By: Jason Kaminsky
While everyone is talking about Nevada’s recent battles on net metering, few are discussing California’s impending electricity rate reform. Unlike net metering, shifting electricity rate structures are inherently retroactive, and will have a significant impact on the solar savings of all solar homeowners in California. Quantifying this risk factor is an important analysis for investors in distributed solar portfolios.
For those of us in the solar industry, the recent overhaul in Nevada has been a story to watch. While there was a moment when it seemed like the entire industry revolted, NV Energy and the Nevada PUC are beginning to back down from their position- at least as it pertains to what is considered by many the most offensive piece of the legislation, which is that it punitively taxes existing solar customers retroactively. (If you need additional background, the New York Times wrote a great overview article yesterday titled “Nevada’s Solar Bait-and-Switch.”).
If we turn to California for a moment, the state with the largest population of residential solar customers, most of the news coverage of late has been related to NEM 2.0 and how this will enable a stable base from which to grow the solar market in the state. (For more context here, we find the dry facts the easiest to understand – and thus refer the interested reader to yesterday’s summary by law firm WSGR.)
With that as context, there was plenty of coverage of CA Rate Reform when it was approved last July, but it seems worthwhile to loop back to those discussions since, to some extent, rate reform is a policy that is being applied retroactively (but not discussed as such.) Yes, it’s complicated, and yes, it retains the full net-metering credit, but it still has the unique distinction of impacting customers under NEM 1.0 — and thus the majority of California solar customers that have been financed to date. At the very highest level, this changes the economics for all customers of SDG&E, PG&E, and SCE in a few ways:
A flattening of the rate tiers through 2019, with the top marginal rates dropping by about a quarter. We covered this in an article for Chadbourne in July.
2-10% of the largest electricity consumers will pay a “super user” surcharge
A minimum bill of $10 per month
A mandatory shift to time-of-use rates in 2019 (with the opportunity to opt-out)
As a result of the ruling, economics for customers have changed as recently as Jan 1 of this year; the very biggest “super uses”may actually see improved economics from their solar system, while the majority will see reductions in their marginal utility rates until 2019 (and thus eroded solar economics). Customers offsetting most of their load will realize a bigger utility bill as a result of the minimum bill; PG&E explains on their website that solar customers offsetting all of their bill will see $66 / yr in additional expenses, a result of the increase in minimum bill to $10/mo from $4.50/mo. Unfortunately most homeowners won’t even realize this until they get their annual true-up in a year.
Thus, the embedded risk of an operating portfolio is not only a function of where that system is located and when it was built, but also what percentage of the customer’s load it offsets and a host of other variables.
Unfortunately, the CPUC also set the tone that fixed surcharges will be on the table for future rate proceedings, which are expected to impact NEM 1.0 customers as well if and when they are approved.
Most solar investors acknowledge that exogenous factors – including policy and utility rates – are outside of the control of their solar industry business partners, but assume that changes in homeowner economics will impact delinquencies and defaults. These risks can be managed if they can be measured, and judicious investors will need to adapt their underwriting and portfolio surveillance capabilities to address the nuances of the solar markets. Standard portfolio surveillance practices (for example, by monitoring the trustee reports to evaluate cash flows) and underwriting tools are inadequate for solar, and will be replaced by advanced analytics that allow for earlier evaluation about the risk-return of distributed solar portfolios. Solar production and homeowner economics will be known well in advance of customer non-payment; why wait for it to be a problem before you quantify the level of the risk?