Reports of the utility death spiral have been greatly exaggerated.
That was one of the findings of a recent report entitled ‘Net Metering and Market Feedback Loops: Exploring the Impact of Retail Rate Design on Distributed PV Deployment’ from the U.S. Department of Energy's Lawrence Berkeley National Laboratory.
Naim R. Darghouth, a researcher and co-author of the report, explains that distributed solar photovoltaics have grown at a rate of 400% over the last five years. Although this is due partly to lower module prices, net-metering policies and favorable retail rates have played a large role.
The often reported problem, however, is that utilities are concerned that the growth of distributed PV will lessen their recovery of fixed costs. Some providers have responded with controversial proposed changes to net-metering incentives – invariably going downward – and others are changing their rate designs. Both can make solar less valuable to consumers and slow further PV deployment.
The report looked at the future impacted by two market feedback effects. One is fixed-cost recovery feedback – the idea that as more people switch to distributed solar, the utilities will have a shrinking base of sales, and thus, costs will be spread over that smaller group. The utility would, in turn, raise retail prices, which will then encourage more consumers to build solar.
‘You might have heard about this before,’ Darghouth says wryly. ‘It has been given the rather ominous name 'the utility death spiral.'’
The opposing feedback is the less commonly noted phenomenon of time-varying rates. As more PV is deployed, peak price periods will shift to evening hours – which reduces the savings that PV users enjoyed. That will have the opposite effect: dampening PV deployment.
In evaluating these effects, the Berkeley Lab study had two objectives: to assess how changes in the retail rate structure could impact distributed PV deployment and to quantify the impact of these two feedback dynamics.
The study authors – Darghouth, Ryan Wiser, Galen Barbose and Andrew Mills – applied the National Renewable Energy Laboratory's Solar Deployment System model. Using information from 216 solar resource regions and 2,000 electric utilities, the model considers costs, solar insolation, retail rates, state and federal incentives, adoption curves, solar-appropriate roof space, and PV system size. The researchers updated the model and added the two feedback mechanisms of fixed-cost recovery and time-varying rates.
The researchers came up with eight rate design and PV compensation scenarios, which are as follows:
- A net-metering scenario that applied a reference mix of flat rates, time-varying rates and demand charges for residential and commercial customers. In this scenario, PV distributed generation deployment increases to approximately 157 GW by 2050;
- One fixed-charge, net-metering scenario stipulated a reference mix of rates with residential rates adjusted to a $10 monthly charge. The charge was somewhat damaging to distributed PV deployment and would reduce the total to approximately 130 GW;
- Another fixed-charge, net-metering scenario applied a reference mix of rates with residential rates adjusted to a $50 monthly charge. This higher charge was even more damaging and was projected to result in a total of less than 75 GW of distributed PV deployment;
- A flat, all-volumetric rate with a net-metering scenario incorporated all residential and commercial customers on flat rates. This option promised a more favorable deployment of just over 157 GW;
- A time-varying rate with net metering offered to all residential and commercial customers was expected to increase deployment in the near term but then would drop off, resulting in less than 125 GW by 2050;
- A partial net-metering scenario involved a reference mix of retail rates with consumers compensated for the PV generation that they export to the grid at avoided-cost rates, which are lower than retail rates. This would decrease deployment to just over 100 GW by 2050;
- A lower feed-in tariff (FIT) scenario stipulated that all PV generation was compensated at $0.07/kWh. According to the study, this would decrease deployment to less than 50 GW by 2050; and
- A higher FIT scenario modeled that all PV generation was compensated at $0.15/kWh. This FIT applied a value of a solar tariff that would result in the deployment of at least 157 GW if the tariff exceeded compensation from retail rates.
‘These are not meant to be exhaustive,’ Darghouth says. ‘These are a subset of the possible scenarios.’
The report also looked at state-level results. Fixed charges decrease deployment in all states, and the amounts vary slightly among states. Flat rates modestly increase deployment in most states, and switching all customers to time-varying rates decreases deployment in 75% of states. Partial net-metering reduces deployment in all states, but the amount depends on the relationship between retail rate compensation and avoided costs. Changing from net metering to FITs would vary depending on how the tariff compares to retail rate compensation.
Nationally, the two feedback effects would tend to offset each other, and the combined effect would be a modest increase in solar deployment. By 2030, the effect of changes in fixed-cost recovery plus the switch to time-varying rates would contribute to an increase in distributed PV of about 0.9%. By 2050, the increase would total about 2.1%. If there were only fixed-cost recovery, PV deployment would increase 8%. If there were only the switch to time-varying rates, PV deployment would decrease 5%.
Today, Darghouth says, most residential customers pay flat rates. Without the feedback, PV deployment would increase 9% through 2050. Most commercial customers pay time-varying rates for which PV deployment would decrease 15% without feedback.
‘Policymakers are going to need to weigh these impacts when making rate design decisions,’ Darghouth says, adding that future research might look at storage and its impact on possible scenarios.
Nora Caley is a Denver-based freelance writer.