We must – and can – change our current path; we must initiate an energy revolution in which lowcarbon energy technologies play a lead role. If we are to reach our greenhouse-gas emission goals, we must promote broad deployment of energy efficiency, many types of renewable energy, carbon capture and storage, nuclear power and new transport technologies. Every major country and sector of the economy must be involved.
Moreover, we must ensure that investment decisions taken now do not saddle us with suboptimal technologies in the long term. There is a growing awareness of the urgent need to turn political statements and analytical work into concrete action. To spark this movement, at the request of the G8, the International Energy Agency (IEA) is developing a series of roadmaps for key energy technologies.
These roadmaps provide solid analytical footing that enables the international community to move forward, following a well-defined growth path – from today to 2050 – that identifies the technology, financing, policy and public engagement milestones needed to realise the technology’s full potential.
The IEA roadmaps include special focus on technology development and deployment to emerging economies, and highlight the importance of international collaboration. The emerging technology known as concentrating solar power, or CSP, holds much promise for countries with plenty of sunshine and clear skies.
Its electrical output matches well the shifting daily demand for electricity in places where airconditioning systems are spreading. When backed up by thermal storage facilities and combustible fuel, it offers utilities electricity that can be dispatched when required, enabling it to be used for base, shoulder and peak loads.
Within about one to two decades, it will be able to compete with coal plants that emit high levels of CO2. The sunniest regions, such as North Africa, may be able to export surplus solar electricity to neighbouring regions, such as Europe, where demand for electricity from renewable sources is strong.
In the medium-tolonger term, concentrating solar facilities can also produce hydrogen, which can be blended with natural gas, and provide low-carbon liquid fuels for transport and other end-use sectors. For CSP to claim its share of the coming energy revolution, concerted action is required over the next ten years by scientists, industry, governments, financing institutions and the public.
This roadmap is intended to help drive these indispensable developments.
Nobuo Tanaka, Executive Director
Concentrating solar power (CSP) can provide lowcarbon, renewable energy resources in countries or regions with strong direct normal irradiance (DNI), i.e. strong sunshine and clear skies. This roadmap envisages development and deployment of CSP along the following paths:
By 2050, with appropriate support, CSP could provide 11 .3% of global electricity, with 9.6% from solar power and 1.7% from backup fuels (fossil fuels or biomass).
In the sunniest countries, CSP can be expected to become a competitive source of bulk power in peak and intermediate loads by 2020, and of base-load power by 2025 to 2030.
The possibility of integrated thermal storage is an important feature of CSP plants, and virtually all of them have fuel-power backup capacity. Thus, CSP offers firm, flexible electrical production capacity to utilities and grid operators while also enabling effective management of a greater share of variable energy from other renewable sources (e.g. photovoltaic and wind power).
This roadmap envisions North America as the largest producing and consuming region for CSP electricity, followed by Africa, India and the Middle East. Northern Africa has the potential to be a large exporter (mainly to Europe) as its high solar resource largely compensates for the additional cost of long transmission lines.
CSP can also produce significant amounts of high-temperature heat for industrial processes, and in particular can help meet growing demand for water desalination in arid countries.
Given the arid/semi-arid nature of environments that are well-suited for CSP, a key challenge is accessing the cooling water needed for CSP plants. Dry or hybrid dry/wet cooling can be used in areas with limited water resources.
The main limitation to expansion of CSP plants is not the availability of areas suitable for power production, but the distance between these areas and many large consumption centres.
This roadmap examines technologies that address this challenge through efficient, long distance electricity transportation.
CSP facilities could begin providing competitive solar-only or solar-enhanced gaseous or liquid fuels by 2030. By 2050, CSP could produce enough solar hydrogen to displace 3% of global natural gas consumption, and nearly 3% of the global consumption of liquid fuels.
Key actions by government in the next ten years
Concerted action by all stakeholders is critical to realising the vision laid out in this roadmap. In order to stimulate investment on the scale required to support research, development, demonstration and deployment (RDD&D), governments must take the lead role in creating a favourable climate for industry and utilities. Specifically, governments should undertake the following:
Ensure long-term funding for additional RD&D in: all main CSP technologies; all component parts (mirrors/heliostats, receivers, heat
transfer and/or working fluids, storage, power blocks, cooling, control and integration); all applications (power, heat and fuels); and at all scales (bulk power and decentralised applications).
Facilitate the development of ground and satellite measurement/modelling of global solar resources.
Support CSP development through long-term oriented, predictable solar-specific incentives.
These could include any combination of feed-in tariffs or premiums, binding renewable energy portfolio standards with solar targets, capacity payments and fiscal incentives.
Where appropriate, require state-controlled utilities to bid for CSP capacities.
Avoid establishing arbitrary limitations on plant size and hybridisation ratios (but develop procedures to reward only the electricity deriving from the solar energy captured by the plant, not the portion produced by burning backup fuels).
Streamline procedures for obtaining permits for CSP plants and access lines.
Other action items for governments, and actions recommended to other stakeholders, are outlined in the Conclusion.
The basic concept of concentrating solar power is relatively simple: CSP devices concentrate energy from the sun’s rays to heat a receiver to high temperatures. This heat is transformed first into mechanical energy (by turbines or other engines) and then into electricity.
CSP also holds potential for producing other energy carriers (solar fuels). CSP is a proven technology. The first commercial plants began operating in California in the period 1984 to 1991, spurred by federal and state tax incentives and mandatory long-term power purchase contracts. A drop in fossil fuel prices then led the federal and state governments to dismantle the policy framework that had supported the advancement of CSP.
In 2006, the market reemerged in Spain and the United States, again in response to government measures such as feedin tariffs (Spain) and policies obliging utilities to obtain some share of power from renewables – and from large solar in particular.
As of early 2010, the global stock of CSP plants neared 1 GW capacity. Projects now in development or under construction in more than a dozen countries (including China, India, Morocco, Spain and the United States) are expected to total 15 GW.
Parabolic troughs account for the largest share of the current CSP market, but competing technologies are emerging. Some plants now incorporate thermal storage.
By contrast, photovoltaics (PV) and concentrating photovoltaics (CPV) produce electricity from the sun’s rays using direct conversion with semi-conductor materials.
The importance of the solar resource
The sunlight hits the Earth’s surface both directly and indirectly, through numerous reflections and deviations in the atmosphere. On clear days, direct irradiance represents 80% to 90% of the solar energy reaching the Earth’s surface. On a cloudy or foggy day, the direct component is essentially zero. The direct component of solar irradiance is of the greatest interest to designers of high temperature solar energy systems because it can be concentrated on small areas using mirrors or lenses, whereas the diffuse component cannot.
Concentrating the sun’s rays thus requires reliably clear skies, which are usually found in semi-arid, hot regions. The solar energy that CSP plants use is measured as direct normal irradiance (DNI), which is the energy received on a surface tracked perpendicular to the sun’s rays. It can be measured with a pyrheliometer.
DNI measures provide only a first approximation of a CSP plant’s electrical output potential. In practice, what matters most is the variation in sunlight over the course of a day: below a certain threshold of daily direct sunlight, CSP plants have no net production, due to constant heat losses in the solar field. CSP developers typically set a bottom threshold for DNI of 1900 kWh/m2/year to 2100 kWh/m2/year. Below that, other solar electric technologies that take advantage of both direct and diffuse irradiance, such as photovoltaics, are assumed to have a competitive advantage.
Distribution of the solar resource for CSP
The main differences in the direct sunlight available from place to place arise from the composition of the atmosphere and the weather. Good DNI is usually found in arid and semi-arid areas with reliably clear skies, which typically lay at latitudes from 15° to 40° North or South. Closer to the equator the atmosphere is usually too cloudy and wet in summer, and at higher latitudes the weather is usually too cloudy. DNI is also significantly better at higher altitudes, where absorption and scattering of sunlight are much lower.
Thus, the most favourable areas for CSP resource are in North Africa, southern Africa, the Middle East, northwestern India, the southwestern United States, Mexico, Peru, Chile, the western part of China and Australia. Other areas that may be suitable include the extreme south of Europe and Turkey, other southern US locations, central Asian countries, places in Brazil and Argentina, and other parts of China.
Recent attempts to map the DNI resource worldwide are based on satellite data. While existing solar resource maps agree on the most favourable DNI values, their level of agreement vanishes when it comes to less favourable ones. Important differences exist, notably with respect to the suitability of northeastern China, where the most important consumption centres are found. However, precise measurements can only be achieved through ground-based monitoring; satellite results must thus be scaled with ground measurements for sufficient accuracy.
Several studies have assessed in detail the potential of key regions (notably the United States and North Africa), giving special consideration to land availability: without storage, CSP plants require around 2 hectares per MWe, depending on the DNI and the technology.
Even though the Earth’s “sunbelts” are relatively narrow, the technical potential for CSP is huge. If fully developed for CSP applications, the potential in the southwestern US states would meet the electricity requirements of the entire United States several times over. Potential in the Middle East and North Africa would cover about 100 times the current consumption of the Middle East, North Africa and the European Union combined. In short, CSP would be largely capable of producing enough no-carbon or low-carbon electricity and fuels to satisfy global demand. A key challenge, however, is that electricity demand is not always situated close to the best CSP resources.
Transporting and exporting electricity from CSP
As demonstrated over decades by hydropower dams in remote regions, electricity can be transported over long distances to demand
centres. When distance is greater than a few hundred kilometres, economics favour highvoltage direct-current (HVDC) technology over alternative-current technology. HVDC lines of gigawatt capacity can exceed 1 000 km and can be installed across the seabed; they also have a smaller environmental footprint.
Electricity losses are 3% per 1 000 km, plus 0.6% for each conversion station (as HVDC lines usually link two alternative-current areas). This creates opportunities for CSP plant operators to supply a larger range of consumers. However, the cost of constructing major transmission and distribution lines must be taken into account.
Current technologies for power production
At present, there are four main CSP technology families, which can be categorised by the way they focus the sun’s rays and the technology used to receive the sun’s energy.
Parabolic troughs (line focus, mobile receiver)
Parabolic trough systems consist of parallel rows of mirrors (reflectors) curved in one dimension to focus the sun’s rays. The mirror arrays can be more than 100 m long with the curved surface 5 m to 6 m across. Stainless steel pipes (absorber tubes) with a selective coating serve as the heat collectors. The coating is designed to allow pipes to absorb high levels of solar radiation while
emitting very little infra-red radiation. The pipes are insulated in an evacuated glass envelope. The reflectors and the absorber tubes move in tandem with the sun as it crosses the sky.
All parabolic trough plants currently in commercial operation rely on synthetic oil as the fluid that transfers heat (the heat transfer fluid) from collector pipes to heat exchangers, where water is preheated, evaporated and then superheated. The superheated steam runs a turbine, which drives a generator to produce electricity. After being cooled and condensed, the water returns to the heat exchangers.
Parabolic troughs are the most mature of the CSP technologies and form the bulk of current commercial plants. Most existing plants, however, have little or no thermal storage and rely on combustible fuel as a backup to firm capacity. For example, all CSP plants in Spain derive 12% to 15% of their annual electricity generation from burning natural gas. Some newer plants have significant thermal storage capacities.
Linear Fresnel reflectors (line focus, fixed receiver)
Linear Fresnel reflectors (LFRs) approximate the parabolic shape of trough systems but by using long rows of flat or slightly curved mirrors to reflect the sun’s rays onto a downward-facing linear, fixed receiver. A more recent design, known as compact linear Fresnel reflectors (CLFRs), uses two parallel receivers for each row of mirrors and thus needs less land than parabolic troughs to produce a given output.
The main advantage of LFR systems is that their simple design of flexibly bent mirrors and fixed receivers requires lower investment costs and facilitates direct steam generation (DSG), thereby eliminating the need for – and cost of – heat transfer fluids and heat exchangers. LFR plants are, however, less efficient than troughs in converting solar energy to electricity and it is more difficult to incorporate storage capacity into their design.
Solar towers (point focus, fixed receiver)
Solar towers, also known as central receiver systems (CRS), use hundreds or thousands of small reflectors (called heliostats) to concentrate the sun’s rays on a central receiver placed atop a fixed tower. Some commercial tower plants now in operation use DSG in the receiver; others use molten salts as both the heat transfer fluid and storage medium.
The concentrating power of the tower concept achieves very high temperatures, thereby increasing the efficiency at which heat is converted into electricity and reducing the cost of thermal storage. In addition, the concept is highly flexible; designers can choose from a wide variety of heliostats, receivers, transfer fluids and power blocks. Some plants have several towers that feed one power block.
Parabolic dishes (point focus, mobile receiver)
Parabolic dishes concentrate the sun’s rays at a focal point propped above the centre of the dish. The entire apparatus tracks the sun, with the dish and receiver moving in tandem. Most dishes have an independent engine/generator (such as a Stirling machine or a micro-turbine) at the focal point. This design eliminates the need for a heat transfer fluid and for cooling water.
Dishes offer the highest solar-to-electric conversion performance of any CSP system. Several features – the compact size, absence of cooling water, and low compatibility with thermal storage and hybridisation – put parabolic dishes in competition with PV modules, especially concentrating photovoltaics (CPV), as much as with other CSP technologies. Very large dishes, which have been proven compatible to thermal storage and fuel backup, are the exception. Promoters claim that mass production will allow dishes to compete with larger solar thermal systems.
Parabolic dishes are limited in size (typically tens of kW or smaller) and each produces electricity independently, which means that hundreds or thousands of them would need to be co-located to create a large-scale plant. By contrast, other CSP designs can have capacities covering a very wide range, starting as low as 1 MW. The optimal size of troughs, LFR and towers, typically from 100 MW to 250 MW, depends on the efficiency of the power block.
Some smaller CSP devices combine fixed receivers with parabolic troughs or, more often, dishes (called “Scheffler dishes”). They are notably used in India for steam cooking devices in facilities that serve thousands meals per day. Dishes have also been used for process heat by gathering the heat collected by each dish; feeding a single power block to produce electricity this way is possible, but this option does not seem to be pursued at present.
Solar thermal electricity without concentration is also possible. Highly efficient non-concentrating solar collectors could evaporate enough steam to run specific power blocks (e.g. based on organic Rankine cycles). The efficiency would be relatively low in comparison to CSP technologies discussed above, but non-concentrating solar power could capture both direct and diffuse sunlight (like PV modules) and thus expand the geographic areas suitable for solar thermal electricity. Low-cost thermal storage and fuel backup could give this technology interesting features when and if it becomes commercial.
Although CSP currently requires higher capital investments than some other energy sources, it offers considerable long-term benefits because of minimum fuel costs for backup/hybridisation. Moreover, initial investment costs are likely to fall steadily as plants get bigger, competition increases, equipment is mass produced, technology improves and the financial community gains confidence in CSP.
In the near term, the economics of CSP will remain more favourable for peak and intermediate loads than for base loads, for reasons explained in this section.
For large, state-of-the-art trough plants, current investment costs are USD 4 .2/W to USD 8.4/W depending on labour and land costs, technologies, the amount and distribution of DNI and, above all, the amount of storage and the size of the solar field. Plants without storage that benefit from excellent DNI are on the low side of the investment cost range; plants with large storage and a higher load factor but at locations with lower DNI (around 2000 kWh/m2/year) are on the high side.
These investments costs are slightly higher than those of PV devices, but CSP plants have a greater energy output per MW capacity. Investment costs per watt are expected to decrease for larger trough plants, going down by 12% when moving from 50 MW to 100 MW, and by about 20% when scaling up to 200 MW. Costs associated with power blocks, balance of plant and grid connection are expected to drop by 20% to 25% as plant capacity doubles. Investment costs are also likely to be driven down by increased competition among technology providers, mass production of components and greater experience in the financial community of investing in CSP projects. Investment costs for trough plants could fall by 10% to 20% if DSG were implemented, which allows higher working temperatures and better efficiencies.
Turbine manufacturers will need to develop effective power blocks for the CSP industry. In total, investment costs have the potential to be reduced by 30% to 40% in the next decade.
For solar towers, investment costs are more difficult to estimate, but are generally higher than for trough plants. However, increasing efficiency from 15% to 25% will allow a 40% reduction in investment in solar-specific parts of the plants, or 20% of overall investment costs. The recent trend toward numerous mass-produced, small, flat mirrors promises to bring costs down further, as the problems of wind resistance and precision in pointing are resolved using computers. As the solar tower industry rapidly matures, investment costs could fall by 40% to 75%.
The costs of CSP electricity should go down even more. Some experts see a greater potential in developing countries for local fabrication of towers than of troughs, leading to lower costs in emerging economies.
Operation and maintenance costs
Operation and maintenance costs for CSP include plant operation, fuel expenses in the case of hybridisation or backup, feed and cooling water, and field maintenance costs. A typical 50 MW trough plant requires about 30 employees for plant operation and 10 for field maintenance. Operation and maintenance costs have been assessed from USD 13/MWh to USD 30/MWh, including fuel costs for backup. As plants become larger, operation and maintenance costs will decrease.
Costs of providing finance for CSP plants
Financing schemes can differ markedly from one investment and legal environment to another, with significant consequences for the costs of generating electricity and the expected rates of return on investment. Large utilities building their own plants with available cash do not incur the costs that utilities or investors face when combining equity and loans from various sources to finance plants. Differences among fiscal regimes, in particular with respect to corporate taxes, have an impact on the turnkey costs (the expenditures necessary before a plant is ready for use) depending on how long it takes to secure financing and build the plant. This impact might be significant for CSP plants that may require one to two years of construction.
The same parameters will have an even greater impact on the electricity generating costs, as capital expenses are much larger for CSP plants than for, say, fossil-fuel plants.
Levelised energy costs, which estimate a plant’s annualised lifetime cost per unit of electricity generation, range from USD 200/MWh to USD 295/MWh for large trough plants, the technology for which figures are most readily available. The actual cost depends mostly on the available sunlight.
The impact of storage on generating costs is not as simple as it may seem. When there is storage capacity, the investment costs increase with the size of the solar field and the added storage but so do the capacity factor and the yearly electrical output (e.g. up to 6 600 hours in Spain with 15 hours of storage), thus the energy cost changes only marginally.
In any case, the main merit of storage is not to reduce the cost of electricity but to increase the value of the plant to the utility in making its capacity firm and dispatchable, allowing solar plants to compete with fossil-fuel plants by supplying base-load power in the
In the regions where CSP plants can be installed, peak and intermediate loads are more often driven by air-conditioning than by electric heating demands, corresponding to the optimal daily and seasonal operation periods for CSP plants. This explains why the economics of CSP will remain more favourable for peak and intermediate loads than for base loads in the coming decade, unless or until CO2 emissions are heavily priced.
Competing energy sources have significantly higher generation costs for peak and mid-peak demand, while the cost of CSP electricity is about the same for peak and base load. Peak loads are usually considered as cumulating 10% of the yearly consumption of electricity, intermediate loads 50% and base loads the remaining 40%. This indicates that there will be an ample market for CSP with peak and intermediate loads, and no need to rush into baseload production.
The US Department of Energy has set an objective for its CSP programme to reach competitiveness with fossil fuels by 2015 for intermediate loads, at around USD 100/MWh, and by 2020 for base loads, at around USD 50/MWh. According to the evolution of levelised electricity costs envisioned in this roadmap, competitiveness is more likely to be achieved by 2020 for intermediate loads and 2025 to 2030 for base loads.
Assuming an average 10% learning ratio, CSPinvestment costs would fall by about 50% from 2010 to 2020, as cumulative capacities would double seven times according to the vision proposed in this roadmap – if all stakeholders undertake the actions it recommends. Electricity costs would decrease even faster thanks to progressively greater capacity factors, making CSP technology competitive with conventional technologies for peak and intermediate loads in the sunniest countries by about 2020. This perspective is fully consistent with the potential for improvement for the various technologies identified in the next section.
Solar thermal hydrogen production costs are expected to be USD 2/kg to USD 4 /kg by 2020 for efficient solar thermodynamic cycles (detailed below), significantly lower than costs of solar electricity coupled with electrolysis, which are expected to be USD 6/kg to USD 8/kg when solar electricity cost is down to USD 80/MWh. Solar assisted steam reforming of natural gas would become competitive with natural gas (as an energy source) at prices of about USD 11 /MBtu.
Overcoming economic barriers
CSP today is usually not competitive in wholesale bulk electricity markets, except perhaps in isolated locations such as islands or remote grids, so in the short term its deployment depends on incentives. A number of regions, including Spain, Algeria, some Indian states, Israel and South Africa, have put in place feed-in tariffs or premium payments.
Spain, for example, lets the producers choose between a tariff of EUR 270 (USD 375)/MWh, or a premium of EUR 250 (USD 348)/MWh that adds to the market price, with a minimum guaranteed revenue of EUR 250/MWh and a maximum of EUR 340 (USD 473)/MWh. This approach has proven effective, as it offers developers and banks long-term price certainty, and makes CSP one of the less risky investments in the power sector.
In the United States, the federal government recently created the Renewable Energy Grant Program, as well as a Federal Loan Guarantee Program designed to foster innovation. BrightSource became the first CSP provider to benefit from this programme, securing USD 1.4 billion from the US Department of Energy in February 2010 for several projects.
In the long term, however, financing of CSP plants may become difficult if investors in technology companies do not supply some equity capital. Prices for capacity and energy are only guaranteed by utilities on a case-by-case basis under renewable portfolio standards (the regulations that require increased production of energy from renewable sources) and these standards are not always binding.
As pointed out earlier in this roadmap, many different technical approaches to CSP have been proposed, each showing expected benefits and potential challenges. All these options have to be tested in pilot plants to reveal their benefits and constraints, so strong government support for innovative small pilot plants is direly needed. Small 5 MW pilot plants are essential as a step towards developing commercial plants.
Once a prototype has been tested through smallscale demonstration, it is conceivable to build a full-scale, first-of-its-kind commercial plant. This is a risky step for private investors. Managing firstof-their-kind plants draws upon public knowledge while also providing lessons to the global CSP community, so public R&D institutes should take part in these efforts.
The US Loan Guarantee Program is one example of a strong incentive designed to foster innovation by private investors. Another useful procedure could be for utilities bidding for capacities to specify that some degree of innovation is required.