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Feed-in tariffs and solar renewable energy credits are among the options being pondered to meet the funding challenges CSP projects now face in the US.

By Jason Deign in Barcelona

Can CSP survive in the USA without the Department of Energy’s 1705 loans guarantee programme?

Last year it backed solar projects to the tune of USD$6.8 billion, funding CSP developments such as Ivanpah and Mojave Solar and dwarfing all the other sources of project finance debt combined.

The programme’s demise in September has left pundits wondering what form, if any, future US government support for CSP will take. The energy analyst, commentator and investor Chris Nelder, for example, has argued for the introduction of a feed-in tariff (FiT).

In a recent blog he said: “The rapid growth of the solar and wind industries due to FiTs has driven their costs down to the point where grid parity has already been reached in sunny and windy regions, and has put them on course to reach parity for most of the world by 2018.”

And last year, Christopher Johnston, then head of forwards markets at the renewable energy trading platform SRECTrade, told CSP Today of the potential for Solar Renewable Energy Credits (SRECs) to fund solar thermal projects.

In states that have adopted the SREC market, utilities must buy or produce enough solar energy to meet the state’s Renewable Portfolio Standard (RPS). If the utility falls short, they can either purchase SRECs from other solar power generators or pay a non-compliance penalty.

The penalty, which is higher than the value of the SREC, provides the incentive for utilities to source enough solar energy to meet their RPS quota; or if this proves uneconomical, to purchase surplus SRECs from a generator that can produce it cheaply and efficiently.

Steven Eisenberg, vice president of business development at SRECTrade, says that SRECs are currently aimed more at small-scale renewable energy projects rather than utility-scale CSP. 

Distributed projects

“When you look at the kind of projects using SRECs they are typically distributed projects,” he states. “The biggest one is 18 MW, the second biggest is 12 MW, and there are only 87 that are rated above 1 MW. [The market] is made up of a large amount of small residential projects.”

This does not mean that SRECs, or more generally trade-able RECs (TRECs), could not be used to support solar thermal projects, though.

“It could be something CSP could carve out,” Eisenberg says. “All these programmes are governed on a state-by-state basis so it depends on the lobby.

“In California there has been the development of a TREC programme so if a CSP plant was installed it would be RPS eligible and could trade the RECs from their system. But there are restrictions: only 25% of the RPS could come from unbundled trade-able RECs.”

Currently, says Eisenberg, “there has been a lot of discussion around TRECs for renewable energy in general,” but “not a specific carve-out for CSP.” And other observers doubt that RECs or FiTs could have a significant role to play in supporting US solar thermal developments.

Generally SRECs are in states like New Jersey and Massachussets where it's not particularly sunny, so the economics aren't very good for solar thermal there. While SRECs may be a big deal in New Jersey, it is mainly for PV, which has a major cost advantage.

Loan guarantees

With tower projects, analyst Brett Prior of GTM Research expects traditional solar debt financiers such as Bank of America, Citibank or Goldman Sachs to step into the funding vacuum left by the Department of Energy’s 1705 loans guarantee programme.

“I think these banks will put money into solar projects, if they feel comfortable with them,” he concludes. “I don't think its debt that's the bigger deal; it may be the tax equity that's harder to get.”

But Jenny Chase, solar insight manager for Bloomberg New Energy Finance, believes there may be reasons why utilities may specifically want to support CSP.

“PV is massively underbidding solar thermal,” she says.   “The best chance for solar thermal is to convince utilities that it’s too risky to take a 500MW chunk of intermittent generation.

“We ran a war game in California last year and asked people to think as if they were utilities and how to meet their renewable portfolio standards. They were quite worried about taking on these big chunks of PV.”

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Jason Deign: jdeign@csptoday.com

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Rikki Stancich: rstancich@csptoday.com