Avoiding Grid Constraints
Brian Lydic is Chief Regulatory Engineer at the Interstate Renewable Energy Council. He has been active in renewable energy since 2005. He works with regulatory stakeholders to further the organization’s mission to increase access to sustainable energy and energy efficiency. He is a member of UL 1741, UL 3141, and IEEE 1547 working groups, helping to improve the grid integration of PV systems.
As electrification efforts and deployment of distributed energy resources (DERs) accelerate, utilities and state regulators around the country are seeking innovative approaches to serve growing electricity demand and connect DERs faster and more economically while maintaining grid safety and reliability. The challenge is that as more new customer resources connect to the distribution system, the grid’s ability to host them becomes more limited.
Fortunately, new strategies are emerging that provide temporary or long-term pathways for DERs to avoid grid constraints that can lead to costly and time-intensive utility infrastructure upgrades. These strategies typically fall under the banner of “flexible interconnection” or “flexible connection” and are gaining momentum in states where queue backlogs, grid upgrade costs, and affordability are of particular concern.
While many jurisdictions are still grappling with how to design flexible connection offerings, there are some key considerations that regulators and other stakeholders should be aware of to ensure that new programs are set up for success.
Flexible Connection Defined
As the grid becomes saturated with DERs and load, upgrades to the distribution system will become necessary. DER owners pay for upgrades in many cases. But for new loads — such as medium- and heavy-duty electric vehicle (MHDEV) charging depots, data centers, and building electrification — ratepayers foot the bill, amplifying already high electricity rates.
The timing of grid upgrades also presents challenges: customer sites may be non-operational for months or years. In the meantime, the utility receives neither revenue from the new load nor energy and services from the new DER.
While a distribution circuit may not have room for new loads or DERs to run at full capacity all hours of the year, there are likely many hours in which the circuit is not fully loaded. New DERs and loads can agree to vary their operations to match circuit loading and unlock more grid capacity without more poles and wires. This is called a flexible connection. Note that in the case of DERs, as opposed to load, flexible interconnection is the commonly used term.
The Benefits of Flexible Connection
Flexible connection approaches have several benefits. They can be used as bridging solutions to allow loads or DERs to connect quickly and start operation before the utility completes capacity expansion projects.
For example, a charging depot might optimize the timing of power draw from its chargers to stay within grid import limits or add stationary storage to continue charging even during hours with grid constraints. Although the owner may have to operate the site differently, it can start operating — and generating utility revenue — much sooner.
While the business case for bridging solutions hinges on site-specific details and incentives, there is evidence of customer interest and benefits. Flexible bridging solutions are being pursued in California, Illinois, Washington, D.C., and Maryland.
Some customers may also be open to non-bridging flexible connection solutions that flexibly limit power indefinitely. Ratepayers can save even more because system upgrades are avoided altogether, in addition to increased utility revenue from load.
Further, the addition of flexible load will increase hosting capacity for DERs. If coupled with the right incentives, and possibly controls, load and generation can work in tandem to maximize grid utilization and even reduce the need for transmission buildout.
Managing How and When a Project Imports/Exports Power
Bridging versus non-bridging is one way to characterize flexible connection solutions. Local versus external control is another. Local control approaches often rely on device capabilities available today and that can be deployed quickly at relatively low cost.
Typical local control mechanisms include:
Power Control Systems (PCS) with a scheduled/fixed operating profile. PCSs are electronics that can be certified to the UL 3141 standard in lieu of time-consuming utility evaluation. California’s Limited Generation Profile and Limited Load Profile programs are examples of flexible connection solutions primarily reliant on certified PCS.
Real-Time Automation Controller (RTAC) that enforces power limits via a schedule. RTACs are industrial computers that communicate limits to onsite inverters and may also manage utility-grade relays to trip the site offline if limits are exceeded.
Unspecified and Uncertified Controls such as manual controls, which maintain power within the required limits. PG&E’s Load Limit Letter pilot allows for this, and simply contractually holds the customer to account with or without additional testing and verification of control strategies.
Autonomous Volt-Watt Curve. For inverter-based DERs, the volt-watt function can automatically reduce power export in real time based on local voltage for overvoltage. The volt-watt capability is required by the IEEE 1547 interconnection standard and available on inverters or systems certified to UL 1741 SB. For voltage-constrained sites, this would likely be the least costly control option, as the only cost is the customer’s lost production due to curtailment. A certified volt-watt solution that addresses import power for under-voltage constraints does not yet exist but could be incorporated into the UL 3141 standard for PCS.
Aside from the volt-watt function, local solutions require calculation of hosting capacity using historical data. As such, a safety buffer is typically included to reduce the risk of exceeding real-time hosting capacity. Additionally, the number of scheduled power limits will likely be constrained. For instance, the Limited Generation Profile in California allows up to 24 scheduled limits throughout the year and includes a 10% safety buffer.
Actively managed external control solutions, on the other hand, continuously update export/import maximum power limits based on forecasted or real-time hosting capacity. Typical external flexible connection mechanisms include:
Distributed Energy Management Systems (DERMS) that are built upon an Automated Distribution Management System (ADMS). Initial implementations only address constraints monitored via existing Supervisory Control and Data Acquisition (SCADA) data and calculate power limits using a rules-based approach. PG&E’s Flex Connect program is an example. Future implementations may include state estimation by regularly running power flow simulations to uncover constraints throughout the whole circuit.
Model-free Hosting Capacity Analysis to develop variable operating envelopes. For example, South Australia Power Network’s (SAPN’s) first flexible interconnection solution maps each feeder to one of 17 prototypical models and uses historical smart meter data for load profiles. Calculations run on this simplified system determine power limits, which are sent via public internet directly to inverters, gateways, or through aggregators.
Calculation of Distribution Transformer or Secondary Overloads at the grid edge by integrating with Advanced Metering Infrastructure (AMI). A local application gathers data from and communicates limits to the AMI meters connected to a single transformer. PG&E currently has a pilot project using computing capability in an AMI 2.0 meter.
With closer to real-time monitoring and control, we can further maximize distribution system utilization by calculating constraints less conservatively. Utilities could also enable additional operational capabilities, including maximizing load and generation output even when circuits are abnormally configured.
In the future, this could also enable orchestration of load and DERs on a circuit to maximize dispatch of DERs to serve load, similar to microgrid operations. During a blackout, that coordination ability could extend to manage a substation or feeder as a multi-customer microgrid.
Whether or not a third-party DERMS platform is installed, actively managed external control flexible connection solutions use common DERMS capabilities, such as real-time hosting capacity analysis, monitoring, and control. DERMS and DERMS-adjacent implementations can vary in capabilities, and each capability has different methodologies with varying degrees of precision, computation, and customer applicability.
An out-of-the-box DERMS vendor solution does not inherently generate maximal distribution system utilization. But what does is the strategic application of DER, load management approaches, and technologies with clearly defined use cases, incentives, costs, and benefits.
Before pursuing a costly and complex roll out of a DERMS capability like state estimation power flow, a clear net benefit for customers should be identified which offsets the research, development, and fixed costs. Cheaper technology alternatives, such as model-free hosting capacity methodologies, should also be investigated.
SAPN found using a model-free hosting capacity methodology to be the most cost-effective at implementing real-time power limits for low-voltage solar generation but is now integrating more advanced technologies that have supported additional use cases over time as they increased overall system benefits.
While the potential outcomes of deploying flexible connection solutions are exciting, regulators should carefully weigh the costs and benefits between local versus external solutions, and between different actively managed external control solutions. The continuous calculations and external controls required for actively managed solutions are likely to be more complex and costly compared to the pre-determined calculations and autonomous controls of local solutions.
Given this, it is recommended that states rapidly adopt cost-effective solutions that fit customer needs before DERMS deployments are ready, such as the local solutions California has implemented with its Limited Generation Profile and Limited Load Profile offerings. Moving forward, Commissions should carefully weigh costs and benefits so that the promise of flexible connection can be achieved — expanding customers’ access to power while lessening the impact on ratepayers.
