Grid Control and Automation

SCADA · ADMS · DERMS · PMUs

Grid control was built for a few hundred power plants. It now has to coordinate millions of inverters, batteries and chargers it does not own.

How often each grid control layer sees or acts on the grid, in seconds on a log scale: synchrophasors (PMUs) report 30 to 60 times per second; protection relays trip in one to three cycles; SCADA and EMS scan every two to four seconds; real-time markets dispatch every five minutes; smart meters record 15-minute intervals; day-ahead markets clear once a day. DERMS and virtual power plants must bridge seconds and minutes. HOW OFTEN EACH LAYER SEES OR ACTS ON THE GRID, SECONDS, LOG SCALE PMU (synchrophasor)30-60 per s Protection relay1-3 cycles SCADA and EMS scan2-4 s Real-time market5 min Smart meter interval15 min Day-ahead market1 day 10 ms 1 s 1 min 1 h 1 d Each layer runs at its own speed; DERMS and VPPs must bridge seconds and minutes.
PMU reporting rate
30-60 per s
SCADA scan
2-4 s
DER market rule
FERC Order 2222
Hub
Energy

Finding

Distribution control is shifting from one-way SCADA to DER-aware ADMS and DERMS, and integration across siloed systems is now the bottleneck, not sensors

Transmission operators have run EMS and SCADA for decades; distribution utilities mostly did not need to. Rooftop solar, home batteries, EV chargers and data-center loads changed that. FERC Order 2222 (2020) opened wholesale markets to aggregated DERs, and utilities are layering ADMS, DERMS and VPP platforms on top of SCADA systems that were never designed to talk to each other.

The supplier field is concentrated. GE Vernova (GridOS), Siemens (Spectrum Power), Schneider Electric (EcoStruxure ADMS), Hitachi Energy (Network Manager), Oracle Utilities and AspenTech (OSI) dominate Western control rooms; in China, State Grid's NARI supplies the D5000 dispatch platform used across its network. Meters are similar: Itron, Landis+Gyr, Honeywell and Aclara in the West, Wasion, Holley, Linyang and Sanxing in China.

Standards determine how much of this works together: IEC 61850 in substations, DNP3 to field devices, IEEE 2030.5 to inverters, OpenADR for demand response and the Common Information Model (CIM) between control systems. The orchestration layer on top is covered on Energy Orchestration.

Systems

Control systems by layer

From field devices to orchestration; adoption outlook through the end of the decade.

Grid control systems
SystemComponentsFunctionsSuppliersOutlook
Field devicesIEDs, RTUs, reclosers, PMUsMeasurement and local actuationSEL, GE Vernova, Siemens, Hitachi Energy; NR Electric, NARIRefresh tied to substation upgrades
SCADAMaster stations, RTUs, communicationsSupervisory control, remote monitoringGE Vernova, Siemens, Schneider, ABBSlow; many small utilities on legacy systems
EMSTransmission SCADA, state estimation, dispatchBalancing, generation dispatch, intertiesGE Vernova, Siemens, Hitachi Energy, AspenTech (OSI); NARI D5000Incremental upgrades tied to TSO budgets
ADMSDER-aware DMS, outage management (OMS)Fault restoration, volt/VAR control, hosting capacitySchneider, GE Vernova, Oracle, Siemens, Hitachi EnergyBecoming baseline for large distribution utilities
Synchrophasors (WAMS)PMUs, phasor data concentratorsOscillation detection, wide-area stabilitySEL, GE Vernova, Hitachi Energy; NARISteady; data volume is the limit
DERMS and VPP platformsDER dispatch, aggregation, AI optimizationCoordinated DER dispatch, demand responseGE Vernova, Siemens, Schneider (AutoGrid), Tesla, EnergyHub, UplightFastest growth; driven by Order 2222 and capacity shortfalls

Metering

Advanced metering infrastructure

The customer-facing layer: interval data, outage detection and price signals.

AMI components
ComponentTechnologyFunctionsNotes
Smart metersDigital meters with RF, cellular or PLC modulesInterval usage, outage and voltage alarmsItron, Landis+Gyr, Honeywell, Aclara; Wasion, Holley, Linyang, Sanxing
AMI networksRF mesh, cellular, power-line carrierTwo-way utility to customer communicationMillions of endpoints per large utility
Meter data management (MDM)Validation and storage platformsBilling and analytics dataOracle, Itron, Siemens
Grid integrationOutage and DER signals into ADMSFaster restoration, load managementSecond-generation meters add edge compute for local DER control

Standards

Standards and interoperability

Grid control standards
StandardScopeRoleNotes
IEC 61850Substation automationInteroperable protection and control devicesGlobal standard for digital substations
DNP3SCADA to field devicesControl center to RTU and IED communicationLegacy but dominant in North America
IEEE 2030.5DER communicationsUtility to inverter, battery and charger controlRequired for smart inverters in California (Rule 21)
IEEE C37.118SynchrophasorsPMU measurement and data formatBasis of wide-area monitoring
OpenADRAutomated demand responseLoad curtailment and price signalsUsed in California, Japan and Europe
CIM (IEC 61968/61970)Data modelConsistent data across EMS, ADMS, DERMSKey to breaking system silos
IEC 62351 and NERC CIPSecurityProtocol encryption; mandatory controls for bulk power operatorsSee Grid Cybersecurity

Bottlenecks

What slows grid control upgrades

Grid control bottlenecks
BottleneckConstraintImpact
Legacy SCADAAging, proprietary hardwareBlocks DER integration and interoperability
System silosADMS, EMS, DERMS bought separatelyHard orchestration, higher O&M
Synchrophasor dataHigh cost and data volumeLimits wide-area coverage
CybersecurityInsecure legacy protocols, IT/OT convergenceSystemic vulnerability
WorkforceFew SCADA/EMS engineers and grid data scientistsDelays and dependence on incumbent vendors

Sources

Sources and scope

Scope
Grid Control and Automation
Sources
FERC Order 2222; IEEE C37.118, IEEE 2030.5, IEC 61850; vendor disclosures
Updated
October 2026