On March 21, 2024, the California Public Utilities Commission issued a major decision allowing renewable energy systems to be approved to interconnect to the electric grid by adhering to schedules that will limit how much energy they send to the grid at different times, based on identified grid constraints. These schedules, called Limited Generation Profiles or LGPs, will be designed to minimize a renewable energy project’s impacts on the electric grid, thereby avoiding the need for costly infrastructure upgrades that might otherwise prevent a project from moving forward. The decision is made possible by California’s requirement that utilities publish detailed, time-varying, data on distribution grid conditions at each node on their system. 

As defined in the order, “Limited Generation Profiles specify the maximum amount of electric generation a [distributed energy resource] system will export to the grid at different times throughout the year, ensuring that the project is responsive to fluctuating grid constraints at different times.”

In this blog post, we take a deep dive into the details of this decision and explore why it is a huge step forward for enabling distributed energy resources (DERs), like solar PV and energy storage, to operate in flexible ways that align with conditions on the grid. For an initial primer on the decision, see our press release here.

What’s Changing for Clean Energy in California as a Result of the Limited Generation Profiles Decision? 

Under the decision, Limited Generation Profiles will be an option for clean energy developers to ensure that a renewable energy project stays within the limits of how much power the electric distribution grid can accept at different times (hosting capacity limits), rather than paying for grid infrastructure upgrades that would otherwise be required if the project did not limit its export. 

Renewable energy systems paired with energy storage have a variety of unique characteristics compared to other sources of generation. Modern renewable energy systems have options to adjust their power output to align with the changing conditions on the grid. This is incredibly valuable because the energy being sent onto the grid at any given time must precisely match the amount of energy that customers are using, an amount that varies greatly throughout the day. For example, a home with a solar array and a battery could charge the battery and not send power to the grid at times when energy demand from customers is low, and then send that stored energy to the grid at a later time when there is high energy demand and additional supply is most needed. 

Despite the value of this kind of flexibility, until now, no state’s interconnection process (the process by which clean energy systems are approved to connect to the grid) has considered these capabilities when evaluating whether grid upgrades will be needed for a system to interconnect. Now, by taking into account the grid conditions at their proposed project site, and designing an export schedule based on those conditions, project developers have a means to avoid potentially costly grid upgrades. Not only will this save money for individual developers and customers, it will also enable the grid to accommodate significantly higher levels of renewable energy at a lower overall cost. 

What Makes This LGP Milestone Possible? California’s Integration Capacity Analysis 

To design a Limited Generation Profile that would enable a project to interconnect without triggering the need for upgrades that would otherwise be necessary, a project developer must have insight into the conditions on the grid in their project’s location, and how those conditions change over time. This latest clean energy milestone in California would not have been possible were it not for previous steps taken to increase grid data transparency in the state. 

At any given time, the electric grid can accept a finite amount of power export from generating systems without needing grid upgrades. This amount, known as hosting capacity, varies throughout the day and year based on grid conditions. Hosting capacity analyses—called Integration Capacity Analyses (ICA) in California—are an analytical tool that provides a snapshot in time of the conditions on a utility’s distribution grid at different locations. These conditions determine the grid’s ability to accommodate additional DERs at specific locations without the need for costly grid upgrades or lengthy interconnection studies.

California would not have ICA data were it not for extensive engagement by IREC and other clean energy stakeholders over the last decade, which resulted in a 2017 decision by the California Public Utilities Commission requiring the state’s investor-owned utilities to create and publish ICA data. (Read more about the lead-up to this milestone, and the resulting lessons learned, in IREC’s related blog post.) Since then, IREC has worked doggedly to ensure that the data was published as ordered and that it was accurate (our investigation uncovered significant errors in earlier versions of the ICA data that utilities published, and contributed to a 2021 order requiring utilities to validate the accuracy of ICA data and limiting the information they could redact in their ICAs). 

IREC also played a significant role in championing the use of ICA data in the interconnection process, an effort that is coming to fruition with this latest decision. The Commission first set the stage for the use of grid ICA data to improve the interconnection process for clean energy in 2020. In the three-plus years since that decision, IREC has been one of the leading parties contributing to the process to define how that would work, and make the decision a reality. This March 2024 decision on Limited Generation Profiles finally puts into practice what the Commission committed to in 2020. 

What Else Is Included in the Commission’s Order? 

In addition to ruling that utilities in California must allow project developers to use Limited Generation Profiles (LGPs) in the interconnection process, the commission resolved a number of other key issues in its decision. These include: the kinds of control systems that can be used to limit the export of power from a system; the allowable format of Limited Generation Profiles (including how many times per year a project can change its output); and the instances in which a utility would be permitted to curtail the output of a system in ways that differ from the originally approved LGP. These elements are discussed in greater detail below. 

Power Control Systems Approved as Primary Method of Export Control

The Commission’s decision also included a determination of what methods of export control would be accepted for systems that interconnect with an LGP. This is a key consideration because utilities must know that systems will operate as stated to ensure the safety and reliability of the grid. Power control systems, devices that electronically control the power output of generating facilities, are a common method for controlling power export. “Relays” are another option; these sensing and computational devices can signal a circuit breaker to trip based on measured quantities of voltage and current. 

The Commission ruled that power control systems that meet required certifications can be used to manage Limited Generation Profiles of interconnecting systems. Compliant devices will be available in the future pending an update to the associated UL product safety standard (UL 3141). 

IREC recommended that relays also be included as a means of control, as they may offer some benefits for larger projects and are readily available today. The commission ruled that relays may be allowed by “mutual agreement” with the utility, but stopped short of indicating that relays are generally acceptable or establishing a required process or terms for obtaining such mutual agreement. While IREC is pleased that the commission created an avenue for developers to utilize relays, the lack of a standardized process for arriving at mutual agreement may limit the use of this avenue in practice. 

Allowable Formats for Export Schedules 

Another key issue addressed in the decision concerns the allowable “LGP configurations,” the format of the profiles, particularly how many different export levels a renewable energy system would be allowed to have throughout the year, and how often those levels may change. 

The decision approves the use of a 24-value “block” configuration recommended by IREC, in which a system’s export levels can vary up to 24 times per year. Utilities had initially proposed that LGP configurations should be limited to no more than 12 values throughout the year and no more than one different value per month. IREC argued that this approach would limit the usefulness of the LGP option, because it would not allow systems to respond to differences in available grid capacity at different times of the day. 

For example, it is widely recognized that the grid faces strain in the evening when many people return home from work and use more power, while solar energy production is simultaneously decreasing as the sun sets. Added generation is particularly valuable at this time of day; the 12-value proposal from utilities would not have allowed projects to provide value to the grid by increasing their power output in the evening. In its decision, the Commission noted that it aimed to balance safety and reliability needs with the benefits of enabling renewable energy systems to increase their power output during times when the grid needs additional power. The IREC-recommended 24-value block configuration will support this functionality and allow interconnecting DERs to provide greater benefits on the grid. 

The commission adopted three different formats of 24-value configurations, which customers can choose between based on what makes the most sense given the conditions at their project site: “24-hourly,” “Block,” and “18-23-fixed.” While we won’t delve into the details of each of these configurations in this article, one shortcoming of these allowable configurations is that they may not align with local time of use rates (variable pricing for energy at different times of the day). The Commission declined to make even minor adjustments to align with the Time of Use rates (such as having a block from 4 to 9 pm, instead of 5 to 9 pm), which could have meaningful consequences on how useful the LGP is. Additionally, IREC believes that it would have been ideal if project developers could propose custom schedules (while still being limited to 24 changes per year) so that they could better align with the local grid conditions of their project. Nevertheless, the decision is a significant achievement for enabling the flexibility and grid support benefits that DERs can provide. 

Under the decision, utilities will be required to gather data that can inform the refinement of these configurations in the future. 

Rules for Curtailment of Project Generation

A third, critical issue that was considered in the Commission’s decision pertains to the instances in which utilities would be permitted to permanently curtail the power output of a renewable energy system in conflict with the agreed-upon LGP. This issue relates to non-emergency curtailment, such as if changing grid conditions (e.g., a significant reduction of energy consumption in a certain area, also known as a load reduction) made it so a portion of the grid could no longer accept as much power generation. 

In such a case, utilities wanted permission to permanently curtail power generation from renewable energy projects that had been interconnected under the LGP option—or to require the project developer to pay for the cost of needed grid upgrades in order to export according to the previously agreed upon LGP. (Utilities also sought to include expansive language that would have allowed this treatment in additional, undisclosed circumstances.) Because project financing is based on established production estimates, and because grid upgrades are often extremely costly, had such a provision been included in the rules it would have left open the possibility of significant negative financial repercussions for project developers. The presence of such a risk could have significantly reduced the likelihood that project developers would actually utilize this new interconnection option, and thus also limit the potential benefits it offers for the grid. It would also have created a restriction that did not apply to non-LGP systems, although it is entirely possible that the same situations requiring upgrades could arise for systems not using a schedule. 

Utilities are tasked with the management of the electric grid. In normal interconnection processes (i.e., for systems that interconnect under current processes rather than using an LGP), if load decreases in that area of the grid, the utility is responsible for making the infrastructure upgrades necessary to ensure that grid reliability is not adversely affected by the power being produced by that renewable energy system. IREC argued that the utilities “failed to show that LGP projects constitute a fundamentally different risk to the distribution grid than conventionally interconnected projects.” IREC asserted that a different level of risk would be the only justification for treating these projects differently concerning curtailment or requiring them to pay for grid upgrades at a later date, given the potential impacts of curtailment on project finances. 

In its decision, the Commission agreed with IREC’s position regarding the need to minimize financial risks for project developers. Accordingly, the Commission required the utilities to undertake upgrades needed to avoid such situations. The Commission did provide the option to utilities that they may “apply for a tariff deviation if they believe that undertaking an upgrade is not a reasonable use of ratepayer funds or is unreasonably costly in a particular case..” The Commission indicated that this option may only be utilized where there is a “sustained load reduction” that is triggering the need for upgrades. The Commission clarified that it is not creating a special opportunity to invite the utilities to file for tariff deviations just for LGPs.

IREC believes that instances of an interconnected DER causing the need for grid upgrades after interconnection are relatively unlikely. Data that IREC requested from the utilities on this point indicated that they are “not aware of even a single incident in the last five years in which a distribution system violation occurred due to sustained load reduction.” Further, as more and more activities are transitioned to electric power sources (electrification), load reductions are expected to become less likely. As such, IREC believes that this outcome is a satisfactory resolution that mitigates risk for project developers while providing reasonable assurances for ratepayers that they have a path to enable upgrades in rare circumstances. 

Over time, the rules may be adapted as more information is available. The Commission ordered the collection of data to track the prevalence of required curtailments and grid upgrades for LGP facilities, to support “better understanding of the uncertainties and risks associated with any LGP facility, especially related to sustained load reductions.” It left open the possibility of making future changes to this policy “[i]f, during the first three years of the LGP option being effective, cumulatively more than 10% of actual LGP facility curtailments, due strictly to the LGP-specific circumstance of sustained load reductions, have required grid upgrades (rather than low-cost mitigations) to restore curtailed LGP.”

With regard to emergency curtailment, the Commission emphasized that, in the case of short-term changes in grid conditions that might necessitate the temporary curtailment in power output from a system—such as in the event of an emergency, or to correct unsafe operating conditions, utilities are already allowed to engage in short-term curtailment of any generator. This treatment is the same regardless of whether a project is interconnected under the LGP option or traditional interconnection processes and was not disputed by IREC. 

The LGP Illustrates How States Can Start to Embrace DER Capabilities Without the Need for Full Communication and Control Systems

California will be the first state to require utilities in the interconnection rules to recognize and enable DERs to operate in ways that align with system peaks and valleys, but it is not the only state considering how to better align interconnection with system needs and realities. The topic of “flexible interconnection” has been coming up in many states and some have begun to pilot approaches or commence conversations about how to move towards more responsive interconnections. 

The LGP concept is distinct from what is commonly referred to as flexible interconnection in that it does not require a sophisticated communication system to be in place that would enable a utility to actively control DER output. The LGP accomplishes this by relying on the Integration Capacity Analysis to design fixed schedules based upon known grid conditions that have already been modeled and made publicly available. Without a high-quality hosting capacity analysis, it is currently challenging for utilities to conduct studies of proposed schedules because they must run multiple different studies for each distinct time period (though this may improve as cloud computing and new software tools are made available). The other challenge is that without a hosting capacity analysis that provides transparency into the grid conditions at different times of the day and year, DER developers do not have adequate information to design a schedule for the utility to study. 

The LGP enables DERs to respond to grid conditions in place at the time of interconnection by proposing a fixed schedule. Under flexible interconnection paradigms, rather than implementing a fixed schedule, DERs would be dynamically controlled to respond to real-time conditions on the grid. This approach offers some advantages for the grid operator as grid conditions change and needs evolve. However, the costs of deploying the sophisticated communication systems necessary for this approach are considerable and it may take many years before they are widely deployed. In addition, flexible interconnection approaches still need to be designed with some level of predictability for DER operators so that they can model the financial viability of projects. 

Both the fixed schedule approach offered by the LGP and more flexible interconnection approaches that will be enabled with distributed energy resources management systems (DERMS) or other communication systems are likely to play a role in DER integration in the coming years. For states that are about to, or have already, deployed a quality hosting capacity analysis, approaches like the LGP may enable more near-term realization of the system benefits and avoided upgrade costs that come with better utilization of DER export control capabilities. 

California’s decision to allow projects to utilize Limited Generation Profiles to avoid grid upgrades is a momentous first for the nation and provides a model for states with public hosting capacity data to unlock important grid benefits from clean energy systems. For states that do not yet have this valuable grid data, it offers a tangible example of the interconnection benefits this data can provide. These strategies will become increasingly important as the nation achieves higher levels of renewable energy on the grid.