A plan to send energy from Tunisia to Britain is underscoring how much the concentrating solar power (CSP) industry now relies onstoragefor viability.
A British firm called Nur Energie is lobbying to secure U.K. government contract-for-difference support to build a 2.5-gigawatt CSP plant in the Tunisian desert and export the power generated to Britain via a high-voltage DC cable crossing the Mediterranean and Europe.
However, the sole reason for relying on CSP is that the plant will use molten salt thermal energy storage to provide baseload power. That would allow it to compete with new nuclear plants, the development of which are still uncertain in the U.K.
Nur Energie CEO Kevin Sara told Bloomberg the project, called TuNur, could work with a U.K. contract for difference 20 percent below the rate being offered for offshore wind.
The contracts awarded for two offshore wind farms in February this year had strike prices of between £114.39 ($173.66) and £119.89 ($182.03) per megawatt-hour.
Taking the lower of these would give TuNur a strike price of around £91.51 ($138.98), just below the £92.50 ($140.49) agreed for the U.K.’s planned Hinkley Point C reactor, but still above the £79 ($120) agreed for three solar PV plants in February.
The fact that PV remains significantly cheaper than CSP is the reason why the latter almost always has to incorporate storage nowadays, said Jenny Chase, solar insight manager at Bloomberg New Energy Finance.
“Basically, solar thermal electricity generation has decisively lost the competition on cost per megawatt-hour from the sun, to PV,” she said.
Contrary to Nur Energie’s estimations, Bloomberg New Energy Finance calculates that most solar thermal plants would need a power-purchase agreement in excess of $200 per megawatt-hour to be commercially viable.
This compares to just under $100 per megawatt-hour for PV “in a similar sunny location,” Chase said. “The only reason anyone would give you that premium is if you were supplying power that matched the demand of the grid you were feeding into better than PV does.”
A survey of recent CSP projects shows that regulators and developers are acutely aware of this fact. Whereas CSP with storage was a novelty until recently (the first solar power tower to use molten salt, Gemasolar, only entered operation in 2011), now it is standard.
This is particularly the case in markets such as South Africa, where there is a need to meet evening demand peaks that PV cannot handle. South African regulators have approved at least half a dozen CSP plants with storage.
“South Africa pays 270 percent of the base rate for power delivered between 4:30 p.m. and 9:30 p.m.,” observed Chase.
This makes it economically viable to supplement PV plants with more expensive CSP projects that have enough hours of storage to cover the early evening peak.
Thus the 50-megawatt Bokpoort parabolic trough plant being built by ACWA Power has nine hours' worth of molten salt storage.
Abengoa, meanwhile, is adding two hours of storage to its 50-megawatt Khi Solar One power tower, and 2.5 and five hours, respectively, to its 100-megawatt Xina Solar One and KaXu Solar One parabolic trough projects.
Storage is even being used for competitive advantage in markets where evening demand peaks are not such an issue, however. Chile, for example, has at least 11 plants with storage either announced or under development (a further two have been canceled).
In the Chilean market, the advantage of storage is that it allows CSP to provide baseload energy supplies for the power-hungry mining operations in the north of the country.
Accordingly, the amount of storage being planned for these projects is much greater, averaging over 12 hours per plant.
The ability to use CSP with storage to cover for times when PV will not work is even leading some developers to consider combining the two in a single, hybrid setup.
In Copiapó, Chile, for example, SolarReserve is planning a plant that blends CSP and PV to provide round-the-clock power for mining. “In a lot of projects, we’re looking at PV and CSP in a singled integrated facility,” said Kevin Smith, chief executive officer at SolarReserve.
“We see them as complementary. We can use PV during most of the day to generate power when the sun is shining, and help round that out with CSP during the day and even 24 hours if you need it.”
The Copiapó plant, which has completed environmental permitting, will deliver 260 megawatts of baseload energy from a 150-megawatt PV farm integrated with two 130-megawatt power towers, each with molten salt storage systems.
One power tower will mostly work during the day to supplement the output from the PV arrays, Smith said, and both will deliver power from thermal energy storage when the sun goes down.
Using PV to cover most of the daytime load helps bring down the overall cost of the project. “The pricing is very cost-effective,” said Smith. “We can beat the grid with no subsidies.”
Going forward, the company is promoting integrated hybrid power plants, involving PV, CSP, and potentially fossil fuels, as an alternative to grid supplies for mining companies. The developer claims CSP and PV can deliver capacity factors of up to 90 percent.
“For full 100 percent availability in off-grid scenarios, a relatively small amount of fossil fuel can be used on cloudy days,” says SolarReserve in its marketing materials.
“The most cost-effective fuel integration strategy usually involves burning fuel (typically diesel) to heat the salt; which still results in a dramatic reduction in fuel use, but also allows the CSP plant’s steam turbine to run at full capacity on fossil fuel if needed.”