new technologies will require utilities to adapt their business model. Private financing, public/private partnerships and support from international financial institutions (IFIs) and the international donor community may often be of key importance. In addition, countries may need improved legal, regulatory and institutional frameworks for cross-country cooperation. For regional integration options, regulatory harmonization among the two or more countries may be necessary for the project's success. Likewise, difficulties resulting from separate ownership of various components of interisland power or fuel supply need to be addressed. For the export of geothermal power by means of a submarine cable, one private party might own the geothermal power plant in the exporting country while another owns and operates the submarine cable. Joint ownership can present other types of issues. Contractual structures and supporting institutions must be created to guarantee supply and allocate risks and responsibilities to the appropriate parties. Finally, a secure supply of energy is often viewed as a national security issue, and many countries may be hesitant to rely on another country for power. Although distillate and HFO are widely available at present, political unrest or technical failures may compromise one country's ability to supply another. As a result, countries involved in regional solutions may choose to increase reserve margins. This may lead to increased operating reserves, the economic impact of which was not taken into account in this study. Nevertheless, the early results from this study reveal interesting interconnection and cross- country opportunities that are worth pursuing further. Many countries have significant potential for saving or earning export revenue and may decide that the benefits merit facing these challenges and risks. Moreover, the interconnections would allow for a greater utilization of renewable resources in the region. Conclusions There are opportunities over the next decade for Caribbean countries to move toward a more integrated and diverse energy mix, one that could increase the use of renewables. These opportunities warrant further exploration. Diversity and integration reduce vulnerabilities from high and volatile fuel prices, load shedding and extreme climate events. The preliminary analysis indicates that there are three main opportunities for the Caribbean. Renewable Energy Development: The Caribbean has a large potential for economic renewable energy resource development, including wind, geothermal and small hydro. These technologies appear to be highly competitive with the technologies currently in use. One of the challenges to development will be to identify sites where the resource is good and development costs are not a barrier. Therefore, to encourage development it xxii may be most cost effective to assist in identifying such sites. Interconnections can increase countries' ability to develop large-scale renewable projects. Submarine Cable Electrical Interconnections: There appear to be a number of highly economic, technically viable electricity market interconnection options which, as noted above, could release more large-scale renewable usage. However, a significant amount of work needs to be done both to understand the viability of interconnections examined in this study and to evaluate interconnections not considered in this analysis, including subregional interconnections (such as a Southern Caribbean Ring), continental connections (such as with Mexico, the US, Colombia or Venezuela), and bilateral interconnections (such as Montserrat­Antigua and Puerto Rico­Dominican Republic). Gas Pipelines: The potential for gas pipelines should be considered, given the positive economic benefits this study shows for the Eastern Caribbean Gas Pipeline (ECGP). The ECGP may provide the most economical fossil fuel for each island it reaches and benefits of economies of scale compared to individual development. The gas is about half as costly as distillate for Barbados, Guadeloupe, Martinique and St. Lucia. Development of any pipeline will require the agreement of many parties, such as gas suppliers, utilities, regulators, financial institutions and governments, making the development process more costly and time consuming. A wide range of support may be required to move these projects forward. This is a high-level concept study; detailed feasibility studies need to be carried out on any proposed interconnection to transform a possibility into a reality. A feasibility study would include a comprehensive analysis of all key issues related to a proposed interconnection, including the technical, environmental, commercial, financial and economic aspects. The analysis would also need to outline the subregional legal, regulatory and institutional frameworks required to attract investors to carry out the project. Regional organizations and IFIs can provide valuable contributions both to facilitate the policy dialogue among the countries and to provide technical assistance and financial support to address political and financial risks for potential investors. Opportunities exist for the countries of the Caribbean region to move to a more regionally based development path that should strengthen their security of supply, support the greater use of renewables and improve their resilience. These opportunities involve considering outside-the-box solutions, such as interconnections. xxiii Chapter 1 Introduction T he countries of the Caribbean region face numerous energy challenges. Most urgently, they must manage the high and growing dependence on imported oil and oil products that fuel their domestic economies. The majority of these countries' power plants rely primarily or entirely on imported diesel and heavy fuel oil (HFO), which tend to be costly and environmentally damaging. In addition, demand is expected to double over the next 20 years and will pose fuel supply and financial challenges. Problems associated with reliance on high-priced liquid fuels will increase in proportion to their demand. There is already significant load shedding in some countries, while others face deteriorating equipment, inadequate tariff levels, and high technical and nontechnical losses. It will be difficult to close the supply gap using current energy fuels, technologies and planning strategies. Moreover, although the region's total installed capacity is around 20 GW, this is fragmented among the many islands, and currently no interconnections exist among island states. Diseconomies of scale have a large impact on the cost of power generation on the small islands since transport and infrastructure services are likely to cost more in small markets. This, in combination with high fuel prices, causes customers in the Caribbean to face some of the world's highest electricity tariffs. Regional solutions, such as electricity market interconnections and gas pipelines, could offer countries lower-cost resources and benefits from economies of scale in power plant and system operations. 1.1 Objective of the study The objective of the study is to conduct a concept-level analysis of the potential for technically and financially sound regional electricity supply options to help match future supply and demand. These regional energy solutions involve new fuels or fuel transport methods (pipeline gas, liquefied natural gas), new and renewable energy resources for power generation (primarily wind and geothermal), and new electrical interconnections through submarine power cables between islands. Although the study explores selected alternative electricity development paths for the Caribbean islands, it is not meant to be a comprehensive analysis of all options or a prefeasibility study. It is hoped that a study of these options will give rise to ideas that could reduce electricity costs, decrease environmental impacts from energy production and increase grid reliability. 1 1.2 Methodology Nexant was commissioned to conduct an analysis that consisted of four main steps: market analysis, individual country analysis, regional solution analysis, and a scenario analysis to measure the aggregate regional impacts and savings from different development paths. The results are presented in its report entitled Caribbean Regional Electricity Generation, Interconnection, and Fuels Supply Strategy (the Nexant Report).5 First, current and future electricity markets were analyzed. This consisted of a country-by- country examination of the current and planned energy infrastructure, a projection of future demand growth (based on forecasts and historical data), and an overview of the available technologies to meet this growth. After collecting data for the report, the team prepared peak and energy demand forecasts for each country. Next, cost and performance parameters were determined for fuels and power generation technologies. Second, a comparison of fuel supply and generation technologies was completed to explore the least-cost options for individual countries in order to later compare these results to regional options. The results were presented as screening curves for each country. These curves plot the simplified representation of costs (cents/kWh) against the relevant capacity factors. The cost was calculated using capital costs, operating and maintenance costs, fuel costs, estimated costs for transmission upgrades, the heat rate (or fuel efficiency), and the capacity factor. The study focuses on the nine Caribbean countries eligible for support from the World Bank (St. Lucia, St. Vincent and the Grenadines, Grenada, Antigua and Barbuda, St. Kitts and Nevis, Dominica, Haiti, the Dominican Republic and Jamaica) and a few other countries relevant to the Caribbean gas pipeline and interconnections (Martinique, Guadeloupe and Barbados). The third step focused on analyzing a gas pipeline to serve four countries, three regional fuel storage options and eleven electricity market interconnections. In addition to those countries on which this study focused in detail, this step involved a cursory analysis of the energy markets of various other countries that would be instrumental in regional solutions (Trinidad and Tobago, Cuba, the United States and Puerto Rico). These results were compared with single-country solutions by adding the additional options onto the screening curves developed in the second step in order to assess their comparative economic benefits. Fourth and finally, a multicountry scenario analysis was conducted to provide a preliminary assessment of the aggregate economic benefits of four illustrative scenarios. The scenarios are: (i) the Base Case Scenario, assuming continued use of distillate (diesel) and HFO; (ii) the Fuel Scenario, assuming potential alternative fossil fuels; (iii) the Interconnection/Renewables Scenario, analyzing the potential for renewable energy development and island integration; and (iv) the Comprehensive Integrated Scenario, combining the options of the Fuel and Interconnection/Renewables Scenarios. This analysis built on the previous steps but involved a more detailed system analysis that simulated yearly expansion and production, based on characteristics of the existing systems, future conditions, and characteristics of new power plants. 5 The Nexant Report can be downloaded at www.worldbank.org/reference/ under Documents & Reports. 2 Based on the net present value (NPV) of investment and production costs, the scale of the benefit of diverging from the business-as-usual path was estimated for each country. 1.3 This Report In general, the structure of the report follows the methodology. Chapter 2 focuses on the context of energy in the Caribbean, including the power generation market and potential resource options. The chapter aims to build an understanding of what the Caribbean looks like geographically and economically. It then delves into the specifics of the current electricity markets and the future projected growth. It concludes with an overview of the generation options and an initial screening to identify which are appropriate for the Caribbean. Chapter 3 analyzes potential individual power solutions for the nine Caribbean countries eligible for support from the World Bank and for several other countries relevant to the Caribbean gas pipeline, using the technology and fuel options outlined in Chapter 2. It begins by explaining the methodology of screening curves and laying out key assumptions about thermal and renewable energy. It then presents screening curves for each country. Chapter 4 describes how regional solutions can further reduce the cost of electricity, and compares the economics of individual countries' options to the regional solutions. First, it examines the gas pipeline, exploring the implications for Martinique, Guadeloupe, Barbados and St. Lucia. This is followed by an exploration of the potential for regional storage facilities. Finally, it examines how electricity market interconnections through submarine cables can help reduce costs of power for importing and exporting countries. Chapter 5 analyzes the cost savings from various different solutions for the region as a whole, focusing on several illustrative scenarios to estimate the regional impacts and savings from different development paths. This section also addresses some of the challenges of pursuing alternative development paths. Finally, Chapter 6 outlines the main conclusions of the study. 3 Chapter 2 The Caribbean Context T his chapter provides general context related to the Caribbean and its electricity markets, given the importance of geography, population and resources to understanding the available development paths. First, it briefly describes the geographic boundaries and key characteristics of the region, including size, populations and the economy. Second, it discusses the electricity markets, including current conditions and the future outlook. Finally, the chapter outlines current fuel and generation technology usage and potential, and defines which technologies would be appropriate for different countries. 2.1 The Caribbean The Caribbean region extends from the northern Caribbean Sea to the northeast of South America. The region is defined by the chain of islands running through the Caribbean Sea. The region has two main subregions: the Greater Antilles and the Lesser Antilles. The Greater Antilles is composed mostly of the larger islands, including Haiti and the Dominican Republic (which share Hispaniola Island), Cuba, Jamaica, Puerto Rico, the Bahamas, and the smaller Cayman Islands. The Lesser Antilles comprises a ring of smaller islands and nations, including Anguilla, Antigua and Barbuda, Barbados, Dominica, Grenada, Guadeloupe, Martinique, Montserrat, St. Kitts and Nevis, St. Lucia, St. Vincent and the Grenadines, Netherlands Antilles, and Trinidad and Tobago. Other countries traditionally considered part of the Caribbean are Aruba, Belize, Bermuda, British Virgin Islands, Guyana, Saint Barthélemy, St. Martin, Suriname, Turks and Caicos Islands, and the US Virgin Islands, many of which are in the Atlantic or on the mainland of South America. The countries within the Caribbean region are geographically diverse. While some countries are over 100,000 km2, others are smaller than 200 km2. The outer ring of islands is mostly flat land, while the inner ring is mainly composed of volcanic mountainous islands, many of which have geothermal activity. The islands themselves are relatively close together, in many cases just a few kilometers apart, which increases the feasibility of energy interconnections. The countries of the Caribbean also range in terms of their economic and population sizes. A few of the larger islands, such as Cuba, the Dominican Republic, Puerto Rico and Jamaica, have multibillion-dollar economies, while the smaller islands have gross domestic products (GDPs) in the range of a few million US dollars. Similarly, while some countries have millions of inhabitants, others have a few thousand. The range in terms of gross national income (GNI) per 4 capita is just as varied. Some of the poorest countries, such as Haiti, have a GNI per capita close to US$600, while in some islands that thrive on tourism or industry, the GNI per capita reaches more than US$20,000. Figure 2.1: Main Countries Analyzed and Electricity Market Size The countries studied in detail in this report include a number of the largest and most populous islands in the Caribbean, including over half the population and about one third of the installed generation capacity. The countries range from extremely small to very large. Figure 2.1 shows these countries on a map and their relative electricity market sizes, while Table 2.1 outlines key statistics. Due to the largely different sizes and populations, each island has vastly different installed capacity and energy needs. As described in Section 2.3, there are numerous technology and fuel options for the region; these options have varying appropriateness given the resources, demand and size of the islands. Table 2.2 also includes the other Caribbean countries that were not studied in detail. Some were briefly examined due to their importance for regional solutions. 5 Table 2.1: Caribbean Countries and Key Statistics Pop. GDP GNI/Capita Installed Country (Million) (US$B) (US$) capacity (MW) Main Caribbean Countries Studied Antigua and Barbuda 0.09 1.2 13,620 90 Barbados* 0.26 3.4 9,330 238 Dominica 0.07 0.4 4,770 21 Dominican Republic 9.95 45.8 4,390 5,518 Grenada 0.10 0.6 5,710 49 Guadeloupe (overseas department of France)* 0.42 9.7 21,780 411 Haiti 9.88 7.0 660 226 Jamaica 2.69 15.1 4,870 1,161 Martinique (overseas department of France)* 0.41 10.4 25,908 412 St. Kitts and Nevis 0.04 0.5 10,960 48 St. Lucia 0.17 1.0 5,530 72 St. Vincent and the Grenadines 0.12 0.6 5,140 58 Subtotal 24.2 95.7 8,243 Other Caribbean Countries Anguilla (British overseas territory) 0.014 0.1 19,945 24 Aruba (part of the Netherlands) 0.11 1.9 21,800 150 Bahamas, The 0.34 6.9 17,160 455 Belize 0.33 1.4 3,820 70 Bermuda 0.07 5.9 69,900 175 British Virgin Islands (British overseas territory) 0.03 0.9 38,500 10 Cayman Islands (British overseas territory) 0.05 1.9 43,800 115 Cuba** 11.20 110.8 9,700 5,180 Guyana 0.76 1.2 1,420 310 Montserrat (British overseas territory) 0.01 0.0 3,400 6 Netherlands Antilles, including Curacao, Bonaire, Sint Eustatius, Saba** and Sint Maarten** (part of the 0.23 2.8 16,000 210 Netherlands) Puerto Rico (commonwealth of the United States)* 3.97 67.9 10,960 5,864 Saint Barthélemy (overseas territory of France) 0.009 0.23 33,800 21 St. Martin (overseas territory of France) 0.035 0.54 18,850 52 Suriname 0.52 2.9 4,990 390 Trinidad and Tobago** 1.34 23.9 16,540 1,480 Turks and Caicos Islands (British overseas territory) 0.03 0.2 11,500 4 United States Virgin Islands (territory of the United 0.11 1.6 14,500 323 States)* Subtotal 19.16 231 14,839 Total 43 326 23,082 *Guadeloupe, Martinique and Barbados are not eligible for support from the World Bank. They are studied in more detail than others due to their importance for the ECGP and for interconnections with countries eligible for support from the World Bank. **These countries were studied in some detail due to their importance for regional solutions. Sources: World Development Indicators, CIA Fact Book, EIA, IEDOM, Nexant 6 2.2 Electricity Market Overview Although the Caribbean countries vary significantly, many characteristics of their power markets are similar. The current power generation market in the Caribbean consists nearly exclusively of regulated, vertically integrated utilities that sell electricity to end-use customers. Some independent power producers (IPPs) and customer-level photovoltaic (PV) installations exist and sell to the local utility. In some Caribbean countries self-generation is an economic way to meet industrial demand or to supply power in the event of load shedding. Since most countries are geographically small, they have small power systems that require high reserve margins to provide satisfactory reliability. There are no existing interconnections between island nations to increase market sizes, and therefore no electricity trade among countries. The main challenge faced by these utilities is high operating costs, driven by high fuel prices and diseconomies of scale. Remoteness and other geographic characteristics typical of small islands also increase costs. The expensive operating costs lead to some of the world's highest electricity tariffs, at around 25 US cents/kWh, compared to 8 US cents to 15 US cents/kWh in many other regions. The high prices hurt residential, commercial and industrial consumers. Although access to electricity in the region is generally high, the quality of service can be low. Some countries experience significant load shedding, while others are faced with deteriorating equipment and with high technical and nontechnical losses. Nonpayment for electricity services makes energy more expensive and hinders cost recovery. Inadequate tariff levels and a lack of appropriate regulations to promote innovation and efficiency exacerbate the problems. In the face of these issues, the countries on which this study focuses are projected to experience enormous growth. Among the countries studied, demand is forecasted to grow at around 3.6 percent through 2028, leading to a near doubling of 2009 values by 2028. Individual country growth rates range from 2.4 percent to 7.9 percent per year. Haiti is expected to experience some of the largest growth since it currently has both a large population and low access rates. Total peak demand is shown in Figure 2.2 (see Annex 1 for a full table of expected demand growth). Figure 2.2: Peak Demand Load Forecasts 2009­2028 (MW) 1000 2028 Forecast 8000 7000 2009 Net Peak Demand (MW) 800 6000 600 5000 4000 400 3000 200 2000 1000 0 0 Source: Nexant 7 To produce enough energy to cover this growth, there are a large number of committed and planned installations. Committed projects are those projects which are not yet operational but are sufficiently far along in planning or construction to assume that they will be built and operational by 2014. Planned projects are those at an early stage of development. Figure 2.3 depicts existing, planned and committed new generation capacity in the Caribbean. Dominica and Nevis have relatively high planned investments in comparison to existing or committed generation due to their large geothermal resources, which are currently being explored. As necessary, plants not yet planned will fill gaps between needed generation and the sum of existing, committed and planned projects. Figure 2.3: Current, Planned and Committed Power Generation (MW) Existing 3000 400 Committed 2500 Planned 300 2000 1500 200 1000 100 500 0 0 Source: Nexant 2.3 Fuels and Generation Technologies: Usage and Potential in the Region The region currently depends on two high-priced, oil-based products--distillate (diesel) and HFO--to fuel its electrical power generation. In total, 71 percent of the installed generation capacity is fueled with distillate and/or HFO. Natural gas supplies 11 percent of power generation demand (mostly in the Dominican Republic, Trinidad and Tobago, and Barbados), and coal 6 percent (mostly in the Dominican Republic). Among the renewable resources currently used, hydro accounts for 11 percent of existing capacity, with wind, photovoltaic, municipal waste and cogeneration combined amounting to about 1 percent. Table 2.2 shows the current fuels employed by each country for power generation. Distillate and HFO fuels tend to supply medium-speed diesel (MSD) and low-speed diesel (LSD), which make up 36 percent of the existing generation capacity. Steam turbines provide an additional 19 percent of the capacity, of which more than two-thirds are fueled by HFO, with the remaining one-third using coal. Combined cycle (CC) and gas and steam turbines also generate electricity for the Caribbean. Figure 2.4 shows the distribution of generation technologies in the countries studied. 8 Table 2.2: Current Fuels for Power Generation Heavy Natural Country Distillate Coal Other Fuel Oil Gas Antigua and Barbuda X X Barbados X X X Bagasse Dominica X Dominican Republic X X X X 20 percent hydro Grenada X Haiti X X Jamaica X X Bagasse Martinique X X Bagasse, Guadeloupe X X X geothermal and wind (4% each) St. Kitts X X Nevis X St. Lucia X St. Vincent and the Grenadines X X Trinidad and Tobago X Source: Nexant Report If demand doubles by 2028, the problems associated with reliance on high-priced liquid fuels will increase proportionally. This opens an economic window of opportunity for other fuels and technologies. Gas delivered by pipeline, or liquefied natural gas (LNG), as well as renewable sources such as geothermal and wind, may become attractive options. Figure 2.4: Existing Generation Technologies, MW The following sections outline both fossil fuel and 47 Combined Cycle Comb Cyc renewable generation 551 886 Gas Turbine Gas Turb technologies used in the 650 Steam Turbine Caribbean or with potential Stm Turb for future use. Of the fossil 692 Low LSD Speed Diesel fuels, the section looks at Medium Speed Diesel MSD liquid fuels, solid fuels such Hydro Hydro as coal and petroleum coal, 1115 900 Other Other and natural gas delivered as LNG, compressed natural Source: Nexant Report gas (CNG) or pipeline gas. It then discusses the various renewable technologies; the discussion is limited to those that can provide grid-connected, commercially ready, utility-scale power. These consist of solar photovoltaic and concentrating solar thermal, wind turbines, biomass (including biogas/landfill gas), small and mini hydro power, and geothermal. However, many other technologies not focused on in this report may also be viable in the future; such as marine technologies, which are briefly mentioned. Each section includes a discussion of current usage in the Caribbean and a brief analysis of the 9 viability for the Caribbean region. This high-level resource analysis is used in Chapter 3 when country-specific options are examined. 2.3.1. Liquid Fuels (Distillate, Heavy Fuel Oil) As mentioned above, distillate and HFO are widely used in the Caribbean, mainly due to the low capital costs of technologies using liquid fuels (LSD, MSD, gas turbines) and the ease of modularity. Since there is limited domestic capacity to produce liquid fuels in the region, countries import the fuels at international prices, which tend to be high and volatile, thus increasing operating costs and making diesel-generated electricity some of the most expensive in the region. As a result, the cost per kWh for diesel-generated power in the Caribbean is estimated at around 20 US cents/kWh for a plant operating at high-capacity factors. Most of the existing engines on the smaller islands of the Caribbean are designed to use distillate instead of HFO, even though distillate is more expensive because it produces relatively fewer air emissions. Some countries such as Grenada use only diesel, whereas other nations such as Jamaica are trying to phase out HFO because of environmental concerns. Many areas have banned HFO use near holiday resorts. However, because of high oil prices, public utilities in the region have experienced pressure in the past to reduce operational costs by switching from diesel to HFO. Trinidad and Tobago is the only country that is a net producer of fuels. For other countries, most imports come from Venezuela through the PetroCaribe agreements and others from refineries in Aruba, Curacao, Surinam and St. Croix. The following countries have some fuel supply from domestic sources: The Dominican Republic has two small refineries that produce products for the domestic market and fuel oils for the power generation industry. Jamaica has a refinery that imports crude oil and produces some liquid fuels for power generation plus diesel, gasoline and aviation fuels for domestic consumption. Martinique has a small refinery that produces heavy fuel oil for power generation in Martinique, French Guiana and Guadeloupe as well as products for domestic consumption. Barbados produces a small amount of crude oil and sends it to Trinidad for processing. Barbados also produces a small amount of natural gas, which is used for domestic consumption as well as for power generation. Trinidad is the major producer of natural gas as well as crude oil and petroleum products. All of its electricity generation is fueled by natural gas. 10 2.3.2. Coal Coal is currently used on some Caribbean islands, although its use is not widespread. To date, coal has been used in the Dominican Republic as fuel for four different steam power plants and is imported from Colombia and the United States. There are also pulverized-coal power plants in Guadeloupe and Puerto Rico; the coal is purchased mainly from Colombia, although some coal comes from the US and Venezuela. The coal plants in Guadeloupe--two 30-MW boilers--burn coal and bagasse and a third 34-MW boiler (to be commissioned in February 2011) will burn coal. Although coal is often cheaper than other energy sources and has a more stable price, for islands without existing coal import facilities or power plants that can burn coal, transitioning to coal may be expensive in comparison to liquid fuels. A country must construct a coal terminal that is only used a few times a year and, as shown in Figure 2.5, transportation to small islands is significantly more expensive. Because coal cannot be used as an alternative fuel in diesel generators or gas turbines, new plants must be constructed and would need to conform to the country's environmental standards. New coal-fueled power plants have much higher initial capital costs than other generators such as diesel or gas turbine units. Furthermore, environmental Figure 2.5: Cost of Transporting Coal considerations should be taken 12 Coal Transportation Cost, $/GJ into account in the choice of a 10 technology that will last for decades. Coal has large 8 externalities from high levels of Coal to Eastern Caribbean Islands 6 local air pollutants such as NOx Coal to Jamaica & Dominican Republic and SOx, and global pollutants 4 such as CO2, that are not 2 incorporated into current market 0 prices. The import of coal through coal import terminals, which 0 100 200 300 400 require deep port depths, may also Power Plant Size, MW have significant impacts on the Source: Nexant Report local environment. If the costs of environmental externalities were internalized, coal would become less economical, thus improving the economics of renewables and other sources of energy. 2.3.3. Petroleum coke Petroleum coke is sparsely used in the Caribbean. The Dominican Republic has used petroleum coke as an alternative to coal in coal-fired power plants. Jamaica plans to install a delayed coking unit to convert the heavy part of the crude to diesel, lighter distillate products, and petroleum coke, which will eliminate the use of HFO in power plants. Jamaica Public Service would like to build a power plant next to the unit in order to utilize the petroleum coke by-product. 11 Beyond use in Jamaica, it is unlikely that petroleum coke will expand significantly in the region. While Venezuela produces substantial amounts of petroleum coke as a by-product of processing heavy crude oil, arranging deliveries would likely be more difficult and expensive than coal since the fuel is not widely used. Moreover, because of high sulfur levels, local environmental standards may not permit the use of petroleum coke from some sources. If the cost of pollution (such as sulfur or CO2) were internalized into the cost of petroleum coke, this fuel might not be viable as a source of power generation in the Caribbean. 2.3.4. Natural Gas (LNG, Mid-Scale LNG, CNG, Pipeline Gas) Natural gas has the potential to fuel high-efficiency, relatively clean generation technologies, such as simple cycle combustion turbines (CCT) and combined cycle gas turbines (CCGT). There are various ways to deliver natural gas to islands, as discussed below, including LNG, compressed natural gas and pipeline gas. Each has varying feasibility, and further analysis of the potential on a country-by-country basis is warranted. 2.3.4.1. Liquefied Natural Gas (LNG) LNG is not widely utilized within the Caribbean. Although Trinidad supplies most of the LNG in the region, since it is the largest exporter to the United States, within the Caribbean it only supplies Puerto Rico and the Dominican Republic. The terminals in these two countries are each situated adjacent to a large power plant complex. In Peñuelas, Puerto Rico the LNG terminal supplies a 540-MW power plant plus a desalination plant, and in Andres, Dominican Republic, the LNG terminal supports a 310-MW power plant. For a number of reasons, Figure 2.6: LNG Transportation Costs additional usage of LNG only 40 LNG Transportation Cost, makes sense for a limited 35 number of larger countries 30 (Jamaica, Guadeloupe, Eastern Caribbean Islands $/GJ-HHV 25 Martinique, Barbados and 20 Cuba). Most potential markets in 15 Jamaica the Caribbean are for small 10 quantities at short to medium 5 distances. As discussed in 0 Section 2.3.4.2, there is little 0 200 400 600 800 Power Plant Size, MW experience with building small Basis 75% Plant Utilization LNG ships or barges, and only a Source: Nexant Report limited number of shipyards are outfitted to produce these vessels. Similar to coal, the cost of transportation increases as the size of the market decreases (see Figure 2.6). For small countries, the infrastructure costs of the receiving terminals and storage overwhelm savings from displacing distillate or HFO with gas. An added logistical problem of LNG is transportation within the country. Some of the larger Caribbean islands with reasonable potential natural gas demands lack internal gas pipeline systems, and power plants are spread around the islands. Therefore, the delivery of gas to all the 12 power plants would require the additional cost of a pipeline distribution system. Unless the economics justified developing the pipeline system, the LNG market would be limited to the largest individual power plant or to power plants that are close together. 2.3.4.2 Mid-Scale LNG Mid-scale LNG refers to systems designed for between 100,000 and 1 million tons of LNG throughput per year. From initial cost data provided by a mid-scale LNG developer, it appears that the mid-scale LNG option could produce the lowest-cost fuel for five locations: Antigua and Barbuda, Grenada, St. Vincent and the Grenadines, Haiti and North Jamaica. On the two larger islands (Jamaica and Haiti), mid-scale LNG may cost less than large-scale LNG, while on the smaller three (Antigua and Barbuda, Grenada, St. Vincent and the Grenadines), mid-scale LNG slightly beats coal-based technologies. Although mid-scale LNG could be a viable option for the Caribbean, it is a nascent technology, which brings additional risks. Developers of this technology are limited; therefore, Nexant was unable to verify or revise the cost information provided. The only plant in development is in Norway, where the current market is 120,000 tons per year. In addition, several factors that may increase costs are not included in the estimates, including costs for specialized docking facilities and costs associated with increasing storage or vessel size as demand grows. Therefore, the option is not studied in detail in this report but may warrant additional analysis. 2.3.4.3 Compressed Natural Gas (CNG) To date, no commercial CNG marine vessels have been built worldwide, making this a nascent technology. Most of the proposed CNG transportation systems would be designed to transport large quantities of gas over short distances. Consequently, islands with large demand, such as Barbados, Jamaica, Martinique, Guadeloupe, the Dominican Republic and possibly Haiti, are the best candidates. However, until a commercial CNG marine transportation system is in operation, the initial cost of operating a first-of-a-kind system adds additional risks and costs. However, it may be an attractive option in the future. 2.3.4.4 Pipeline Gas There are currently no intercountry gas pipelines in the Caribbean, and most countries have limited, if any, internal distribution networks. This study focuses on the Eastern Caribbean Gas Pipeline (ECGP), which was proposed in 2002 by the Prime Minister of Trinidad and Tobago. The initial concept is to connect a few islands to the gas supply in Trinidad and Tobago, including Barbados, Martinique, Guadeloupe and St. Lucia. However, the pipeline would be expandable to other islands north of Guadeloupe. This pipeline is explored further in Chapter 4. It appears that gas pipelines would be economical for all four countries that it plans to reach. One of the biggest benefits of pipeline gas is that it is not affected by weather, and the only likely interruption is from the breakdown of the feed gas compressor, which can easily be avoided by having sufficient spare capacity. There is no visual impact offshore during operation and there is a small onshore footprint. Some of the negative aspects are that a catastrophic failure such as a 13 line break caused by a submarine seismic event or an unsupported span could temporarily or permanently shut down the pipeline. In addition, gas pipelines have high capital costs that must be covered at the beginning of the project when the demand is much smaller than the ultimate demand. Therefore, unit costs are relatively high in the early years. Subsidies may be needed to provide incentives for the pipeline until demand increases. 2.3.5 Solar Photovoltaic (PV) and Concentrating Solar Power (CSP) Although the sun shines everywhere in the Caribbean, frequent cloud cover and the transient nature of clouds limit the hours of bright sunlight. As a result, the high capital cost of PVs reduces the economic competitiveness when compared to other technologies available for central station power generation.6 Still, PV technology is used in the region, mainly stimulated by subsidies such as high feed-in tariffs for purchases of renewable energy, favorable tax treatment, and other measures to promote development. Martinique and Guadeloupe have 19 MW and 16 MW, respectively, of installed PV capacity, primarily on warehouse rooftops but also as ground PV plants, which sell to the utility at a French Government-mandated rate of 400 per MWh. Given the exponential development of PV projects, the French Government, decided in July 2010 to lower the feed-in tariffs by an average 12 percent. CSP, on the other hand, is not currently used on a large scale in the Caribbean, since the transient nature of clouds makes it difficult to design plants because the units cannot use diffuse light. Furthermore, a CSP plant needs to be at least 20 MW to achieve reasonable economies of scale, which would require 90­150 acres (36­60 hectares) per plant. It may be difficult to locate a sufficient number of large parcels to support significant penetration, especially on the smaller islands. 2.3.6 Wind Wind turbines are in operation at numerous sites in the Caribbean, and the potential is being explored on many additional islands. Turbines for grid usage are presently operational in the Dominican Republic (100 MW at two 50 MW wind farms), Jamaica (20 MW), Guadeloupe (25 MW at 13 wind farms) and Martinique (1 MW). The turbines in Montserrat were put out of operation by volcanic activity on the island. Demonstration projects have also been built both in Antigua (a 120-kW vertical axis wind turbine) and Montserrat (an 85-kW horizontal axis turbine). Other demonstration projects are being considered for Barbados and Curacao. The potential for wind power in the Caribbean is relatively large since wind patterns are dominated by the northeast trade winds. The trade winds blow throughout the year, interrupted only at short intervals during the summer by tropical disturbances and in the winter by eastward- moving Atlantic depressions. Thus, a number of wind farm projects are being built, giving wind the potential to be the fastest-growing renewable energy technology in the region over the next two decades. 6 The Nexant Report does not consider the competitiveness of solar technologies for distributed uses. 14 Although there are promising sites on most Caribbean islands, the economic viability of wind is highly site dependent, and detailed wind measurements must be conducted at potential sites to arrive at more accurate projections of the feasibility of specific wind power development. 2.3.7 Geothermal Current usage of geothermal resources in the Caribbean is limited. The only operational geothermal plant is the 15 MW Bouillante plant in Guadeloupe, which has produced electricity since 1986. Geothermal projects are at various stages of exploration and development in St. Lucia, Dominica and Nevis. On the other hand, the potential for geothermal energy is huge. It is of the most underutilized indigenous energy resources in the Caribbean. The islands of Saba and St. Eustatius (Statia) of the Netherlands Antilles, St. Kitts and Nevis, Montserrat, Dominica, St. Lucia, St. Vincent and the Grenadines, and the French territories of Guadeloupe and Martinique form part of the active volcanic arc of the Eastern Caribbean and the Lesser Antilles, creating ideal geothermal resources. In the cases of Dominica (at Wotten Waven) and St. Lucia (at La Soufrière-Qualibou), intense surface hydrothermal activity marks the presence of high-enthalpy geothermal systems. Resources also exist in Grenada. Estimates of geothermal resource availability in these countries vary from 450 MW to several thousand MW. 2.3.8 Hydro The Caribbean provides an ideal environment for hydropower, with hilly areas and high year- round rainfall. As a result, the Caribbean islands already have well-developed hydro resources. At present, grid-connected hydroelectricity is generated in Dominica (7.6 MW), the Dominican Republic (472 MW), Haiti (62 MW), Jamaica (43 MW), St. Vincent (6 MW) and Guadeloupe (9.4 MW). There are also several new hydropower plant developments, especially in the Dominican Republic. However, future exploitation may be limited to larger countries with more resources. Although the introduction of low-volume, continuous-flow systems has made hydropower technologies readily applicable for small streams, poor agricultural practices and inadequate forest management have decreased flows in rivers and streams on many islands of the Caribbean. Given the decreased water flow, with the exception of the larger Caribbean countries that still have some rivers of note, only Dominica, and to a lesser extent St. Vincent and the Grenadines, may be able to economically exploit hydropower. However, hydro is highly site specific and detailed studies must be conducted at potential sites to arrive at more accurate projections of the economic viability of development. 2.3.9 Biomass The Caribbean region has various biomass resources, which are utilized in a number of countries. As mentioned in Section 2.3.2, Guadeloupe uses bagasse (and coal) to fuel two boilers, and the bagasse contribution accounts for the equivalent of a 15-MW boiler working in baseload. Martinique has a 4-MW municipal waste plant that primarily uses paper and plastic. Several 15 other biomass projects are being considered in the Bahamas, the Dominican Republic and Jamaica. In addition to carbon-based materials, waste-to-energy technologies such as landfill gas may also be a viable option, although municipal solid waste disposal sites in the Caribbean currently lack the means to collect generated landfill gas. Large cities with landfill disposal could consider modification of existing landfill sites to collect and utilize resulting gas. Moreover, waste-to- energy encompasses a wide number of technologies, some of which are highly evolved while others are still emerging. Definitive estimates of biomass power generation potential in the Caribbean are not available due to the site-specific nature of the resources. However, the potential appears to be large. Detailed studies are required to demonstrate resource potential and economic viability. 2.3.10 Other Technologies Numerous other renewable energy technologies exist that are not considered in this report, but these may be competitive and offer significant potential for the Caribbean islands in the long term. In particular, given the geography of the Caribbean, marine technologies have the potential to play a large role in the energy future. For example, wave power can harness the ocean to generate electric power, tidal power can use the changing currents to produce electricity, and Ocean Thermal Energy Conversion (OTEC) utilizes temperature variations in shallow and deep water to run an engine. Biofuels may also present another option. Distributed uses of technologies are not considered, although these may play a role in meeting the energy needs of the islands, particularly the needs of the rural poor. 2.4 Conclusion Overall, the Caribbean is a diverse region with disparate energy needs, ranging from large island countries with millions of people, such as the Dominican Republic and Puerto Rico, to extremely small ones, such as Anguilla and St. Kitts and Nevis, with a few thousand inhabitants. The sizes of the economies range from billions of dollars to a few million. Given this disparity in size and wealth, energy access and demands vary. Most countries have near-universal access, while others, such as Haiti, struggle to provide coverage. However, the main challenge of these countries is similar: supplying a growing energy demand in a reliable and efficient manner. Most countries rely on diesel and HFO, which are expensive and lead to extremely high electricity tariffs, although a few also rely on natural gas, coal, bagasse and hydro. Since electricity demand is projected to double by 2028, large new investments must be made, and it is useful to consider what alternative options may be a part of meeting the challenge of supplying cheaper energy to the Caribbean. Given the distinct nature of the countries and their energy needs, no single development path will be suitable for all countries, and it is important to consider different options. Most islands currently use diesel and HFO, although a few also rely on natural gas, and fewer on coal, bagasse 16 and hydro. However, numerous other resources, both fossil and renewable, are available in the region. These are summarized in Table 2.4. This report indicates that the resources with the most potential are LNG, pipeline gas, geothermal, wind, hydro and biomass. The Nexant Report concludes that all renewable resources (except solar) are viable, even without subsidies. It is important to note that the report only examines large-scale grid-connected systems, and does not look at the economics or viability of distributed systems. In order to compare the viability of these options, the following chapters explore the economics of these technologies on a country-by-country basis. Table 2.4: Technology Options for the Caribbean Usage in the Fuel Type Technology Potential Region Distillate (MSD, LSD, GT) Wide Wide usage likely to continue without interventions. Oil HFO (MSD, LSD, GT) Wide Wide usage likely to continue without intervention. Potentially viable for many islands, but Coal Coal (PC, CFB) Limited environmental externalities should be considered before implementation. LNG Limited Potential limited to countries with high demand. Potential for many countries, but not studied in Mid-Scale LNG None detail since the technology is nascent. Natural Gas Potential limited to countries with high demand, but CNG None not studied in detail since the technology is nascent. Trinidad and Potential limited to countries that a pipeline (not yet Pipeline Gas Tobago developed or agreed to) reaches. Solar Photovoltaics Very limited Potential, but capital costs are still high. Potential limited by solar influx and land Concentrating Solar Power None availability. Wind Limited Large potential on most islands. Geothermal Very limited Large potential on certain islands with resources. Renewable Large potential limited to a few countries with rivers Hydro Limited of note. Large potential, but further assessments are needed Biomass/Waste-to-Energy Very limited to identify specific sites. Emerging technologies None Potentially large, but not examined in this study. (wave, tidal, OTEC, etc.). 17 Chapter 3 Individual Countries' Energy Options A lthough the Caribbean as a whole faces similar energy challenges, the appropriateness of each technology for a single country is highly dependent on that country's location, resources and electricity demand. This section provides a country-by-country analysis of the fossil and renewable technologies outlined in Chapter 2 in order to determine which are most cost effective for which countries. It first explains the methodology, describing the screening curve analysis used for comparing technologies and presenting the assumptions used to determine costs for both renewable and fossil fuel technologies. Next, it provides screening curves on a country-by-country basis; these curves compare the various options available in order to determine the least-cost options for each country. The results are later used to understand how regional options compare with individual country options. 3.1 Methodology and Assumptions Prior to conducting the specific country-by-country analysis, it is important to understand how the economics and resource constraints of fossil fuels and renewable energy differ. For example, fossil fuel technologies tend to have low capital costs, but high fuel costs increase the total costs incurred to produce electricity. In comparison, renewable energy technologies often have significantly higher capital costs, but in many cases negligible fuel costs. Given the differing allocation of when costs are incurred, in order to fairly compare the economics of the technologies all costs over each project's lifetime need to be included in the analysis. Moreover, while fossil fuels are accessible wherever they can be transported and operate at a wide range of capacity factors, renewable energy technologies tend to be site specific and operate at limited capacity factors. Thus, the basis for comparison among technologies is a screening curve analysis, which incorporates into the analysis tradeoffs among capital costs, operating costs and usage levels for different types of generating units. The screening curve helps identify the optimal mix of generating technologies for a specific type of load by creating simplified representations of costs and plotting this against the capacity factor. The cost is calculated using capital costs, operating and maintenance costs, fuel costs, estimated costs for transmission upgrades, the heat rate (or fuel efficiency) and the capacity factor. For example, this method recognizes that for applications requiring small amounts of annual generation, the low capital/lower efficiency characteristics of combustion turbines are preferable to high capital/higher efficiency characteristics of combined cycle units. 18 There are two ways to represent costs, either as total annual costs ($ per kW-year) or in unit energy costs (cents per kWh). The following equations define how each cost is calculated: total annual cost ($/kW-year) = (annualized fixed cost) + (variable cost * capacity factor * total hours per year) unit energy costs (cents/kWh) = total annual costs * (cents per dollar)/(hours in operation per year) Figure 3.1 presents these equations graphically. The scale for the solid line is US$/kW-year on the left side. The vertical axis intercept is the technology's fixed costs, while the slope of the line represents variable costs. The dotted line represents Figure 3.1: Cost Representation for Screening energy unit costs (US Analysis Method cents/kWh) and its axis is 2,500 80 on the right. The line slopes Example, US$/kW-yr 70 downward since capital 2,000 costs are spread over more Example, US cents/kWh 60 Annual Cost, $/kW-year Cost, US cents/kWh units as the capacity factor 1,500 50 increases. This report will 40 present all results in cents 1,000 30 per kWh. 20 500 Slope = Variable cost * The specifics of how this capacity factor * 8760 10 Intercept = Fixed cost method is applied to both 0 0 fossil and renewable 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% technologies are described Capacity Factor, % in the following sections. Source: Nexant Report 3.1.1. Fossil Fuel Analysis For each country, the fossil fuel options were added to the screening curve. The Nexant Report assumes that there is no practical limit on fuel; therefore, resources can be added to the extent needed and technologies can be used across the range of capacity factors. The technology with the lowest cost at each capacity factor is considered part of the Least Cost Line (LCL), although least cost does not take into account environmental externalities. As an illustrative example, Figure 3.2 compares generic technologies: coal-fueled steam plants, distillate-fueled gas turbines, and gas-fueled combined cycle plants. The costs are not for any specific Caribbean country. In this example the Fossil LCL (the lowest-cost technologies only considering fossil options) is composed of simple cycle distillate-fueled gas turbines from 0 to 15 percent capacity factor, gas-fueled combined cycles from 15 percent to 55 percent capacity factor, and conventional coal-fired steam plants from 55 percent to 90 percent capacity factor. In order to construct these curves for each country, it is first necessary to determine the country- specific fuel and technology costs. In this analysis, the capital costs are assumed to be the same 19 Figure 3.2: Illustrative Example of the Least Cost Line for all countries, but for some 160 fuels the prices vary across Gas Turbine 140 countries.7 For distillate and Combined Cycle Cost, US cents/kWh 120 HFO, the same price is used on 100 Conv Coal each island, since no new 80 Least Cost Line infrastructure is needed and similar delivery methods exist 60 for each country. On the other 40 hand, the price of coal varies 20 by country. This is because for 0 many of the islands coal would 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% require significant Capacity Factor, % infrastructure investments, and Source: Nexant the smaller the island's demand, the higher the cost per unit because the initial capital costs of a delivery system are spread over fewer gigawatt hours (GWh). Dominica and St. Kitts and Nevis are the only countries where coal is not a practical option since the demands are so small. As described below, the estimated cost of natural gas also significantly varies among countries given the large initial infrastructure costs of setting up a delivery method. For each country, the lowest-cost gas option is selected as the fuel for the screening analysis. For the largest countries--the Dominican Republic, Haiti and Jamaica--LNG appears to be the lowest-cost natural gas fuel. Although not studied in the same detail as the other fuel delivery options since it is a nascent technology, mid-scale LNG may also provide an economically attractive option for some countries. CNG is the lowest-cost gas option for several countries, but is always higher in cost than distillate, and therefore does not appear in the analysis for each country. For countries where CNG is estimated to be considerably lower in cost than distillate, it is more costly than other gas delivery options. Pipeline gas is the cheapest gas option for each country it reaches. However, since a pipeline is a regional solution, the impacts on the associated countries (Barbados, Martinique, St. Lucia and Guadeloupe) are discussed in Chapter 4. Table 3.1 summarizes the prices for fossil fuels in different countries.8 The prices assume that the fuels would be available starting in 2014 and used throughout a 15-year study period (through 2028). All associated transport and facilities are sized to accommodate the 2028 demand. The forecasted prices do not include any costs associated with CO2 emissions, which would further increase prices, particularly of coal. It is interesting to note that every country except Dominica has at least one fuel which is a lower-cost option than distillate (without including generation technology costs). 7 All prices were related to prices from the Energy Information Agency (EIA) report on fuel supply, prices and parameters. 8 The general basis for all prices is the March 2009 EIA report on fuel supply, prices and other parameters. 20 Table 3.1: Fossil Fuel Prices 2014­2028 Fuels Selected in Levelized Fuel Price, US$/GJ Country Addition to Coal and Fuel Distillate Coal Distillate Selected Antigua and Barbuda None N/A 12.3 20.7 Barbados Pipeline Gas 7.4 7.8 20.7 Dominica Distillate only N/A N/A 20.7 Dominican Republic LNG 9.4 4.2 20.7 Grenada None N/A 12.3 20.7 Guadeloupe Pipeline Gas 10.9 7.8 20.7 Haiti LNG 12.5 7.8 20.7 Jamaica LNG 9.8 4.2 20.7 Martinique Pipeline Gas 9.0 7.8 20.7 St. Kitts and Nevis None N/A 12.3 20.7 St. Lucia Pipeline Gas 10.5 9.1 20.7 St. Vincent and Grenadines None N/A 12.3 20.7 Note: for methodology on pipeline gas prices, see Chapter 4. Source: Nexant Report In addition to determining appropriate fuels and prices for each country, it is necessary to determine which generation technologies would best fit the country's needs based on its demand. For example, it is assumed that smaller countries would use 10-, 25- and 50-MW circulating fluidized bed (CFB) steam plants, while countries with larger demand could accommodate a 100- MW or 300-MW conventional coal steam plant. 3.1.2. Renewable Energy Resource Analysis Although the concept of the screening curve is similar for renewable technologies, renewable resources have several unique characteristics that must be taken into account in building the screening curve. First, unlike fossil fuel resources, which can be reliably supplied to areas where indigenous resources do not exist, renewable resources are site specific. For example, the wind blows and the sun shines almost everywhere, but the locations where their intensity is high enough for economic exploitation for power generation are limited; biomass and municipal waste have relatively low energy density, with a limited range over which they can be transported economically; and geothermal and hydro resources exist only in certain locations. Second, many renewable resources can only generate electricity within a limited range of capacity factors due to the intermittent energy input. Therefore, other capacity must be added to the system as reserve, which often increases the costs. Similar to fossil fuel technologies, capital costs for renewable energy are assumed to be the same in each country.9 To deal with the site-specific nature of renewable resources, all costs assume that the renewable technology is built on a good site. Total renewable energy development for each country would be limited by the available resources, which are summarized in Table 3.2. 9 Because biomass is the only renewable resource that requires the purchase of a fuel, its costs were assumed to be equal to the costs of export coal in the US. 21 Table 3.2: Renewable Resource Estimate for the Caribbean Region Resource Wind Geothermal Hydro Solar PV Biomass Total GWh/ GWh/ GWh/ GWh/ GWh/ GWh/ Country MW MW MW MW MW MW yr yr yr yr yr yr Antigua and Barbuda 400 900 27 47 427 947 Barbados 10 22 26 45 36 67 Dominica 100 701 8 40 45 79 153 820 Dominican Republic 3,200 9,000 210 1,104 2,899 5,079 6,309 15,183 Guadeloupe 15 33 30 210 98 171 143 414 Haiti 10 22 50 263 1,654 2,897 40 210 1,754 3,392 Jamaica 70 153 22 113 650 1,139 20 105 761 1,510 St. Kitts and Nevis 5 11 300 2,102 16 27 321 2,141 St. Lucia 25 175 36 64 61 289 St. Vincent/Grenadines 2 4 5 33 23 41 30 78 Trinidad and Tobago 50 110 308 539 363 669 Saba Island Total 3,762 10,255 455 3,189 294 1,552 5,781 10,128 65 335 10,357 25,460 Notes: It is most important to note that these estimates are preliminary and not comprehensive. A blank cell indicates that sufficient and credible information is lacking, and Nexant could not estimate the available resources. A blank does not mean that that resource does not exist in that country. Similarly, a small number may indicate that resources have been estimated, but does not indicate that the estimate included all resources. In particular, geothermal potential is especially uncertain, and the full potential will not be known until wells are drilled. This table estimates the technical potential, and does not consider economic or financial viability. Sources: Highlighted cells are Nexant-derived estimates from different sources. Nexant estimates Solar PV potential based on a US Government study covering 0.1 percent of land with PV and 200­300 W/m2 solar insolation. Guadeloupe: Wind Carilec 2002 http://www.carilec.org/Presentations/RE_Conf_2002/Specifity%20of%20Wind%20Market%20in%20Caribbean%20Islands.pdf Jamaica Wind Power Study, Renewable Energy Systems Ltd, UK. Ministry for Public Works, Transportation and Communications, Bureau of Mines and Energy Electricity of Haiti; Haiti Energy Sector Development Plan, 2007 ­ 2017: November 2006. http://www.bme.gouv.ht/energie/National_Energy_Plan_Haiti_Revised20_12_2006VM.pdf Database of Geothermal Resources in Latin American & the Caribbean, Liz Battocletti of Bob Lawrence & Associates, Inc. for Sandia National Laboratories under Contract No. AS-0989. February 1999. http://www.bla.com/ECB/PDFFiles/GeoResLAC.pdf Geothermal Energy Potential in the Caribbean Region, Erouscilla P. Joseph, Seismic Research Unit, University of the West Indies, St. Augustine, Trinidad, 2008. http://www.un.org/esa/sustdev/sids/2008_roundtable/presentation/energy_joseph.pdf Energy Sustainability in Latin American and the Caribbean: The Share of renewable Sources, ECLAC/UNEP (Economic Commission for Latin America and the Caribbean/United Nations Environment Programme) (2001); http://www.eclac.org/publicaciones/xml/3/13413/Lcl.1966i.pd 22 In total, an estimated minimum of 3,700 MW of wind, 455 MW of geothermal and 294 MW of hydro could be developed for power generation in the Caribbean. Additional resources could be developed from solar and CSP, although as mentioned earlier these are not considered due to the high relative costs.10 While there is some potential for biomass, the generation capacity is site specific, and there is little information on available sites at this stage. However, judging by experiences in other countries, there may be viable options to develop some sites from landfill gas, waste and by-products. In order to take into account the intermittency constraints, a line for each resource is only drawn over its applicable capacity factor. For geothermal, once a resource has been found, it is not limited by intermittency, and therefore on the screening curve it is shown over the entire capacity factor range (although it typically operates at high capacity factors). Wind, on the other hand, is extremely intermittent, and therefore is shown ranging between a 25 and 35 percent capacity factor, though the actual capacity factor will be site specific. Wind with backup is a more appropriate comparison to fossil fuels than wind without backup since backup increases the facility's reliability. For this analysis, backup consists of adding the costs of the country's lowest-cost generation option at a 5 percent capacity. This increases the capacity factor for the wind plant to between 30 and 40 percent. In Figure 3.3 below, backup costs from a 20-MW LSD are added. The capacity factors for hydro and Figure 3.3: Distillate LCL vs. Renewable Energy Options biomass are site specific, 90 Distillate LCL although in the figure, 80 Commercial PV 500 kW small hydro is shown over 70 Solar Trough 6 hr Storage Cost, US cents/kWh the range of 30 to 60 60 20 MW Geothermal percent capacity, while Biomass 50 biomass ranges from 40 to Small Hydro 40 1.5 MW Wind Turbine 75 percent. Both solar 30 1.5 MW Wind w/Backup troughs and PVs are 20 modeled with a capacity 10 factor between 20 and 25 0 percent. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Capacity Factor, % Figure 3.3 illustrates how Source: Nexant these resources appear when they are added to the screening curve. The figure compares renewable energy options to a 20-MW LSD, the Distillate LCL (the lowest-cost distillate option). Where a renewable energy option's line is below the dotted line, there is a net benefit to employing renewable options. Where it is above the dotted line, it represents a net cost. The figure shows that in Caribbean countries all grid-connected, utility-scale renewable energy (except solar) technologies examined have the potential, at a good site, to be considerably less costly than distillate-fueled power generation. Therefore, in this analysis of utility-scale power plants, solar PVs and troughs will not be considered for generation additions. 10 It is important to note that Nexant's analysis only looks at centralized generation and does not consider solar for distributed uses. 23 Renewables are particularly competitive in the Caribbean due to the high cost of diesel generation caused by the small installed capacities, high costs of liquid fossil fuels, and additional transport costs for the Caribbean. Although many of these renewable energy technologies are still competitive when compared to lower-cost fossil fuels, such as pipeline gas and coal, their competitive margin is diminished. 3.2 Country-specific Results The following results present screening curves for various countries in the Caribbean. These curves estimate the least-cost options for each country when acting as an isolated system. Many of these countries have other regional options, such as interconnecting to pipeline gas or integrating electricity markets with neighboring islands, as presented in Chapter 4. The results in this section are used to compare isolated options with regional options in Chapter 4, and also as the basis for cost information for the scenario analysis in Chapter 5. 3.2.1 Antigua and Barbuda, Grenada, and St. Vincent and the Grenadines At present, Antigua and Barbuda, Grenada11, and St. Vincent and the Grenadines primarily use diesel units to generate electricity, although all countries recognize that diversification is necessary. Antigua and Barbuda aims to transfer some units to HFO, the utility in Grenada believes that diversifying the fuel mix is a critical objective, and St. Vincent and the Grenadines hopes to provide 20 percent of electricity from renewable resources. Due to the islands' small demands (30 to 60 MW of peak demand), all have similar technology choices and fuel prices. Therefore, they are analyzed together. Figure 3.4: Options for Antigua and Barbuda, Grenada, The three countries have a and St. Vincent and the Grenadines number of energy options. 90 1.5 MW Wind Turbine Wind is the least-expensive 80 1.5 MW Wind w/Backup option at capacity factors at Cost, US cents/kWh 70 10 MW CFB Hi Coal which it might operate at a 60 10 MW MSD Dist good site. Other renewable 50 20 MW GT Dist plants, such as small hydro 40 and biomass, could be 30 competitive as well if suitable 20 sites are identified. In 10 considering only fossil fuels, 0 based on the basic fuel cost 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% analysis presented in Section Capacity Factor, % 3.1.1, coal is a possible Source: Nexant alternative fossil option to distillate. It is important to note, however, that a coal plant has more environmental impacts than a distillate-fueled plant, particularly in its concentrations of global greenhouse gas emissions, and significantly more 11 Grenada has geothermal resources, the development of which was not examined in this study. The government recently announced plans to explore the potential of development, which could impact the country's energy options. 24 impacts than renewable resources. LNG is not considered since the price is above that of distillate fueled generation. 3.2.2 Barbados Currently, most of Barbados' 240 MW installed capacity is generated from diesel units. Given this dependence, the private, vertically integrated utility, Barbados Light and Power, is looking to diversify its fuel mix away from imported liquid fuels. Fortunately, Barbados is blessed with many options for fuels and energy technologies that provide relatively low-cost options for the country. When the country is considered as an isolated system, the least-cost fossil fuel option is a 20- MW LSD facility running on natural gas (LNG), which would cost 11.3 US cents (with the plant operating at an 80 percent Figure 3.5: Selected Individual Country Options for capacity factor). Wind with Barbados backup is also competitive, 70 1.5 MW Wind Turbine and given its environmental 1.5 MW Wind w/Backup and economic benefits, 60 25 MW CFB Coal opportunities for Cost, US cents/kWh 50 20 MW LSD Dist development could be further 40 20 MW LSD LNG explored. Hydro and biomass may also be marginally 30 economical if adequate sites 20 are identified. Alternative 10 fossil options include a coal- fueled 25-MW CFB plant, 0 which would cost 11.7 US 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% cents per kWh at an 80 Capacity Factor, % percent capacity factor, and Source: Nexant continued diesel development with costs estimated at 19.2 US cents per kWh. However, similar to the discussion in Section 2.3.2, coal has more environmental issues than distillate, and these are not taken into account in this analysis. 3.2.3 Dominica and Nevis Currently, Dominica and Nevis both rely on diesel power but have a number of options for electricity generation. Most significantly, they both have large indigenous renewable potential, particularly for geothermal. Cheap fossil fuel options are limited since technologies such as coal and LNG have high upfront fixed costs, which lead to high unit costs when spread over the small demand (15 MW for Dominica and 10 MW for Nevis), thus making renewable energy options competitive. Since the analysis for the two islands is similar, they are considered together. Geothermal resources appear highly likely to be able to provide sufficient capacity to cover demand on each island. Comparing the cost of geothermal to the least-cost fossil option, a 5-MW MSD running on distillate at a cost of 20.4 US cents/kWh at an 80 percent capacity factor, it is 25 clear that there is significant economic benefit from geothermal development. The cost of geothermal is estimated at 5.5 US cents/kWh at an 80 percent capacity factor. At high capacity factors (around 80 percent), the net benefit would be approximately 15 US cents/kWh, which decreases until a break-even point with diesel at an 18 percent capacity factor. Given that geothermal plants run in a baseload mode, it is likely that the benefit of developing these resources would be large, provided that a sufficiently large market is available. For Dominica and Nevis, it is important to consider the size of the geothermal power potential compared to the islands' demands. A plant could be designed on both islands to serve 100 percent of the island's demand at the time of installation. The geothermal plant for the analysis is estimated at 20 MW on each island, but plants serving only Nevis or Dominica may be closer to 10 MW. The cost per kW of a smaller plant would be expected to be somewhat higher. However, even if the geothermal costs were twice the estimate above, the energy would cost 11 US cents/kWh at an 80 percent capacity factor, which would still be far below the cost of power generated from distillate. Since no power plant is Figure 3.6: Selected Individual Country Options for Dominica and Nevis available for service 100 90 1.5 MW Wind Turbine percent of the time, the 80 1.5 MW Wind w/Backup requirements for spinning and operating reserves may Cost, US cents/kWh 70 10 MW CFB Hi Coal 60 5 MW MSD Dist increase, since the utilities 50 20 MW Geo would need to plan for 100 40 percent backup of the 30 geothermal plant from other 20 resources. Although this could 10 be initially covered by existing distillate-fueled generators, it 0 may eventually be necessary to 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% build new plants exclusively Capacity Factor, % for backup. This new Source: Nexant generation would impose an economic burden that is not accounted for in this analysis. However, incorporating these costs would most likely not eliminate the economic advantage. In addition to geothermal, if good wind sites are identified, wind could supply energy at lower cost than distillate or coal. Other renewable energy options, not shown in the Figure 3.6, such as hydropower and biomass, might also contribute to lower-cost energy. 3.2.4 Dominican Republic (DR) Unlike many countries in the Caribbean, DR today uses a range of fuels, including coal and natural gas delivered as LNG, although most of its existing generation continues to be fueled by HFO. Given the country's large size and growing demand, DR has numerous options to meet future demand and reduce costs, including the continued use of fossil fuels and the development of its renewable potential. 26 DR has the largest demand of Figure 3.7: Selected Options for Dominican Republic any of the islands addressed 70 300 MW ST HFO in this study. This reduces the 60 50 MW GT LNG fuel costs of LNG by Cost, US cents/kWh 300 MW CC LNG 50 Small Hydro spreading the fixed costs over more gigajoules, making it a 40 1.5 MW Wind w/Backup 1.5 MW Wind Turbine competitive fuel option. Coal 30 is also an option, but 20 environmental considerations should be taken into account 10 before moving ahead with 0 coal development. If 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% alternative fossil fuels are not Capacity Factor, % available for generation, a Source: Nexant 300-MW HFO-fueled steam plant would be the likely replacement candidate, with costs more than three times as much as alternative options at high-capacity factors. DR has multiple economic renewable options as well. Wind with backup is marginally economical at the capacity factors corresponding to a good site. Studies have estimated that the Dominican Republic has approximately 460 km2 with excellent wind generation potential, totaling 3,200 MW. In addition, the country has an estimated 210 MW of small hydro potential. 3.2.5 Guadeloupe The bulk of generation in Guadeloupe is currently produced from diesel, although it also has two coal/bagasse boilers within the country, and one coal boiler to be commissioned. Its relatively large demand (260 MW) Figure 3.8: Selected Individual Options for Guadeloupe and installed capacity (411 70 25 MW CFB Coal MW) allows some of the 20 MW LSD Dist technologies with larger 60 capital costs to be Cost, US cents/kWh 20 MW LSD LNG 50 competitive. 1.5 MW Wind w/Backup 40 1.5 MW Wind Turbine Independently, the country 30 has various supply options, 20 including LNG, wind, 10 diesel and coal. Considering the least-cost 0 fossil options, Guadeloupe 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% has the options of building Capacity Factor, % CFB plants to burn coal or Source: Nexant natural gas (LNG)-fueled plants. When comparing for baseload power, at an 80 percent capacity factor, in this analysis coal-fueled power costs 11.7 US cents/kWh while gas-fueled generation is 12.5 US cents/kWh. Although coal is slightly less expensive than natural gas (LNG)-based generation at high- 27 capacity factors, this does not include a carbon price, which would likely make coal-based generation more expensive than gas. For comparison purposes, distillate-based generation, the most expensive and widely used option, costs 19.1 US cents/kWh. Wind with backup is marginally economical when compared to LNG and coal options and is highly economical when compared to diesel generation. 3.2.6 Haiti Unlike the other countries studied in this report, Haiti has a significant shortage of generating capacity. Moreover, only about 12 percent of the country has formal access to electricity. Although the metropolitan area of Port-au-Prince has an installed capacity of 155 MW, around half of all demand is often not served. Most of its generation is MSD fueled by distillate, and the machinery is in poor condition. Haiti has some existing and planned hydro plants. Therefore, due to its urgent need for new generation,12 Haiti has the potential to immediately benefit from the proposed alternative development paths. Haiti has various options for Figure 3.9: Selected Options for Haiti lower-cost energy technologies 70 20 MW LSD Dist and fuels. Wind with backup 25 MW CFB Coal 60 (20-MW gas turbine)13 and 20 MW LSD LNG Cost, US cents/kWh small hydro are economic 50 1.5 MW Wind Turbine options for the country. Haiti is 1.5 MW Wind w/Backup 40 currently collecting wind data Small Hydro to identify potentially 30 economic wind sites. 20 Considering fossil options, Figure 3.9 shows that the 10 lowest-cost options are a 20- 0 MW gas turbine (GT) running 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% on natural gas (LNG) at very Capacity Factor, % low capacity factors (although Source: Nexant it is questionable if it would be worth installing a GT to run for so few hours, particularly for a country like Haiti with a baseload deficit) and a 20-MW LSD plant running on natural gas (LNG) at 5 to 85 percent capacity factors. Coal is also an option for Haiti because the country has proven reserves of lignite, although environmental impacts must be taken into account. Figure 3.9 illustrates that without renewables, coal or LNG, costs are 65 percent higher at high-capacity factors. 3.2.7 Jamaica Ninety-five percent of Jamaica's energy is currently generated from petroleum products, making the country extremely reliant on fuels with volatile and high prices. As a result, the country is 12 The need will be even greater following the major earthquake that destroyed many buildings and infrastructure in Port-au-Prince on January 12, 2010. 13 It is unlikely that Haiti will afford to have a backup plant, given the deficit of baseload generation. 28 focused on diversifying its generation mix, particularly through the use of natural gas. Since Jamaica is a large country, numerous opportunities exist as alternative electricity sources. Jamaica's demand is concentrated in two areas: the southern coast around Hunts Bay and Montego Bay on the northern coast. The two areas are separated by a mountain range. Thus, the analysis was divided into two parts: Jamaica's southern region which makes up 60 percent of Jamaica's demand, and the northern area which serves about 30 percent of demand. The results for southern Jamaica and northern Jamaica are nearly identical.14 The study indicates that wind with backup (20-MW gas turbine) is a low-cost option at the capacity factors at which it might operate. Jamaica may also have opportunities Figure 3.10: Selected Options for Jamaica for hydro and biomass 60 50 MW CFB Coal development, although 50 50 MW GT LNG Cost, US cents/kWh further studies should be 20 MW LSD LNG conducted to understand the 40 1.5 MW Wind Turbine potential. Least-cost fossil 1.5 MW Wind w/Backup 30 options for Jamaica are a 50- MW GT running on natural 20 gas (LNG) for a capacity 10 factor from 0 to 10 percent, a 20-MW LSD running on 0 natural gas (LNG) for 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% capacity factors of 15 to 45 Capacity Factor, % percent, and a 50-MW coal- fueled CFB for capacity Source: Nexant factors from 50 to 90 percent. However, these results do not include environmental costs, and including a carbon price may make LNG the less-expensive option when compared to coal. As Figure 3.10 demonstrates, without coal or LNG a 20-MW LSD running on distillate would be the next least-cost technology, and costs would more than double at high-capacity factors. Although the results suggest significant economic benefits from developing LNG in both the north and the south, this study did not compare this option to the possibly viable option of a gas pipeline connecting the north and south. 3.2.8 Martinique Martinique's power sector runs almost exclusively on diesel plants, but has various options available for lower-cost energy generation. A 20-MW LSD fueled by natural gas (LNG) is the most economic option for baseload power, with costs of 11.5 US cents/kWh (at an 80 percent capacity factor), while gas turbines running on natural gas (LNG) would be best for peaking. A 25-MW CFB using coal is also an option, because it is slightly more expensive than LNG without considering CO2 costs, at 11.7 US cents/kWh (at an 80 percent capacity factor). If CO2 costs are included in the analysis, the competitiveness of LNG over coal may increase. The 14 The only difference between northern and southern Jamaica is the price of natural gas derived from LNG, with levelized 2014­2028 US$10.90/GJ for north Jamaica compared to US$10.16 for the southern coast. 29 Figure 3.11: Selective Individual Options for Martinique highest-cost option analyzed is 70 25 MW CFB Coal distillate fueling a 20-MW 60 20 MW LSD Dist LSD plant, which is estimated Cost, US cents/kWh 20 MW LSD LNG to cost 19.1 US cents/kWh. 50 1.5 MW Wind w/Backup Martinique also has the 40 1.5 MW Wind Turbine option of CNG, but since this 30 technology is nascent, it is not 20 suggested. 10 Compared to each of these 0 fossil fuel options, wind with 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% backup is economical at the Capacity Factor, % capacity factors where it Source: Nexant might operate at a good site. Other renewable resources, including hydro power and biomass, are likely to be economical if appropriate sites are found on the island. 3.2.9 St. Kitts Similar to Dominica and Nevis, St. Kitts has a small electricity demand of about 30 MW peak, limiting its options for alternative fossil fuels. The screening curve is the same as for Dominica and Nevis, as shown in Figure 3.6, with the least-cost fossil fuel option being a 5-MW MSD plant running on distillate. This electricity would cost approximately 20.4 US cents/kWh at an 80 percent capacity factor. Unlike Dominica and Nevis, however, St. Kitts's indigenous geothermal potential is not as vast or easily accessible, which makes it more likely to be expensive to exploit. Therefore, in the absence of an interconnection with Dominica, which will be discussed in Chapter 4, the other renewable options are wind with backup and biomass, both of which are site specific and would require further feasibility studies. Small hydro may also be competitive, but it is unclear whether adequate resources exist. 3.2.10 St. Lucia The electricity sector in St. Lucia primarily comprises diesel for its 75 MW of installed capacity. The country has a comfortable reserve margin, and the utility has reasonable regulation and a strong financial position. Given its dependence on fossil fuels, new supply options could decrease the costs of power generation and increase its financial strength. Renewables could be developed as clean alternatives because wind with backup is economical at the capacity factors where it might operate at a good site. St. Lucia is collecting wind data to determine the feasibility of wind developments. Similar to the other islands, hydro and biomass may be economical options if adequate sites are identified. 30 Among the fossil fuel options Figure 3.12: Selected Individual Country Options analyzed, the only technology for St. Lucia with lower costs than distillate 70 25 MW CFB Coal generation is a 25-MW CFB 60 20 MW LSD Dist fueled by coal. This is because Cost, US cents/kWh 1.5 MW Wind w/Backup natural gas (LNG)-fueled 50 1.5 MW Wind Turbine generation is more expensive 40 than distillate, given the large 30 upfront costs that would be 20 spread over a small demand. However, coal also has more 10 environmental issues than 0 distillate and should be 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% considered in a more detailed Capacity Factor, % cost comparison. Source: Nexant 3.3 Conclusions Overall, individual Caribbean countries have a number of energy options. The most appropriate fossil fuel technologies on each island are influenced by the island's size, while the competitiveness of renewable technologies is impacted by both the resources available and the cost of competing fossil fuels. Table 3.3 summarizes these results. Notably, the results indicate that the smallest islands, including Antigua and Barbuda, Grenada15, St. Vincent and the Grenadines, St. Kitts, and St. Lucia, all have limited fossil fuel options, with the cost of coal and distillate being comparable. Natural gas is not an economical option since there are high costs associated with delivering and developing infrastructure for natural gas in small markets. Consequently, renewable options, such as wind, hydro and biomass, are highly competitive where suitable sites can be identified. Dominica and Nevis have an array of choices similar to those of other small nations, but their options are augmented by large geothermal potential. In both countries geothermal energy would be the cheapest generation source at the capacity factors at which it would operate. However, it is important to consider the ratio of the size of the resource to the size of the market. In both countries, a plant could supply 100 percent of the island's demand at the time of installation; this would increase the requirements for operational reserves. Moreover, the extensive geothermal resource would be underutilized. Regional opportunities to solve these problems through interconnection are discussed in Chapter 4. 15 Grenada has a large estimated geothermal resource, the development of which was not examined in this study. The government recently announced plans to explore the potential of development, which could impact the country's energy options. 31 Table 3.3: Summary of Individual Countries' Viable Future Options16 Country Distillate Coal LNG Wind Geothermal Hydro* Biomass* Antigua and Barbuda Grenada St. Vincent and the Grenadines St. Kitts St. Lucia Dominica Nevis Barbados Guadeloupe Martinique Haiti Jamaica Dominican Republic = viable option * The resources are site specific and need to be studied further. In the slightly larger markets of Barbados, Guadeloupe and Martinique, natural gas (LNG) is the most economical option, and in all countries wind energy has the potential to be competitive if good sites are identified. CNG could also be viable in the future, but it was not the least-cost gas option. Mid-scale LNG may also be an option for these countries, but this resource was not explored in detail in this study since it is a nascent technology and thus brings additional risks. Finally, according to the study, alternative fossil fuels are competitive in the three largest markets (Haiti, Jamaica and the Dominican Republic). Due to the low cost of fossil fuels in Jamaica and the Dominican Republic, renewables such as wind lose the large competitive advantage that they have in smaller countries unless the environmental costs are factored in. In Haiti, natural gas (LNG) fuels the cheapest power at nearly all capacity factors, and wind energy is a viable option. 16 Although mid-scale LNG may be a viable option for many countries, it is not included in the analysis due to the nascent nature of the technology. Mid-scale LNG may be the lowest-cost option for Barbados, Jamaica, Martinique, Guadeloupe, the Dominican Republic and possibly Haiti. In addition, CNG may also be viable for Barbados, Jamaica, Martinique, Guadeloupe, the Dominican Republic and possibly Haiti, but it has additional risks since it is a new technology. In this analysis the geothermal energy for Martinique and Guadeloupe was not examined, though potential exists. 32 Chapter 4 Regional Energy Options T he major objective of this study is to explore, at a concept level, regional options that may reduce energy costs and increase system reliability. Three types of regional integration are considered in this chapter: (i) a gas pipeline, (ii) regional fuel storage facilities, and (iii) electricity market interconnections through submarine cables and overland transmission lines. These options are compared with individual country solutions in order to understand the additional benefits they could offer. It is important to note that the interconnections and regional solutions described in this section are by no means an exhaustive set of possible interconnections or regional solutions for the Caribbean. The purpose of this section is to make a preliminary determination of whether regional solutions are worth considering, and to indicate several among those examined that appear technically and economically feasible. 4.1 Natural Gas Pipeline Although there are many imaginable interconnections that use gas pipelines, this report focuses on the proposed Eastern Caribbean Gas Pipeline (ECGP). The initial concept is to connect a few islands to the gas supply in Trinidad and Tobago with pipelines that could supply demand growth for the next two decades. The first section would be a 172-mile, 12-inch pipeline from Tobago to northwest of Barbados with a small offshore lateral to the island's main power plant. The second section would be a 120-mile, 10-inch line from Barbados to Martinique with a side spur to St. Lucia. The third section would be a 188-mile, 8-inch line from Martinique to Guadeloupe. The pipeline is designed to send 50 million standard cubic feet per day (MMscfd) to Barbados and 100 MMscfd combined to Martinique, Guadeloupe and St. Lucia. This pipeline reaches depths of 5,300 feet between Tobago and Barbados and 5,600 feet near Martinique. Previously suggested connections to Grenada and St. Vincent were abandoned to avoid tectonic areas. The interconnections are seen in Figure 4.1. 4.1.1 Technical Feasibility of the Pipeline The interconnection appears to be technically feasible, although challenges may be encountered. There are steep slopes off the shores of Martinique that may require a rerouting of the pipeline and could add additional pipeline length. High Resolution Seabed surveys would be needed in the area. Moreover, due to hurricane season, each section of the pipeline would have to be 33 completed between the end of November and the beginning of June. Pipeline is laid at an average rate of 2.5 miles per day and the longest pipeline is 180 miles; therefore, the longest section should take only 75 days. This would leave a buffer period of around 100 days, which seems reasonable. 4.1.2 Economics of the Pipeline Various cost estimates have been made on the capital costs of the pipeline. In 2004 Doris Engineering performed an initial mapping survey and developed a capital cost estimate of US$550 million for the project. This cost was updated in 2008 to US$800 million. Since then, many costs have come down and Figure 4.1: Schematic of Eastern Caribbean Gas pipeline advocates believe the Pipeline Proposed Route cost would be closer to US$675 million. Independent cost estimates indicate that these costs are reasonable, but they are preliminary and subject to uncertainty. The economics of the pipeline are affected by two cost components: (i) the gas price and (ii) the transportation costs. The gas price would be determined by the price negotiated with the Trinidadian gas producers. Currently, Trinidadian prices vary based on end use. The lowest price is for residential consumers, followed by commercial and industrial consumers, and the highest price is for LNG production, which is indexed to the world price. The Nexant Report bases its economic analysis on a gas price equivalent to the LNG input price in Trinidad, which is the price of LNG in the US upon landing minus losses of 9.1 percent and gasification costs of US$1.42/GJ. Similarly, the distribution of transportation costs among the various islands would be determined by negotiations between the pipeline company (ECGPC) and the individual islands. For this evaluation, in order to divide the costs among countries, the fixed costs for each of the individual legs are multiplied by the maximum volume of gas to each island and divided by the total volume of gas that would use that section of pipeline. This results in 11 percent of the capital cost being allocated to Barbados, 26 percent to Martinique, 16 percent to St. Lucia and 47 percent to Guadeloupe. With this model, the transportation costs to each country in 2014, 2020 and 2028 are shown in Table 4.1, although for the purpose of this study a levelized cost of fuel 34 over the operation period was used for each country. The unit costs are lowest for Barbados, increasing for Martinique, St. Lucia and Guadeloupe. These price increases correspond to increases in the pipeline length. Table 4.1: Pipeline Transportation Costs ­ All Islands Connected Transportation Costs, US$/GJ, Based On Common Segment Costs and Usages Price to All Year Barbados Martinique St. Lucia Guadeloupe All Islands 2014 2.28 4.08 6.73 9.15 4.84 2020 2.03 3.59 5.63 5.58 3.88 2028 1.58 3.07 4.47 4.73 3.21 Source: Nexant Report Since most costs are fixed and do not depend on demand, as demand increases unit costs decline. Thus, the unit costs in US$/GJ are highest in 2014, which has the lowest demand and spreads the fixed costs over the smallest number of GJ, with decreasing costs through 2028. In addition, prices will be lowest if all islands connect due to the higher gas volumes delivered. In reality, low usage levels in early years may result in prohibitively high costs, and subsidies or cross- subsidies may be necessary until the market grows sufficiently large. This would add complexity to the situation because it may be prohibitively difficult for multiple countries to arrange such policies. If one or more of the islands decides not to interconnect, economies of scale would be lost and prices would further increase. Moreover, although the economics of the gas pipeline look promising, further analysis needs to be conducted. In particular, further sensitivity analysis of capital costs should be performed given the large uncertainty of the actual costs. Further investigation of expected growth rates of the natural gas market should also be completed to understand how varying growth rates of the pipeline affect the economic viability. These challenges will be discussed further in Section 4.4, while some of the political challenges are examined in Box 4.1. Box 4.1: History of the Eastern Caribbean Gas Pipeline The concept of a Caribbean gas pipeline was proposed by the Prime Minister of Trinidad and Tobago in 2002. An ad hoc development company was created and ownership stakes have changed several times. The current ownership structure of the Eastern Caribbean Gas Pipeline Company (ECGPC) is 40.5 percent Guardian Holdings, 40.5 percent Trinidad & Tobago Unit Trust Corp., 10 percent National Gas Company of Trinidad & Tobago (NGC), and 9 percent Intra Caribbean Gas Pipeline Limited (ICGPL). In 2003, a prefeasibility study demonstrated the technical and financial viability of the ECGP. A further in-depth feasibility study was completed in 2004, specifying the pipeline corridors, eliminating connections to smaller markets and estimating associated investment costs. The current concept envisages a 12-inch pipeline from the eastern gas fields of Trinidad up to Tobago; this pipeline has yet to be endorsed by the Government of Trinidad and Tobago. In March 2010 the Government of Barbados approved a gas pipeline connection to the island. To achieve economies of scale and scope, the viability of the gas pipeline will rely on the commitment 35 of Guadeloupe and Martinique to participate in the pipeline; this commitment remains uncertain. ECGPC has received backing from the French Government, which wants to reduce the subsidies provided to its high-electricity-cost territories. Customers in French islands pay the same rates for electricity as Parisians; the difference between the cost of producing electricity in the islands and the revenues is a government subsidy. There is also interest from various commercial groups in Martinique and Guadeloupe who are willing to commit to certain quantities of gas contingent on a price. There have been discussions with Trinidad gas producers, but no commitment has been made. The true challenges associated with the Eastern Caribbean Gas Pipeline are political rather than economic or technical in nature. Regional infrastructure projects require the creation of strong and effective regional institutions and legal and regional frameworks and political coordination, which are currently lacking. 4.1.2.1 Impact on Barbados Barbados would be the first connection on the pipeline from Trinidad and Tobago. This means that it has the lowest cost of gas among all countries connected to the pipeline. According to the results, pipeline gas fueling a 20-MW LSD plant with Figure 4.2: Comparison of Pipeline to Individual Country capacity factor between 10 and Options for Barbados 90 percent is the lowest-cost 70 1.5 MW Wind Turbine fossil fuel option, as shown in 60 1.5 MW Wind w/Backup Cost, US cents/kWh Figure 4.2. 25 MW CFB Coal 50 20 MW LSD Dist Given the cheap pipeline gas, 40 Fossil LCL, ECGP Barbados has the lowest-cost 30 20 MW LSD LNG Fossil LCL of all countries in 20 this study, with electricity prices around 8 US cents/kWh 10 (at an 80 percent capacity 0 factor). Based on the screening 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% curve, the second-cheapest Capacity Factor, % option is LNG, followed by a Source: Nexant coal-fueled 25-MW CFB plant, as examined in Chapter 3. Costs would be approximately 50 percent higher using LNG or coal when compared to pipeline gas. Although wind with backup is competitive in a scenario without pipeline gas, it is marginally competitive when pipeline gas is an alternative. 4.1.2.2 Impact on Guadeloupe Guadeloupe is the country farthest from the source of the pipeline gas, and therefore it would experience some of the highest gas prices. Even so, when compared to Guadeloupe's supply options as presented in Chapter 3, the most economical fossil fuel option still appears to be pipeline gas. The Fossil LCL for the country comprises a 20-MW GT for capacity factors between 0 and 5 percent, and 20-MW LSD for capacity factors above 5 percent, both running on pipeline gas. When compared to LNG and coal, pipeline gas appears to provide only marginally 36 less expensive electricity, but it Figure 4.3: Comparison of Pipeline to Individual is close to 50 percent less Country Options for Guadeloupe expensive than distillate at high 70 25 MW CFB Coal capacity factors. 60 20 MW LSD Dist Cost, US cents/kWh 20 MW LSD LNG 50 1.5 MW Wind w/Backup 4.1.2.3 Impact on 40 1.5 MW Wind Turbine Martinique Fossil LCL, ECGP 30 Martinique would be a central 20 island in the Eastern Caribbean 10 Gas Pipeline because it accepts the pipeline from Barbados and 0 then sends gas on to 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Capacity Factor, % Guadeloupe. According to the Source: Nexant results Martinique would be a central island in the Eastern Caribbean Gas Pipeline because it accepts the pipeline from Barbados and then sends gas on to Guadeloupe. According to the results, pipeline gas appears to be the cheapest fossil fuel option for Martinique, and its Fossil LCL is composed of a 20-MW GT for capacity factors of 0 and 5 percent and a 20-MW LSD plant for capacity factors of 10 percent and above, both fueled by pipeline gas. Similar to the case of Guadeloupe, pipeline gas is marginally less expensive than the fossil fuel options available to the country when developed in isolation. The pipeline gas could provide power at 8.5 US cents/kWh with a plant operating at an 80 percent capacity factor. The costs are slightly below the corresponding Figure 4.4: Comparison of Pipeline to Individual values for Guadeloupe due to Country Options for Martinique the country's higher gas cost 70 25 MW CFB Coal (levelized US$8.98/GJ versus 60 20 MW LSD Dist US$10.88 for Guadeloupe). 20 MW LSD LNG Cost, US cents/kWh Comparable values for 50 1.5 MW Wind w/Backup electricity based on the coal and 1.5 MW Wind Turbine 40 LNG are 11.7 US cents/kWh Fossil LCL, ECGP 30 and 11.5 US cents/kWh, respectively. Distillate is nearly 20 twice as expensive, at 19.1 US 10 cents/kWh. Although wind with 0 backup is still competitive 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% without pipeline gas, when Capacity Factor, % pipeline gas is added it becomes Source: Nexant marginally economical. 4.1.2.4 Impact on St. Lucia When pipeline gas is added to St. Lucia's screening curve, as shown in Chapter 3, pipeline gas proves to be cheaper than any fossil fuel alternative St. Lucia could develop on its own. The Fossil LCL comprises a 20-MW GT for capacity factors of 0 and 5 percent and a 20-MW LSD 37 for capacity factors from 10 Figure 4.5: Comparison of Pipeline to Individual through 90 percent, both fueled Country Options for St. Lucia by pipeline gas. Pipeline gas- 70 25 MW CFB Coal fueled generation is about three- 60 Cost, US cents/kWh fourths the price of coal, and 50 20 MW LSD Dist nearly half the price of diesel at an 80 percent capacity factor. 40 Similar to the other countries 30 connected to pipeline gas, 20 although wind is significantly less 10 expensive than the least-cost 0 fossil options when individual country solutions are examined, 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% with the addition of pipeline gas it Capacity Factor, % becomes marginally economical. Source: Nexant 4.2 Fuel Storage and Transshipment Options Having large regional/subregional facilities to store petroleum products such as gasoline, diesel and HFO is another solution that may offer a cheaper, more secure fuel supply to the Caribbean islands. For many of the islands, the petroleum fuel demand is small; without large storage facilities, delivery costs are high and countries cannot take advantage of bulk pricing. By having sufficient fuel storage, larger ships can be used to deliver the refined products to the regional storage facility, thereby reducing the costs. Moreover, limited fuel storage makes countries susceptible to shortages in the event of interruptions due to events such as scarcity of petroleum tankers, major weather events, or worldwide oil supply shortages. Large regional fuel storage increases the ability to obtain products from nearby when there is a major worldwide shortage of oil or a short-term spike in oil prices. 4.2.1 Current Situation of Regional Storage A number of fuel storage facilities exist in the region. The larger islands and some groups of islands currently have existing refineries that process crude and store petroleum products. Others store liquid fuels at the power generation facilities. Among the Eastern Caribbean islands, there are already four centralized storage facilities that serve as transshipment centers for delivery to nearby islands. The first is located in St. Lucia and serves as a facility to store products for delivery to other countries in the PetroCaribe agreements.17 The second, in Antigua, is half used by Antigua and Barbuda with the other half used as storage for PDVSA (Petroleos de Venezuela, the Venezuelan oil company). Martinique has a refinery that supplies products to Martinique and the other French islands, and has a fuel storage facility that holds two months' worth of output from the refinery. The final regional storage and transshipment facility is in St. Eustatius (Netherlands Antilles), which is owned by NuStar Energy and is leased to various parties. 17 In these agreements the countries obtain a base price for the refined products based on an index. The countries then pay for shipping costs. Nearly all of the countries in the Eastern Caribbean have signed the PetroCaribe agreements. 38 In the future, the most cost-effective system to maximize the existing storage for small islands may be to coordinate purchase and product delivery, whereby a large vessel would deliver sufficient products to fill each island's storage. Since Jamaica, Haiti and the Dominican Republic are relatively far from the smaller islands of the Eastern Caribbean, they are not considered in this solution. 4.2.2 Storage Options for the Future Three options are explored for expanding regional fuel storage facilities, although none appears to provide a significant economic advantage. All of the scenarios assume that a large tanker would deliver products from one of the four large Caribbean refineries (in Aruba, Curacao, St. Croix and Trinidad) to a regional fuel storage facility where the products would then be shipped by a smaller tanker or barge to each individual island. All four refineries are approximately 500 nautical miles from the potential regional storage facilities. The first scenario is to expand Antigua's facility to serve Nevis, St. Kitts, Barbuda and St. Maarten. These are all within 87 nautical miles of Antigua. If 200,000 barrels of storage are added, the shipping costs could be reduced between US$1.3 and US$3.2 million per year. However, US$8.4 million would be required to develop the storage facilities. After amortizing the new tankage and adding interest on the cost of the additional inventory, the cost exceeds the savings of using a larger delivery ship, making this scenario marginally unattractive. A smaller incremental tankage could be analyzed. The second scenario is to expand the facility in St. Lucia to serve Dominica, Grenada, and St. Vincent and the Grenadines. These islands are within 130 nautical miles of St. Lucia. If 200,000 barrels of storage are added, the shipping cost could be reduced between US$1.9 and US$3.9 million per year. As in the first scenario, US$8.4 million is required to develop the fuel storage facility. In this case, after amortizing the new tankage and adding interest to the cost of the additional inventory, the cost is slightly less than the savings of using a larger ship, with potential savings of approximately US$130,000 per year. Given this small value, the savings from expansion would most likely be insignificant. The third scenario would expand tankage in Martinique to serve Guadeloupe. However, there already is sufficient tankage at this facility to handle the large ships that carry upwards of 800,000 barrels. In addition, Guadeloupe has product storage equivalent to two months' supply and has a large enough demand to be supplied by large tankers. Thus, no additional fuel storage is needed. The preliminary analysis of fuel storage scenarios indicates that there is little potential for regional storage facilities in the Caribbean. To fully understand the feasibility, however, a more detailed look at individual fuel storage situations on each island and the cost to transship from the regional storage facilities to each island would be required. 39 4.3 Regional Electricity Market Interconnections Interconnections of electricity markets are another regional integration option that may help reduce electricity costs. Interconnections involve connecting one country to another by land or submarine transmission lines. Although land interconnections are most common worldwide, the interconnections discussed in this section rely mostly on submarine cables due to the geography of the Caribbean. After discussing the viability of submarine technology, this section analyzes the economics of specific interconnection options, including: the Dominica markets (Dominica­ Martinique, Dominica­Guadeloupe), the Nevis markets (Nevis­Puerto Rico, Nevis­USVI, Nevis­St. Kitts), Saba­St. Maarten, and the Northern Ring (Florida­Cuba or Florida­Haiti, Haiti­Dominican Republic, Haiti­Jamaica, Dominican Republic­Puerto Rico, Puerto Rico­ Nevis). 4.3.1 Submarine Cable Technologies and Costs Submarine cables are advanced technologies that are widely used for underwater electricity interconnections. Many thousands of kilometers of submarine cables are installed worldwide, using two technologies: alternating current (AC) and direct current (DC) cables. Although the cables have been used successfully with low failure rates, it is important to understand the technical limits of each type in order to assess their appropriate usage. The usage of AC and DC submarine cables is technically limited by the interconnection length and maximum route depth. Technical characteristics make AC cable technology more suitable for short to medium distances; the longest installed AC submarine cable measures 105 km between the Isle of Man and the UK mainland. DC connections, on the other hand, are technically feasible up to 1,000 km, although the longest DC connection currently spans 580 km between Norway and the Netherlands. Depth limitations of submarine cables are also of special interest in the Caribbean, which is generally deep with numerous trenches. In order to lay a cable and retrieve it for repair, the strength of the cable material must sufficiently support the weight of the length of the cable between the ocean floor and the surface. As a general guideline, the maximum depth for AC cables is about 1,000 meters whereas DC cables can be laid in depths up to 1,500 meters (with current technologies). Another limitation to current submarine cable technology is the splicing ability. It is beyond available technology to have a main line carrying bulk power with spliced spurs delivering smaller amounts of power to a series of islands along the main line's length. Therefore, interconnecting several islands can only be accomplished by going from island to island, with terminals on each, or by delivering all the power to a single central island. Submarine cables from the central island would then connect separately to one or more islands in the region. The costs of interconnections vary significantly based on the route length and depth, and on the capacity of the cable. Given the complexity of estimating costs, the Nexant Report draws on cost research that had already been conducted on Caribbean interconnections. In particular, Nexans, a supplier of submarine cables, had analyzed the technical details and estimated costs of seven submarine power cable interconnections, as seen in Table 4.2. The results of Nexans' work were used to extrapolate the cost of various submarine cable interconnections in the Caribbean by 40 adding the cost of AC substations for AC and DC lines and adding the cost of the converter/inverter stations for DC lines. Table 4.2: Characteristics of Researched Submarine Cable Interconnections Nexans Route Max. Nexant Researched Voltage, Power, Cost, Source Length, Depth, Cost Interconnections kV MVA/MW* US$ km m US$/kW*** Million** Dominica to 132 kV Nexans 100 MVA 70 700 47 588 Guadeloupe AC Dominica to 132 kV Nexans 100 MVA 75 1,000 50 588 Martinique AC US Virgin Not studied Islands to British Nexans 36 kV AC 25 MVA 32 20 16 by Nexant Virgin Islands Nevis to St. Kitts Nexans 90 kV AC 50 MVA 5 15 12 328 Saba to St. 132 kV Nexans 100 MVA 60 1,000 44 528 Maarten AC Nevis to US 150 kV Nexans 80 MW 320 1,000 255 3,541 Virgin Islands DC Nevis to Puerto 400 kV Nexans 400 MW 400 1,000 575 1,791 Rico DC Extrapolation United States to 400kV from Nevis­ 400 MW 400 1,000 575 1,791 Cuba DC Puerto Rico Dominican 110kV Republic to Haiti Nexant 250 MW 563 N/A 1,890 AC (land) **** *MW is real power­watts. MVA is total power, which includes real power (MW) and reactive power (MVAR). **Nexans' estimated costs do not include the costs of the associated facilities (converter/inverter stations for DC lines, AC substations for AC and DC lines). ***Nexant's update to Nexans' costs take into account the costs of associated facilities as defined above. These costs were used throughout the analysis, since associated facilities can add significant costs to the project. **** A second interconnection project was proposed in July 2010: the 138-kV AC/55-km-long project could have a capacity of 20 to 60 MW and would cost between US$8 and US$14 million (Source: Decon Consulting). This proposal was not analyzed in this report. Source: Nexant Report Cost estimates for four other interconnections that had not been previously studied by Nexans are estimated by a best-fit line:18 (i) Puerto Rico­Dominican Republic, (ii) Haiti­Cuba, (iii) Haiti­ Jamaica, and (iv) Florida­Haiti. Each connection is sized at 400 MW and 350 kV, the capacity used for the Nevis­Puerto Rico and the Florida­Cuba interconnections. The best-fit line used for determining the connection costs is based on Nexans' cost data (cost/kW = 265 + 2.93 * [distance in km]). These costs assume that reasonable routes with maximum depths close to 18 In addition, the costs for Nevis to Antigua (75 km, 25 MVA, AC) and St. Vincent to Barbados (170 km, 50 MVA, DC) appear to fit the unit costs developed for the US Virgin Islands to the British Virgin Islands and Nevis to the US Virgin Islands, respectively. The probable costs of these interconnections are Nevis to Antigua, US$37.5 million, and St. Vincent to Barbados, US$85 million. However, these interconnections were not studied in detail in this report. 41 1,000 meters can be found, which is not always possible. It is important to note that costs generated from a best-fit line are a rough estimate of what actual costs might be. The specific costs would be strongly influenced by the details of the route. The estimated costs are shown in Table 4.3. Table 4.3: Northern Ring Interconnection Cost Estimates Cost of Cable Cost of Route Cable System Power, Max Depth, System and Cable and Parameter Length, Cost (US$ MW m Stations,* US$ Stations, Km Million) Million US$/kW PR­DR 400 150 400 282 423 705 Haiti­Cuba 400 200 >1,500 340 482 851 Haiti- Jamaica 400 250 >1,500 399 541 998 Florida­ Haiti 400 1,100 >1,500 1,395 1,537 3488 *Stations include convert, inverter, AC facilities at two DC stations, substations and related facilities. Source: Nexant Report 4.3.2 Evaluation of Interconnections/Markets The above data provide estimates of the costs of interconnections, but in order to understand the overall economic viability of a specific interconnection, an assessment of the electricity markets of the interconnected islands is required. This takes on both a technical and planning dimension: first, analyzing the potential usage of submarine power cables to make the physical connection, and second, assessing the benefits that can be derived from a subregional electricity market. In addition to the factors included in the Nexant Report's economic analysis, interconnections may also allow countries to receive emergency support in the face of natural disasters or shortages, and in many cases improve access to clean power. Interconnections can also unlock access to certain large and renewable energy resources in the region, which are keys to reducing carbon emissions in the region. These economic benefits are not taken into account in this study, and it would be important to consider them when a more detailed feasibility study is conducted. 4.3.2.1 Subregional Electricity Market I: Dominica Interconnections Interconnections offer significant potential to reduce domestic energy costs for Dominica and supply its neighbors with clean electricity. As discussed in Section 3.2.3, due to the small market size of Dominica's power sector (21 MW of installed capacity), the country has relatively limited options for power production when operating in isolation. The Fossil LCL for Dominica shows costs of 20.4 US cents/kWh for a 5-MW MSD running on distillate (80 percent capacity factor). At the same time, Dominica's large estimated geothermal potential (100 MW) could provide cheaper electricity for the country. However, this potential is relatively large compared to the country's demand, and one plant alone could serve the island's demand at the time of installation. Since no power plant is available for service 100 percent of the time, the utilities would need to plan for 100 percent backup of the geothermal plant from other resources, and the 42 requirements for spinning and Figure 4.6: Schematic of Dominica Interconnections operating reserves would increase. By interconnecting with Martinique and Guadeloupe, which both have current installed capacities of over 400 MW, Dominica could increase the reliability of its own system while decreasing energy costs and providing cheap power to neighboring islands. Dominica­Martinique: An interconnection between Dominica and Martinique based on geothermal power exports from Dominica offers the potential to supply significantly cheaper energy to Martinique. At present, expensive distillate fuels virtually all of Martinique's generation. While the previous analysis for Martinique presented multiple lower-cost options such as LNG, pipeline gas and coal, a submarine interconnection could also be beneficial. This study considers a 100-MW, 70-km AC submarine interconnection, which appears to be both technically feasible and economically viable. The interconnection cost would be US$588/kW (including substations). As shown in Figure 4.7, when compared to Martinique's other options, the interconnection would be the cheapest power option for the country, assuming that Dominica's geothermal plant runs at a capacity factor above 63 percent. Specifically, at an 80 percent capacity factor the geothermal/submarine cable option costs 7.1 US cents/kWh, compared to the Fossil LCL (technologies using pipeline gas), at a cost of 8.6 US cents/kWh. Geothermal is also lower in cost than the individual country options: coal and LNG. When geothermal costs are compared to current distillate-based generation (20.4 US cents/kWh), it is clear that significant savings could be realized. Although the analysis assumes that Martinique can accept 93 MW (100 MW minus losses), because its current installed capacity is 412 MW there would still be benefits even if a cable with a lower capacity were installed. Instead, if a 50-MW line were installed, the electricity costs would increase slightly (assuming that the cost would be 67 percent of the capital costs of the 100-MW interconnection), but geothermal would remain the least-cost option for capacity factors above 75 percent. 43 Figure 4.7: Comparison of Submarine Interconnection to In general, Martinique is Other Options for Martinique blessed with multiple options, 40 "Individual" Fossil LCL including pipeline gas and 35 Fossil LCL ECGP geothermal energy by means of 100 MW Geo Dom Exp a submarine cable. Each option Cost, US cents/kWh 30 50 MW Geo Dom Exp has uncertainties that will need 25 to be addressed before 20 implementation, particularly 15 related to whether other 10 countries will choose to proceed with the gas pipeline and the 5 size of the geothermal resource 0 in Dominica. Most importantly, 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% however, it is clear that both Capacity Factor, % options offer large economic Source: Nexant benefits for future generation. Dominica­Guadeloupe: The discussion for Guadeloupe is similar to that for Martinique. The interconnection between Dominica and Guadeloupe is technically feasible and has the potential to offer significant economic benefits. Guadeloupe is primarily dependent on distillate, but to a lesser degree than Martinique. It has two boilers fueled by coal and bagasse, with a planned third boiler on the same site, fueled only by coal, and a 15-MW geothermal plant. The two countries have roughly the same installed capacity (411 MW) and demand, and the submarine interconnection analyzed is a 100 MW AC, spanning 70 km, at a cost of US$588/kW (including substations). At an 80 percent capacity factor, the geothermal power plant and submarine cable project cost 7.1 US cents/kWh. Likewise, Guadeloupe has Figure 4.8: Comparison of Submarine Interconnection to alternative fuels with Other Options for Guadeloupe considerably lower prices than 40 "Individual" Fossil LCL distillate (LNG, pipeline gas 35 Fossil LCL ECGP Cost, US cents/kWh and coal). Pipeline gas from 30 Tobago through Barbados and 100 MW Geo Dom Exp 25 50 MW Geo Dom Exp Martinique provides the lowest 20 price among these four. With pipeline gas available, the costs 15 for energy generation for gas 10 plants operating at an 80 5 percent capacity factor are 10.1 0 US cents/kWh. Due to the 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% higher gas costs on Guadeloupe, Capacity Factor, % pipeline gas is the least-cost Source: Nexant option only for capacity factors below 52 percent, and geothermal remains least expensive for capacity factor at which it might operate. 44 When the geothermal power plant with the submarine cable project is sized as 50 MW rather than 100 MW (with capital costs estimated at 67 percent of the capital costs of the 100-MW plant) the geothermal and submarine cable project's costs are below the Fossil LCL at capacity factors above 62 percent. The net benefits are reduced but still significant. 4.3.2.2 Subregional Electricity Market II: Nevis Interconnections Interconnections between Nevis and 4.9: Schematic of Nevis and Puerto Rico and Puerto Rico, the US Virgin Islands US Virgin Islands Interconnections and St. Kitts, appear to offer large potential to provide clean, cheap power to the interconnected islands and reduce energy costs for Nevis. As discussed in Section 3.2.3, and similar to the case of Dominica, the size of the geothermal power potential in Nevis (estimated at around 300 MW) is large in relation to the island's small energy demand (a peak of 10 MW), and the island has relatively few other low-cost generation options. A plant could be designed to serve 100 percent of Nevis's and St. Kitts's demand at the time of installation. Therefore, in order to fully utilize the geothermal potential, it is important to look to other interconnections within the region, such as with Puerto Rico and the US Virgin Islands. Nevis­Puerto Rico: The interconnection from Nevis to Puerto Rico is technically feasible and has the potential to reduce electricity costs for Puerto Rico. The submarine cable would span 400 km with a 400-MW DC capacity, at a cost of US$1,791/kW. Puerto Rico's installed capacity is 5,864 MW, meaning the amount of imported energy is small relative to the market size. It would be important to verify whether Nevis has sufficient supply to develop 400 MW of capacity (the Nexant Report estimates 300 MW of potential). If sufficient resources are not available, a smaller interconnection would have to be considered. Since Puerto Rico is not one of the countries studied in detail in Chapter 3, for comparison purposes this section considers two future development options for Puerto Rico: LNG and HFO. The economic benefit of the interconnection varies significantly between these two. First, the geothermal/interconnection option is compared to meeting future electricity demand by building an additional LNG facility. As shown in Figure 4.10, building the geothermal plant and the submarine interconnection is more expensive than a 400-MW combined cycle LNG-derived natural gas plant. Next, comparing the interconnection to expanded HFO-based generation, the 45 Figure 4.10: Comparison of Puerto Rico­Nevis net benefit is about 14.5 US Interconnection to Selected Fossil Fuel Options cents/kWh at an 80 percent capacity factor, which 45 decreases as the capacity 40 4x100 MW Geo Nevis 35 Exp factor shrinks until the break-even point at 26 Costs, US cents/kWh 30 25 percent. Since Puerto Rico's 20 generation is currently HFO 15 fuel based, this is the most 10 likely expansion base case, 5 and therefore HFO is the 0 more appropriate 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% comparison for net benefit. Capacity Factor, % Source: Nexant Nevis­US Virgin Islands: Although the submarine connection between Nevis and the US Virgin Islands (USVI) is technically feasible, according to the Nexant Report the interconnection appears to provide small benefits for the USVI when compared to diesel generation, and then only at high capacity factors. Since the USVI are not among the countries studied in detail, there is no comprehensive analysis of alternative options, and the geothermal/interconnection option is compared to a 5-MW LSD, which is the least-cost fossil option for other small islands such as Dominica and Nevis. The break-even point at which the interconnection becomes valuable is at a 75 percent capacity factor, with net benefits growing to about 5 US cents/kWh at a 90 percent capacity factor, as shown in Figure 4.11. The benefits are smaller than for Figure 4.11: Comparison of US Virgin Islands­Nevis other interconnections because Interconnection to Selected Fossil Fuel Options the distance between the two 60 islands is long (320 km), and the 80 MW 320 km Geo Nevis Exp 50 5 MW MSD Dist USVI amount of power delivered is relatively small (80 MW, DC). Costs, US cents/kWh 40 Thus, the cost per kilowatt is 30 high when compared to other interconnections, totaling 20 US$3,541/kW. However, it is 10 interesting to note that a long, expensive submarine cable 0 moving a relatively small 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% amount of geothermal-generated Capacity Factor, % power still appears to be Source: Nexant marginally competitive when compared to distillate-fueled power generation. Geothermal power generation is so much less costly than the liquid fuel alternatives that transportation costs from an interconnection do not completely compromise geothermal's economic advantage. 46 Other interconnection options to connect Nevis and the USVI could be considered, such as increasing the size of the interconnection to Puerto Rico and then connecting Puerto Rico and the USVI. Nevis­St. Kitts: St. Kitts currently runs primarily on diesel; compared to alternative generation options, a geothermal interconnection is highly economically viable. The distance between the two islands is only 5 km, thus creating an environment for a Figure 4.12: Comparison of Nevis­St. Kitts technically simple Interconnection to Individual Options for St. Kitts interconnection. The connection 40 Fossil LCL would be made by means of a 50- 35 MW submarine cable at a cost of 30 50 MW 5 km Geo Nevis US$328/kW. The geothermal 25 Exp Costs, US cents/kWh capacity of 50 MW would be 20 enough to serve the 40 MW load 15 of the St. Kitts utility and some hotels that are not currently 10 connected to the grid, with room 5 for growth. 0 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% The high costs of the other Capacity Factor, % generation options provide large Source: Nexant opportunities for viable alternative options such as geothermal resources. St. Kitts has the same Fossil LCL as Dominica and Nevis, with a 5-MW MSD distillate plant with costs of 20.4 US cents/kWh. In comparison, the annual cost of geothermal generation and transmission at an 80 percent capacity factor is 7 US cents/kWh, creating a net benefit of about 13 US cents/kWh. The benefits decrease with the capacity factor until a break-even point is reached at about a 23 percent capacity factor. Because the geothermal plant and Figure 4.13: Schematic of Saba­St. interconnection could be designed to serve 100 Maarten Interconnection percent of St. Kitts' demand, the discussion on backup requirements for the geothermal power plant in Section 3.2.3 applies to St. Kitts as well. The increase in reserve requirements imposes an economic burden not accounted for in the analysis. However, the incorporation of these costs would not reverse the economic advantages of the interconnection. 4.3.2.3 Subregional Electricity Market III: Saba­St. Maarten Saba and St. Maarten are both part of the Netherlands Antilles, and an interconnection between the two has the potential to be 47 economical if sufficient demand is present on St. Maarten. Since neither of the two islands is studied in detail in Chapter 3, this section compares the costs of a 100-MW, 60-km submarine cable from Saba to St. Maarten to the installation of 20-MW distillate-fueled LSDs. Given a cost of 19.1 US cents/kWh for LSD at an 80 percent capacity factor, the geothermal plant/submarine cable combination costs considerably less. The net benefit Figure 4.14: Comparison of Saba­St. Maarten is estimated to be over 12 US Interconnection to Distillate in St. Maarten cents/kWh at an 80 percent 45 100 MW / 60 km Geo Saba Exp capacity factor. These benefits 40 35 20 MW LSD Dist StM decline as the capacity factor decreases, until they break even 30 Costs, US cents/kWh at 24 percent. 25 20 15 However, this analysis assumes 10 that St. Maarten will have 5 sufficient demand to utilize 100 0 MW of electricity, which may 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% not be the case. Increasing the Capacity Factor, % receiving market size by Source: Nexant interconnecting with St. Martin, which shares the same island as St. Maarten, would be the best solution to increase demand for the interconnection, but this solution is complicated by the fact that St. Martin operates at 50 Hz, while St. Maarten operates at 60 Hz. Instead, similar to the discussion in Section 4.3.2.1, a smaller line may be possible and economical. 4.3.2.4 Subregional Electricity Market IV: The Northern Ring Interconnection The Northern Ring is a conceptual set of interconnections in the northern Caribbean, potentially linking Florida, Cuba, Haiti, Jamaica, the Dominican Republic, Puerto Rico and Nevis, or some subset of those areas (see Figures 4.15 and 4.16). These interconnections would involve the largest countries in the Figure 4.15: Schematic of Northern Ring Interconnections region and could have an impact on the largest number of people. For that reason the interconnections are especially worth considering. This section first examines the feasibility of individual interconnections, and then examines the potential for a larger link. 48 Figure 4.16: Alternative schematic of Northern Ring Florida­Cuba: An Interconnections interconnection from Florida to Cuba could offer large savings for Cuba as a stand-alone connection. Cuba has an installed capacity of 5,180 MW and enough demand to warrant a large interconnection. The parameters used to analyze the interconnection are identical to the Nevis­ Puerto Rico interconnection (a 400-km, 400-MW HV DC cable, with costs of US$1,791/kW). Since the maximum depth between the US and Cuba is 1,000 meters, the interconnection is technically feasible. The analysis indicates that the connection could be highly beneficial for Cuba. Natural gas and coal fuel most of the generation in Florida, while nearly all the power plants in Cuba are crude oil or HFO-fueled steam turbine plants. Both natural gas and coal Figure 4.17: Comparison of Florida­Cuba fueled generation have Interconnection to HFO in Cuba significantly lower costs than 60 400 MW Coal US Exp HFO-fueled steam power. For 400 MW CC Gas US Exp 50 example, gas costs approximately 356 MW ST HFO Cuba Costs, US cents/kWh 9 US cents/kWh compared to 24 40 cents/kWh for HFO-fueled 30 generation at an 80 percent capacity factor. As shown in 20 Figure 4.17, the net benefit of 10 exports from a US coal plant is 13 0 US cents/kWh at an 80 percent capacity factor, while the net 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Capacity Factor, % benefit of exports from a US gas Source: Nexant plant is 15.4 US cents/kWh. Haiti­Dominican Republic: Unlike the other interconnections explored in this section, the Dominican Republic and Haiti would be connected by land. The primary objective of this landline would be to provide Haiti with access to lower-cost generation from the Dominican Republic. 49 Figure 4.18: Schematic of Haiti­Dominican Republic Interconnection The interconnection examined is a 563-km landline between Port-au-Prince and Santo Domingo. The line's normal rating is 250 MW, nearly double the 130-MW average demand in Haiti. The total cost, including substations and related facilities, would be around US$246 million, or US$1,890 per kW. The Nexant Report analyzed two potential generation sources from the Dominican Republic--HFO, the prevalent fuel used in the country, and natural gas from LNG. Assuming that the HFO-based generation is exported, the Nexant Report indicates that the energy from the interconnection would be more expensive than local generation. At present, generation in Haiti comes from LSD running on distillate with low heat rates due to the poor conditions of the units. Although HFO is less costly than distillate, the cost advantage of HFO over distillate is small in comparison to the relatively large interconnection costs. Although the cost of the interconnection in US$/km is well below any of Figure 4.19: Comparison of Haiti­Dominican Republic the submarine cables, the Interconnection to Distillate in Haiti US$/kW cost, which is more 50 important in an energy cost calculation, is well above any 40 of the submarine cable cases Costs, US cents/kWh 30 except those of Nevis­USVI and Florida­Haiti. 20 20 MW LSD Dist Haiti On the other hand, if 10 100 MW CC LNG DR Exp generation comes from natural 300 MW ST HFO DR Exp 0 gas, there are net benefits of 9.6 US cents/kWh at an 80 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Capacity Factor, % percent capacity factor, decreasing at lower capacity Source: Nexant factors until breaking even at 50 a 27 percent capacity factor, as shown in Figure 4.19. While the Dominican Republic currently has an LNG terminal with some spare capacity, it would most likely have to build an additional terminal to expand generation for sufficient export capacity. Because Haiti has an enormous lack of domestic capacity, electricity from the interconnection may have additional economic benefits that are not included in this study. For example, the interconnection could provide baseload power for the Haitian power system and emergency support in the face of natural disasters or shortages. Alternatively, power could be sold back to the Dominican Republic in the event of an emergency. These economic benefits are not taken into account in this study, and it would be important to consider them when a more detailed feasibility study is conducted. Dominican Republic­Puerto Rico: The Dominican Republic­Puerto Rico link has interconnection costs in an economically viable range and appears to be technically feasible. The route between the islands is short and straightforward, with modest and steady depths. The 400- MW, 150-km interconnection would cost an estimated US$705/kW. Since both countries have relatively high-cost electricity, the interconnection was not studied in detail in this report. Most of the benefits reaped from this interconnection would be decreased required reserves, emergency support in the face of natural disasters or shortages, or access to cleaner power if one of the countries develops alternative supply options. Since these benefits were not considered in the analysis, it would be important to conduct a more detailed feasibility study on this interconnection. Nevis­Puerto Rico: See Section 4.3.2.2. As an independent link, the connection between Nevis and Puerto Rico is technically feasible and economical, assuming that the geothermal energy exported from Nevis replaces HFO-based generation in Puerto Rico. Other Haiti interconnections: Interconnections from Haiti to Florida, Cuba and Jamaica appear to be technically infeasible with current technologies. Due to the extensive undersea canyons and ridges, a path could not be found with a maximum depth of less than 1,500 meters between Haiti and these countries, but further verification of the route options is required, and technical advances may make these interconnections possible. Interconnected Northern Market: Although some Northern Ring interconnections stand alone as independent links, others may benefit from a series of interconnections to bring less-expensive power into the market, either from Florida or Nevis. This would work by having each country along a series of interconnections take some of the less-expensive power and pass on the rest to neighboring countries. As a hypothetical and simplistic example, Cuba might receive 1,000 MW from Florida, keep 400 MW and deliver 600 MW to Haiti. Haiti would keep 200 MW and deliver 400 MW to the Dominican Republic. It is unlikely that a full Northern Ring interconnection would materialize from Florida to the Caribbean due to technical and political barriers. Specifically, for political reasons it is unlikely that Florida and Cuba will interconnect, and it appears to be technically infeasible with current technologies to bypass Cuba by connecting directly with Haiti, due to the extreme depths. 51 Furthermore, even if a reasonable path between Florida and Haiti could be found, the costs of the interconnection appear to be outside the economical range. When bringing cheap power from Nevis to the Greater Antilles is considered, the prospects are more promising. An interconnection between Nevis and Puerto Rico appears to be technically feasible and economically viable under certain conditions. From there, interconnections from Puerto Rico to the Dominican Republic and the Dominican Republic to Haiti are both technically feasible and have the potential to be economical with a cheap source of electricity flowing from Nevis. Since the Haiti­Jamaica and Haiti­Cuba interconnections appear technically infeasible with current technology, the interconnection would stop in Haiti. As a result, an interconnection among Nevis, Puerto Rico, the Dominican Republic and Haiti is possible and has the potential to be economically feasible. An added challenge for this ring is that land-based transmission systems within the interconnected countries would have to be strengthened in order to move power across the country to the next converter or invert station. These expenses are not included in the costs estimates and have the potential to significantly increase costs. Box 4.2: Moving from Concept to Reality This is a high-level concept study, and detailed feasibility studies need to be carried out on all the proposed interconnections. A feasibility study would include a comprehensive analysis of all key issues related to a proposed interconnection, including the technical, environmental, commercial, financial, economic and legal aspects. It would also include an assessment of energy supply and demand scenarios in the subregional markets that are connected and of energy trading opportunities. Finally, an analysis would need to be carried out to ensure the presence of efficient and effective subregional legal, regulatory and institutional frameworks to attract investors to carry out the project. Regional organizations and international financial institutions (IFIs) can provide valuable contributions to facilitate the policy and political dialogue among the countries and to provide technical assistance and financial support to address the political and financial risks facing potential investors. 4.4 Challenges and Risks The analysis is based on a purely economic and technical comparison of fuels, renewable technologies and interconnections; it does not include any assessment of political, institutional, regulatory or financial risks. Issues such as energy security or financial, environmental or regulatory concerns may present additional obstacles to implementation. 4.4.1 Financial and Economic Issues Geothermal power plants and submarine cables, or gas pipelines, often have significantly higher capital costs than those of distillate-based generation. Although the higher capital investments may lower costs in the long run, obtaining financing for the projects could be a challenge. Local 52 utilities may have difficulty in funding such large investments and some countries may opt to maintain more expensive operating costs to reduce upfront financing. For example, while in some countries renewable-based generation may cost less than diesel in cents/kWh, the capital costs for renewable technologies are several times those of oil-based generation. This, combined with the fact that fuel costs can be fully passed on to purchasers, make investment in renewable energy less attractive to the private sector even for well-known renewable technologies such as hydropower. In addition to obtaining financing, many utilities may be hesitant to take the risk to make such large investments when future fuel costs are unknown. In particular, utilities may be hesitant to switch from distillate if prices fall or appear to be falling. On the other hand, continuing with liquid fuels is risky, because prices may return to US$150/barrel (bbl) of oil, and hedging fuel costs through diversification has its own costs. Utilities must invest based on their own situation and perceptions. Thus, private financing, public/private partnerships and support from IFIs and the international donor community may be of key importance. The private sector is already leading the region in developing the untapped geothermal potential in many countries and will play a key role in developing wind and other renewable resources. The same applies for the development of the Eastern Caribbean Gas Pipeline and potential new LNG facilities. IFIs can help leverage these investments and mitigate some of the associated risks. 4.4.2 Commercial and Regulatory Issues To encourage private sector participation and public/private partnerships, and to facilitate subregional integration, effective legal, regulatory and institutional frameworks will need to be established. For interconnections in particular, regulation affecting more than one country, such as regulation associated with power for export, submarine cables, the Eastern Caribbean Gas Pipeline and imported fuels, will be important. When more than one country is involved in a project, regulatory harmonization is desirable and may be mandatory for success. The institutional arrangements of each country will have a profound impact on its ability to implement regional projects. Where multiple countries are involved, such as in the Eastern Caribbean Gas Pipeline, an additional level of complexity exists, which would most likely extend the time needed to reach a successful conclusion. Similarly, challenges from separate ownership of various components of interisland power or fuel supply would need to be addressed. For the export of geothermal power by means of a submarine cable, one private party might own the geothermal power plant in the exporting country while another owns and operates the submarine cable. For the gas pipeline, a separate firm will own and operate the pipeline while another organization will supply the gas. Joint ownership can present other types of issues. In both of these cases, contractual structures must be created to guarantee supply and allocate risks and responsibilities to the appropriate parties. The needs of all parties would be best served by long-term contracts that guarantee supply to the customer and a revenue stream to the suppliers. 53 4.4.3 Security of Supply A secure supply of energy is often viewed as a national security issue, and utilities may be concerned about relying on another country for power or fuel vital to power generation. Although distillate and HFO are widely available at the present time, political unrest or technical failures, such as a break in the gas pipeline, albeit unlikely, may compromise one country's ability to supply another. In addition, if there is an outage in one system, it may impact the other given the systems' interdependence. This may impact the reserve margin that countries maintain to assure adequate supply at all times. A more detailed economic analysis than that included in this study should incorporate the costs of the increased reserve margin. Operating reserves may also change, and a more detailed economic analysis of the economic impact would have to be conducted. In the event that operating reserves are calculated on a largest contingency basis, and if the largest unit was previously 16 MW but becomes 50 MW, the costs of this change would have to be considered. However, given that both geothermal power generation and submarine cables tend to be highly reliable facilities, countries may choose to decrease their operating reserves. 4.4.4 Environmental Concerns The main environmental concerns about submarine cable or pipeline technologies relate to seabed impact. These concerns surround fears that laying the pipeline could stir up harmful toxic substances contained in seabed sediment, and that submarine cables may increase erosion on the ocean floor. Moreover, construction of the pipeline or cable may temporarily disturb the flora and fauna of the area. An Environmental Impact Assessment would indicate the risks related to construction and operation of the pipeline or cable. 4.5 Conclusions Regional solutions appear to be interesting options for Caribbean electricity supply because they could help countries benefit from economies of scale and indigenous resources on neighboring islands, particularly aiding the penetration of large-scale renewable Table 4.4: Summary of Gas Pipeline Savings projects. Consequently, many Country Estimated Savings (cents/kWh)* countries could benefit from 11.7/ compared to distillate significantly cheaper energy Barbados 4.3/ compared to coal generation either from a gas pipeline 4.0/ compared to LNG or an electricity market 9.0/ compared to distillate interconnection. It does not appear that Guadeloupe 2.5/ compared to LNG a regional fuel storage facility would -3.0/ compared to geothermal imports offer any significant benefit. 10.5/ compared to distillate Martinique 3.0/ compared to LNG -1.5/ compared to geothermal imports The results indicate that the Eastern Caribbean Gas Pipeline could provide 9.3/ compared to distillate St. Lucia 3.2/ compared to coal the cheapest fossil fuel to the countries *All savings assume plants running at 80 percent capacity factor. 54 it reaches: Barbados, Guadeloupe, Martinique and St. Lucia. Pipeline gas could cut electricity generation costs by half when compared to diesel-based generation, and provide cheaper fuel than coal or natural gas through other delivery methods. Thus, despite the barriers to implementation, pipeline gas should continue to be considered a viable option. Table 4.4 shows the potential cost savings when compared other options for each country. Electricity market interconnections are also attractive options for the Caribbean because they can offer cheap alternative energy options, particularly when geothermal-based electricity can be exported. Many of the interconnections studied are both economically viable and technically feasible. As shown in Table 4.5, the Nevis­Puerto Rico, Nevis­St. Kitts, Saba­St. Maarten and Florida­Cuba interconnections also offer large savings due to the availability of low-cost geothermal power in Nevis and Saba and cheap coal and natural gas in Florida. Both Dominica interconnections have the potential to bring significant savings to Martinique and Guadeloupe. Savings for the Dominican Republic­Haiti interconnection would depend on the generation source of exported electricity, while the interconnection between Nevis­US Virgin Islands showed some small savings due to the long distance and small amount of energy transported. In addition to the potentially large economic benefits for some countries, interconnections may allow countries to receive emergency support in the face of natural disasters or shortages, and in many cases improve access to clean power. For some countries, these reasons alone may provide significant justification for further pursuing the idea of interconnections through additional exploration or studies, because these benefits were not taken into account in this simplified analysis. Interconnections can also unlock access to certain large and renewable energy resources in the region, a key to reducing carbon emissions in the region. Despite the favorable initial economics, a host of financial, regulatory and security risks must be addressed prior to implementation. This is a high-level concept study, and before moving forward with any project, further analysis must be conducted to build a more detailed understanding of the financial, regulatory, economic and technical feasibility of the options. 55 Table 4.5: Electricity Market Interconnections Summary Estimated Savings Inter- Technically Energy for Country MW Km Comments connection Feasible Generation Receiving Power (cents/kWh)** Geothermal 13.3/ compared to exported from distillate Benefits still exist if Dominica­ 100 70 Yes Dominica. interconnection is 50 Martinique* 1.5/ compared to MW. pipeline gas 13.3/ compared to Geothermal distillate Benefits still exist if Dominica­ 100 70 Yes exported from interconnection is 50 Guadeloupe* 3.0/ compared to Dominica. MW. pipeline gas Geothermal 14.5/ compared to Nevis­Puerto exported from HFO 400 400 Yes Nevis. Rico* -0.7/ compared to LNG Nevis­US Geothermal 1.5/ compared to Virgin 80 320 Yes exported from distillate Islands* Nevis. Plant would serve 100 Geothermal Nevis­St. 13.4/ compared to percent of St. Kitts' 50 5 Yes exported from Kitts* distillate demand, requiring Nevis. increased reserves. Assumes St. Maarten Geothermal can accept 100 MW. Saba­St. 12.2/ compared to 100 60 Yes exported from A smaller Maarten* distillate Saba. interconnection may still be economical. Coal-fueled 13/ coal export steam plant or compared to HFO Florida­ 400 400 Yes gas-fueled CC Cuba* 15.4/ gas export exported from US. compared to HFO HFO-fueled -2.3/ HFO export Dominican steam plants or compared to distillate Republic­ 250 563 Yes gas-fueled CC Haiti* exported from 9.6/ gas export DR. compared to distillate Puerto Rico­ 400 150 Yes N/A. Not estimated DR Given the lack of low- Haiti­Cuba 400 200 Technically N/A. Not estimated cost power for export questionable on the islands, the Haiti­Jamaica 400 250 N/A. Not estimated basic economic with current technology analyses for these US export from interconnections were given, inter coal-fueled not studied in detail. Florida­Haiti 400 1,100 alia, depth of Not estimated steam plant or sea floor. gas-fueled CC. *Country receiving power. **All savings are quoted assuming that plants are running at an 80 percent capacity factor, and costs include both capital and operation and maintenance (O&M) costs for each option. 56 Chapter 5 Regional Scenario Analysis T he goal of the scenario analysis is to preliminarily assess the aggregate economic benefits of several supply and interconnection development options across the region. Each of the four scenarios analyzed offers different development options, and the costs of these options are evaluated in order to understand the cost and financial impact for each individual country and the region. It is important to note that the scenarios are illustrative of the options available to the Caribbean, with the aim of indicating promising directions for future work. While inputs from Chapters 3 and 4 are used to limit and define the available fuels, resources and costs for each island, the scenarios do not compare individual versus regional approaches but are instead defined based on the type of supply options. This chapter first outlines the methodology used for the analysis and the four illustrative scenarios: (i) the Base Case Scenario, which is based on existing utilities' development plans and/or an assumed business-as-usual planning approach; (ii) the Fuel Scenario, which includes options for expanding the availability of natural gas and coal to the region; (iii) the Interconnection/Renewables Scenario, which assumes the combined addition of submarine cable interconnections and the most attractive new renewable resources; and (iv) the Comprehensive Integrated Scenario, which combines the expansion of fossil fuel options, the building of interconnections and the development of renewable generation. The chapter then compares the results of the model, looking at the NPV and the investment and production costs. Next, on a country-by-country basis, it describes the potentially beneficial energy options identified for each country. 5.1 Methodology The scenario analysis conducts a more detailed system analysis, simulating yearly expansion and production, based on extensive inputs about the existing system, future conditions, and characteristics of new power plants. The scenarios take into account the results of the screening analysis, as the results help define the size and operational role of the various fuel supply and interconnection options. The scenario analysis is conducted through a spreadsheet model that simulates the operation of the generation system from 2009 to 2028, calculating the supply/demand balance for the planning period to indicate the required capacity additions by year and by country. This is based on the electricity demand forecast and the expected future production from existing and planned 57 resources. The capacity balance uses peak demand and calculates the required reserve margin based on capacity reliability criteria.19 Resources are assumed to contribute to the reserve margin with their full net capacity, excluding capacity generators used for power export and wind generation, both of which do not contribute to the reserve margin at all. Therefore, power exports and wind development do not affect resource development plans, and the benefits of these resources are based only on the energy generation savings. After developing the capacity balance, the model calculates the energy balance from available resources. Energy production for each unit takes into account the type of unit, unit operating cost, forced and maintenance outage rates, and limits on energy production typical of renewable energy units. A discounted cost analysis was conducted for the selected combination of resource additions and interconnection options. The analysis covers the entire planning period, taking into account salvage value20 for all investments during the planning period. This total discounted cost forms the basis for cost comparisons between scenarios. The analysis is based on a 10 percent discount rate, applied to the costs expressed in constant 2009 US dollars. Although this is a low rate for private investment in the region, the analysis only considers the economic costs of the various options, for which 10 percent is considered representative. 5.2 The Scenarios 5.2.1 The Base Case Scenario The first scenario developed is the reference scenario or Base Case Scenario, which uses utilities' existing development plans or, when these are not available, assumes that utilities will continue their current planning behavior and are thus likely to follow the same development path of the past. The Base Case Scenario does not assume additional new fossil fuel options, renewable generation, or interconnections. All units already under construction or committed are included in the Base Case Scenario. The least-cost generation resources within the Base Case constraints are then added to each system as they are needed to meet load growth plus the required reserve margin. The size estimates of future power plants are based on the technology, fuel options and the size of the system. For most countries this scenario implies continued development of diesel units using distillate fuel. In some of the larger power systems, such as those of the Dominican Republic and Jamaica, the existing coal and LNG fuel usage may be expanded. The results of this scenario are summarized in Table 5.1 on a country-by-country basis. 19 The reserve margin is dependent on the system's size. The model used three different levels of reserve margin: 35 percent for systems up to 150 MW, 30 percent for systems up to 600 MW, and 25 percent for larger systems. These values are comparable to the planning reserve margins used by utilities in the region. 20 The salvage value is calculated based on the in-service year using the straight line depreciation and a 30-year life for all generation and transmission projects, other than for diesel units, for which a 20-year useful life was assumed. 58 Table 5.1: Base Case Scenario Least-Cost Existing Technologies New Units added by 2028 Committed units assumed in all Country scenarios Natural Gas Diesel Coal Antigua and Six 5-MW MSD on distillate Three 10-MW Barbuda added between 2011 and 2013 MSD Barbados Nine 16-MW LSD, 6 added Two 20-MW between 2011 and2013, 3 added LSD as needed Dominica No new capacity needed until Three 5-MW 2012 MSD Dominican Hydro (356 MW) and Wind (100 Eight 300-MW CC Republic MW) between 2010 and 2011 using LNG for mid- range. Two 50-MW GT on LNG for peaking Grenada No new capacity needed before Seven 10-MW 2013 MSD Haiti Already short on generation. Need Total of 540 MW four 20-MW LSD to meet 2009 of LSD units demand Jamaica 11-MW LSD, 120-MW ST, 155- Eleven 100- MW Cogen, 2-MW wind MW conventional coal units St. Kitts and No new capacity needed until Seven 5-MW Nevis 2012 MSD for St. Kitts, five 5-MW MSD for Nevis St. Lucia No new capacity needed until Four 20-MW 2011 LSD St. Vincent No new capacity needed until Seven 10-MW and 2017 MSD Grenadines 5.2.2 Fossil Fuel Scenario The Fossil Fuel Scenario assumes that future power generation development of the Caribbean islands could be based on alternate and potentially less expensive fossil fuels and power generation technologies. This Fossil Fuel Scenario does not assume additional renewable generation or interconnections, thus assuring that this scenario accounts only for the costs and benefits associated with selecting different fossil fuel options. Similar to the Base Case Scenario, all committed units are included, and generation systems are then added as they are needed to meet the load growth or the reserve margin. The fuels and the technologies selected for each country are both based on their availability and their ranking in the screening analysis, with the least-cost generation options installed to their maximum potential. 59 The Fossil Fuel Scenario demonstrates that nearly all countries have lower-cost fossil fuel options than distillate, including natural gas and coal. Pipeline gas-fueled generation appears to be the lowest cost fossil fuel option for every country reached by Eastern Caribbean Gas Pipeline (Barbados, Martinique, St. Lucia and Guadeloupe). LNG is an attractive option for the Dominican Republic, Haiti and Jamaica. The Nexant Report indicates that coal is competitive with distillate in Antigua and Barbuda, Grenada, and St. Vincent and the Grenadines. Natural gas, on the other hand, is relatively expensive due to the small demand and geographic distances. Dominica and St. Kitts and Nevis have no alternative, economically viable fossil fuel option when compared to distillate; the relatively small demand and the high fixed costs associated with other fuel transportation modes make all other fuel options more costly than distillate. However, it is important to remember that in all these countries, the prices do not take into account environmental externalities. The inclusion of a carbon price increases the viability of gas and distillate compared to coal. The results are summarized in Table 5.2 below. Table 5.2: Summary of Fossil Fuel Scenario Capacity Additions Committed units Country Gas Distillate Coal assumed in all Scenarios Antigua Six 5-MW MSD added Three 10-MW and between 2011 and 2013 CFB Barbuda Barbados Nine 16-MW LSD, 6 Two 20 MW LSD on added between 2011 and pipeline gas 2013, 3 added as needed Dominica No new capacity needed Three 5-MW MSD until 2012 (same as Base Case) Dominican Hydro (356 MW) and Two 50-MW GT Eight 300-MW Republic Wind (100 MW) between running on LNG for conventional coal 2010 and 2011 peaking units for baseload Grenada No new capacity needed Seven 10-MW before 2013 CFB Haiti Already short on Total of 540 MW of generation. Need four 20- LNG gas units, with MW LSD to meet 2009 LNG terminal starting in demand 2014 Jamaica 11 MW LSD, 120 MW Eleven 100 MW CC ST, 155 MW Cogen, 2 running on LNG. 450 MW wind MW of existing units converted to NG St. Kitts No new capacity needed Seven 5-MW MSD and Nevis until 2012 on St. Kitts, five 5- MW MSD on Nevis (same as Base Case) St. Lucia No new capacity needed Four 20-MW LSD on until 2011 pipeline gas St. Vincent No new capacity needed Seven 10-MW and until 2017 CFB Grenadines 60 5.2.3 Interconnection/Renewables Scenario The Interconnection/Renewables Scenario analyzes the potential for renewable and interconnection developments. Where economically and technically viable, it assumes that submarine cable interconnections will be constructed, and countries will develop the most attractive new renewable generating resources. The reason for the pairing of interconnections and renewable energy is that most of the interconnections involve generating geothermal power in one country and exporting the power to other countries through submarine cables. Similar to the Base Case and Fossil Fuel Scenarios, all committed units are included and generation is added as needed. The results of this scenario indicate that all interconnections are economically viable under certain circumstances. Many of the countries were not included in the scenario analysis, such as the USVI, Saba, St. Maarten, the US and Cuba; therefore, the benefits from these interconnections were not included in the results. Table 5.3 below summarizes the analytical findings, which show that these results are similar to those presented in Section 4.3. The Interconnection/ Table 5.3: Summary of Interconnection/Renewables Renewables Scenario indicates Scenario Findings that there are economically Interconnection Viability attractive renewable generation Nevis­St. Kitts Highly economical options which should be Nevis­Puerto Highly economical if in place of HFO exploited to their full potential, Rico generation both for individual country use Marginally economical if in place of and for export. Mainly, these Nevis­US Virgin distillate generation include geothermal Islands Benefits not included in scenario analysis development in Dominica (for Highly economical if in place of distillate connections with Martinique generation and St. Maarten can accept 100 MW and Guadeloupe) and in Nevis Saba­St. Maarten Benefits not included in scenario analysis (for connections with St. Kitts results and Puerto Rico). The scenario Dominica­ Highly economical if in place of distillate also indicates wind Martinique generation development in Antigua and Dominica­ Highly economical if in place of distillate Barbuda, Barbados, the Guadeloupe generation Dominican Republic, Grenada, Export from coal-fueled steam plant or gas- Haiti, Jamaica, St. Lucia, and fueled combined cycle St. Vincent and the Grenadines. United States Highly economical if in place of HFO Table 5.4 provides a summary (Florida)­Cuba generation of the model results for Benefits not included in scenario analysis renewable development on each results island. Viability depends on the generation type of the Dominican exported electricity. Republic­Haiti Nexant assumes HFO; therefore, the benefits It is important to note that in are not included in scenario analysis this simplified analysis, wind generation development is limited to around 15 percent of each system's peak load, which Nexant considered adequate to demonstrate the potential cost impact of developing wind in the 61 system. Future development of wind on each island will, of course, depend on the availability of good sites for wind generation. Table 5.4: Summary of Renewables/Interconnection Scenario Capacity Additions Country New Generation Added by 2028 Antigua and Barbuda Same units as Base Case, plus 14 MW of new wind Barbados Same units as Base Case, plus 45 MW of new wind 20 MW geothermal, plus two 92.5-MW units for export to Martinique and Dominica Guadeloupe Dominican Republic Most of the same generation as Base Case, plus 540 MW of new wind Grenada* Same units as Base Case, plus 12 MW of new wind Most of same generation as Base Case, plus 81 MW of new wind. No Haiti interconnection with DR Jamaica Most of the same generation as Base Case, plus 219 MW of new wind Nevis will interconnect with St. Kitts by 2011, and two 20-MW geothermal St. Kitts and Nevis units will supply 30 MW to St. Kitts and 10 MW to Nevis. 200 MW of geothermal will be built to supply Puerto Rico, to be completed in 2014. St. Lucia Most of the same generation as Base Case, plus 18 MW of new wind St. Vincent and the Grenadines Most of the same generation as Base Case, plus 14 MW of new wind *Grenada also has large geothermal capacity the potential of which was not explored in this study. 5.2.4. Comprehensive Integrated Scenario Finally, the Comprehensive Integrated Scenario models countries developing with all the options of the other three scenarios on a lowest-cost basis. The objective of this Comprehensive Integrated Scenario is to understand the interdependence of various development options and identify those that are most beneficial for development. For example, a renewable option, which shows significant benefits when high-cost distillate generation is replaced in the Interconnection/Renewables Scenario, may have much smaller or no benefits if, in the Comprehensive Integrated Scenario, lower-cost gas through a pipeline is available. In general, this scenario indicates that in most cases both fossil fuels and renewables should be exploited to the fullest extent possible, and the development of one will not affect the other. Thus, the capacity additions would include the fossil fuels from the Fossil Fuel Scenario and the renewables from the Interconnection/Renewables Scenario. In Martinique and Guadeloupe, both the gas pipeline and the interconnection are constructed. The results of the Comprehensive Integrated Scenario are summarized in Table 5.5. 62 Table 5.5: Summary of Comprehensive Integrated Scenario Capacity Additions New Generation Added by 2028 Country Fossil Fuels Renewables Antigua and Barbuda Three 10-MW CFB 14 MW of new wind Barbados Two 20-MW LSD on pipeline gas 45 MW of new wind 20 MW geothermal, plus two 92.5-MW units for export to Martinique and Guadeloupe. Dominica Fuel savings in Martinique and Guadeloupe are reduced compared to the Interconnection/ Renewables Scenario. Two 50-MW GT for peaking, eight Dominican Republic 300-MW conventional coal units for 540 MW of new wind baseload Grenada Seven 10-MW CFB 12 MW of new wind Total of 540 MW of LNG gas units, 81 MW of new wind. No interconnection with Haiti with terminal starting in 2014 DR. Eleven 100-MW CC running on Jamaica LNG. 450 MW of existing units will 219 MW of new wind be converted to natural gas. Nevis interconnects with St. Kitts by 2011, and two 20-MW geothermal units supply 30 St. Kitts and Nevis MW to St. Kitts and 10 MW to Nevis. 200 MW of geothermal is built to supply Puerto Rico by 2014. St. Lucia Four 20-MW LSD on pipeline gas 18 MW of new wind St. Vincent and the Seven 10-MW CFB 14 MW of new wind Grenadines 5.3 Cost Comparison of Scenario Results This section explores the NPV results of the scenario analysis on a countrywide and regional basis. Overall, it is clear that there are savings from the Comprehensive Integrated Scenario when compared with the other three scenarios. 5.3.1 Net Present Value Based on the scenario analysis, it appears that many countries could significantly benefit from developing a combination of renewables, alternative fossil fuels and interconnections. When the NPV of cost savings compared to the Base Case is estimated, the Comprehensive Integrated Scenario offers the largest savings at US$4.37 billion through 2028, followed by the Interconnection/Renewables Scenario at US$2.57 billion and the Fossil Fuel Scenario at US$2.56 billion. The NPV includes investment and production costs. In addition to accounting for savings within the nine Bank countries, the results factor in fuel savings from displaced fuel from energy exports to Guadeloupe, Martinique and Puerto Rico (see Table 5.6, Note 1). The 63 costs of these interconnections are also taken into account. Table 5.6 presents the economic savings from each of the four different scenarios on a country-by-country basis, calculated by subtracting the respective scenario from the Base Case. Each scenario in each country Table 5.6: NPV Cost Savings (US$ million) provides some cost savings Interconnection/ Comprehensive Base Fuel compared to the Base Case, Country Case Scenario Renewables Integrated since all numbers in Table 5.6 Scenario Scenario have positive values, with the Antigua exception of those for and 0 12 20 31 Barbuda Dominica, St. Kitts and Nevis in the Fossil Fuel Scenario, Barbados 0 906 39 912 which have zero benefit since Dominica 0 0 604 (Note 1) 10 (Note 1) there are no alternative fossil Dominican 0 444 350 721 options to distillate. The net Republic benefits are particularly large Grenada 0 32 17 45 for Nevis, resulting from the Haiti 0 433 76 476 fuel savings from exporting its Jamaica 0 500 138 628 geothermal power. St. Kitts 0 0 159 159 When the relative scale of these Nevis 0 0 1,135 (Note 1) 1,135 (Note 1) savings is considered, it is St. Lucia 0 216 18 221 necessary to examine them in St. Vincent relation to the total costs of and the 0 18 14 29 each scenario for each country. Grenadines Table 5.7 shows the total NPV Total 0 2,561 2,570 4,367 cost of meeting and supplying Note 1: The savings include the net impact of the increased costs the growing demand over the associated with building and operating power plants and submarine cables next two decades and the for exporting power from Dominica and Nevis to countries not listed in percent savings when the table, and the increased benefits of reduced fuel and other costs in comparing the Comprehensive those countries. The Base Case fuel and other costs in those countries are Integrated Scenario to the Base not included in the Base Case costs for Dominica and Nevis. Therefore the Interconnection/Renewables and Comprehensive Integrated Scenario Case Scenario. savings for Dominica and Nevis are not directly comparable to the savings shown for the other countries in the table. This comparison suggests that Source: Nexant there are a number of countries with large relative savings in the Comprehensive Integrated Scenario, such as Barbados, Haiti, St. Kitts, Nevis and St. Lucia, with savings ranging from 25 to 52 percent. The savings in Barbados and St. Lucia result from fuel savings from the gas pipeline, while savings in Nevis and St. Kitts result from geothermal exports. Nevis and Dominica experience negative costs in the Interconnection/Renewables Scenario due to the large fuel savings in Guadeloupe, Martinique and Puerto Rico. Haiti is the one country that shows significant benefits from diversifying its energy sources independently, with estimated savings of 24 percent. Dominica is the only country with higher costs in the Comprehensive Integrated Scenario than the Interconnections/Renewable Scenario; because the Comprehensive Integrated Scenario assumes that the gas pipeline is constructed. The model shows that benefits of the interconnection are 64 reduced when Guadeloupe and Martinique have access to pipeline gas. This may not be the case if the resources do not directly compete.21 Table 5.7: Total NPV Cost (US$ million) Interconnection/ Comprehensive Comprehensive Base Fuel Integrated Country Renewables Integrated Case Scenario Scenario % Scenario Scenario Savings Antigua and Barbuda 708 696 688 677 4% Barbados 2,266 1,360 2,227 1,354 40% Dominica 157 157 -447 (Note 1) 147 ( Note 1) (Note 1) Dominican Republic 16,357 15,913 16,007 15,636 4% Grenada 489 457 472 444 9% Haiti 1,955 1,522 1,879 1,479 24% Jamaica 8,488 7,988 8,350 7,860 7% St. Kitts 308 308 149 149 52% Nevis 188 188 -947 (Note 1) -947 (Note 1) (Note 1) St. Lucia 670 454 652 449 33% St. Vincent and the 400 382 386 371 7% Grenadines Total 31,986 29,425 29,416 27,619 14% Total Percent 8% 8% 14% Reduction Note 1: The NPV costs include the net impact of the increased costs associated with building and operating power plants and submarine cables for exporting power from Dominica and Nevis to countries not listed in the table, and the savings of reduced fuel and other costs in those countries. The Base Case fuel and other costs in those countries are not included in the Base Case costs for Dominica and Nevis. Therefore, the Interconnected/Renewables and Comprehensive Integrated Scenario costs for Dominica and Nevis are not directly comparable to the savings shown for the other countries listed in the table, and the percentage of savings are not meaningful for Dominica and Nevis. Source: Nexant Therefore, the analysis suggests that the largest savings arise in countries that can either interconnect through submarine cables or through the Eastern Caribbean Gas Pipeline. Other countries are likely to experience savings from diversifying their fuel mix or developing indigenous renewable energy, but these savings are estimated to be comparatively small (less than 10 percent). 5.3.2 Investment Requirements and Production Costs Although the NPV demonstrates savings from scenarios that deviate from the Base Case, the investment requirements increase with the NPV savings achieved. From the Base Case Scenario, 21 As mentioned in Guadeloupe's and Martinique's power system master plans, for the time being EDF has agreed to convert existing diesel plants to gas if a gas supply emerges. Geothermal imports from Dominica, on the other hand, are seen as one of the supply options for the additional near term baseload needs. 65 investment costs increase by about US$1.7 billion for the Fossil Fuel Scenario, US$3.8 billion for the Interconnection/Renewables Scenario, and US$5.5 billion for the Comprehensive Integrated Scenario. The reason for this increase is that the Fossil Fuel, Interconnection/ Renewables and Comprehensive Integrated Scenarios take advantage of technologies that have lower or no fuel costs, such as wind energy and geothermal development, but larger upfront costs. The undiscounted investment requirements for each country to cover electricity demand through 2028 are outlined in Table 5.8 for each scenario. These include the costs of interconnections, which are attributed to the exporting country. In order to achieve the Table 5.8: Investment Requirement by Scenario, US$ million lower NPV costs discussed Interconnection/ Comprehensive Base Fuel in the previous section, the Country Case Scenario Renewables Integrated production costs also must Scenario Scenario be considered. As discussed Antigua and 27 90 44 107 in Section 3.1, many Barbuda technologies with the Barbados 84 84 140 140 highest capital costs have Dominica 7 7 818 (Note 1) 818 (Note 1) the lowest production costs. Dominican 2,965 5,525 3,640 6,200 The production cost savings Republic range from US$3.7 billion Grenada 32 179 47 194 for the Interconnection/ Haiti 259 259 360 360 Renewables Scenario to Jamaica 2,928 1,663 3,202 1,937 US$13.5 billion for the Comprehensive Integrated St. Kitts 16 16 2 2 Scenario. These savings Nevis 11 11 1,913(Note 1) 1,913(Note 1) offset many of the initial St. Lucia 38 38 61 61 investment costs, St. Vincent demonstrating the possible and the 32 179 48 195 benefits of following a Grenadines regional and integrated Total 6,399 8,051 10,275 11,927 approach for power Note 1: Includes the increased costs associated with building power plants and development. It is submarine cables for exporting power to other countries. important to note that the Source: Nexant calculated production cost savings are conservative, because the benefits are only considered through 2028, but the plants and interconnections may last significantly longer. Depending on when the investment was made, these investments could continue for more than 15 additional years. Despite the net benefits from the integrated approach through decreased production costs, financing the large investment requirements will be a challenge for the Caribbean countries. Although capital investments will reduce overall costs in the long run because expenditures for fuel purchases will decline, the public sector may not be able to supply such large upfront sums because many utilities may not have the necessary financing capabilities, as discussed in Section 4.4. 66 Table 5.9: Production Cost Summary, US$ million, by Scenario Interconnection/ Comprehensive Country Base Case Fuel Scenario Renewables Integrated Scenario Scenario Antigua and Barbuda 1,906 1,809 1,821 1,729 Barbados 6,022 2,951 5,818 2,882 Dominica 410 410 500 (Note 1) 500 (Note 1) Dominican Republic 39,919 35,983 37,894 34,203 Grenada 1,370 1,118 1,296 1,061 Haiti 5,796 4,105 5,421 3,865 Jamaica 19,078 18,587 18,392 17,915 St. Kitts 816 816 300 300 Nevis 433 433 761 (Note 1) 761 (Note 1) St. Lucia 1,765 1,028 1,676 988 St. Vincent and the 1,189 1,004 1,123 952 Grenadines Total 78,704 68,244 75,002 65,156 Note 1: Includes the increased costs associated with variable O&M for power plants and submarine cables for exporting power to other countries. Source: Nexant 5.4 Country-specific Results and Options The analysis demonstrates that the most expensive strategy for countries in the region is to continue to rely on HFO and diesel to meet future power demand (Base Case Scenario). For many countries, the benefit of diversifying fossil fuels and interconnecting is substantial. However, the largest net benefit to the region is realized when there is a diversified approach. A breakdown of the preliminary findings of the integrated approach for each country follows. For more detailed country-specific results, see Annex 2. Antigua and Barbuda: The Nexant report suggests that Antigua and Barbuda could achieve savings by meeting future demand through a combination of wind and coal developments, but it is important to note that environmental costs were not considered in the analysis. The country could pay up to US$31 million more if it were to continue to rely on distillate and HFO to meet future electricity demand. However, in comparison to the total expected investments required, these savings are minimal ­ only 4 percent of the total investments needed. The addition of coal-fueled CFB technology reduces the NPV costs of supplying electricity, not including environmental costs, by US$12 million compared to the Base Case Scenario. The cost advantage compared to distillate-fueled MSD technology ranges from 2 percent at a 55 percent capacity factor to 10 percent at an 80 percent capacity factor. However, due to the large investments required for coal and to the environmental impacts, diesel may continue to be the fuel of choice. When a US$50/ton carbon price is added to the analysis, the cost advantage of 67 coal over distillate disappears. Although conventional LNG is more costly than distillate, Antigua and Barbuda may consider mid-scale LNG as a viable alternative. A more detailed analysis is warranted. The extent to which new fossil fuel capacity will be required will depend on how much wind capacity can be developed. Development of wind generation reduces NPV costs by US$20 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. Small hydro and biomass would also be economical if good sites can be identified. The benefits associated with developing renewables are relatively unaffected by the choice of fuel for the country's fossil units. Due to the environmental impacts associated with coal and other fossil fuels, it would be beneficial to aggressively promote new wind development and also investigate the potential for other site- specific competitive renewables. Barbados: The most significant savings for Barbados come from the introduction of natural gas into its power generation mix. Replacing distillate and HFO with pipeline gas-fueled generation to meet future power needs could save the country up to NPV US$906 million through 2028 when compared to the Base Case. Its cost per kWh compared to distillate-fueled generation ranges from half at a 20 percent capacity factor to 40 percent at an 80 percent capacity factor. In total, an estimated 40 percent savings could be realized in comparison to the Base Case. If the ECGP does not materialize, the other fuel options (LNG, coal) could be considered. They would offer savings compared to distillate, although not as dramatic as the ECGP gas offers. As shown in the Interconnection/Renewables Scenario, there are also large potential savings from wind development when compared with traditional fuel options. Development of wind generation reduces NPV costs in the Interconnection/Renewables Scenario by US$39 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. These benefits are reduced to an estimated US$6 million when pipeline gas is available. This illustrates the high dependence of wind generation savings on the assumed fuel supply option, and the possibility that wind generation penetration might be limited to only a few of the best wind sites. Good hydro sites would also be economical, but biomass would be marginally uneconomical. Dominica: According to the analysis, Dominica does not have alternative fossil fuel solutions that are competitive with diesel due to the country's small demand. However, as shown in the Interconnection/Renewables Scenario, it could potentially reap large benefits by developing geothermal for export to Martinique and Guadeloupe and subsequently supplying the domestic market. This could create large cost savings (to the three countries involved) of over US$600 million through 2028 compared to the Base Case Scenario. This development would help insulate the country from the high price of distillate and reducing CO2 emissions. However, as indicated by the decrease in savings in the Comprehensive Integrated Scenario, the economic benefits of geothermal development in Dominica for exports to Martinique and Guadeloupe may depend on whether additional units in Martinique and Guadeloupe have access 68 to less expensive natural gas through the pipeline (ECGP) or LNG.22 A more detailed analysis of the Martinique and Guadeloupe systems would be required to determine if both geothermal and natural gas pipeline options should be developed simultaneously, and to what extent there is a first-mover advantage. Moreover, it would be important to confirm that the geothermal resource in Dominica is large enough to serve Martinique and/or Guadeloupe. Considering the low cost of geothermal power, wind generation is only marginally economical compared to geothermal for domestic consumption in Dominica. Small hydro would also be marginally economical if good sites can be identified, but biomass would be marginally uneconomical. Dominican Republic: The Dominican Republic uses a wider range of fuels than any other country in the Caribbean and has significant renewable resource options. However, because it already has a largely diversified energy sector, the savings from alternative scenarios are insignificant, with estimated savings of 6 percent (US$700 million). The benefits come from continuing to develop a range of fossil fuels while developing good wind and hydro sites. The Fossil Fuel and Interconnection Scenarios indicate some savings from the development of alternative generation. Although the Nexant Report shows that developing coal could save US$444 million compared to the Base Case, this does not take into account the environmental costs. If a carbon price of US$50/ton is implemented, LNG becomes less costly than coal. The Interconnection/Renewables Scenario shows savings from the introduction of wind generation. However, due to the relatively low-cost fuel options, even in the Base Case Scenario, renewable generation has smaller benefits than in many other countries. Wind generation and small hydro are marginally economical if good sites can be identified, and biomass is marginally uneconomical. The Comprehensive Integrated Scenario shows savings of about 90 percent of the sum of savings from the Fossil Fuel and Interconnection/Renewables Scenarios, meaning that options in both scenarios can be developed without significantly reducing the benefits of alternative options. Grenada: Grenada could benefit from an alternative energy resources, saving up to US$50 million by 2028, or 9 percent, in the Comprehensive Integrated Scenario compared to the Base Case. Adding coal-fueled CFB technology in the Fossil Fuel Scenario reduces NPV costs, not including environmental impacts, by US$32 million compared to the Base Case Scenario, with a cost advantage compared to distillate-fueled MSD technology ranging from 2 percent at a 55 percent capacity factor to 12 percent at a 90 percent capacity factor. As in many other countries, in Grenada the cost advantage of coal disappears if costs of US$50/ton are added for CO2 emissions. Although conventional LNG is more costly than distillate, mid-scale LNG may be a more viable fuel option and should be analyzed further. The Interconnection/Renewables Scenario shows savings from the development of wind generation; NPV costs are reduced by US$17 million compared to the Base Case Scenario. This assumes that sites with good winds and low development costs can be identified and acquired. Small hydro and biomass would also be 22 As mentioned in Guadeloupe's and Martinique's power system master plans, for the time being EDF has agreed to convert existing diesel plants to gas if a gas supply emerges. Geothermal imports from Dominica, on the other hand, are seen as one of the supply options for the additional near term baseload needs. 69 economical if good sites can be identified. The benefits are relatively unaffected by the choice of fuel for the country's fossil units.23 Thus, the Comprehensive Integrated Scenario shows combined savings from coal and wind options that are close to the sum of the other two scenarios. This result means that wind development will not negatively affect the coal option and vice versa. Haiti: The poor condition and inadequate amount of generation in Haiti make all near-term additions highly cost effective until an adequate reserve margin is established. In particular, Haiti could benefit by introducing LNG and wind, with savings of up to US$476 million through 2028, or 24 percent savings when compared to the Base Case. The Fuel Scenario savings indicate that it is beneficial to introduce LNG as a fuel, while the Interconnection/Renewables Scenario shows savings from the introduction of wind generation. First, in the Fuel Scenario, LNG is the least-cost option and could save US$433 million through 2028 compared to the Base Case. Second, the development of wind generation in the Interconnection/Renewables Scenario could reduce NPV costs by US$76 million compared to the Base Case Scenario. This assumes that sites with good winds and low development costs can be identified and acquired. The Comprehensive Integrated Scenario shows combined savings of LNG and wind options, assuming that a new LNG plant starts operation in 2014. In the Comprehensive Integrated Scenario, wind is less attractive but is still economical because it is used in place of lower-cost LNG rather than distillate. Small hydro would also be economical and biomass would be marginally economical if good sites can be identified. The Comprehensive Integrated Scenario savings results are close to the sum of the other two scenarios, meaning that wind development will not negatively affect the LNG option and vice versa, and the power system would benefit the most from development of both options. The Comprehensive Integrated Scenario does not include an interconnection between the Dominican Republic and Haiti since Nexant assumes that exports would be based on the more expensive HFO generation. On an NPV basis, the interconnection would increase system costs in the Dominican Republic by US$322 million and decrease system costs in Haiti by US$556 million, for total savings of US$235 million. At the same time, the NPV costs of building and operating transmission lines are US$242 million. However, if the Dominican Republic expands its natural gas-fueled generation, thus reducing electricity costs, the interconnection could be economically viable. Jamaica: The situation in Jamaica is similar to that of the Dominican Republic where alternative fossil fuels combined with wind generation developments could save money, although not a significant amount relative to the investments that must be made. In the Fuel Scenario, LNG displaces HFO in existing plants and the new coal generation assumed to be added in the Base Case Scenario remains. These changes lead to savings of US$500 million. 23 Grenada has a large estimated geothermal resource, the development of which was not examined in this study. The government recently announced plans to explore the potential of development, which could impact the country's energy options. 70 Development of wind generation in the Interconnection/Renewables Scenario reduces NPV costs by US$138 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. Small hydro would also be economical if good sites can be identified. The benefits are relatively unaffected by the choice of fuel for the country's fossil units. In total, these changes could save about US$630 million compared to continuing the use of HFO and distillates. However, the Base Case Scenario assumes that the infrastructure to deliver and generate with coal will be put in place. If this does not occur, the other scenarios' benefits would be much larger. St. Kitts and Nevis: Due to their small systems and geographic locations, St. Kitts and Nevis do not have any viable alternative fossil fuel options when compared to distillate. Therefore, geothermal development is important for the two islands, because it would help insulate them from the high and variable price of distillate and reduce CO2 emissions. St. Kitts and Nevis would benefit from large savings (US$159 million) from geothermal development on Nevis and an interconnection to St. Kitts. These saving are much higher than the increased costs associated with developing the plant and interconnection (around US$100 million). This indicates a win- win situation for interconnection, and it seems likely that a plan of at least 40 MW will be developed. Furthermore, Nevis can achieve large potential benefits through additional geothermal development and an interconnection with Puerto Rico. The large benefits associated with the development of 400 MW for export to Puerto Rico are based on using Nevis's electricity exports in place of HFO generation in Puerto Rico. In total, NPV savings from geothermal development and the fuel cost savings from interconnections create potential for huge export revenue. West Indies Power indicates that exploration data suggest a resource of at least 300 MW, and once the resource is known, a better estimate of the savings can be calculated. Given the low cost of geothermal power, other renewables are not as competitive as on other islands. Wind generation is only marginally economical for domestic consumption. Small hydro is also marginally economical, though it is not clear that adequate resources exist, and biomass appears marginally uneconomical. St. Lucia: According to the analysis, St. Lucia can achieve the largest savings for power generation by introducing natural gas (from the pipeline) and developing wind power, with a net benefit of US$221 million, or 33 percent savings of its Base Case costs. The most attractive option is the Eastern Caribbean Gas Pipeline, gas from which could displace distillate in existing units and fuel new units. The Fuel Scenario estimates NPV savings of US$216 million compared to the Base Case Scenario from pipeline gas. Savings from wind largely depend on the extent to which gas is introduced, because only good wind sites will be able to compete with natural gas. Development of wind generation reduces the Interconnection/Renewables Scenario's NPV costs by US$18 million compared to the Base Case Scenario. This would require the development of enough good wind sites with low development costs. However, when ECGP gas is available, as is assumed in the Comprehensive Integrated 71 Scenario, the addition of wind generation saves only US$5 million. Wind is marginally economical, as is small hydro if sites can be identified, and biomass appears to be marginally uneconomical. This illustrates the high dependence of wind generation savings on the available fuel supply. Therefore, wind generation may be limited to only a few of the best wind sites. St. Vincent and the Grenadines: St. Vincent and the Grenadines may benefit from introducing a combination of coal and wind generation to replace HFO and distillates in meeting its future power demand, although the savings are relatively insignificant and the costs do not include environmental impacts. The analysis indicates that cost savings of up to US$30 million (7 percent of the Base Case) could be achieved over the next two decades. In the Fuel Scenario, adding coal-fueled CFB technology reduces NPV costs, not including environmental costs, by US$12 million compared to the Base Case Scenario. The cost advantage compared to distillate-fueled MSD technology ranges from 2 percent at a 55 percent capacity factor to 12 percent at a 90 percent capacity factor. However, this cost advantage disappears if a carbon price of US$50/ton is added, and diesel returns to being a competitive technology. In addition, a more detailed study on the potential of mid-scale LNG is justified. Although conventional LNG is more costly than distillate, smaller-scale LNG may be a viable option. Development of wind generation reduces NPV costs by US$20 million compared to the Base Case Scenario, assuming good sites. Small hydro and biomass are also economical if good sites can be identified. The benefits from wind are relatively unaffected by the choice of fuel for the country's fossil units. However, the extent to which new coal capacity would be required will depend on how much wind capacity can be developed. 5.5 Conclusions Overall, it appears that the region could benefit significantly from developing a combination of renewables, alternative fossil fuels, and interconnections. The countries that would experience the most significant benefits are those that would either be connected to the gas pipeline or be part of a geothermal interconnection. These include Barbados, Dominica, St. Kitts and Nevis, and St. Lucia, with savings ranging from 30 to 52 percent. Haiti is the one country that shows significant benefits from diversifying its sources independently, with estimated savings of 24 percent. These results are summarized in Table 5.9. All other countries without potential for a gas pipeline or submarine interconnection appear to have some expected benefit from diversifying fossil fuels by pursuing renewable energy options on their own, but the savings are predicted to be relatively small. Most notably, the small islands with limited alternative fuel options have small potential savings. These include Antigua and Barbuda, Grenada, and St. Vincent and the Grenadines. In addition, the analysis indicates that although the absolute savings for the Dominican Republic and Jamaica are large, the savings relative to the total cost that are expected to be incurred in the Base Case to meet growing demand are small. 72 Table 5.9: Source and Size of Savings by Country Potential Cost Savings Country Country-Size Source of Largest Savings Relative to Base Case Costs Dominican Republic Large Fossil fuels Insignificant Grenada Very Small Imported coal* Insignificant Jamaica Large LNG Insignificant Antigua and Barbuda Very Small Renewables Insignificant St. Vincent and the Very Small Renewables Insignificant Grenadines Barbados Small Pipeline gas Significant St. Lucia Very Small Pipeline gas Significant Haiti Large LNG Significant St. Kitts Very Small Geothermal Imports Significant Geothermal development Dominica Very Small Very Large and export Geothermal development Nevis Very Small Very Large and export *This study does not consider the development of Grenada's geothermal resource, which would likely change this result. This study used a simplified approach; future work is needed to identify the optimal approaches for each country. As this scenario analysis suggests, many opportunities exist for cost savings and should be further explored. Regional solutions and the diversification of energy sources provide additional benefits, such as reducing price volatility, improving environmental conditions, and increasing resilience, which may be attractive to many countries. 73 Chapter 6 Conclusions and Looking Forward O verall, the Caribbean countries face sizeable challenges as they struggle to meet a growing energy demand and diversify their energy mix. Distillates and HFO are the dominant fuels for power generation in the region, but they come with a variety of problems such as high prices and price volatility. As demand increases, the problems associated with relying primarily on liquid fuels increases as well. 6.1 Key Conclusions In general, when acting independently, some individual Caribbean countries stand to benefit from developing indigenous renewable resources and expanding fossil fuel options. The smaller islands appear to have some benefits from introducing renewable energy, such as wind, hydro and biomass, but the largest potential among them are the geothermal resources in Dominica and Nevis. In the slightly larger markets of Barbados, Guadeloupe and Martinique, LNG is the most economical option, with wind also as a viable option. Finally, in the three largest markets--Haiti, Jamaica and the Dominican Republic--coal and LNG could potentially reduce costs, although environmental factors should be considered. While the savings for many of the countries are not significant, the options are viable and may warrant taking next steps, such as conducting more in-depth prefeasibility studies to better understand the viability and expected benefits. The study shows that many countries may be able to enhance the benefits of developing alternative resources by considering regional solutions, such as interconnecting electricity markets and constructing a gas pipeline. In most countries, these options appear to provide the lowest-cost energy, often by significant margins over distillate. Many of the electricity market interconnections analyzed in depth in the study appear to be technologically feasible, with the exception of submarine interconnections with Haiti, and most are economically viable under certain circumstances. The most direct benefit of an interconnection comes when one country has a source of low-cost power and its neighbor does not; therefore, lower-cost electricity can be exported, earning revenue for the exporting country and lowering electricity costs for the importing country. Geothermal is the source of generation that drives the benefits for many of the interconnections. It is so low cost in comparison to distillate that even a long connection moving a small amount of power, such as from Nevis to the US Virgin Islands, shows marginal economic benefits. 74 Another regional solution, the proposed Eastern Caribbean Gas Pipeline, also offers the potential to reduce electricity costs by reducing fuel import costs. Pipeline gas is economical for every country that it passes through, supplying the cheapest fossil fuel option. However, similar to individual country solutions, there may be a first-mover advantage between the gas pipeline and alternative options. Thus, regional options offer added benefit over individual development. In all countries that were studied as part of a regional solution, regional integration can further reduce electricity generation costs. There are also many benefits from interconnection beyond those considered in the analysis, such as potentially reducing the required reserve, providing emergency support, and increasing access to cleaner technologies. For some countries, these reasons alone may provide significant justification for further pursuing the idea of interconnections through additional exploration or studies. 6.2 Limitations and Challenges The analysis is based on a purely economic and technical comparison of fuels, renewable technologies and interconnections. However, as discussed in Section 4.4, there are environmental, financial, institutional and political difficulties and risks that may inhibit the achievement of lower-cost options in the region. These are important to consider in discussions of the feasibility of projects. A number of financial risks and challenges are associated with pursuing alternative options. Although the higher capital investments required for alternative generation sources may reduce expenditure in the long run, obtaining financing for the projects could be a challenge. Local utilities may have difficulty funding such large investments, and some countries may opt for slightly more expensive operating costs to reduce upfront financing. There are also many unknowns when future cash flows are projected, and risks associated with betting on fuel costs are high. As a result, utilities may be hesitant to invest in alternative technologies. Thus, the private sector, public-private partnerships and support from international financial institutions (IFIs) and the international donor community may often be of key importance. In addition, countries may need improved legal, regulatory and institutional frameworks domestically and for cross-country cooperation. For regional integration options, regulatory harmonization among two or more countries may be necessary for the success of the project. Similarly, issues arising from separate ownership of various components of interisland power or fuel supply need to be addressed. For the export of geothermal power by means of a submarine cable, one private party might own the geothermal power plant in the exporting country while another owns and operates the submarine cable. Joint ownership can present other types of issues. Contractual structures and supporting institutions must be created to guarantee supply and allocate risks and responsibilities to the appropriate parties. The needs of all parties would be best served by long-term contracts that guarantee supply to the customer and a revenue stream to the suppliers. 75 Finally, a secure supply of energy is often viewed as a national security issue, and many countries may be hesitant to rely on another country for power. Although distillate and HFO are widely available at present, political unrest or technical failures may compromise one country's ability to supply another. However, this hesitancy has been overcome in many other countries. Countries may choose to increase reserve margins to improve security, the economic impact of which was not taken into account in this study. Nevertheless, these early results reveal interesting interconnection and cross-country opportunities that are worth pursuing further. Many countries have significant potential for saving or earning export revenue, and may decide that the benefits merit facing these challenges and risks. Interconnections may also increase the use of large-scale renewable energy, thereby reducing carbon emissions from the region. 6.3 Next Steps There are opportunities for Caribbean countries to move toward a more integrated and diverse energy mix--one that includes more renewables--over the next decade. Diversity and integration reduce vulnerabilities from high and volatile fuel prices, load shedding and extreme climate events. Much more detailed and project-specific work must be done before proceeding with any major facility, but the priority concepts emerging from this study are as follows: Renewable Energy Development: The Caribbean has a large potential for renewable, economic energy resource development, including wind, geothermal and small hydro. Based on this study, these technologies appear to be highly competitive with the technologies currently in use. A challenge to development will be to identify sites where the resource is good and development costs are not a barrier. Therefore, to encourage development it may be most cost effective to assist in identifying such sites. Interconnections can increase countries' ability to develop large- scale renewable projects. Submarine Cable Electricity Interconnections: There appear to be a number of highly economical, technically viable electricity market interconnection options. As noted above, this could promote larger-scale renewable usage. However, a significant amount of work needs to be done, both to understand the viability of interconnections examined in this study and to evaluate interconnections not considered in this analysis, including subregional interconnections (such as a Southern Caribbean Ring), continental connections (such as with Mexico, the US, Colombia or Venezuela), and bilateral interconnections (such as Montserrat­Antigua and Puerto Rico­ Dominican Republic). Gas Pipelines: The potential for gas pipelines should also be considered, given the positive economic benefits that this study suggests. The Eastern Caribbean Gas Pipeline may provide the most economical fossil fuel for each island it reaches and the benefits of economies of scale compared to individual development. The gas is about half as costly as distillate for Barbados, Guadeloupe, Martinique and St. Lucia. Development of any pipeline will require the agreement of many parties, such as gas suppliers, utilities, regulators, financial institutions and 76 governments, making the development process more costly and time consuming. A wide range of support may be required to move these projects forward. This is a high-level concept study; a detailed feasibility study needs to be carried out on any proposed interconnection to turn a possibility into a reality. A feasibility study would include a comprehensive analysis of all key issues related to a proposed interconnection, including the technical, environmental, commercial, financial and economic aspects. The analysis will also need to outline the subregional legal, regulatory and institutional frameworks needed to attract investors to carry out the project. Regional organizations and IFIs can provide valuable contributions both to facilitate the policy dialogue among the countries and to provide technical assistance and financial support to address political and financial risks for potential investors. Overall, this study provides evidence that regional electricity solutions merit further research and investigation in the Caribbean. Many countries have significant potential to gain from developing new resources and exploring interconnections. Therefore, it is recommended that individual countries or sets of countries use these preliminary high-level findings to conduct more in-depth prefeasibility and feasibility studies of individual, subregional and regional solutions. 77 Annex 1 Forecasted Demand and Supply Table A1.1: Net Peak Demand Load Forecast (MW) Antigua and Dominican St. St. St. Vincent and Year Barbados Dominica Grenada Haiti* Jamaica Nevis Martinique Guadeloupe Total Barbuda Republic Kitts Lucia the Grenadines 2009 54 170 15 2353 31 226 680 29 10 56 27 242 250 4143 2010 57 176 15 2447 33 237 707 30 10 58 28 247 256 4301 2011 60 182 16 2544 34 249 736 31 11 61 30 255 263 4472 2012 63 188 16 2640 36 261 767 32 11 63 32 263 269 4641 2013 65 195 17 2727 38 274 799 33 12 65 35 272 276 4808 2014 67 201 17 2803 40 288 832 35 13 68 37 281 284 4966 2015 69 208 18 2896 42 303 867 36 13 70 40 290 291 5143 2016 71 216 18 2992 45 318 904 37 14 73 42 297 298 5325 2017 73 223 19 3091 47 334 943 38 15 76 45 303 305 5512 2018 75 231 19 3194 50 350 983 40 16 79 48 310 313 5708 2019 77 239 20 3300 52 368 1026 41 17 82 52 317 321 5912 2020 80 247 20 3409 55 386 1071 43 18 85 55 324 329 6122 2021 82 256 21 3522 58 405 1116 44 19 88 49 331 337 6328 2022 85 265 21 3638 61 426 1165 46 20 91 63 339 346 6566 2023 87 274 22 3758 64 447 1214 47 21 95 68 346 354 6797 2024 90 284 22 3882 68 469 1267 49 23 98 72 354 363 7041 2025 92 294 23 4010 72 493 1322 51 24 102 77 362 372 7294 2026 95 304 24 4143 75 517 1379 52 25 106 83 370 381 7554 2027 98 314 24 4280 80 543 1439 54 27 110 88 378 391 7826 2028 101 325 25 4421 84 570 1502 56 29 114 94 387 400 8108 Growth Rate 3.3% 3.5% 2.7% 3.4% 5.4% 5.0% 4.3% 3.5% 5.9% 3.8% 6.9% 2.5% 2.5% 3.6% * All forecasts were conducted before the January 2010 earthquake. Source: Nexant Report 78 Table A1.2: Net Generation Forecast (GWh) Antigua St. Vincent Dominican St. Year and Barbados Dominica Grenada Haiti* Jamaica St. Kitts Nevis and the Martinique Guadeloupe Total Republic Lucia Barbuda Grenadines 2009 318 1,039 87 12,638 198 660 4,490 161 60 345 156 1,575 1,663 23,390 2010 315 1,073 89 13,142 209 726 4,674 166 67 356 167 1,620 1,720 24,324 2011 312 1,107 91 13,663 220 799 4,865 171 74 367 178 1,672 1,775 25,294 2012 410 1,143 94 14,179 232 878 5,066 175 82 378 191 1,727 1,832 26,387 2013 422 1,180 96 14,646 244 966 5,277 180 86 390 204 1,783 1,888 27,362 2014 434 1,218 99 15,054 257 1,063 5,494 186 90 402 218 1,840 1,947 28,302 2015 447 1,258 101 15,554 270 1,169 5,726 191 94 415 233 1,900 2,003 29,361 2016 461 1,298 104 16,070 285 1,286 5,974 196 99 428 249 1,938 2,060 30,448 2017 475 1,340 106 16,601 300 1,415 6,232 202 103 442 266 1,978 2,117 31,577 2018 489 1,384 109 17,154 316 1,556 6,497 208 107 455 284 2,018 2,174 32,751 2019 503 1,428 112 17,724 333 1,712 6,777 214 111 470 304 2,058 2,233 33,979 2020 519 1,475 114 18,309 350 1,883 7,073 220 115 484 325 2,100 2,284 35,251 2021 534 1,522 117 18,914 369 1,977 7,376 226 119 500 348 2,142 2,337 36,481 2022 550 1,572 120 19,539 389 2,076 7,696 233 124 515 372 2,186 2,390 37,762 2023 567 1,622 123 20,184 409 2,180 8,024 239 129 531 397 2,230 2,445 39,080 2024 583 1,675 126 20,851 431 2,289 8,370 246 134 548 425 2,275 2,501 40,454 2025 600 1,729 129 21,539 454 2,403 8,734 253 139 565 454 2,321 2,559 41,879 2026 618 1,785 133 22,251 478 2,523 9,114 261 145 583 485 2,368 2,618 43,362 2027 636 1,843 136 22,986 504 2,650 9,510 268 150 601 519 2,416 2,679 44,898 2028 654 1902 139 23745 530 2782 9924 276 156 620 555 2465 2,741 46,489 Growth Rate 3.9% 3.2% 2.5% 3.4% 5.3% 7.9% 4.3% 2.9% 5.2% 3.1% 6.9% 2.4% 2.7% 3.7% * All forecasts were conducted before the January 2010 earthquake. Source: Nexant Report 79 Annex 2 Nexant Country Overviews24 1. Antigua and Barbuda Overview: The Antigua Public Utility Authority (APUA) is responsible for power generation, transmission and distribution of electricity in Antigua and Barbuda. APUA purchases most of the power from the Antigua Power Company (APC), a private company. Antigua and Barbuda has historically relied exclusively on diesel for power generation, although some diesel engines were recently converted to HFO. Current and Forecast Load: The country's 2009 peak demand was just over 50 MW, with net generation of over 300 GWh. By 2028 peak demand is projected to increase to around 100 MW, with net generation increasing to around 650 GWh (an increase rate of 3.9 percent per year). Losses in the transmission and distribution system are projected to decrease from over 30 percent in 2009 to around 10 percent by 2028. Fossil Fuel Options: Imported coal is considered as an alternative fuel. Due to the location and electricity demand on the islands, the study does not find natural gas to be an economically viable fuel option. Renewable Generation Potential: Wind is the most promising renewable resource for Antigua and Barbuda. A 2008 Energy Engineering Corp. report indicated that up to 400 MW of wind power can be developed on the islands, primarily on Barbuda.25 Solar PV potential is estimated at 27 MW, though its development was not considered in this study. Development Scenarios: All four scenarios assume that the committed system additions of the Casada Gardens units will be installed during 2011­2013. With these unit additions, system reserve margin requirements would be fulfilled until 2019. During 2020­2028, the system's demand growth will require the building of additional generation units. For the Base Case Scenario, new unit additions are assumed to be 10-MW MSD units using distillate oil. By 2028 the system will need another 30 MW (3 x 10 MW units) to meet the required capacity. For the Fuel Scenario, coal-fueled CFB plants are marginally more economical than distillate- fueled MSD plants, but environmental considerations are not taken into account. Although in this scenario new unit additions are assumed to be 10 MW CFB units using imported coal, CO2 costs 24 This annex is drawn from the country overview prepared by Nexant. 25 GTZ has recently conducted a more precise assessment of some specific sites. 80 of US$50/ton would make the distillate-fueled units more economical than the coal-fueled units. Conventional (large-scale) LNG is more costly than either the distillate or coal option. Although not studied in the same detail as the other fuel options, mid-scale LNG may provide an economically attractive option. By 2028 the system will need another 30 MW (3 x 10 MW units) to meet the required capacity. The Fuel Scenario results show that the introduction of coal provides NPV savings of US$12 million compared to the Base Case Scenario (not including environmental costs). The Interconnection/Renewables Scenario assumes development of new diesel units, as in the Base Case Scenario, with the addition of 14 MW of new wind units. This assumes that sites with good winds and low development costs can be identified and acquired. The Interconnection/Renewables Scenario results show that the introduction of wind generation provides NPV savings of US$20 million compared to the Base Case Scenario. The Comprehensive Integrated Scenario assumes that new generation units are 10-MW CFB units, as in the Fuel Scenario, and the addition of 14 MW of new wind units, as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario results show that including both coal as a fuel and wind generation provides combined savings of US$31 million over the Base Case Scenario, not including environmental costs. The Comprehensive Integrated Scenario results show savings close to the sum of the savings of other two scenarios. Discussion of Country Results: Adding coal-fueled CFB technology reduces NPV costs by US$12 million compared to the Base Case Scenario, not including environmental costs which would reduce the savings. The cost advantage compared to distillate-fueled MSD technology ranges from 2 percent at a 55 percent capacity factor to 10 percent at an 80 percent capacity factor. This cost advantage disappears if costs of US$50/ton are added for CO2 emissions. Conventional LNG is more costly than distillate, but mid-scale LNG might be a viable fuel option, thereby justifying a more detailed analysis. Development of wind generation reduces NPV costs by US$20 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. With that assumption, wind is much lower in cost than distillate-fueled generation. Small hydro and biomass would also be economical if good sites can be identified. The benefits are relatively unaffected by the choice of fuel for the country's fossil units. 81 2. Barbados Overview: Barbados Light and Power (BL&P), a private company, is responsible for power generation, transmission and distribution of electricity in Barbados. Existing installed generation of around 240 MW, mostly comprising low- and medium-speed diesel units, substantially exceeds peak demand and provides a comfortable reserve margin. BL&P is looking to diversify its fuel mix, which is mostly dependent on imported oil products. Current and Forecast Load: The country's 2008 peak demand was 164 MW, with net generation of over 1,000 GWh. By 2028 peak demand is projected to double to around 325 MW, with net generation increasing to around 1,900 GWh (an increase rate of 3.5 percent per year). Fossil Fuel Options: Natural gas, delivered as LNG or through the Eastern Caribbean Gas Pipeline (ECGP), and imported coal are considered as alternative fuel options. Due to the location and electricity demand on the island, natural gas delivered through ECGP appears to be the most economically attractive fuel option. Renewable Generation Potential: No studies on country-specific overall wind and solar potential are available. Therefore, Nexant estimates Barbados' wind potential to be at least 10 MW based on an already approved project. Solar PV potential is estimated at 26 MW of installed capacity, though its development was not considered in this study. Development Scenarios: All four scenarios assume that the committed system additions of the nine 16-MW Trent units will be installed. The first six units will be added during 2011­2013, and the next three will be added when required to match the load growth. All Trent unit additions would satisfy reserve margin requirements until 2025. During 2026­2028, the Barbados system will require new capacity additions. For the Base Case Scenario, new additions are assumed to be 20-MW low-speed diesel units using distillate oil. By 2028 the system will need another 40 MW (2 x 20 MW units) to meet the required capacity. For the Fuel Scenario, assumed system additions are the same as for the Base Case Scenario. The difference is that in this scenario most existing and all new units are assumed to use natural gas as a fuel, supplied through the ECGP. The Fuel Scenario shows that the introduction of ECGP natural gas could provide NPV savings of US$906 million compared to the Base Case Scenario. For the Interconnection/Renewables Scenario, most assumed system additions are the same as for the Base Case Scenario. The difference in this scenario is the addition of 45 MW of new wind units. This assumes that sites with good winds and low development costs can be identified and acquired. There is no electrical interconnection. The Interconnection/Renewables Scenario shows that the introduction of wind generation could provide NPV savings of US$39 million compared to the Base Case Scenario. 82 For the Comprehensive Integrated Scenario, the availability of natural gas is assumed, as in the Fuel Scenario, combined with the addition of 45 MW of new wind units, as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario results show NPV savings of US$912 million over the Base Scenario, only slightly more than for the Fuel Scenario. Discussion of Country Results: Barbados has three fossil fuel options that offer economic benefits compared to continued reliance on oil products: natural gas through the ECGP, LNG, and coal (not including environmental costs). By far the most attractive is the ECGP option, which provides NPV savings of US$906 million compared to the Base Case Scenario. Its cost per kWh compared to distillate-fueled generation ranges from less than half at a 20 percent capacity factor to less than 40 percent at an 80 percent capacity factor. If the ECGP does not materialize, the other fuel options should be considered. They would offer significant savings compared to distillate. Development of wind generation reduces Interconnection/Renewables Scenario NPV costs by US$39 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. However, when ECGP gas is available, as is assumed in the Comprehensive Integrated Scenario, adding wind generation increases savings by only US$6 million. Wind is only marginally economical, as would be small hydro if good sites can be identified, but biomass would be marginally uneconomical. This illustrates the high dependence of wind generation savings on the assumed fuel supply option, and the possibility that wind generation penetration might be limited to only a few of the best wind sites. 83 3. Dominica Overview: Dominica Electricity Services Limited (DOMLEC) is a sole producer responsible for power generation, transmission and distribution of electricity in Dominica. Existing installed generation, comprising high- and medium-speed diesel units and hydro units, exceeds peak demand in the wet seasons. Dominica is looking to diversify its fuel mix, which is mostly dependent on imported oil products. Current and Forecast Load: The country's current peak demand is around 15 MW, with net generation of around 90 GWh. By 2028 peak demand is projected to increase to 25 MW, with net generation increasing to around 150 GWh (an increase rate of 2.5 percent per year). Fossil Fuel Options: Due to the low electricity demand on the island, the least-cost fuel is distillate because the fixed costs associated with all other fuels produce higher unit costs in US$/GJ. Renewable Generation Potential: Based on the ongoing assessment of potential at the Watton Waven field in central Dominica, and West Indies Power's exploration in the Soufrière area, geothermal potential is estimated to be adequate to supply 100 MW of geothermal power plants. Drilling of the first three slim (exploratory) wells are scheduled to start in July 2011 in the Soufrière area near the southern coast. Solar PV potential is estimated at 45 MW of installed capacity, though its development was not considered in this study. Dominica also has small-scale hydro and wind potential. Development Scenarios: Starting in 2012 Dominica will require new capacity additions. For the Base Case Scenario, new additions are assumed to be 5-MW medium-speed diesel units using distillate oil. By 2028 the system will need another 15 MW (3 x 5 MW units) to meet the required capacity. Dominica does not have a potentially less expensive fossil fuel option. The Interconnection/Renewables Scenario assumes the addition of a 20-MW geothermal unit in 2012 to meet local needs. It also assumes submarine cable electrical interconnections with Martinique and Guadeloupe, and the addition of two 92.5-MW units in 2014 to support exports to those two countries. The results show large benefits of geothermal development in this Scenario, with NPV savings of US$604 million compared to the Base Case Scenario. The Comprehensive Integrated Scenario assumes the same geothermal additions and interconnections as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario assumes construction of the ECGP and natural gas deliveries to those two countries, so fuel savings on Martinique and Guadeloupe are reduced because the model assumes imports are replacing lower-cost natural gas- (rather than distillate-) based generation, which may not be the case (see footnote 19). The Comprehensive Integrated Scenario results show combined savings of only US$10 million, demonstrating that savings are highly dependent on the assumed fuel supply option for Martinique and Guadeloupe. Savings of US$10 million are considerably less than the savings from the much smaller supply to Dominica alone. 84 Discussion of Country Results: Because its low demand means that no fossil fuel options appear economical compared to distillate, geothermal development is particularly important for Dominica. It seems probable that a geothermal resource at least large enough to serve Dominica's demand will be confirmed. This would be the most important result from the country's point of view, because it would insulate the country from the high price of distillate and from the uncertainty associated with variations in that price over time. It would also reduce CO2 emissions. Considering the low cost of geothermal power, wind generation is only marginally economical compared to geothermal for domestic consumption on Dominica. Small hydro would also be marginally economical if good sites can be identified, but biomass would be marginally uneconomical. Confirmation of a resource sufficient to serve exports to Martinique and/or Guadeloupe is less certain. Additionally, Martinique and Guadeloupe have alternative supply options ­ LNG and pipeline gas ­ both of which provide large cost savings over distillate. It is clear that a more detailed analysis of the Martinique and Guadeloupe systems would be required to determine the desirability of developing geothermal power in Dominica for export to those countries. That will depend on the resource, how alternative fuel supplies are used and developed (distillate, ECGP, LNG), as well as factors such as costs and the number of units that could be converted to natural gas. 85 4. Dominican Republic Overview: Prior to 1997, all the generation, transmission and distribution assets of the Dominican Republic were held by the state-owned company, Corporación Dominicana de Empresas Eléctricas Estatales (CDEEE). In 1997 a capitalization process divided the three entities and the stocks of the companies were sold to private investors. Now the Dominican Republic has eleven different private thermal power-generating companies and a government- owned hydroelectric entity, Empresa de Generación Hidroeléctrica Dominicana (EGEHID). AES Dominica, the largest thermal power generator, is owned by AES, an international utility company. Other generation companies are: Empresa Generadora de Electricidad Haina (EGE Haina), Generadora Palamara La Vega (GPLV), Compañía de Electricidad de San Pedro de Macorís (CESPM), and five smaller companies. There are three private and one public distribution companies and a public-owned transmission company. Current and Forecast Load: The country's 2008 peak demand was 2,168 MW, with net generation of over 11,600 GWh, making it by far the largest power market of all the countries studied. By 2028 peak demand is projected to double to over 4,400 MW, with net generation increasing to around 23,750 GWh (an increase rate of 3.4 percent per year). Fossil Fuel Options: Today the Dominican Republic has power plants that use coal and natural gas derived from LNG, but most of its existing generation uses HFO. Options for the future include expanding the use of coal and LNG. Renewable Generation Potential: The government enacted a law in 2007 that defined goals for future renewable energy development. The goal is to have 25 percent renewable energy by 2025. About 350 MW of wind projects have already been approved. There is also significant additional wind potential, based on provisional studies. There are also estimates of 2,899 MW of solar PV projects. Construction is under way or contracts have been signed for 356 MW of new hydro plants. In addition, several hundred MW of new hydro projects are in different stages of development. Development Scenarios: In 2010 and 2011, the installation of already committed hydro and wind resources will add enough new capacity to cover the short-term load growth in all scenarios. Starting in 2012, the Dominican Republic system will require new capacity additions. For the Base Case Scenario, new additions are assumed to be 300-MW CC units using LNG, with a few additions of 50-MW GT units to cover peaking generation. Results of the analysis show that by 2028 the system will need another 2,400 MW (8 x 300 MW) of CC units and 100 MW of GT units. For the Fuel Scenario, new additions are assumed to be coal-based units. The first additions are planned units (Montecristi and Haltillo-Azua), followed by generic 300-MW conventional coal units using imported coal. This scenario again includes additions of 50-MW GT units to supply peaking generation. The results of the analysis show that by 2028 the system will add another 2,400 MW (8 x 300 MW) of coal units and 100 MW of GT units. The Fuel Scenario results show that the introduction of coal could provide NPV savings of US$444 million compared to the 86 Base Case Scenario, although these savings are relatively small compared to the system costs and the results do not take into account the environmental externalities that should be considered. The Interconnection/Renewables Scenario assumes the addition of renewable energy resources. Most assumed generation is the same as in the Base Case Scenario, but the Interconnection/Renewables Scenario includes the addition of 540 MW of new wind units (30 MW each year starting in 2011). This scenario does not include interconnection with Haiti since savings will depend on the fuel exported, and it is not clear that the fuel used for generation will be natural gas. The Interconnection/Renewables Scenario shows potential savings of US$350 million from the introduction of wind generation only. The Comprehensive Integrated Scenario assumes that system additions are the same as in the Fuel Scenario, with the addition of new wind units as in the Interconnection/Renewables Scenario. This Scenario shows combined savings of US$721 million or about 90 percent of the sum of savings from the other two scenarios. Discussion of Country Results: The Dominican Republic currently uses a wider range of fuels than any other country, and has significant renewable resource options. It could expand its use of coal and LNG while adding wind and hydro. As with Barbados, the relatively low fuel cost makes renewable generation economically less attractive than in other countries unless environmental considerations are taken into account. Wind generation is marginally economical. Small hydro would be marginally economical if good sites can be identified, but biomass appears to be marginally uneconomical.26 26 Considerations of environmental costs have been added to the overviews. 87 5. Grenada Overview: Grenada Energy Services Ltd. (GRENLEC) is a private energy provider that owns all the generation and transmission facilities in Grenada, Carriacou and Petit Martinique. GRENLEC's installed generation, mostly LSD units, exceeds 2008 peak demand by about 81 percent, providing a comfortable reserve margin. Most of the generating units were installed after 2002 and are relatively efficient. The diversification of the fuel/energy mix and the use of alternative energy sources are two critical strategic objectives. Current and Forecast Load: The country's peak demand is around 30 MW, with net generation of around 190 GWh. By 2028 peak demand is projected to increase significantly to around 84 MW, with net generation increasing to around 530 GWh (an increase rate of 5.3 percent per year). Fossil Fuel Options: Imported coal is considered as an alternative fuel. Due to the location and electricity demand on the island, the study does not find natural gas to be an economically viable fuel option. Renewable Generation Potential: Wind is the most promising renewable resource for Grenada. Initial wind measurements and project installations are under way. Grenada is also encouraging small photovoltaic installations. Solar PV potential is estimated at 21 MW of installed capacity. Grenada's geothermal potential is estimated at 400 MW. The government recently announced plans for development of the resource, though the impact from future development was not considered as a part of this study. It is possible that the development of geothermal resources would significantly change the future energy options of the country. Development Scenarios: Grenada will require new capacity addition starting in 2013. For the Base Case Scenario, new additions are assumed to be 10-MW medium-speed diesel units using distillate oil. By 2028 the system will need another 70 MW (7 x 10 MW units) to cover projected load growth. For the Fuel Scenario, new unit additions are assumed to be 10-MW CFB units using imported coal. Conventional (large-scale) LNG is more costly than either the distillate or coal option. Although not studied in the same detail as the other fuel options, mid-scale LNG may provide an economically attractive option. By 2028 the system will need an additional 70 MW (7 x 10 MW units) to cover projected load growth. The Fuel Scenario results show that the introduction of coal provides NPV savings of US$32 million compared to the Base Case Scenario, although these savings do not take into account environmental costs. For the Interconnection/Renewables Scenario, most assumed new generation units are the same as in the Base Case. The difference in this scenario is the addition of 12 MW of new wind units. This assumes that sites with good winds and low development costs can be identified and acquired. The Interconnection/Renewables Scenario results show that the introduction of wind generation provides NPV savings of US$17 million compared to the Base Case Scenario. 88 The Comprehensive Integrated Scenario assumes that system additions are the same as in the Fuel Scenario, with the addition of new wind units as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario results show that including both coal as a fuel and wind generation provides combined savings of US$44 million over the Base Case Scenario, not including the environmental costs of coal. The Comprehensive Integrated Scenario results show savings close to the sum of the savings of other two scenarios. Discussion of Country Results: Adding coal-fueled CFB technology reduces NPV costs, not including environmental costs, by US$12 million compared to the Base Case Scenario, with a cost advantage compared to distillate-fueled MSD technology ranging from 2 percent at a 55 percent capacity factor to 12 percent at a 90 percent capacity factor. This cost advantage disappears if costs of US$50/ton are added for CO2 emissions. Conventional LNG is more costly than distillate, but mid-scale LNG may be a viable fuel option and merits a more detailed analysis. Development of wind generation reduces NPV costs by US$20 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. Small hydro and biomass would also be economical if good sites can be identified. The benefits are relatively unaffected by the choice of fuel for the country's fossil units. 89 6. Haiti27 Overview: Electricité d'Haïti (Electricity of Haiti, EDH) has the monopoly for electricity generation, transmission and distribution in Haiti. The EDH grid consists of ten isolated areas, of which the Metropolitan area, which includes Port-au-Prince, is by far the largest, with 80 percent of total demand. Only about 12 percent of the country's population is officially electrified (20 percent if unofficial connections are included). Generation, transmission and distribution facilities are old and need rehabilitation. Operational capacity of generating units is only about 155 MW. At times half of all demand is not served due to load shedding. Current and Forecast Load: The country's 2008 unconstrained peak demand was estimated at 215 MW, but due to load shedding net generation was only around 600 GWh. With the assumption that the economic conditions will improve and generation resources will, over time, catch up with demand, by 2028 unconstrained peak demand is projected to increase to around 570 MW with net generation increasing to around 2,800 GWh (an increase rate of 5 percent per year for peak demand and 7.9 percent for energy generation). Fossil Fuel Options: LNG and imported coal are considered as alternative fuels. The analysis finds LNG to be the economically preferred fuel option. Renewable Generation Potential: Wind and hydropower are the most promising renewable resources for Haiti. A study of wind at three sites was conducted with good results. Haiti has untapped resources of at least 50 MW in small hydro projects. Solar PV potential is estimated at 1,654 MW of installed capacity, though its development was not considered in this study. The biomass resource must be assessed cautiously, taking into account deforestation and land use issues. Development Scenarios: Haiti's power system was already short of generation resources in 2009. Nexant calculated that the already committed resources and an additional 80 MW of LSD units (4 x 20 MW) would need to have been built during 2009 just to meet the existing demand. For the Base Case Scenario, new unit additions are assumed to be 20-MW LSD units using distillate oil. Starting in 2010 the system needs another 20 MW (in some years 40 MW) in new units each year to cover projected load growth. By 2028 the system will need to install a total of 540 MW of new units. The Fuel Scenario assumes that system additions are the same as for the Base Case Scenario. The difference is that in this scenario all new units use natural gas as a fuel. Natural gas would be supplied starting in 2014 from a new LNG terminal. The Fuel Scenario results show that the introduction of LNG provides NPV savings of US$433 million compared to the Base Scenario. Although not studied in the same detail as the other fuel options, mid-scale LNG may also provide an economically attractive option. The Interconnection/Renewables Scenario assumes that generation is the same as in the Base Case Scenario, but includes the addition of 81 MW of new wind generation. This assumes that 27 The analysis does not take into account the impact of the January 2010 earthquake. 90 sites with good winds and low development costs can be identified and acquired. There is no electrical interconnection. The Interconnection/Renewables Scenario results show that the introduction of wind generation provides NPV savings of US$76 million compared to the Base Case Scenario. The Comprehensive Integrated Scenario assumes that system additions are the same as in the Fuel Scenario, with the addition of new wind units as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario results show that including both LNG as a fuel and wind generation provides combined savings of US$476 million over the Base Case Scenario. The results show that 55 percent of the wind savings in the Interconnection/Renewables Scenario appear in the Comprehensive Integrated Scenario. The results of the separate analysis, which studied only interconnection and exports from the Dominican Republic to Haiti, show, on a NPV basis, that system costs in the Dominican Republic increase by US$322 million when HFO fuels the exported generation. System costs in Haiti decrease by US$556 million. The total savings are thus US$235 million. This compares with the NPV costs of building and operating the transmission line calculated at US$242 million. The total cost increases outweighed the potential benefits, and therefore a transmission interconnection is not included in the Interconnection/Renewables Scenario or the Comprehensive Integrated Scenario. If natural gas-fueled generation provides the exported generation, the interconnection becomes economically attractive in this analysis. Furthermore, there are other considerations that should be taken into account when considering an interconnection, such as the access to emergency energy support or the possibility or reducing reserve margins. Discussion of Country Results: The poor condition and inadequate amount of generation in Haiti make all near-term additions highly cost effective until an adequate reserve margin is established. LNG is much less costly than distillate, leading to estimated savings of US$433 million. Coal, which is more expensive than LNG, is also an option, but it becomes significantly less economical when costs of US$50/ton are added for CO2 emissions. Development of wind generation in the Interconnection/Renewables Scenario reduces NPV costs by US$76 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. In the Comprehensive Integrated Scenario, because lower-cost LNG displaces distillate, wind is less attractive but still economical. Small hydro would also be economical, and biomass would be marginally economical if good sites can be identified. The viability of the land-based interconnection with the Dominican Republic depends on the fuel source for the DR's generation. Because of its length, the terrain, and the relatively low amount of power transmitted, the interconnection itself is costly despite being on land, and is most viable with low-cost generation such as natural gas. 91 7. Jamaica Overview: Jamaica Public Service (JPS) is the sole distributor of electricity in Jamaica. It is a vertically integrated company involved with generation, transmission and distribution of electricity. It also buys power from four independent power producers in Jamaica. The government has reorganized the energy department under the Ministry of Energy and Mining (MEM). It sets energy policy and has recently issued a draft of the new energy policy. The main focus is on developing energy diversity, since 95 percent of power is currently generated by petroleum products. The ministry has held extensive negotiations with major fuel users, gas suppliers and foreign partners to help develop a natural gas industry in Jamaica. Current and Forecast Load: The country's 2008 peak demand was 622 MW, with net generation of over 4,100 GWh. By 2028 peak demand is projected to increase to around 1,500 MW, with net generation increasing to around 10,000 GWh (an increase rate of 4.3 percent per year). Fossil Fuel Options: Natural gas, delivered as LNG, and imported coal are considered as alternative fuel options. Renewable Generation Potential: Wind is the most promising renewable resource for Jamaica. Detailed engineering is under way to expand Wigdon Wind Farm by 18 MW. Jamaica has limited potential for small hydro and biomass development. The current resource plan includes the development of an estimated 20-MW municipal waste project in Kingston. Solar PV potential is estimated at 650 MW of installed capacity, though its development was not considered in this study. Development Scenarios: During the next three years, until 2014, Nexant assumes that the planned resources, including the Kingston, Hunts Bay, Windalco, Jamalco and Wigton units, will be built to cover the load growth. If these resources are built, Jamaica will require new capacity additions starting in 2015. For the Base Case Scenario, new additions are assumed to be 100-MW conventional coal units using imported coal. The results of the analysis show that by 2028 the system will need another 1,100 MW (11 x 100 MW units) to cover projected load growth. For the Fuel Scenario, starting in 2015 new additions are assumed to be 100-MW CC units using natural gas supplied from two new LNG terminals, one on the southern side of the island and one on the northern side. Natural gas will become available during 2014 and by that year about 450 MW in existing units are also assumed to be converted to use natural gas. Although not studied in the same detail as the other fuel options, mid-scale LNG may provide an economically attractive option. The results of the analysis show that by 2028 the system will need another 1,100 MW (11 x 100 MW units) to cover projected load growth. The Fuel Scenario results show that the introduction of LNG provides NPV savings of US$500 million compared to the Base Case Scenario. 92 The Interconnection/Renewables Scenario assumes that system unit additions are the same as for the Base Case Scenario. The difference is the addition of 219 MW of wind generation by 2028. This assumes that sites with good winds and low development costs can be identified and acquired. There is no electrical interconnection. The Interconnection/Renewables Scenario results show that the introduction of wind generation provides NPV savings of US$138 million compared to the Base Case Scenario. The Comprehensive Integrated Scenario assumes that system additions are the same as in the Fuel Scenario, with the addition of new wind units as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario results show that including both LNG as a fuel and wind generation provides combined savings of US$628 million over the Base Case Scenario. The Comprehensive Integrated Scenario results show savings close to the sum of the savings of other two scenarios. Discussion of Country Results: The Base Case Scenario assumes that the infrastructure to deliver and generate with coal will be put in place. If this does not occur, the other scenarios' benefits would be much larger. LNG has the advantage that in the Fuel Scenario it can displace HFO in existing plants as well as the new coal generation added in the Base Case Scenario. Replacing new coal generation in the Base Case Scenario with LNG in the Fuel Scenario, and displacing HFO use in existing plants, leads to savings of US$500 million. Coal becomes even less economical when costs of US$50/ton are added for CO2 emissions. Development of wind generation in the Interconnection/Renewables Scenario reduces NPV costs by US$138 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. Wind is economical, as would be small hydro if good sites can be identified. The benefits are relatively unaffected by the choice of fuel for the country's fossil units. 93 8. St. Kitts and Nevis Overview: St. Kitts and Nevis have distinct utility structures. The electricity service in St. Kitts is provided by a department of the St. Kitts Government. All generation is by low- and medium- speed diesel units. A plan is under way to convert some of the units to HFO. The Nevis Electricity Co. Ltd. is a stand-alone government entity that supplies power to Nevis. All of Nevis's generation is also by low- and medium-speed diesel units. Current and Forecast Load: Current peak demand for both islands is less than 40 MW, with net generation of around 200 GWh. By 2028 peak demand is projected to increase to 85 MW, with net generation increasing to around 430 GWh (an increase rate of 3.6 percent per year, with rates of 2.9 percent per year for St. Kitts and 5.2 percent per year for Nevis). Fossil Fuel Options: Imported coal is considered as an alternative fuel. Due to the location and electricity demand on the island, the study does not find natural gas to be an economically viable fuel option. Renewable Generation Potential: Nevis has significant geothermal resources estimated to support the development of 300 MW of geothermal power plants. Production drilling for a 10 MW plant is scheduled to begin in January 2011. A 30-MW plant on Nevis to serve demand on St. Kitts is in late stages of planning. The islands also have the potential to develop small 4- to 5- MW wind farms. Solar PV potential is estimated at 16 MW of installed capacity, though its development was not considered in this study. Development Scenarios: Starting in 2012, St. Kitts will require new capacity additions. For the Base Case Scenario, new additions are assumed to be 5-MW medium-speed diesel units using distillate oil. By 2028 the system will need another 35 MW (7 x 5 MW units) to cover projected load growth. Starting in 2011, Nevis will require new capacity additions. For the Base Case Scenario, new additions are assumed to be 5-MW MSD units using distillate oil. By 2028 the system will need another 25 MW (5 x 5 MW units) to cover projected load growth. Neither St. Kitts nor Nevis has an alternative, potentially less expensive fossil fuel option to be used for the Fuel Scenario. The Interconnection/Renewables Scenario assumes that Nevis will be interconnected with St. Kitts by 2011 and the two 20-MW geothermal units on Nevis will supply 30 MW for St. Kitts and 10 MW for Nevis. No new generation units will be built on St. Kitts. This scenario also assumes that two 200-MW geothermal units will be built on Nevis in 2014 to supply Puerto Rico. A submarine cable connecting Nevis and Puerto Rico is also assumed to be completed by 2014. The St. Kitts results show NPV savings of US$159 million compared to the Base Case Scenario, as the result of interconnection and geothermal development on Nevis. These savings are much higher than the increased costs of US$100 million on Nevis associated with serving the St. Kitts load. Interconnection of St. Kitts and Nevis and geothermal development of Nevis to serve both islands is clearly a cost-effective option. Furthermore, large potential benefits of over 94 US$1 billion are the result of additional geothermal development, interconnection and exports of energy to Puerto Rico. The Comprehensive Integrated Scenario assumes the same interconnection with Nevis by 2011 and no new generation units built on St. Kitts, as in the Interconnection/Renewables Scenario. Discussion of Country Results: Because their low demand means that no fossil fuel options appear economical compared to distillate, geothermal development on Nevis is particularly important for St. Kitts and Nevis. It seems highly probable that a geothermal resource of at least 40 MW will be developed, based on the exploratory well and signed contracts. This would insulate the country from the high price of distillate and from the uncertainty associated with variation in that price over time. It would also reduce CO2 emissions. Considering the low cost of geothermal power, wind generation is only marginally economical compared to geothermal for domestic consumption on St. Kitts and Nevis. Small hydro would also be marginally economical if good sites can be identified, but biomass would be marginally uneconomical. Development of a resource sufficient to serve exports to Puerto Rico is less certain, but West Indies Power indicates that exploration data support at least 300 MW. The very large benefits associated with the development of 400 MW for export to Puerto Rico are based on the exports displacing HFO in Puerto Rico, which seem reasonable since HFO is the main fuel used today. 95 9. St. Lucia Overview: St. Lucia Electricity Services Ltd. (LUCELEC) is responsible for power generation, transmission and distribution of electricity on St. Lucia. Existing installed generation of around 75 MW, composed of diesel units, exceeds peak demand and provides a comfortable reserve margin. LUCELEC is looking to diversify its fuel mix, which is mostly dependent on imported oil products. The utility has adequate tariffs, reasonable regulation and a strong financial position. Current and Forecast Load: The country's 2008 peak demand was 54 MW, with net generation of over 350 GWh. By 2028, peak demand is projected to increase to around 115 MW, with net generation increasing to around 650 GWh (an increase rate of 3.2 percent). Fossil Fuel Options: Natural gas, delivered as LNG or through the ECGP, and imported coal are considered as alternative fuel options. Due to the location and electricity demand on the island, natural gas delivered through the ECGP is found to be the most economical fuel option. Renewable Generation Potential: Wind is the most promising renewable resource for St. Lucia. LUCELEC is pursuing a wind farm on land it already owns and is starting measurement on several other promising sites. St. Lucia also has rooftop solar PV installations at many locations. Solar PV potential is estimated at 36 MW of installed capacity, though its development was not considered in this study. There was significant geothermal exploration in the 1970s and 1980s, but the wells did not produce much steam. There appears to be some geothermal potential, but for a long time the rights to the resource were, and may still be, tied up with a developer. Development Scenarios: Starting in 2010, St. Lucia will require new capacity additions. For the Base Case Scenario, new additions are assumed to be 20-MW LSD units using distillate oil. By 2028 the system will need another 80 MW (4 x 20 MW units) to meet the required capacity. The Fuel Scenario assumes that system additions are the same as for the Base Case Scenario. The difference is that in this scenario most existing and all new units will use natural gas as a fuel. Natural gas will be supplied through the ECGP. Fuel Scenario results show that the introduction of ECGP gas provides NPV savings of US$216 million compared to the Base Case Scenario. The Interconnection/Renewables Scenario assumes that system additions are the same as for the Base Case Scenario. The difference is the assumed addition by 2028 of 18 MW of wind generation. This assumes that sites with good winds and low development costs can be identified and acquired. There is no electrical interconnection. The Interconnection/Renewables Scenario results show that the introduction of wind generation provides NPV savings of US$18 million compared to the Base Case Scenario. The Comprehensive Integrated Scenario assumes that system additions are the same as in the Fuel Scenario, with the addition of new wind units as in the Interconnection/Renewables 96 Scenario. Similar to the Barbados results, the Comprehensive Integrated Scenario NPV savings of US$221 million are only US$5 million higher than the Fuel Scenario, showing that savings from wind generation are much smaller when the assumed displaced fuel is low-cost gas rather than high-cost distillate. Discussion of Country Results: St. Lucia has two fossil fuel options that offer economic benefits, not taking into account environmental costs, compared to continued reliance on oil products: natural gas through the ECGP and coal. By far the more attractive is the ECGP option, which in the Fuel Scenario provides NPV savings of US$216 million compared to the Base Case Scenario. Its cost per kWh compared to distillate-fueled generation ranges from less than half at a 20 percent capacity factor to less than 40 percent at an 80 percent capacity factor. ECGP gas could displace distillate in existing units and could fuel new units. Development of wind generation reduces Interconnection/Renewables Scenario NPV costs by US$18 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. However, when ECGP gas is available, as is assumed in the Comprehensive Integrated Scenario, adding wind generation increases savings by only US$5 million. Wind is marginally economical, as would be small hydro if good sites can be identified, but biomass would be marginally uneconomical. This illustrates the high dependence of wind generation savings on the assumed fuel supply option, and the possibility that the penetration of wind generation might be limited to only a few of the best wind sites. 97 10. St. Vincent and the Grenadines Overview: St. Vincent Electricity Service Ltd. (Vinlec) is a state-owned corporation responsible for power generation, transmission and distribution of electricity on the islands. Existing installed generation of around 58 MW, mostly comprising low- and medium-speed diesel and small hydro units, exceeds peak demand and provides a comfortable reserve margin. The St. Vincent Government's goal is to provide 20 percent of electricity from renewable resources. Canouan Island has generating capacity of 2.5 MW and remaining islands have much smaller generating capacity. Current and Forecast Load: The country's 2008 peak demand was around 25 MW, with net generation of around 150 GWh. By 2028 peak demand is projected to increase to around 95 MW, with net generation increasing to around 550 GWh (an increase rate of 6.9 percent per year). Fossil Fuel Options: Imported coal is considered as an alternative fuel. Due to the location and electricity demand on the island, the study does not find natural gas to be an economically viable fuel option. Renewable Generation Potential: Wind and expansion of small hydro are the most promising renewable resources. The country announced its first 2-MW wind farm development for Canouan Island. There appears to be some geothermal potential, but the rights to the resource are tied up with a developer. Solar PV potential is estimated at 23 MW of installed capacity, though its development was not considered in this study. Development Scenarios: St. Vincent and Grenadines will require new capacity additions starting in 2017. For the Base Case Scenario, new additions are assumed to be 10-MW medium-speed diesel units using distillate oil. By 2028 the system will need another 70 MW (7 x 10 MW units) to cover projected load growth. For the Fuel Scenario, coal-fueled CFB plants are marginally more economical than distillate- fueled MSD plants, but this does not take into account environmental costs. Although new unit additions are assumed to be 10-MW CFB units using imported coal, CO2 costs of US$50/ton would make the distillate-fueled units more economical than the coal-fueled units. Conventional (large-scale) LNG appears to be more costly than either the distillate or coal option. Although not studied in the same detail as the other fuel options, mid-scale LNG may provide an economically attractive option. By 2028 the system will need another 70 MW (7 x 10 MW units) to meet the required capacity. The Fuel Scenario results show that the introduction of coal provides NPV savings of US$18 million compared to the Base Case Scenario, not considering environmental costs. The Interconnection/Renewables Scenario assumes that system additions are the same as for the Base Case Scenario. The difference is the assumed addition of 14 MW of wind generation by 2028. This assumes that sites with good winds and low development costs can be identified and 98 acquired. The Interconnection/Renewables Scenario results show that the introduction of wind generation provides NPV savings of US$14 million compared to the Base Case Scenario. The Comprehensive Integrated Scenario assumes that system additions are the same as in the Fuel Scenario, with the addition of new wind units as in the Interconnection/Renewables Scenario. The Comprehensive Integrated Scenario results show that including both coal and wind generation provides combined savings of US$29 million over the Base Case Scenario, not considering environmental costs. The Comprehensive Integrated Scenario results show savings close to the sum of the savings of the other two scenarios. Discussion of Country Results: Adding coal-fueled CFB technology reduces NPV costs by US$12 million compared to the Base Case Scenario, not including environmental costs, with a cost advantage compared to distillate-fueled MSD technology ranging from 2 percent at a 55 percent capacity factor to 12 percent at a 90 percent capacity factor. That cost advantage disappears if costs of US$50/ton are added for CO2 emissions. Conventional LNG is more costly than distillate, but mid-scale LNG might be a viable fuel option and deserves a more detailed analysis. Development of wind generation reduces NPV costs by US$20 million compared to the Base Case Scenario, assuming that sites with good winds and low development costs can be identified and acquired. Small hydro and biomass would also be economical if good sites can be identified. The benefits are relatively unaffected by the choice of fuel for the country's fossil units. 99 1112077