Introduction to the ‘Business side’ of Solar: Securitization

by Guest Contributor Travis Lowder.

Originally published on NREL.

The U.S. solar industry is an $11.5 billion market with over 360,000 systems in place [1]. Since 2008, solar capacity additions have exhibited a compound annual growth rate of over 50%, with strong gains anticipated in the coming years.

As the industry grows, it is exploring alternative financing options outside of its traditional funding sources (namely debt, tax equity, and cash equity). Securitization—the process of structuring an illiquid asset into a liquid and tradable one (i.e., a security)—represents an emerging opportunity for the distributed solar market in particular. Access to the capital markets through security issuance can assist the solar market in achieving greater liquidity among investors and an advantageous cost of capital relative to traditional funding sources (namely debt, tax equity, and sponsor equity). Liquidity and lower financing rates have both proven somewhat elusive given solar’s current reliance on project financing and tax equity structures.

A new report from the National Renewable Energy Laboratory, The Potential of Securitization in Solar PV Finance, explores this capital market finance option for PV assets. The report provides a general overview of the securitization process (see Figure 1), the actors involved, the benefits (and risks), and the rationale for pursuing this kind of funding strategy.

The report also offers a high-level analysis of the volumes of solar deployment that could be supported given a single securities offering [2]. It posits that a single $100 million securitization transaction (not accounting for fees, overcollateralization, and other structuring/transactional costs) could potentially support 72 MW of residential solar assets, or 100 MW of commercial, or 133 MW of large commercial and industrial (C&I) projects [2]. See Table 1.

Solar projects will likely be pooled into different types of securities based on several factors, including: project size; the type of cash flows securitized; and the entity that will issue the securities. The report broadly identifies three classes of securities that, upon preliminary analysis, would be applicable to the solar industry: asset-backed securities (ABS), collateralized loan obligations (CLOs), and project bonds. ABS instruments are typically used in the securitization of cash flows in the consumer finance sector (e.g., credit cards, auto loans, and student loans); CLOs are securitizations of loan payments and are commonly used to alleviate banks’ balance sheets; and project bonds are debt instruments that have been issued against project-level cash flows [2].

While there are several nuances that would determine which instrument would be applicable in a given solar project or portfolio of projects (such as a tax equity fund for residential assets), the report offers the following general classification:

  • ABS securitizations will be widely applicable to the residential solar sector, as the metrics for evaluating these instruments (e.g., FICO scores) are similar to those for evaluating the credit quality of residential solar assets.
  • CLO securitizations will be more applicable to the commercial sector. This is because the cash-flow pools will require fewer underlying systems to reach the same dollar volume as a residential. Fewer systems mean fewer offtakers, which in turn mean less portfolio diversity. And, without a diversity of offtakers behind the cash flows in the pool, there is greater focus on the creditworthiness of each offtaker. Typically, CLOs are the appropriate securitization structure to manage this kind of corporate risk.
  • Project bonds are debt securities issued against project-level cash flows and have been used to finance utility-scale projects. A bond obligation can look similar to a non-recourse loan on a balance sheet, though it has the distinct advantage of tapping into funding sources outside of the commercial lending market and at larger sums. In the last two years, project bonds have been issued to finance both the construction (MidAmerican’s Topaz and Solar Star projects) and takeout (NextEra’s St. Clair) of large-scale solar projects [2].

Looking Forward

Institutional investors, such as pension and insurance funds, will typically allocate about 5% of their assets for “alternative investments,” such as a renewable energy project investment. Courting these entities will therefore require solar to transcend the “alternative” category and offer itself as a bankable, standardized, and transparent investment product. Institutional investors allocate as much as 40% of their assets to these types of investments, which, by some estimates, could amount to some $37 trillion at the outset of 2014 [3,4].

Even if the PV industry posts half of the annual growth rate that it has from 2008 – 2013, this would amount to about 20 GW of capacity additions by the time the 30% investment tax credit expires in 2017. At an average of $3/W across market segments, 20 GW of solar PV represents $60 billion worth of assets, a third to a half of which would likely have securitizable cash streams flowing through them. A $20 –30 billion base of long-dated assets, made liquid through securitization and investment grade through continued understanding of the credit risk, would be a strong draw for many of the investors in that conventional category.


[1] Renewable Energy Finance, Solar Securitization: A Status Report (Fact Sheet). (2013). Golden, CO: National Renewable Energy Laboratory. Accessed January 31, 2014:

[2] Lowder, T.; Mendelsohn, M. (2013). The Potential of Securitization in Solar PV Finance. Golden, CO: National Renewable Energy Laboratory. Accessed January 23, 2014:

[3] Turner, G.; et al. (2013). Profiling the Risks in Solar and Wind: A Case for New Risk Management Approaches in the Renewable Energy Sector. Swiss Re and Bloomberg New Energy Finance. Accessed January 23, 2014:

[4] TheCityUK. (September 2013). Fund Management 2013. TheCityUK. Accessed January 23, 2014:

This article, Solar Securitization Intro, is syndicated from Clean Technica and is posted here with permission.

‘Soft Costs’ Now the Largest Cost of U.S. Solar Installations

by Joshua S Hill.

U.S. Department of  Energy (DoE)  National Renewable Energy Laboratory (NREL) cost of solar chart.
U.S. Department of Energy (DoE) National Renewable Energy Laboratory (NREL) cost of solar chart.

Two reports published by the US Energy Department’s National Renewable Energy Laboratory (NREL) show that soft costs — such as financing and other non-hardware costs — now make up the largest section of solar installation costs, coming in at 64% of the total price for residential solar energy systems.

The two reports – ”Benchmarking Non-Hardware Balance-of-System (Soft) Costs for U.S. Photovoltaic Systems, Using a Bottom-up Approach and Installer Survey – Second Edition” and ”Financing, Overhead, and Profit: An In-depth Discussion of Costs Associated with Third-party Financing of Residential and Commercial Photovoltaic Systems” — combine to show just how soft costs are becoming an increasingly more important part of solar installations.

“The two new reports, along with previous reports, provide a comprehensive look at the full cost of installing solar, while delineating and quantifying the various contributors to that final cost,” NREL analyst Barry Friedman said.

The first report showed that in the first half of 2012 soft costs represented the majority of all costs — 64% of the total price for a residential system, up from 50% as identified in a previous report conducted in 2012, and similarly high percentages for small and larger commercial installations.

Residential soft cost categories for the first (2010 data) and second (2012 data) editions of the benchmarking study. For the first edition of the benchmarking study, 2010 “all other soft costs” had not been differentiated. For the second edition, we quantified five sub-categories within this broader category.

The second report focused on the five sub-categories identified in the previous report only as ‘other soft costs’ — namely, transaction costs, indirect corporate costs, installer/developer profit, supply chain costs, and sales tax.

This article, NREL: Soft Costs Now Largest Piece Of Solar Installation Costs, is syndicated from Clean Technica and is posted here with permission.

About the Author

Joshua S. HillJoshua S Hill I’m a Christian, a nerd, a geek, a liberal left-winger, and believe that we’re pretty quickly directing planet-Earth into hell in a handbasket! I work as Associate Editor for the Important Media Network and write for CleanTechnica and Planetsave. I also write for Fantasy Book Review (, Amazing Stories, the Stabley Times and Medium.   I love words with a passion, both creating them and reading them.

$5.7 Trillion Worth of Renewables With No Added Grid Costs

by Giles Parkinson

Originally published on RenewEconomy

Analysts at Citi have produced a detailed report which suggests another 900 gigawatts of solar installations, and another 1,500GW of wind farms could be installed around the world with little added cost to electricity grids. This amounts to an investment opportunity of $US5.7 trillion – and it only relates to those investments that can be achieved without much added expense to existing infrastructure.

The estimate is based on Citi’s assessment that most electricity markets could – on average – integrate 20 per cent of wind generation with little problem, and around 10 per cent of solar – although some generation assets are likely to find themselves stranded because they are being priced out of the market.

The wind penetration assessment, by Citi’s own admission, is conservative, because many studies say 30 per cent is possible and countries such as Denmark have already gone well above that. But Citi says it is a global average based on the fact that many developing countries may struggle to integrate more without added expense.

It cites coal and nuclear as being victims of increased wind generation, because it tends to eat into baseload demand. It says solar is most likely to sideline peaking gas generators because it is the most cost-effective way to address peak demand. Gas is either already too expensive in many countries, and even in the areas like the US where gas is now cheap, utilities are investing in solar anyway because they are wary of the risk of future gas price rises, and coal and nuclear cannot meet that demand.

To put Citi’s forecast is some context, there is currently just more than 100GW of solar installed in the world, and around 282GW of wind energy. Bloomberg New Energy Finance today issued a new forecast saying it expects about 37MW of solar to be installed this year, and  about 36GW of wind.

It also comes as a new report from the National Energy Renewable Laboratory in the US releases a study that says 33 per cent wind and solar penetration in the western grid of the US would save $7.5 billion in fuel costs, but would add little in added costs of “spinning reserve” or “cycling – dismissing one of the major objections of wind energy opponents, and lending some support to Citi’s contention that this amount of variable renewables can be installed with little added cost. You can read Eric Wesoff’s excellent report on that analysis here.

Citi notes that its 30 per cent assessment is not a blanket rule for all markets, because of different geographies and weather conditions. For instance, it notes that solar could account easily for 10 per cent of output for countries closer to the equator with better solar resources, but just 5 per cent for countries where solar produces little in winter. (Many analysts would content that solar could do a lot more, and will).

Citi cites Germany as an example of a country that might have gone “too far” too quickly, noting that it will likely have to change the structure of its markets to ensure that some form of “capacity” payments are made to ensure that enough fossil fuel generators remain in production.

The biggest markets for solar and wind energy investment are China and the US, which is natural considering they have the biggest economies and biggest electricity grids, with greater capacity to absorb variable renewables.

Using 2013 $ prices, Citi sees a near $1 trillion market in the US (consisting of $US366bn solar and $US560bn wind) and a $US1.5 trillion market in China ($US542bn solar and $US906bn wind).

But it suggests the most interesting regions for growth are areas such as Latin America, Japan and India, which all have “decent sized” electricity demand, a small installation base of renewables and a sizeable opportunity to grow significantly.

Japan in particular is an extremely attractive location for renewables after the country closed most of its nuclear fleet and now is scrambling for affordable energy while it burns imported gas at $16/mmbtu (vs. $3.5 in the US). The country has shown its support for renewables and in particular solar through the implementation of generous feed-in tariffs for renewables generators.

On solar, Citi says Japan and Latin America are the only markets where utility-scale solar is clearly competitive at a wholesale level.

In areas with strong solar resources, such as western US.  the region studies by NREL – it says utility-scale solar will compete with peaking gas – even though gas prices are low in the US. Utilities want to hedge themselves against the risk of volatile fuel prices.

The real game changer is being felt at residential level, where solar is already at socket parity in many nations – meaning it is cheaper than retail prices. It notes that in Australia, households are facing the choice between (a) buying electricity from the socket at a rate of $30ct/kWh or (b) producing solar electricity at a cost of $18.5ct/kWh. “By installing solar panels a household would save $11.5ct for every kWh consumed from solar,” it notes. (We have more on the Australia story here, and see also Warwick Johnston’s latest market update).

As for wind, Citi says onshore wind cost is only attractive as an investment on an unsubsidised basis in Latin America (Brazil), the UK and Canada, although Argentina and Italy will follow suit by 2020.

However, there are secondary reasons why utilities might prefer wind over baseload fuels such as coal and nuclear: “Coal is environmentally questionable, and similar concerns combined with uncertainty over costs and remuneration make nuclear hard to build in many markets.” Citi writes.

“In a meaningful comparison between coal and wind CO2 costs should arguably be included in the analysis. Unfortunately, the economic costs are not captured by current carbon markets and hence these carbon prices do not provide a good indicator for the true economic cost of carbon emissions on the environment.”

It says nuclear reactors do not emit any CO2, but pose an investment risk because the cost of generation is very sensitive to discount rates due to the scale of back-end liabilities and the cost of capital, which is pricing in the low visibility of what future costs nuclear might impose on society.

Citi says onshore/offshore wind shows limited seasonal variability and its generation profile is much more similar to baseload generation than solar. “For these reasons we do not consider wind as a peak shaving resource but rather as a substitute to baseload capacity such as coal and nuclear.”

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This article, $5.7 Trillion Worth of Renewables With No Added Grid Costs, is syndicated from Clean Technica and is posted here with permission.

About the Author

Giles Parkinson is the founding editor of, an Australian-based website that provides news and analysis on cleantech, carbon, and climate issues. Giles is based in Sydney and is watching the (slow, but quickening) transformation of Australia’s energy grid with great interest.

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