Solar Thermal Plants Heating Up Again

Pending final approval, for the first time in over ten years, a solar thermal power plant will be built on American soil.

Las Vegas, Nevada – January 6, 2003 [] Sierra Pacific Resources’ two Nevada-based utility subsidiaries have signed long-term contracts with Duke Solar Energy to supply 50 MW of electricity generated by a solar thermal plant to be located in Eldorado Valley, near Boulder City, Nevada. The plant will serve as many as 50,000 customers. There are only nine solar thermal plants – all located in California – known as SEGS plants that were built by LUZ International during the 1980s and 1990s. During construction of a tenth plant in 1991, the company filed for bankruptcy citing a combination of eroding Renewable Energy incentives and plummeting energy prices, according to Hank Price, Parabolic Trough Technology team leader of SunLab at the National Renewable Energy Laboratory (NREL). “In 1991, LUZ filed for bankruptcy because they were unable to get construction financing for their tenth plant due to delays in the signing of the California solar property tax exclusion,” said Price. “But declining energy prices and incentives were the real problem that halted further expansion of trough power plants.” Time has passed however, and things have changed since the 1991 collapse of LUZ International. New state requirements for Renewable Energy coupled with successful research partnerships have revived solar thermal power plant technology. PUBLIC-PRIVATE PARTNERSHIP NREL’s involvement with Duke Solar on parabolic trough technology falls under their support of the Department of Energy’s Concentrating Solar Power (CSP) program. (In the CSP program, NREL works jointly with Sandia National Laboratories (SNL), under the banner of SunLab.) Despite the bankruptcy of LUZ International, the nine solar thermal plants in California performed up to expectations and have attracted attention once again as a viable source of Renewable Energy . “Because of the good operational experience of the SEGS plants, it seemed that trough technology might be a lower risk CSP technology for developers,” said Price. “So in 1998, the CSP program began to evaluate the potential for cost reduction of parabolic trough technology. Based on encouraging results from a technology road mapping effort, the CSP program began to invest in parabolic trough R&D. Duke Solar’s new thermal plant for Nevada is a result of the combined effort of those partnerships. The new plant may be an echo of the past but developers are confident that lessons learned from nine SEGS plants applied to the new project coupled with favorable Renewable Energy Incentives will usher in a new era of solar thermal plants. IMPROVED DESIGN Gilbert Cohen, vice president of engineering and operations at Duke Solar knew where to begin on improving on the SEGS plant designs since he worked on them in the 1980s. “We operated them for more than 10 years and we learned a lot – we knew what kind of improvements we needed for the next one,” said Cohen. “We don’t currently have any plants like this, but most of our staff were working on the SEGS plants, in fact it’s a big part of why we started Duke Solar. Ten years later we have improved the technology and design. We did a lot of research including wind tunnel testing of the troughs. It’s a big improvement and we think the overall solar field will be 20 percent more efficient than the older designs.” Among the improvements to the older design is an increase of co-generation efficiency. The SEGS plants use approximately 20 percent fossil fuels during overcast weather and at night. With the new plant, only a two percent mix of fossil fuels will keep the system warm throughout the night, but it will be the first solar thermal plant of its size not to generate any electricity from fossil fuels. Instead of relying on fossil fuels to handle the temperature change, the new design allows the equipment to handle the temperature fluctuations. The improved technology also helps the plant to be run by only 15 employees – far fewer than the SEGS plants. There also won’t be any on-site engineers or administration. Instead the plant will be remotely administered from Duke’s headquarters in North Carolina. MEETING REQUIREMENTS Nevada Power contracted for approximately two-thirds of the power generated by the plant, while Sierra Pacific Power Company contracted for the other third. The companies will now make filings with the Public Utilities Commission of Nevada (PUCN), which will review the contracts for final approval. “With the addition of this solar contract and the geothermal and wind contracts we recently signed, we expect to be able to satisfy the renewable portfolio requirements for both utilities for the year 2005 and exceed the requirement for the year 2006,” said Walt Higgins, chairman, president and CEO of Sierra Pacific Resources. “Nevada has a tremendous amount of native Renewable Energy resources and these contracts will help us unlock some of those resources while helping the state to meet its growing needs for energy.” The contracts are part of the two utilities’ actions to comply with legislation that requires the use of a certain percentage of Renewable Energy sources to generate electricity for customers within the state. The legislation contains an escalation provision that requires providers of electric service to increase the use of Renewable Energy by two percent every third year, until the provider’s energy portfolio accounts for 15 percent of its total energy sales. The requirement for solar-generated power must be 5 percent of the total Renewable Energy portfolio. Cohen said an energy storage solution may be added at some point in the future to the thermal plant. One such possibility, which is still in a research phase, is a salt-based storage system where salt is melted into a liquid and in turn stored at extremely high temperatures in a tank. After the sun goes down, heat exchanging systems can then run through the salt solution adding energy production capacity. Superheated liquid salt has proven a good medium for efficiently retaining heat. Cohen said this technology could conceivably add a much as four more hours of peak electrical generation to a solar thermal power plant. The storage phase however is only a possibility and will depend on increased research and the economics of implementation. Cohen is confident however, that approval for the thermal plant is a near certainty. As developers wait for word from the PUCN, Cohen wonders what might have been if California had made more of an effort to retain the incentives for solar thermal plants throughout the 1990s. “What happened after LUZ, with the cost of energy so low, is that nobody looked at solar,” said Cohen. “There was no real need or demand for large plants – I think it was a big mistake. If California had built more of these they would not be in the state they are in today. Once it’s paid for in 20 years, the energy is free. If I was the Governor of California I would build 20 of them.”


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