Renewable energy essential iea by Alessandro Filippa

YDROPOWE

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Renewable Energy Essentials: Hydropower

Market status Hydropower production

ydropower is currently the most common form of renewable energy and plays an important part in H global power generation. Worldwide hydropower produced 3 288 TWh, just over 16% of global electricity production in 2008, and the overall technical potential for hydropower is estimated to be more than 16 400 TWh/yr.

T he BLUE scenario of the IEA publication Energy Technology Perspectives 2010, which aims to achieve a 50% reduction in energy-related CO2 emissions by 2050, projects that hydro could produce up to 6 000 TWh in 2050.

ydropower’s storage capacity and fast response characteristics are especially valuable to meet sudden H fluctuations in electricity demand and to match supply from less flexible electricity sources and variable renewable sources.

T he costs of power production from hydropower can vary widely depending on project details, but usually fall into a range of USD 50 to 100/MWh. Upgrading existing hydropower plant projects offers further options for cost-effective increases in generation capacity.

T he environmental and social effects of hydropower projects need to be carefully considered. Countries should follow an integrated approach in managing their water resources, planning hydropower development in co-operation with other water-using sectors, and take a full life-cycle approach to the assessment of the benefits and impacts of projects.

ydropower worldwide produced 3 288 TWh, equivalent to 16.3% of global electricity production H (20 181 TWh) in 2008. Hydropower production in OECD countries reached 1 381 TWh, accounting for 12.9% of gross electricity production; hydropower in non-OECD countries produced 1 906 TWh, equal to 20.1% of gross electricity production. 3 500

TWh/yr

3 000 2 500 2 000 1 500 1 000

500

18%

30%

12%

2% 3% 3%

11% 3% 4%

China Canada Brazil United States Russia Norway India Venezuela Japan Sweden Others

90 19 92 19 94 19 96 19 98 20 00 20 02 20 04 20 06 20 08

Others Sweden Japan Venezuela India Norway Russia United States Brazil Canada China

Figure 1: Evolution of global hydropower generation between 1990 - 2008

Figure 2: Shares in hydropower generation in 2008

Data source: IEA Electricity Information 2010

Since 1990, global hydropower generation has increased by 50% (Figure 1), with the highest absolute growth in China. Hydropower generation by the top ten countries accounted for about two-thirds of the world’s hydropower generation (Figure 2) in 2008.

Hydropower The global technically exploitable hydropower potential is estimated at more than 16 400 TWh11 per year. potential This potential is unevenly distributed. The five countries with the highest potential (China, United States, 1. W orld Energy Council (WEC), Survey of Energy Resources 2007, which defines the technically exploitable potential as the annual energy potential of all natural water flows which can be exploited within the limits of current technology. © OECD/IEA, 2010

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Russia, Brazil and Canada) could produce about 8 360 TWh per year, and the next five countries (DR Congo, India, Indonesia, Peru and Tajikistan) have a potential of about 2 500 TWh per year. These ten countries account for about two-thirds of the global hydropower potential. The hydropower production and potential for the world regions and for the top five countries with the highest potential are shown in Figure 3. Data for the countries which have developed the largest proportion of their hydro potential and a production level of over 30 TWh/yr are shown in Figure 4. Globally, around 19% of the potential has been developed. Countries which have actively developed hydropower use around 60% of their potential. Numerous other countries have a huge amount of untapped hydropower potential. Although climate change may affect water resources and may lead to significant variations of the potential for hydropower at a country level, these variations are expected to cancel out roughly on the global scale, leaving the overall potential virtually unaffected.2

Europe (29%) North America (25%) Latin America (21%) Africa (5%) Middle East (5%) Asia and Pacific (18%)

Switzerland (88%) Mexico (80%) Norway (70%) Sweden (69%) France (68%)

China (24%) United States (16%) Russia (10%) Brazil (25%) Canada (39%)

Japan (61%) Austria (54%) Production

Paraguay (52%)

Potential 0

1 000 2 000 3 000 4 000 5 000 6 000 TWh/yr

Figure 3: Hydropower development ratio for world regions and top five countries with the highest potential

Production

Italy (45%) 50

100

150

200 250 TWh/yr

Figure 4: Countries with largest developed proportion of their hydro potential (countries with hydropower production over 30 TWh/yr)

Data source: WEC Survey of Energy Resources 2007, IEA Renewables Information 2010 (2008 data)

Economics

Investment costs

Construction costs for new hydropower projects in OECD countries are usually less than USD 2 million/MW for large scale hydro (> 300 MW), and USD 2 to 4 million/MW for small- and medium-scale hydro (< 300 MW) (Table1). The initial investment needs for particular projects must be studied individually due to the unique nature of each hydropower project. Parameters affecting investment costs and the return on investment include the project scale, which can range from over 10 000 MW to less than 0.1 MW; the project location; the presence and size of reservoir(s); the use of the power supplied for base or peak load or both; and possible other benefits alongside power production, such as flood control, irrigation, fresh water supply, etc. The way in which the project is financed is also a key factor. The capacity of many existing hydropower plants could be raised by 5 to 20%. Such refurbishment projects may be easier from a technical and social point of view, and faster and more cost effective than new plants. Table 1. Classification of hydropower

1 2 3 4

Category

Output/unit

Storage

Power use (load)

small medium medium large

< 10 MW 10-100 MW 100–300 MW > 300 MW

run-of-river run-of-river dam and reservoir dam and reservoir

base load base load base and peak base and peak

Investment costs (USD M/MW) 2-4 2-3 2-3 <2

Data source: IEA Hydropower Implementing Agreement

Generation costs The generation costs of electricity from new hydropower plants vary widely, though they often fall into a range of USD 50 to 100/MWh. It should be noted that generation costs per MWh will be determined by the amount of electricity produced annually and that many hydropower plants are deliberately operated for 2. H amududu and Killingtveit (2010), “Existing Studies of Hydropower and Climate Change: An Overview”, Hydropower 10, 6th International Conference on Hydropower, Tromsø, Norway. © OECD/IEA, 2010

HYDROPOWER

peak load demands and back-up for frequency fluctuation, so pushing up both the marginal generation costs and the value of the electricity produced. As most of the generation cost is associated with the depreciation of fixed assets, the generation cost decreases if the projected plant lifetime is extended. Many hydropower plants built 50 to 100 years ago are fully amortised and still operate efficiently today. Operation and maintenance costs are estimated at between USD 5 to 20/MWh for new medium to large hydro plants, and approximately twice as much for small hydro.

Operation and maintenance (O&M) costs

Climate change and other negative effects of using fossil fuels for power production, along with a growing demand for energy coupled with concerns over energy security, are driving the expansion of renewable sources of energy. Hydro is a well established source of low-carbon power that can meet these needs, and at present is the largest source of electricity from renewable sources.

Outlook

Over the last two decades, decisions on many hydropower development projects have been affected by controversy about the environmental and social effects of hydropower. Analysing the benefits and impacts of such projects is both difficult and time consuming. In deciding on the role of hydropower within an electricity supply portfolio which addresses climate change and energy security concerns, energy policy makers have to consider a whole range of issues including: Enhancing economic equity among citizens. Protecting the lives and property of citizens from floods and droughts. Securing the rights of citizens with respect to expropriation of land to be inundated. Protecting the environment concerning air, land, water and biodiversity.

Barriers

Growth drivers

Some or all of these competing, and sometimes conflicting, policy objectives bring major hydropower decisions into the political arena. The interests of the communities who are positively and negatively affected by hydropower projects -- and the economic, social and environmental benefits and impacts -- need to be carefully analysed on a case-by-case basis before proceeding with projects.3

The BLUE Map scenario in the Energy Technology Perspectives 2010, which aims to achieve a 50% reduction in energy-related CO2 emissions by 2050, suggests that hydropower could provide 5 749 TWh in 2050. Under this scenario, hydropower would see its share in the global electricity production increase slightly from 16.3% in 2008 to 17.3% in 2030 but then reduce to 14.1% by 2050 as other power-generation technologies grow at faster rates (Figure 5). Hydro will continue to be a major source of renewable electricity on a global scale, contributing to base load and providing the flexibility needed to meet peaks in demand. Figure 5: Hydropower development for world regions in ETP BLUE Map scenario 20.0% 18.0% 16.0% 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% 2010

TWh/yr

7 000 6 000 5 000 4 000 3 000 2 000 1 000

2015 Europe Africa

2020

2025

2030

2035

2040

2045

0 2050

North America Latin America Middle East Asia and Pacific Share in total power generation

Data source: IEA Energy Technology Perspectives 2010.

Hydropower plants can be designed to produce electricity for base or peak demand, or both. Hydropower’s quick start capability helps to cope with fluctuations in electricity system loading. Pumped-storage hydropower generates electricity to meet peak load, allowing the optimum use of other, less flexible electricity sources, such as nuclear and coal-fired power plants. Pumped-storage hydropower is the largest and most costeffective form of electric energy storage at present. The current global capacity of pumped-hydro storage could increase tenfold as some existing hydropower plants could be transformed into pumped-hydro storage plants.

In order to implement hydropower projects in a sustainable manner, all environmental and social impacts need to be explored and anticipated early in the planning process so that appropriate steps can be taken to avoid, mitigate, or compensate for impacts. The IEA Hydropower Implementing Agreement has done 3. Koch F. H. (ed.) (2002, November), Energy Policy: Special Issues: Hydropower, Society and the Environment in the 21st Century, Vol. 30, No. 14. © OECD/IEA, 2010

Long-term scenarios

System-related aspects Hydropower’s role in stabilising electricity systems

Environmental impacts

YDROPOWE

Environmental pioneering work in this field and has recently updated its Recommendations for Hydropower and the and social impacts Environment.4 The International Hydropower Association has developed a Draft Hydropower Sustainability

Assessment Protocol which aims to provide a broadly supported sustainability assessment tool to measure and guide performance in the hydropower sector.

Carbon balance In the early 1990s, some stakeholders raised the issue of a potential adverse carbon balance resulting from in reservoir the creation of new freshwater reservoirs. This related primarily to emissions of carbon dioxide and methane and a number of attempts have been carried out to measure “a gross emission” from specific reservoirs. In order to ensure that projects are sustainable and do in fact lead to a reduction in carbon emissions, a full life-cycle analysis, including the likely impacts of inundation, needs to be carried out. The IEA Hydropower Implementing Agreement , under Brazil’s leadership, has recently initiated further work on the “Management of the Carbon Balance in Freshwater Reservoirs”.

Public acceptance The issue of public acceptance has become a high priority for hydropower development over the last two of hydropower decades. Local citizens, including those stakeholders most impacted by developments, need to be fully consulted as part of the project development process.

This has also implications for the financing of hydro power plants. For instance, World Bank lending for hydropower bottomed out in 1999 due to growing opposition from environmental and other nongovernmental organisations. However, there is now a growing awareness that countries must follow an integrated approach in managing their water resources, planning hydropower development in co-operation with other water-using sectors and taking environmental, safety and social factors properly into account. World Bank lending is now expanding in this sector, reflecting a Water Resources Sector Strategy, approved in 2003, which recognises that significant levels of investment in water infrastructure are required throughout the developing world.

Technology status and development Hydropower technology and technology advances

Hydroelectric power is the energy derived from flowing water. This can be from rivers or from man-made installations, where water flows from a high-level reservoir down through a tunnel and away from a dam. Turbines placed within the flow of water extract its kinetic energy and convert it to mechanical energy. This causes the turbines to rotate at high speed, driving a generator that converts the mechanical energy into electrical energy. The amount of hydroelectric power generated depends on the water flow and the vertical distance (known as “head”) the water falls through.

There are three main types of hydroelectric projects: Storage schemes In storage schemes, a dam impounds water in a reservoir that feeds the turbine and generator, which is usually located within the dam itself. Run-of-river schemes Run-of-river schemes use the natural flow of a river, where a weir can enhance the continuity of the flow. Both storage and run-of-river schemes can be diversion schemes, where water is channelled from a river, lake or dammed reservoir to a remote powerhouse, containing the turbine and generator. Pumped storage Pumped storage incorporates two reservoirs. At times of low demand, generally at night, electricity helps pump water from the lower to the upper basin. This water is then released to create power at a time when demand, and therefore price, is high. Although not strictly a renewable energy (because of its reliance on electricity), pumped storage is very good for improving overall energy efficiency. While hydropower is a well proven and mature technology, it is still advancing and expanding its scope of application, for example by developing cheaper technologies for small-capacity and low-head applications so as to enable the exploitation of smaller rivers and shallower reservoirs. Hydrokinetic technologies are being developed that do not require a hydraulic head but extract energy from water flows in rivers and waterways.

Lifetime Many hydropower plants built 50 to 100 years ago are still operating today. Hydropower is the most proven,

efficient, flexible and reliable source of electricity based on more than a hundred years of experience. Upgrades and refurbishment can readily extend lifetime of plants which contribute to the low cost of electricity from hydropower.

R&D priorities Equipment manufacturers are striving for higher efficiency, reliability and longevity through computational fluid dynamics design, advanced manufacturing processes and new materials. R&D is also directed into IT systems, i.e. automation, remote control and diagnostics. 4. http://www.ieahydro.org/reports/AnnexXII_Task2_BriefingDocument_March2010.pdf © OECD/IEA, 2010

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INTERNATIONAL ENERGY AGENCY

Renewable Energy Essentials: Wind n

orld generating capacity of wind energy is growing at 20-30% per year, and surpassed 90 Gigawatts W (GW) in 2007 – 50 times installed capacity in 1990. Approximately 152 teraWatt hours (TWh) of wind electricity were generated in 2006. Annual investment topped USD 50 billion in 2007. The global wind industry employs around 200 000 people. Turbine costs have decreased by a factor of four since the 1980s. Since 2004, however they have increased by 20-80%, due to tight supply of turbines and components, and high commodity prices. In 2007, onshore turbine costs ranged from USD 1.2m – 1.8m per MW. Recent production costs onshore range from USD 75/MWh to 97/MWh at high to medium quality wind resource sites. Onshore wind is competitive at sites with good resource and grid access. The IEA Energy Technology Perspectives 2008 publication suggests that in 2050 wind power could supply up to 12% of global demand for electricity – with concentrated effort and technology innovation. Barriers to growth include capital cost, uncertainty regarding policy support and impacts of variability on power systems, limited grid capacity and visual impact.

n n n

Market status Wind power in total generated 152 TWh of electricity

in 2006. In 2007, wind power plants provided for 20% of electricity consumption in Denmark, 10% in Spain, and 6% in Germany. More than 20GW of capacity were installed in 2007 alone, led by the United States, China and Spain. Cumulative installed capacities are shown in the map below. The largest individual wind power plant operating in 2007 (in Texas) had a capacity greater than 700 MW, the same order of magnitude as conventional power plants. Figure 1. Cumulative installed gigawatts of wind power in leading countries, 1990 – 2007

Spain

Germany India

China United States

10 5 0 19 9 19 0 9 19 1 9 19 2 9 19 3 9 19 4 9 19 5 9 19 6 97 19 9 19 8 99 20 0 20 0 0 20 1 02 20 0 20 3 04 20 0 20 5 0 20 6 07

Offshore Offshore installed capacity topped 1.1 GW in 2007, located in just six countries, including Denmark (420 MW), United Kingdom (300 MW), Netherlands (130 MW), Ireland (25 MW), and Sweden (135 MW). Several large projects are planned in other countries. Offshore wind power plants can produce up to 50% more electricity than their onshore cousins, due to higher and steadier wind speeds. Other advantages include greatly reduced visual impact, less turbulence, and lower noise constraints – allowing higher rotor speeds. On the other hand, with current technology the hardware and its installation are more expensive.

Small wind Small and micro wind turbines have in the past been considered mainly for off-grid applications. Recently a number of countries have shown renewed interest, including Canada, Ireland, Italy, Portugal, Spain, United Kingdom and United States. However, reliability problems persist, and markets remain small.

The wind resource The global resource map below illustrates approximate, average global wind speeds on- and offshore. The

energy content of the wind is proportional to the cube of the wind speed, so a slighter faster average speed yields significantly greater output. This has major bearing on the financial viability of a project. A good wind speed site for an average development is around 7m/s (25 kmph, 16mph) and above, at a hub height of around 80 metres. The importance of a high quality wind regime is illustrated by the fact that the US produced more wind electricity in 2007 than any other country, even though it does not have the largest installed capacity. Similarly, offshore wind energy represented 1.8% of total installed capacity (in 2006) but produced 3.3% of total wind electricity. High quality wind resources are distributed throughout the globe.

Manufacturing S ix countries worldwide account for almost all wind turbine manufacturing (see Figure 2). Although Denmark and employment contains only a little over 3% of global installed wind capacity, it was the birthplace of modern wind energy and still produces over a third of all turbines sold worldwide. Other principle manufacturing countries are Germany, Spain, the USA, India and China. The global wind industry employs around 200 000 people. © OECD/IEA, 2008

New investment Investment reached USD 50.2 billion in 2007, accounting for 43% of new investments in renewable energy. Wind raised USD 11.3 bn in public markets, 60% of which through a single Initial Public Offering.

Figure 2. World onshore and offshore resource map at 80m height and 15 km resolution, with installed capacity, production and manufacturing data for leading countries Wind speed over water 5

15 m/s

United Kingdom 2.4 0.4 5.4 1.3%

Germany 22.2 1.7

Denmark 0 7.2 19.9%

Wind speed over land 35.5%

6 m/s

39.5 6.4% 22%

United States 16.9 5.3 48

3.1

1% 15.5%

Cumulative installed GW in 2007 Net increase in GW capacity in 2007 TWh from wind energy In 2007 Share of wind in electricity production in 2007 Share of global manufacturing in 2006

2.7

Italy 0.6 4

1.2%

Spain 15.1 3.5 27

5.9

9.8% 18.4%

3.9 n/a 2.8%

Portugal 2.2 0.5 4

China 3.3

8.5%

France 2.4 1 4

0.7%

7.8 8

India 1.6 n/a 7.7%

World 93.8 19.9 152

Wind resource map ÂŠ 2008 3TIER Inc.

Map notes: Figures for 2007 capacity increase for India and China are gross. TWh produced in India and China are for 2006. Most Danish activity in 2007 was in re-powering. Leading states in the Unites States, in terms of share of national electricity production, include Minnesota (5%), Iowa (5%), New Mexico (4%) and Oregon (3.5%).

Economics

Investment costs

Turbine costs have decreased by a factor of four since the early 1980s. Since 2004, however, they have risen by around 20-80% (2006), driven by supply tightness (turbines, gear boxes, blades, bearings and towers) and higher commodity prices (particularly steel and copper). Industry sources expect supply tightness to loosen by 2010. In 2007, onshore turbine costs ranged from USD 1.2m per 3.0 2003 MW in the United States to USD 2004 2.5 1.8m in Italy. Total installed costs 2005 (inc. turbine) ranged from USD 1.4m 2.0 2006 in the UK to USD 2.7m in Ireland 2007 (Figure 3). 1.5 1.0

na da nm ar Fi k nl a Ge nd rm an Gr y ee c Ire e la nd Ita ly Ne Jap th an er la nd No s rw Po ay rt ug al Sp ai Sw n Sw ed itz en er la nd

Figure 3. Evolution of investment costs in selected countries: 2003 to 2007 (USD millions per MW)

0.5

Operation and The annual operating cost for large onshore turbines in 2006, including insurance, regular maintenance, maintenance (O&M) spare parts, repair and administration was in the range of USD 14/MWh to USD 26/MWh. O&M costs are considerably higher for offshore wind turbines.

Production costs At sites with the best available wind resource as well as nearby grid access, wind power plants can be competitive with conventional electricity producers. The cost per unit of electricity generated depends on the quality of the ÂŠ OECD/IEA, 2008

Wind

wind resource (represented by the number of full load hours of operation) investment cost, O&M cost, and turbine longevity. Wind power plants are capital-intensive so the cost of capital (discount rate) is a decisive factor in wind cost estimation. Typical production costs, levelised over turbine lifetime, with a discount rate of 7.5% and investment costs of USD 1.6m per MW, for example, range from USD 75/MWh to 97/MWh, at high to medium quality wind resource sites, as illustrated in Figure 4.

USD/MWh

osts are largely dependent on water depth and distance from shore. Foundations, installation, and grid C connection are significantly more costly offshore. Turbine cost is typically 20% higher, and towers and foundations perhaps 150% more. However, offshore wind 200 plant output can be up to 50% greater, due to higher USD 2 300/kW 160 wind speeds. Installations in the United Kingdom and USD 1 640/kW 120 Sweden in 2007 – 2008 cost between USD 2.5m per MW and USD 3.7m per MW, and production costs at these 80 locations ranged from USD 85 – 105/MWh. 40

0 1 500 1 700 1 900 2 100 2 300 2 500 2 700 2 900 Full load hours

Offshore costs

Figure 4. Wind power production costs as a function of the wind resource and investment cost

rivers for cost reductions include increased performance and reliability, technology advances, larger turbines D (when installed offshore), and increased manufacturing capacity. The use of “learning rates” to gauge future cost reductions is based on the assumption that existing trends will persist. In essence, this methodology yields a percentage reduction in costs for each doubling of production. For wind energy, recent IEA analysis suggests a learning rate of around 10-20%. With a 10% learning rate, costs in 2015 would be about USD 53/MWh at high wind, onshore sites.

Cost reductions

Strategies to mitigate anthropogenic climate change, and other negative environmental effects of conventional power production, have given rise to a range of supportive government policies for renewable energy, some of which are specific to wind energy, as well as carbon markets. Other drivers include technology advances, fossil fuel scarcity and increasing price, growing concern regarding energy independence, electricity market liberalisation, and rising electricity demand particularly in emerging economies. Off-grid and rural energisation, and poverty reduction are important developing country drivers.

Outlook

arriers to wind energy development include uncertainty relating to the future of /lack of incentive schemes B (e.g. annual renewal of the Production Tax Credit in the USA), concerns about the impacts of variability on power system reliability, access to transmission, perceived visual and ecological impacts, and the structure of conventional electricity markets. The latter evolved around conventional generation and utilities, and in many cases could be optimised to facilitate wind power participation.

Barriers

Long-term scenarios

TWh

The outlook is for continued double-digit percentage annual growth in wind energy. IEA Energy Technology Perspectives (ETP) 2008 suggests that wind technology could feasibly provide 9% (approx. 2 700 TWh) of global electricity in 2030 . By 2050, the IEA’s advanced “BLUE” Scenario, which requires significant technology innovation, suggests that as much as 12% (approx. 5 200 TWh) could be feasible . These amounts are plotted in Figure 5, as a range. The Global Wind Energy Council has prepared an Advanced Scenario that suggests that, if stronger early action is taken, wind electricity 6 000 production could reach still higher: 5 200 TWh in 2030 5 000 and 7 200 TWh in 2050. The IEA scenarios are generated 4 000 by a model which also takes into account competing 3 000 generation technologies. 2 000 1 000 0 2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Figure 5. IEA ETP Scenarios: range of potential global wind electricity production (TWh)

. “ACT” Scenario, in which CO2 emissions stabilised at present levels by 2050, and measures are taken with a cost of up to USD 50/tonne CO2. . “BLUE” Scenario, in which present CO2 emissions halved by 2050, and measures are taken with a cost of up to 200/tonne CO2. © OECD/IEA, 2008

Growth drivers

System related aspects Variability

Wind power plants – like wave, tidal, and solar plants – depend on a variable resource; the wind does not blow all the time in any one place. Consequently, the capacity factor of wind turbines ranges from 20% to 40%, lower than for conventional base-load technologies. Variability is commonly perceived to be challenging at high shares, but there is no intrinsic, technical ceiling to variable renewables’ potential. Nonetheless, as variable electricity inputs to the system increase, so the flexibility of the power system must increase also, to provide for times when wind power output is low. In electricity system terms, flexible power plants are those in the generation portfolio that can quickly ramp production of electricity up or down as required. But the system can also respond to fluctuating wind power output through the use of stored energy, import from other areas and through enabling demand side response. A number of operational measures exist also, particularly relating to the operation of transmission capacity and electricity markets.

Environmental The costs relating to social and environmental damage caused by pollution – are rarely taken into account impacts in assessment of the costs of power technologies. Wind power plants require no fossil fuel and produce little External costs

environmental pollution during their manufacture, operation and decommissioning. CO2 emissions for wind energy are small, (around 10g of CO2 per kWh). If external costs were taken into account in normal cost assessments, studies suggest that wind energy would already be competitive with most power technologies.

Local impacts Although public support for wind power is often high, wind turbines may be considered by some to be visually

Technology status and development

Turbine technology

Wind turbines extract kinetic energy from moving air flow (wind) and convert it into electricity via an aerodynamic

rotor connected by a transmission system to an electric generator. Today’s standard turbine has three blades rotating on a horizontal axis, upwind of the tower, with a synchronous or asynchronous generator connected to the grid. Two-blade, and direct-drive (without a gearbox) turbines are also found.

Larger turbines The electricity output of a turbine is roughly proportional to the rotor area, so fewer larger rotors (on taller towers) use the wind resource more efficiently than more numerous, smaller machines. The largest wind turbines today are 5-6 MW units with a rotor diameter of up to 126 metres. Turbines have doubled in size approximately every five years, but a slowdown in this rate is likely for onshore turbines, due to transport, weight and installation constraints.

Lifetime and The estimated lifetime of an individual wind turbine is 20 to 25 years. Life spans may stretch as the technology availability continues to mature. However, due to the youth of the industry and the re-powering of plants with the latest turbine technology, few turbines have been around long enough to test this assumption. Due to extensive testing and certification, the reliability of wind turbines – the proportion of the time they are technically available for operation – is around 99%.

Technology advances Technology efficiency gains are ongoing. More efficient blades and drive trains, lighter nacelles (rotor plus generator) and fewer components mean a higher electricity output per unit of materials required in the manufacturing process. Such efficiency gains will to some extent counter rising capital costs associated with higher commodity prices (e.g. copper and steel).

Offshore/deep offshore To a large extent, the move offshore can be said to be driving wind energy technology development generally. Most offshore wind at present is installed in shallow water. Floating turbines, for the deep offshore environment, are at the demonstration phase with a 2.3 MW prototype scheduled to be deployed in 2009 off the coast of Norway in the North Sea, and another 2.5 prototype scheduled to be installed in 2009 off the Apulia region in Italy.

R&D priorities Subjects for further research, specific to wind energy technology, include more refined resource assessment; materials with higher strength to mass ratios; advanced grid integration & power quality and control technologies; standardisation and certification; development of low-wind regime turbines; improved forecasting; increased fatigue resistance of major components such as gearboxes; better models for aerodynamics and aeroelasticity; generators based on superconductor technology; deep-offshore foundations; and high-altitude “kite” concepts. . The amount of output a power plant produces, divided by the amount it would have produced, had it been in operation 24h, 365 days. © OECD/IEA, 2008

Resource map from 3Tier; capacity and production figures from IEA Wind and Wind Power Monthly; manufacturer data from BTM Consult. Photos: © EWEA, 2008.

intrusive. Micro-siting techniques can be used to reduce visual impacts. Issues relating to aerodynamic noise are largely resolved with suitable codes relating to the allowable distance from residential areas. Following concern about potential avian, bat and marine impacts, most environmental assessments have suggested that these are easily minimised through careful siting of turbines.

EATING AND COOLIN

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OLA

Renewable Energy Essentials: Solar Heating and Cooling n

S olar heating and cooling technologies use the sunlight to produce directly usable heat for water and space heating or industrial processes, or to run air-conditioning systems.

lobal solar heating and cooling (SHC) potential continues to grow. The solar thermal collector capacity in G operation worldwide equalled 171 gigawatts thermal (GWth) corresponding to 244 million square meters at the end of 2008.

hina alone accounted for more than half global capacity, with 101 GWth. Other countries with a large C number of collectors in operation are the United States (unglazed collectors), Germany and Turkey. With respect to the capacity installed per 1 000 inhabitants, the leading countries are Cyprus (651 kWth), Israel (499 kWth) and Austria (273 kWth).

S olar thermal energy for domestic hot water preparation is common all over the world with significant market penetration in Australia, China, Europe, Israel, Turkey and Brazil.

S o-called solar “combi-systems” for combined hot water preparation and space heating show a rapidly growing market in European countries. In Germany and Austria, the predominant share of the annual installed collector area is already for combi-systems.

L arge-scale (producing 1MW or more) solar systems for district heating show considerable growth rates in the Scandinavian countries, Germany and Austria.

ew applications for low temperature process heat, air-conditioning and cooling, as well as desalination, N are now entering the market.

L ow temperature solar collectors for water and space heating are very efficient. High temperature solar collectors for refrigeration, industrial process heat and electricity generation, require improvements. Heat storage (both seasonal and compact) represents a key technological challenge.

Market status The global solar thermal market enjoyed a growth Recent trends

Figure 1: Annual newly installed capacity of glazed rate of about 15% in 2007 (down from 20% in tube collectors by economic region 2006), thanks to a sustained growth of 22% in Source: IEA SHC 2009 the largest world market, China (see Figure 1.) Installed capacity [MW /a] Provisional numbers for 2008 suggest that 2008 20 000 China + Taiwan Australia + New Zealand witnessed further 42% growth in the Chinese 18 000 Europe Japan 16 000 market, with 21 GW installed. Others United States + Canada 14 000 th

The disappointing results of 2007 in Europe (minus 9%), due to a 30% decrease in the largest European market, Germany, were more than compensated in 2008 by a staggering rebound in growth of 45‑50%. The US market, mostly of unglazed collectors, also showed a decrease in 2007. Industrial process heat has taken off in recent years with a couple of large projects in China and Europe. Figure 2: Annual per capita installations by regions Source: IEA SHC 2009

The dominance of China is driven by its large population and the dynamic growth of its solar heating sector. Australia and New Zealand form the second largest regional market (Figure 2).

12 000 10 000 8 000 6 000 4 000 2 000 0

12 10 8

1999

2000

2001

2002

2003

2004

2005

2006

2007

Installed capacity per 1 000 inhabitants [kWth/a] China + Taiwan Europe Others

Australia + New Zealand Japan United States + Canada

6 4 2 0

EATING AND COOLIN

Cumulative At the end of 2008, the solar thermal collector capacity in operation worldwide equalled 171 GWth, of which installed capacity 101 GWth in China alone. Figure 3 shows its distribution by country at the end of 2007. China ranks first (101 GWth), followed by the United collectors at the end of 2007 States (22 GWth). With approximately 8 GWth each, Source: IEA SHC 2009 Turkey and Germany rank third, followed by Japan Total capacity [MW ] (~5 GWth), Australia (4 GWth), Israel, Brazil, Austria 24 000 and Greece. 19 000

Evacuated tube Glazed Unglazed

72 618

China represented 77% of the global market in 2007. The United States ranked second with unglazed collectors and Germany third, but its growth may have outpaced the United States in 2008.

14 000 9 000

7 280

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Top ten With respect to cumulative installed capacity, Figure 3: Total capacity in operation of water

4 000

Top ten per capita On a per capita basis, taking into account both 0 China United Turkey Germany Japan Australia Israel Brazil Austria Greece unglazed and glazed collectors (flat plate and States evacuated tubes), leading countries are Cyprus and Israel, followed by Austria, Granada and Greece, the Barbados, Australia, Jordan, Turkey and Germany. The United States and China have been added for reference in Figure 4.

Energy produced The energy produced in 2007 was about 89 TWh or 319 PJ, or 7.6 million tonnes oil equivalent (Mtoe). Amongst the “new” renewable energy sources (excluding biomass and hydropower), solar thermal energy production comes second only to wind. Still, it represents less than 1% of the global primary energy demand, However, passive solar inputs are not accounted for in the statistics.

The solar resource The solar resource is virtually unlimited – the earth Figure 4: Solar thermal capacity in kWth per and the demand receives from the sun each hour as much energy 1 000 inhabitants at the end of 2007 for heat as humankind currently consumes in a year. Heat Source: IEA SHC 2009 demand is probably close to half the total demand for energy services. However, the solar resource is dispersed and does not always correspond in time and place to the demand for heat; the opposite is more often true, notably for space heating.

kWth per 1 000 inhabitants

700

Unglazed

600

Glazed

500 400 300

Tu r

lia

ria

Isr

In the absence of affordable ways to store large 200 amounts of heat from one season to another, 100 the contribution of solar heat to space heating 0 needs is currently limited. Installed capacities vary considerably among countries with similar climatic conditions and solar resources. This suggests that considerable development still lies ahead. Many countries with large water-heating loads, high energy costs and huge solar resources still make little use of this considerable potential. Domestic hot water and process heat are less sensitive to climatic conditions and thus more favourable for solar heat. To date, only solar water heating has entered into use on a significant scale.

Manufacturing The solar heating and cooling sector employs more Figure 5: Total capacity in operation (GW) in 2007 and employment than 200 000 people worldwide, according to the and energy generated (TWh) in 2007

Economics

IEA Solar Heating and Cooling programme. Some other estimates give higher figures.

Source: IEA SHC 2009

Costs vary greatly according to climate conditions, requiring more or less complex installations, and other factors such as labour costs. A SHW thermosiphon system for one family unit consisting of a 2.4 m2 collector and 150 litre tank costs EUR 700 in Greece, EUR 200 in China. In central Europe, a pumped system of 4–6 m2 and 300‑litre tank, fully protected against freeze, costs around EUR 4 500.

200

Total capacity in operation [GWel], [GWth] and produced energy [TWhel], [TWhth], 2007

150 100

heat power 190

Total capacity in operation [GW] 2007 Produced energy [TWh] 2007

147 89

94 58

50 0

10 Solar thermal Wind power heat

9.4 10

0.61.5

0.4 0.6

Geothermal Photovoltaic Solar thermal Ocean tidal power power power

Solar domestic hot water systems cost in Europe EUR 50-160 per MWh of heat, which is usually more expensive than heat from natural gas in urban areas, but often prove competitive with retail electricity prices. For solar combi-systems the cost is about EUR 160-500 per MWh. These costs are expected to decline by 2030 to EUR 50-80 per MWh for solar hot water systems, 100-240 EUR per MWh for combi-systems, and EUR 30‑50 per MWh for large-scale applications (>1MWth). Recent experience suggests that costs are reduced by 20% when the cumulative capacity doubles at country level. The profitability of solar space heating systems depend son solar resource and on the heat demand. In France, for example, space heating systems offer better economic performance in the east or the north while solar water heaters are more profitable in the south. Figure 6: Solar energy, domestic hot water heating, space heating and space cooling needs in Central Europe

Solar collector yield Domestic hot water demand

Source: ESTIF, 2007

Space heating demand Cooling demand

Solar cooling requires more expensive investments, but costs are reduced if a solar thermal collector is designed to be used for both summer cooling and winter heating. Solar cooling benefits from a better time-match between supply and demand (See Figure 6).

Letting the sun heat buildings in winter and letting daylight enter them to displace electric lighting, is the least-cost form of solar energy. In many cases, for small additional investment costs, passive solar design can help cut up to 50% of heating and cooling loads in new buildings.

Markets can be naturally growing or incentive-driven. In China, Cyprus and Turkey, low-cost solar water heaters are already an economic alternative for households to produce hot water. In incentive-driven markets like Germany and Austria, there are grants for households and companies. A third category of market is driven by legal frameworks such as solar ordinances. Israel passed an ordinance 30 years ago that applies to all new residential buildings, hotels, homes for the elderly and boarding schools. Spain followed two years ago with a national solar ordinance (regions had initiated the trend).

In Australia and some US States, solar water heaters can count toward utilities’ renewable energy portfolio standards. Forthcoming stringent regulations of specific net energy consumption in new buildings, such as in most European countries, are likely to benefit solar heat markets. Barriers to the installation of SHC can be technical, economical, institutional, legal or behavioural. Technical issues at component level have been fixed by most manufacturers, but many countries have a shortage of skilled personnel able to properly conceive and install solar systems.

Economic barriers: High up-front expenses deter many potential investors looking for short “pay-back time” while the investment offers long-term benefits. The volatility of fuel prices, the lack of internalisation of environmental costs of various alternatives and, in some countries, the high-level of subsidies to fossil fuels can also twist decisions against solar heating. The slow rotation of building stock is also a barrier, as solar space heating technologies are usually possible in new construction or extensive retrofits only. Institutional barriers: Property developers and building owners renting their properties have little incentive to invest in solar thermal devices for the benefit of the current occupants. “Split incentives” also exist in large companies or public services, when resources for investment and operating costs are separated. Other institutional barriers arise in multi-dweller buildings.

Legal barriers vary greatly from country to country, as well as at more local levels. Permitting is often an issue. Behavioural issues include lack of awareness of the current status of the technology, reluctance to manage a slightly more complex system and the (mis)perception that variability may lead to a lower comfort.

SOLAR

HEATING AND COOLING

Systems of this size might be used only for water heating, or also contribute to space heating (as in the Netherlands). Combi-systems covering a larger fraction of heating loads may require collectors from 15 to 30 m2 in Europe.

Outlook

Growth drivers

Barriers

EATING AND COOLIN

Long-term The IEA World Energy Outlook 2008 foresees a contribution from solar thermal of 45 Mtoe to final energy scenarios demand by 2030 if policies do not change. Extending the same trend to 2050 would lead to a contribution of 180 Mtoe, or about 18% of the total forecasted heat demand at that time.

The European Solar Thermal Industry Association forecasts an installed capacity of 1019 GWth by 2030 in the European Union, supplying about 15% of the low temperature heat demand, by 2030. By 2050, the capacity could reach 2 716 GWth to supply about 129 Mtoe of solar heat – 47% of the overall heat demand in EU-27, or roughly 20% of the region’s overall energy demand. Solar thermal technologies can have significant effects on electric systems or regional fuel markets. For example, in South Africa, electric water heating accounts for a third of the power consumption of the average household. The government has identified the massive deployment of solar water heaters as one effective option to avoid electric shortages.

Environmental impacts

Solar thermal requires no fossil fuel and produces little environmental pollution during its manufacture, operation and decommissioning. CO2 emissions from solar thermal energy are small. If the external costs of energy technologies were systematically taken in account, solar thermal energy could possibly be already competitive with most heating technologies.

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System-related aspects

External costs

Local impacts Solar thermal systems generally do not have a big visual impact. Recent systems are placed on the roof of

Technology status and developments

buildings, and more and more integrated into roof systems and building envelopes (see Figure 7). Systems for domestic hot water and space heating are now mature in various climatic environments but inexperienced installers might still make mistakes.

Figure 7: Integration of solar thermal in the building envelop

Solar thermally-driven air conditioning and cooling systems are still under development, in particular for individual houses.

R&D priorities

Material research Effective optical coatings on surfaces and low-cost, anti-reflective, self-cleaning glazing materials need to be developed. To prolong service intervals and lifetime, the ability of new materials like polymeric materials and carbon nano tubes and components to withstand high temperatures must be improved.

Advanced components Multifunctional facade and roof systems with integrated solar thermal collectors are needed for large-scale applications, especially in combi-systems. New process heat collectors for medium temperature levels (up to 250°C) would help develop solar heat for industry and cooling systems. Photovoltaic-thermal combined collectors would deliver warm water and electricity.

Compact storages with Advanced and more compact storage could allow a cost-effective increase in the solar share of heating loads. high energy density Phase-change materials or thermo-chemical processes are being explored for these purposes, with the aim of increasing the energy density of heat storages by the factor of 8. Increased R&D efforts are necessary to provide these new storage technologies by 2030. System development Many improvements are expected in the area of solar air conditioning and cooling, especially for small systems and Combi+ systems providing domestic hot water, space heating and cooling, as well as combinations of solar thermal and heat pumps.

. Weiss, W. and P. Biermayr: Potential of Solar Thermal in Europe, ESTIF, 2009. © OECD/IEA, 2009 - photo : R. Delacloche /OBSERV’ER - Architecte : H. Vidal

oncentrating Thermal Powe

www.iea.org

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Renewable Energy Essentials: Concentrating Solar Thermal Power n

Concentrating solar thermal power (CSP) turns sunlight into electricity.

SP requires clear skies and strong sunlight, which is abundant in the southwestern United States, Mexico, C North Africa, the Middle East, Central Asia, South Africa and Australia. Southern Europe and parts of China and India may also have sufficient solar resources.

oncentrated solar thermal power provides firm, peak, intermediate or base load capacities due to thermal C storage and/or fuel back-up.

SP technology showed especially strong growth in Spain and the United States since 2006. Installed C capacities near 1 gigawatt (GW) and projects under development or construction exceed 15 GW worldwide.

I nvestment costs range from USD 4.2 to 8.4 per watt, depending on the solar resource and the size of the storage. Levelised electricity costs range from US cents 17-25 per kWh, mostly depending on the quality of the solar resource.

E nergy costs are expected to decrease as more suppliers enter the market and as a result of R&D efforts and learning. In good sites, they could break the threshold of US cents 10 in fewer than ten years.

T he BLUE scenario of the IEA publication, Energy Technology Perspectives 2008, foresees that CSP will provide 5% of world electricity by 2050. Preliminary results of the forthcoming IEA CSP Roadmap suggest a contribution of 12% to global electricity supply by 2050.

Market status Concentrated solar thermal power (CSP) is a re-emerging market. The Luz Company built 354 MWe of commercial Recent trends plants in California, still in operations today, during 1984-1991. Activity re-started with the construction of an

11-MW plant in Spain, and a 64-MW plant in Nevada, by 2006. There are currently hundreds of MW under construction, and thousands of MW under development worldwide. Spain and the United States together represent 90% of the market. Algeria, Egypt and Morocco are building integrated solar combined cycle plants, while Australia, China, India, Iran, Israel, Italy, Jordan, Mexico, South Africa and the United Arab Emirates are finalising or considering projects. While trough technology remains the dominant technology, several important innovations took place over 2007-2009: the first commercial solar towers, the first commercial plants with multi-hour capacities, the first Linear Fresnel Reflector plants went into line.

The solar Concentrating sunrays requires clear skies, which are usually found in semi-arid, hot regions. The resource resource: DNI is measured as Direct Normal Insolation (DNI), which is the energy received on a (tracking) surface Figure 1: Direct Normal Insolation in kWh/m2.y and on-going projects Breyer & Kniess 2009, after DLR-ISIS, plus IEA information. Spain troughs 100+; towers 31; troughs 660+; tower 17+

Algeria, ISCC troughs 20/470; 140/800

Jordan troughs 100

USA troughs 424; Fresnel 177; troughs 1583; towers 645; dishes 800

Israel troughs 100 Egypt ISCC troughs 25/150 Emirates troughs 100 Iran ISCC troughs 67/450

3 000 kWh/m2/y 2 500 kWh/m2/y 2 000 kWh/m2/y 1 500 kWh/m2/y 1 000 kWh/m2/y

Morocco ISCC troughs 25/150

South Africa tower 100

Australia fuel saver Fresnel 2/2000

500 kWh/m2/y 0 kWh/m2/y

Legend: existing capacities; capacities under construction; announced capacities; xx: capacity in MWe. +: indicates large storage capacities (the capacity of the power plant is larger than the electrical capacity indicated); xx/yy: for Integrated Solar Combined Cycle or fuel saver systems, xx indicates the solar capacity, yy indicates the overall capacity.

ÂŠ OECD/IEA, 2009

oncentrating Thermal Powe

perpendicular to the sunrays. Areas suitable to CSP technologies are found between 15° to 40° parallels – and occasionally at higher latitude. The most favourable areas, shown in Figure 1, are found in large parts of North Africa, Middle East, southern Africa, western India, the southwestern United States, Mexico, places in South America, and Australia. Other suitable areas are in the extreme south of Europe and Turkey, central Asian countries, western China. Satellite data and regional climatic mapping must be confirmed with DNI monitoring on the ground.

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Manufacturing The building of CSP plant creates eight to ten jobs per megawatt of equivalent electrical solar capacity in the and employment construction and manufacturing of components.

Economics

For large state-of-the-art trough plants, investment costs are in a range of USD 4.2 to 8.4 per Watt depending

Investment costs on labour and land costs, technologies, the quality of the solar resource (DNI) and the sizes of storage and solar field.

Generation costs Levelised electricity costs range from USD 170 to 250 per MWh for large trough plants, depending mostly on the solar resource (assumptions: 30 years economic lifetime, 8% discount rate).

When there is large storage capacity, the investment costs increase significantly with the size of the solar field but so does the electrical output, so the energy cost changes only marginally. If storage serves to extend the production, energy costs will slightly decrease as smaller turbines can be used.

Cost reductions As cumulative capacities increase, investment costs Figure 2: Levelised electricity cost from CSP plants

Growth drivers

The deployment of CSP plants is driven by feed-in tariffs in Spain, and Renewable Energy Portfolio Standards and a grant programme in the United States. Projects in Egypt and Morocco are supported by grants from the Global Environment Facility. Algeria, South Africa and the Gujarat State in India have also established feed-in tariffs for CSP.

Source: IEA analysis. Assumption: 16 GW global CSP capacity by 2015-2020.

Desert climat

2015 - 2020

Seville Spain

Outlook

and energy costs will decrease to an estimated range of USD 97 to 130 per MWh by 2015-2020, assuming learning rates of 12% for the solar-specific investments and of 5% for the power block and balance of plant investments.

Today 2015 - 2020 Today 0

100

150

200

250

The Mediterranean Solar Plan of the Union for the Mediterranean is likely to initiate a wave of new projects on the south shore of the Mediterranean Sea. Of a total of 20 GW renewable energy capacities expected by 2020, half or more might be CSP plants. Exports of renewable electricity to the European Union would provide a strong incentive.

Barriers Low costs of fossil fuels remain an important barrier on grid – even more so in countries where fossil fuels prices are kept below world prices by direct or indirect government subsidies. Suitable areas are often semi-arid and water scarcity might be an issue, unless costlier dry cooling is used. Permitting and connection to the grid might also be challenging.

Technical potential The technical potential for CSP is virtually unlimited. An area of 100 miles squared in Nevada could power

the entire US economy. The technical potential of the Middle East and North Africa (MENA) is more than one hundred times the total current electricity consumption of the MENA and European regions together. High voltage direct current (HVDC) transport lines may allow CSP suitable areas to feed energy-demand centres.

Long-term In the “Advanced Scenario” of their publication CSP Global Outlook 2009, the IEA SolarPACES Programme, scenarios the European Solar Thermal Electricity Association and Greenpeace have estimated the global CSP capacity by 2050 at 1500 GW. With large storage and solar fields, the yearly output would be 7 800 TWh, or 670 million tonnes oil equivalent.

In a detailed study of renewable energy potential in the Middle-East North Africa Region, the German Aerospace Center (DLR) has estimated that CSP plants could possibly provide by 2050 about half the region’s electrical production, from a total of 390 GW CSP capacities.

Figure 3: Growth of global renewable electricity production in the BLUE Scenario of ETP 2008

600 500

In the Blue Scenario of the IEA publication, Energy Technology Perspectives (ETP) 2008, where global energy-related CO2 emissions are down to half their 2005 level by 2050, CSP would globally produce 2 200 TWh at the time from a capacity of 630 GW. CSP would thus contribute to about 5% of global electricity production (see Figure 3).

400 300

Blue

200

Act

100 0

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

Preliminary results of the forthcoming IEA CSP Roadmap suggest a solar contribution from CSP of 12% to global electricity supply by 2050.

In regions with suitable solar resources, peak electricity loads are increasingly driven by air-conditioning systems; there is a good match between loads and resources. Further, CSP technologies are usually open to both thermal storage and fuel back-up, offering systemic advantages. Thermal storage and fuel back-up increase the value of the plant by providing guaranteed capacities. Storage can be used to extend the electricity generation after sunset, when electricity loads remain high. Storage could also serve round-the-clock, base-load generation, displacing, e.g. high-CO2 emitting coal plants. Figure 4: Round-the-clock operation of a CSP plant with storage and back-up

40 30 20

Fossil backup

10 0

To storage

Firm capacity line

From storage

Solar direct

Source: Geyer, SolarPACES Annual Report 2007

SOLAR

Concentrating Thermal Power

700

20 22 24 Time of day

Cheap back-up with some fuel can extend the guarantee of full capacity to winter periods – avoiding costly extra-investment in the solar field. This can be especially useful at a system level as other renewable energy technologies (e.g. wind turbines) cannot offer guaranteed capacity.

System-related aspects

Life-cycle CO2 emissions of solar-only CSP plants are assessed at 17 g/kWh against, e.g., 776 g/kWh for coal plants and 396 g/kWh for natural gas combined cycle plants. However, to the extent that some fossil fuel is used as a back-up, a CSP plant or an ISCC cannot be qualified as a “zero-emitting” plant. In Energy Technology Perspectives 2008, CSP would save annually about 1 260 Mt CO2 in the BLUE scenario – 7% of a total 18 Gt CO2 avoided in electricity production relative to the reference scenario. Other polluting emissions – from SOx to NOx, metals and particulate matters – would also be avoided.

Environmental impacts

An 80 MW trough plant requires about 1.2 million cubic meters of water per year, mostly for cooling the steam cycle, and for cleaning the mirrors. Dry air cooling systems could considerably reduce the consumption of water, at a cost.

Local impacts

The use of molten salts and synthetic oil in a CSP plant bears some risk of spillage or fire. This may in turn hinder acceptance of a project by the local population.

There are four main technologies, shown in Figure 5. Troughs and Fresnel reflectors track the sun on one axis, while dishes and towers track the sun on two axes. Troughs or parabolic cylinders concentrate the solar rays on long heat collector pipes (moving with the troughs). Current plants use some synthetic oil as heat transfer fluid. Alternative concepts include direct steam generation, and the use of molten salts as transfer fluid. Troughs represent the most mature technology and the bulk of current projects; some have significant storage capacities. Their solar to electricity conversion can reach than 15% (annual mean value). Linear Fresnel reflectors (LFR) use slightly curved mirrors reflecting the solar rays on a long, fixed receiver. Investment costs per mirror area are lower but the annual efficiency remains below 10%. Saturated steam is directly generated in the receiver tubes. . External Costs from Emerging Electricity Generation Technologies, NEEDS, 2009. © OECD/IEA, 2009

Life-cycle emissions

Technology status and development

oncentrating Thermal Powe

Towers or central receiver systems (CRS), concentrate the sunrays on top of a fixed tower. This allows for higher temperatures and efficiencies than linear systems. Towers can generate saturated or superheated steam directly, or use molten salts, air or other media as heat transfer fluids. Solar fields of thousands of small heliostats are proposed as a cheap alternative to state-of-the-art field design.

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Parabolic dishes concentrate the sunrays on a focal point that is moving together with the dish tracking the sun, offering the highest optical efficiency on much smaller capacities (typically tens of kW). Mass production may allow them to compete with the larger systems, which benefit from economies of scale. Dish systems are less compatible with thermal storage than other CSP technologies, but require no cooling water. Figure 5: Troughs, towers, LFR and dishes Source: CSP Global Outlook 2009. Linear Fresnel reflector (IFR)

Central receiver

Parabolic dish

Parabolic trough

Central receiver

Curved mirrors

Reflector Absorber tube

Receiver/ engine Absorber tube and reconcentrator

Heliostats

Solar field piping

Reflector

Storage and Trough plants, linear Fresnel reflectors and most tower designs can be completed with heat storage and/or integration fuel back-up. The current reference technology for storage is based on molten salts.

R&D priorities

“Integrated Solar Combined Cycle” power plants are relatively small solar fields in large combined cycle gasfired plants. The heat from the solar field increases the production of the bottom steam cycle. Research and development efforts so far, most of them taking place within the IEA Solar PACES Implement Agreement, have been supported in particular by Germany, the European Commission and the US Department of Energy. Improvements can be expected on all components of CSP plants. One possible step improvement with troughs would be direct steam generation, increasing the overall efficiency. Phase-change materials and concrete offer novel options for storage. Towers have even greater room for improvements. Many innovative designs are currently proposed, with one or several towers sharing fields of heliostats, a great variety of central receiver designs, heat fluids and storage options. Towers with air receivers feeding the gas turbine of a combined cycle power plant could offer record solar-toelectricity efficiency of around 35%. Other possible applications are industrial process heat and brine water desalination. The production of solar fuels such as hydrogen and other energy carriers can take several roads, notably in conjunction with fossil fuels but reducing their carbon footprint (see Figure 6); it still requires significant R&D efforts. Figure 6: Different ways of producing hydrogen from solar energy Source: Steinfeld, 2005. Water splitting Water Solar thermolysis

Concentrated solar energy

Solar thermochemical cycle

Decarbonisation Fossil fuels (NG, oil, coal)

Solar electricity + electrolysis

Long-term goal Solar hydrogen

Solar reforming Short/mid-term transition

Solar gasification

Optional CO2 sequestration

EOTHERMA

www.iea.org

Renewable Energy Essentials: Geothermal n Geothermal energy is energy available as heat contained in or discharged from the earth’s crust that can

be used for generating electricity and providing direct heat for numerous applications such as: space and district heating; water heating; aquaculture; horticulture; and industrial processes. In addition, the use of energy extracted from the constant temperatures of the earth at shallow depth by means of ground source heat pumps (GSHP) is also generally referred to as geothermal energy.

n World geothermal energy installed capacity at the end of 2009 was 10.7 gigawatts (GWe) for electricity

generation and 50.6 GWth for direct use. Approximately 67 terawatt hours (TWh) of baseload electricity were generated with typical capacity factors of 75%. Almost 440 petajoules (PJ) of direct heat were used, with ground source heat pumps (GSHPs) the largest contributor at about 50%.

n Positive

characteristics of geothermal include: capability to provide base load power; no seasonal variation; immunity from weather effects and climate change impacts; compatibility with both centralised and distributed energy generation; resource availability in all world regions, particularly for direct use. Barriers to deployment include high capital cost, resource development risk, lack of awareness about geothermal energy and perceived environmental issues.

n Geothermal

investment worldwide exceeded USD 2.5 billion in 2008, up 40% on 2007. In 2008, the global geothermal sector employed about 25 000 people, and more than 6 GW of new projects were under development and are expected to be completed in 2015.

n In

2008 capital costs for greenfield geothermal flash plant developments ranged from USD 2000/kWe to USD 4 500/kWe, with lower temperature binary developments at USD 2400->5900/kWe. Capital cost pay-back times for ground source heat pumps typically range from four to eight years in Europe.

ecent electricity generation costs for flash plant developments range from USD 0.05/kWh to R USD 0.12/kWh for higher temperature resources and USD 0.07/kWh to USD 0.20/kWh for lower temperature binary developments. Production costs for district heating in Europe vary between USD 0.06/kWht and USD 0.17/kWht; average GSHP costs amount to USD 0.08/kWht.

n Geothermal

power production could increase up to more than 1 000 TWh by 2050, according to the IEA Energy Technology Perspectives (ETP) 2010 BLUE Map scenario. Forecasts for 2050 presented at the World Geothermal Congress 2010 indicate a possible increase of geothermal direct use (including GSHP) of almost twenty times compared to current levels.

Market status In Electricity generation and capacity

2009, the global geothermal energy installed capacity was 10.7 GWe and generated 67.2 TWh of electricity, at an average of 6.3 GWh/MWe. Geothermal power provides a significant share of total electricity demand in Iceland (25%), El Salvador (22%), Kenya and the Philippines (17% each), and Costa Rica (13%). In absolute figures, the United States produced the most geothermal electricity: 16 603 GWh from an installed capacity of 3 093 MWe (Table 1). Table 1. Top 15 countries using geothermal energy Data source: Bertani, WGC 2010; Lund et al., WGC 2010

Geothermal electricity production Country United States Philippines Indonesia Mexico Italy Iceland New Zealand Japan Kenya El Salvador Costa Rica Turkey Papua New Guinea Russia Nicaragua

GWh/yr 16 603 10 311 9 600 7 047 5 520 4 597 4 055 3 064 1 430 1 422 1 131 490 450 441 310

Geothermal direct use Country China United States Sweden Turkey Japan Norway Iceland France Germany Netherlands Italy Hungary New Zealand Canada Finland

GWh/yr* 20 932 15 710 12 585 10 247 7 139 7 000 6 768 3 592 3 546 2 972 2 762 2 713 2 654 2 465 2 325

* 1 000 GWh = 3.6 PJ

Direct use capacity Over 70 countries utilise geothermal energy for direct heat applications, such as: ground source heat pumps

EOTHERMA

(GSHPs); space heating; greenhouse and aquaculture pond heating; crop drying; industrial processes; bathing; cooling; and snow melting. Total estimated thermal energy use in 2009 was 438 PJ, 60% higher than in 2005 (Table 1). Significant growth in the GSHP market continues worldwide, with about 2.9 million units installed, >35 GWth capacity and >214 PJ heat production.

Manufacturing Geothermal power is generated using steam and binary cycle plants, the latter dominant at temperatures and employment <180 °C. Most geothermal steam turbines and generators are manufactured in Japan, while the United

States produces the majority of binary cycle generators. Other major manufacturing countries include Italy, Germany, France and Mexico. The worldwide geothermal industry employed about 25 000 people in 2008.

Economics

Investment costs

Electricity generation: Geothermal development costs depend on resource temperature and pressure, reservoir depth and permeability, fluid chemistry, location, drilling market, size of development, number and type of plants (dry steam, flash, binary or hybrid) used, and whether the project is greenfield or expansion (10-15% less). Development costs are strongly affected by commodity prices (oil, steel and cement), and the drop in oil and gas prices since 2008 has contributed to decreasing geothermal capital costs. In 2008, the capital costs of a greenfield geothermal power development typically amounted to about USD 2 000–4 000/kWe for flash plant developments and USD 2 400-5 900/kWe for binary developments (Figure 1).

Figure 1. Capital costs Data source: IEA Geothermal Implementing Agreement.

Capital costs (USD/kW)

GSHP

Direct space heating

Range of binary plant

1 000

Hybrid (flash and binary) 2 000

The cost breakdown is shown in Table 2. Table 2. Breakdown of capital costs

Range of flash plant

3 000

4 000

5 000

6 000

Exploration and resource confirmation Drilling Surface facilities Power plant

10-15% 20-35% 10-20% 40-60%

Capital costs are expected to decrease by about 5% by 2020. In Europe, small binary developments (a few MWe) using low-medium temperature resources, like those now operating in Germany and Austria, are expected to multiply. Total investment costs are estimated to be about USD 5 900/kW. The availability of renewable energy feed-in tariffs and the sale of heat from CHP development (e.g. district heating) increase economic viability significantly. Direct use: Capital costs of geothermal systems for direct space heating range between USD 1 700/kWth and USD 3 950/kWth. Capital costs of ground source heat pumps strongly depend on the system selected. Costs for GSHPs are USD 439-600/kWth for China and India, USD 905-1 190/kWth for North America, and USD 1 170-2 267/kWth in Europe.1

Operation Electricity generation: O&M costs are a small percentage of total costs because geothermal requires no and maintenance fuel. Typical O&M costs depend on location and size of the facility, type and number of plants, and use of (O&M) costs remote-control; they range from USD 9/MWh (large flash) to USD 25/MWh (small binary), excluding well replacement drilling costs.

Direct use: Ground source heat pump systems are low maintenance cost systems.

Generation costs Electricity generation: Planned economic lifetimes of geothermal plants are typically 20-30 years,

though they usually operate for much longer (the Wairakei [NZ] and Larderello [IT] plants now exceed 50 years). A recent 30 MW binary development (United States) has estimated levelised generation costs of USD 72/MWh.2 New plant generation costs in some countries (e.g. New Zealand) are highly competitive (even without subsidies) at USD 50-70/MWh for known high temperature resources. For the United States, new greenfield levelised costs range up to USD 120/MWh; in Europe, costs range up to USD 200/MWh for lower temperature resources. Estimated Enhanced Geothermal Systems (EGS) production costs using current power plant technology range from USD 100/MWh (300 °C resource at 4 km depth) to USD 190/MWh (150 °C resource at 5 km) in the United States, while European estimates are USD 250-300/MWh (Figure 2). 1. Source: IEA Heat Pump Implementing Agreement, Navigant Consulting, Ecodesign Hot Water Task 4. 2. Under the condition of a 15-year debt, 6.5% interest rate. © OECD/IEA, 2010

GEOTHERMAL

Direct use: Direct use of geothermal energy for heating purposes can be currently competitive with conventional energy sources. In Europe, geothermal district heating costs are about USD 55-165/MWhth, averaging USD 68/MWhth. The average cost for GSHP operation is about USD 79/MWhth.

Figure 2. Generation costs Data source: IEA Geothermal Implementing Agreement. Generation costs (USD/MWh) >50 MW high t. flash <30MW Binary Greenfield high t. Greenfield low t. EGS District heating USD/MWth GSHP average USD/MWth 0

100

150

200

250

300

Electricity generation: Opportunities for cost reductions include reduced well drilling costs; more reliable high temperature and pressure (HTHP) downhole pumps and logging tools; more accurate estimates of resource potential prior to well drilling; and better methods of creating deep hot reservoirs and for control/mitigation of induced seismicity. In Europe, 2030 target costs are: USD 29/MWh for conventional geothermal; USD 74/MWh for low-temperature and EGS production.

Cost reductions

Direct use: GSHP cost reductions will be driven by economies of scale related to the rapid global deployment. In Europe, by 2030, cost is expected to decrease by 10%, to USD 74/ MWhth. District heating costs are expected to decrease by 5%, to USD 65/MWhth.

Investment in geothermal development grew significantly in the past few years, reaching USD 2 507 million in 2008, a several fold increase over 2005, and sustained 40% growth in 2007-2008.

New investment

Climate change and other negative environmental impacts of conventional power and heat production have raised awareness of the need to use renewable energies, including geothermal. Several countries in Europe have developed incentive schemes, e.g. feed-in tariffs and Renewable Portfolio Standards or quota obligations, that make geothermal power generation and GSHPs economic. Other drivers include the desire for energy independence and security; increasing fossil fuel costs; and rapidly growing energy demand.

Outlook

The main barriers to geothermal development are high initial capital costs and resource development risk, e.g. failure of drilling wells, significant depth requirements, insufficient productivity and accessibility of the reservoir. Other barriers to geothermal development include: low awareness and limited information about geothermal energy, related technology and the various options and advantages for both power generation and direct use; lack of incentive schemes and uncertainty about the future of such schemes; a shortage of trained geothermal scientists and engineers; and perceived environmental issues (induced seismicity, subsidence, etc.). For GSHPs, technical (standards, quality control) and legal security (licensing, regulation) issues are important.

Barriers

The Baseline scenario in IEA Energy Technology Perspectives (ETP) 2010 suggests that geothermal technology could provide 1% (approximately 300 TWh) of global electricity in 2050 (Figure 3). Furthermore, the ETP BLUE scenario, which targets a 50% CO2 reduction by 2050, suggests that geothermal electricity generation could increase up to 1 060TWh/yr in 2050. A forecast presented in the World Geothermal Congress 2010, indicates that the 2050 electricity installed capacity could go up to 160 GWe (including EGS), with an associated production of about 1 261 TWh/yr. In the same forecast, the expected total direct use capacity deployment in 2050 is estimated at 815 GWth (Figure 4).3

Long term scenarios

Geothermal developments have minor environmental impacts. The disposal of waste water containing small quantities of chemicals (boron and arsenic) and gases (H2S and CO2) is an important issue, but various methods are used for dealing with it, including total reinjection of separated water, condensate and gases; chemical treatment; and mineral extraction. Costs can amount to 1-2% of generation cost. CO2 emissions from low temperature resources are negligible (0-1 g/kWh). Most binary systems, district heating and CHP schemes typically operate in a closed-loop, hence have nearly zero emissions, as will EGS developments. GSHPs reduce CO2 emissions by at least 50% compared to an oil boiler, depending on the source of the electricity used.

Environmental impacts

Induced seismicity (felt earthquakes) has become an environmental/social issue at some EGS R&D projects. Small seismic tremors have sometimes been felt, though on a minor scale. An international protocol has been developed to address this concern, and proper management methods are being investigated. Subsidence (land sinking) has occurred and caused concern at a few high temperature developments; however, monitoring is standard, and targeted injection is used to minimise it.

Local impact

3. B romley, C.J., Mongillo, M., Hiriart, G., Goldstein, B., Bertani, R., Huenges, E., Ragnarsson, A., Tester, J. Muraoka, H. and Zui, V. (2010), Contribution of Geothermal Energy to Climate Change Mitigation: the IPCC Renewable Energy Report. Proc. World Geothermal Congress 2010, Bali, Indonesia, 25-30 April 2010, 5 pages. © OECD/IEA, 2010

Growth drivers

External effects

Figure 4. Geothermal direct use and GSHP capacity growth scenarios

Data source: IEA, 2010.

Data source: Bromley et al., 2010.

EOTHERMA

Figure 3. Geothermal electricity generation scenarios

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Technology status and development

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Conventional plants use steam separated from hot geothermal fluid to drive turbine-generators to produce electricity. Binary plants often use lower temperature (< 180 °C) fluid in a heat exchanger to “boil” a secondary fluid to create a gas that drives the turbine-generators. The emerging technology of EGS, which are underground reservoirs that have been created or improved artificially, circulates water from the surface down wells into deep, enhanced permeable volumes of hot rock, where it heats up, is produced through other wells, sent to binary plants to generate electricity, then circulated back down in a closed loop. Some power developments operate in a cascade mode, whereby the hot water exiting the flash or binary plants is used for district heating or other heat applications prior to disposal.

Use of hot supercritical hydrous fluid (400-600 °C) from great depths (4-5 km) will increase the power output/well by a factor of up to 10 (50 MWe/well), reducing development costs by decreasing the number of wells required. Geothermal developments have planned (economic) lifetimes of 20-30 years; although ~50% of the current global installed capacity has been in operation for >25 years, and two developments for >50 years. Geothermal plants operate with high capacity (75-95%), load (84-96%) and availability (92-99%) factors. Recovery through natural heat recharge allows depleted resources to be re-used after a rest period.

Ground source GSHPs use the relatively constant temperature of shallow ground (< 300 m deep) to provide space heating, heat pumps cooling and domestic hot water. GSHPs lift heat from low-temperature ground or groundwater to a higher useful temperature. GSHPs come in two general configurations: vertical borehole heat exchangers and horizontal subsurface loops. Ground source heat pumps are now the fastest growing application of direct geothermal energy use, with about 3 million GSHPs installed at the start of 2010.

Technology Advances in binary plant design have resulted in power production from fluids with temperatures as low as advances 73 °C. They allow power generation using separated water from steam plants, CHP use of deep sedimentary fluids and they may potentially allow EGS power generation almost anywhere on earth. Better tools for logging High Temperature and Pressure (HTHP) geothermal wells and smaller boreholes produce more reliable and accurate data faster, so reduce logging costs. Modern drill rigs, with better control equipment and drill bits, make it possible to drill more accurately and successfully, sometimes deeper and faster, thus reducing costs. Technology improvements in GSHPs are expected to improve the performance and lower the cost of heat pump technologies. Key components such as compressors and heat exchangers will provide the largest areas for improvement.

R&D priorities Further technology advances are expected in terms of better methods for more accurate estimates of resource potential prior to drilling, better drilling methods and equipment, more reliable HTHP downhole pumps and logging tools, better methods for creating/enhancing deep hot reservoirs, and better control/mitigation of induced seismicity. Reservoir utilisation/management will be improved with earlier better determination of sustainable production levels and dynamic recovery factors. The main R&D goals for GSHPs aim at reducing investment costs and improving operating efficiency, while expanding the range of products for most of the heating and cooling applications and sub-markets in the building sector.

The IEA wants to thank the Geothermal Implementing Agreement for their substantial contribution in preparing the Geothermal Essentials.