In keeping with what seems to have become a semi-annual tradition, the Section 45 Renewable Energy Production Tax Credit (PTC) was resurrected at the end of 2015. The Consolidated Appropriations Act, 2016 passed in early December retroactively renewed the PTC through the end of 2014. For eligible wind energy facilities, the credit was extended through the end of 2019, and will be reduced by 20% in 2017, by 40% in 2018, and by 60% in 2019. For other eligible technologies, the credit will once again expire at the end of 2016.
The same legislation saved the Energy Investment Tax Credit (ITC), and the solar energy industry, from certain doom. Previously, the ITC for solar energy was set to reduce to 10% after December 31, 2016. The credit is now extended through the end of 2019 at the 30% level, and will step down to 26% in 2020, 22% in 2021, and 10% in 2022 and future years. Geothermal heat pumps continue to be eligible for a 10% ITC through the end of 2016, and geothermal electric systems are eligible for a 10% ITC through 2022 and future years. Utility-scale wind projects continue to be eligible to claim the ITC in lieu of the PTC as long as the PTC is in effect.
Now that the solar energy industry is no longer peering anxiously into the abyss of a world without the ITC, we can start thinking about the type of ancillary effects this extension might have. One possible impact is to accelerate the end of net metering such as we’re seeing in Nevada right now, care of NV Energy and the Nevada Public Utilities Commission. The idea is that as solar costs continue to drop and project economics remain buoyed by the ITC, the case is stronger for utilities to claim losses and expenses as a result of increasing solar adoption. The form that’s taken so far is an overhaul to net metering policies.
Solar energy systems produce at their max typically in the middle of the day when the sun is most directly incident on the modules. But typical residential consumers, who by-and-large aren’t home in the middle of the day, have relatively small home loads at these times. When systems produce excess power because of low load demand, that power is delivered back to the grid and the meter is ‘credited’ for the delivered energy during the day. Those credits are used at night when loads are typically higher in the house and the PV system is not generating. Historically, net metering rules have given a 1:1 credit for excess generation meaning every excess kWh generated is a kWh credited. Currently, this mechanism of shifting energy generation from daytime to nighttime using credits is what helps incentivize and fuel solar growth at the consumer level.
The Nevada PUC ruling in late December 2015 unanimously approved a new tariff structure for solar customers (and later modified its ruling in February 2016). The new tariff institutes a new, higher fixed monthly charge (i.e. independent of energy use) for net metering customers and implements a tiered de-escalation of the ‘credit’ these customers receive for their excess generation. The NV Energy excess energy credit, as of January 1, starts at roughly 83 – 94% of the retail energy value and ramps down every 3 years over the course of 12 years until it reaches the wholesale rate of energy. That’s just over 2.5 cents per kWh of excess generation. What this amounts to is that solar energy producers will not be credited for excess generation during the day in the way they’ve historically been used to, making pay-back periods much longer and threatening economic viability of many projects altogether.
The PUC hearings for these rulings received enormous press and included testimony from stakeholders across the energy industry such as high profile energy developer Elon Musk, SolarCity board chairman. Solar City currently holds Nevada’s largest market share for residential solar. One of the more contentious details following the rulings was the rejection of a “grandfathering” rule which sought to make current solar producers already under the old net metering tariffs, and who invested in their systems under the impression that net metering rules would not dramatically change, exempt from the new tariff changes. As a result, many PV system owners may not even recoup their investment. This kind of government bait and switch is very harmful to consumer trust and industry sustainability, and further, strains the ability to add new industry-related legislation down the road for fear about its impermanence. We’ll dive deeper into this topic in a separate blog post later this year.
But the Nevada PUC isn’t the first commission to file such rulings. Late last year the Hawaii PUC similarly voted to end net metering for Hawaii Electric Company’s (HECO) solar generating customers. The related issues behind this vote were decidedly a bit more complex than in Nevada due to the uniquely high solar penetration Hawaii is experiencing (as of October 2015, roughly 16% of HECO Companies customers were generating power with grid-connected solar the capacity of which amounted to about 35% penetration on the system peaks. The tariff change in Hawaii also differs from Nevada in the sense that the new rate for selling back excess power, while roughly half of the retail rate, is still 15 – 28 cents per kWh (due to the high wholesale energy rates in Hawaii) and likely still valuable enough to justify many PV projects. But the new rates are only applicable for the next two years making investment in solar a very difficult decision considering the 20 – 30 year life cycle of projects.
While the examples of Nevada and Hawaii are strikingly different from each other, they represent a potential sea change that could be seen in many other states as utilities continue the push to recapture revenues lost to solar generation and grid planning costs associated with preparing for higher circuit penetration rates on their lines. So far in solar’s journey, net metering has been the secret sauce for many sectors that makes the generation profile of solar make economic sense.
Without net metering, and considering the gradual plateauing trend of installation cost reductions, many are speculating that demand response and storage mechanisms, such as generation-coupled batteries, will be the future of helping to monetize the energy value of customer-sited distributed solar and maintain favorable economics and incentive for consumers to go solar. Customer-sited demand response technology is at a very young stage in its development and deployment and the costs reflect this, but looking at the trend of solar cost reductions in the last 10 years it’s easy to imagine a similar industry boom and increase of accessibility for this newer technology. With the looming threat to net metering and the enormous potential of distributed storage, we believe the next 12 months will be very telling in exactly what the future of customer-sited solar will look like for the next 10 – 20 years and beyond.
(Thanks to Heidi Alsbrooks for collaborating on this post.)