California Pioneers New Path for Large-Scale Distributed Energy Grid Integration

Advocates for reforming the interconnection of large-scale distribution system resources, such as community solar and rooftop photovoltaic arrays at large retail stores, say efforts to remove interconnection barriers are accelerating. These resources, especially projects in the 1 MW to 5 MW range, can flexibly meet peak electricity demand without major power system upgrades. However, under current interconnection practices, the cost of increasing system hosting capacity makes many projects requiring system upgrades economically infeasible.

California leads the way in flexible interconnection

The Limited Generation Profile (LGP) option approved by the California Public Utilities Commission (CPUC) on March 24 will be the first statewide implementation of the emerging "flexible interconnection" innovation for distribution system resources. These innovations also include rooftop solar and solar-plus-storage systems owned by commercial and industrial customers, analysts and stakeholders agree.

"The LGP option allows developers to schedule export limits during periods of power system congestion to prevent overloads," said Sky Stanfield, an attorney with the Interstate Renewable Energy Council (IREC), an interconnection reform advocacy group, and a partner at Shute, Mihaly & Weinberger LLP. But she added that the losses from export curtailment will be less than the cost of upgrading the power system's hosting capacity.

Policymakers in other states, including New York, Illinois, and Colorado, are moving toward more flexible interconnection practices for these large-scale distribution system resources.

Nadav Enbar, project manager for distributed energy resource interconnection at the Electric Power Research Institute (EPRI), said flexible interconnection "pre-defines" annual curtailment percentages. He added that the "core calculation" is whether it is more economical to upgrade the system during peak hosting capacity congestion or to incur the cost of unscheduled curtailment of distribution system resource generation.

Advocates and analysts say flexible interconnection options allow projects to interconnect faster by accepting limited curtailment, which helps achieve policy goals. But they also acknowledge that the rapidly changing dynamics of U.S. distribution systems will make protecting reliability and maintaining cost predictability for developers challenging.

Interconnection cost issues

Despite a lack of validating interconnection data, stakeholders and analysts across the United States agree that anecdotal reports suggest new interconnection options for distribution system resources appear necessary.

"As distributed energy resource applications and penetration rise, more bottlenecks and longer wait times often emerge," said Mari Hernandez, regulatory program director at IREC. She added that open sources have reported distribution system interconnection backlogs in Maine, Massachusetts, Minnesota, and other states.

The California Public Advocates Office reported in April 2023 that a site-specific analysis showed "more granular LGPs" would add "considerable" generation to the state's power system.

The U.S. Department of Energy's 2021 Solar Futures Study shows U.S. distributed solar potential of up to 200 GW by 2050, but the study did not draw conclusions on interconnection issues, acknowledged Jeffrey Cook, renewable energy policy and market analysis manager at the National Renewable Energy Laboratory (NREL).

Project developers provide the strongest evidence that streamlined interconnection options are needed.

"In New York, distribution upgrade costs often double developer costs," reported Benjamin Piiru, director of interconnection strategy and policy at Nexamp, with some costs "even increasing sixfold." He added that without Illinois' flexible interconnection pilot, "we might have walked away from a project rather than paying $50 million in upgrade costs."

California's massive transmission system interconnection application backlog has affected distribution system project interconnections, added Victoria Moroney, senior manager of market development at Forefront Power. As a result, the vast majority of 1 MW to 5 MW projects are delayed, and LGP "can be a viable alternative," she said.

Utilities and advocates say the LGP option will be complex and only feasible thanks to the years of work by California's investor-owned utilities in mapping their distribution systems.

Limited Generation Profile explained

IREC's Stanfield said LGP allows developers to voluntarily schedule reductions in project generation when power system congestion is expected at their location, rather than paying for capacity upgrades. LGP is feasible because of the monthly updated, site-specific distribution system hosting capacity analysis maps from California's investor-owned utilities, Stanfield said.

Using these maps, California distributed energy resource providers "will be the first in the United States" to be able to eliminate the requirement to pay for capacity upgrades by "proposing export schedules based on system conditions," Stanfield said.

"Utilities need to ensure that the necessary power control technology can maintain developers' commitments," Stanfield acknowledged. The CPUC order delays LGP implementation until "nine months after distributed energy resource power control systems are certified under UL Standard 3141," she added.

Stanfield added that as LGP scheduling increases, changes in system load and supply could lead to new congestion points. The CPUC addresses this by allowing utilities to curtail project generation outside the LGP schedule when "persistent load drops" occur.

The CPUC order allows generation project owners to schedule two periods per day during which their generation can drop below 100% of capacity—based on distribution system capacity patterns at the specific interconnection point. If changed monthly, this would create up to 24 generation changes for projects.

Southern California Edison believes LGP helps achieve clean energy goals and protect reliability, but they add "operational complexity," said Jeffrey Monford, a spokesperson for the utility. He added that the special load-loss curtailments allowed by the CPUC order, the required UL hardware certification, and limited scheduling changes will ensure reliability.

But utilities "still need to develop systems and operational practices to implement LGP," and such complex implementation will require "clear and timely" guidance from the CPUC, Monford said.

Nexamp's Piiru said California's LGP rules "are an important first step toward flexible interconnection" and "could be a game-changer because they allow for granular calculations of project financial viability." But he added that under more flexible interconnection rules, developer decisions "might be easier because those rules set specific maximum annual curtailment percentages."

Developers, utilities, and analysts say more flexible interconnection rules are already advancing.

More flexible interconnection approaches

Most stakeholders agree that timely and cost-effective interconnection can be achieved in ways that give developers greater benefits and utilities more control. Flexible interconnection is a range of approaches that "may not always be the right choice, but does expand the options available to project developers," said Samantha Weaver, senior director of interconnection and grid integration policy at the Coalition for Community Solar Access.

California's LGP is "one end of the spectrum," while the more flexible approaches being piloted in New York, Illinois, and other states are at "the other end of the spectrum," Weaver said. Flexible interconnection requires utilities to have advanced communications and distributed energy resource management systems (DERMS) "to handle unscheduled but capped curtailments," Weaver continued. For these approaches, tariffs, curtailment rules, and caps will be important, she added.

Commonwealth Edison's flexible interconnection pilot "successfully integrated 6.75 MW of solar capacity" with only 17 curtailment events over seven months in 2022, reported David O'Dowd, a spokesperson for the utility. The pilot showed that "curtailment events and durations are not broadly predictable" and that scheduling them "would lead to unnecessary curtailments," he added.

IREC's Hernandez said DERMS-managed flexible interconnection is also valuable because most states' hosting capacity analyses, including New York's and Illinois', are insufficient for interconnection. She added that national standards are needed to determine data reporting frequency and requirements for validating data reports for interconnection decisions.

Nexamp's Piiru said upgrade cost sharing can also be tested in pilots. When multiple projects connect to the same feeder and upgrades are needed, "all developers, not just the last applicant, can share the costs," he added.

Xcel Energy's flexible interconnection pilot anticipated Colorado Senate Bill 24-218, which calls on the state's regulators and stakeholders to "modernize the energy distribution system," said its lead sponsor, Democratic state Senator Chris Hansen. The bill was signed by Colorado Governor Jared Polis on May 22.

The utility is reviewing existing policies and gathering stakeholder feedback, reported Kevin Coss, an Xcel spokesperson. It will finalize plans for a "small-scale demonstration pilot" within the "next six months" to evaluate "the policy and technical considerations needed for broader deployment," he added.

"Flexible interconnection is a tool," Senator Hansen said. "As curtailment increases in Colorado, it provides incentives for project developers to add storage options to increase the use of their generation during peak demand periods when generation is not curtailed, thereby increasing the value of projects to the system and to distributed energy resource builders and owners," he added.

Ultimately, new technologies will be needed to address the potential complexities in flexible interconnection approaches, Hansen, Xcel, and others agree.

Unresolved challenges

Solutions that work for interconnection under certain conditions may become obstacles under others. "The dynamics of power system operation make precise curtailment predictions difficult," said EPRI's Enbar. "Even if a developer interconnects at an unrestricted location with full export allowed, other interconnection projects may eventually exhaust all capacity on that feeder and require developers to pay for upgrades," he added.

But cost sharing for upgrades among developers "is not easy because their revenues will be modified," Enbar said. "Flexible interconnection can serve as an effective transitional measure while upgrade construction and cost-sharing negotiations take place," he said.

Defining "the difference between curtailment from flexible interconnection and curtailment from grid service programs like demand response" is also critical, said Karyn Boenker, chief researcher and project manager in the Electricity Infrastructure and Buildings Division at Pacific Northwest National Laboratory.

"Developers with flexible interconnection agreements may face curtailment and financial losses, while demand response programs that protect system reliability are voluntary and compensated," Boenker said. Policymakers must decide "how to differentiate compensation for the two," and regulators must decide "whether ratepayers or developers pay" for the new technologies required, she added.

But the "current norm" of relying on system upgrades eliminates "potential innovations," said NREL's Cook. "Interconnection processes can be tailored, and best practices will vary based on distributed energy resource penetration levels, utility, customer, and developer characteristics and preferences, power system attributes, and other factors," he added.

"There may be complex puzzles to solve, but streamlined distribution system interconnection can save billions of dollars, reduce emissions, and greatly improve reliability," responded Colorado Senator Hansen.