Thermal energy storage tanks. Image: Abengoa / Dennis Schroeder.

Instead it is testing pilot projects using batteries at utility-scale, even though it must be obvious to bean counters at utilities that batteries are never going to compete with utility scale CSP storage. 

By Susan Kraemer

The 32 MWh battery storage pilot for USD$49.9 million at Tehachapi works out to $1,500 dollars per kilowatt hour. Though battery developers talk of cutting costs 30% in the next few years, even then battery storage will still be prohibitive.

But molten salt storage for utility scale CSP can already be built for $20 per kilowatt hour, and by 2020 that is expected to be $15.

CSP already sells Power Purchase Contracts (PPA)s for both energy and storage for 13 cents a kilowatt hour at utility scale. Yet currently in California, though regulators have mandated 1.3 GW of storage, none is supplied by CSP.

“With storage, CSP is a highly valuable resource, and we have to figure out how to properly value that. We’ve started to. But it's going to take a few years,” says former CPUC staff member Larry Chaset, now an Attorney with Sustainable Futures.

Catch 22

Building more apparently cheap PV and then putting much more expensive battery storage on the grid to patch up the new steep evening peak it creates makes no sense. CSP with molten salt storage handily beats the cost of PV with battery storage.

But the utilities’ renewables buyer doesn’t buy storage. And the storage buyer doesn’t buy renewables.

Perhaps a CSP project should price its storage separately from generation to make it clearer that it is the same price as PV if you priced the storage separately.

For example, of the 13 cent PPA that SolarReserve signed with NV Energy, 5 cents per kilowatt hour might be assigned as pure generation like PV. The other 8 cents per kilowatt hour, for storage.

One way to split it might be to treat CSP projects the same way as natural gas projects, paying for energy and dispatchability or capacity factor separately.

CSP with energy storage behaves very much like a natural gas plant, with the same ability to operate at the same capacity factor as a natural gas plant, and to operate to meet the needs of a utility at any time.

“We can operate at a 90 to 95% capacity factor during the periods that NV Energy wants us to operate to meet peak demand,” says SolarReserve CEO Kevin Smith, of his utility contract to supply Las Vegas nightlife with electricity from the 110 MW Crescent Dunes CSP tower project. At 1,100 megawatt hours of storage, it has 35 times the storage of the Tehachapi project.

SolarReserve’s contract lets NV Energy choose the optimum operating schedules to meet its peak demands - which vary seasonally but typically are 12 noon to midnight - while requiring 500,000 megawatt hours annually, so its PPA enforces storage.

A PPA designed to value dispatchability

“The way the utility could structure the PPA is more like a conventional power plant contract; as a fixed payment that essentially pays for the storage, and a variable payment that pays for generation,” Smith posits. “Then you would provide guaranteed delivery during peak periods. If you didn’t deliver as guaranteed during peak periods because you weren't meeting your storage goals, then you would have to pay a penalty.”

When SolarReserve first approached utilities for PPAs, it suggested this model.

The inspiration was the conventional power industry contract. Before starting SolarReserve, Smith negotiated contracts for many traditional gas-fired projects over the years.

“Typically, conventional energy contracts are structured with an energy only price and then a capacity payment, which guarantees a certain percentage of capacity is available during peak periods,” he explains. “If it isn’t, then the utility doesn’t pay the pro rata portion of the fixed payment, which is essentially like a penalty for not being available.”

This penalty is on a percentage basis. The utility would typically require a guarantee that so many megawatts of power will be available 95% of the time. If it is only available 80% of the time, the utility pays only 80% of the capacity payment. Sometimes there is an additional penalty for non-performance.

They are also compensated to shut down for voltage control when too much energy is on the grid, or for the variable costs to start up when they must run on short notice.

The PPAs for both Abengoa’s Solana project in Arizona and Crescent Dunes in Nevada are written to accommodate these sorts of day-ahead requests for changes in operating schedules only possible with storage. So both behave like conventional power plants.

There is an obstacle to using a conventional PPA in California for a renewable energy resource - convention. Renewable energy contracts in California are written for energy generated on a per kilowatt hour basis only.

The exception

The old SEGS at Kramer’s Junction did have a contract like those for traditional energy generation. That is because the SEGS units began their first round of power contracts between 1984 and 1991, and have now begun their second round of 20 and 25 year PPAs.

According to Marc Ulrich, former VP of trading and energy operations at SCE the reason there are two payments in this second round of PPAs is that its original ones were a holdover from familiar gas plant contracts.

“It’s just a legacy of how contracts were established twenty years ago,” he told CSP Today in 2013. “There are fixed payments to SEGS and there are variable payments.”

By pre-dating the renewable era of utility-scale solar, some SEGS units have become ideally situated in their second round of PPAs to reap the benefit of conventional power contracts, because these ascribe a value to the high capacity factor possible with CSP with storage.

SEGS I had a form of thermal storage for its first 12 years that predates today’s more efficient technology. Its owner, Cogentrix, is now looking at cheaper and more efficient molten salt storage using its already-on-site storage infrastructure.

Valuing CSP storage

South Africa has sensibly avoided the wasted time and money of running after much more expensive utility-scale battery storage, and simply carved out two distinct allocations for solar: one for a certain amount of PV - without storage - and a separate one for CSP - with storage.

As well as the carveout, CSP gets a base rate payable for 12 hours every day, but receives 270% of that base price during South Africa’s two daily peak periods. This two-part policy effectively accounts for the value of storage.

California offers time of use pricing, but the differential is not enough to incentivize CSP with storage.

But perhaps regulators in California will find a way, rather than buying more cheap PV and coming in afterwards with prohibitively expensive batteries.

“We’re just going to have to wait and see a little bit,” says Chaset. “If the storage only adds a relatively small amount to the cost, you’re going to start looking more competitive, price wise. My advice to this industry is hang in there.”

Recently ACWA Power signed two PPAs at Ouarzazate in Morocco. Noor II - parabolic trough with 7 hrs. of storage - is 14.9 cents. Noor III, a power tower with molten salt thermal energy storage is about 1 cent more.

And now, ACWA Power and SolarReserve's Redstone CSP Project has been awarded preferred bidder status under South Africa's Renewable Energy Independent Power Producer Procurement Program (REIPPPP). In South Africa, "preferred bidder" status means that they are guaranteed to be able to get a PPA assuming they achieve financial close. Their project is a power tower - with storage - at just 12 cents a kilowatt hour.

Since publication on 6 February 2015, this article has been amended. For further queries, please contact the editor at acastillo@csptoday.com