Utilities own a wide range of devices on the transmission and distribution grid to manage power quality. The technologies are likely unfamiliar to the average homeowner: capacitor banks, load tap changers, shunt reactors and synchrophasers are just a few.
But there’s another power control device that may be much more familiar to the hundreds of thousands of American homeowners with solar on their roofs: inverters.
Should utilities own those too?
As solar’s gateway to the grid, inverters are extremely important. But they’ve historically played a relatively simple role. For the vast majority of grid-tied applications in the U.S., inverters convert DC electricity into AC and feed it through a circuit breaker for self-consumption. Any excess solar electricity is pushed back onto the distribution grid and the homeowner is credited through net metering.
However, the role of the inverter is changing. The emergence of new “smart” designs combined with increasing worries about the financial and technical impact of distributed PV on the grid are pushing inverters to the center of conversations around the future of solar.
Aside from utility-scale projects, the inverter is almost always on the customer side of the electric meter in the U.S. Some in the solar and utility business are now asking if the inverter should be like any other device a utility operates to manage power quality. As solar starts saturating the distribution network, should the utility handle that asset and use it to better control how PV — and possibly storage — interact with the grid?
Answering that question raises all kinds of thorny scenarios about ownership models and how to monetize inverter services. It also opens up potential opportunities for lowering the installed cost of systems, engaging utilities in PV deployment and smoothing out the electricity system when lots of solar gets installed in concentrated areas.
The idea is still very new, but it’s getting more attention within the power sector.
The Solar Electric Power Association (SEPA), a U.S. trade group focused on utility involvement in solar, recently issued a report laying out the opportunities for putting residential and commercial inverters on the power company’s side of the meter. Although the business case will vary from utility to utility, SEPA argues that there are compelling technical and financial cases for such a model across the industry.
“Recognizing the inverter as a distribution system asset, extending utility ownership to the inverter, and leveraging utility operational control capabilities are logical steps in managing the stability and reliability of the electric grid for all customers,” wrote Ted Davidovich and John Sterling in the report.
By using inverters for reactive power, utilities could enhance control of the distribution system through equipment already being installed on homes and businesses, potentially lowering expenditures on other grid equipment. Utility ownership could also lower the installed cost of a solar system for a customer by 10 percent to 15 percent and improve reliability by adding inverter maintenance into normal grid service operations, argues SEPA.
“Strong operational arguments can be made for this shift; indeed, as penetration of distributed solar increases across the country, centralized operational visibility and control will become imperative in future protocols that ensure reliable operation of the grid,” wrote the authors.
So far, however, those arguing the case are limited to think tanks and lone advocates within utilities.
Jim White, a senior conservation engineer with the Chelan County Public Utility District in Washington state, attempted to pitch his municipal utility on an inverter ownership model. After hearing about the idea from Outback Power co-founder Christopher Freitas, White created one of the first basic plans and demonstration projects for “utility-grade” solar inverters.
But the plan hasn’t gotten much traction. Because there’s so much cheap hydropower in the region, executives have not been supportive of solar, said White. So far, he’s built one prototype.
“Internal management doesn’t want to see this go forward. But we’re still trying to get some demonstration projects running,” he said in an interview.
White also wants to bring the idea to other utilities. He’s currently writing a white paper for the Electric Power Research Institute that outlines how utility-grade solar inverters could be installed and operated.
The structure as proposed by White is relatively simple. After a homeowner gets a solar system installed, they would contact the power company to connect an inverter to the grid side of their meter, possibly installed in the meter itself. Utilities would then purchase all of the electricity from the array, compensating the homeowner either through a bill credit or by simply sending a check. It might look like a hybrid German-American model, with utilities buying all the electricity produced as they would under a feed-in tariff, but crediting the homeowner as if the system were net metered.
The payment scheme could be flexible, but the concept is roughly the same: “In a way, it’s really the same model they have for the generation from any plant,” said White. “They are buying fuel and converting that fuel, using the same mechanism they have for purchasing anything.”
Utilities could ratebase the inverters and get compensated by regulators for purchasing and maintaining the equipment. They could also prevent losses in retail sales by metering generation and consumption separately. More importantly, utilities would be able to directly service and control the inverters, using them to balance the grid when needed. They could also lease batteries to homeowners for extra grid support or backup.
White outlines the benefits in his upcoming paper for EPRI: “Treating the AC-to-DC inverter as just another transformer should be relatively easy for utilities to incorporate into their existing business systems. Owning the inverter also provides the utilities greater control over the grid-connected variable resource, and the ability to receive full cost recovery on a new generating asset.”
Chris Cook, a principal at Solar Grid Storage, has been working on a similar idea for hybrid solar-storage systems. Under the Solar Grid Storage plan, customers would still net-meter their systems. The utility would charge for every kilowatt-hour of DC electricity they convert into AC, while also charging a fee for operating a battery.
“It may not be as much revenue as selling a full kilowatt-hour to said customer, but it ensures the utility is still earning some revenue on every kilowatt-hour…which, in theory, gives them a reason to exist [in the] long term,” said Cook in an email.
Assuming the price for the service is right, such a model might give utilities a competitive advantage. But is it really as simple as it seems on paper?
“It sounds really nice. But there are a lot of complications that need to be worked out,” said MJ Shiao, the solar director at GTM Research. “We still don’t understand how a lot of this will work.”
The obstacles are numerous. Because utility-grade inverters are still just a concept and have not been considered in a formal regulatory process, there are many unanswered questions about customer billing, interconnection standards, payback methods and the ability of utilities to manage tens of thousands of inverters.
Shiao puts those considerations into two categories: compensation and implementation.
The compensation piece applies to both investors and homeowners. Commercial and residential customers with inverters providing grid support could be paid for ancillary services. Those payments could help support payback of the DC solar system. But they could also complicate financing as well.
“If the inverter is asked to perform some kind of service, or even curtail generation, you could imagine that impacting the payback,” said Shiao.
Power companies would also need to be careful about overpricing inverter or battery services.
“Utilities could be successful here as long as they don’t price the hell out of the service,” said Cook of Solar Grid Storage. “If it is comparable to what a turnkey solar service might have been, they will succeed. If they want to charge monopoly rents, few to no one will buy the utility service.”
Implementation could also be a challenge. Theoretically, a utility could deploy the same workforce used for managing meters to install and maintain inverters. But will customers trust the utility? Will the process be as fast and seamless as it is under a solar installer today? And will solar installers be willing to give up inverter services? It’s nearly impossible to answer those questions today with no real world experience.
There are many technical considerations as well. Regulators, utilities and inverter manufacturers would need to agree on technical standards for smart inverters. California is currently considering such rules under its smart inverter working group; however, that process does not factor in utility ownership of the inverters. And with tens or hundreds of thousands of distributed systems under management, utilities would have to create a process for managing and acting on a vast new source of data.
For now, these scenarios are limited to academic discussions and proposals in white papers. It could take another couple of years before utilities and commissioners catch on to the idea and start issuing real proposals.
Although there is little activity currently underway, SEPA believes regulatory considerations of utility inverter ownership is inevitable.
“It is a certainty that new technological developments will radically change the way utilities interact with customers in the future. As distributed solar becomes more and more economic and penetration increases, smart inverters appear to be the obvious initial opportunity for utilities to maintain and increase system reliability and performance,” concluded the authors of the SEPA report.
Photo Credit: Utility Inverter Ownership/shutterstock
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