By David Wagman, Chief Editor
Not so long ago the most prevalent form of solar power was the big, clunky looking rooftop panels that heated enough water during the course of a sunny day to wash a sinkful of dinner dishes...maybe.
Not anymore. Utility-scale solar is catching on fast, in part to meet renewable portfolio standards in two-thirds of the states and in part to take advantage of market conditions that put buyers in the driver’s seat in some markets.
Ron Kenedi, vice president-Americas for Sharp Solar, calls this the “beginning of the utility era” in the U.S. solar market. Utility demand for PV could be “huge” and may grow to be his company’s largest segment. “It’s happening all over at once,” he says.
A recent report from the World Resources Institute, “Juice from Concentrate: Reducing Emissions with Concentrating Solar Thermal Power,” says that direct insolation of around 5.5 kWh/m2/day is a minimum requirement for CST development. “Significantly higher DNI (available sunlight) is much preferred if costs are to be kept to an acceptable level,” the report said. Conditions in North America favorable enough to support CST are in the U.S. Southwest. Elsewhere, South Africa, Australia, Northern Africa, Spain, Brazil and parts of India and China have suitable conditions for CST development.
“The main thing making concentrating solar thermal bankable is the quality of the sunlight,” says Britt Childs Staley, one of the report’s authors. “You can’t site CST in Maine; you need a much higher quality of sun with higher radiation.” Photovoltaic cells aren’t nearly as particular about sunlight quality. That makes it possible for a utility like Public Service Electric & Gas to commit to installing 200,000 PV units on its poles across New Jersey.
Even Florida offers somewhat limited quality insolation for CST, the Institute report says. That’s because higher levels of atmospheric water vapor disperse the radiation, reducing a Florida-based solar plant’s potential output. For example, a CST in Phoenix with six hours of storage would have a capacity factor of around 40 percent. An identical facility in Tampa would have around a 25 percent capacity factor. The difference affects both facilities’ bottom-line economics. The Phoenix plant’s long-term real cost of electricity would be around 14.4 cents/kWh. The report said it would be around 23 cents/kWh for the Tampa plant.
“Given the reduced output and lower profitability of CST plants located outside the Southwest, it is unlikely that significant capacity will be installed in other parts of the country,” the report said.
Perhaps, but that hasn’t stopped Florida Power and Light from developing the 75 MW Martin Next Generation Solar Energy Center, which will be one of largest solar plants of any kind outside of California. The facility, near Indiantown, Fla., will also be among the first hybrid facilities to connect a solar facility to an existing combined-cycle power plant, providing solar thermal capacity that directly displaces fossil fuel usage. The project will consist of around 180,000 mirrors over 500 acres at the existing FPL Martin Plant site. Construction began late in 2008 with an in-service date expected in mid-2010.
As an aside, the World Resources Institute report pegged the long-term cost of electricity for a 500 MW pulverized coal power plant with an 85 percent capacity factor and a $2,290/kW capital cost at about 6.26 cents/kWh. By contrast, a 200 MW trough CST with six hours of storage, a 40 percent capacity factor and capital cost of $6,044/kW would have a long-term cost of electricity of 15.36 cents/kWh. Using the federal investment tax credit, the same plant would have a long-term cost of electricity of around 11.37 cents/kWh.
Not surprisingly, CST developers focus their attention on sun-rich locations where utilities and large-scale developers can choose between both PV and CST technologies. “We don’t see it as an either-or,” says NV Energy’s renewable energy executive Tom Fair when asked if his utility favors either technology. “Both are equally proficient at finding sites” around the state.
NV Energy has a purchased power agreement to take 20 MW of PV generated at a site in southwest Nevada. The utility is also looking at installing 250 MW of CST capacity with molten salt storage northwest of Las Vegas. It also is considering adding 80 to 100 MW of solar capacity at its gas-fired Harry Allen and Chuck Lenzie stations near Las Vegas. If built, the integrated solar combined cycle power plant would essentially swap solar Btu’s for natural gas Btu’s, similar to FPL’s Martin Next Generation scheme.
The idea of incorporating a solar field with a natural gas-fired combined cycle power plant is gaining momentum, Fair says. “When you have direct normal insolation (shadow-producing sunlight) it’s a pretty interesting resource.” One benefit is that peak demand typically occurs on hot, sunny days, which is a good fit with the solar resource. Utilities also gain by making use of existing power blocks and transmission infrastructure. That helps minimize permitting scuffles, gets renewable capacity into the utility’s generating portfolio in a hurry and helps control capital costs.
And that’s no small thing, since until recently utility scale solar has been expensive; in some cases prohibitively so.