This is the second article in a two-part series on the post-ITC future of the U.S. solar industry. You can find part one, which explores trends in securitization, here.



To illustrate the importance of the post-2017 investment tax credit (ITC), we have provided the following tables to compare certain electricity offtake prices for solar with the cost of capital and required all-in installation prices without the federal ITC and with a 10 percent ITC. This table is certainly not perfect, but it provides a framework and tool set via which to examine many of the questions in this article.

So, for example, at an effective cost of capital of 7 percent and a power purchase agreement (PPA) price of $0.11 without the federal ITC, a developer would have to build a system at $1.35 per watt to break even.

The table assumes a twenty-year PPA with a 1 percent annual escalator, a California tax rate, degradation of .5 percent annually, no ITC, no additional incentives, and a production capacity ratio of 1500 kilowatt-hours annually. Importantly, there is no consideration for potential solar renewable energy credits (SRECs) or feed-in tariff income, and we do not take into account a potential step-up in basis.

Comparing this to the same chart below that factors in a 10 percent ITC, you can see that with the same cost of capital and the same offtake price, projects can still break even with a decent differential in the required all-in price. With the 10 percent ITC, for example, developers can build the same project for around 19 cents more per watt and still break even.

From another perspective, the 10 percent ITC provides developers with a ~150-basis-point advantage in their cost of capital. Put another way, the complete termination of the federal ITC (rather than a step-down) will either increase the effective cost for the industry or increase the cost of capital to the industry by 150 basis points. That is significant.

Setting Goals for the Industry



Combining this analysis with the U.S. Energy Information Agency data on current retail electricity prices, we can start to make some helpful assumptions about where all-in costs need to be in 2017 for distributed generation solar. These costs differ significantly depending on customer type (e.g., residential, commercial or utility).

The current average retail price of electricity across all sectors nationally is approximately 10 cents per kilowatt-hour. The average national retail rate for commercial users is roughly 10.3 cents per kilowatt-hour. The average national retail rate for residential customers is approximately 12.5 cents per kilowatt-hour. Although some states such as California and Hawaii have higher electricity rates, the industry on a national level is generally competing with rates that average between 8 cents and 13 cents per kilowatt-hour.





If we assume retail electricity prices will stay relatively consistent in the next five years, and assume that PPA rates will roughly correlate to these prices, we can begin to set some targets for where all-in development costs need to be. For commercial customers, average all-in prices for solar projects in 2017 will need to be between $1.60 or as low as $1.33, assuming a cost of capital between 6 percent and 8 percent. Residential installations in 2017 will need to be reduced to a cost range of $1.98 to $1.65 assuming a cost of capital between 6 percent and 8 percent.

Can the Solar Industry Scale Appropriately?



These prices may or may not comport with future projections, depending on one’s assumptions. Sol Systems reviews hundreds of projects a year on behalf of investor clients. In our experience, commercial rooftop solar systems are currently being installed at an all-in cost of $2.25 and $2.50 per watt. Small ground-mounted systems are currently being installed at $1.90 to $2.00 per watt, with larger systems over 2 megawatts being installed at $1.50 to $1.60 per watt. Residential rooftop systems are being installed at $2.90 to $3.00 per watt.

Current projections by Bloomberg estimate that these values will decline to around $2.15 per watt for residential rooftop systems and around $1.34 for large ground-mounted systems. Commercial systems will likely fall somewhere in the middle.

We take a slightly more aggressive view on pricing. But regardless of your perspective, the industry must scale considerably, and equipment costs and customer acquisition costs must come down significantly, in order for solar to truly compete nationally.

Our Key Observations and Conclusions



1. We Don’t Need $1-per-Watt Solar by 2020

The Department of Energy has set a $1-per-watt goal for all-in costs for solar. This is an aggressive and well-intended goal, but we do not think it is necessary for most projects. Even utility projects selling wholesale electricity at 8 cents per kilowatt-hour can be built for slightly more than $1 per watt and still attract capital in the 7 percent IRR range post-2017. From our estimates, commercial projects competing with retail electricity rates in many markets need to achieve all-in costs between $1.37 to $1.80 post-2017 to attract capital. Some projects will, and some will not, depending on their risks.

2. Reductions in the Cost of Capital Means More Residential and Commercial Systems

As the ITC steps down, the key drivers of all-in development costs and electricity offtake price become more important for the solar industry. Large utility-scale projects that are selling at wholesale rates (somewhere around $0.06 to $0.08 in most states) are unlikely to be able to compete -- even with a lower cost of capital and lower installation costs -- with the expanding distributed generation asset class.

For example, even if we assume utility-scale developers can access capital at 6 percent, and are able to sell electricity at $0.08, with a 10 percent ITC, projects will need to be built at around $1.20 per watt for the developer to break even. That will be challenging.

Another interesting observation is that swings in the cost of capital disproportionately impact the residential market rather than the commercial or utility solar markets because of higher retail electricity rates.

For example, a 100-basis-point drop in the cost of capital increases the required all-in pricing for a residential portfolio at a $0.125 PPA rate from $1.98 to $2.18, which equates to $0.20. An increase in the required all-in pricing is a good thing for the industry, as it means that installers and developers can potentially make more money. If you take the same 100-basis-point drop in the cost of capital from 6 percent to 5 percent for commercial projects selling electricity at a $0.10 per kilowatt-hour PPA rate, you see a slightly smaller increase of $0.16 per watt.

In sum, it appears that residential and (to a lesser degree) commercial solar (both with higher PPA rates than utility-scale) will benefit disproportionately from a reduced cost of capital -- not only because of scale, but also because the maturation of the financial landscape means that required installation costs will not significantly drop after the transition of the ITC from 30 percent to 10 percent.

3. Retail Rates Will Become More Important

As the market matures, there will likely be further differentiation in the residential and commercial markets where retail rates differ because the investment tax credit will be less influential. For example, retail electricity rates for commercial customers in Ohio in 2013 were $0.09 per kilowatt-hour, while retail electricity rates for residential customers in 2013 were $0.12 cents/kWh. Utilizing a 7 percent cost of capital, commercial solar projects will have to be developed at an all-in cost of around $1.19, while a residential system will need to be built at around $1.72. Both may be challenging.

4. SREC Programs Will Become More Important, and SRECs More Valuable

As noted, this analysis does not include additional project-level income from solar renewable energy credits (SRECs) like those available in New Jersey, Maryland, Massachusetts, Ohio, Pennsylvania or others. This analysis also does not include state or local rebates, or feed-in tariff income. If markets have low electricity rates, but also have a renewable portfolio standard, then project development will likely slow in those states (see the Ohio example above), while SREC prices will rise and will be of even greater importance in the long term.

5. The Solar Market Will Become a More Geographically Diverse Market

Securitization and the maturation of the financial market will provide the industry with a large enough boost to make solar competitive in an increasing number of places in the United States. The potential reduction to 6.5 percent blended cost of capital for the industry means a required install rate of $1.52 for commercial customers paying $0.103 cents per kilowatt-hour and $1.89 for residential customers paying $0.125 cents per kilowatt-hour.

Looking at the chart below, one can get a very simplified sense of the markets in which residential solar will continue to expand rapidly. This chart does not include the additional benefits solar gets from state-level programs like Connecticut’s ZREC program and RPS programs in the states of Massachusetts, New Jersey, Pennsylvania, Delaware, the District of Columbia and others, as well as state tax credit programs like that in North Carolina. As noted, these programs will continue to be key drivers for the industry in the future.