Christoph Richter and Sven Teske
September 14, 2009 | 0 Comments
London, UK [Renewable Energy World Magazine] The levelized electricity cost of concentrating solar power plants depends on both the available solar resource and development costs of investment, financing and operation. Plants under the same price and financing conditions in the south western United States or upper Egypt, will have a levelized electricity cost 20% to 30% lower than in southern Spain or the north African coast. This is because the amount of energy from direct sunlight is up to 30% higher (2600–2800 kWh/m2 a year compared with 2000–2100 kWh/m2 a year). The solar resource is even lower in France, Italy and Portugal, while the best solar resource in the world is in the deserts of South Africa and Chile, where direct sunlight provides almost 3000 kWh/m2 a year.
The economic feasibility of a project is determined by both the available solar resource at the site and then by power sale conditions. If the local power purchase price does not cover the production cost, then incentives or soft loans can cover the cost gap between the power cost and the available tariff. Environmental market mechanisms like renewable energy certificates could be an additional source of income, in particular in developing countries. All the CSP plants in the US were pre-financed by developers and/or suppliers/builders and received non-recourse project financing only after successful start-up. In contrast, all CSP projects in Spain received non-recourse project financing for construction. Extensive due diligence preceded financial closure and only prime engineering procurement construction (EPC) contractors were acceptable to the banks, which required long-term performance guarantees accompanied by high failure penalties.
‘Bankability’ of the plant revenue stream has been the key to project finance in leading markets like Algeria, Spain and the US. Different approaches have been long-term power purchase agreements and feed-in tariffs, but it has taken considerable effort during years of project development to remove the barriers and obstacles to bankability.
The cost of concentrating solar thermal power is dropping. Experience in the US shows that generation costs are currently about 15 US cents/kWh (11 Eurocents/kWh) for solar generated electricity at sites with very good solar radiation, with predicted ongoing costs as low as 8 US cents/kWh (6 Eurocents/kWh) in some circumstances.
The technology development is on a steep learning curve, and the factors that will reduce costs are: technology improvements, mass production, economies of scale and improved operation. CSP is becoming competitive with conventional, fossil-fueled peak and mid-load power stations, and adding more CSP capacity to the grid can help keep the costs of electricity stable, and avoid drastic price rises as fuel scarcity and carbon costs take effect.
Several factors are increasing the economic viability of CSP projects, including reform of the electricity sector, rising demand for ‘green power’, and the development of global carbon markets. Direct support schemes also provide a strong boost, such as feed-in laws or renewable portfolio standards for renewable power in some countries.
Last but not least, increasing fossil fuel prices will bring the price of solar in line with the cost of conventional power generation. Although high initial investment is required for new CSP plants, over their entire lifecycle, 80% of costs are in construction and associated debt, and only 20% are from their operation. This means that, once the plant has been paid for, over the next 20 or so years only the operating costs remain, which are currently about 3 US cents/kWh (2 Eurocents/kWh). Under such circumstances, the electricity generated becomes comparable to that produced from long-written-off hydropower plants.
CSP in Europe
Spain is currently leading the world in the development of CSP. Firstly, it has a 2010 CSP target of 500 MW installed capacity. Secondly, it was the first southern European country to introduce a feed-in tariff funding system. CSP plants up to 50 MW now have a fixed tariff of 26.9 Eurocents/kWh (38 US cents/kWh) for 25 years, increasing annually with inflation minus one percentage point. After 25 years the tariff drops to 21.5 Eurocents/kWh (30 US cents/kWh). This tariff was fixed by the Royal Decree 661 of 2007. It separated the tariff from the market reference price, which goes up with oil prices, automatically increasing renewable tariffs.
Spain has progressively increased the tariff, from 12 Eurocents/kWh (17 US cents/kWh) in 2002, to 27 Eurocents/kWh (38 US cents/kWh) from 2004. The 2004 decision triggered a lot of development proposals, but it was only with the increase to current levels that a large number of projects became bankable. The current decree of 2007 keeps some key elements of the former decree of 2004 (RD 436); in particular it makes projects bankable with a 25-year guarantee and it allows 12%–15% natural gas backup to allow for optimized plant operation.
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At present, the target is exceeded by the number of planned installations but the best proof of the success of the Spanish support system for CSP is the current state of development of projects in the country. There are currently six power plants in operation, totaling 81 MW, plus another 12 plants under construction, adding a further 839 MW. More projects have been announced to the tune of several thousand megawatts.
The figures below, in Table 1, show how development is outstripping targets and how much potential Spain has for introducing CSP into its energy supplies.
The National Commission of Energy is responsible for monitoring the register of installations. It has established a website that will show the progress to the national target by plants that have met all the requirements for construction. When 85% of the target is reached, the authority will determine how much longer newly-registered projects can claim the premium fixed tariff. This approach is creating a race by developers to register their projects before the 85% is reached.
The industry now requires more certainty about the target and tariff level so that investments in future projects can also be guaranteed. Industry participants have proposed a target of 1000 MW a year while industry advocates Pro Thermosolar say that a tariff should be no lower than 0.24 or 0.25 €/kWh (34 or 35 US cents/kWh); any less than this would put a halt to market development, and not meet the costs of producing electricity under current market conditions. In May 2009, an additional decree was published which defines the requirements for inclusion of projects in the current tariff based on achieved project progress (for example, ground work started, 50% of hardware contracted, study on water availability performed). A revised law is under preparation to establish new annual capacity thresholds and new tariffs. It should also remove the current limit of 50 MW per power plant to be eligible for the feed-in tariff, because this is now lower than the economic technical optimum.
More South European countries, are preparing the ground for CSP deployment, mostly through feed-in laws already in place or under preparation. Examples of this are found in France, Italy, Portugal and Greece. In Italy, the most advanced project is the Archimede plant, a demonstration project integrating a 5-MW parabolic trough solar field coupled to an existing gas-fired power station. Its most innovative feature is the use of molten salt as a heat transfer fluid in the solar field and storage medium. The Archimede plant is expected to start operating in 2010.
Germany has a feed-in law that would also allow for CSP, but does not have the solar resources to match. However, following long-term research and industry activity in this field, a 1.5-MW concentrating solar tower in Jülich began operation at the end of 2008. It will serve as a showcase for volumetric air receiver technology and also as a test facility.
Algeria has excellent solar resources with over 2000 kWh/m² per year of direct sunlight. Nationally, there is a goal to provide 10% of energy from renewable energy by 2025 and to increase the solar percentage in its energy mix to 5% by 2015. Considering a partnership with the European partners in which power plants in Algeria deliver energy needed for Europe to meet its targets, a new company called New Energy Algeria (NEAL) was created to enhance participation of the local and international private sectors.
In 2004, the Algerian government published the first feed-in law of any OECD (Organisation for Economic Co-operation and Development) country with elevated tariffs for renewable power production to promote the generation of solar electricity in integrated solar combined cycle systems (ISCCS). This decree sets premium prices for electricity production from ISCCS; depending on the solar share a 5%–10% solar share can earn a 100% tariff, while a solar share over 20% can gain up to 200% of the regular tariff.
In 2005, NEAL launched a request for proposals for their 150 MW ISSCS plant with 25 MWe of solar capacity from parabolic troughs. The project called for a tariff below 6 US cents/kWh (4 Eurocents/kWh), with a solar share of over 5% and an internal rate of return in the range of 10%–16%. The Abengoa Group from Spain won the tender and their solar thermal plant is now under construction at Hassi R’mel, Algeria. Two more projects are planned; two 400 MW ISCCS plants with 70 MW of CSP each, to be developed between 2010 and 2015. The feasibility study of the next project will be conducted this year (2009).
The United States have for long been the only showcase for modern CSP projects, with about 350 MW capacity based on parabolic trough technology operating in the SEGS (Solar Electricity Generation Systems) in the Californian Mojave Desert since the mid-1980s.
Recently the Nevada Solar One plant with 64 MW capacity started a ‘new’ CSP era, going on-line in June 2007. Many large projects of up to 280 MW capacity are now under preparation, as several more paths towards CSP market development have recently gained momentum, focused on projects in the south-west US, where there is an excellent direct beam solar resource and demand for power from a growing population.
Among measures supporting CSP development in the country is the recently agreed 30% Investment Tax Credit, an important funding tool which was extended through to 2017. It is not known how this will operate in the long term due to the 2008 financial crisis, but for a two-year period it will provide a direct 30% payment back to the project upon commissioning.
Furthermore, several state initiatives, such as California’s Renewable Energy Portfolio Standard (RPS) – which now requires investor-owned utilities to produce 20% of their retail electricity sales from renewables by 2017, and Nevada’s 2003 Renewable Energy Portfolio Standard which requires the state’s two investor-owned utilities (Nevada Power and Sierra Pacific Power) to generate at least 15% of their retail electricity sales from renewable energy by 2013 – are in place.
Meanwhile, in 2002, the US Congress asked the Department of Energy to develop a policy initiative for reaching 1 GW of new parabolic trough, power-tower and dish/engine solar capacity to supply the southwestern United States by 2006.
Applications for CSP
Aside from electricity generation there are a number of other potentially significant applications for CSP systems, and solar process heat stands out as a smart and productive way to get the most out of these technologies.
Many industries need high temperature heat processes – for example in sterilization, boilers, heating and for absorption chilling. A 2008 study commissioned by the International Energy Agency (IEA) determined that in several industrial sectors, such as food, wine and beverage, transport equipment, machinery, textile, pulp and paper, about 27% of heat is required at medium temperature (100–400°C or 212–752°F) and 43% at above 400°C.
Parabolic troughs and linear Fresnel systems are most suitable for industrial processes and could be considered an economic on-site option for a whole range of industry types requiring medium to high temperature process heat. The IEA study recommended that the sectors most compatible with process heat from solar concentrating technology, are food (including wine and beverages), textiles, transport equipment, metal and plastic treatment, and chemicals. The most suitable applications and processes include cleaning, drying, evaporation and distillation, blanching, pasteurization and sterilization, among others. Solar thermal or CSP should also be considered for space heating and cooling of factory buildings and the use of towers or dishes for high temperature heat processes, like those required in ceramics, is also under research.
Another potential CSP application is desalination, which has been controversial – primarily for the large amount of energy it takes and also for the potential harm to marine life from the intakes and discharge of super-concentrated seawater. Most commercial plants are based on reverse osmosis or multi-stage flash desalination technology and run either on grid electricity or directly powered by oil and gas. However, with the growth and increasing affordability of concentrating solar power, some researchers are looking into how desalination could address water scarcity. Of course, places with large amounts of solar radiation are often also places with water supply problems. A 2007 study by the German Aerospace Centre (DLR) into CSP desalination of seawater, looked at the potential of this technology for providing water to the large urban centres in the Middle East and North Africa (MENA). The study found that the regional solar resource is more than enough to provide energy for desalination to meet the growing ‘water deficit’. The report predicts that electricity from solar thermal power will become the cheapest option at below 4 US cents/kWh (3 Eurocents/kWh) and desalinated water at below 40 Eurocents/m³ (56 US cents/m³) in the 20 years.
Global CSP outlook scenarios show a range of outcomes are possible depending on the decisions made now for managing demand and encouraging growth of the CSP market. In the next five years, to 2015, there could be as little as 566 MW of new CSP capacity installed each year under a conservative model, or as much as 6814 MW annually under an advanced scenario. Even under the moderate scenario, the world would have a combined solar power capacity of over 68 GW by 2020 and 830 GW by 2050, with the annual deployment running close to 41 GW. This would represent 1%–1.2% of global demand in 2020, 3%–3.6% in 2030, but jump to 8.5%–11.8% in 2050. In the moderate scenario, economic outcomes would be over €92 billion (US$129 billion) in investment and over a million jobs.
To put this in context, the projected installed capacity in 2050 is about equal to the generation capacity of the USA today – or almost equal to all coal-fired power plants in operation in 2005. Under an advanced industry development scenario, with high levels of energy efficiency, CSP could meet up to 7% of the world’s power needs in 2030 and a full quarter by 2050.
According to ESTELA, strong market growth of CSP will be demonstrated by a number of factors. Technical and economic success of the initial projects is the first step. To make this technology mainstream will require stable green pricing or incentives to bridge the initial gap in levelized electricity costs and continued cost reduction of the components and power produced.
New markets and market opportunities, for example in exporting power from north Africa to Europe, are vital for the long-term development of the industry and strong research and development is required to continue technical improvements in power production.
Long-term, stable feed-in tariffs have been proven the most efficient instrument for sustainable market penetration. The experience of Spain demonstrates how tariffs can increase the market for this technology exponentially. Legislated feed-in tariffs are already in place in Spain, Greece, Italy, France, Algeria, South Africa, France and Israel, and are under discussion in Turkey.
Legislated renewable energy sales targets, aimed at the electricity retail sector are another effective way to boost installation. The experience of south-western US states, especially California, provides evidence of these policies in action. Another measure supporting the industry is grants, as seen in Morocco and Egypt.
Concrete measures are needed to boost CSP to the level where it can account for 8%–25% of the world’s energy demand in 2050. While Spain and the US show how big potential markets can be for CSP, to open up the massive potential in other regions requires Kyoto instruments, such as the Cleaner Development Mechanism (CDM) and Joint Implementation (JI) to be made applicable to CSP, and mechanisms need to be bankable and sufficient.
Governments must also install demand instruments and promote feed-in laws as the most powerful instrument to push generation. The general consensus among industry players is that a legislated tariff of 0.24–0.27 €/kWh (34–38 US cents/kWh) with a guarantee of 20 to 25 years is required in southern Europe to make projects bankable. Feed-in tariffs should also reassure investor confidence that premiums will not change, so that returns on investment can be met, and provide clear and published time-scales for eligibility.
As with any developing industry, the next generation technologies will significantly drive down costs. To allow for this requires funding for pre-commercial demonstration plants so the next generation technologies may enter the market. Demonstration plants also need loan guarantees to cover the technology innovation risk.
Technically, it would only take 0.04% of the solar energy from the Sahara desert to cover Europe’s electricity demand and just 2% of its land area could supply the world’s electricity needs. This concept is staggering. With the growth of CSP technology, electricity export from north Africa to western Europe is a viable option. It requires massive investment in landmark plants and high voltage transmission lines which dramatically reduce transmission losses.
Areas with high peak electricity demands, like southern Spain, are already having summer blackouts, in particular from use of air-conditioning. In southern Europe, at least, co-operation with neighboring countries for energy supplies is already a day-to-day practice. There are gas and power interconnections between Italy, Tunisia and Algeria, as well as between Morocco and Spain.
Governments and industry development must now put the measures in place to usher in the maximum amount of concentrating solar power possible. Together with other renewable resources like wind, solar photovoltaics, geothermal, wave and sustainable forms of bioenergy, this technology has a major role to play in averting catastrophic climate change.
Sidebar: CSP basics
Concentrating solar thermal power (CSP) comprises a range of technologies that are used to collect and concentrate direct sunlight and to turn it in to medium to high temperature heat. This heat may then be used to generate electricity in a conventional way, for example, using a steam or gas turbine or a Stirling engine, or used in some other applications, supplying, for example, process heat.
The concentrating mirror systems used in CSP plants are either line or point-focusing systems. Line systems concentrate radiation about one hundred times, and achieve working temperatures of up to 550°C (1022°F), while point systems can concentrate far more than one thousand times and achieve working temperatures of more than 1000°C (1832°F). There are four main types of commercial CSP technologies: parabolic troughs and linear Fresnel systems, which are line-concentrating, and central receivers and parabolic dishes, which are point-concentrating. Central receiver systems are also known as solar towers.
Life-cycle assessment of the components of a CSP system, together with the land-surface impacts of their installation, indicate that it takes around five months to ‘pay back’ the energy used to manufacture and install it. Considering the plants could last 40 years this is a good ratio. Furthermore, most of the CSP solar field materials can be recycled and used again for further plants.
Sidebar: Heat Storage
Solar heat collected during the day can be stored in liquid or solid media such as molten salts, ceramics, concrete or phase-changing salt mixtures. At night, it can then be extracted to keep the turbine running. Thermal power plants with solar-only generation work well supplying summer midday peak loads in wealthy regions with significant cooling demands, such as Spain and California. With thermal energy storage systems they operate longer and even provide base-load power.
For example, in Spain the 50 MWe Andasol plants are designed with about eight hours of thermal storage, increasing annual availability by about 1000–2500 hours. The Andasol plant relies on indirect storage using molten salts. The plants use ‘cool’ tanks (about 290°C, 554°F) and hot tanks (about 390°C, 734°F) of molten salts, with about 29,000 tonnes in each tank. The cold liquid salts are passed through a heat exchanger with the oil that is heated by the concentrator, and then stored in the hot tank for later use. To extract the heat, the process is reversed through the exchanger, making steam for the generator. One advantage is that the oils for heat transfer are a tried and tested technology. The downside is that heat exchangers are expensive and add investment costs to the development.
Conversely, a direct steam storage technique is used commercially in the PS10 plant, also in Spain, providing about 30–60 minutes of extra operations. Its capacity for storage is limited because of the high cost of pressurized vessels for large steam volumes. This is, in principle, a conventional technology, also known as Ruth’s storage. The best use of this technology is as buffer storage for peak power.
Another technique for energy storage, using concrete to store heat, is at different stages in prototype installations with a good record so far. The concrete ‘store’ operates at temperatures of 400–500°C (752–932°F), and is a modular and scalable design having 500–1000 MWh capacity. Currently, the investment cost is about €30/kWh ($42/kWh), but the target is for less than €20/kWh ($28/kWh). The first generation storage modules, with a 300 kWh capacity, have been operating for two years. Second generation modules have a 400 kWh capacity and are now ready for a demonstration application.
Indirect storage in a phase-changing medium is still under development, and uses the melting/freezing points of salts, such as sodium or potassium nitrates, to store and deliver heat for condensation and evaporation of steam in direct steam plants. It has only been tested in various prototypes, but there are no commercial applications.
In this system, hot heat transfer fluid flows through a manifold embedded in the phase-changing materials, transferring its heat to the storage material. The main advantage of this technology is its volumetric density and the low cost of the storage materials. However, there are some developmental challenges of this method that need to be overcome before it becomes a commercially viable solution.
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