Nothing is likely to hold back the rise of solar, so utilities and grid operators across the country are looking for ways to protect the grid from new threats that come with high solar penetration.
Solar photovoltaic capacity roughly tripled between 2011 and 2013. About 140,000 grid-connected distributed PV systems were added in the U.S. in 2013, bringing the cumulative total to 475,000. Forecasts project another doubling of the growth rate by the end of 2016, according to the report Utility Strategies for Influencing Locational Deployment of Distributed Solar from the Solar Electric Power Association (SEPA) and the Electric Power Research Institute (EPRI).
With high penetrations of solar on some distribution circuits and rising levels on many others, “electric utilities are increasingly being asked to develop grid planning and management strategies that uphold system reliability and safety standards without limiting the pace of solar resource expansion,” the report said.
The three broad pathways for utility-solar interactions are in rates that value (1) its energy, capacity, and ancillary services, (2) its peak and off-peak generation, and/or (3) its locational flexibility, according to a paper from the Rocky Mountain Institute eLab.
Today, there is only significant concern in Hawaii and parts of California IOU territories. But grid planners in Massachusetts and New Jersey are formulating strategies to deal with exponential growth, according to another paper from the Interstate Renewable Energy Council (IREC). And planners at New York’s ConEd are looking at distribution level impacts, the SEPA paper reports.
“We started from the premise that distributed solar installations are built where the consumers are or where the solar industry markets,” said SEPA Research Director and report co-author Mike Taylor. “Consumers and the solar industry are going to put solar where they want to, but there is an influencing opportunity for utilities.”
6 routes to better solar siting
The SEPA/EPRI paper describes six ways for utilities to “get ahead of the curve” and “send a market signal that some areas are easier for interconnection,” Taylor said.
The most common is an information exchange. High solar penetration areas tend to have the best demographics and the least obstructions. They also tend to be where the interconnection costs are highest and the waits for approvals are longest. Maps showing these areas, as well as low solar penetration but high electricity demand areas, are already pointing installers in California, Hawaii, and the Northeast to new markets. But, they are still not “optimized” or “widely in use,” Taylor said.
Penetration screens can protect systems’ power quality and minimize the risks of unintentional islanding, voltage deviations, and protection miscoordination on overloaded distribution circuits, according to IREC. But “they do not provide much guidance regarding the ability of the local distribution system to accommodate a specific proposed generator at a specific point of interconnection.”
Targeted interconnection processes might do that, the SEPA paper proposes. “The signal now is, if you are in a high penetration area, it is going to take longer or cost more, or both, to interconnect,” Taylor said. “Utilities could flip that by guaranteeing a lower cost or shorter time-line. It would be promoting the ease of low penetration.”
Utilities could also offer incentives “for locating in low penetration areas or in high demand areas where solar could help relieve congestion,” Taylor said. An in-house cost-benefit analysis might reveal opportunity. Or a utility might conclude that if processing a rooftop solar interconnection is significantly faster and cheaper in low penetration areas, “why not offer half or more of the difference as an incentive?”
That is especially true where interconnect applications in high penetration areas trigger costly grid studies or expensive infrastructure upgrades.
Utilities also can exert price leverage on interconnection costs. This could be a useful tool where “incentive” is synonymous with “subsidy” and “tax” as “politically untenable or dirty words,” Taylor said.
The solar industry would fight an increased interconnection cost, Taylor said. But it might trade that for new incentives, which ratepayer advocates or utilities would likely oppose. “In one place, the best approach might be an incentive. In another, it might be better to raise the cost,” Taylor said. “It’s a political calculus.”
Where it is politically or economically viable, a dedicated tariff could be offered for solar-generated power from low penetration locations. “It is similar to a value of solar tariff or a feed-in tariff or a reverse auction mechanism-determined rate—a sweetener for sending solar onto the grid." Taylor said.
Finally, Taylor said, there could be “targeted distribution infrastructure upgrades and cost allocations.”
Where there is high solar penetration, utilities often must do costly and time-consuming feeder system evaluations before greenlighting new installations. Evaluations often call for upgraded distribution system infrastructure equipment like transformers, advanced inverters, capacitor banks, static VAR compensators, line regulators, and/or load tap changers to manage two-direction power flows and system-threatening frequency and voltage fluctuations.
To avoid such costs, “they just shut down solar,” Taylor said. “Or they may shut down everything above a certain system size. Or they may allow the interconnection but whoever triggers the evaluation has to pay for the study and the upgrade.”
The complete distribution system renovation needed for the new emerging smart grid and distributed energy reality will be costly and most utilities remain reluctant to undertake it, Taylor added.
But the costs for solar could be allocated at the distribution system level across all the beneficiaries, Taylor said. “This idea is very theoretical and out of the box and we are interested to see how utilities and the solar industry react to it.”
A utility could distribute the costs for the study and upgrade among all applicants for new solar builds. Or the solar industry could fund them and own franchise rights on that feeder system. Either way, utility ratepayers don’t bear the cost.
“Since solar customers are causing the need for the upgrade, maybe the solar industry would want to pay for it,” Taylor said. “They would have to run the numbers to see if it is worth the cost of upgrading for the additional business it would get in that already highly penetrated area, relative to going to a low penetration area.”
Such a cost allocation scheme might require an update of the current regulatory rules on distribution system management, Taylor added, but it could also make things like crowdfunding and community solar more workable.
What about a distribution system operator?
The SEPA proposals are conceptually sound, James Tong, vice president of strategy and government affairs at solar third-party finance company Clean Power Finance, told Utility Dive. But, a revised regulatory construct should also create an independent third-party to guarantee that decisions about the distribution system are transparent and balanced.
Tong is the co-author, with former FERC Chair Jon Wellinghoff, of a call for an independent distribution system operator (IDSO). “The whole idea of an IDSO comes from the need for a neutral arbiter,” he said.
From the solar industry’s point of view, utilities have significant leeway to influence outcomes, Tong explained. "Utilities could identify low penetration by grid needs," he said. "But if you’re a utility, would you rather meet those needs with customer owned assets or monopoly owned assets? You’re incentivized to do the latter."
A neutral IDSO may not be the perfect solution, Tong said, “but it reduces tension.”
With SEPA’s tariff proposal, customers might object to rates that differ by location, and the cost allocation idea raises “broader philosophical issues” between utilities and the renewables industries, Tong said.
“If clean energy is just an individual choice, it makes sense to charge individuals,” Tong said. “But if we as a society agree that cleaner energy is a public goal, then to say the solar customer is the one creating the cost for the grid and should pick up the tab is unfair.”
In the many states with policies dedicated to new renewables, private capital is supporting societal goals. “Where everybody benefits, everyone should pay,” Tong said.
“It’s also unfair to force rooftop solar customers to pay for grid upgrades when many of them are likely needed regardless of distributed solar,” he added. “Studies show outages are extremely expensive in the U.S., costing an estimated $18 billion to $33 billion per year. A more resilient and robust grid benefits everybody.”