Solar with fossil fuels: partner or competitor?

Five years ago, at the Solar Power conference in Long Beach, California, a man named Charlie Todd worked the exhibit hall, passing out brochures advertising something called CoalSol. It claimed to be a company selling coal-solar-hybrid technology, but actually it was just a joke. Todd, the founder of a comedy group called Improv Everywhere, had been hired by Sharp Solar to pull a prank on attendees and instill some humor into the industry gathering.
The purported technology, illustrated with a smiley-faced sun on a lump of coal and the motto, “Sunshine & Coal Working Together,” was “the worst thing I could think of,” Todd said at the time. And, indeed, many conference-goers smirked or laughed at the idea. The prank wouldn’t seem as funny today.
That’s because companies have started combining solar panels with coal and other fossil-fuel power plants in real life. True, the partnership doesn’t come in the form of the rooftop smokestacks-and-solar-panels solution that Todd pandered back in 2007, but it’s still an unexpected pairing for many outsiders. Until now, solar power has more often found itself positioned as a competitor to fossil fuels rather than a partner.

The shift

The shift began with the world’s first “hybrid” solar power plant, which utility Florida Power & Light unveiled last year. The 75 megawatt solar thermal project, also touted as the first utility-scale solar plant in the southeast U.S., connects to an existing combined-cycle natural-gas power plant. Then in January, Tucson Electric Power (TEP) announced plans to add up to five MW of solar thermal power to a coal- and natural-gas-fired plant in Arizona by early next year.
Meanwhile, Areva Solar (formerly known as Ausra, which provided the solar thermal technology for the TEP project, called the Sundt Solar Boost, has also started construction on a 44 MW solar project for a coal-fired power station in Australia, which it expects to open within a year. And General Electric (GE) is building a 530 MW plant slated to in clude solar thermal power, natural gas and wind power when it opens in Turkey in 2015.
The growing trend of hybrid, or as Areva calls them, “booster” projects could significantly boost the market for concentrated solar power in the U.S. “Here in the U.S., primarily the opportunities we’re pursuing right now are booster opportunities,” says John Robbins, senior director of North American sales at Areva Solar. “I think those projects are going to be the largest share of our U.S. market in the near term. I think, overseas, it’s going to be more balanced between standalone and booster projects. Markets overseas have been very active for us.” He’s referring to markets such as Australia, India, Saudi Arabia, as well as countries in Southeast Asia and South Africa, which offer “carve-out” policies that specify goals for getting a certain amount of CSP or other CSP-specific incentives. Large stand-alone solar thermal projects have cropped up in those markets, while the growth of these stand-alone projects has been slower in places without those sorts of policies. That’s because, in general, stand-alone solar thermal is more expensive than photovoltaic solar in locations like California, explains Jenny Chase, lead solar analyst for Bloomberg’s New Energy Finance.

The draw of hybrid projects

Hybrid projects could change the equation. CSP technologies use mirrors or lenses, a compact linear Fresnel reflector, in the case of Areva Solar, to focus the sun’s heat onto receivers, where it heats water into steam. Then, steam turbines convert that steam into electricity. Conventional fossil fuel power plants also create steam and use steam turbines to make electricity.
And when new CSP projects can use existing steam turbines, interconnection and transmission from fossil-fuel plants, and avoid the permitting costs and challenges of building a brand new plant, especially on previously undeveloped land, the cost drops considerably. This makes it cheaper than new PV projects, Robbins claims.
“It’s really an opportunity to install the lowest cost solar generation available,” he says. “When you compare the total installed cost and economics of a booster with a PV project of the same size, the booster is lower-priced. You just have to install the solar collectors that produce the steam and send it to the steam cycle in the combined plant. Probably half the infrastructure you need is already in place.” Locating CSP at existing power plant sites also speeds the time to market: it typically takes nine months to a year for Areva, he adds. Basically, adding solar enables utilities to expand a plant’s power generation without increasing its carbon emissions. That can make it easier to get an expansion approved by regulators and can also enhance utilities’ image among their customers because they’re doing something to make an existing, and polluting plant greener.
Of course, adding additional solar capacity usually doesn’t reduce emissions from a power plant, although it does avoid the additional emissions of expanding with fossil fuel. But, in some cases, utilities will be able to replace some fossil fuel power with solar power, which would, in fact, reduce emissions. Typically, utilities have been interested in expanding fossil fuel plants’ capacities by five to 20 percent via solar thermal boosters; Robbins says that Areva could also expand beyond that.

An intuitive match?

Robbins admits that partnerships with existing coal- and natural-gas-fired plants hardly make for an intuitive match. “Yes, I’m not sure we would have foreseen this in the very beginning, but I think the customers, at least here in North America, like the booster concept because it is very cost-effective and gives them a lower-cost solution than PV.” Aside from fossil fuel plants, these booster projects could work on geothermal plants, as well as for industrial buildings like chemical refineries or food-processing plants,” says Katherine Potter, Vice President of Communications at Areva.
The booster concept makes good sense, according to Chase. “I think utilities like it better [than PV] because it’s a lot more similar to what they own already,” she says. “You don’t have to buy an extra turbine, and can run it with sun in the daytime and with gas in the nighttime. It’s still really just being tried out, but it’s being tried out in quite a few places, and it’s a big hope for solar thermal because it’s a way utilities can try out their linear Fresnel reflectors for less than PV. It makes sense to try it on a small scale: you can show that it works and generate renewable energy credits without taking the risk of building an Ivanpah.” (BrightSource Energy’s Ivanpah Solar Energy Generating System in the California Mojave Desert is expected to cost US$2.2 billion by the time it’s completed in 2013.) Because solar projects tend to generate the most electricity on hot days, when air conditioners may be running at full blast and boosting electricity demand, adding solar to conventional power plants also could slash the demand for “peaker” power plants. That could cut peak electricity costs, given that peaker plants only switch on during times of peak demand and deliver the most expensive electricity.
Solar thermal also fluctuates less than PV. There’s more inertia in the system so it’s less spiky when there’s cloud cover, for example, and combining it with fossil fuels could further stabilize that flow and reduce the remaining intermittency. It’s more dispatchable or controllable than PV, according to Potter. As Robbins adds, there’s plenty of flexibility in the amount of steam and the pressure of the steam that gets integrated into power plant systems to make power, so those variables can be optimized for utilities’ specific needs. CSP also offers the potential for easier, cheaper energy storage via water, ice or molten salt, he adds.
The announcement in March that the U.S. Environmental Protection Agency could impose greenhouse gas emission limits on new power plants for the first time could also grow the market for these hybrid projects. If the proposal is ultimately approved, it will essentially ban new coal-fired power plants unless they incorporate costly emission controls, so utilities will be looking for other ways to expand their capacity. “I think this will give a shot in the arm to the booster market in the U.S.,” Robbins says. He adds that another proposal for stronger controls of mercury and other toxic air pollution would do the same. “Anything that forces utilities to think about greenhouse gases from existing plans is going to make them think about this kind of technology.”

Obstacles

These hybrid projects still have obstacles to overcome, however. After all, they’re still a fairly new concept, with only one project completed, so they have plenty to prove. Challenges include integrating the system, controlling the gas versus solar component and dealing with the usual intense engineering challenges of building a solar thermal plant, Chase says. “There are always challenges retrofitting a major engineering work,” she says.
An incident at the Florida Power & Light project underlines that point: last June, the system leaked steam, water and heat transfer fluid for about two hours after too much pressure had built up, dramatically reducing its performance and requiring a cleanup, according to the Orlando Sentinel.
So far, at least for Areva, integrating the steam hasn’t proven to be much of a headache, says Robbins. It’s mainly just a matter of figuring out where best to integrate the steam into an existing system, he says. “It’s just steam and we’re very comfortable working with steam, so it’s really just a question of what’s the most effective point,” he says.
A bigger issue is that the projects also need to have enough existing land to add the solar thermal, as well as enough sun, Robbins adds. And, as Chase points out, coal and gas are usually located near water for cooling, meaning they often aren’t in high desert sites that would be perfect for solar thermal. But Areva is seeing plenty of potential sites: while not all fossil fuel plants have land available next door, many larger ones do, as Robbins says. That makes sense, given that locations next to large power plants don’t tend to be particularly popular. So the big question for the PV industry is if these hybrid projects will lead to more utilities opting for CSP instead of PV? Chase dismisses the idea, at least for now. “Not in the near term. There’s plenty of space for both, and, in the long term, many of the grid, intermittency and transmission issues which may ultimately limit PV will not be affected by hybrid CSP plants.” Robbins says he also doesn’t think boosters will replace large-scale solar projects, either for CSP or PV, because there are still many good locations out there where the economics are very favorable for standalone projects.
However, it also doesn’t seem like PV players have much of an opportunity to play a role in these hybrid plants because they don’t create the steam that would allow them to integrate with fossil fuel plants in the same way as CSP.
One caveat: by including wind, perhaps the GE project could open the door for the inclusion of PV in a hybrid project as well. Wind, like PV, doesn’t produce the same ingredient – steam – as CSP and fossil fuel. “It would be very similar to having a PV plant out there,” Robbins says. But wind is an easy choice for GE, which also sells wind turbines, and there’s at least one reason that integration of wind might make more sense to pair with CSP than PV: wind systems tend to make more electricity at night, while solar creates electricity during the day.
In any case, it’s clear that as the market for booster plants grows, competition will too. For booster plants, the cost, reliability of the system and the maintainability of the system will likely determine which technology providers will win out, Robbins says.