Demystifying DERMS: Understanding Their Capabilities

DERMS Capabilities

As more distributed energy resources (DERs) come online, utilities will face new grid impact challenges. New solutions can help optimize the control of DERs while reducing capacity issues and reversing capacity flow. One such solution is a distributed energy resource management system (DERMS). Fundamentally, a DERMS is a utility system designed to visualize and control customer and utility-owned DERs. Practically, DERMS have a different significance for different stakeholders, and each DERMS implementation is unique to each utility, its business use cases, and its service territory. The broad spectrum of capabilities makes the evaluation, selection, and justification of DERMS challenging. Creating a common language and an understanding of all the functionalities of a DERMS is a critical first step for utilities, regulatory bodies, and policymakers as they decide how a DERMS will contribute to an effective, affordable, and equitable distributed energy system. 

As part of an effort to clarify the potential of DERMS for the utility industry, the Smart Electric Power Alliance (SEPA) convened a task force of 12 utilities between late 2021 and 2022 to review DERMS vendors, discuss DERMS capabilities, understand architecture implications, and share information on utilities' respective experiences with DERMS and DERMS-like tools. The project team also brought in 11 DERMS vendors to demonstrate and explain their product offerings, to help understand the market maturity of the various DERMS functionalities. Some DERMS functionalities, such as transactive energy and market bidding functions, are still in the early-emergent stages, whereas other functionalities, such as utilizing a DERMS for a demand response program, are fully mature and widely adopted.

As part of the project, the team created an encyclopedia of DERMS functionalities to address the majority of utility business use cases. By dividing a DERMS into discrete functionalities, utilities and their regulators and stakeholders can develop a more robust understanding of what to expect from a DERMS. SEPA and the utility task force identified 19 top-of-mind functionalities that they would expect to be available from vendors (Figure 1). These 19 functionalities included:

• Visualize DERs on the grid system
• Forecast and model DER consumption from and injection into the grid
• Aggregate and optimize thousands to hundreds of thousands of DERs
• Bid into and interact with market systems such as those for regional transmission organizations (RTOs) and independent system operators (ISOs)
• Communicate with and send command signals to DERs for grid and ancillary services
• Settle customer accounts for their participation in utility DER programs

 Figure 1. DERMS Module Inventory

Source. SEPA. (2023). DERMS Encyclopedia.

The task force grouped these functionalities into four major categories: Configure, Analyze & Optimize, Control, and Transact. These business use cases align with different aspects of DERMS deployments. Many utilities interviewed for the project indicated that phased DERMS deployments would allow them to ensure the DERMS is integrated into other enterprise systems, such as an advanced distribution management system (ADMS), and to offer new utility programs as more DERs come onto the grid.

Configure

Utilities want the ability to visualize all DERs on their grid. The Configure business use case is the first step toward utilities controlling and managing customer behind-the-meter (BTM) and distributed utility front-of-the-meter (FTM) assets. When utilities have data on the location of DERs on individual feeders on circuits and their DER class (such as solar, stationary storage, electric vehicle charging, and bidirectional vehicle charging), utilities can model and predict DER grid impacts. For utilities in jurisdictions prohibited from communicating with and controlling customer DERs, the Configure business use case still yields significant benefits for planning distribution upgrades, anticipating generation needs, predicting peak events, and educating customers on utility programs. The modules included in the configuration category are Registration and Asset Configuration.

Analyze & Optimize 

The Analyze & Optimize use case addresses utility needs for more robust DER data analysis. This business use case is for utilities that are not yet at the point of controlling BTM and FTM assets; however, utilities want to use the DERMS to analyze, forecast, and visualize DER data. These functionalities allow utilities to view the historical, current, and predicted capacity and availability of DERs to better study and anticipate their grid impacts. Collectively, these functionalities give utilities a clearer understanding of the expected or real-time status of customer and DER assets including information such as location, operational status, and device connectivity. The modules included in this category are Monitoring/Estimating, Forecasting, Aggregation, Optimization, and Measurement & Verification. 

Control

Utilities addressing this use case have advanced to the point where they want to automatically or manually adjust the output of specific DERs to achieve a desired operational objective, such as calling demand response events, participating in a virtual power plant (VPP), or providing volt/VAR optimization (VVO). Many utilities asserted that the ability to control BTM and FTM DERs and provide grid and ancillary services is a primary motivation for implementing a DERMS. By controlling DERs, utilities can act as grid orchestrators and reduce utility (and customers’) costs, reduce wear and tear on the distribution grid, address system constraints and congestion, and optimize DER asset value for customers and the utility alike. The Control modules include Scheduling & Dispatch, Virtual Power Plant, Curtailment, Demand Response, Grid Management, Renewable Smoothing, Resilience/Microgrids, and Volt-Var Optimization.

Transact

For this use case, utilities are seeking the ability to bid DERs into local markets, support transactive energy models, and interact with third-party aggregators. The DERMS will be designed to monitor, predict, and present information on market conditions for optimized energy purchase and sales, and will provide utilities with a platform for coordinating with third parties that may manage BTM DERs. Market-related DERMS applications require monitoring and predictions of locational marginal pricing and other parameters to inform DER trading in capacity and/or energy markets. These functions rely on access to DER capabilities and benefit from aggregation functions to create VPPs, group DERs by aggregator, and support FERC Order 2222 requirements focused on connecting DERs with markets. Vendors are largely still developing these functionalities because they rely on a high degree of communication and interaction with market systems and numerous entities working in the DER space. The Transact modules include Aggregator Data Exchange, Bidding, Settlement, and Transactive Energy. 

Grid Architecture Implications 

Implementing a DERMS is a complicated process that requires both extensive grid architecture and engineering analysis as well as a deep understanding of how the utility will use the DERMS and implement customer-facing programs (Figure 2). DERMS implementation heavily relies on integration to other utility systems. Close coupling of the DERMS with an ADMS blur the lines among the systems. Many U.S. utilities have begun implementing, or are in the process of adopting, an ADMS because these systems provide utilities with advanced insight into the real-time status of the distribution grid and produce power-flow models for distribution operators. 

Figure 2. Architecture Diagram for DERMS Integration

Source. SEPA. (2023). DERMS Encyclopedia.

SEPA’s ongoing work tracking utilities' carbon-reduction initiatives and progress - as part of the SEPA Utility Transformation Challenge - shows that 89% of 2023 utility respondents had obtained approval for a ADMS proposal, were in the process of implementing an ADMS, or had a fully operational ADMS. Similarly, 75% of the respondents were taking the same steps for a DERMS deployment (Figure 3). As utilities pursue the DERMS adoption process, they must consider if their DERMS will remain separate from an existing or future ADMS, or if the DERMS will be a modular add-on to the ADMS. 

Figure 3. Implementing ADMS and DERMS Solutions

Key Takeaways from Utilities

Regardless of which business use cases appeal to the utility, there are several key DERMS implementation considerations that all utilities should incorporate into their planning processes: 

• Include a system architecture plan that requires testing environments
• Plan for phasing the implementation in achievable portions 
• Plan for scaling the technical solution as the number of DERs on the system grows
• Incorporate cybersecurity from the beginning
• Define the requirements for each set of stakeholders, and include them early in the planning process
• Determine the utility’s data requirements, existing systems, and future integration needs

By incorporating these considerations, utilities can better plan for the architecture, communication, and planning needs that will be required in any DERMS deployment. As utilities undergo their own DERMS deployments, they can use industry resources such as SEPA’s free, upcoming DERMS Encyclopedia to create their own roadmaps and ensure that all stakeholder groups understand DERMS. As DERs proliferate, an in-depth grasp of DERMS implementation will allow utilities to stay ahead of potential problems while maximizing the impact of new grid resources.