Archive for April, 2010
April 14th, 2010 | 
Author: 
I always believe it is best to examine what is happening internationally, especially in countries that are years ahead of us in this solar thermal sector (basically everybody). This may help us predict what trends may slowly develop here in South Africa.
Solarthermalworld wanted to investigate why the Australian Government decided to discontinue its Solar Water Heater Rebate Programme and conducted an interview with Stephen Cranch, Sales and Marketing Manager of Solahart Industries Pty Ltd Australia.
Cranch provided a short overview of the current market and support scheme situation. Since 2005, the solar water heater expert has been part of the Solahart Team, an Australian flat plate collector and tank manufacturer. Before that, he had been General Marketing Manager at Heatcraft Australia, a major supplier for the refrigeration and air-conditioning sector.
Solarthermalworld: We have recently reported that the Federal Solar Water Heater (SWH) Rebate has been discontinued. What caused this abrupt end?
Cranch: There has been a lot of market turmoil here. Around September last year, the heat pump rebate was reduced to AUD 1,000, because people were installing for free and the market was massively overheated. As a result, REC prices plummeted, which made solar less attractive and the demand started to drop off. The peak for the SWH market was around June till November. In January, the New South Wales rebate was reduced from up to AUD 1,200 to AUD 300.
At the same time, the insulation program had been plagued with some real problems. And therefore, the Federal Government decided to suspend the program on 19 February 2010 and to reintroduce it in June this year. However, for SWHs, which as you know were part of the programme, a new scheme was immediately launched called the Renewable Energy Bonus Scheme and the rebate amount reduced from AUD 1,600 to AUD 1,000, effective from 20 February 2010.
Solarthermalworld: In 2009, market volume almost doubled and reached its peak around June/July 2009. Was the market volume pushed by the Federal Solar Water Heater Rebate?
Cranch: In February 2009, the Federal Government increased the national solar hot water rebate from AUD 1,000 to AUD 1,600 and removed the requirement for means testing, which was previously only available to householders earning a combined income of AUD 100,000 or less. This was bundled up with free home insulation as part of the federal government stimulus package in the midst of the global financial crisis.
Solarthermalworld: Insulation and solar water heaters are not usually combined in one and the same incentive programme. How did that work?
Cranch: You could only claim the SWH rebate when replacing an electric water heater and proving that you had not had free insulation installed. For instance, householders could have free insulation up to AUD 1,600 or the AUD 1,600
SHW rebate. Insulation was provided free to householders without money changing hands, whereas with SWHs, the householder still had to pay the up-front cost and wait 2 to 3 months for the rebate to come back after sending the paperwork in.
This was on top of the Renewable Energy Certificates (RECs), which are linked to the 20 % renewable energy target by 2020. 1 REC is 1
MW of electricity generated or displaced over a 10-year period. The value of each REC is determined by market factors, for instance: the current value around 33 AUD/ REC, multiplied by the number of RECs per system – lets say 30 – is AUD 990. Additionally, some other state rebates where available, such as the New South Wales rebate, which was up to AUD 1,200. Those rebates and RECs are available for heat pumps and solar water heaters.
Solarthermalworld: How would you assess the current state of the SWH market?
Cranch: Now, it’s significantly down from the numbers in 2009. In summary, the market is a lot tougher now than 12 months ago. It peaked at around 200,000 SWH systems, including a large number of heat pumps, but has come back significantly from these numbers.
The interview was conducted by communication specialist Hanna Schober based in South Africa.
Posted in 
The government has set the target of 10 000 GWh of renewable energy generation by 2013 and Eskom is expecting its Solar Water Heating Programme to contribute up to 23% of this target. According to Cedric Worthmann, the Solar Water Heating Programme manager at Eskom, the programme has delivered an average of 6.4 GWh per annum to date.
Worthmann says that the significant increase of the rebate was calculated in order to allow a five-year payback period. “This calculation is done taking into account the average cost of systems, average savings per system, average electricity tariff rate and cost of capital at prime interest rate per system size,” says Worthmann.
Solar by law?
James Shirley, General Manager at Kayema Energy Solutions, says that although the Eskom rebate increase has caused a significant increase in solar water heater sales, he doubts that the government’s target will be reached.
“The rebate is definitely helping the solar water heating industry, but I doubt that government will be able to achieve such significant market penetration,” says Shirley. “Eskom have raised the rebate in order to make solar water heating systems financially viable for the public, but unless government is going to make solar water heating systems compulsory for all new buildings, I don’t see how we will achieve 10 000 GWh of renewable energy generation by 2013.”
Barry Bredenkamp, operations manager at NEEA (National Energy Efficiency Agency), says that he doesn’t think it will be necessary or practical for government to make solar water heaters compulsory. “In some instances, solar water heaters are just not practical,” says Barry before explaining that if a building’s orientation doesn’t lend itself to the optimal use of the technology, or for example, where indigenous trees provide a natural barrier between the building and the sun and where an alternate technology, such as a heat pump, may provide a better solution for the application.
“However, with the rising price of electricity, the increase in subsidies and the reduction in the price of solar water heaters as more competitors enter the market, I believe we will see a natural evolution from conventional electrically-operated geysers to more efficient solar water heaters, without legislation being introduced,” says Bredenkamp.
Changing the rebate requirements
Shirley also says that the requirements that enabled consumers to qualify for a solar water heating rebate (i.e added cost of installed equipment) were too high, and offset the previous rebate amount, and the administrative work around claiming the rebate was laborious. “Eskom had a lot of prerequisites concerning not only the heating system, but also the installation, putting a lot of consumers off the process of installing these systems because, it was too difficult to claim the rebate,” says Shirley.
According to Shirley, there is a lot of paperwork involved in claiming your solar water heating rebate from Eskom, but it isn’t difficult. “You generally wait about eight weeks to get your money back. This is not an extremely long time, but I’m thinking that people are a bit strapped for cash when they are waiting for their claim to be processed, which is deterring them from getting a solar water heating system.”
“The new process for claiming is very simple: the reason people think it is difficult is that generally, people do not read instructions, and are being misled by suppliers that are not prepared to join the programme,” says Worthmann.
www.eskom.co.za/dsm states the rebate system is not in anyway exclusive. The current requirements of a supplier to sell systems that qualify for rebates are the following:
• Be able to offer a five year guarantee
• Submit documents, including public liability and company details
• Have system tested and passed at the SABS for the following:
o Safety
o Mechanical
o Thermal
The actual rebate claiming process
The ten step program on reclaiming a rebate (according to the Eskom-system), can be summed up as follows:
• Thoroughly research the solar water heating system.
• Call EEDSM Help or visit www.eskom.co.za/dsm to get an approved supplier.
• Get an Eskom approved installer to install the (Eskom approved) system.
• Make sure an (Eskom approved) timer is installed by an ECB registered electrician.
• Get your supplier, installer and electrician to fill out the relevant details on your claim form.
• Complete the rest of the details and attach the relevant documents (original invoice, copy of ID, copy of utility bill and/or electricity bills are listed as examples).
• Post the claim to the facilitating auditors (Deloitte) in a self addressed envelope or drop it off in a designated drop box within six months of installation.
• Wait for a SMS notification that a) the facilitating auditors have received your application and b) when your application is processed and queued for electronic funds transfer/your form is incomplete.
• Payment is made within eight weeks of receipt.
• Random technical audits will be carried out on some systems to ensure installation quality and operation.
Types of solar water heating systems
According to Shirley, there are two main types of solar water heating system; the closed loop and the open loop heating systems. “A closed loop system uses heat exchanger fluid and an open loop means that your actual drinking water goes through a tube through the solar panel.” Shirley says that South Africans have three general solar water heating categories to consider when choosing a system:
1. Thermo-siphon systems. This solar water heating system works like a heating suction where the tank sits above the solar panel of tubes. Water temperature and density are used to create the heat cycle of the system.
2. Pumped or split system. The tank of a pumped or split system is separate from the collector (the tank is usually in the roof in this case).
3. Retrofit. Although a bit of money will be saved when retrofitting an electric geyser to work as a solar water geyser, Shirley believes that this is not the correct way of installing a solar water heating system if the current geyser is more than three years old and an entirely new system should be installed instead of retrofitting an existing geyser.
Proven technology – the problem is money and public buy-in
The value of Eskom’s solar water heating rebate is based on the capability of the system to replace the use of electrical energy and all solar water heating systems included in the programme will have a SABS test conformity report rating their efficiency (www.eskom.co.za/dsm). Based on these test results, a system will qualify for a rebate ranging typically between ZAR1 500 and ZAR5 000.
www.eskom.co.za/dsm states that electrical geysers use between 30% and 50% of a household’s monthly electricity bill and replacing a conventional geyser with a solar powered system will reduce that percentage of electricity consumption by up to 70%.
“The technology is proven internationally and people now trust the technology in South Africa. The only problem is funding. Even though the solar water heating rebate has made the payback period more viable, the general public still has to be convinced to spend the initial capital on purchasing a system. The client then needs to recover the subsidy from a third party, which means that they are burdened with the administrative issues involved,” says Shirley.
The deadlines
“The important thing is that the rebate won’t last forever and it has been put in place to encourage people to switch now rather than later,” says Shirley.
Worthmann confirmed that there is in fact a deadline for Eskom’s programme. “The Solar Water Heating Programme will continue until 2014 as per an agreement with the Minister of Energy, or when the first million units are installed,” says Worthmann. “Eskom is engaging with various financial institutions and insurance companies, to increase the uptake of SWHs in the programme. People don’t want to spend money on replacing a system that is functioning, which is why we are engaging with the insurance companies to replace damaged geysers with solar. We are also focusing on working with the municipalities to assist them to help their consumers to convert. This rebate will be offered to all qualifying persons and installations as long as funds are available.”
Electrical geysers – who is losing?
“In the solar water heating industry, almost all geyser manufacturers have either completely switched to solar water heating systems or they are including solar ranges into their product offerings,” explains Shirley. “The industry knows that solar water heating is the future and everyone is adapting. I don’t think there are any suppliers who truly believe that selling only electrical geysers is a financially viable option – power is getting too expensive and that situation is not going to change. We need to change the way we heat water.”
Bredenkamp comments that although solar water heating systems are more widespread today, there are still people selling electrical geysers. “Like I’ve said before, there are certain applications where there is no choice but to install an electric geyser. Many solar water heaters are installed in parallel with an electric geyser, which serves as a back-up for when there are extended periods of inclement weather, so we can’t just do away with electrical geysers,” says Bredenkamp.
Solar water heating life cycle
Shirley says that, “the life cycle of electric geysers and solar water heating systems are more or less the same”. “Electric geysers generally have a five year guarantee, some have a ten year guarantee, and the design lifetime of a good solar water heating system is around 20 years.
Although www.eskom.co.za/dsm states that most systems are guaranteed for five years, the expected life of the equipment is between ten and 15 years and that each piece of equipment has a different profile, which depends on various elements such as geographical area, water usage profile, number of users and the size of the system.
Bredenkamp explains that even if you had to replace a relatively more expensive solar water heating system approximately every ten years, the energy savings that one receives is still worth the more expensive initial costs.
“The energy savings will definitely make up for the initial costs of the system, but there are some instances where it would not be worth it, such as a holiday home that is only used for one month of the year. It is not really a good idea having a ‘un-utilised’ solar water heater installed, as the pressure build-up can lead to problems with various components of the system, such as the rubber seals,” says Bredenkamp.
“Although in principle, we would like to see as many solar water heaters on roofs as possible, one has to do a realistic assesment of the situation and a simple calculation, to determine the sheer economics of the specific application.”
Imports not designed for our climate or resources
www.eskom.co.za/dsm states that although solar water heating technology is not new to the industry in South Africa, it is still characterised by high manufacturing costs and low sales volumes.
“Although the market for solar water heating systems in South Africa is certainly growing, the biggest concern for local suppliers is reputable companies being bombarded by people overseas bringing back cheap goods,” says Shirley. “The problem is not only that overseas solar water heating suppliers don’t have a proper working knowledge of our national codes of practice or that they can not offer a back up service, the problem is that these products are not always designed for South Africa’s climate or resources. Our ambient temperature and solar radiation levels are not the same as many overseas countries, meaning that there needs to be corrective design at the factory level to ensure correct water temperature limits are met for imported systems.
Bredenkamp says that although there will always be the problem of cheap imports, South Africa has standards and procedures in place to protect consumers from the majority of poor quality solar water heaters.
“There will always be cases where opportunistic individuals see a business opportunity and start importing ‘cheap’ products from various countries abroad. We in South Africa are lucky in this respect, since all products that want to qualify for a subsidy, need to be tested and passed by the South African Bureau of Standards (SABS). There is a national standard with which the products need to comply and the SABS and the Tshwane University of Technology have the equipment to test products according to this standard,” says Bredenkamp.
“However, we must caution the public against purchasing solar water heaters that may initially appear to be cheaper (even without any subsidy), than those who have been tested by the SABS. In most cases, these products will not withstand the test of time and the supplier or distributor may not be around in future to honor any given guarantees. It is therefore imperative that the public insist on seeing a SABS test report of the specific product, before making a purchase decision.”
Engineering precision of commercial solutions
Shirley says that commercial solar water heating systems are very different from the types of solar water heating systems that home owners use. “Commercial solar water heating systems are an entirely different story,” says Shirley. “A lot of engineering work is involved and the costs are obviously higher. Instead of installing one or two panels, you may need over 100 panels with large storeage tanks in the case of a hospital or hotel where a lot of hot water is consumed. But even though this is expensive, the electricity savings does make it financially viable.”
According to Worthmann, Eskom will have a programme in place for commercial applications this year. “We are busy formalising a commercial sector solar programme which we hope to launch mid-year. There are many competent companies that can design and install these large systems, and have being doing so for many years,” says Worthmann.
“The way I see it, solar water heating systems for commercial applications are about reducing a company’s carbon footprint and lowering your operating costs. A solar water heater should be seen as an investment, not a product. When you buy a solar water heating system, you are buying hot water for the next 15 – 20 years and you are using a lot less energy for this hot water,” concludes Shirley
We are by far the highest carbon emitter per capita in Africa, in fact companies like SASOL are the most polluting operation to be found in the world, but paradoxically it is these companies (ESKOM) that are subsidising the implementation of Green Tech, like the solar geyser rebate system.
The installation of flue gas desulphurisation (FGD) technology at the Medupi coal-fired power station, the construction of which will be part funded by a $3,75-billion loan from the World Bank, has been confirmed as a loan-package condition.
The technology, which will reduce sulphur-dioxide emissions, would have to be retrofitted, owing to the fact that it had not been included in the plant’s original design. This would add to the project’s capital cost, and its water consumption.
The bank published its ‘Project Appraisal’ document for the controversial loan on Tuesday, which shows that Eskom will need to develop, adopt and thereafter implement a FGD programme across each of the plant’s six power generation units by no later than June 30, 2013.
It is also stipulated that FGD equipment for the first generation unit must commence on the later of either the sixth anniversary of the commissioning date, or by March 31, 2018. The FGD equipment for all six generation units would need to be installed and be fully operational by no later than December 31, 2021.
The FGD installation between 2018 and 2021 will be aligned to the scheduled operational maintenance programme of the Medupi units, which would be taken off-line for routine maintenance after six years of operation.
The bank notes that the sulphur content of the coal to be used at Medupi, which is calculated at 1,4% by weight, together with the large scale of the plant, some 4 800 MW, meant that sulphur-dioxide emissions could have a “significant adverse environmental impact”.
Therefore, sulphur-dioxide emissions would have to be removed using a “wet FGD” solution, or a gypsum process, using limestone located at Kraalhoek and Dwaalboom, some 180 km from the Lephalale site.
The process would increase the plant’s water consumption and the World Bank has, thus, flagged for possible concern the fact that sufficient water might not be available in time for the commissioning of the last three units or the FGD equipment.
“Progress on the project to supply the required amount of water is on schedule. Nevertheless, the Bank has requested evidence from the Department of Water Affairs to Eskom, committing to timely water supply,” the document states.
The water allocation is dependent on the availability of water from the Mokolo and Crocodile Water Augmentation project, which is not expected to become available until 2014 at the earliest.
The FGD system is expected to add at least $150/kW to the final capital cost, while yearly water consumption, including FGD, will rise to 12-million m3.
The total cost of Medupi is estimated at about $12,1-billion.
It is great to see large corporations investing in greener futures. Lets hope it not all just some PR stunt:
SEOUL (Reuters) – South Korea’s LG Group will invest 20 trillion won ($17.90 billion) through 2020 to develop environmentally-friendly businesses and reduce emissions by 40 percent against 2009 levels, unit LG Corp said on Monday.
The group is South Korea’s fifth-largest by assets and led by LG Electronics, LG Display and LG Chem. It will split the investment between green research and development and facilities to cut 50 million metric tones of greenhouse gas emissions per year by 2020, a statement from LG Corp said.
The investment aims to expand its production of energy-efficient products and renewable energy businesses such as fuel cells and rechargeable batteries for electric vehicles, bringing revenue from such sectors to 10 percent of the group’s total revenue in 2020, the statement said.
South Korea, Asia’s fourth-largest economy heavily dependent on oil and gas imports, set a voluntary 2020 emissions reduction target last year to a 30 percent reduction from its forecast under a business as usual scenario.
The government said last July said it would invest 107 trillion won, or 2 percent of its annual GDP, in environment-related industries over the next five years.
Samsung Electronics has also said it would invest 5.4 trillion won in green research and development and facilities to make the world’s largest memory chip maker a leading eco-friendly company by 2013.
(Reporting by Cho Mee-young; Editing by Jonathan Hopfner)
Global wind energy markets are expected to continue their rapid growth, with the world’s wind power capacity increasing by 160% over the coming five years, according to the annual industry forecast presented by the Global Wind Energy Council (GWEC).
GWEC said that it expects that the global installed wind capacity will reach 409 GW by 2014, up from 158.5 GW at the end of 2009. This assumes an average growth rate of 21% per year, which is conservative compared to the 29% average growth that the wind industry experienced over the past decade. The organization predicts that in 2014, total wind capacity additions will be more than 60 GW, up from the 38.3 GW of annual wind capacity installations in 2009.
“Even in the face of a global recession and financial crisis, wind energy continues to be the technology of choice in many countries around the world. Wind power is clean, reliable and quick to install, so it is the most attractive solution for improving supply security, reducing CO2 emissions, and creating thousands of jobs in the process,” said Steve Sawyer, GWEC Secretary General. “All of these qualities are of key importance, even more so in times of economic uncertainty.”
GWEC will present its full annual Global Wind 2009 Report at the European Wind Energy Conference in Warsaw on April 21 2010, which will include a five year forecast for the development of the global wind energy market. In the past, these projections have regularly been outstripped by the actual performance of the industry and have had to be adjusted upwards. Despite the ramifications of the financial crisis, 2009 was no exception.
The two markets leading global wind power expansion will continue to be the U.S. and China, whose markets have exceeded all expectations in recent years.
North America Wind Development
While in the U.S., the development for 2010 will be hampered by continued tightness in the financial markets and the overall economic downturn, the provisions of the US government’s Recovery Act, and in particular the grant programs, will continue to counteract the impacts of the crisis.
Coupled with legislative uncertainty at the federal level in Canada, the result is that the North American market is forecast to stay flat for the next couple of years, and then pick up again in 2012, to reach a cumulative total of 101.5 GW by 2014 (up from 38.5 GW in 2009). This would translate into an addition of 63 GW in the US and Canada over the next five years.
Canada could see a boost from offshore projects however. This week Windstream Wolfe Island Shoals Inc., a subsidiary of Windstream Energy LLC was awarded a Feed-in Tariff contract by the Ontario Power Authority to develop Canada’s first offshore wind site. The 300 MW site is located west of Wolfe Island, Ontario on approximately 48,000 acres of shallow water shoals in Lake Ontario.
“We are extremely excited about the opportunity afforded to us by the government of Ontario and the Ontario Power Authority. The 300MW offshore Wolfe Island site will create hundreds of jobs for the Province of Ontario and the local municipalities. Wolfe Island is one of the windiest areas of the province and has proven local support for wind development. Our project is close to the Lennox Thermal Station, and will offset the use of fossil fuels, by providing power generated by the abundant winds of Lake Ontario,” said Ian Baines, president of Windstream Energy.
Chinese Wind Growth
In China, growth is set to continue at a breathtaking pace. Already in 2009, China accounted for one third of total annual wind capacity additions, with 13.8 GW worth of new wind farms installed. This took China’s total capacity up to 25.9 GW, thereby overtaking Germany as the country with the most wind power capacity by a narrow margin.
China will remain one of the main drivers of global growth in the coming years, with annual additions expected to be over 20 GW by 2014. This development is underpinned by a very aggressive government policy supporting the diversification of the electricity supply and the growth of the domestic industry. The Chinese government has an unofficial target of 150 GW of wind capacity by
Europe and Beyond
Until 2013, Europe will continue to host the largest wind capacity. However, GWEC expects that by the end of 2014, Europe’s installed capacity will stand at 136.5 GW, compared to Asia’s 148.8 GW. By 2014, the annual European market will reach 14.5 GW, and a total of 60 GW will be installed in Europe over this five-year period.
The African wind market isn’t high on many analysts radar, but developer Rainmaker Energy Projects has started full Environmental Impact Assessments for two proposed wind farms situated in the Eastern Cape, South Africa totaling 610 MW. Rainmaker has been conducting on-site feasibility studies for the past year and plans to have all development processes completed by the fourth quarter of 2010.
The two projects are the 550-MW Dorper project covering 150 square kilometers in the vicinity of Molteno and the 60-MW AB’s project covering 20 square kilometers in the vicinity of Indwe.
“The Dorper and AB’s projects have shown the most magnificent wind regime. In terms of average wind speed, mean wind speed and energy profile, they are exceptional. During peak usage times over winter, the Dorper and AB’s projects both consistently have the profile which could almost be compared to a base load power station — complementing South Africa’s energy consumption profile and providing power when its grid is at its most fragile,” said Development Manager for Rainmaker Energy Projects’ Luke Callcott-Stevens.
A number of wind energy projects in South Africa have commenced development during the last three years, but the industry has so far failed to come online. However, the Renewable Energy Feed-in Tariff (REFIT) announced in 2009 and the proposed introduction of the Independent Systems Operator by the Department of Energy and the National Energy Regulator of South Africa (NERSA) promise an imminent breakthrough for the industry.
The proposed Dorper and AB’s projects both have existing transmission grid infrastructure on site. Their development and operation could contribute to the Department of Energy’s self-imposed target of producing 10,000 GWh of renewable energy by the year 2013
Viruses: they are the latest candidate for energy storage.
A team of scientists lead by material science professor Angela Belcher has genetically modified a virus that can exploit sunlight to split water into oxygen and hydrogen. If it works and can be commercialized, the process could help solve the vexing problem of energy storage and the equally vexing problem of producing hydrogen in a reasonable and cost-effective way. Hydrogen remains — in theory — one of the most efficient vehicles for storing energy: the gas can be bottled until the electrons needed to be stripped from the hydrogen molecules. Unfortunately, most manufacturers generate hydrogen by cracking methane, thereby releasing large amounts of carbon dioxide, or by electrolyzing water, an energy-intensive process that can be expensive.
The group genetically modified a virus, M13, to bind a catalyst (iridium oxide) and a biological pigment. The pigment absorbs sunlight while the catalyst, along with the absorbed energy from the sun, splits the water molecule. The reaction gives oxygen molecules, protons and electrons as byproducts.
The team next wants to devise a virus that can reassemble the protons and electrons into storable hydrogen. To keep the viruses from clumping, they are coated in a microgel.
The virus in the reaction largely acts as a wire or a scaffold, i.e., as a structure to arrange the pigment and catalyst in an efficient and effective manner. The virus is not transforming water through a metabolic process, such as the way that yeast consume sugar to produce wine. Other researchers, such as BioCee out of the University of Minnesota, are concentrating on metabolic transformations. BioCee has received Department of Energy grants to devise microbes that will absorb sunlight and carbon dioxide and turn them into liquid fuels through the magic of the microbial equivalent of your digestive system.
Stanford professor Jim Swartz in the mid-2000s discovered a naturally occurring microbe thatmetabolizes sunlight to split water. Unfortunately, the microbe also dies in the presence of oxygen.
Daniel Nocera, another MIT professor, has created a company called Sun Catalytix that is focusing on trying to devise catalysts with cobalt and other materials that can reduce the amount of energy required to split water. They’ll be talking. In a way, Belcher’s work represents almost a middle ground between the groups trying to exploit organisms for chemical transformations and the chemistry crowd that is coming up with classic chemistry catalysts. It involves a bug, but the biological organism serves as a piece of lab equipment.
Belcher is one the leaders in the field of industrial microbiology. Cambrios Technologies, a company that commercializes her work, has devised microbes that can secrete semiconductor insulators and materials that can detect weak spots and stress fractures on airplane wings. Last year, she published a paper on a virus that could secrete proteins that could lead to chemical reactions that could form anodes and cathodes for batteries.
Some 150 years after the French mathematician Augustin Mouchot began generating steam from concentrating solar energy, the father of CSP technology would no doubt be delighted to see his prodigy growing up fast. Mouchot’s vision is at last becoming a reality, given the evidence of the past year or so.
Use of solar energy steam generators connected to fairly standard conventional power islands – steam turbine and generator – is a technology that is now well understood and while the various designs of solar collector may present some novelties, CSP installations share many common traits with their fossil-fired cousins. It is perhaps for this reason that CSP has attracted the interest not only of utility companies keen to expand on their renewable portfolios, but also original equipment manufacturers which have traditionally supplied the utility market.
Certainly, one of the clearest signs that the CSP sector is maturing came from the autumn 2009 acquisition of CSP technology company Solel by Germany engineering colossus Siemens.
Siemens acquired the remaining 63% stake in Israel-based Solel Solar Systems which it didn’t own from London-based investment firm Ecofin Ltd. for US$418 million.
The company produces solar parabolic troughs and has been involved in the manufacture and installation of solar fields since its 1992 launch by former Luz International staff, after Luz went bankrupt. Explaining its decision, Siemens said that it is projecting annual double-digit growth rates for CSP plants by 2020 and that it expects the market to reach a volume of more than €20 billion ($27 billion) by then. It is backing its convictions with acquisitions. The Solel deal followed a March 2009 acquisition of a 28% stake in Archimede Solar Energy, an Italian company which manufactures solar receiver tubes.
With a stake in two key parabolic trough-type CSP technologies and considerable expertise in the engineering of the conventional power island, Siemens appears well placed to exploit a growth market. And, in order to support its ambitions, the company has also announced at least one capacity addition in the months following the acquisitions. In January 2010 Archimede, the joint venture between Angelantoni Industrie Spa and Siemens, began construction at a new receiver production facility in the Italian town of Massa Martana.
Starting in early 2011, the plant has a planned annual production capacity of approximately 75,000 solar receiver tubes, which will be ultimately be increased to 140,000 per year. These solar receivers will use molten salt for heat transfer medium instead of oil, which the company says can significantly increase efficiency.
A first commercial plant is currently under construction in Sicily, the Priolo Gargallo project, which will use 1500 solar receivers with molten salt as the heat transfer medium and is expected to go operational early in the summer of 2010.
Peter Löscher, Siemens’ president and CEO, emphasised that the move followed the company’s promise to expand its solar thermal activities earlier in 2009, noting: ‘After the rapid and highly successful expansion of our wind power business, we now want to continue this success story in the solar sector.’ Löscher added, ‘We now have complete control of all solar thermal components.’
No doubt the company’s interest in Solel was in no small part down to a landmark 2007 agreement with Californian utility groupPacific Gas and Electric Company(PG&E), which signed a power purchase agreement for the 553 MW Mojave Solar Park. Planned for construction in California’s Mojave Desert, when operational in 2011 the installation will cover up to 6000 acres (2428 ha) use 1.2 million mirrors and 317 miles (507 km) of vacuum tubing. Over the past 20 years, Solel technology has installed nine operating solar power plants generating 354 MW in the Mojave Desert.
Of course, for PG&E and other utility groups, Solel and Siemens are hardly the only game in town. During 2008 and 2009 PG&E, for example, signed power purchase agreements (PPAs) for more than 1900 MW of CSP capacity with groups including subsidiaries of FPL’s NextEra Energy Resources, Abengoa Solar, NRG Energy and BrightSource Energy, which also has links to Israel’s Luz.
NextEra’s proposed Genesis Solar Energy Project consists of two 125 MW units scheduled to come on line in two phases, the first in 2013 and the second in 2014. It is expected to deliver about 560 GWh annually. Meanwhile, Abengoa Solar’s proposed 250 MW Mojave Solar project is to be located at Harper Lake in San Bernardino County and is expected to deliver more than 600 GWh per year. The project is scheduled to become fully operational by late 2013.
And, under the terms of a series of contracts with BrightSource Energy Inc, PG&E has signed PPAs for seven CSP projects and a total of 1310 MW of capacity since April 2008. Collectively the projects are expected to produce some 3.7 TWh annually. The first of these solar power plants, 100 MW in Ivanpah, California, is scheduled to be operating in 2012 and is expected to produce 246 GWh annually, PG&E says.
In a separate agreement with NRG Energy subsidiary Alpine SunTower LLC, PG&E will also be purchasing output from a 92 MW solar tower installation using technology from eSolar and scheduled for completion in 2012. The project will be located near Lancaster, California, and will produce approximately 192 GWh annually.
The project is part of eSolar and NRG’s previously announced plans to develop up to 500 MW of CSP capacity in California and across the Southwestern United States.
eSolar’s CSP projects feature a proprietary combination of optics and software in a pre-fabricated modular form, each unit with a capacity of 46 MW.
Commenting on the strategy Fong Wan, vice president of energy procurement at PG&E, observed: ‘Solar thermal energy is an especially attractive renewable power source because it is available when needed most in California – during the peak mid-day summer period.’
California law requires each investor-owned utility to increase the share of eligible renewable generating resources in its electric power portfolio to 20% by 2010 and while PG&E has made contractual commitments to have over 20% of its future deliveries from renewables it is not alone.
In 2009, for example, Southern California Edison and BrightSource Energy signed a deal for 1300 MW of CSP installations across seven projects which is expected to deliver some 3.7 TWh per year.
BrightSource Energy will use its proprietary Luz Power Tower 550 (LPT 550) system which uses air-cooling condensers, minimising water consumption, an important factor in the typically arid environments suited to CSP applications.
A different CSP technology comes from Stirling Energy Systems (SES) and Tessera Solar, which unveiled their new dish-engine system at Sandia National Laboratories in Albuquerque, New Mexico, in 2009 and plans commercial-scale deployments beginning in 2010. Each dish can generate up to 25 kW and the proprietary technology will be deployed in two of the world’s largest solar generating projects in Southern California with San Diego Gas & Electric in the Imperial Valley and Southern California Edison in the Mojave Desert, in addition to a previously announced project with CPS Energy in West Texas. Bob Lukefahr, Tessera Solar North America CEO commented: ‘Our projects will break ground next year [2010], with the goal of producing 1000 MW by the end of 2012.’
Beyond California, Florida’s FPL Group and associated companies reportedly remained the market leader at the end of 2009 in terms of installations. The group, which includes – NextEra Energy Resource and Florida Power & Light (FP&L) – is expected to maintain its overall leadership position by combining NextEra’s 147 MW net ownership in California and FP&L’s Martin 75 MW integrated solar combined cycle (ISCC) facility in Florida, which is due to come online in 2010 and which will be the world’s first hybrid solar energy plant combining a solar-thermal field with a combined-cycle natural gas power plant. Construction commenced in December 2008 and the plant, the largest solar thermal installation outside of California, has an annual estimated generation of about 155 GWh.
Over in Europe – where evidence of utility engagement is less obvious via PPAs and directed more into joint project development – Spain is the central focus of CSP activity with a number of installations commissioned or under development. For example, in June 2009, Abengoa Solar’s first high-temperature power tower, Eureka, was unveiled as a platform to test a new type of high temperature receiver. This experimental plant occupies a 16,000 square foot (1486 m2) portion of the Solúcar Platform, a 300 MW solar thermal and photovoltaic solar installation complex scheduled for completion in 2013. Eureka uses 35 heliostats and a 164 foot (15 m) tower which houses the experimental superheating receiver. Capacity of the plant is approximately 2 MW and the facility includes a thermal energy storage system.
With this new development Abengoa Solar now has three solar power towers in operation, two in commercial use, and began operation of the world’s largest solar power tower plant, the 20 MW PS20 installation in April of 2009 at the Solúcar Platform, near Seville in Sanlúcar la Mayor. PS20 consists of a solar field made up of 1255 mirrored heliostats with a surface area of 1291 square feet (119 m2) and a receiver at the top of a 531 foot (131 m) high tower.
In addition to 31 MW already operational, in December 2009 Abengoa entered 13 plants in the CSP pre-allocation registry in Spain with a combined capacity of 650 MW. The new plants, each with a capacity of 50 MW, are grouped into five solar platforms: Solúcar, where construction is being completed on three plants included in the registry; Écija, where two plants are under construction; Ciudad Real, where construction will begin on two plants in 2010; Carpio Complex (Córdoba), where construction of two plants will commence in 2010; and, Extremadura Complex in Logrosán (Cáceres), where four plants will be built in different stages.
CSP market leader Acciona Energia, also of Spain, has received pre-allocation for five CSP projects, totaling 250 MW, with a capacity of 50 MW each: Alvarado (also called ‘La Risca’); Palma del Río I and Palma del Río II (in Andalusia), and Orellana and Majadas (in Extremadura). The 250 MW have been included in Phase 1 of the four established by the Spanish Cabinet in November 2009, which means that the facilities can enter service as soon as their construction is completed. They represent 28% of the CSP capacity preallocation in this first phase and 11% of the total preallocated capacity.
The Solúcar Platform, which features a research and development area that is building several demonstration plants for new technologies, contains installations employing practically every type of solar technology available, whether in commercial use or under demonstration. However, Abengoa is also working on a similar development in Aurora, Colorado known as the Solar Technology Acceleration Center (SolarTAC), which announced its start-up in October 2009. Abengoa Solar, one of the six developers of SolarTAC, will set up a parabolic trough collector experimental site linked to an assembly plant located within the facility for testing and validating the company’s new designs. The Electric Power Research Institute (EPRI), the US National Renewable Energy Laboratory (NREL), the City of Aurora, the Colorado Renewable Energy Laboratory, the US Midwest Research Institute (MRI), SunEdison and Xcel Energy have also signed up to join SolarTAC.
Elsewhere in Europe, alongside Abengoa, other players include Schott Solar AG, which significantly expanded its CSP production capacity to 400 MWe, compared with the previous year’s 200 MWe, in 2008/2009. Schott says It has 1 GWe of CSP capacity planned.
And, at January’s World Future Energy Summit in Abu Dhabi, Ferrostaal AG announced an order for the Andasol 3 parabolic trough CSP plant in southern Spain. Another CSP plant is also planned, the parabolic trough Ibersol in Extremadura, which like Andasol 3, is scheduled to have a capacity of 50 MW and to be completed in 2013. Andasol 3 is slated to begin supplying power in 2011. Both Andasol 1 and Andasol 2, each of which has an output of around 50 MW, have already been connected to the power grid and started test operation. And, like Andasol 1 and 2, Andasol 3 will have a thermal storage which will enable power to be generated reliably for up to eight hours at night or in cloudy weather. Ferrostaal is implementing Andasol 3 together with RWE Innogy, RheinEnergie, Solar Millennium and Stadtwerke München (Munich City Utilities).
Prof. Fritz Vahrenholt, chairman of RWE Innogy said: ‘Parabolic trough technology sets new benchmarks for solar electricity generation. It can be deployed on a large scale and generates electricity in a reliable and grid-friendly way even after sunset thanks to a huge molten salt thermal storage system. This allows the plant to generate electricity for almost twice the amount of hours as a solar power plant without the storage system. For us, this investment is therefore a further important step toward a sustainable and safe method of providing energy on the basis of renewable energies.’
Market Expectations
While still limited in terms of MW installed, CSP is clearly attracting considerable interest. According to EER’s January 2010 Power Advisory analysis – see figures 1 and 2 shown on page 70 and 71 – in 2009, CSP additions jumped 26% from the 2008 total of some 482 MW to 606 MW.
At the start of 2009, with around 480 MW of CSP installed globally and another 800 MW under construction in Spain, the CSP industry was gaining momentum – yet significant permitting and regulatory hurdles remain. Now, with close to 130 projects under development in Spain and over 50 projects in the US pipeline, the CSP sector is expected to demand as much as US$80 billion of investment over the next decade. And, though the market will be led by financially-sound first-movers with CSP plants under construction, a host of new entrants are now vying for CSP market share along the value chain.
In Europe Acciona Energía and Iberdrola Renovables added 50 MW each to their renewable portfolios in 2009. However, Iberdrola’s omission from Spain’s ‘pre-registration’ list indicates that it has abandoned a previously announced 600 MW Spanish pipeline, EER says. Acciona is expected, nonetheless, to add another 100 MW and 50 MW in 2010 and 2011, respectively
Elsewhere in Spain, independent power producers (IPPs) Abengoa Solar, Grupo Samca, and ACS Cobra are scheduled to add 100 MW each in 2010, collectively some 44% of total annual additions for 2010, placing them into the top five of EER’s CSP ownership rankings.
By the end of 2010, 59% of the 1292 MW of global installed capacity will be in Spain, compared to 30% at year-end 2008, overshadowing the US market’s projected total installed capacity of 493 MW by year-end 2010, EER forecasts.
In 2010, the US market is expected limited to FP&L’s 75 MW ISCC project, Chevron’s 29 MW enhanced oil recovery system by BrightSource in Coalinga, California, and two demonstration systems – Xcel Energy’s 4 MW ISCC and Tessera Solar’s 1.5 MW facility.
Parabolic trough technology leads, and is forecast to represent more than 93% of global installations, including 125 MW of ISCC applications in Algeria, Morocco, Italy, and the US by the end of 2010. However, in 2010 – with eSolar’s 5 MW direct steam-generating demonstration facility and 15 MW planned for 2010 by licensee ACME Energy in India – central receiver technology will receive a minimal boost in 2010.
David Appleyard is associate editor of Renewable Energy World.
Uncertainty over a global treaty to cut carbon emissions has slowed investment in clean energy in South Africa, where only a handful of such projects have started compared to other emerging markets.
A senior official from South Africa’s agency for assessing domestic clean-energy projects told an African conference on biofuels on Monday the country, the continent’s worst emitter, has lagged global trends in launching such projects.
Under the Kyoto protocol’s Clean Development Mechanism (CDM), countries are required to cut carbon emissions by 5,2% by 2012.
“One of the barriers to CDM projects in South Africa is the uncertainty around the post-2012 regime, on whether the accord will continue or not,” Ndiafhi Tuwani, the official at South Africa’s Designated National Authority (DNA) said.
“Some of the potential project developers are reluctant because of that …there is need for a new protocol or a new accord. The previous Copenhagen accord did not come up with a new protocol (beyond) 2012.”
According to Tuwani, South Africa has 17 CDM projects registered to date, of which only four have been issued with CERs. The top two nations in the scheme, according to UN figures, are China with 787 projects and India with 498.
The CDM is part of the Kyoto protocol climate pact whose first phase ends in 2012 and there is no decision yet to extend it or agree on a separate climate treaty.
Under the agreement, rich nations that invest in clean-energy projects in developing countries earn certified emissions reductions (CERs) that can in return be sold for profit or used by polluting firms to meet their mandatory emissions targets.
A UN meeting in Bonn, Germany on Sunday agreed to revive talks on a new deal to slow global warming after December’s Copenhagen summit fell short of a binding deal.
CDM Africa Technical Manager Marco Lotz was optimistic projects aimed at cutting emissions would continue beyond 2012.
“Protocols come and go but it is not the end of the world if the Kyoto (protocol) expires. There is a whole industry that has evolved,” said Lotz.
Reuters
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With headlines proclaiming “water is the new oil,” the race to make desalination a viable solution to worldwide water shortages is on.
In recent years, a number of big-name companies have gotten into the desalination game, including Dow and General Electric, both of which have worked on advanced material membranes for desalination. Today, IBM joined the group with its announcement of a pilot desalination project in Saudi Arabia.
Conducted in partnership with a team of researchers from the King Abdulaziz City for Science and Technology, the IBM pilot will test two new technologies from IBM’s research team: a nanomaterial membrane that will help to chemically separate water from salt and other elements found in ocean or brackish water, and a concentrated solar system with an innovative cooling mechanism that will allow it to take better advantage of the desert heat and fuel the desalination process with renewable energy.
As is the case with most projects that grow out of Big Blue’s research team, these technologies will be tested by IBM but commercialized by someone else.
“We are not about to get into the solar business or the membrane business, we’re in IT,” explains Sharon Nunes, vice president of IBM’s Big Green Innovations.
The project gets at one of the primary reasons many environmentalists have long opposed desalination: It’s energy intensive.
The vast majority of desalination plants in the world employ a process called reverse osmosis. Either ocean water or brackish water is pushed through a series of membranes at very high pressure, effectively separating water from other elements.
Most companies looking to get into the desalination space, which is all but guaranteed to grow over the next several years, concentrate on the membrane, researching advanced materials that can help to chemically strip water from other elements and thus reduce the pressure requirements for the water coming through the membranes, which in turn reduces the energy requirements of the process.
According to the Encyclopedia of Desalination and Water Resources, the theoretical minimum amount of energy required to desalinate a cubic meter of water is .86 kWh, but the actual energy required in plants throughout the world is five to 26 times that. The theoretical minimum calculates only the energy required to separate water from other elements, not the power required to keep a plant running in general.
That’s where the solar power comes in.
Desalination plants and solar energy are a natural fit: More often than not, areas with water shortages also tend to be areas where there’s quite a bit of sun. At the IBM/KAST Saudi Arabia plant, a solar concentrator system will capture energy equivalent to 1,500 suns, according to IBM, powering a plant that will produce 30,000 cubic meters per day of fresh water for a city of 100,000 people.
So why haven’t solar-powered desal plants been popping up all over the world?
“Solar is still not at grid parity, and if you’re going to build a solar system into a desalination plant, you also need a back-up system in case of cloudy days or dust storms, and all of that is a large additional cost to building a plant,” explains Nunes.
Part of what reduces the cost of solar in this case, according to Nunes, is a proprietary cooling technology that cuts down on system outages and maintenance issues. The liquid metal interface of the system, a technology that grew out of IBM’s experience with mainframe computers and chip manufacturing, enables very high cooling rates, according to Nunes, and thus more intense energy capture.
“Usually, the more energy capture, the hotter your solar cell gets, and we’re talking about really extreme temperatures, which means you end up with unreliable chips or you burn out your chips entirely, so cooling these systems is very important,” she said.
High-Tech Membranes Increase Efficiency
According to Nunes, the membranes employed at the Saudi desalination plant will help reduce the plant’s energy requirements.
The membrane includes fluorine, which is naturally hydrophobic, but at an adjusted pH that makes it hydrophilic. In layman’s terms, through the magic of chemistry, a material that usually repels water now attracts it, which makes it a very effective membrane with which to desalinate water. The material also is resistant to chlorine, which is often used to pre-treat water in purification systems but typically degrades membranes.
The membrane is also more resistant to fouling than other membranes on the market, according to Nunes. The sand, shells, weeds and small sea creatures that can get stuck on membranes means they need to be cleaned fairly often, and when the membranes are at their dirtiest, more energy is required to push water through them at a higher pressure.
Which gets to the other aspects of desalination that environmentalists don’t particularly like, aspects that IBM’s technology isn’t yet focused on: loss of biodiversity in some marine areas and the effect of the briny effluent produced by the desalination process, which is generally dumped back into the original water source.
Concerns for Biodiversity
The brine (a highly salty water that’s 10 times saltier than average ocean water) produced by desalination plants has been tested in labs and shown to have little effect on marine life, but the argument from some marine biologists is that in a lab test, fish and other sea life can’t get away; while the brine may not kill them, in a real-world scenario they may opt to just leave an area that is suddenly 10 times saltier than it used to be.
The loss of biodiversity is an issue that has largely been pooh-poohed by desalination proponents. There are currently more than 12,000 desalination plants in the world, and as that number grows, it could have a drastic effect on marine ecosystems as the smallest organisms are routinely sucked into a pump and crushed against membranes.
The current focus on improving energy and water efficiency in desalination plants is a positive one, and replacing coal-powered desalination with solar-powered desalination is imperative, otherwise the “solution” to the water problem is helping to exacerbate one of the causes: climate change.
But the idea of efficiency needs to be more broadly applied to the water problem as a whole. One of the reasons that fresh water is at a premium is that much of it has been polluted. In some cases, that renders the water completely undrinkable; in others, in order to drink it, the fresh water needs to be purified in much the same way that saltwater needs to be desalinated, and that process is also energy intensive.
Purification processes need to become more efficient, fresh water stores need to be better protected and technologies that help people use less water and use it more efficiently are still desperately needed. As is the case with energy, solutions to the water shortage need to look at efficiency first and then filling in with “new” water where nothing more can be done on the efficiency front.
As a researcher at the Pacific Institute studying the pros and cons of desalination once put it to me, if you’ve got a leaky bucket, what’s the more logical solution, to just add more water or to plug the holes?