Nexamp added energy storage to two existing community solar farms in the grid-constrained ISO New England market. The Clark Road community solar farm (pictured) has 7.1 MW of solar capacity and 3 MW/6.1 MWh of storage. (Courtesy: Nexamp)
Perhaps the greatest threat to achieving ambitious renewable energy goals in the U.S. is the costly and time-consuming process of tying projects to the grid.
The Biden administration wants 5 million homes to be powered by community solar projects by 2025, a 700% increase in capacity compared to 2021. But developers say a lack of transparency and urgency around interconnection puts that goal in jeopardy.
The slog through the interconnection queue is a shared nuisance for renewable energy developers and asset owners nationwide. So it may be no surprise that interconnecting energy storage and solar+storage hybrid power plants face their own challenges.
For example, researchers from the National Renewable Energy Laboratory (NREL) published analysis that found paired solar PV and battery energy storage systems, along with a defined operating agreement between developers and utilities, could save time and money during the interconnection process.
But the analysis found two primary pain-points for renewable energy deployment: the utility-developer relationship remains tenuous, and the interconnection process is seen by many as the biggest threat to meeting climate goals.
Mark Frigo, vice president of storage at solar and storage developer Nexamp, said he frequently runs into interconnection challenges.
"Parties are dealing with this stuff commercially" through contracts rather than through regulatory requirements, Frigo told Renewable Energy World.
Recently, the Interstate Renewable Energy Council (IREC) released a toolkit to overcome what it identified as eight regulatory and technical barriers to interconnecting energy storage projects to the distribution grid.
Known as "BATRIES" (Building a Technically Reliable Interconnection Evolution for Storage), the multi-year project was supported by the Department of Energy's Solar Energy Technologies Office, the Electric Power Research Institute, Solar Energy Industries Association, California Solar & Storage Association, New Hampshire Electric Cooperative, PacifiCorp, and Shute, Mihaly & Weinberger, LLP.
The toolkit is intended to provide solutions to eight barriers facing storage interconnection:
1. Define energy storage
At a foundational level, most states' distributed energy resource (DER) interconnection processes were not designed with energy storage in mind, IREC said.
To remedy that shortcoming, interconnection procedures must clearly define: energy storage, operating schedule, operating profile, use of power control systems (PCS), and the maximum amount of output that takes into account export capacity, in constant with a DER's nameplate rating. IREC also recommended that states require utilities to update related interconnection documents and agreements, application forms, and study agreements.
2. Standardize safe and reliable export controls
Interconnection procedures should be updated to identify a list of acceptable methods that can be trusted and relied upon by both the interconnection customer and the utility. PCS should be included in the list of eligible export controls, and the limits set by the PCS should be considered as enforcing the export capacity specified in the application.
3. Don't overestimate grid impacts of non- and limited-export systems
IREC estimated that DER storage capacity could be greatly increased if utilities accurately assessed the grid impacts of non- and limited-export systems. It said that most interconnection procedures don't appropriately take into account export controls.
Once a utility verifies an applicant's export controls, eligibility for fast tracking interconnection should be based on export capacity not nameplate rating, in order to reflect the role of export controls. Applicants should be eligible for fast tracking if their inverter-based projects have a nameplate capacity that does not exceed 50 kW and an export capacity that does not exceed 25 kW, IREC said.
Additionally, separate screenings designed to distinguish between nameplate rating and export capacity may be justified.
4. How to address inadvertent export
A DER can inadvertently export power to the grid when load drops off suddenly, IREC said. So, utilities need to understand whether these inadvertent export events can impact the grid.
IREC conducted time-series analysis of both an urban and a rural feeder with exporting solar photovoltaic systems and non-exporting storage distributed along the feeders to better understand the range of worst-case impacts.
Its analysis found that feeders can host more DER capacity if the DER is export-controlled. This can be viewed as increasing the feeder’s available hosting capacity for nameplate DER or as a more efficient use of existing feeder capacity for DERs. While both the urban and rural feeder assessments supported this finding, the extent to which hosting capacity can be increased depends on feeder characteristics, as well as the location and size of the exporting DER.
5. Improve distribution grid transparency
Pre-application reports and hosting capacity analysis (HCA) can improve distribution grid transparency, IREC found, by enabling applicants to access information prior to submitting an interconnection application.
Developers can use HCA results to design their energy storage systems to avoid contributing to grid constraints by limiting charging during existing net peak load hours. HCA tools must also incorporate the latest DER queue, however, to properly inform developers. IREC said that doing so will require action by utilities, regulators, and developers.
6. Allow developers to make changes to address gid impacts
The interconnection application review process typically does not support design changes to avoid grid impacts without forfeiting their place in the queue. This is key barrier for energy storage interconnection, IREC said.
Utilities should share data behind failed interconnection screens to ensure that a customer can make needed design changes, as well as clear guidance for how a failed application could pass.
7. States should incorporate updated standards
Interconnection standards and guidance documents, such as the suite of Institute of Electrical and Electronics Engineers (IEEE) 1547 standards, play what IREC said is a crucial role in ensuring that devices are interconnected to the grid safely and reliably.
Some of the IREC recommendations include:
-Interconnection applications should be revised to ask whether or not a PCS is included in the DER system design, and if so, require its identification
-IEEE 1547 defines reference point of applicability (RPA) so that it is clear at what physical point in the configuration of the system the requirements of the standard need to be met for testing, evaluation, and commissioning
-To ensure DERs are appropriately addressed by technical requirements, any stated execution of mode or parameter change performance requirements should align with or reference IEEE 1547-2018
-The interconnection evaluation process should include an understanding of any interactions between storage system use cases and export or import limits or other functions.
8. Define rules and processes to evaluate operating schedules
Current interconnection procedures don't properly value energy storage's ability to operate according to a predetermined schedule that governs both the power imported and exported as well as the timing, IREC said.
Standards should be developed that describe the scheduling of energy storage operations, especially time-specific import and export limitations. Regulators, while limited in their ability to develop standards, can create a sense of urgency and expectation.
Because new standards typically take years to develop, IREC recommended that regulators actively develop or encourage the development of field test programs to validate the performance of a deployed system to a fixed operating schedule or profile.
At Nexamp, Mark Frigo said that storage interconnection faces challenges because procedures are based on legacy technology and equipment from 100-year-old distribution system. Utilities typically classify assets as either a generator, a transmission and distribution asset, or a load, but storage can fall into all three buckets.
Frigo said Nexamp has found workarounds through commercial solutions. Even though a storage asset provides a non-wires alternative to distribution and solves a grid resiliency issue, utilities still levy a demand charge because that's the rule. So, Nexamp sends the same bill back the other way.
Unfortunately, there's no standardization for this process and Frigo's team has to negotiate separate contracts with each individual utility.
"That's not a very elegant solution, but it works," he said. "Until the rules get really fleshed out, that's kind of what's happening behind the scenes."
