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You can say those three hurdles will always remain and not just    for CSP, which uses reflectors to concentrate and beam sunlight toward a    receiver for producing steam, which then goes to powering    turbine-generators for producing electricity. But the three issues have    evolved in a marketplace that also has changed in the last few years.    Photovoltaic panels have become far cheaper than expected, prompting    solar thermal power companies such as Solar Trust of America and    SolarReserve to start developing PV projects.

Concentrating photovoltaic (CPV) technology is attracting buyers,  and   that’s going to spark competition between CPV and CSP for optimal    project sites. Both technologies work best in super sunny locals  without   much clouds – they both use reflectors to concentrate  sunlight, and   those optics don’t do well with diffused light.

CSP technology developers know competition will only grow more    fierce. To win customers, they are improving efficiencies of their    equipment to turn sunlight into electricity and adding storage to make a    CSP project operate more like a fossil-fuel power plant. The U.S.    Department of Energy, in addition to funding power plant projects, also    has directed its researchers to explore similar technology issues.

“Our research includes the development of new heat-storage  materials   that are stable at high temperatures and methods that  maximize the   thermal energy storage capacity at low costs,” said Cliff  Ho, a   scientist at the Sandia National Laboratory.

The CSP market so far has a bright future. About 17.54 GW of  power   projects are under development worldwide, and the United States  leads   with about 8.67 GW, according to GTM Research. Spain ranks  second with   4.46 GW, followed by China with 2.5 GW. 

About 1.17 gigawatts of CSP power plants already are online.  Spain is   home to 582 megawatts of them, followed by the United States  with 507   megawatts. Iran, interesting, takes the third place with 62  megawatts,   GTM said.

Front Runners

Major CSP players share similar profiles: they are staffed with    experts in power plant engineering, sometimes specifically in CSP plant    designs. They also are able to raise the capital to finance research  and   development and power plant construction. Some of them already  have   built projects in Spain, where feed-in tariffs provide a  sure-source of   incomes and an incentive to use energy storage to boost  production.   These project developers include Solar Millennium,  BrightSource Energy,   Abengoa Solar, Penglai Electric, Renovalia and  NextEra Energy. Solar   Millennium, by the way, is part owner of Solar  Trust of America, which   focuses on U.S. projects.

Although the United States has no feed-in tariffs, which are    government-set wholesale electricity pricing designed to guarantee good    returns, certain state policies have attracted a cadre of developers.    They have flocked mostly to the southwestern region, which offers a    combination of sunny climate, state mandates for renewable energy use,    and public land that is available for energy development leases.

California, a state that recently passed a law that requires    utilities to get 33 percent of their electricity from renewable sources    by 2020, has been a magnet. So have Arizona, Nevada and Colorado. The    California Energy Commission alone approved nine CPS projects  totaling more than 4.1 gigawatts within a four-month period last year.    The federal Bureau of Land Management, which also signed off on many  of   these California projects, approved additional projects in Nevada. One of Abengoa’s key projects, 280-megawatts Solana, will be built on private land in Arizona.

Winning permits only clears one major obstacle for these  developers.   Raising money is another. Without feed-in tariffs, these  CSP projects   must compete more on cost in order to win power sales  contracts from   utilities. As a result, the projects are all more than  100 megawatts in   order to reach an economy of scale that keeps the  construction and   operating costs down. Solar Trust of America is  working on the   1,000-megawatt Blythe Solar Project in California, but that project is divided into four power plants of 250 megawatts each.

The need for scale also leads to a high price tag for the overall    cost of each project. Many developers applied to a federal loan    guarantee program that sprung from the stimulus package in 2009. Nailing    that loan guarantees was critical for all these companies who wanted  to   build their first CSP power plant in the United States. They also  had   to be able to raise equity for the project because the loan  guarantee,   which paves the way for the recipients to get loans from  the   Treasury-run Federal Financing Bank, will at most cover 80 percent of a project’s cost.

The U.S. Department of Energy, which oversees the loan program, has been fond of CSP. It has offer a total of roughly $5.89 billion to four projects;    that’s more money and more projects than what the DOE has offered to    developers of photovoltaic or concentrating photovoltaic power plants.    Solar Trust is set to get about $2.11 billion to build half of Blythe; SolarReserve is finalizing the paperwork for $737 million for the 100-megawatt  Crescent Dunes  Solar Energy Project ; BrightSource closed $1.6 billion    for the 392-megawatt Ivanpah Solar Electric Generating System; and    Abengoa closed about $1.45 billion for Solana.

SolarReserve is waiting for word about its loan guarantee  application   for another, 150-megawatt project called Rice Solar Energy  Project in   California, said Tom Georgis, senior vice president of  development at   SolarReserve.

The loan guarantee program is set to end this Sept. 30. Solar    companies would like to see it get more funding. But it’s unclear how    likely that will happen, considering that lawmakers and the White House    are sparring over what to cut in next year’s budget. Solar industry    lobbyists also hope to save a program run by the Treasury Department    that covers 30 percent of the cost of a project. CEO of Solar Trust, Uwe    T. Schmidt, said his company is mindful that federal funding won’t    always been plentiful, and he hinted at the company’s efforts to find    other sources of funding.

“We are looking for innovative ways to complement the traditional    debt and equity structure,” Schmidt said. “You will see examples of  what   we mean.”

Key Technologies

Power plant designs that use parabolic trough reflectors and power-tower receivers are the most popular.    Solar Millennium and Abengoa Solar are primarily devotees of  parabolic   trough technology while BrightSource concentrates on the  power-tower   design. The parabolic trough design features rows of  connected   reflectors that focus the sunlight onto tubes that run along  the length   of the reflectors. These tubes contain synthetic oil that  flows to a   heat exchanger to heat water and produce high-pressure  steam. The steam   then powers a turbine, which in turn runs a generator  to produce   electricity.

Parabolic trough power plant developers such as Solar Trust and    Abengoa like to call this type of technology “proven” because a series    of parabolic trough power plants totaling 354 megawatts materialized  in   California between 1984 and 1990. But today’s parabolic trough  designs   are quite different than those from two decades ago. NextEra  owns 310   megawatts of this cluster of CSP plants in California. The  company also   is developing a 250-megawatt, Genesis Solar project in  California, for   which it has received the construction permit from the  California Energy   Commission. The largest CSP power plant proposal is  the 1,000-megawatt   Blythe project by Solar Trust.

Another CSP technology uses a central tower instead of tubes as  the   receiver. A field of reflectors beams the light to the top of the  tower,   where a tank of water or molten salt sits. The heated fluid  then goes   through the similar steps for steam generation and  electricity   production. BrightSource and SolarReserve both are betting  on the   success of this technology; BrightSource uses water while  SolarReserve   uses molten salt. The salt, which keeps heat trapped for  hours, can be   used for electricity generation after the sun goes down.

Stirling engines make up the third common CSP technology and,  unlike   parabolic trough and power tower setups, each Stirling engine  embodies   both the thermal and electric generation mechanisms and uses  gas rather   than fluid to transfer the sun’s heat. Main components of a  Stirling   engine include a giant round dish of reflectors that  concentrate the   sunlight to heat up hydrogen gas or helium inside an  engine. The heat   gas expands and creates a lot of pressure that is  then used to run the   piston that then drives the generator to produce  electricity. Stirling   engine companies include Infinia and Stirling  Engine Systems (SES).

Stirling engines from SES seemed close to being deployed  commercially   by Tessera Solar until Tessera had a hard time raising  the necessary   financing and sold its two prized projects late last  year and earlier   this year. One of the buyers, K Road Power, said it will still use Stirling engines  but only for a small portion of the Calico project; the rest will use    solar panels. Tessera sold Calico as an 850-megawatt project because  the   project came with an electric grid interconnection agreement for  850   megawatts. But the California Energy Commission cut the size to  663.5   megawatts before issuing the permit, and the commission said  the application from K Road to modify the permit in order to use solar    panels does not request any change to the size of the project.

The second buyer, AES Solar, told the commission that it wasn't going to    use Stirling engines at all for the 709-MW Imperial Valley Solar    Project and will use some sort of PV technology instead. But the company    then notified the commission last week that it still wanted to hold  on   to the permit for the solar thermal power plant, so it remains  unclear   what the company plans to do. AES declined to comment for the  story.

Which Works Best

Developers of different technologies will tell you one type is better than the other.    There are indeed advantages and room for improvements for all three,  Ho   said. Temperatures that these technologies can achieve when heating  up   the heat transfer fluid in the receiver, reflectivity of the  reflectors,   as well as the sunlight-to-electric conversion  efficiencies are some of   the metrics.

Parabolic trough plants generally heat the heat transfer fluid to    about 390 degrees Celsius, which is lower than the temperatures from    power tower plants and Stirling engines, Ho said. Power tower designs    can achieve around 550 degrees Celsius and higher. Running a steam    turbine at a higher temperature improves its efficiency. The    thermal-to-electric efficiency of a parabolic plant is around 38 percent    while the efficiency for a power tower plant is up to 42 percent, Ho    said.

A power tower plant can end up operating for fewer hours each  year   than the trough plant, however, because power tower relies on a  single   receiver. The plant’s output will be compromised if that  receiver isn’t   working well. A trough plant has many loops of tubes,  so one problematic   loop won’t cause the whole plant to shut down, Ho  said.

If you look at the sunlight-to-electricity efficiency, Stirling    engine can do better than parabolic trough or power tower. The    paraboloidal dish of the Stirling engine gives it the highest solar    concentration ratio, Ho said. As a result, the sunlight-to-electric peak    efficiency is about 31 percent for Stirling engine and 22-23 percent    for the other two, Ho said. Stirling engines use far less water and    needs it for washing the dishes. Parabolic trough and power tower    designs, on the other hand, need far more water  to condense the steam for re-use after it’s gone through the generator.    The latter two can use dry cooling by running fans, but that adds  costs   and lowers the plant’s efficiency. Fights over water use have  prompted   BrightSource, Solar Trust and NextEra to incorporate dry cooling in designs for some of their projects.

Stirling engines are modular; each of them is a stand-alone power    producer. That can be an advantage for deployment because these  engines   don’t require a centralized turbine-generator. But it also can  be a   disadvantage because it can’t achieve a certain economy of scale  that is   possible with parabolic trough and power tower designs, where  one way   to increase energy output may be to add more reflectors but  not other   pieces of equipment. A Stirling engine plant scales more  like a PV power   plant, Ho noted. Adding storage to Stirling engines  will improve the   technology’s appeal.

“Currently, without storage, dish-engine systems are similar to  PV   systems,” Ho said. “Storage will be a differentiating factor  between   dish-engines and PV modules that can increase the capacity  factor of   dish-engines and potentially reduce costs.”

Storage is a big selling point for CSP developers these days,    particularly since they are having a harder time competing with PV    technologies that have become much cheaper in the last two years.    Storing thermal energy for use after the sun goes down means a CSP plant    is more flexible in adjusting its power output to meet a utility’s    demand. PV power plant output can drop significantly in the late    afternoon and early evening, when electricity use can spike as people    come home from work and turn on TVs and other appliances.

CSP power plants with storage already are running in Spain.    Developers such as Solar Trust and SolarReserve have designed storage    into their projects in the United States as well. Although including    storage means adding costs, the greater ability to provide power on    demand makes a CSP plant more valuable than one without storage or with    PV, Georgis said.

“Las Vegas’ demand stays warm into the evening, when all the  lights   are turned on. We can operate like a conventional power plant.  We can   displace conventional generation,” he added.

Researchers are working on boosting the temperatures of the  molten   salt so that a smaller amount of it is necessary to produce the  same   amount of electricity, Ho said. Finding materials that will keep  molten   salt stable at high temperatures is another goal. Right now,  molten salt   can start to decompose and cause plugged pipes and valves  when it   reaches 600-650 degrees Celsius.

Improving the reflectivity of the reflectors is another research    focus. Schmidt said the latest reflector design by Solar Millennium  and   its R&D partners have created larger and more efficient  reflectors   that come with fewer parts for easy assembly. At Sandia,  meanwhile,   researchers plan to test a metalized polymer film produced  by 3M to see   how it compares with glass reflectors, HO said. This  project is set to   start this summer.

"We want to look at the peak flux, total power, and beam size and    shape to see if we can get a tight beam on the receiver with these    metalized reflective films,” Ho said.