US photovoltaic (PV) solar capacity increased by 109% in 2011, according to the Solar Energy Industries Association (SEIA) and GTM Research. Capacity hit 1,855MW last year, mainly in 10 key states (see table below), thanks to the decreasing cost of developing projects – though this is still high compared to more conventional technologies – and generous government support.

Utilities in California – the US state with the highest installed solar capacity – operate auctions for power purchase agreements, a process that has driven down the tariffs they pay for power. Generous state and federal tax credits have also helped put downward pressure on the prices that developers are able to offer the utilities.

Top 10 US states for PV Installations in 2011

Rank	State	Capacity
1	California	542MW
2	New Jersey	313MW
3	Arizona	273MW
4	New Mexico	116MW
5	Colorado	91MW
6	Pennsylvania	88MW
7	New York	60MW
8	North Carolina	55MW
9	Texas	47MW
10	Nevada	44MW
Total		1,629MW

Source: Solar Market Insight Report 2011, SEIA and GTM Research

“Solar is a very interesting area to be working in at the moment,” says Charles Brettell, a partner at Energy Asset Advisors. “The last year has seen the pricing of offtake agreements fall dramatically, especially in California. That said, some of that pricing impact has been muted in the short-term by the plummeting cost of panels. Regardless, given the pricing we’ve heard about in announced deals it remains to be seen whether explosive growth in solar development can continue.”

The falling price of solar panels – notably cheap Chinese imports – has already contributed to the collapse of US developer Solyndra, which filed for chapter 11 bankruptcy protection last year, but a decision last month from the Department of Commerce is likely to put upward pressure on the prices that developers can offer.

Panel beating

Commerce launched an investigation in 2011 into SolarWorld Industries America’s complaint that Chinese companies were selling panels at below-market rates – sometimes more a third – forcing US firms in turn to slash prices. Commerce said on 17 May that Chinese importers did fall foul of anti-dumping rules, and proposed imposing a surcharge of roughly 31% on a group of 61 Chinese exporters.

US panel manufacturers are, unsurprisingly, pleased, but domestic developers that rely on Chinese panels face an increase in prices of more than a third in their largest single cost, at a time when PPA pricing and profit margins are dropping. Market observers think that this could lead to a squeeze in the lower end of the market, but that bigger deals will progress. Darren Van’t Hof, director of renewable energy investments for US Bank, says: “Generally speaking, the panel cost increase should not prohibit good projects from moving forward. We speculate that the market has already priced in some of these tariffs.”

Mike Lorusso, managing director and group head for Energy at CIT, also believes the move will have “minimal impact”. “Solar project developers will simply factor in the tariff cost or switch to a supplier that is not affected,” he claims. “There are many non-Chinese international suppliers of cost-competitive PV panels.”

The dispute intensified following the demise of Solyndra, which filed for bankruptcy in August 2011. But Solyndra’s battle against the impact of Chinese imports was not the biggest headline from its bankruptcy – especially for the politicians – but the $535 million loan guarantee it received from the US Department of Energy.

Extending guarantees

The US government’s guarantee programme for renewable energy was established in 2005, and bolstered by the 2009 American Recovery and Reinvestment Act. Until the end of September 2011 it was divided between 1703, which authorised guarantees loans to projects using or manufacturing innovative technologies, and 1705, which covered loans for renewable projects, power transmission systems and manufacturing, and which could use more proven technologies.

The 1705 programme included an appropriation to cover credit subsidy costs – essentially the premium that developers would have had to pay to cover the department’s potential losses on the programme – while the 1703 programme did not, and 1703 borrowers without the deep pockets needed to offer project guarantees or pay the premium have shunned the programme. But borrowers under 1705 needed to begin construction before 30 September 2011, and the US congress refused to extend the programme’s authorisation during acrimonious budget negotiations earlier in the year.

Lorusso says the programme was intended to provide financing during the period immediately after the 2009 financial markets collapse, when most banks did not have the capital to do so. The second point was “to provide financing to projects that banks were unwilling to finance because they involved new, innovative technology that was largely unproven. A few projects or companies benefited from this part of the programme, including, most notoriously, Solyndra,” Lorusso continues. “This part of the programme did the banks a favour by helping them avoid deals that they were not interested in. The programme also suffered from its own lack of success in this area.”

The 1705 programme’s main impact was in high-end PV, according to Will Marder, global product manager for project finance in Deutsche Bank’s trust and securities services business: “Before the initiative, most of the larger deals involved concentrated solar power and the market had not seen PV solar on a large scale; it was unheard of to develop PV projects of 500MW, so the guarantees did help in bringing the solar sector forwards.” Most of the solar projects that tapped the loan guarantee were large-scale, and a total of 12 benefited (see table below). 

Closed DoE guarantees for US solar projects

Sponsor	Amount	Capacity	Location	Signed
Abengoa Solar (Solana)	$1.44 billion	250MW	Gila Bend, AZ	Dec-10
BrightSource Energy	$1.6 billion	383MW	Baker, CA	Apr-11
NextEra Energy Resources (Genesis Solar)	$852 million (partial)	250MW	Riverside County, CA	Aug-11
NRG Solar (Agua Caliente)	$967 million	290MW	Yuma County, AZ	Aug-11
Abengoa Solar (Mojave Solar)	$1.2 billion	250MW	San Bernardino County, CA	Sep-11
Cogentrix of Alamosa	$90.6 million	30MW	Alamosa, CO	Sep-11
Exelon (Antelope Valley Solar Ranch)	$646 million	230MW	Lancanster, CA	Sep-11
Mesquite Solar 1 (Sempra Mesquite)	$331 million	170MW	Maricopa County, AZ	Sep-11
NextEra Energy Resources (Desert Sunlight)	$1.46 billion (partial)	550MW	Riverside County, CA	Sep-11
NRG Solar (California Valley Solar Ranch)	$1.23 billion	250MW	San Luis Obispo, CA	Sep-11
Prologis (Project Amp)	$1.4 billion (partial)	752MW	28 States	Sep-11
SolarReserve (Crescent Dunes)	$737 million	110MW	Nye County, NV	Sep-11

Source: DoE

“The government initially said the 1705 plan was to encourage and benefit smaller developers yet a project needed to provided in-depth environmental analysis as well as be rated by a credit agency,” Marder adds. “This is an expensive and time consuming process so it was the big developers and savvy players that were able to take advantage.” The benefits to borrowers in terms of debt pricing, often at small margins over the US government’s cost of borrowing, were substantial, but the renewables industry struggled to clearly articulate the benefits it received from the programme. Congress is now investigating the Solyndra deal and could scrutinise more guarantees, creating an even less supportive environment for renewables borrowers.

“Is the DoE out of the game after the end of the guarantees?” asks Bill Harrison, head of the renewable energy execution group at BBVA Securities. “New projects are still eligible for financing under DOE’s 1703 programme, however, there is no budget allocation to provide a credit subsidy for a new project so the borrower has to pay the credit subsidy cost.”

The 1703 track record has been so limited that few think there will be a flood of new guarantees. Brettell says the guarantees were often issued to deals with proven technologies backed by credit-worthy sponsors with long-term sales to creditworthy counterparties, cancelling the need for the guarantee. “As such, banks continue to lend to decent projects and the guarantees served more as an added extra, enabling sponsors to obtain the most favorable and optimal leverage for their projects,” he adds.

u A new set of incentives

The ending of the 1705 guarantee – together with the Department of Treasury’s 1603 cash grant programme – does not mean that sponsors are without government support. Most deals are still premised on a combination of state-level non-tariff-related inducements and the production and investment tax credits. Van’t Hof thinks that solar growth will continue to be strong, saying that state renewable portfolio standards (RPS) and state renewable energy credit programmes, coupled with existing incentives, will “continue to drive the market”.

An RPS requires utilities to source a set proportion of their demand from renewable sources – thus establishing a floor for demand from renewable sources, and will continue to support the signing of new lender-friendly PPAs – although Harrison believes the biggest issue is tax incentives. The production tax credits for wind expire at the end of this year and, if these benefits are not extended, the focus could move much more onto solar, because the ITC is not due to expire until December 2016.

“A look back at the history of renewable energy tax benefits shows that they have usually been put in place for a short timeframe, such as two to three years,” Harrison claims. “This results in a lot of development and investment activity in the first year or so, before investments tail off in the final year as the market waits to see whether there will be a renewal.”

It means solar activity is likely to remain robust, at least for a few years. Lorusso says that solar projects benefit from reliable technology, a dependable resource and simple installation and maintenance requirements, although high capital costs and low production levels are still problems. “[The projects] therefore require subsidies in the form of either tax benefits, solar production credits or above market rates paid by utilities.”

Solar, at least solar PV, has been able to survive the end of the 1705 programme. Banks are already comfortable with the uncovered risk profile of solar PV projects, particularly when they are selling power to well-rated utilities, and have robust construction contracts. Sources suggest that pricing on solar too is moving in line with other renewable markets, running between 225bp and 300bp over Libor.

Solar flair

Perhaps the best example of a project’s ability to raise uncovered debt, however, was MidAmerican’s bond financing of its Topaz solar project, which closed in February 2012; the first ever public issuance for a PV project. The $850 million bond had a coupon of 5.875% and a 27.5-year maturity and funded the first stage of the 550MW solar photovoltaic project in California. Investor appetite was strong – it was oversubscribed by more than $400 million – in large part because it reached an investment grade rating of BBB-. Topaz was an unsuccessful DoE applicant.

The deal is proof that investors are keen on holding long-term debt for solar, though its deep-pocketed sponsor managed to reduce the negative carry – bonds’ biggest disadvantage – by backstopping a second bond issue later in construction with a contingent equity commitment. Van’t Hof says that while the market has not seen many bonds and US Bank generally has not participated at that level, “these investment-grade bonds should continue to attract a lot of market attention”.

NextEra closed institutional placements for solar projects in 2011 – the Genesis and Desert Sunlight solar deals – but these were private placements that benefited from cover under the DoE’s financial institutions partnership programme, a 1705 solicitation. Topaz was a more widely distributed 144A offering and opens up a new financing avenue. Indeed, advisers claim that other solar projects are now looking at bond issues. But 144A issues still require two public ratings and millions of dollars in fees, and thus are only really viable for large projects, sponsors or portfolios.

“Bond financing has limited usefulness for solar power projects,” says CIT’s Lorusso. “The variable and unpredictable risks of a power financing must be eliminated or minimised to make a bond financing attractive. An existing operating project with fixed costs and revenues and of a reasonable scale may be attractive for a bond financing.” While 144A bonds may be rare, private placement activity could pick up. “A private placement does not have to be registered with the SEC and is typically targeted at a smaller group of investors that are interested in long-term investments, such as insurance firms and pension funds,” BBVA’s Harrison says.

Changing dynamics

CIT’s Lorusso says that the solar market is essentially divided into three segments: small-scale residential and commercial; medium-scale distributed generation for commercial/industrial; and large utility scale. “We expect to see consolidation among the small developers with the possible involvement of certain utilities,” he adds. “Also, the passive nature of solar power, combined with likely advances in technology offers it great potential for growth in new applications in the future.”

This year has already seen large-scale projects reach financial close, like Tenaska Solar Ventures’ $500 million 130MW Imperial project and LS Power’s $466 million 127MW Arlington Valley II plant, plus smaller deals for SunEdison, Invenergy, NRG Solar and Borrego Solar.

“There is a lot of uncertainty, whether regarding loan guarantees, tax breaks, environmental attributes markets or anti-dumping tariffs,” Brettell says. “I think those projects that are already being processed should be fine, but it may be a lot harder for new projects in the medium- and long-term.”