The Potential of Renewable Energy Resources for Electricity Generation in

Latin America

November 23, 2009

Alan Douglas Poole

Table of Contents

1. General Considerations..........................................................................................3Scope.........................................................................................................................................3Current contribution of renewables to electricity generation......................................................4Dealing with the variability of most renewable energy resources..............................................5

2. Hydroelectric Potential............................................................................................12Current hydro use and estimates of potential..........................................................................12Hydrological diversity in Latin America....................................................................................23Possible impacts of climate change.........................................................................................28

3. Wind Energy Potential.............................................................................................30Issues in defining the natural resource potential......................................................................32

Technology and potential................................................................................................................... 36The economics of wind energy................................................................................................38Observations on regional potential..........................................................................................43

4. Geothermal...............................................................................................................465. Biomass - sugarcane residues...............................................................................536. Solar Energy.............................................................................................................587. Renewable Potentials in the Context of Future Growth.......................................64References....................................................................................................................69Annexes........................................................................................................................74

Annex A: Comparison of Estimates of Hydropower Potential in Latin American Countries....74Annex B-: Wind farms in Latin America...................................................................................76Annex C: Wind Energy Potentials in Selected Countries.........................................................80Annex D: Observations on Possible Cooperation in Latin America.........................................96

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Glossary of Terms

GW Gigawatt: equal to 1,000,000 kilowatts (kW)kW Kilowatt: unit of power = 3600 kilojoules/hour (3600 kJ/h) or 3412 Btu/hkWe & kWth Kilowatt usually refers to electricity but sometimes the subscripts e and th used to distinguish electric

from thermal energy flowkWh Kilowatt-hour: unit of energy = 1 kW over 1 hour or 3600 kJMW Megawatt: equal to 1000 kilowatts (kW)TWh Terawatt-hour: equal to 1000 Gigawatt-hours (GWh) or 1,000,000 Megawatt-hours (MWh)

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1. General Considerations

Scope

This report summarizes and discusses current estimates of the potential for electricity generation from renewable energy resources in Latin America and the Caribbean islands. The focus is on electricity generation for the grid, not for off-grid rural or small isolated systems.

The report first considers hydro, geothermal and wind energy resources There are big differences in the state-of-the-art of these estimates.

Hydro has been developed for years and there are fairly detailed inventories of at least some of the resource potential in most countries.

Geothermal is also a resource whose use is well established in a few countries of the region. However, in general there has been relatively little exploration to dimension new reserves, even in some countries which have developed this resource to some extent.

Wind has become prominent much more recently and even now actual production is very small in the region. Inventories of the potential are incipient and often incomplete.

There are also big differences between countries in their presentation of estimates of these resources.

All three resources are very site specific. Levelized costs per kWh generated (based primarily on the cost per kW of capacity and the load factor) can vary enormously from site to site, as can the environmental impacts. Hence, estimates of theoretical potential which do not refer to cost (or other constraints) are of very limited practical value. Unfortunately, that is generally the way estimates of potential are presented, especially for wind, but usually for geothermal and even hydro.

This report also addresses the potential for electricity generation from solar energy and biomass, but in less detail at a country or subregional level.

A. Biomass has been used for electricity generation for decades, on a fairly small scale. Almost all of this electricity generation has been based on the use of residues, whether they be from agro-industrial processes, forest products or urban waste (solid and liquid). The potential to increase electricity generation from biomass is a function of:

Increasing flows of residues; Increasing the electricity output per ton of residue with new technology; In some cases increasing the share of residues being converted to electricity –

often in cogeneration schemes.The analysis of these three factors for a multiplicity of residues is quite complex. In most cases the potential for increasing the electricity generated would be quite modest. Considering the context and objectives of this report, as well as the limited time available, attention has been limited to electricity generation from sugarcane residues (principally bagasse). This is overwhelmingly the largest source of electricity from biomass in the region.

B. The conversion of solar energy to electricity is far more expensive today than any other renewable energy resource. At the same time, it is much less site specific than the other

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renewable resources, though there are large differences between sub-regions of Latin America in terms of the annual solar insolation, direct versus indirect radiation and the seasonal variability of solar energy. Thus, defining the potential for solar generation is predominantly a question of analyzing possible advances in solar conversion technology rather than an inventory of favorable areas and sites.

The main horizon of the analysis is around 2030. This horizon implies a pre-occupation not only with the ultimate economically viable potential (in any case a moving target) but with the possibilities of deployment over the next two decades. On the other hand, the basic information and analyses needed to form a clear picture of potential in the region are mostly lacking. This report will comment the quality of the information available, but it can be stated from the outset that improving access to reliable information on potential will be needed if there is to be any move to seriously increase the contribution of renewable to the generation mix.

Current contribution of renewables to electricity generation

The contribution of renewables to electricity generation today in Latin America is summarized in Table 1-1, together with estimated values for individual countries or sub-regions. The overall share is about 58%, or 59% if biomass is included.1

Table 1-1: Share of renewables in electricity generation in 2007

Country/sub-region Hydro Share Other Renewable a b TotalArgentina 27% 0.1% 27%Bolivia 41% 0% 41%Brazil 84% 0.5% 84%Caribbean (ex-Cuba)b 8% 0% 8%Central America 45% 9.3% 55%Chile 39% 0% 39%Colombia 79% 0.1% 79%Cuba 1% 0% 1%Ecuador 52% 0.1% 52%Guyanas 55% 0% 55%Mexico 12% 4.0% 16%Paraguay 100% 0% 100%Peru 67% 0% 67%Uruguay 86% 0% 86%Venezuela 73% 0% 73%Total LAC 57% 1.2% 58%

a “Other renewable” includes geothermal, wind and solar energy in the original OLADE database.b “Other renewable” excludes biomass since no information on generation by country is available. The overall contribution in the region is estimated to be 14-16 TWh or 1.2-1.4% of the total generation of the 1225 TWh. In Brazil the share of biomass would be over 2% and levels close to this might be found in Central America and Colombia.c The Caribbean does have some significant wind power, but it is on islands not included in the OLADE database. Source: Based on OLADE, 2008.

1 The table does not include values for biomass, since this fuel is not discriminated from fossil fuel generation in the original source. See the note to Table 1.1.

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This share of renewables is relatively high by world standards and as a consequence, Latin America has the lowest carbon emissions of any continental region in the world. The large contribution of renewables is due overwhelmingly to the high share of hydro.

While no systematic review of past trends has been made, it appears that the share of renewable has been stable or slighting declining in most countries of the region. The expansion plans for the power sector – typically for the coming decade – also show little change in the share of renewable in most countries.

Dealing with the variability of most renewable energy resources

The renewable energy resources, with the exception of geothermal, have energy flows which vary significantly over time. This variability is a pronounced characteristic of hydro, wind and solar resources. Biomass supply – especially that of sugarcane residues - is also subject to variations, but given the fact that biomass is a fuel, the link to power output is less direct.

The issue of the variability of supply has several distinct facets. One set concerns changes in the average output over different intervals of time, as for example:

the average output in different seasons; the change in output in short intervals, like minutes, hours or days.

To these one adds factors which affect the uncertainty of the supply of the resource: The profile of the extent of deviations from the average behavior. The ability to forecast future levels of output with horizons of minutes, hours, days or

months of anticipation.

As an illustration, Table 1-2 below briefly compares the variability and uncertainty of hydro and wind natural power flows, over the different time horizons which are important for power sector planning and operations.

Table 1-2: Variability and uncertainty of natural energy flows of hydro and wind power over different time scales at the plant (or “wind farm”) level

Time scale Hydro WindVariability Uncertainty Variability Uncertainty

Load regulation Seconds to minutes

Almost none Vanishingly small. Significant oscillations at turbine level, smaller at “farm” level

Relatively small uncertainty, forecasting techniques are improving

Load following 10s of minutes to hours

Very small variations Vanishingly small. Significant oscillations hour to hour

Relatively small uncertainty, forecasting techniques are improving

Plant scheduling & Unit Commitment 1 day or more

Very small except around floods

Very small. Significant oscillations day to day

Medium uncertainty, forecasting techniques are improving

Seasonal 1-4 months

Often large variation in average seasonal flow. Sometimes very large.

Often large (±) deviations around average seasonal variation. With >1 month large uncertainty.

Usually large/very large variation in average seasonal flow.

Considerable uncertainty. Need research on deviation around average and compare with hydro.

Annual/Multi year

Large variations in annual flows.

Great uncertainty Annual variation is probably smaller than hydro. Little research.

Probably less than hydro.

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The shorter time scales refer to categories used for the operation of the grid and the dispatch of generating plants making up the system. These categories are illustrated in Figure 1-1.

Figure 1-1: Time scales for grid operationsSource: EERE/USDOE, 2008

The variability of short term output has always been an obvious challenge facing the growth of wind and solar energy. It has often been considered a key obstacle to the successful introduction of large scale generation for the grid.

However, in considering the implications of this variability, it is well to remember that the load created by consumers is also constantly changing. To understand the impact of, say, a given capacity of wind energy on the dispatch of the remaining capacity on the grid, one should subtract the electricity generated by the wind from the load curve, as illustrated in Figure 1-2.

Figure 1-2: Hourly load shapes with and without wind generation

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Source: EERE/USDOE, 2008

From the changes in the load, one can calculate the “ramping” (up or down) required to follow the load. Figure 1-3 illustrates the impact of wind generation on a generic North American distributor/operator of the grid, showing the profile of hourly capacity changes in MW required with and without the wind capacity. This ramping rate is a key factor in determining the reserve requirements of the grid’s system and the costs of incorporating a variable source like wind.

Figure 1-3: Impact on ramping requirements over 10 minute intervalsSource: Smith, 2009

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Positive correlation of changes in wind output with those of consumer load can reduce net ramping with wind, at least on average. What one should look out for in this type of analysis is "heavy tailed" net ramping distributions which are highlighted in the figure. Strictly speaking, these should be analyzed in a LOLP-framework (that, is, when a large plant generating plant has an unexpected forced outage). If wind increases the risk that we may have higher ramping needs, then the next question becomes how large are our short-term wind and demand forecasting errors and how are the errors correlated.

Improvements in forecasting 3-24 hours ahead can reduce net ramping requirements, especially the unforeseen component, which is especially critical.

A big difference between hydro and wind or solar capacity is that hydro generation is often associated with storage capacity in reservoirs. The existence of reservoir capacity can “smooth out” river flows and guarantee a “firm” hydro supply (constant supply throughout the year of at least a given level of kW) which can be substantially higher than the output equivalent to the lowest river flow. There is no equivalent on-site storage capacity associated with wind. Indeed, these hydro reservoirs are the closest equivalent that the electricity supply system has to storing electricity today at anything like economically viable costs. Hydro capacity can be ramped up very quickly up or down, like the expensive “spinning reserve” in thermal systems. This makes hydro a good technology for regulation and load following.

While over shorter time scales, wind and solar energy flows are more variable and uncertain than hydro’s, over longer time scales (seasonal and annual) the variability of wind may well be smaller than hydro’s. The author has seen no published multiyear analysis comparing the annual variability of hydro and wind, but apparently the Brazilian energy planning agency EPE has found that there is less annual variation in wind than in hydro output in that country. There are hints in this direction from various data series. Consider, for example, Figures 1-4A and 1-4B which show monthly curves of hydro and wind output over a series of years in Costa Rica.

Figure 1-4A: Monthly hydro output in Costa Rica (1965-2002)

Source: ICE, 2007

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Figure 1-4B: Monthly plant capacity factors of wind farms in Costa Rica

Source: ICE, 2007

The seasonal and annual dispersion certainly seems greater for hydro than for wind, though the number of years in the time series for hydro is considerably longer. The issue of the variability of wind output over longer time periods (months and years) needs more attention, as do comparisons with hydropower over these timeframes.

The big challenge traditionally facing hydro has been the variation of seasonal and annual flows: both the averages and especially the deviations – flood years and drought years. Storage has been one approach to mitigate the impact of this variability on the “firm” supply of power. Another important approach has to exploit the hydrological diversity of different river basins by interconnecting them. This strategy, called “hydrological complementation” has long been a key element of hydropower planning in some countries. When flow is seasonally low in one basin it may be high in another; or a wet year in one basin may compensate for a dry year in another.

The same logic of complementation applies to wind. Much analysis has shown that increasing the catchment area smooths out short term fluctuations in output and reduces the range from minimum to maximum output. Figure 1-5 shows a European example of the effect of expanding the catchment area on the load duration curve of the wind capacity.

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Figure 1-5: Load duration curves: single wind farm vs. Nordic average

Most attention has been given to the impact of a larger catchment area on shorter term variability and the corresponding need for regulatory and load following reserve capacity. The question of the cost of this reserve has been a priority in the process of accommodating an increasing role of wind energy in the generation mix.

However, linking large catchment areas in complementation may also open opportunities for reducing the usually large seasonal variations in wind power generation, in a way more comparable with hydro complementation strategies. Indeed, one of the most promising forms of complementation may be between hydro and wind. That means that when wind is higher hydro may be lower and vice versa. One sees tantalizing examples of this in places as distinct as Argentina, Brazil, Colombia, Canada and Costa Rica (see Figures 1-4A & 1-4B above). This is a possibility that needs systematic evaluation.2

Complementation is a transmission-intensive strategy which could involve integrating quite distant regions with backbones of bulk transmission. Hydro has pushed in this direction already - experience in Brazil and in Central America are examples. Continued development of hydro will tend to reinforce this, as would the new development of wind energy on a significant scale.

Proposals to dramatically increase wind energy production in the USA point to a new infrastructure of bulk transmission, serving as a kind of continental interstate and tying together regions as never done before.

2 Analyses of expanding catchment areas usually stop short at areas too small to capture the full possibilities of complementation. One reason is that the analysts, in order to be accepted as practical, tend to accept the basic restrictions of the existing transmission system.

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In Latin America, where hydro will play a larger role than it ever did in North America, this could also happen over the next 20 years, even before wind becomes large. Again, Brazil is already well down this road, as will be discussed in the next section. Such a Latin American bulk transport system could indeed help pave the way for wind. Unfortunately, a move in this direction would confront the historic near autarchy of most national electrical grid systems. Excluding the bi-national plants of Brazil and Argentina with Paraguay – Itaipú and Yaciretá- trade of energy between countries is still minute. Even in Central America, where there was much infrastructure and institution-building towards this end, trade decreased from the mid-1980s.

There is something of a natural fit between hydro and wind, which is why it is important to evaluate these resources together – something which is not normally done. This is especially the case in Latin America, since overall there is still large hydro potential to be developed. In the next two sections on hydro and wind we will return to the issue of variability and how to deal with it.

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2. Hydroelectric Potential

Current hydro use and estimates of potential

Hydropower produces almost 57% of the total electricity generated in the overall region of Latin America (including the Caribbean). This is by far the largest share of supply by hydropower in any major region of the world.

Of course, the share of hydro varies sharply from country to country and between sub-regions, as shown in Table 2-1. For example, on the Caribbean islands generally (including Cuba) the contribution of hydro is quite small. At the other extreme, essentially 100% of Paraguay’s generation for the grid is hydro. Almost all of this power was generated by the bi-national plant Itaipú and most of this was exported to Brazil. Because of these massive imports, the effective share of hydro in Brazil’s matrix is even higher than the 84% output shown in the table.

Table 2-1: Sources of generation in 2007, by country (TWh)Source: OLADE, 2008

Country Hydro Thermal b Others a Nuclear Total % HydroArgentina 31,1 76,9 0,1 7,2 115,2 27,0%Barbados 0,0 1,0 0,0 0,0 1,0 0,0%Bolivia 2,3 3,4 0,0 0,0 5,7 40,5%Brazil c 374,4 58,8 2,1 12,3 447,6 83,7%Chile 22,8 35,7 0,0 0,0 58,5 39,0%Colombia 43,0 11,5 0,1 0,0 54,6 78,9%Costa Rica 6,8 0,7 1,6 0,0 9,1 74,5%Cuba 0,1 17,5 0,0 0,0 17,6 0,7%Ecuador 9,0 8,3 0,0 0,0 17,3 52,1%El Salvador 1,7 2,7 1,4 0,0 5,8 29,9%Grenada 0,0 0,2 0,0 0,0 0,2 0,0%Guatemala 3,0 5,5 0,3 0,0 8,7 34,5%Guyana 0,0 0,9 0,0 0,0 0,9 0,0%Haiti 0,5 0,1 0,0 0,0 0,6 84,2%Honduras 2,3 3,8 0,2 0,0 6,3 36,5%Jamaica 0,2 7,3 0,0 0,0 7,5 2,3%Mexico 27,0 185,8 9,3 10,4 232,5 11,6%Nicaragua 0,3 2,7 0,2 0,0 3,2 9,7%Panama 3,9 2,6 0,0 0,0 6,5 59,8%Paraguay 53,7 0,0 0,0 0,0 53,7 100,0%Peru 20,0 9,9 0,0 0,0 29,9 66,9%Rep Dominicana 1,7 13,2 0,0 0,0 14,8 11,3%Surinam 1,4 0,3 0,0 0,0 1,6 84,0%Trinidad & Tobago 0,1 6,8 0,0 0,0 6,9 1,4%Uruguay 8,1 1,4 0,0 0,0 9,4 85,6%Venezuela 80,8 29,3 0,0 0,0 110,1 73,4%Total 694,2 486,0 15,2 30,0 1225,3 56,7%SubregionsCentral America 18,0 17,9 3,7 0,0 39,6 45,4%Caribbean ex-Cuba 2,4 28,5 0,0 0,0 30,9 7,9%

a “Others” includes geothermal, wind and solar. b Thermal includes biomass-fueled thermal plants.c Brazilian hydro output does not include imports of about 38 TWh from the bi-national Itaipú plant.

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Not only does hydropower provide a large share of Latin America’s electricity today, the remaining potential which can be developed in the region is large. The question is how large.

In this paper the focus is on conventional hydro. Hydrokinetic resources (including wave energy and tidal energy) are not included. It is expected that their overall contribution within the report’s timeframe of 20-25 years would be small, though there may be interesting specific opportunities.

As with other energy resources, there are several progressively more restrictive definitions of hydropower potential. The broadest category is the gross hydropower potential, which is defined as the annual energy that would be potentially available if all natural runoff at all locations were to be harnessed down to sea level (or to the border line of a country) without any energy losses.

The share of this highly theoretical potential which has been or could be developed under current technology, regardless of economic and other restrictions, forms the technical hydropower potential. From this, the economic hydropower potential is the portion, which can or has been developed at costs competitive with other energy sources. Finally, the exploitable hydropower potential takes into account environmental or other special restrictions.

As with other energy forms, the cost of preparing credible estimates increases as one goes from the broader to the more restrictive definitions of potential (e.g. from “theoretical resources” to “exploitable reserves”). Not surprisingly, the best (i.e. most precise and restrictive) estimates of potential are available in regions which have developed a larger share of their potential – which also happen to be the richer countries. This is unfortunate, since, from the perspective of energy strategy the regions which are of most interest are those whose potential has been less developed.

Although hydropower is a mature energy technology, there are large differences between estimates of potential, even at the level of gross theoretical and technical potential for the world. Consider the two estimates of world potential in Table 2-2.

Table 2-2: Examples of global estimates of hydropower potential (TWh/year)

Category of Potential Eurelectric, 1997 Hydropower & Dams Atlas, 2000 a

Gross potential 51,000 40,500Technical potential 14,300Economic potential 13,100 8,100 b

Exploitable potential 10,500 8,100 b

a Survey in the 1999 edition of the International Journal of Hydropower & Dams World Atlas & Industry Guide, as cited in IHA, 2000.b Although the Hydropower & Dams Atlas source refers to “Economic Potential”, it treats it as essentially equivalent “Exploitable Potential”

By way of comparison, current world hydropower production is approximately 3000 TWh per year – a value which should be subtracted from those shown above in order to estimate remaining potential.

The differences between published estimates can be even larger at the regional level. This is illustrated in Table 2-3, where the differences are especially marked for Africa and the former Soviet Union. Over a decade, the former increased (though information is especially precarious

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in this continent) while the region of the former Soviet Union experienced a huge drop in expected potential.

Table 2-3: Comparison of estimates of regional potential (TWh/year)

Region AIWP&D, 1989

BEurelectric, 1997

Technical Potential Economic PotentialAfrica 1,150 2,500North America (USA & Canada) 970 970Latin America 3,540 3,530Europe 1.070 869Former Soviet Union/CIS 3.830 1,094China 1.920 1,260Rest-of-Asia 2.410 2,677Australasia/Oceania 200 200World 15,090 13,100

Note that in column A the estimate is for “technical” potential while that in column B is supposedly for “economic” potential. This does not invalidate the comparison, since we are interested in perceived regional shares and overall movement of estimates. It makes the absolute increase in Africa even more impressive. Indeed, it is not clear just how different the criteria are. Note that the values for both Latin America and North America are precisely the same in both columns.

Another set of regional estimates is shown in Table 2-4. These are shown separately because the regional breakdown is different in Eurasia and in the Americas. This breakdown includes estimates for both the “technical” and the “exploitable” potential. The values for “technical” potential are roughly intermediate to those in columns A and B in Table 2-3 above. Note that the value for the Americas is very close to that shown in Table 2-3 (4325 TWh versus 4500 TWh). In all cases, the potential of Latin America is estimated to be substantially larger than that of North America (defined as only the USA & Canada).

Table 2-4: A regional breakdown of technical and exploitable potentials (TWh/year)

Region Technical Potential Exploitable Potential a

Africa 1,750 1,000Asia 6,800 3,600Europe (incl part of former USSR) 1,325 850 North & Central America 1,660 1,000 South America 2,665 1,600Americas 4,325 2,600World 14,300 8,100

Source: International Journal of Hydropower & Dams World Atlas & Industry Guide, 1999 as cited in IHA, 2000. a Although formally referred to as “economic” potential, in the text was treated more as an “exploitable” potential.

As one of the reports makes very clear (Eurelectric, 1997), the information available to make these estimates is fragmentary and often very preliminary.

The parameter used to describe the potential in these tables is the electricity generated per year (say, MWh or TWh) rather than capacity (kW or MW). Annual output rather than capacity is

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preferable as a parameter for general analysis of potential and is generally estimated first. The analysis to estimate capacity (kW) is more complex. Besides the energy in the natural river flows, the design capacity will depend heavily on the power system into which the new hydro plants will be inserted, storage capacity in the system, etc. The capacity factors of hydro plants vary widely and they can be “super-turbinized” years after they began operation. Nevertheless, the public and policy makers seem to be more familiar with kWs than MWhs. Analyses of potential in Latin America are often presented only in terms of capacity, as will be seen below.

Turning now to focus on Latin America, Table 2-5 shows estimates of the hydro potential in the countries of the region and compares it with the hydro capacity existing in 2007. It is based on the summary published by OLADE, a key source for regional energy statistics. Adjustments were made in the cases of Brazil and Argentina.

Table 2-5: Hydro Potential Compared with Hydro Generation in 2007, by CountrySource: OLADE, 2008 (except Argentina and Brazil – see notes to table)

Country Existing Hydro Total Potential Existing/PotentialCapacity Output Capacity Output Capacity Output

GW TWh GW TWh % %Argentina a 9,94 31,06 40,40 130,00 25% 24%Bolivia 0,49 2,32 1,38 4,81 35% 48%Brazil b 76,94 374,38 251,49 1.213,00 31% 31%Chile 5,37 22,80 25,16 26,56 21% 86%Colombia 8,53 43,02 96,00 420,48 9% 10%Costa Rica 1,41 6,77 6,41 28,08 22% 24%Cuba 0,04 0,12 0,65 1,30 6% 9%Ecuador 2,06 9,04 23,75 96,77 9% 9%El Salvador 0,47 1,74 2,17 9,48 22% 18%Guatemala 0,78 3,01 4,10 15,21 19% 20%Guyana 0 0 7,60 19,64 0% 0%Haiti 0,06 0,48 0,17 0,50 36% 97%Honduras 0,50 2,30 5,00 21,90 10% 11%Jamaica 0,02 0,17 0,02 0,11 90% 162%Mexico 11,34 27,04 53,00 232,14 21% 12%Nicaragua 0,10 0,31 1,77 7,74 6% 4%Panama 0,85 3,87 3,28 14,38 26% 27%Paraguay 8,13 53,71 12,52 54,82 65% 98%Peru 3,23 20,03 58,94 385,12 5% 5%Rep Dominicana 0,47 1,68 2,01 8,80 23% 19%Surinam 0,19 1,36 2,42 10,60 8% 13%Trinidad & Tobago 0 0 0 0 0 0Uruguay 1,54 8,07 1,82 7,95 85% 102%Venezuela 14,60 80,81 46,00 201,48 32% 40%Total 147 694 646 2.911 23% 24%SubregionsCentral America 4,1 18,0 22,7 96,8 18% 19%Caribbean ex-Cuba 0,6 2,4 2,2 9,4 25% 26%

a In OLADE, 2008, potential Argentine output was cited as being 354 TWh – which would imply a 100% capacity factor for the estimated potential capacity. In Devoto (no date), a source from the Argentine power sector regulator estimates the technical potential to be 40 GW and 130 TWhb Value for Brazilian potential output (in TWh) derived from the Balanço Energético Nacional for 2008. The value in OLADE, 2008 was 1490 TWh. Value for potential capacity (GW) from EPE, 2007 & 2007b.

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Taken at face value, Table 2-5 suggests that the remaining potential is more than 2200 TWh, or more than 3 times the output of existing hydro capacity in the region. This value is also as large, or larger, than all the electricity growth forecast for the region over the next 20-25 years (though of course there are huge differences between individual countries).

However, this series of estimates of potential published by OLADE has serious limitations as a guide for estimating the future contribution of hydro to system expansion. There are no explanations beyond the “headline values”. While it appears that the parameter is “total potential” (which includes capacity that has already been developed) and not “remaining potential”, this is not made clear. There are several countries in the table where the existing hydro capacity already exceeds or is close to 100% of potential (eg Uruguay). Is this due to very complete development of hydro resources in that country or to an incongruence of definitions – that is, may the country be reporting remaining potential instead of total potential?

In addition, in a few countries there are large “asymmetries” between estimates of potential capacity compared with estimates of output. Take the case of Chile. According to Table 2-5, only 21% of the total potential capacity (GW) has been developed, compared to 86% of the potential output (TWh). This implies that the remaining hydro resource would have a very low capacity factor (~2%), which is odd.

Beyond these possible mistakes or inconsistencies (examples have been signaled with red numbers in the table), there may be important differences between countries in the definition of what is “potential”. First, there is the minimum hydro plant size considered. In the case of Colombia it is 100 MW. In Brazil it is 30 MW. Some other countries set much lower limits.

A larger doubt surrounds the restrictiveness of the definition of potential; is it “technical”, “economic”, or “exploitable” potential? Overall, the OLADE values for the region approximate the estimates of “technical” potential shown in Tables 2-3 and 2-4 above (see Annex A, which also shows a comparative country by country breakdown). However, it is possible that in some countries the definition is considerably more restrictive than in others. Under a more restrictive definition (such as “exploitable” versus “technical”) a larger share of the nominal potential could really be developed.

Consider, for example, the hydro potential of Mexico. In Table 2.5 is estimated to be about 53 GW and 232 TWh. So far about 21% of the capacity (11 GW) and only 12% of the potential output (27 TWh) have been developed, while hydro supplies less than 12% of the country’s generation. Planned expansion is nevertheless quite modest over the coming decade: 8.4 GW and 19.8 TWh (SENER, 2008). At this rate, one wonders whether Mexico will ever attain even a modest 40% of the claimed potential, especially in terms of output (TWh). Interestingly, the technical potential cited in Annex A is substantially lower than that in Table 2.5 (160 versus 232 TWh)

By comparison, a larger share of Central America’s nominal potential (~23 GW and 97 TWh) seems likely to be eventually developed. A recent review by the World Bank with ESMAP estimates about 24 GW of “usable” capacity (WB/ESMAP, 2009). This is contrasted with gross potential in two countries:

Costa Rica – Gross potential is 25.5 GW. “Usable” is 6.6 GW, of which 2.8 GW are in National Parks and Indian Reserves

Guatemala – Gross potential is 10.9 GW. “Usable” is 5.8 GW. In the case of Panama the value published by OLADE (3.3 GW & 14 TWh) is broadly corrobated as an “exploitable” potential by a recent source from that country – with 3.7 GW

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divided between 1.5 GW in the process of licencing and 1.3 GW in the inventory which are open for development (ETESA, 2007).

Another point to be aware of is that the evaluation of the hydro resource is carried out at different levels of thoroughness and there may be big differences in how far different countries have advanced in the evaluation process.

The most precise and reliable estimates are from detailed engineering designs for construction and from feasibility and pre-feasibility studies. Proper “inventory” evaluation also is based on substantial information about geology, environmental conditions, etc derived from measurements at the site (the methodology varies from country to country).

Much less reliable are studies of preliminary identification and reconnaissance. These are based on secondary information with a minimum of field measurements beyond a few stations to obtain river flow data. These “identification” studies may be for individualized sites, or more rudimentarily without specification of sites.

Feasibility studies are quite expensive and even an evaluation at the “inventory” level represents a significant outlay and years of data collection and measurements for a larger river basin. Few, if any, countries in the region have fully inventoried all their river basins.

Consider the case of Brazil. It is important not only because it has about 40% of the region’s hydro potential and generates more than half the region’s hydropower today. There is also a more substantial literature available than for most countries. Table 2-6 summarizes the status of evaluation of the remaining hydro resources in Brazil, as well as in the Brazilian part of the basin of the Amazon River where a large share of the remaining potential is found.

Table 2-6: Levels of evaluation of the remaining hydro resource in Brazil in 2009(excludes plants under construction)

Level of Evaluation Brazil Of which, in Amazon Basin *MW Share MW Share

Reconnaissance: basin 26.539 16,6% 17.919 20,4%Reconnaissance: individual plant 31.592 19,8% 24.773 28,1%Inventory 61.136 38,2% 25.707 29,2%Feasibility 27.709 17,3% 11.988 13,6%Executive project (detailed design) 12.945 8,1% 7.643 8,7%Total remaining potential 159.921 100% 88.030 100%

Source: SIPOT, 2009 – Sistema de Informações do Potencial Hidrelétrico Brasileiro (Information System on Brazil’s Hydroelectric Potential, operated by Eletrobrás). The values shown here are somewhat different than those in the Plano Nacional de Energia – 2030 (EPE, 2007/2007b) which is the basic reference for Brazil in this section. In principle, the SIPOT values are more recent. The biggest difference is that the category “Reconnaissance: basin” was reduced by about 10,000 MW, contributing to most of the reduction in the estimated resource.* Includes the tributaries: Tapajós, Madeira, Xingú, Negro, Trombetas, Jarí and other smaller rivers.

A large amount of the remaining nominal potential has still only been evaluated in a relatively superficial way, especially in the Amazon basin.

Colombia and Peru, the countries with the second and third largest potential in the region, seem to be less advanced in the assessment of their resources, though there are differences in

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terminology which complicates comparisons. In Colombia, out of a remaining total of 87 GW (Colombia UPME, 2008):

In reconnaissance: 63 GW (72%) Prefeasibility study: 7 GW (8%) Feasibility study: 12 GW (14%) Detailed design: 5 GW (6%)

In Peru, out of a remaining potential of about 56 GW, only 35% (19.7 GW) appear to have been defined at the level of individual plants, as shown in the breakdown below (Peru MEM, 2008):

  MWPlants with concession granted 1299Plants under study (temporary concession) 5519Plants without concession 1141Potential for interconnection with Brazil or other countries 11,735Total           19,693

It is not surprising that these countries appear to have large amounts of relatively unstudied hydro potential. Colombia has developed only 9% of its potential, Peru only 5%. From a national planning perspective, why spend scarce resources on defining plants that may only be constructed decades hence?

The degree of evaluation achieved varies from country to country. The information so far available to the author on resource assessments which have been prepared is somewhat limited, but it can be said that not enough is known about a large partare of the potential in the region to judge whether it should or should not ever be built. Simply studying a site is far from being a guarantee that it will be viable, but it cannot possibly be viable without prior evaluation.

Thus there is great uncertainty about the size of the ultimately viable potential of hydro. However, it is clear that the remaining potential in the region which can ever realistically be developed will be significantly less than the nominal value shown in Table 2-5. Within the timeframe of 20-25 years the feasible limit is still less, although the predominant part of the remaining viable potential will probably be developed within this period.

The question is, “what share of the nominal potential might be achieved?” The best one can do now is propose a range of values based on some analogies and show the implications.

As an upper value, we take the hypothesis of Brazilian planners that 70% of the inventoried potential could be susceptible to development (though not necessarily by 2030). In the highly developed Paraná basin, this level of development has already almost been achieved and some other basins are also approaching this level.

International comparisons with more developed regions of the world are popular for justifying the choice of a future level of exploitation. Such comparisons are of limited value. First it takes a huge leap of faith to extrapolate results between regions with very different geography. Ambiguity is added by the precarious nature of many estimates and difficulties in assuring consistency, so that we are comparing like with like. For example, the fact that Western Europe

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has achieved 70% of its “economic” potential3 is hardly an argument that Latin America can achieve 70% of its “technical” potential.4

Returning to Brazil itself, achieving the development of 70% of the potential may be harder to achieve in the Amazon region than elsewhere in the country. Not only is there the complication that a large share of capacity will be within restricted areas such as national parks and indigenous reserves. Many potential sites are just not that good: heads are low, flooded areas are large relative to output (and would cover dense forest), extensive dikes may be required. As an illustration, consider the potential of the sub-basin of the Xingú river, a tributary of the Amazon (see Box). Given the large share of Brazil’s remaining potential which is in Amazonia, a significant shortfall in that basin would depress the national average.

Figure 2-1 shows an estimate of the cost per kW of the remaining potential in Brazil versus new capacity, with variations of ±10% in unit cost.

Figure 2-1: Estimate of the cost of remaining hydropower potential in Brazil(Baseline and ± 10% sensitivity)

Source: EPE, 2007bNote: Cost is in US$ of 2005. Interest during construction and the cost of connecting to the national grid are not included

3 The calculation of “economic” potential – about 580 TWh - is from Eurelectric,1997. In this case the value seems to be truly an estimate of “economic” and not “technical” potential. An example of a “technical” potential for Western Europe is 910 TWh (IWP&D, 1989).4 In the case of North America (USA & Canada only) – with a hydro output of 640 TWh in 2005 – 66% of the technical potential has been already been developed using Table 2-3 as a reference. However, more recent analyses in Canada (CHA, 2007) suggest that the technical potential in that country is rather larger than implied by the table, so that the regional total would increase to something on the order of 1100 TWh, with a correspondingly lower percentage level of development achieved until now.

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This figure suggests that, assuming a limit of $ 1800/kW on the baseline cost curve, about 77 GW could be built. According to the source this would be equivalent to about 31% of the total potential – raising the total developed to slightly over 60%. An $ 1800/kW limit is somewhat arbitrary, but beyond this capacity the curve shows fairly sharply rising costs. Also, environmental limits, such as those illustrated in the example of the Xingú, are not included.

The Xingú River and the Varying Quality of Potential Sites

The first large dam planned for the Xingú is Belo Monte. This will be a run-of-river project with a very small reservoir relative to its output of 11,233 MW. The dam lies near the Transamazon highway in an already settled region. This hydro plant has a certain elegance and will certainly be built.

However, the possibilities upstream are much less attractive. The table below summarizes some parameters of dams proposed in the inventory performed in the 1980s in preparation for a major building campaign which was then being planned (Poole, 2005). The upstream dams, between them, would have roughly the same capacity as Belo Monte, but inundate an area more than 30 times larger.

Characteristics of Planned Hydro Plants on the Xingú River

Hydro Plant Capacity Reservoir Area & Ratios UsefulVolume

Approx Head

(MW) (km2) (kW /ha) (109 m3) (m)Belo Monte (Kararaô) 11233 516 217,7 1.2 88Altamira (Babaquara) 5750 1 6140 9,4 97.0 68Ipixuna 1900 3270 5,8 22.4 43Kokraimoro 1490 1770 8,4 18.4 49Jarina 620 1900 3,3 12.4 24Iriri 770 4060 1,9 31.0 40Total Xingu River 22,082 17,656 12,5 182.4 xxxxTotal w/o Belo Monte 10,530 17,140 6,1 181,2 xxxxSources: Belo Monte from EPE, 2009b. Other plants upstream based on CNEC, 1980 and Eletrobrás, 1993. Except for Belo Monte these are all very preliminary estimates and are subject to change.1 Another value cited for Altamira/Babaquara is 6590 MW.

Although this set of estimates is relatively old, no new full inventory of the sub-basin appears to have been prepared. The current estimate of potential (22.7 GW) is close to that shown in the table. Unfortunately, though the National Energy Plan for 2030 (EPE, 2007b) has a volume dedicated to hydropower, there are no estimates of the inundated areas, either for individual plants or for scenarios of development of basins.

Times have changed since the mid-1980s. Power sector planners in Brazil today place less emphasis on building storage reservoirs than they did 30 years ago. The technology of and experience with low-head turbines has improved. New configurations for dams are thus likely to be closer to run-of-river. A larger number of smaller candidate sites might well be developed with smaller reservoirs.

Nevertheless, to go from half of the river’s hydro potential to 70% will clearly be a challenge, especially given the goal of reducing deforestation and the issues surrounding indigenous reserves. This may be an example of how the work of resource assessment is cumulative and can evolve due both to improved information about potential sites and to changing guidelines for planning system expansion.

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Figure 2-1 only includes the potential which has been inventoried. There is a sizeable amount of additional potential which has been subject only to preliminary reconnaissance which could add to the ultimately exploitable resource at a given ceiling in $/kW (“move the curve to the right” as it were). However, much of this potential may not be very attractive.

Given all the uncertainties in a relatively well studied country like Brazil and considering the even greater uncertainties at the level of Latin America as a whole, the use of a range of values is clearly indicated.

For illustrative purposes, this report assumes a minimum of 50% development of the potential in Table 2-5 and a maximum of 70% for Latin America as a whole. Appropriate ranges for individual countries will be different and are not discussed here. Within this range, the remaining potential would be:

50% development - 802 TWh 60% development - 1084 TWh 70% development - 1366 TWh

These values can be compared with hydro output in 2007, which was 646 TWh. This potential does not cover the category of small hydro in many of the countries, though definitions differ. The inclusion of small hydro is unlikely to increase the overall values by more than about 5%.5

It is important to distinguish between ultimate development and that which would be feasible in a 20-25 year period. Even the lowest scenario (50% of potential) would represent more than doubling pre-existing capacity which was built over a period of 50+ years. A factor to consider is that more than half of the potential outside of Brazil is in countries which today use 10% or less of their resource (Colombia, Ecuador, Peru and the Guyanas). The internal markets alone of these countries would be unable to absorb half of their potential within 20-25 years.

A climate change mitigation strategy seeking to minimize costs would seek to maximize the rate of development of viable hydro capacity as fast as possible at a regional level. An implication of this would be dramatically increased exchange and export of power, even before considering the benefits of linking together river basins with diverse hydrology – which will be discussed below.

The existing level of information regarding the characteristics of undeveloped hydro potential in Latin America is unsatisfactory. Various difficulties have been described in this section. It is strongly recommended that international entities interested in climate change mitigation support a systematic review of hydroelectric potentials in the region, taking into account environmental and social indicators as well as economic costs. This review should support the acquisition of new data in surveys, as well as bringing together existing resource assessments.

The development of hydroelectric power is the foundation for any energy strategy to reduce growth in greenhouse gases from electricity generation. It is crucial that policy makers have a clear idea of the real opportunities, costs and trade-offs for hydro development in the region.

Some economic and social criteria are summarized in the Box below. To these indicators should be added more information about the storage capabilities of proposed hydro plants (and of the existing systems). The energy storage capacity of hydro reservoirs has always been a crucial parameter for the design and operation of hydro systems. In the future it will be more 5 For example, in Brazil, small hydro (> 30 MW) technical potential was estimated to be about 17.5 GW (EPE, 2007), which can be compared with 252 GW in Table 2.5 (usually with a somewhat higher capacity factor).

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important yet. Dams with large useful storage play a much more important role in the operation of a hydro system than their generation capacity alone suggests, especially if they are at the top of a cascade of hydro plants (the classic example in Latin America is the Furnas hydro plant in Brazil, located at the top of a cascade of hydro plants).

Key Indicators of Likely Environmental ImpactsSource: Ledec

• Reservoir Surface Area (hectares): A large reservoir area implies much loss of natural habitats and wildlife, or displacement of many people, or both. Hectares (ha)/MW is a useful measure. Typically a good dam site would have <25 ha/MW and a bad site >50.

• Water Retention Time (days): Used to predict water quality problems; the shorter the better. • Biomass Flooded (tons/ha): Minimize flooding of forests to improve water quality, conserve

biodiversity, reduce greenhouse gas emissions. • Length of River Impounded (km): Minimize the length, for aquatic and riparian biodiversity.• Length of River Left Dry (km): Minimize for fish and other aquatic life below the dam, riparian

ecosystems, human water uses. • Downstream Tributaries (major, un-dammed) (#): The more, the better, for migratory fish, natural

flooding regime, and estuaries. • Inter-basin Transfers (#): One or more could spread invasive species and threaten aquatic

biodiversity.• Likelihood of Reservoir Stratification (Densimetric Froude Number, derived from reservoir length,

depth, flow, and volume): When >1, stratification and anaerobic conditions are avoided.• Useful Reservoir Life (years): Sustainability of power generation.• Access Roads through Forest (km): Minimize where deforestation risks are high.

Key indicators of impacts for which extra data are required.• Persons Requiring Resettlement (#): Diverse social impacts, disruption of livelihoods; also

environmental impacts of resettlement.• Critical Natural Habitats Affected (#, ha): Avoid or minimize damage to protected areas, other

sites of high conservation value.• Conservation Win-Win Opportunities (yes/no): Possible--when seriously promoted-- through

creation/strengthening of compensatory protected area(s), payment into a protected area fund, or environmental service payments to landholders.

• Migratory Fish Species (#): The more migratory species, the greater the potential disruption from the dam.

• Endemic Aquatic Species (#): Sites with lower endemism (species found nowhere else) have reduced conservation risks.

• Cultural Property Affected (# and type): Avoid or minimize flooding important archaeological, historical, paleontological, or sacred sites.

These indicators can be used to screen individual project proposals or to rank different project sites.

Despite the importance of storage, information about available reservoir storage capacity is very hard to come by, whether for existing or future plants. In looking at future project possibilities, reservoirs with useful storage tend to have more environmental difficulties than run-of-river plants of the same size (though obviously this depends hugely on the sites in question). If there is not a clear framework of information regarding the benefits of this storage capability there will be an asymmetric analysis of the costs and benefits of such plants.

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One point that emerges from this preliminary review is that, looking ahead to 2030, it will be probably be very difficult for Latin America to maintain its current ~60% renewable mix in generation without a substantial increase in the use of renewable resources besides hydro power, compared to current levels. This point will be discussed in Section 7, when we will return to look at the scenarios of hydro development in the context of a wider strategy to maintain or enhance renewables’ contribution to electricity generation in Latin America.

Hydrological diversity in Latin America

As observed earlier, hydropower is subject to variations in natural river flows. The fluctuations from dry to wet season or dry years to wet years can be large. One way to compensate for these variations is build storage reservoirs. However, adequate sites for storage reservoirs are limited.

Another approach is to exploit the diversity of the patterns of flow in different river basins. This strategy – called complementation – was introduced in general terms in Section 1, since it is relevant for most renewable resources.

Figures 2-2 and 2-3 show the big differences in the seasonality of natural flows of a selection of rivers in Latin America. These graphs also show how large the mean seasonal variation can be.

The regime of the Uruguay river is typical of Southern Brazil, Uruguay and parts of Argentina.

The Paraná River is typical of Brazil’s southeast and mid-west, where there is the greatest concentration of hydro plants in that country.

The Xingú River is an Eastern tributary of the Amazon. The Caroni River is a tributary of the Orinoco The Madeira is in the southwest of the Amazon basin and is fed by run-off from Bolivia

and Peru (including the Andes) as well as Brazil. The Magdalena River is in Colombia. Fortuna and Chixoy are important hydro plants in Panama and Guatemala respectively.

Map 2-1 shows the seasonality of river flows in South America in a more general manner. It shows the three months of maximum flow and the % of annual flow which occurs in these moths. In large areas of the Brazilian Amazon, Bolivia and Peru more than 60% of the run-off occurs in the 3 months of peak flow, as exemplified in Figure 2-2 by the Xingú River. Other regimes are less extreme, but still show a high concentration in the months of maximum flow (Madeira, Caroni, Chixoy, Paraná).

Another aspect of variability is the changes in average annual flows. The history of six of the rivers is illustrated in Figure 2-4. In most river basins fluctuations of ±25% are common, though in some ±50% is commonly reached (Uruguay River).

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Figure 2-2: Variation in average seasonal river flow (% long term mean flow)Sources: ONS, 2001; OLADE

Figure 2-3: Variations in average seasonal river flow (% long term mean flow)Sources: ONS, 2001; OLADE

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Map 2-1: Three month periods of maximum river flow and their share of annual runoff in South America

Source: Moreira & Poole, 1993

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Figure 2-4: Variations in annual river flow (% long term mean flow)Sources: ONS, 2001; OLADE

Linking basins with diverse hydrology can increase the “firm energy” which can be obtained from each. Brazil has long exploited the substantial diversity between rivers in the far south (such as the Uruguay) and the southeast/mid west (Paraná), as well as lesser differences in hydrology in the northeaster and Amazon regions. As a consequence, Brazil may have the most tightly integrated grid at a semi-continental scale in the world. Superimposed on a map of Europe, Brazil’s grid extends from Lisbon almost to Moscow (see Map 2-2).

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Map 2-2: Brazil’s electricity grid superimposed on a map of Europe

The existing interconnections between countries in Central America are also justifiable in part because of the significant diversity which exists within a relatively small area (compare the sites in Panama and Guatemala, for example).

Substantial opportunities exist to exploit hydrological diversity in Latin America. An interesting example is the proposed intertie between Colombia and Central America.

Perhaps the most important possibility arises from the fact that the Equator runs through South America. As one goes from the Northern Hemisphere to the Southern Hemisphere the seasonality of rains is inverted (just as summer and winter are at higher latitudes). As consequence the Xingú, the Paraná and the Madeira (Southern Hemisphere) peak in January-April, which is the dry season on the Caroni (Northern Hemisphere). The Northern Hemisphere tropical rivers tend to be high when the Southern Hemisphere equivalents are low.

As Brazil develops its potential in the Amazon, beginning with plants on the Madeira and the Xingú (Belo Monte) and new capacity is developed in the Andean countries, the possibilities for an “inter-hemispheric interconnection” become more realistic (Poole, 2005).

Interconnections linking the major complexes of hydro in basins throughout much of Latin America could be a major factor allowing for more rapid development of the most economic and

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environmentally sound hydro capacity. Besides smoothing seasonal output and providing greater security against droughts, increasing interconnection would greatly diminish the problem of the “lumpiness” of hydro capacity additions. It would also contribute to greater security of supply from the hydro system as the effects of climate change become manifest in the coming decades, as discussed below.

Possible impacts of climate change

Any evaluation of the possible impacts of climate change on renewable energy resources is necessarily very preliminary. In Latin America, analysis so far appears to be limited to the impact on hydropower via changes in precipitation patterns. An example, summarized in a recent World Bank report (ESMAP, 2009) is briefly discussed here.

A climate model called Earth Simulator was run in order to estimate the likelihood of extreme weather events to the end of the century. The Earth Simulator is a super-high resolution atmospheric general circulation model with a horizontal grid size of about 20 km. Given the very large computing power required at this resolution, a 60 km grid was also used for an “ensemble” of consistency checks.

Two extreme indices for precipitation were used to illustrate changes in precipitation extremes over South and Central America, one for heavy precipitation and one for dryness.

Map 2-3 shows the changes in maximum 5-day precipitation total (RX5D) for the 60-km and 20-km resolution. RX5D is projected to increase in the future over almost all of South and Central America.

Likewise, Map 2-4 shows the changes in maximum number of consecutive dry days (CDD). A "dry day" is defined as a day with precipitation less than 1 mm. CDD periods are projected to increase, in particular over the northern coast.

It is generally accepted that global warming will result not only in changes in mean conditions but also increases in the amplitude and frequency of extreme precipitation events. Changes in extremes will have an impact on the hydrology of rivers.

The preliminary analysis illustrated here suggests that for rivers in the Amazon basin there will be a greater concentration of rainfall in the wet season, as well as a lengthening of dry periods – especially in southeastern Brazil. This will increase the amplitude of stream flow variations, with an increase in stream flow during the high-flow season and a decrease in the low-flow season. This would in turn reduce the firm capacity of hydro plants with a given reservoir capacity.

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Map 2-3: Changes in maximum 5-day precipitation until end of 21st century (mm)For (a) 60-km and (b) 20-km resolution.

For 60-km model, areas with the highest projected consistency in sign are hatched. Zero lines are contoured. Source: ESMAP, 2009

Map 2-4: Changes in maximum number of consecutive dry days until end of 21st century (days)

For (a) 60-km and (b) 20-km resolution.

For 60-km model, areas with the highest projected consistency in sign are hatched. Zero lines are contoured. Source: ESMAP, 2009

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3. Wind Energy Potential

Compared with other regions of the world, the installed wind generation capacity in Latin America is the smallest in proportion to total generating capacity.

Total regional capacity has grown substantially since 2005, as shown in Table 3-1. The rate of growth was somewhat faster than that for the world, but the growth was from a very small base and all the new capacity was in very few countries – Brazil and Mexico, with smaller increments in Chile and Uruguay. Pioneers in Central America and the Caribbean have not so far continued their earlier expansion. One does not yet see a pattern of broadly based and steady regional expansion.

The table also shows that the “wind farms” - the equivalent of individual hydro or thermal plants - are also mostly quite small by international standards, with only a couple of exceptions.

Table 3-1: Wind power capacity since 2005

Country Capacity (MW) Largest plant(s)* MW2005 2006 2007 2008 (early 2008)

Argentina 26,8 27,8 29,8 29,8 17,7Brazil 28,6 236,9 247,1 338,5 150,0 & 62,0Costa Rica 71,0 74,0 74,0 74,0 19,8 (two)Chile 2,0 2,0 20,1 20,1 18,2Colombia 19,5 19,5 19,5 19,5 19,5Cuba 0,5 0,5 21,0 7,2 5,1Curaçao 12,0 12,0 12,0 12,0Ecuador 0,0 0,0 3,1 4,0 2,4Guadeloupe 20,5 20,5 20,5 20,5Guyana 13,5 13,5 13,5 13,5Jamaica 20,7 20,7 20,7 20,7Martinique 1,1 1,1 1,1 1,1Mexico 2,2 84,0 85,0 85,0 83,3Peru 0,7 0,7 0,7 0,7 0,5Uruguay 0,2 0,2 0,6 20,5Total 219,3 513,4 568,7 667,1Central America 71,0 74,0 74,0 74,0Caribbean (ex Cuba) 54,3 54,3 54,3 54,3Guyanas 13,5 13,5 13,5 13,5

* Plant = “ wind farm”. Existing wind farms in most countries of the table are shown in Annex B-1, with information on localization and turbine number and sizes.Source: WWEA, 2009; Latin American Wind Energy Association website

Projected increments in the existing medium term expansion plans are modest or very small in almost all countries. The main exceptions are: Costa Rica, with scheduled additions of 150 MW to 2014; Mexico, with at least 500 MW of new capacity planned by 2012 or soon after, and possibly as much as 2450 MW;6 and Brazil, which will hold an auction for new capacity in

6 Under the program “Temporada Abierta” (“Open Season”) some 2470 MW of new projects and accompanying transmission infrastructure have been agreed to in the region of the Isthmus of Tehuantepec in southern Mexican state of Oaxaca. Of these 507 MW are to be constructed by the Federal utility CFE, the rest of the capacity by private sector agents (SENER, 2009). The 507 MW are

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December, 2009 (see Box). These relatively ambitious initiatives may help change the outlook in the broader region.

Brazil’s Wind Energy Auction

Under Brazil’s energy policy model, new generating capacity is contracted through periodic auctions. An auction specifically for wind power has been scheduled for December, 2009 (MME-Brazil, 2009). The auction was designed to stimulate the wind power sector and the response has been impressive – 441 projects with 13,342 MW of capacity have been registered.

The winning projects will enter on-line in 2012 with contracts of 20 years. How much capacity will in fact be contracted is still uncertain. The amount will depend in part on the prices offered – estimates range from 1500 MW to almost 3000 MW. Even the lower value would be almost 3 times existing capacity.

From an international perspective, the most interesting aspect of the proposed contracts is that the wind power producer’s obligations are limited to achieving annual goals in MWh, indeed, quadrennial averages. There is no reference to guaranteeing capacity. There is no penalty if the shortfall in output is less than 10% over an initial four year period – generation in excess of the contracted level (up to 130%) will be paid at 70% of the contracted price per MWh. (EPE, 2009)

Based on experience in this period, new contractual levels will be established for the subsequent four year period and thereafter every 4 years over the life of the contract. Payments will be made in equal monthly installments, adjusted periodically based on experience. The stable and relatively predictable payment arrangements should facilitate project finance.

The focus on energy (MWh) instead of capacity (kW) is a consequence of Brazil’s predominantly hydro power system and the relatively large amounts of reservoir storage available. In Brazil’s power system the key challenge is to provide rated levels of firm energy even over multi-year “critical periods” of drought. Because of the strategy of complementation to exploit the possibilities of hydrological diversity between river basins, generating capacity to assure firm energy is larger than that needed to provide peak power. From the perspective of the Brazilian system, the crucial need for wind is to guarantee annual average generation in MWh.

In their preparations for the auction, the Brazilians have found that annual average output from wind varies less than does hydro output. This is an interesting addition to the evaluation of the characteristics of the variability of these two resources introduced earlier in this paper.

While this situation is unlikely to repeat itself in many countries, Brazil is a good example of how hydro and wind are a good pair. Hydro facilitates the entry of wind.

Projections of wind power in the expansion plans tend to be in terms of MW of capacity. This criterion flatters wind power since plants in good sites will typically have a load factor of 30- 40%, well below the regional average for most technologies, as shown in Table 3-2. At the same time, it is also worth noting that most thermal capacity also has a rather low capacity factor.

included in the official expansion plan (SENER, 2008), the rest does not yet appear there. A number of projects are also being contemplated in the northern state of Baja California for export of power to the United States.

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Table 3-2: Average load factors of different types of generation in Latin America - 2007

Technology → Hydro Thermal Geothermal Nuclear TotalCapacity Factor 53.9% 44.6% 86.6% 77.8% 50.2%

Source: OLADE, 2008

Emphasizing capacity (MW) instead of electricity generated (MWh) is also a conceptual distraction. Wind power is essentially about bringing MWh of generated energy to consumers over time, not about providing MW of peak demand capacity.

Issues in defining the natural resource potential

The evaluation of wind resources for electricity generation begins with the identification and delineation of areas where wind speeds are relatively high on average and reasonably constant.

A common mapping convention is the Battelle Wind Power classification. This ranks the potential of areas in seven categories, ranging from “Poor” to “Superb”. The values for each category vary with the height, since average wind speed tends to increase with height.

Table 3-3: Classes of wind potential by wind speed

Class Resource Power Density Wind speed (m/s)Potential At 50 m – W/m2 50 m height 65 m height 80 m height

3 Fair 300-400 6.4-7.0 6.6-7.3 6.8-7.54 Good 400-500 7.0-7.5 7.3-7.8 7.5-8.15 Excellent 500-600 7.5-8.0 7.8-8.3 8.1-8.66 Outstanding 600-800 8.0-8.8 8.3-9.1 8.6-9.47 Superb 800-1600 8.8-11.1 9.1-12.4 9.4-12.8

Wind speeds assume a Weibull k value of 2.0.

Wind is naturally variable, but in some areas winds are more variable than in others. The Weibull number is a coefficient used to describe the distribution of wind speeds. A narrower distribution (which implies a more constant wind regime) has a higher number, as shown in Figure 3-1.

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Figure 3-1: Effect of the Weibull number on distribution of wind speeds

The energy in the wind does not follow wind speed linearly, it varies with the cube of the wind speed. In addition, turbines produce no power at all below a “cut-in” speed, as shown in Figure 3-2.

Figure 3-2: Typical power output versus wind speed curveSource: EERE/USDOE, 2008

Output then rises sharply until the “rated wind speed” is achieved. This is the wind speed at which the turbine produces it’s nominally rated power. Above that wind speed power output is flat until the “cut-out” speed is reached at very high winds. At that point the turbine shuts down.

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Designers can modify these values to some extent, as illustrated by two versions of a 1.5 MW GE turbine:

Model → 1.5 sle 1.5 xleCut-in wind speed 3.5 m/s 3.5 m/sRated wind speed 14.0 m/s 12.5 m/sCut-out wind speed 25.0 m/s 20.0 m/s

A very rough initial idea of potentially promising areas can be obtained from conventional meteorological stations. This source of data provides reasonably good quality information about the variability of the resource. However, it is of limited value for estimating absolute values. The measurements are taken at a much lower height, which reduces the wind speed. Also, these stations tend not to be in the most promising places and the wind resource can vary substantially between relatively nearby sites due to the effects of topography.

There have been improvements in lower cost prospecting using mathematical modeling techniques for broader meso scale resource assessments. These assessments can identify the most promising areas and their probable resource category.

The best areas for wind resources are often quite limited in size. Consider the example of Brazil, one of the most thoroughly mapped countries in Latin America. Land areas with different average wind speeds are summarized in Table 3-4. Of the million km2 categorized, 90% are no better than “Fair” (Class 3), with average wind speeds below 7 m/s. Only 3%, or about 30,000 km2, have Class 5 or better wind potential (average wind above 7.5 m/s).

Table 3-4: Areas of Land in Different Wind Speed Classes Brazil

Average Wind Speed Approximate Wind Class Area in Class (m/s @ 50 m height) (km2)6 Class 2 667.3916.5 Class 3 (starts 6.4) 231.7467 Class 4 71.7357.5 Class 5 21.6768 Class 6 6.6798.5 & higher Class 6/7 1.775

The total land area of Brazil is about 8 million km2.Source: (CEPEL, 2001)

Even so, the gross potential in these relatively small areas can be impressively large. The Brazilian Atlas estimates a gross potential of about 60 GW and 147 TWh in the relatively small areas with wind speeds above 7.5 m/s (Class 5 and above).

The areas with higher class wind resources are more attractive because they permit higher capacity factors with equivalent turbines. Exactly how much higher depends on the wind speed distribution, which is approximately characterized by the Weibull number. Table 3-5 shows two sets of estimates: the USDOE analysis of 20% wind penetration in the United States (EERE/USDOE, 2008) and the Brazilian Wind Atlas (CEPEL, 2001). The latter are much lower and appear to be excessively conservative by today’s standards. The capacity factors being achieved by modern turbines in Brazil are much closer to the USDOE values.

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Table 3-5: Approximate Capacity Factor Associated with Wind Speed Class

Average Wind Speed Approximate Wind Class Capacity Factor (%)(m/s @ 50 m height) USDOE Brazil Atlas6 Class 2 NA 14.6%6.5 Class 3 (starts 6.4) 32% 18.2%7 Class 4 36% 21.7%7.5 Class 5 40% 26.4%8 Class 6 44% 30.7%8.5 & higher Class 6/7 47% * 34.3%

* The 47% value is for Class 7, which begins above 8.8 m/s at 50 meters.Sources: EERE/USDOE, 2008; CEPEL, 2001

There are several reasons for the conservatism of the Brazilian Atlas. It was prepared a decade ago and reflects the technological assumptions of that time, or even somewhat before. The effective wind speed in the same class is higher because turbines today reach 90m or more and average wind speed will usually increase by 1 m/s as a result (see also Table 3-3 above). The efficiency of turbines has also improved. On top of this, the analysis was conservative then regarding estimates of average wind speed.

A second factor to consider is the density of power capacity per unit area, in MW/km2, which can be achieved in wind farms. Each turbine produces downstream turbulence in the air, so there are physical limits on how closely turbines can be packed together in order to avoid mutual interference which degrades performance. It is difficult to generalize about the spacing of turbines because topography and wind conditions have an influence. A general rule of thumb is that there should be about 7 rotor diameters between each turbine, in each direction (Krohn, personal communication).7

Thus on relatively flat, even terrain one can achieve about 6-7 MW/km2 on average. This value may be somewhat conservative, at least at the level of specific wind farms. Wind farm developers in Brazil tend to use 10 MW/km2 as a general rule, with Energy Yield Assessments resulting in values anywhere from 7-30 MW/km2 (Pacheco, personal communication). Interestingly, the achievable power density is not influenced by the size or height of the turbines, though the capacity factor is.

Table 3-6 illustrates the impact of using revised parameters on estimates of the gross technical potential of wind energy in Brazil by wind class. Due to the higher capacity assumed per km 2 (6 MW versus 2 MW) and the higher capacity factors assumed for equivalent classes of wind speed, the resulting gross potential is far higher than in the Brazilian Atlas.. .

7 If wind comes from one direction only, the turbines may be spaced more closely in a line, but then if there is a second line behind it must be further away, say 9 rotor diameters.

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Table 3-6: Gross Brazilian wind energy potential – Brazil Atlas and modified parameters

Wind Class Wind Capacity (GW) a Generation (TWh)Speed Brazil Atlas Modified Brazil Atlas b Modified c

Class 3 (from 6.4) 6.5 m/s 464 1,390 739 3,705Class 4 7 m/s 144 430 272 1,290Class5 7.5 m/s 43 130 100 433Class 6 8 m/s 13 40 36 147Class 6/7 8.5 m/s 3,6 11 11 39Total Classes 3-7 >6.5 m/s 667 2,002 1.158 5,614Classes 4-7 >7.0 m/s 204 611 419 1,910Classes 5-7 >7.5 m/s 60 181 147 619

a The Brazil Atlas assumes a power density of 2 MW/km2. The modified scenario assumes 6 MW/km2.b Capacity factors used as in Table 3-5.c The capacity factors in Table 3-5 for USDOE were reduced by 5%, except for the Classes 6/7 which were reduced by 10% since Class 7 starts at a higher wind speed (8.8 m/s). The resulting capacity factors were: Class 3 – 30.4%; Class 4 – 34.2%; Class 5 – 38.0%; Class 6 – 41.8%; Class 6/7 – 42.3%.

Of course, both of these estimates are for a kind of gross technical potential. One should not assume that more than a relatively small percentage of the land area which is apt for wind power could be developed. Some of the best potential sites may be in areas with characteristics that severely limit or prohibit development. Unusual scenic areas are one example. Places with concentrations of birds may be another. Buffer areas between wind farms are advisable and some land uses may be incompatible - though this is not the case with agriculture (while renting space for the towers can be a source of income for farmers). Technological advance has reduced some impacts, for example noise and the distracting reflection from turning rotor blades. 8

However, it is interesting how a modernization of resource estimates can significantly alter the perception of the possible role of wind energy. In this case, just 12% of Class 4-7 land area (about 12,000 km2 or 0.15% of Brazil’s land area) could supply 50% of the electricity generation today (448 TWh in 2007), up from 10% under the old estimates.

Technology and potential

The effective potential of wind energy is very much a function of evolving technology as well as of the characteristics of the natural resource. Wind power technology has been evolving continuously and continues to develop. These developments tend both to decrease the costs of wind generation and to increase the capability to extract more power from the same resource.

Commercial wind energy development converged several decades ago on horizontal axis turbines, whose rotors typically have three blades. A notable aspect of the evolving technology is the increasing capacity of the turbines’ rotors and the height of the tower hubs. This evolution is summarized in Figure 3-3. From typical sizes in the range of 500-750 kW in the late 1990s,

8 A review of environmental impacts can be found in (CNE-Chile, 2006), as well as USDOE/EERE, 2008. The noise level at 300 meters from modern large turbines is less than 45 dB. The impact on avian populations is reviewed, most studies show relatively low mortality, but this impact will be quite site dependent.

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turbines for on-shore wind farms are now in the 1.5-2.5 MW range. Offshore turbines are now 3.5 MW and will soon typically reach 5 MW.

Figure 3-3: Evolution of size and capacity of wind turbinesEERE/USDOE, 2008

This increase in rated output has necessarily been accompanied by an increase in turbine size. Turbines with 1.5 MW rated capacity have rotors that are more than 75 meters. 2.5 MW turbines are more than 90 meters long. Towers with hubs 100 meters high or more are now common. Taller towers mean access to the higher quality resource available at higher elevations. Figure 3-4 illustrates this effect in a mid-western State of the USA.

The other road to improve the quality of the available resource is to go off-shore. This option has so far been almost exclusively developed in Europe, where some 1470 MW have been developed (out of a total of 66,160 MW in Europe and 121,188 MW worldwide (WWEA, 2009). Off-shore turbines are more expensive per installed kW than an equivalent land-based turbine. However, average wind speeds are usually significantly higher offshore, which permits higher load factors. Also, off-shore turbines will tend to be even larger than land-based ones. They may not suffer some of the restrictions on component size imposed by land transport systems, depending on the site.

Logistics are clearly a major concern for developing cost effective sites. The large size and weight of big components such as the rotor and the tower modules means that transport costs can be significant. The large size of the components and the specialized skills involved in construction also argue for a certain economy of scale to reduce costs per kW in wind farms.

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Figure 3-4: Comparison of the wind energy resource at 50, 70 and 100 meters in IndianaEERE/USDOE, 2008

Most wind farms so far developed in Latin America are far too small to capture economies of scale. Even more important, the total rate of construction of wind capacity is very small and irregular in most national markets in the region. The lack of any regular flow of orders increases unit costs.

The economics of wind energy

Advances in technology have brought substantial reductions in the investment cost per kW of capacity and in the O&M costs. Cost reductions are projected to continue, especially over the next decade or so. Technological advances have also helped to increase the capacity factor of new machines, by reaching higher in the air or going off-shore.

Table 3-7 summarizes cost parameters for wind power from two recent studies. One is a generic review of generation technologies by ESMAP (ESMAP, 2007). The second is from an an analysis of the possibility of achieving a 20% share of the United States generation mix by 2030 (EERE/USDOE, 2008). There are considerable differences between these analyses regarding near term investment costs and their evolution.

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Table 3-7: Comparison of wind power cost parameters and their evolution over time

Investment US$/kW

2005 2010 2015 2020 2030

ESMAP, 2007 Maximum 1390 1230 1110

(US$ 2005) Probable 1240 1080 960

Minimum 1090 890 750

US 20% Wind 1650 1650 1610 1570 1480

(US$ 2006)

Fixed Operations US$/kW-year

2005 2010 2015 2020 2030

ESMAP, 2007 Maximum+20% 16,72 16,72 16,72

(US$ 2005) Probable 13,93 13,93 13,93

Minimum -20% 11,15 11,15 11,15

US 20% Wind 11,50 11,50 11,50 11,50 11,50

(US$ 2006)

Variable O&M US$/MWh

2005 2010 2015 2020 2030

ESMAP, 2007 Maximum+20% 2,64 2,64 2,64

(US$ 2005) Probable 2,20 2,20 2,20

Minimum -20% 1,76 1,76 1,76

US 20% Wind 7,00 5,50 5,00 4,60 4,40

(US$ 2006)

A noteworthy difference between these studies is that the ESMAP review projects a substantial reduction in unit investment costs in the next decade,9 while the projected reduction in the USDOE study is much more modest. However, the discrepancy between these studies is perhaps not as great as it appears at first. The USDOE study emphasizes achieving higher load factors. Thus, for example, wind farms constructed in areas with a resource classification of 4 (7-7.5 m/s at 50 m) are expected to achieve a capacity factor of 36% today, while those constructed in 2015 are expected to achieve 41%, rising to 43% for those entering operation in 2030. Basically this means investing in taller towers as well as other performance enhancing innovations, which together increase initial costs. The ESMAP review appears to project lower cost to achieve the same performance. Both approaches should reduce the cost per MWh over time.

The capacity factor of wind farms certainly has an important impact on total generation costs, as shown in Table 3-8. This is due mostly to the relatively high initial investment cost per kW of capacity.

9 This projection reflects European analyses of technological trends. The ESMAP report also notes that existing US cost estimates tend to be higher than European estimates.

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Table 3-8: Wind generation costs at different capacity factors – 2005 & 2015

Load Factor→ 28% 32% 36% 40% 44% 48%EERE/USDOE, 2008 - For 2005 $90,67 $80,21 $72,07 $65,57 $60,24 $55,80EERE/USDOE, 2008 - For 2015 $86,75 $76,53 $68,58 $62,23 $57,02 $52,69

ESMAP, 2007 - For 2005 $67,23 $59,10 $52,78 $47,72 $43,58 $40,13ESMAP, 2007 - For 2015 $53,83 $47,37 $42,36 $38,34 $35,05 $32,32

Assumes a 10% discount rate (or weighted average cost of capital) and a 20 year lifetime.EERE/USDOE estimates are in US$2005, those of ESMAP US$2006.

Given the capital intensity of wind power, generating costs are also sensitive to assumptions about the discount rate and the lifetime of the equipment, as illustrated in Figure 3-5.

Figure 3-5: Generation costs as a function of discount rate and equipment lifetime(US$/MWh)

Source: Calculated from parameters in EERE/USDOE, 2008 for a plant with a 36% capacity factor.

The two reviews of costs cited here are for relatively developed markets in richer countries. Costs in Latin America will be distinct. At present they seem to be substantially higher than the values cited here. For example a 300 MW wind farm in northern Colombia is estimated to cost between US$ 1900-2400 per kW (ESMAP, 2009), resulting in a cost of power of $74-91/MWh instead of the $48-66 in Table 3-8 above.10 It is not clear why investment costs should be so much higher, though the small and irregular market in Latin America clearly has a role. This suggests that there should be considerable scope for reducing costs just to bring the region closer in line with costs elsewhere.

The trend of costs in Brazil should be interesting to watch given the larger scale of the program in that country. A comparative analysis of historical costs is complicated by the large oscillations in the exchange rate which have occurred in recent years. Two of the larger projects appear to show investment costs close to the level cited for the USA in Table 3-7 above

10 The calculation assumes a 40% load factor (close to that of the existing small wind farm), a 10% discount rate and fixed and variable O&M as in USDOE, 2008).

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(US$1600-1700/kW), though smaller projects (18-28 MW) appear to have had substantially higher unit costs (US$ 2300-3100/kW)

Assuming that Latin America’s costs can converge with international costs, then wind power in good sites begins to be quite competitive – perhaps much more competitive than perceived by energy policy makers in the region today – influenced as they are by the high historic costs of wind projects just commented on.

But competitive with what? The profile of generation and expected generation varies throughout Latin America, so the context for comparison changes considerably from country to country. Here are some general observations.

First, in many countries, the low cost baseline is hydro. Wind is not so much competing with hydro as complementing it. Both contribute to lower carbon emissions. At the same time, security concerns caution against an exclusive reliance on hydro, while at the regional level (and most countries) there are simply not enough hydro resources to even contemplate such an approach – a point already emphasized in the section on hydro. In a sense, wind is competing against other generation resources to complement hydro.

The most common comparison made is with conventional pulverized coal plants and these usually appear to be considerably cheaper. However, these comparisons usually have a major flaw, they assume that the alternative thermal plant is operating at base load with capacity factors of 80% or more. This flatters the cost of the thermal plant, but it is a bit like comparing apples with oranges.

Wind is not a base load generation technology and the power generation system cannot be made up exclusively of base load plants – since system load factors are more like 50% (the average in Latin America in 2007 was about 50%). One needs to compare two mixed sets of generating technologies that can supply that profile of demand. This is a more complex analysis than comparing individual alternatives for a plant, but as with the question of variability and reserves, wind requires us think more carefully about the system as a whole if we are to take it more seriously.

A quick crude way to illustrate the impact of stepping back from simplistic comparisons with base load plants is to consider a coal plant operating at lower factors, as in Table 3-9.

Table 3-9: Cost of generation from pulverized coal plant at different load factorsUS$2006 per MWh

Capacity factor → 40% 50% 60% 70% 80%300 MW subcritical 66,10 57,54 51,83 47,76 44,70500 MW supercritical 64,10 55,66 50,03 46,01 43,00Source: Calculation based on ESMAP, 2007

In Table 3-8 above there is a range of wind options which produce power at $55-65 per MWh. A coal plant operating at 60% capacity factor has a cost of about $50/MWh, so the difference isn’t huge. Indeed, it would appear that carbon credits at today’s prices (about US$ 18/t CO2) could have a significant impact on the relative economics, since a credit of $18/t CO2 translates to an increase in cost of about $15 per MWh in a coal plant. Of course, this comparison would be representative only once the unit cost of wind power investment gets close to international

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levels, which may require a transition with larger incentives – as for example are discussed for Colombia in ESMAP, 2009.

New coal plants or combined cycle natural gas plants are not usually run at 60%. However, many thermal plants – including older coal plants - operate at this or much lower capacity factors (e.g. intermediate load plants, not to mention peaking and those on standby to complement hydro in dry periods). The average capacity factor of thermal plants in Latin America was less than 45% in 2007, as was shown in Table 3-2. Their average cost per MWh is definitely not less than the values in the table above for coal. In any case, this calculation is only meant to illustrate a point.

This paper only addresses energy for the grid, though wind energy began as a small scale resource for isolated regions and indeed is still often perceived in this way. There are niches for small isolated wind systems, but it is clear that this technology has substantial economies of scale up to plants (wind farms) of 100 MW or more. Table 3-10 shows the estimated investment cost per kW at different scales.

Table 3-10: Investment per kW at different scales of wind generation

Scale Investment per kW (US$2006)0.30 kW 5370100 kW 278010 MW 1440100 MW 1240

Source: ESMAP, 2007

Costs not included so far are: (a) transmission costs, and (b) the costs for ancillary services. Transmission costs depend entirely on the location of the project and the condition of the local grid. They may be small or quite high. It will be necessary to view the transmission needs for the expansion of wind power in a strategic manner and not simply project by project. There is an analogy with hydropower, except that in the case of wind the individual projects will typically be smaller - one should analyze clusters of potential projects.

The costs for ancillary services are dominated by the costs to provide backup to compensate for the variability of the wind supply. These include reserves for short term regulation and load following and somewhat longer term unit commitment (see the discussion in Section 1 and Figure 1-1), as well as fuel (natural gas) for reserve generation. Figure 3-6 shows estimates of these costs as a function of the share of wind energy in the generating mix. There is a tendency for these costs to increase as the share of wind in the system’s capacity increases. However, even with a 20% share the cost is less than US$ 5.00/MWh.

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Figure 3-6: Diverse studies of the cost of wind plant ancillary services(regulation service, load following, unit commitment and natural gas)

Source: NAS/NAE, 2009

All plants have ancillary costs, so not all of this cost would be “net” when comparing with alternatives. In addition, the cost estimates are for the USA. In the context of Latin America, which has a much larger hydro share, the cost of these ancillary services may be less. For example the cost of short term regulation and natural gas should be less with hydro as the primary reserve.

Observations on regional potential

Unlike hydropower, there are currently no published general estimates of wind power potential in Latin America, theoretical, partial or otherwise. Indeed, there are many countries for which there is no published estimate at all. This does not mean there is no interest in those countries. Peru for example has no estimate of published official estimate of potential, but has registered a relatively large portfolio of possible plants. Similarly, Chile has no overall estimate of potential but has surveys indicating promising sites in parts of the country. Even oil-rich Venezuela is building a 100 MW wind farm and plans several more, despite the rudimentary nature of published surveys there.

A number of countries have published partial or complete national surveys indicating the most promising areas for wind project development, without, however, estimating overall potential. The few countries with estimates give few indications of the detailed assumptions underlying those estimates.

As already discussed above, estimating the effective potential of wind power is tricky. There are evolving technical possibilities, while estimates also involve making some assumptions regarding land use constraints which are necessarily rather arbitrary and/or subjective,

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especially since the development of estimates is still quite incipient. Hydro, by comparison, is a mature technology which has been the object of intensive study of much more easily definable sites for many decades.

However, there is no doubt that Latin America does have some excellent areas for the development of wind energy and the high quality potential (say, wind Classes 4, or more rigorously, 5 and up) of the region as a whole is big enough to make a strategic difference for electricity expansion over the coming several decades. Because of the need to economize financial resources, the emphasis throughout is on areas with higher quality potential.

Annex C provides summaries information about selected countries and groups of countries.11 The review does not consider possible shallow off-shore resources, which have barely begun to be investigated. This is not surprising, considering that the development of cheaper and easier on-shore resources has barely begun.

Given the limited and very uneven information about the distribution of wind energy resources throughout Latin America it is impossible to quantify the regional potential even approximately. Put another way, any regional estimate would be fairly meaningless. What we can say is that:

a. The gross potential from high quality resources (Class 4 and up) in the region as a whole is much larger than current electricity generation (1225 TWh in 2007).

b. Only a relatively small fraction of the gross potential (perhaps 10-15% in most countries) can effectively be developed.

However, even with this restriction, the potential is large relative to current total generation in the region.

Again, taking into account this restriction, less than 1% of high quality wind potential has been developed in the region overall.

c. This potential is unevenly distributed, both within countries and between countries. Argentina alone has the gross potential to supply Latin America several times over, no one else comes close.

d. While there are large differences between countries, in all the countries reviewed there appears to be enough high quality potential to make a significant contribution to electricity supply expansion over the next 20-25 years (say, more than 10%).

While regional potential certainly needs to be better defined, another line of analysis which should be developed is from the perspective of the grid’s capability to absorb increasing shares of wind generation capacity.

Studies in countries where wind is more developed suggest that up to 15-20% of total capacity, wind can be integrated in grids covering large catchment areas without high additional costs for reserves (EERE/USDOE, 2008; Smith, 2009).

In Latin America, given the large share of hydro, which is well adapted to complementing and providing short term reserves for wind, this is probably a conservatively low value.

Given the load factors of wind plants, 15-20% of total capacity translates to something like 9-14% of generation output in terms of MWh (or TWh, which are one million MWh).

In the context of Latin America in 2030, this share of output would translate to about 290-450 TWh.

At a regional level, and within most countries, there are more than adequate high quality resources to meet this kind of target.

11 The countries considered in the annex are: Argentina, Brazil, Peru, Colombia, Venezuela, Mexico and the Dominican Republic, as well as Central America.

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Complementation strategies which take advantage of the diversity of wind regimes (as well as of the diversity of hydrology) would facilitate the reliable absorption of a relatively large share of wind energy in the region’s electrical systems.

Such strategies imply a wider exchange between countries (especially middle sized and smaller countries) to increase the diversity of the “catchment area”. This in turn implies a more robust network of bulk transmission interconnecting the countries in the region. This would represent a deepening of a more intense interconnection strategy already recommended for optimizing the regional development of the remaining hydro resources.

In Section 7 the possible role of wind is discussed in the context of broader scenarios to maintain the share of renewable in the region’s generation mix.

Looking further into the future it will be prudent to consider limits on the energy extracted from the wind to avoid effects on weather and climate at a local or continental level. Preliminary analyses suggest that this limit is on the order of 20% of the energy in the wind field (NAS/NAE, 2009). Such a limit represents an extraction of at least several thousand TWh/yr, which is far above any level of output which could be achieved in the next several decades. Indeed, it is above the level of extraction judged feasible from the perspective of land use constraints.

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4. Geothermal

Geothermal is the third largest source of generation of electricity from renewable energy in Latin America today. Capacity is concentrated Mexico and Central America, as shown in Table 4-1. Mexico is the third largest geothermal producer in the world, after the USA (2002 MW) and the Philippines (1909 MW). Central America’s capacity of 426 MW is large relative to the installed capacity

Table 4-1: Existing geothermal capacity and generation in Latin America (2007)

Country Capacity (MW) Generation (TWh)1995 2000 2007 2007

Mexico 753 755 953 7.40

El Salvador 105 161 161 1.38

Costa Rica * 55 143 159 1.19

Nicaragua 70 70 77 0.24

Guatemala 0 33 29 0.26

Total 983 1162 1379 10.47 Central America 230 407 426 3.07

* Costa Rica data are for 2006.Sources: Iglesias et alii, 2005; SENER, 2008; ICE, 2007; OLADE, 2008; Dickson & Fanelli, 2004.

As shown in the table, the growth of geothermal in Latin America has been slow in recent years. With existing technology the ability to contribute to the expansion of future supply is generally regarded as rather limited, even in the regions with the clearest potential along the Andes, Central America, Mexico and the Eastern Caribbean. This modest assessment could change if there is a breakthrough in the development of “enhanced” (or “engineered”) geothermal systems (EGS), especially those for extracting heat from deep dry rock formations. Even without such a breakthrough geothermal could probably play a larger role than is currently suggested in the expansion plans of the power sector.

Different from the other renewable resources, geothermal energy is not ultimately dependent on the sun’s radiation, but on flows of heat from the interior of the earth. Geothermal plants are operated as base load and can have capacity factors of 90% or more.

There are various basic kinds of geothermal resources. The only commercially used resources at present are hydrothermal resources. These are found in formations which contain hot water and/or steam trapped in fractured or porous rock at shallow to moderate depths (from approximately 100 to 4,500 m, but usually fairly close to the surface in developed sites). Hydrothermal resources are categorized as vapor-dominated (steam) or liquid-dominated (hot water) according to the predominant fluid phase. Temperatures of hydrothermal reserves used for electricity generation range from 90º C to over 350º C, but roughly two thirds are estimated to be in the moderate temperature range, or 150-200º C (Dickson & Fanelli, 2004).

In addition to hydrothermal resources there are geopressured resources and hot dry rock resources (HDR).

Geopressured geothermal resources are hot water aquifers containing dissolved methane trapped under high pressure in sedimentary formations at a depth of approximately 3 to 6 km. Temperatures range from 90 to 200º C, although the reservoirs

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explored to date seldom exceed 150º C. The extent of geopressured reserves is not yet well known world-wide, and the only major resource area identified to date is in the northern Gulf of Mexico region. This resource is potentially very promising because three types of energy can be extracted from the wells viz., thermal energy from the heated fluids, hydraulic energy from the high pressures involved, and chemical energy from burning the dissolved methane gas.

Hot, dry rock (HDR) resources are accessible geologic formations that are abnormally hot but contain little or no water. The basic concept in HDR technology is to form a man-made geothermal reservoir by drilling deep wells (say, 4-6,000 m) into high-temperature, low-permeability rock and then forming a large heat-exchange system by hydraulic or explosive fracturing. Injection and production wells are joined to form a circulating loop through the man-made reservoir, and water is then circulated through the fracture system, as shown in Figure 4-1. Because of the man-induced fracturing of the reservoir these also are referred to as “enhanced (or “engineered”) geothermal systems (EGS). The power plant design options are similar to those for “conventional” hydrothermal resources.

Figure 4-1: Schematic of production from hot dry rock

.Source: NAS/NAE, 2009

Two types of technology are used to generate power from hydrothermal geothermal resources: binary systems and steam (or “flash”) systems.

The steam or flash plants use steam directly from the source to directly drive a conventional Rankine cycle turbine, or use flash plants to depressurize hot water from the source (170-300º C) to produce the steam. They are available with either back-pressure (atmospheric) or condensing exhausts (see Figures 4-2 & 4-3). Those plants exhausting to the atmosphere consume twice as much steam per kWh and are usually smaller units (2.5-5 MW).

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In binary systems, the hot geothermal water (125-170º C) is routed through a closed-loop heat exchanger, where a low boiling-point hydrocarbon such as isobutane or isopentane is evaporated to drive a Rankine power cycle turbine, as shown in Figure 4-4. The upper temperature limit depends on the thermal stability of the organic binary fluid, and the lower limit on technical-economic factors. Below a certain temperature the size of the heat exchangers required would render the project uneconomical.12 The cooled or “spent” geothermal fluid is then returned to the reservoir. Since the cycle is self-contained, there are no emissions, other than water vapor.

Figure 4-2: Sketch of a geothermal steam plant with atmospheric exhaust

Source: Dickson & Fanelli, 2004

Figure 4-3: Sketch of a geothermal steam plant with condensation

The flow of high-temperature geothermal fluid is shown in red, and the cooling water in blue. Source: Dickson & Fanelli, 2004

12 Binary plants can be designed for temperatures down to 85-90º C but for economic reasons stay in the range 125-170º C as shown in the text.

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Figure: 4-4: Sketch of a geothermal binary plant.

The flow of geothermal fluid is in red, the secondary fluid (e.g. iso-pentane) in green and the cooling water in blue. Source: Dickson & Fanelli, 2004

Binary plants are usually constructed in small modular units of a few hundred kWe to a few MWe

capacity. These units can then be linked up to create power-plants of a few tens of megawatts. Their cost depends on a number of factors, but particularly on the temperature of the geothermal fluid produced, which influences the size of the turbine, heat exchangers and cooling system. The total size of the plant has little effect on the specific cost, as a series of standard modular units is joined together to obtain larger capacities.

Binary plants permit the use of lower temperature geothermal fluids than do steam plants. They also have environmental advantages:

There is no need to dispose of geothermal liquids, which can often be a problem. There is no release of pollutant gases, such as H2S or CO2. The reinjection of fluids largely eliminates subsidence.

These advantages can compensate for the fact that they are more expensive per kW and binary plants are quite common world-wide (NAS/NAE, 2009), though steam plants predominate in Latin America’s existing capacity.

Table 4-2 provides a range of investment costs per kW of capacity for generic flash steam and binary plants. Table 4-3 then discriminates the cost components for the “probable cost” case.

Table 4-2: Estimate of range of investment costs for binary and steam geothermal plants(US$ 2005/kW)

Technology Minimum Probable Maximum20 MW binary $3.690 $4.100 $4.50050 MW flash $2.260 $2.510 $2.750

Source: ESMAP, 2007.

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Table 4-3: Breakdown of investment costs for binary and steam geothermal plants(Conventional hydrothermal resource)(US$ 2005/kW – “Probable cost” case)

Cost category 20 MW Binary a 50 MW Flash Steam b

Exploration/confirmation $790 $610Main wells $710 $540Power plant $2,120 $1,080Other $480 $280Total $4,100 $2,150

a Binary plants typically operate between 125-170º C. Since this is a mid-case cost scenario it may represent the case for an intermediate temperature, say 150º C.b Flash steam plants operate from 170º C. In this mid-case cost scenario case it will be above 200º C.Source: ESMAP, 2007

The higher cost of the binary plants relative to the flash steam plants is due in part to the lower temperature of the resource, which reduces the efficiency and increases the volume of geothermal fluids required.

The same source estimated the levelized cost per MWh of the two technologies as shown in Table 4-4.

Table 4-4: Levelized costs per MWh for binary and steam geothermal plants(US$ 2005/MWh)

Technology Capital Fixed O&M Variable O&M Total20 MW binary $50,2 $13,0 $4,0 $67,250 MW flash $30,7 $9,0 $3,0 $42,7

Basis for the levelized capital cost is the “Probable” investment per kW shown in Table 4-2.Source: ESMAP, 2007.

Even though the costs may be a bit optimistic regarding the assumed discount rate for a relatively risky investment and the lifetime load factor of 90%,13 geothermal generation is relatively competitive in sites with good quality hydrothermal resources. It should be able to compete with fossil fuels if relative modest costs for carbon emissions are considered.

But how big are the geothermal resources?

Available estimates by Latin American energy planning agencies of the potential for electricity generation from hydrothermal geothermal resources are quite spotty and values were not found for some countries which clearly have potential, such as Colombia and Peru. Table 4-5 summarizes estimates for several countries and Central America.

13 The average capacity factor of geothermal plants world-wide is closer to 70% than 90% (IGA, 2001). However, the output is constant despite the lower capacity factor.

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Table 4-5: Estimates of remaining hydrothermal geothermal resources

Country/Region GWe TWhe * Existing Generation

TWhe % Potential **Central America 2.95 23.3 3.1 12%Chile 1.24-3.35 9.7-26.4 0 naMexico: proven - probable 1.32-5.92 10.4-46.7 7.4 14-42%

* Assumes a 90% capacity factor. ** % of total potential (remaining + existing).Sources: Central America (OLADE, 2005); Chile (BCN, 2004); Mexico – proven (SENER, 2005 & Iglesias et alii, 2005), probable (Iglesias et alii, 2005)

There is a large degree of uncertainty in these estimates and it is not clear to what extent they include somewhat lower temperature resources (say, below 175º C) which are accessible to production with binary plants.

Dimensioning the reserves requires exploratory drilling, which is quite expensive. Not much drilling has been done, which means there is considerable uncertainty in these estimates. It is noteworthy that in Mexico, which is the third largest geothermal producer in the world, there has been no published review of the potential of high temperature resources since the mid-1980s (Iglesias et alii, 2005). In June of 2009, Chile announced an auction of geothermal concessions, which should lead to more exploration in that country.

These country level estimates point to a relatively modest potential as do the published expansion plans in the few countries which include geothermal. The situation in the USA is rather similar (NAS/NAE, 2009) even allowing for the fact that the potential in Latin America may be substantially larger (see below).

The outlook could change substantially if the technology to exploit hot dry rock (HDR) geothermal resources matures. An example of estimates is shown in Table 4-6. To calibrate the values shown for Latin America, the region generated 1225 TWh in 2007.

Table 4-6: Global estimates of geothermal potential

Region Land Steam a Steam & BinaryArea Output/yr Density b Output/yr Density b

106 km2 TWhe/yr kWe/km2 TWhe/yr kWe/km2

North America c 18.3 1,330 8.3 2,700 16.8Latin America 21.1 2,800 15.1 5,600 30.3Rest of World 109.4 7,070 7.4 14,100 14.7World 148.8 11,200 8.6 22,400 17.2

a Conventional steam plantsb Density assumes constant output, i.e. a capacity factor of 100%c Includes only the USA and CanadaSource: Based on IGA, 2001.

Note that this broader analysis indicates a density of potential in Latin America that is almost double that of the rest of the world on average. Unfortunately this study presents almost no information regarding the assumptions underlying these large estimates of potential.

The values shown seem to imply “mining” of the resource, as well as a large “footprint”. The mean geothermal heat flux over land at Earth’s surface is approximately 60 mWth/m2, or 60

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kWth/km2 , though there is considerable variation around this mean.14 An efficiency of 15% is estimated for electricity generation from the relatively low temperature heat available from this resource (NAS/NAE, 2009). Thus, on average, the extractable electric power density from the geothermal resource on a renewable basis is about 10 kWe/km2. This value can be compared with the densities in the Table 4-6 above. In Latin America the average density of heat flow may be significantly higher than in North America, but even so the values seem excessively high even as an ultimate “technical potential”, where there is extraction of heat throughout the whole land mass.

In any case, the generation of electricity from the heat in hot dry rocks (HDR) is for now only a hypothesis around which there is a very big question mark. This concerns the possible stimulation of earthquakes by the techniques used to enhance the geothermal reservoir. This could be a show stopper. As already observed, the creation of the reservoir requires the fracturing of the impermeable bedrock. A pioneering project in Basle, Switzerland, was suddenly shut down in December, 2006, by a series of earthquakes clearly induced by the project (NYT, 2009). The induction of some seismic activity has been attributed to some conventional hydrothermal geothermal projects, such as the Geysers, in California. However, the severe seismic impact of the Swiss HDR project was unprecedented and has raised serious doubts about “Enhanced Geothermal Systems”.

However, even if HDR ultimately proves to be too risky from a seismic point of view, geothermal from relatively shallow hydrothermal resources could possibly play a significant role in a strategy to reduce carbon emissions from electricity generation in Latin America over the next 20-30 years.

Accepting the parsity of published information and estimates from Latin America, let us take as a reference the estimates of hydrothermal geothermal potential in the United States, where actual drilling of all kinds has been far more intense. A review by the National Academies of Science and Engineering (NAS/NAE, 2009) cited identified potentials of 13 GW (~100 TWh/yr) in the Western US, of which 5.6 GW (~45 TWh/yr) could conceivably be developed by 2015. The study cites other larger values for the country as a whole, as well as exploration to find sources without surface manifestations, but let us restrict ourselves to these identified sites.

The land area of Latin America is 2.3 times that of the USA. In addition, it is possible that the potential per km2 (energy density) is higher in Latin America is higher, as suggested by Table 4-6. Assuming an energy density only 25% higher, Latin America would have a hydrothermal potential of:

125 TWh/yr assuming the exploitable potential in the USA to 2015 (5.6 GW) 295 TWh/yr assuming the equivalent of 13 GW in the US

The lower scenario of 125 TWh/yr might be a reasonable regional target for 2030. It is ambitious and would represent an order of magnitude increase in investments, beginning with short term prospecting. However this goal probably would require no technological breakthroughs. This potential would be concentrated in the countries of the “Pacific Rim” of Latin America, as well as the Caribbean.

In Section 7, the possible role of geothermal is discussed in the context of broader scenarios to maintain or increase the share of renewable in the mix of electricity generation in the region.

14 The subscript “th”, as in kWth means that the energy or power capacity refers to a thermal rather than electrical flow, even though kW and kWh are normally used for electricity. One kW = 3416 Btu/hour or 3.6 MJ/hour. In these circumstances we distinguish electrical output with the subscript “e”, as in kWe.

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5. Biomass - sugarcane residues

Biomass is the second largest renewable resource for generation in Latin America today, after hydroelectricity. Unfortunately there are no region-wide statistics on electricity generation from biomass.15

Within the category of biomass, sugarcane residues are by far the most important resource for electricity generation in the region. It was decided to concentrate on sugarcane, due to the short time available to prepare this report, the diversity of the characteristics of specific biomass resources and the opportunities to generate power, as well as the fragmented statistical information available.

The primary sugarcane residue is bagasse, which is a residue of the milling and squeezing of the cane to produce sugar or alcohol. Bagasse is traditionally used to cogenerate electricity and process steam. Two other residues are little used today for electricity generation, but could become complementary resources in the future:

“Field trash” (“ponta e palha” in Portuguese) - the cut leaves and cane tops – is traditionally left in the field and burnt. Mechanized harvesting techniques open the possibility of gathering at least part of this residue, though a part should still be left in the fields.

Stillage – (“vinhoto” or “vinhaça” in Portuguese) – is a liquid residue of the fermentation process in the production of alcohol. It has high organic content and some fertilizer nutrients (especially high potassium). If treated beforehand, this liquid waste can used as fertilizer in the sugarcane fields. One treatment, anaerobic digestion, yields methane which could be consumed in electricity generation systems

Production of sugarcane is widespread in Latin America and the Caribbean. Table 5-1 shows the production by country in 2004-06 and compares output with 1994-96. Total production was about 660 million tons of crushed cane. Over the decade output grew by about 2.5% per year. Brazil is overwhelmingly the largest producer in the region and its share increased over the period from about 60% in 1994-96 to 69% in 2006. Production of sugarcane grew almost as fast in Central America. On the other hand, output stagnated or contracted in the Caribbean, with huge reductions in Cuba and Trinidad & Tobago.

15 In the OLADE statistical reports – a standard statistical resource for the region – generation from biomass is lumped together with fossil fuels under the category “thermal”.

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Table 5-1: Production of sugarcane in Latin America

Countries 1994-1996 2004-2006 2004 2005 2006Argentina 16.833 21.453 20.953 24.405 19.000Bahamas 45 35 50 50 6Barbados 452 374 361 350 410Belize 1.170 1.099 1.191 927 1.180Bolivia 4.030 5.547 5.328 5.112 6.201Brazil 304.302 431.803 415.206 422.957 457.246Chile 0 0 0 0 0Colombia 32.733 39.650 40.100 39.849 39.000Costa Rica 3.397 4.140 4.200 4.000 4.220Cuba 39.367 15.487 23.800 11.600 11.060Dominica 5 4 4 4 4Dominican Republic 5.851 5.219 5.547 4.951 5.160Ecuador 6.752 6.653 6.122 6.838 6.999El Salvador 3.996 4.869 4.921 4.405 5.280Guatemala 14.296 20.153 18.283 23.454 18.721Guyana 3.193 3.283 3.744 3.006 3.100Haiti 1.233 911 895 839 1.000Honduras 3.239 5.364 5.466 5.625 5.000Jamaica 2.482 1.840 2.100 1.470 1.950Mexico 43.374 50.328 48.662 51.646 50.676Nicaragua 3.147 4.116 4.027 3.817 4.505Panama 1.559 1.765 1.754 1.771 1.770Paraguay 2.704 3.552 3.637 3.820 3.200Peru 6.600 7.182 7.497 6.804 7.246Saint Kitts & Nevis 190 153 260 100 100Saint Vincent & Grenadines 20 19 18 20 20Suriname 100 87 70 70 120Trinidad & Tobago 1.376 458 535 420 420Uruguay 204 169 155 178 175Venezuela 6.379 9.284 8.832 9.674 9.346

Total 509.031 644.998 633.718 638.161 663.115

Central America 30.805 41.506 39.842 43.998 40.677Caribbean (ex Cuba) 11.654 9.015 9.771 8.204 9.070

Source: FAO, 2009. This source does not distinguish between sugarcane and sugarbeet production. Based on other sources, sugarcane output in Chile was assumed to be zero.

Until fairly recently, sugarcane mills were usually designed to be approximately self sufficient in electricity, due to the lack of economically interesting markets to which to sell power. There was no incentive to produce or use steam efficiently, either for the industrial thermal processes or the generation of power. Hence traditionally, most sugarcane mills produce steam for electricity at very low pressure – typically 20-22 atmospheres. In such a configuration, process steam use was about 400-500 kg per ton of cane crushed (tc) and exports of power would be in a range from near zero to 10 kWh/tc (ton of cane)

Much higher output of electricity can be obtained from the same quantity of bagasse by increasing the pressure of the steam produced. Table 5-2 illustrates net generation available for export per ton of sugarcane processed at different steam pressures.

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Table 5-2: Net electricity for export per ton of cane at different steam pressures

Country/Region Steam Pressure (bars) a

22 42 67 82/87Southern Africa 25 53-75 130-140India 90-120 130-140Brazil 0 20 40-50 105

a One bar = one atmosphere. Sources: For estimates in Southern Africa and India as well as Brazil up to 67 bar - Seebaluck et alii, 2007. For Brazil 82 bar, Larson, et alii, 2001.

There are substantial differences between the estimates for different countries. The lower net output in Brazil is notable. This may be due to somewhat more intensive processing of sugar (or alcohol) in Brazil. The other examples may include some fuel other than bagasse. The wide range of results for the same boiler pressures shows clearly the need to be specific about specifying factors such as the bagasse content of the cane and the associated industrial operations when comparing sugarcane cogeneration options and performance in different countries. In this report the main series of reference will be the estimates for Brazil, which are also more conservative.

By the early 1990s it was recognized that by going to gasification and gas turbines, the electricity production per ton of sugarcane could be increased substantially compared to simply increasing steam turbine temperature and pressure. This is because gas turbines generate substantially more electricity per ton of low pressure process steam. The increase is big enough to compensate the losses in the gasification process.

Under this gasification approach, the gas produced from the bagasse would enter a gas turbine. There would then be heat recovery from the exhaust gases to drive a steam turbine in cogeneration mode. It would thus be configured as a “combined cycle” plant. This alternative was denominated biomass integrated gasification/gas turbine combined cycle technology or BIGCC.

Analyses in Brazil suggested that total electricity generation per ton of cane could be increased from 135 kWh/tc with steam turbines at 82 atmospheres to about 180 kWh/tc with the BIGCC (Larson et alii, 2001). The electricity available for export would be 15-30 kWh/tc lower, depending on the characteristics of the sugarcane mill.

Unfortunately attempts to build a large-scale demonstration BIGCC plant never succeeded, so the technology remains untested. Finely ground residues like bagasse present a challenge for gasifiers, which are generally more adapted to convert lumpier solid material (e.g. wood chips or coal).

Another way to increase electricity generation is to use the residues which today are usually burned in the field. This “field trash” is composed of the leaves and tops of sugarcane. As already observed, the spread of mechanized harvesting makes the collection of these residues feasible. Table 5-3 summarizes the impact on generation potential of assuming one scenario of use of “field trash” in order to permit generation during the off-season as well.

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Table 5-3: Estimated electricity per ton of sugarcane under different assumptions (kWh/tc)

Bagasse Only a With Field Trash b

Steam Turbine Gasifier & Gasifier &22 bar 42 bar 67 bar 82 bar Comb Cycle 82 bar Comb Cycle

Export to grid 0 20 45 105-120 145-160 180-195 290-305Total generation 10 30 60 135 175 210 320

a Assumes bagasse dry matter of 140 kg/ton of cane. Harvest during 210 days.b Additional 103 kg of residue per ton of cane. Generation throughout the year with 87% capacity factor. Sources: Based on estimates for Brazil. Steam turbine 22 & 42 bar Seebaluck et alii, 2007; 22 & 67 bar is from a Brazilian project; other cases from Larson, et alii, 2001.

Adding “field trash” increases the potential significantly per ton of cane. The impact of different assumptions on the potential for electricity generation in Latin America is illustrated in Table 5-4, considering the level of production of sugarcane production in 2006. By way of comparison with the values shown, electricity generation in Latin America was 1175 TWh in 2006. If 82 bar is taken as an approximate limit short of gasification technologies and ½ of capacity had access to field residues, then the potential might be roughly 115 TWh, or about 10% of current regional generation.

Table 5-4: Potential generation from existing sugarcane under different assumptions (TWh)

Output in 2006 Bagasse Only With Field Trash663 million tons Steam Turbine Gasifier & Gasifier &

22 bar 42 bar 67 bar 82 bar Comb Cycle 82 bar Comb CycleExport to grid 0 13.3 29.8 69.6 96.1 119.3 192.3

Total generation 6.6 19.9 39.8 89.5 116.0 139.2 212.2

The potential weight of sugarcane cogeneration varies widely from country to country. Using 2006 data and the criterion above (82 bar with 50% of the field trash), the potential in Brazil and Central America would be 17-18% of total generation, in Colombia and Cuba 12-13%, while in the Caribbean and most other countries it would 5% or less.

The resource base for cogeneration should expand in the future as sugarcane production increases. Future growth of sugarcane production is quite uncertain and will depend both on the market for sugar and for fuel alcohol (ethanol) or other liquid fuels from sugarcane. Rapid growth of such biofuels could increase the potential for cogeneration of electricity. On the otherhand, a countervailing factor would be the development of economic processes to produce liquid fuels from cellulosic materials. There is a large global R&D effort directed towards this goal. Sugarcane residues would be an obvious candidate feedstock for such processes – which would drastically limit the quantity available for electricity generation.

A simplistic extrapolation of past growth at 2.5% would represent a kind of “business as usual” scenario with neither a big push to liquid biofuels from cane sugar nor breakthroughs in cellulose from cane residues. It implies a sugarcane production of about 1.2 billion tons per year or about 80% larger than today. The electricity generation potentials for the region in this scenario are summarized in Table 5-5, for different technology options. In each case it is

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assumed that the option would be used for all sugarcane. In practice, a mix of technologies will be used for many decades.

Of course, some of this potential has already been developed. As already observed, systematic estimates of generation from sugarcane are not available. However, assuming that Brazil is roughly representative, about 13 TWh of electricity was generated in sugarcane mills in 2006.16 This value for existing generation has been subtracted to determine “remaining potential” in the table.

Table 5-5: Potential generation from sugarcane under different assumptions - 2030(TWh)

Output in 2030 Bagasse Only With Field Trash a

1.2 billion tons Steam Turbine Gasifier & Gasifier &22 bar 42 bar 67 bar 82 bar Comb Cycled 82 bar Comb Cycled

Export to grid 0 24 54 126 174 216 348Total generation 12 36 72 162 210 252 384Remaining total b - b c 23 59 149 197 239 371

a Assumes that all field trash is used. Assuming 50% used, total potential generation from 82 bar steam turbines would be 207 TWh and from gasifier & combined cycle plants it would be 297 TWh.b As observed in the text, estimated generation from sugarcane in 2006 was about 13 TWh. This value is subtracted from the projected total potential generation to calculate the remaining potential with that technology option assuming all sugarcane is used for that option. c In the case of the 22 bar steam turbine option, existing generation (with 660 million tons of cane) is already slightly greater than would be produced from 1.2 billion tons in 2030. Thus the “remaining total potential” is zero. This is because many existing mills already have 42 bar or higher steam turbines. The 22 bar technology is already obsolete and is not suggested as an option for future plants..d Plants with biomass gasifier & combined cycle technology are not yet technologically proven.

Today, most projects for new or retrofit capacity are designed to operate at 67 bar and do not assume the use significant amounts of field trash. Thus, a “business as usual” scenario might project something like 60 TWh of new generation by about 2030. The sugarcane processing industry is quite conservative and even this modest scenario implies improved electricity pricing in many countries, even though new 67 bar capacity can be economically competitive.

Going to higher steam pressures and using more field trash do not need technical breakthroughs and might add 100-150 TWh. Gasification would push potential up another 30-40% but it’s impact until 2030 would be substantially less, since even if a successful development program were launched now, commercial deployment would be unlikely before 2020.

The possible contribution of generation from sugarcane to the mix of supply for future expansion in the region will be discussed in Section 7.

16 In 2006, total generation from sugarcane in Brazil was 8.4 TWh, rising to 11.1 TWh in 2007. Sugarcane production increased by 15% between 2006 and 2007, which explains about half of this large increase. In 2006 Brazil produced 69% of the region’s sugarcane. New plants have at least 40 bar pressure and usually more, thus increasing the average coefficient of kWh/tc of the industry.

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6. Solar Energy

There are two basic technological approaches to generating electricity from solar radiation. They have very different characteristics.

Solar thermal generation technology heats a fluid which is converted to mechanical energy in a heat engine based on a thermodynamic cycle – usually Rankine. In order to increase thermodynamic efficiency, sunlight is usually concentrated in order to achieve higher temperatures and hence greater efficiency.

Photovoltaic (PV) technology converts radiation to electricity in semi-conductors. PV arrays with crystalline silicon are the most common and include the most efficient configurations. Non-crystalline arrays and other semi-conductor materials are also being used.

From the perspective of the electrical system, the most important difference between these two approaches is that the PV is inherently far more adapted to small scale decentralized (or “distributed”) generation applications. PV systems can be installed in peoples’ residences to supply a part of their power. Solar thermal electric systems are >1 MW and more complex to operate. They are equivalent to other central station power plants, which must be operated by utilities or specialists (IPPs) selling to the grid.

Photovoltaic systems come in two basic types: flat plate and with concentrators. An advantage of the concentrators is that the relatively expensive PV surface area is much reduced. On the other hand, concentrator systems depend on direct radiation to operate. Flat plate PV arrays can use indirect or diffuse radiation as well. This characteristic of PV concentrator systems is shared with solar thermal systems and makes them suitable only in regions with very low nebulosity, such as deserts. These systems are also more complex and thus are likely to be owned and operated by utilities in centralized facilities.

The efficiency of solar thermal plants depends on the temperature of the heated working fluid, which depends in turn on the factor of concentration of sunlight achieved. The most common configuration is parabolic trough concentrators, shown in Figure 6-1. A more recently installed configuration is heliostats which reflect sunlight onto a central tower. The capacity of a parabolic dish is too small to be of much interest for electricity generation.

Figure 6-1: Configurations for solar thermal plantsSource: NAS/NAE, 2009

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The efficiency of PV systems depends on the semi-conductor materials used and their configuration. There is also a large difference between the best efficiencies achieved in experimental lab-scale PV cells and commercially deployed modules. The best flat plate single crystal silicon experimental cells have achieved 25% or more, while multicrystalline cells achieve 20%. Commercial flat plate silicon crystal modules now typically achieve 13-15 %.

Triple junction III-V compound modules with concentrators have achieved an extraordinary 41% efficiency at very high factors of concentration - 380 times the sun’s intensity (NAS/NAE, 2009).17

At the other end of the spectrum, thin films of amorphous silicon or other semiconductor materials have achieved only 12 % in the lab and 50-60% of that level in commercial moduless. However, there are cost advantages to this approach. The thin films are laid down on low cost substrates, such as plastic or glass, and use 1/10th to 1/100th the quantity of expensive semi-conductor material used in crystalline cells. Manufacturing technology is simpler and many processes are continuous. Module fabrication, involving the interconnection of individual solar cells, is usually carried out as part of the film deposition process. The resulting cost per m2 of module surface area is much lower than for single crystal or polycrystalline silicon arrays (USDOE, 2007). Unfortunately, the thin film modules’ performance degrades more rapidly than that of the crystalline arrays. Whereas a lifetime of 20 years may be assumed for the latter, 15 years is the current limit for thin films (ESMAP, 2007).

Finally, there are emerging technologies such as dye sensitized nanocrystalline titanium dioxide films, cells based on organic polymers and cells based on other nanomaterials (USDOE, 2007). TiO2 cells have achieved 10% efficiency in the lab. Organic semiconductors hold promise as building blocks for very low-cost solar cells. Organic solar cells can be about 10 times thinner than thin film solar cells. The basic materials are cheaper and high-volume production techniques could be used. However, efficiencies are still relatively low (6-7% in the lab) and stability of the compounds is an issue.

The amount of incident solar radiation is so vast that electricity needs could in theory be satisfied even with modest levels of efficiency of conversion of sunlight into electricity. For example, assuming only 100 kWh per m2 of PV solar arrays, the area required to generate all of Latin America’s electricity would be less than 12,500 km2. This is a very much smaller area than that now covered by hydro plant reservoirs in the region. To calibrate 100 kWh/m2, look at Map 6-1 below, which assumes an efficiency of 11.5% for a PV system (14% for individual modules). The search for improving efficiency has much more to do with improving the economics of solar energy than with increasing the potential output. The real challenge is to maintain efficiencies already achieved while using lower cost production techniques (e.g. silicon), or to increase the low efficiencies of concepts with clear potential for low cost production (e.g. organic polymers).

The geographic distribution of the quality of solar PV potential is illustrated in Map 6-1, in terms of annual kWh of electricity generated per m2 of array area. Since the estimate is for flat panel PV arrays, this is a function of total and not just direct radiation. The best potentials are not

17 The III and V indicate the column location of elements in the Periodic Table. Compounds based on these are the materials for modern optoelectronic devices typically used in high-speed transistors. In this case the triple junction is based on GaInP2/GaInAs/Ge which was developed originally for space applications. Most concentrator systems are less intense (10-50 times), use silicon crystals and achieve efficiencies on the order of 25% in laboratories.

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found near the equator, given the humidity in most places. Dry areas and those at higher altitudes have higher potential per m2 of array. In Latin America the very best areas are in the deserts of northern Mexico as well as the Andean highlands and the dry Pacific Coast.

Map 6-1: Annual solar photovoltaic potential (kWh/m2) - WorldSource: Czisch, 2004.

Compared with wind, there is much less difference in the average annual energy output per kW of installed capacity between areas with excellent potential and those with merely average potential. This means solar is less site dependent than wind energy, at least if we consider flat plate PV technologies. The deployment of solar thermal and concentrator PV systems would be much more geographically restricted.

A key characteristic of solar energy is its variability. Besides the diurnal cycle, when output falls to zero, there is also a predictable seasonal variation. At higher latitudes the amplitude of this seasonal variation is very large – summer output is about 4-5 times higher than winter at 50º North or South. At the lower latitudes of most of Latin America the seasonal variation of total radiation is much less pronounced, which is advantageous for the economics of solar energy in the region.

The PV industry grew at more than 40 % per year worldwide from 2000 through 2008. Much of this growth is the result of national programs targeted toward growing the PV industry and improving PV’s competitiveness in the marketplace. In 2007, PV modules supplying 3.4 GW were produced worldwide – though deployment in Latin America was tiny. Growth in solar thermal has been smaller.

Despite this impressive growth, the generation of electricity directly from solar radiation is still far too expensive to be considered a significant option for supplying electricity to the grid. The

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more viable applications are found in off-grid situations, usually in isolated localities with very small consumption, where alternatives are also very expensive.

The costs per kW of installed capacity have been falling substantially and are projected to fall further in the future. One analysis suggests of the evolution of PV costs suggests that the prices of PV modules have followed a historical trend along the “80 percent learning curve.” That is, for every doubling of the total cumulative production of PV modules worldwide, the price has dropped by approximately 20 percent. This trend is illustrated in Figure 6-2.

The final historical data point shown for 2003 corresponds to about $3.50/Wp and a cumulative PV capacity of 3 GW. From 2003 until 2008 the price of PVs does not seem to have decreased substantially. This may have been a result of the boom in commodity prices in general and the tight supply for PVs given the rapid expansion of demand (production of PVs in 2007 was larger than the cumulative installed capacity in 2003). A similar price inflation was observed during this period with wind turbines.

Figure 6-2: Learning curve for photovoltaic costsSource: NAS/NAE 2009

The cost of the module is only about 50% of the total cost of the PV system. Generic estimates made by ESMAP/World Bank suggest that the capital cost of a 5 MW plant for the grid would be about $7,000/kWp in 2005, falling to $5500 by 2015 (ESMAP, 2007). Assuming a discount rate of 10%, a lifetime of 20 years and a capacity factor of 20% the levelized capital cost per MWh would be $473/MWh, falling to $369/MWh in 2015. To this must be added an O&M cost of $1.20-11.00/MWh.18 The generation costs per MWh are many times higher than those of other renewable energy technologies.

18 The lower value is from ESMAP, 2007. The higher value is based on a fixed O&M cost of $10-20 per year per installed kW in the United States (NAS/NAE, 2009).

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The high economic cost of PV systems has some relationship with another less obvious problem - the large amount of energy needed to fabricate crystalline silicon cells. It typically requires several years to “pay back” this energy investment, much more than other generation technologies (NAS/NAE, 2009). With technological innovation the tendency is for this payback period to decrease (or the “External Energy Ratio” to increase) and with thin films and other emerging technologies the payback time could be less than one year. This improvement will be important, because a relatively long payback period together with rapid growth can seriously reduce the effective net contribution of new generation capacity, as illustrated in Figure 6-3.

This is very simple illustrative example of the net fossil fuel (or, better, energy) displaced by rapidly introducing a renewable technology with a payback time of 4 years (fairly typical of historic paybacks for PV). In this case one unit of renewable capacity is introduced each year over a five year period (the green line shows the cumulative renewable output). The graph then shows the units of fossil energy required to produce the new renewable technology capacity (red line). Over the five years of deploying the renewable technology, the net contribution is negative (black line).

Figure 6-3: Simple illustrative example of cumulative net fossil fuel Displaced by a hypothetical renewable technology

(Assumes all energy input to fabricate renewable capacity is fossil fuel)

Source: NAS/NAE, 2009

Although the graph is a great simplification, something like this situation probably occurred during the recent years of rapid expansion of PV capacity.

A major reduction in the projected future cost of PV modules depends on advances with thin films, concentrator systems, or other new technologies. The graph in Figure 6-2 projects the path of future costs under historical learning rates as well as with slower and faster rates of learning.

Solar thermal electric generation is substantially cheaper than photovoltaic today. The ESMAP/World Bank study estimates an investment of $2480/kW in 2005 falling to $ 1960 in 2015 for a 30 MW plant without storage. A longer lifetime (30 years) is also assumed. Thus the levelized capital cost would be about $ 150/MWh falling to $ 120/MWh in 2015.

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An equivalent plant with storage is assumed to have an investment of $4850/kW, falling to $3820 in 2015. The storage is assumed to increase the capacity factor from 20% to 54%. Such a high capacity factor seems optimistic. Capacity factors cited in NAS/NAE, 2009 generally do not exceed 35%. Depending on the capacity factor, the range of levelized capital costs for plants might thus be between $110 and $170 per MWh.

While this is substantially lower than the capital cost of photovoltaics, it is still expensive. There is another problem, which limits the potential for solar thermal generation: the need for cooling water. Solar thermal generation plant would be more or less restricted to arid regions where water is usually scarce.

There is in fact a wide range in the projections of future solar energy costs. For example, the most optimistic estimates of future levelized costs per kWh for PV systems are ¼ - ⅟5 the cost of the most pessimistic estimates for equivalent time horizons (from 2020 to 2035). The more optimistic projections tend to be based on targets.

Solar electricity is likely to remain expensive over the main time horizon of this report (~20 years) compared to other renewable energy technologies. However, over a longer time frame technological advances may make solar energy more competitive. It bears remembering that photovoltaics are part of a family of semi-conductor science & technologies which have already wrought huge revolutions in our economic life. Large improvements in PV cost and durability can’t be predicted, but they are certainly possible. On the other hand, the potential to dramatically reduce solar thermal generation costs is much more limited.

It is quite possible that solar energy will first have a significant impact on the grid’s supply of electricity via decentralized or “distributed” applications on consumers’ premises. Photovoltaics have very small, if any, economies of scale – different from most electricity generating technologies. For example, in the ESMAP/World Bank study (ESMAP, 2007) the total investment per kW capacity in a 50 Watt PV system is 6% higher than in a 5 MW system which is 100,000 times larger. Even this may overstate (or invert) the difference, since the 50 Watt plant is assumed to have a battery storage sub-system which is absent from the 5 MW plant (in the same study there is no change in cost per kW with systems ranging from 50 W to 25 kW, which all have battery storage).

If one considers consumers connected to the grid instead of isolated systems (which was the emphasis of the ESMAP/World Bank study), there is no inherent reason why consumers interested in PVs for a relatively small part of their consumption should also invest in expensive battery storage, at least beyond a very small capacity to facilitate the interface with the grid. This is especially the case in Latin America, where in most countries electricity supply is quite reliable. In any case, the decision to install substantial battery storage would be more of a result a judgment about the reliability of the grid’s supply than of the desire to have a solar complement.

While on the one hand there is almost no economy of scale for PVs, there is definitely an economic benefit from generating power at the point of use. The price paid by low and medium voltage consumers is usually much higher than the wholesale price paid to generators, at least in countries where electricity prices are not heavily subsidized. An investment in a 3-400 Wp

system (less than 2 m2 of PV module in many places of Latin America) could cost less than $2000 within a decade long. Meanwhile, a whole constellation of new “smart grid” technologies could play a key role facilitating the entry of solar PV systems in consumers’ buildings and homes, in a way that is still unthinkable almost everywhere in Latin America today.

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Finally, another aspect of the decentralized supply of solar energy deserves mention. While the focus here is on electricity generation, it should be noted that technologies for solar water heating can substitute directly for electricity use in tropical/subtropical countries, such as Brazil, where electricity is commonly used for residential hot water. Modest systems designed to substitute only a part of the hot water supply can be quite inexpensive and deserve much more attention than they have received. There are also more limited, but interesting, opportunities to bring solar radiation into buildings for lighting – “passive lighting” systems, as it were.

7. Renewable Potentials in the Context of Future Growth

What might the contribution of renewable energy sources be to the future expansion of generation in Latin America? This section attempts to provide a preliminary overview of the possibilities.

In order to establish a reference against which to compare the estimates of potential made earlier, a very simple scenario of growth in total generation has been prepared. It is assumed that by about 2030 electricity generation would have grown by 2000 TWh. The increase has deliberately been set relatively high - equivalent to a growth rate of 4.3% per year from the base of 1225 TWh in 2007 (between 1998 and 2007, the growth rate was 3.7%).

The purpose of this paper is only to analyze potentials, not to provide an expansion plan. The objective of the scenario is thus simply to roughly calibrate the estimated contributions of different kinds of resources to Latin America’s expansion over the coming 20-30 years. From this perspective, it is not important whether the increase of 2000 TWh has occurred by 2028 (4.7% per year) or by 2035 (3.5% per year). Given the large uncertainties surrounding estimates of the potential of different resources, precision in estimating the rate of exploitation would be a distraction at this stage. Factors which influence the rate of exploitation are mostly quite distinct from those which set the underlying potential.

Returning to the present, in 2007 the share of renewables was about 59.3% of the total generation. Of this, 56.7% was from hydropower and about 2.6% from other renewables.19 The tendency has been for this proportion to fall slightly over the past two decades or so.

If Latin America is to simply maintain this proportion of ~60% renewable electricity supply over the next 20-30 years, one point seems clear: the use of renewable resources other than hydro must expand, probably dramatically.

In the section on hydropower it was estimated that somewhere between 800 and 1360 TWh of economically and environmentally viable potential remain to be developed. This means that hydro might provide as little as 40% of the total increase, assuming that all of the potential were developed in this time frame. In the most optimistic hydro scenario (which assumes that 70% of the total potential of about 2900 TWh in Table 2.5 can be developed), there would in principle be enough hydro resources to supply ⅔ of the 2000 TWh of growth.

However, it seems highly unlikely that all the remaining hydropower potential in Latin America could be developed within the next 20-25 years, especially in the higher scenarios of exploitable potential. Hydro resources are unevenly distributed and take time to develop – some are

19 Of this 16-17 TWh is estimated to be from sugarcane biomass and 15.2 TWh from everything else.

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located in remote areas. Brazil, which has 40% of the region’s hydro resources and more than half the production today, is very unlikely to exhaust the development of its hydro resource within the next 20 years. Outside of Brazil, three countries – Colombia, Peru and Ecuador – have more than half of the remaining potential and currently use less than 10% of it. Unless their hydro output is somehow integrated into the supply of other countries in the region there will simply not be a market for much of their potential in this timeframe.

Development of most of the viable hydropower potential in the region by around 2030 implies a degree of interconnection and international commerce in electricity which is barely being discussed today.

In order to visualize the challenges, three simple scenarios have been prepared.. a. In the most pessimistic case only ~800 TWh of hydro remains to be effectively exploited

and 90% of it is developed in the period over which generation expands by 2000 TWh.b. In a moderate case, ~1080 TWh remain to be exploited and 85% are developed in the

period.c. In an optimistic case, ~1360 TWh remain to be exploited and 80% are developed in the

period.Table 7-1 summarizes the consequences.

Table 7-1: Scenarios to maintain a 60% share of renewables for next 2000 TWh of growth

Hydropower Remaining Built in Share of Other Renewables toScenario Hydropower Period Growth in Period To Maintain 60% Share

TWh TWh % % Growth Δ TWhLow 800 720 36.0 24.0 480Medium 1080 920 46.0 14.0 280High 1360 1090 54.5 5.5 110

Even in the most optimistic (high) hydropower case, the share of “other renewables” must double in order to maintain a 60% share. In terms of TWh, the increase is bigger: 110 TWh versus ~32 TWh generated today from “other renewables”. In the medium hydropower case, one sees a nine-fold increase, to 280 TWh. In the low hydropower case, a fifteen-fold increase.

A parallel study has been prepared for the World Bank which synthesizes projections from governments of the region and performs sensitivity analyses of the impacts of oil and carbon prices on the mix of generation in 2030.20 It was made available to the author after the analysis in this paper had been completed.

The results of this separate study of supply and demand balances reinforce the conclusion that the regional share of hydro is tending downwards over the coming decades. In all the scenarios, it is expected that only 48% of expansion will be from hydropower (see Box). This is very close to the share in the medium scenario of Table 7-1. However, the projection of total generation growth is much smaller - about 1140 TWh of new generation output by 2030, equivalent to a growth rate of 2.9% from 2007.

20 The study cited is an input for Part II of the World Bank report Latin America and Caribbean Region’s Electricity Challenge, which is currently in preparation. This paper on the potential for renewables is an annex for the same report.

65

A parallel perspective of the contribution of hydropower to 2030

The separate analysis of supply & demand balances cited in the text provides a useful snapshot of the perspective of planners in the region. Several results stand out from the sequence of scenarios summarized in the figure showing Latin America’s generation mix in 2030 under different scenarios of prices for oil and CO2.

A B C D EScenarios

Despite the large differences in fossil fuels` prices there is no significant change in the projected share of nuclear or renewables, especially hydropower. The share of hydro is apparently seen as a kind of maximum feasible level, with no sensitivity to fuel prices. What happens is a play between natural gas and coal, with a bit role for fuel oil.

Scenario A, with low prices for oil (US$ 50/b) - and implicity, natural gas – has a large share of natural gas in the generation mix.

Scenario C, with high oil & gas prices (US$ 150/b), has a large coal supply (while gas almost disappears and fuel oil increases a bit).

Scenario E, with medium oil & gas prices (US$ 100/b) and high CO2 prices ($50/t CO2) returns to almost the same mix as Scenario A. Increasing the CO2 price increase the relative cost of coal.

Overall, hydro’s share of the region’s expansion is projected to be substantially smaller than the historical share, as is shown in the table. The contributions of all other renewable energy resources remain tiny.

Share in 2007 Share of expansion 2007-2030Hydro Nuclear Other Hydro Nuclear Other

Latin America 57% 2,4% 41% 48% 8% 44%Southern Cone 49% 3% 48% 33% 34% 33%Brazil 83% 3% 14% 77% 4% 18%Andean 71% 0% 29% 51% 0% 49%Central America 45% 0% 55% 55% 0% 45%Caribbean 8% 0% 92% 9% 0% 91%Mexico 12% 4% 84% 3% 0% 97%

66

-

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

2030 @ LowCrude price

2030 @Medium Crude

price

2030 @ HighCrude price

2030 @ HighCrude pricewith MediumCO2 price

2030 @Medium Crudeprice with High

CO2 price

GW

hr

Nuclear

Hydro

Geothermic

Gas

Fuel Oil

Wind

Diesel

Coal

Biomass

Assuming the projections of hydropower expansion in this parallel supply/demand analysis, the increment of “other renewables” needed to maintain a 60% renewable share would be about 140 TWh, almost a five-fold increase over today.

This kind of acceleration would clearly pose a big challenge for policy. However, judging from the analysis in the previous chapters, it seems possible from a physical perspective to achieve even the higher levels of generation from “other renewables”. This is also probably true from an economic perspective if there is some form of credit for reducing greenhouse gas emissions relative to fossil fuel thermal plants. We briefly review the different renewable resources and some factors influencing their possible contributions..Wind has the largest potential of the non-hydro renewables over the coming several decades and is the possible “game changer” in the region. As described in Section 3, the ability of a system to absorb a share of wind capacity up to 20% of total capacity (or 9-14% of generation output) without high reserve costs now seems to be widely accepted. In this case, assuming a regional system with ~3200 TWh of generation (i.e with 2000 TWh of growth), wind could supply 290-450 TWh. Assuming the lower projections for 2030 descroibed above (about 2400 TWh), the limit on wind would be about 210-330 TWh.

Reaching the higher values by 2030 seems problematic, simply in terms of deployment. Beyond some point (perhaps 150-200 TWh) stronger intra-regional interconnections will be very desirable to provide complementation. This would be an extension of the stronger interconnections already recommended for the optimized development of hydropower in the region. In general, the large share of hydro in Latin America should facilitate the absorption of wind power.21

The wind resource base in some countries may be too small to reach 20% of capacity, though others have abundant high quality resources and overall Latin America’s potential from high quality resources is probably substantially larger than the 450 TWh “ceiling” set from the perspective of system integration. This report has focused on higher quality wind potential – at least “Class 4” (7.0 m/s or more) or even “Class 5” (7.5 m/s) - because higher capacity factors can be obtained, which substantially reduces the cost gap with conventional fossil fuel generation technologies.

Biomass, particularly sugarcane residues, could make a significant contribution, whose size depends on what standard of technology the sugarcane mills adopt. The current tendency is install new generating plant with 67 atmospheres (bar) pressure steam. More aggressive policies might take the standard to 80+ bar. At the same time, mechanization of the harvest and prohibitions on burning field trash in the field are opening the possibility of increasing the fuel available for generation. Based on the discussion in Section 5, Table 7-2 provides a simple matrix of possible outputs for the grid, depending on the technology and the degree of use of field trash as fuel.

21 Hydro has characteristics which facilitate the incorporation of both wind and solar into the grid. The technology is well suited to ramping and load following – even better than turbines using natural gas. In addition, storage capacity permits adjustments to variations from average output - though, planners should avoid naïve schemes to use hydro to provide base load power from wind. The terms of the contracting of wind power in Brazil’s auction described in Section 3 – which set only annual production targets – are a practical illustration of the benefits of a hydro system.

67

Table 7-2: Illustrative matrix of generation options from sugarcane residues(TWh/year sold to the grid) a

67 bar 82 bar BIGTCC b

Assume 1/4 capacity using trash 54,9 139,4 208,3Assume 1/2 capacity using trash 64,9 161,9 251,8Assume 3/4 capacity using trash 74,9 184,3 295,2

a Values refer to the electricity which could be sold (or “exported”) to the grid and refer to the possible increase between 2006 and 2030. Each value assumes that all the sugarcane output in 2030 goes to that option. For more information see the notes to Table 5-5.b The technology option “Biomass gasifier with combined cycle gas turbines” is not yet technically proven.

If 67 bar technology were used and ¼ of plants used field trash for fuel, an increase of 55 TWh would be possible, compared to about 9 TWh sold to the grid in 2007. This might not be far from the trend already underway.

If there were a jump to 82 bar steam technology and ½ of plants used field trash for fuel, something like 160 TWh might be sold. If there were a technology breakthrough in gasification/combined cycle plants (BIGTCC) then export to the grid could grow substantially more. However, such a breakthrough (if it happens at all) seems unlikely to occur in time to substantially impact output much before 2025

The values here assume a sugarcane industry growing at 2.5%/year – roughly the historic rate of the previous decade. This implies that there is no large expansion of sugarcane for ethanol production and also that few, if any residues are diverted for the production of liquid biofuels from cellulose. Other sources of biomass (residues of the pulp and paper industry, rice, urban solid wastes) may also add some to the expansion of electricity generation from biomass, though they have been relatively small historically.

Geothermal potential is something of an incognita. Published analyses are minimal. By analogy with the United States, where there has been more exploratory drilling, the potential of “conventional” hydrothermal resources might be almost 300 TWh per year throughout Latin America. Of this, perhaps 125 TWh might conceivably be developed by 2030, compared with the 11 TWh currently generated.22 This hydrothermal potential would be concentrated along the tectonically active Pacific Rim from Mexico to Chile and in some Caribbean islands.

If there is a breakthrough in the use of nonconventional geothermal resources, especially from deep hot dry rocks (HDR), the potential output would be substantially increased. However, such a breakthrough is far from certain, especially considering problems with the induction of earthquakes which have been encountered in the course of fracturing the reservoir.

Solar electricity generation also depends on breakthroughs to reduce costs if it is to contribute seriously to supply on the grid, though off-grid applications will probably grow. No estimates have been made in this report. In the nearer term, solar thermal applications – especially for water heating – could substitute for electricity in some tropical/subtropical countries. This option deserves attention.

*****

22 This value is equivalent to what might be developed in the USA by 2015, adjusted to account for land area and a heat flux which is 25% higher on average than in the US/Canada, as discussed in Section 4.

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Considering the non-hydro renewable resources discussed above, it should be possible to maintain the current average share of renewables of around 60%. This is true even under the pessimistic projection of hydro in Table 7-1 of only 720 TWh, or 36% of expansion, though the challenge would be huge. This scenario would require about 480 TWh of new output from these sources. From the brief review above it is clear that much turns on whether wind can fulfill its promise:

Wind: 290-450 TWh (with the lower projections to 2030 cited above, 210-330 TWh)Sugarcane: 50-150 TWhGeothermal: 25-125 TWhSolar: probably small, not evaluated

Even the low scenario for wind would represent a dramatic change from today. Sugarcane (and biomass in general) are more limited but still important. The low scenario here is practically “business as usual”. Geothermal is very uncertain, but is probably the smallest of the three resources. In the case of the supply/demand projections cited above II, where generation increases less, the gap of 140 TWh is actually quite small relative to the potentials.

In more optimistic hydro scenarios, covering, say 45-55% of expansion, an accelerated scenario of other renewables (say 350-400 TWh) would provide the basis for an increase in the total share of renewables. This possibility has not been analyzed in this paper, in part because Latin America’s share of renewables is high by world standards. However, the goal of reducing or even stabilizing GHG emissions worldwide could make this increase desirable – especially considering the difficulties which may be encountered in other sectors of energy use.

Evidently, the mix of renewables would vary considerably among the different parts of Latin America given their distinctive resource endowments. Argentina is particularly rich in wind. Brazil has large hydro, biomass and wind resources, but very little geothermal. Central America has relatively large hydro, biomass and geothermal resources, but high quality wind resources there may be limited.

The Caribbean islands present challenges which are very distinct from the rest of the region. Possibilities for interconnection, which will probably be important for accelerating utility scale renewables elsewhere, will mostly not be feasible. The cost of renewable strategies will be higher and possibilities for complementation will be less. Solar may have a larger role sooner. The use of biomass probably needs to have a larger weight and attention given to diverse feedstocks. Geothermal energy could be an interesting possibility on some volcanic islands.

This report has emphasized defining better the possibilities for renewable energy development, not the probabilities. There are considerable policy challenges involved, whose discussion goes beyond the scope of this report. At a more elementary level there is a paucity of reliable information on potentials to orient policy makers on where the opportunities are and how big they really are. There is an urgent need to invest in seriously improving the quality and quantity of information and analyses available on renewable resource potentials. Individual countries need to take the lead in this endeavor, but multilateral agents could play an important supporting role. Annex D summarizes some specific points where such support seems useful.

69

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Annexes

Annex A: Comparison of Estimates of Hydropower Potential in Latin American Countries

To complement the country by country breakdown of Table 2.5 in the main text, based primarily on OLADE’s summary of hydropower potentials (OLADE, 2008), this annex compares it with another breakdown prepared by the Union of the Electricity Industry, a European entity (Eurelectric, 1997).

In the table below, Column A shows the estimates summarized by OLADE and column B those by Eurelectric. Column C compares the values in percentage terms. Where the OLADE value is >20% higher, the percentage is in red. Where the OLADE value is less than 80% of the Eurelectric estimate, it is shown in green.

Table A-1: Comparison of country estimates from two sources

Country A B COLADE, 2008 Eurelectric, 1997 A/B

TWh TWhArgentina (130) 354 172 (76%) 206%Bolivia 5 50 10%Brazil (1213) 1490 1115 (109%) 134%Chile 27 130 20%Colombia 420 415 101%Costa Rica 28 35 80%Cuba 1Ecuador 97 120 81%El Salvador 9 4 237%Guatemala 15 40 38%Guyana 20 60 33%Haiti 0 0 124%Honduras 22 24 91%Jamaica 0 0 53%Mexico 232 160 145%Nicaragua 8 7 119%Panama 14Paraguay 55 40 137%Peru 385 410 94%Rep Dominicana 9 3 352%Surinam 11Trinidad & Tobago 0Uruguay 8Venezuela 201 260 77%Total (2.911) 3412 3045 [3530]

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The Eurelectric analysis has some relevant characteristics for the comparison. First, it is not complete. There are no estimates for countries such as Panama, Surinam and Uruguay. Second, the regional total for Latin America shown in Table 2-3 of the main text assumes an explicit increase to the sum of the individualized country values, as shown in Table A-2.

Table A-2: Share of individualized country estimates in total regional potential (Eurelectric, 1997 – page 20)

Since North America was assumed to be surveyed at the same level of detail at the country level (USA, Canada & Greenland) as Europe (in the wide definition of Europe used – including the European part of the former Soviet Union, or CIS), this “regional adjustment” factor was applied entirely to Latin America when preparing Table 2-3. Rather surprisingly, the resulting regional totals – 3530 TWh/year for Latin America - are the same as those from an earlier study of technical potential (IWP&D, 1989) also summarized in Table 2-3. This value is shown in brackets in Table A-1 above

Although the Eurelectric paper refers to these values as being for “economic” potential, in the case of Latin America at least, they are really for the “technical” potential, which is less restrictive.

The original OLADE estimate of potential for the region – 3412 TWh is close to the overall technical potential estimate of 3530 TWh from Eurelectric (and ultimately IWP&D, 1989). At an individual country level there are some massive differences – with both much higher and much lower estimates from OLADE.

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Annex B-: Wind farms in Latin America

The locations and characteristics of wind farms in Latin America are summarized in the tables below, based on the Latin American Wind Energy Association website. Unfortunately, information is not provided on wind farms in most Caribbean countries. Countries are listed in the order of the size of their wind generation capacity in 2008.

Brazil

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

OSORIO: Sangradouro, Osorio, Dos Indios Rio Grande do Sul 150 75 2 2006

Rio Do Fogo Rio Grande do Norte 49,6 62 0,8 2006

Agua Doce Santa Catarina 9 15 0,6 2006

Horizonte Santa Catarina 4,8 8 0,6 2003

Bom Jardim da Serra Santa Catarina 0,6 1 0,6 2002

Central Eólica Experimental do Morro do Camelinho  Minas Gerais 1 4 0,25 1994

Taíba Ceará 5 10 0,5 1998

Prainha Ceará 10 20 0,5 1999

Mucuripe Fortaleza, Ceará 2,4 4 0,6 2002

Palmas Paraná 2,5 5 0,5 2000

Macau Rio Grande do Norte 1,8 3 0,6 2004

Olinda Pernambuco 0,3 1 0,3  

Eólica de Fernando de Noronha Pernambuco 0,225 2    

Millennium Matacara/Paraiba 10,2 12 0.85 2007

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Mexico

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

La Venta I Oaxaca 1,5 7 0,225 1994

La Venta II Oaxaca 83,3 98 0,85 2007

Guerrero Negro Baja California 0,6 1 0,6 1998

Cementos Apasco* Coahuila 0,5 1 0,5

*En

reparació

n

Costa Rica

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

Tejona Guanacaste 19,8 30 0,66  

Central Tilarán PESA Guanacaste 19,8 60 0,33 1996

Molinos Viento del Arenal S.A. MOVASA Guanacaste 24 32 0,75 1999

Aeroenergía   6,75 9 0,75 1998

Argentina

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

Antonio Morán, Comodoro Rivadavia Chubut 17,7 26 2(0.25)/8(0.75)/16(0.7) 94/97/01

Pico Truncado (Jorge Romanutti) Santa Cruz 2,4 4 0,6 2001/2004

Punta Alta Buenos Aires 2,2 4 1(0.4)/3(0.6) 1998

General Acha La Pampa 1,8 2 0,9 2002

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M. Buratovich Buenos Aires 1,2 2 0,6 1997

Tandil Buenos Aires 0,8 2 0,4 1995

Darragueira Buenos Aires 0,75 1 0,75 1997

Claromecó Buenos Aires 0,75 1 0,75 1998

Cutal-Có Neuquén 0,4 1 0,4 1994

Rada Tilly Chubut 0,4 1 0,4 1996

Barrick Veladero 2 1 2 2007

Colombia

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

Jepirachi La Guajira 19,5 15 1,3 2004

Chile

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

Alto Baguales XI región 2 3 0,66 2001

Canela Coquimbo 18.15 11 1.65 2007

Peru

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

Mal Abrigo   0,25 1 0,25 1996

San Juan de Marcona   0,45 1 0,45 1999

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Cuba

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

Isla Turiguano Moron, Ciego de Avila 0,45 2 0,225 1999

Los Canarreos Isla de la Juventud 1,65 6 0,275 2007

Gibara Holguín 5,1 6 0,85 2007

Ecuador

Wind Farms Location Farm # Turbine DateCapacity-MW Generators Capacity-MW On Line

San Cristobal Isla Galapagos 2,4 3 0,8 2007

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Annex C: Wind Energy Potentials in Selected Countries

“Southern Cone” - Argentina/Chile

Argentina probably has, by far, the largest potential from high quality wind resources of any country in Latin America. Unfortunately, there has been relatively effort to define this resource and there has not been the kind of simplified systematic review of potential, as Brazil has made. This is consistent with the tiny investment so far in wind power. However, the little analysis and organized information that is available suggests that Argentina could be a kind of “Saudi Arabia” of wind. Map C-1A shows the average annual wind speeds at 50 m height. Note the relatively large areas in Patagonia with average wind speeds over 9 m/s, that is Class 7. Going down to 8 m/s (class 6) more than doubles the already large area. Map C-1B shows approximately the areas which are class 4 or higher.23

Map C-1: Average wind speed at 50 m and areas class 4 or higher

AAverage daily wind speed over a year –

Argentina at 50 m

BAreas with an estimated capacity factor

higher than 35% at 70 m

Source: CADER, 2009; Centro Regional de Energía Eólica - Ministerio de Planificación Federal, Inversión Pública y Servicios

23 In the original, the boundary is a capacity factor of 35% or higher at 70 m height, which seems to be follow the contours of average wind speeds above 7 m/s.

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Considering that Argentina covers 2.8 million km2, the class 7 area probably exceeds 100,000 km2. The area covered by class 5 or higher probably exceeds 420,000 km2. That would be 14 times the equivalent areas in Brazil, which were summarized above. The gross technical potential is simply huge: for class 7 areas alone it could be 600 GW or 2200 TWh/year.

Average wind speeds are higher in the summer than in the winter, as shown in Figure C-1. There appears to be some complementation with hydro output, which tends to peak in the winter (June-September). On a daily basis, winds are almost always highest about 6 pm, throughout the year, as shown in Figure C-2.

Figure C-1: Patagonia - Average daily wind speeds at 60 m height during a year

Figure C-2: Diurnal wind speeds with averages for months of different seasons at 60 m Source: CADER, 2009

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There is legislation to promote renewable energy for the grid in Argentina. Law 26,190 of 2006 set a target of 8 % of electricity generation to be produced by renewables by 2016. This could mean an expansion of 2500 MW from renewable sources, according to the Secretariat for Energy. In principle this could be a major near term impulse for the wind energy industry in Argentina. There is a fund to subsidize producers by 15 pesos per MWh. Unfortunately, in the market context of Argentina – with high regulatory uncertainties – this is probably not a sufficient incentive to be effective (CADER, 2009). In addition, there is no penalty for non-compliance with the target.

Brazil

Among South American countries, Brazil has undertaken the most systematic mapping of its wind energy resource and has gone furthest in implementing projects. Map 3-2 shows the distribution of wind resources in the country. The best areas are found along some parts of the coast and in some mountainous areas in the interior.

Map C-2: Brazil – Average annual wind speeds at 50 mSource: CEPEL, 2001

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The seasonal variations in average wind output appear to be roughly complementary to average variations in the flows of Brazil’s large hydro system. That is, average wind speeds are higher in winter (June – September), which is the dry season.

Quantitative estimates of the gross potential were discussed earlier (see Tables 3-4 thru 3-6 in the main text) to illustrate issues encountered in dimensioning the potential wind resource. Gross potential in areas with Class 5 potential or better might be ~620 TWh, depending on the parameters used. Relaxing the criteria to allow Class 4 would substantially increase the gross potential to about 1900 TWh.

Of course, as discussed earlier, these are values for the gross potential and only a relatively small fraction could ever be developed. Even so, wind power could make a very significant contribution to the expansion of Brazil’s generation over the next two decades if there were the appropriate policies.

Brazil jump-started its wind sector with the PROINFA program. This was originally intended to implement 3300 MW of renewable capacity divided equally between wind, small hydro and biomass projects. Long term power purchase contracts were offered with guaranteed prices. Implementation has been slow and partial, but even so the program catapulted Brazil into being the leading country in Latin America in terms of installed capacity.

In December, 2009, an auction will be held specifically for new wind power projects. This will mark a new phase in promoting wind power. Projects will be selected on the basis of price. Crucially, the terms for contracting power allow for wind’s variability. Suppliers need only guarantee an average annual output as described in the main text.

Andean Countries and Venezuela

Colombia – The most promising region is the North Coast, especially the La Guajira peninsula in the extreme northeast. Wind speeds average close to 10 m/s at 60 m height (Class 7) and are quite steady during the day. The Colombian Academy of Sciences estimates a potential of 14 GW (49 TWh at 40% load factor) in this area (ESMAP, 2009). There are also relatively good winds (apparently Class 5) in areas of the Santander Andes in NE Colombia (San Cristobal). In general, the rest of the interior of Colombia presents few opportunities. Possibly interesting sites will be quite small. Map C-3 shows annual average wind speeds at 50 m.

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Map C-3: Colombia – Average annual wind speeds at 50 mSource: Colombia IDEAM, 2006

The winds of the most promising locations along the North Coast are quite regular and are higher during the day between 9 am and 5 pm. This pattern is shown in Figure C-3 for a meteorological station in the La Guajira peninsula.

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Figure C-3: Average hourly wind speed, by month, on La Guajira peninsulaMeteorological Station: Almirante Padilla Airport

Source: Colombia IDEAM, 2006

The figure also shows that wind output is higher in the first several months of the year, as well as in the middle. This pattern is confirmed in Figure C-4, which shows how it nicely complements natural hydro flows.

Figure C-4: Complementarity of wind speed with hydrology in Colombia(La Guajira Peninsula vs Magdalena River)

Source: EEPM, 2006

One of the very few analyses of the complementarity of wind with hydro and the correlation of output with the peak has been prepared for Colombia (ESMAP, 2009). Output from the existing Jeripachi wind farm in La Guajira was compared month by month, between wet season and dry season and peak, medium and low load times. As shown in Table C-1, average wind output in the dry season was 20%+ higher than in the wet season. Interestingly, Figure C-4 above suggests that hydro output drops in July-August – a detail not considered in the table below – which would strengthen the calculated complementarity of the wind output..

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Table C-1: Relative wind output during peak and off-peak load and dry vs wet seasonMonths designated as “dry season” are shaded in light yellow

Level of Load on the SIN Grid Total inPeak Medium Low Month/Yr

Jan 1,18 1,30 0,58 1,08Feb 1,46 1,51 0,65 1,26Mar 1,60 1,61 0,77 1,36Apr 1,21 1,23 0,70 1,08May 1,10 1,10 0,63 0,96Jun 1,15 1,17 0,57 1,00Jul 1,48 1,52 0,97 1,36Aug 1,27 1,26 0,68 1,09Sep 1,02 1,03 0,56 0,89Oct 0,55 0,63 0,30 0,53Nov 0,69 0,76 0,30 0,62Dec 0,73 0,99 0,34 0,79Year 1,12 1,17 0,59 1,00

Dry season 1,23 1,33 0,61 1,11Wet season 1,04 1,07 0,57 0,92

Source: Calculations based on data in ESMAP, 2009

The complementarity with hydro is important in Colombia, since hydro is dominant in that country and coal is also very competitive. One question which has not been addressed yet in published work is the impact of extreme meteorological periods such as El Niño/La Niña. This kind of analysis is of course needed throughout Latin America.

At present, the Jeripachi wind farm is the only significant plant in Colombia. A second wind farm of the same size is under construction. The small size is due to the fact that incentives for nonconventional renewable energy is limited to plants smaller than 20 MW.

Venezuela – The same ocean winds that make the North Coast of Colombia an area of high quality wind potential have that effect in Venezuela, as shown in Map C-4.

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Map C-4: World oceans - annual wind power density at 50 m

Source: Prepared by NREL, US National Renewable Energy Laboratory, from scatterometer measurements made by satellites. See Annex C-1 about QuikSCAT and to see seasonal changes.

A rather rudimentary wind resource map of the country suggests that high quality resources (Class 5 or higher) are located around the vicinity of Lake Maracaibo – both along the coast and to the southwest and southeast. The lake itself might be a good area for shallow off-shore plants.

Venezuela has no wind farms at present. However a 100 MW plant is being constructed on the Paraguaná peninsula, which is across from La Guajira peninsula at the entrance to Lake Maracaibo. Another four wind farms of undeclared size are then to be constructed by 2013.

Peru

Peru has less than 1 MW of installed wind capacity and the existing expansion plan (Peru MEM, 2007) for 2006-2015 makes no reference to renewable projects other than hydro. Assessments of the potential are still pretty rudimentary. Published maps show higher quality sites to be along the Pacific Coast. However, they are difficult to calibrate with standard classifications and do not show the potential geographic areas available except very schematically.

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Although wind does not figure in the power sector’s expansion plan, there have been temporary concessions taken out on 34 sites (Peru MEM, 2008) with a total of 5535 MW. Only the proposed capacity and site are shown in this inventory. Five projects with a total of 210 MW were summarized in an earlier inventory of projects (Peru MEM, 2007b) and slightly more information is available about four of them, though some of it is inconsistent and may be of dubious quality.

For these projects one sees projected capacity factors of 34% in two and 30% in two others – though it is not clear what height of the towers is assumed (30 m has been a common reference in Peruvian documents, this height is quite low by modern standards). The largest proposed plant, at Marcona south of Lima, expects an average wind speed of >10 m/s at 55 meters, which would be Class 7 standards. This is particularly interesting because the highest average wind speeds are generally shown to be in the extreme north of Peru (Piura).

A group at the Catholic University of Lima estimates the exploitable potential to be about 65,000 MW (PUC, 2008), an order of magnitude higher than preliminary (apparently unpublished) estimates of the government. This would be equivalent to 170-200 TWh at 30-35% capacity factor. The basis of these calculations is unknown.

Central America

The only country in Central America with significant development of wind power is Costa Rica, which was a pioneer in Latin America. In 2005 it had the largest installed capacity of any country in the region. Since then capacity has grown very little.

An aggregate estimate of wind potential in Central America, as summarized in OLADE, 2005, was 8441 MW. At a 35% capacity factor this would be equivalent to almost 26 TWh. Unfortunately, this estimate excludes Honduras and El Salvador. Worse, there is no information regarding the basis for the overall estimate.

Mapping of the region is still quite limited as illustrated by Map C-5, which covers the region north of Costa Rica. What the maps show is that the higher quality potential tends to be restricted to quite small areas in the highlands.

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Map C-5: Partial view of wind potential in Central America north of Costa RicaSource: NREL

Mexico

Mexico has substantial potential for wind energy, though the mapping of this resource is still very incomplete. In 2005, the government made a preliminary estimate of about 5000 MW, distributed roughly as shown in Map C-6. A more recent report suggests a somewhat larger potential of 10,000 MW (SENER, 2009). Even this value may be conservative today.

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Map C-6: Promising areas for wind power development in Mexico

Source: SENER, 2005

The most promising area is the Isthmus of Tehuantepec in the State of Oaxaca, in the extreme south of Mexico. This site was mapped in an agreement with the US National Renewable Energy Laboratory (NREL, 2003). It has a concentration of approximately 4300 km2 high quality resources (Class 5-7) as shown in Table C-2 and Map C-7. Assuming 5 MW of capacity per km2 this suggests a gross potential of almost 22 GW. Assuming capacity factors of 35-40%, this would be equivalent to about 67-77 TWh (compared to Mexico’s total generation in 2007 of 233 TWh). The performance of the existing wind farm in La Venta suggests that high capacity factors are feasible.

Table C-2: Wind Potential (Gross) in Oaxaca

Class Wind Speed Area PotentialAt 50 m (km2) (MW)

Class 3 6.1-6.7 m/s 2234 11.170Class 4 6.7-7.3 m/s 2263 11.315Class 5 7.3-7.7 m/s 1370 6.850Class 6 7.7-8.5 m/s 1756 8.780Class 7 >8.5 m/s 1248 6.240Classes 3-7 >6.1 m/s 8.871 44.355Classes 4-7 >6.7 m/s 6.637 33.185Classes 5-7 >7.3 m/s 4.374 21.870

Wind speeds based on a Weibull k value of 2.0 and an elevation of 2000 m.Installed capacity per km2 assumed to be 5 MW.Source: NREL, 2003

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Map C-7: Areas of high wind potential in the Isthmus of Tehuantepec, Oaxaca

The months of October through March have the highest average wind power, as shown in Figure C-5. This data is from longer term off-shore measurements, however NREL found good correlation with the seasonality measured by on-shore stations.

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Figure C-5: Average Seasonality of Wind Speed and Power Density in the Isthmus RegionSource: NREL, 2003. Satellite Ocean Monthly Wind Data for Offshore

There are substantial inter-annual variations in the monthly and total annual output, as shown in Figures C-6 and C-7.

Figure C-6: Interannual variability of wind power in the Isthmus of Tehuantepec

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Figure C-7: Variability of monthly wind power in the Isthmus of Tehuantepec

The diurnal pattern at the higher class wind resource sites is relatively flat. The amplitude of variation is only around 1 m/s at Class 7 locations, with the maximum resource generally from late morning to afternoon. However, during the windiest months (November through February), the wind resource is sometimes slightly greater at night than during the day. Slightly larger diurnal amplitudes and daytime maximums are typical in lower wind resource months from April through September.

Very little information has been found so far relating to other possible sites for wind power elsewhere in Mexico. Map C-8 shows potentials in the northwestern border area.

Map C-8: Wind potential in northwestern border areasSource NREL

Purple = Class 5; Red = Class 6; Blue = Class 7

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Although there are areas with high class wind resources, as in Baja California, the areas are quite small. They tend to be found along ridges in mountainous areas.

The Caribbean Islands – Dominican Republic

The islands as a group have a very distinct profile of energy resources and opportunities relative to the mainland. They are also diverse between themselves.

Several of the smaller islands, such as Guadeloupe and Curaçao, were pioneers in the installation of wind power. However there has been little development in recent years. Although there are reasonable quality wind regimes in some of the islands – see for example Map C-4 above - they suffer from an inability to interconnect geographically disperse sites to mitigate variations in output. This makes them more like small isolated electrical systems.

For reasons of time, this report restricts itself to one of the larger countries, the Dominican Republic, which is among the best inventoried in the Caribbean. Higher quality wind resources are concentrated in the southwest and northwest corners of the country, as illustrated in Map C-9 from NREL, 2001.

Map C-9: Wind energy in the Dominican RepublicSource: NREL, 2001

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Restricting the assessment to the high quality resources (“Excellent”) there is an area of about 460 km2 and a capacity of about 3200 MW in terms of gross technical potential. This would be equivalent to about 8-10 TWh with capacity factors between 30% and 35%. See Table C-3.

Table C-3Source: NREL, 2001

Because this assessment of wind potential was performed almost ten years ago, the assumptions about technology and therefore capacity factors may be somewhat low, though the potential in terms of capacity (MW) should be less effected. In this case gross generation potential might be increased to 10-12 TWh. This value can be compared to the total generation in 2007, which was 14.8 TWh. Since the areas in question are quite small and dispersed it may be possible to develop a higher share of the theoretical potential than is common in mainland countries.

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Annex D: Observations on Possible Cooperation in Latin America

Supporting the development of renewables appears to be accepted as an important strategy for the World Bank, as well as for other donors and multilateral agents in the region. The new driver is concern about climate change, but there is also a need for maintaining reliability, security and as low an economic and environmental cost (besides climate change) as possible.

The objective of increasing the share of hydropower and other renewable energy resources cannot be met by the market alone and governments are likely to need considerable assistance in implementing strategies to achieve this objective.

Various kinds of concessional finance, especially for non-conventional renewable and some transmission projects, will be needed. This is especially the case in the nearer term given the pioneering nature of many initiatives and higher costs before economies of scale can be achieved. Special attention needs to be given to attracting risk capital.

Besides help in financing the project investments, technical assistance is important. All countries in the region will be going up a steep learning curve regarding different aspects of planning and project development, including which incentives will most effectively promote the objectives. Introducing best practices for analysis and exchanging experiences will be valuable.

There should also be ample benefits from exchanges and cooperation between countries which multilateral agents can facilitate.

Some examples are raised below of subjects where technical assistance and cooperation appear to be useful.

Wind’s short term variability should be addressed in the context of the grid’s constantly varying load, not in isolation from it. If the output of wind correlates strongly with peak demand on the grid, the variability seen by the remaining generators may on average be less than without wind – though the “tails” of more extreme ramping may still increase somewhat. In many countries in the region peak wind tends to be in the late afternoon, so correlation may be rather good. Studies are needed to analyze hourly wind data from the same region as that for hourly demand. Meteorological conditions associated with different levels of wind can be associated with factors influencing energy demand. (Krohn, personal communication).

Attention is also needed to the variability of wind over longer timeframes, especially annual averages. Unfortunately, there has so far been very little analysis of different aspects of variability of the wind resource in Latin America.

Seasonal and annual complementarity has long been an element of hydroelectric planning at a national level – at least in countries large enough to have hydrologic diversity between river basins. There has, however, been almost no analysis of the potential for hydrologic complementarity of basins throughout Latin America. Yet the possibilities exist and the benefits could be very large. After all, the equator passes through South America and seasonal patterns are inverted.

The seasonal variability of wind also differs from one “basin” to another. It also appears to be complementary to that of hydro in many situations – examples in the region so far discovered include Colombia and Brazil (complementarity = one resource abundant when the other is scarce). These are an important addition to the traditional analysis of complementarity for

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hydro. It is important to study the development of the two resources together. The analysis of all this is in its infancy and there has been little attention to this in most other big wind markets like Europe and the USA, since hydropower is proportionately much smaller and there is little left to build.

An important contribution for planning would be provided by bringing together and analyzing hydrological and wind information for Latin America as a whole and for sub-regions such as Central America. These analyses should include comparisons of hydro and wind variability over seasonal, annual and multi-year timescales. Solar should be added, but is less of a priority.

Analyses of hydro need to include the energy storage capability of existing dams and the potential new storage in future hydro plants. Today almost no systematic data on storage is published (except perhaps the surface area for environmental analysis). Storage may have a big impact on the ease with which wind and solar can be absorbed.

On the wind side, much analysis can actually be done without having a single wind turbine installed. Even normal, fairly low-precision meteorological measurements from a number of stations in the affected area will provide the needed variability data, since we do not need the absolute wind speed but only the relative variations. However, we have to assume something about the size of the wind power plants and their mean capacity factor. Analyses building from growing international and regional experience with wind plants will add confidence to these latter factors.

One question which has not been addressed much in published work is the impact of extreme meteorological periods such as El Niño and more broadly of the impact of climate change on hydrology and wind regimes. This kind of analysis is needed throughout Latin America.

Based on this work which addresses the variability of different renewable resources, support will be important for designing and implementing bulk transmission schemes – especially interconnections between countries.

There is evidence that wind energy projects in Latin America for the grid have been quite expensive relative to international standards and are still projected to be expensive. It is not clear why investment costs should be so much higher, though the small and irregular market in Latin America clearly has a role. This suggests that there should be considerable scope for reducing costs just to bring the region closer in line with costs elsewhere. A study of recent and specific proposed projects may help clarify better where the higher costs originate and the opportunities to reduce them.

Another kind of question where multilateral exchange would be useful concerns R&D and design. For example, there is a question whether turbines available in the market are designed for conditions commonly found in Latin America. For example, a higher cut-off point may be appropriate. Another example is planning tools for a more integrated grid at a continental level. Adequate tools for this do not even exist yet in the USA or Canada (CAE, 2009).

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