The imminence of high penetrations of rooftop solar is giving U.S. electric utilities anxiety — and with good reason. But most utilities today have less than 1% rooftop solar penetration on their grids. They can see the challenge of operating their grid with high penetrations of rooftop solar coming on the horizon, but it’s not here for many — yet.
But in the sunny area around San Diego where utility San Diego Gas & Electric (SDG&E) has its service territory, it’s an entirely different story.
SDG&E could count approximately 39,000 rooftop solar installations in its service territory at the beginning of July, Tom Bialek, the utility’s chief engineer, told Utility Dive in an interview. That’s a total 270 MW of nameplate capacity — the equivalent of 5.9% of SDG&E’s 4,600 MW peak load.
“How we look at the world is changing,” Bialek explained at the Grid Edge conference in late June. “Customers are changing how we view the world just because they are making choices. They are making choices to put solar on the roof; they are making choices to buy an electric vehicle.”
But consumers do not come to the utility when they’re making these choices. That’s not just a problem for the utility business model — it’s also a problem for the utility’s system operations. As customers continue to make the choices they want, SDG&E needs to maintain reliable service, match load with generation and keep voltage levels within limits, according to Bialek.
Bialek estimates the number of rooftop solar installation in SDG&E’s territory to double by the end of 2015. That would equal 540 MW of rooftop solar at peak output — or nearly 12% of SDG&E’s peak load today. In other words, the challenge presented by high penetrations of rooftop solar is not getting any easier.
The challenges
Bialek told Utility Dive that SDG&E is experiencing a host of operational issues as a result of DG solar penetration, including:
- Reverse power flow
- Significant voltage variability
- High voltage on circuits and secondary services with a commensurate reduction in conservation voltage reduction compliant circuits
- Reduced switching flexibility
- Lack of visibility of actual circuit loads due to net energy metering (NEM)
- Increased O&M for voltage regulation equipment
- Distribution planning study issues
- Adoption of nascent power electronic devices
- Aggregation issues at the transmission level
Perhaps the biggest operational problem — and certainly one that has garnered the most attention in the utility industry — is the Duck Curve.
Solar reaches peak output in the afternoon between 2 p.m. and 9 p.m., according to James Avery, senior vice president of power supply at SDG&E parent company Sempra Energy. Solar’s exact peak in SDG&E’s service territory occurs between 5 p.m. and 6 p.m. — when the load on SDG&E’s system is not particularly high.
But “as the sun then begins to do down, these installations will stop producing power,” Bialek told Utility Dive. That drop in solar output “coincides with high customer demand in the evening, as people come home from work and turn on their TVs and appliances.”
SDG&E customers are naturally interested in installing rooftop solar because “they can save money,” Ted Reguly, SDG&E’s director of customer programs and projects, told Utility Dive in a recent interview. “They can go out today, buy rooftop solar or lease it, and save money from day one.”
But when a customer puts solar on the rooftop, “[it] avoids energy, but it doesn’t do anything to serve the capacity needs on our grid,” Avery said. Customers are incented to use solar to avoid utility system consumption — and thus reduce their own energy costs — but they are inadvertently “making it harder and harder for us to operate the grid.”
The solutions
“In order to [operate the system with high penetrations of rooftop solar], we need flexible systems,” Bialek said. “It’s not going to be this one big monolithic system that sits back in our mission control center.”
Bialek told Utility Dive there are multiple potential solutions that SDG&E is looking at to address the issues presented by high penetrations of rooftop solar:
- Circuit modifications including monitoring and ensuring resource adequacy and voltage regulation
- Demand response including potentially slower dP/dt events
- Four quadrant control through utility-owned dynamic VAR devices, utility-owned energy storage, and customer-owned inverters and storage
- Regulatory/standards changes including Rule 21 updates to require advanced inverter functionality in California and the implementation of Draft IEEE 1547.8
“Today, of all the solutions, energy storage provides the maximum flexibility and results at the highest cost,” Bialek said. “Next in the toolkit is the installation of dynamic VAr devices followed by traditional capacity upgrades. These solutions have worked well but some are nascent and expensive.”
SDG&E is pushing for the adoption of smart inverters for all new DG solar installations “to counter the intermittency issues at the source,” Bialek added. “This will allow the PV inverters to automatically mitigate the issues they create as opposed to having SDG&E install additional equipment after the fact.”
The future
As SDG&E seeks to become more customer-centric and enable the choices their customers want, the utility must embrace the increasingly complex challenge of operating the grid with quickly growing penetrations of rooftop solar.
“The region will need more flexible power sources that can react quickly to meet demand and replace all these panels going offline, including robust customer conservation, more energy storage and fast ramping natural gas ‘peaker’ plants,” Bialek said.
But it’s not just utilities in high solar growth regions such as California and Hawaii that need to pay attention to what SDG&E is doing.
“What we are experiencing now are things you will experience in the future,” Avery said. “If you do not get ahead of these issues today, the problems you will face in the future are the same ones we are facing in California right now.”
