AI Agentic Workflow for Integrating Distributed Energy Resources (DERs) During Outages

This workflow automates the identification, communication, and orchestration of customer-owned Distributed Energy Resources (DERs) within an isolated grid section. By analyzing SCADA, ADMS, and meter data, it identifies available capacity, establishes secure communication via DERMS or OpenADR, and coordinates the synchronization of inverters to form a stable, self-sufficient microgrid. The operational bottleneck it removes is the manual, time-intensive process of locating and dispatching utility crews or mobile generation, directly reducing Customer Average Interruption Duration Index (CAIDI) and outage costs.

Implementation integrates with existing utility systems like OSIsoft PI for telemetry, Oracle Utilities NMS for network topology, and Siemens Spectrum Power for SCADA control. The architecture requires robust exception routing for communication failures or unstable microgrids, escalating to human operators in the DMS control room. Observability is built via a Grafana dashboard tracking microgrid stability, DER participation rates, and estimated outage minutes saved, providing clear ROI through avoided outage costs and improved reliability metrics.

This workflow automates the identification and orchestration of Distributed Energy Resources (DERs) within an electrically isolated grid section following an outage. It replaces manual, time-intensive processes of calling customers and attempting remote dispatch with a deterministic, API-driven sequence. The operational upside is measured in reduced Customer Minutes of Interruption (CMI) and avoided costs from extended outages, directly improving SAIDI/SAIFI metrics by leveraging existing customer assets as a grid resource.

Implementation integrates with utility OMS, SCADA, and third-party DERMS platforms like Sunrun or Tesla via APIs. The orchestrator agent, built on frameworks like LangGraph, manages state, handles communication timeouts, and routes exceptions. Critical controls include operator approval gates before any switching, continuous observability of microgrid frequency/voltage, and automatic fallback to traditional restoration if DER synchronization fails. This creates a production-grade system that operationalizes customer assets for grid resilience.

This workflow automates the identification, communication, and orchestration of customer-owned Distributed Energy Resources (DERs) within an isolated grid segment during an outage. It replaces manual, time-intensive coordination by utility operators, directly reducing Customer Average Interruption Duration Index (CAIDI) and improving reliability metrics. The system ingests real-time telemetry from Advanced Metering Infrastructure (AMI) and utility SCADA to assess DER availability, state-of-charge, and grid-forming inverter capability, initiating a controlled sequence to restore power to priority loads.

Implementation follows a phased, risk-aware delivery: Phase 1 establishes secure API integrations with DERMS (like SunSpec) and the Outage Management System (OMS) for read-only observability. Phase 2 introduces the orchestration logic, built on LangGraph, with a digital twin for safe sequence simulation before any physical command. The final phase enables closed-loop control with mandatory human-in-the-loop approval gates for synchronization commands. Monitoring via Grafana dashboards tracks DER utilization, stability metrics, and exception rates, ensuring operational governance.

This workflow automates the identification, communication, and synchronization of customer-owned solar and battery systems within an isolated grid segment to form a stable, self-powered microgrid. It eliminates the manual, time-intensive process of locating and coordinating DERs during an outage, directly reducing customer interruption duration (CAIDI) and extending resilience without utility capital expenditure. The operational upside comes from faster service restoration and the ability to leverage distributed assets as a grid resource, but it requires stringent controls for safety, cybersecurity, and regulatory compliance.

Implementation requires integration with the Outage Management System (OMS) for fault triggers and a DER Management System (DERMS) for asset control. A phased rollout starts with a single, non-critical feeder segment using a limited set of pre-enrolled, utility-managed DERs. Governance mandates real-time operator approval via an HMI before any switching action, with continuous observability of microgrid voltage/frequency and automated fallback to a safe state. Subsequent phases expand to more feeders and third-party DERs, contingent on demonstrated reliability and updated cybersecurity protocols for customer gateway communication.

The operational upside comes from autonomously forming stable microgrids within isolated network sections, extending resilience without utility capital expenditure. This workflow automates the high-latency, manual processes of identifying available DERs, establishing secure communications, and managing load within their aggregate capacity. Savings are realized through reduced outage minutes (SAIDI), avoided truck rolls, and deferred infrastructure upgrades, directly impacting reliability metrics and operational cost.

Implementation requires integrating SCADA for topology, DERMS for asset registry, and Advanced Metering Infrastructure for last-gasp signals. The orchestrator, built on frameworks like LangGraph, must include digital twin simulation for pre-sync validation and human-in-the-loop approval gates for major reconfiguration. Critical controls involve real-time observability of microgrid frequency/voltage, automatic fallback on instability, and audit trails for all autonomous switching commands to satisfy utility compliance and NERC CIP requirements.