The utility industry is full of leaders who have spent 30, 40, or 50+ years working in the sector. Even for folks whose entire careers have focused on managing our power system, the alphabet soup of utility software acronyms can be extremely confusing.
For folks new to the industry or new to thinking about these systems, we’ve put together a glossary of the most common acronyms for electric utility software systems.
A disclaimer: utility software systems are a little like snowflakes – no system is exactly the same. We’ve done our best to characterize the most common definitions and use cases for these acronyms, but there are certainly exceptions to the rules.
Definition: An Advanced Distribution Management System is the software platform that supports the full suite of distribution management and optimization. An ADMS includes functions that automate outage restoration and optimize the performance of the distribution grid. ADMS functions include fault location, isolation and restoration; volt/volt-ampere reactive optimization; conservation through voltage reduction; peak demand management; and support for microgrids and electric vehicles. Source: Gartner
What does that mean? An ADMS is a software system that provides advanced network management capabilities, building on those provided by a traditional Distribution Management System (DMS). Effectively the ADMS serves as the “brain” for conventional utility operations, enabling system monitoring, control of utility equipment (e.g. automated switching, tap-changing transformers), and advanced voltage management. The ADMS usually has close ties to the Outage Management System (OMS) to coordinate restoration and recovery. With an ADMS, a utility can automate previously manual processes and begin to integrate siloed meter data, asset data, and billing systems. ADMS systems are typically quite expensive ($ millions) and time-intensive (2-5 years) to deploy – in large part because of their reliance on accurate grid models to perform power flow-based analyses.
Providers: General Electric, Schneider Electric, Oracle; OSII, Siemens, Hitachi / ABB, Survalent
Definition: Advanced Metering Infrastructure is a composite technology composed of several elements: consumption meters, a two-way communications channel and a data repository (meter data management). Jointly, they support all phases of the meter data life cycle — from data acquisition to final provisioning of energy consumption information to end customers (for example, for load profile presentment) or an IT application (such as revenue protection, demand response or outage management). Source: Gartner
What does that mean? AMI refers to metering infrastructure that represents the shift from “dumb” meters to “smart” meters. AMI collects time-differentiated (often 15-min or hourly) data from individual meters and automatically sends that back to the utility at frequent intervals via private communications networks. AMI provides more data, more frequently, and more quickly than prior metering approaches. AMI is widely but not universally deployed – with billions of dollars spent on metering infrastructure between ~2005 and 2020. AMI also provides limited two-way communication, useful for automatic connect/disconnect and outage management. AMI is a key data provider for more dynamic grid operations (DER orchestration, Distribution Automation), though such capabilities require sufficient bandwidth and broadcast capabilities.
Providers: Landis+Gyr, Itron, Aclara, Sensus, Trilliant
What is it? A Common Information Model is an abstract model that represents all the major objects in an electric utility enterprise typically involved in utility operations. It provides a standard way of representing power system resources as object classes and attributes, along with their relationships. The CIM facilitates the integration of network applications developed independently by different vendors, between entire systems running network applications developed independently, or between a system running network applications and other systems concerned with different aspects of power system operations, such as generation or distribution management. Source: IEC
What does that mean? The CIM is a series of open standards for representing power systems under the International Electrotechnical Commission (IEC). These standards facilitate the exchange of power system data between different industry stakeholders, as well as enable applications and systems to share and exchange data. The main goal of the CIM is to serve as a canonical model to enable that exchange of data. Development of an international CIM began in the 1990s and existing standards are consistently updated.
Providers: While the CIM is more of a standard, originally developed by the Electric Power Research Institute (EPRI) in North America, there are vendors who help utilities implement CIMs, including DNV, IBM, and Amazon Web Services.
What is it? A Customer Information System refers to the system used to store customer-specific information, including account enrollment status, rate tariff, payment history, collection status, and other information necessary for the utility to effectively administer services. Source: Gartner
What does that mean? A CIS is the primary means by which utilities provide account information and manage billing/collections. A major focus of CIS is “meter-to-cash”, which is the process utilities carry out to measure consumption, generate and disseminate accurate bills, collect payments, and ensure sufficient revenue is collected to cover approved utility rates. CIS also supports customer service interactions – including call centers, automated texts, and virtual chatbots – often in coordination with third-party or add-on applications.
Providers: Oracle, Salesforce, SAP, Fluentgrid, Cayenta, NISC
Definition: At a fundamental level, a DERMS is a control system specifically designed to handle DERs. A DERMS acts as a switchboard for DER-related protocols and information to simplify the management of these disparate systems and feed information into other utility backend systems for planning, operations, and customer engagement. These DERs can include demand response, solar, energy storage, electric vehicles, or other distributed technologies. Source: SEPA
What does that mean? A DERMS helps monitor, control and optimize DER behavior. Most often, DERMS in the utility context refers to an “Enterprise DERMS” or “Centralized DERMS” – a system used by the utility to manage a portfolio of flexible resources connected to the utility’s distribution network. This version of DERMS sends signals to DERs to instruct those devices to behave in a way that benefits the distribution network. Example applications include decreasing load to reduce peak demand charges, moving load to match low-carbon generation, and curtailing generation to avoid voltage deviations. This utility-managed DERMS is ideally closely integrated with other core utility systems – including the DMS or ADMS – to ensure DER dispatch is coordinated with overall grid needs. In reality, that integration is uncommon today – with most DERMS operating reasonably independently from other utility systems.
Sometimes DERMS is used to refer to DER control systems managed by DER aggregators / owners, rather than the utility. The concept is similar – monitoring devices and sending dispatch signals to optimize behavior for a set of goals. The difference is that the aggregator or device owner (or a third-party on their behalf) sends the signals, instead of the utility. It’s possible for the utility to send signals from their Enterprise DERMS directly to these “Edge DERMS”.
Note: At Camus, we provide “DER Orchestration” software (as part of a larger “Grid Orchestration” platform) that takes a DERMS and adds grid awareness (part of an ADMS) and market integration (part of an MMS) to provide a more comprehensive and effective tool for managing DER impacts. We don’t consider ourselves to be a “DERMS” provider exactly, but we can help utilities who are looking to solve their DER management challenges.
Providers: Camus, Schneider Electric (AutoGrid), GE Digital (Opus One Solutions), Siemens, Generac Grid Services (Enbala), EnergyHub, OSI, Smarter Grid Solutions
Definition: A Demand Response Management System (DRMS) is an information management system used for monitoring, controlling, scheduling, and managing a utility’s portfolios of demand response (DR) resources. Source: Department of Energy
What does that mean? A DRMS provides communication between the utility and its demand response providers. Demand response refers to the action of requesting electricity consumers to reduce their demand during specified periods of time in exchange for compensation. An example is when peak electricity demand on a hot summer day threatens to exceed available generation. In those cases, the grid operator may call upon demand response resources to reduce demand during peak periods.
Historically, demand response programs have focused on large commercial and industrial loads, though aggregated residential loads also participate. The DR provider may take actions like adjusting thermostats, rescheduling non-critical production, or switching to onsite generation or alternative fuels. A frequent distinction between a DRMS vs. a DERMS is the degree of control: with DRMS, it’s very rare for the grid operator to directly control device behavior, while direct control is very common with a DERMS.
Providers: CPower, Enel X, AutoGrid, Itron, Eaton, OATI, Siemens, GE
Definition: A utility Enterprise Asset Management system (EAM) is a business application used to optimize maintenance and repair of key utility equipment. An EAM typically includes asset registration, work order management, inventory and procurement in an integrated software package. Source: Gartner
What does that mean? Utilities need to be able to maintain, optimize, repair and replace their key equipment. An EAM helps a utility track the lifecycle of its assets, including age, usage, and maintenance history of each asset to inform inspections, diagnostics, maintenance, and other operations. Increasingly, advanced analytics capabilities are enabling utilities to leverage EAM data for preventative maintenance rather than corrective maintenance. Example assets include poles, wires, switches, cutouts, fuses, reclosers, and transformers.
Providers: SAP, Oracle, IBM, Schneider Electric, ABB
Definition: An energy management system (EMS) – sometimes called a transmission management system – manages the real-time operation of transmission grids, often including both transmission and generation assets. Source: DNV
What does that mean? The EMS is to the transmission system what the ADMS/DMS is to the distribution system. It manages real-time operations and includes applications like state estimation, optimal power flow, contingency analysis, and voltage stabilization at the transmission level. A key data source for the EMS is SCADA, providing two-way communication with and one-way control of transmission and generation assets. More advanced energy management systems (sometimes called AEMS) offer capabilities like variable renewable forecasting and autonomous restoration.
Note that an EMS can also refer to a system used to manage individual devices (fans, pumps, lighting, etc.) within a facility or to refer to a system managing a microgrid.
Providers: GE, Schneider Electric, ABB, ETAP, Siemens
Definition: A geographic information system (GIS) is a collection of computer hardware, software and geographic data for capturing, managing, analyzing and displaying every form of geographically referenced information, often called spatial data. Source: Gartner
What does that mean? A GIS is a software system that enables utilities to create, manage, and map spatial data. The GIS forms the backbone for modeling out the physical grid in a digital environment – representing the location of each asset. The GIS takes important information from other systems and maps it to physical assets and locations, informing asset management and workforce management decisions, along with grid planning and analysis.
Providers: ESRI, GE, Schneider Electric, Bentley Systems, SEDC (Futura), Hexagon, Milsoft
Definition: A Meter Data Management System (MDMS) collects and stores meter data from a head-end system and processes that meter data into information that can be used by other utility applications including billing, customer information systems and outage management systems.
What does that mean? An MDMS is important for utilities to access and use the massive quantities of data collected from smart meters and advanced metering infrastructure (AMI). While the AMI is the physical infrastructure (meters) and outward communications mechanism from those devices, the MDMS collects the meter data (aka “interval data” because it’s collected at consistent intervals) and helps frame that data for other systems to access. Most MDMS go beyond simple collection of the data to also help validate, store, and analyze interval data.
Providers: Oracle, Siemens, Itron, Honeywell, Landis+Gyr, AVEVA, NISC, Tantalus, Nexgrid, Eaton
Definition: An Outage Management System (OMS) is a utility network management software application that models network topology for safe, efficient field operations related to outage restoration. An OMS tightly integrates with call centers to provide timely, accurate, customer-specific outage information, as well as supervisory control and data acquisition (SCADA) systems for real-time-confirmed switching and breaker operations. These systems track, group and display outages to safely and efficiently manage service restoration activities. Source: Gartner Glossary
What does that mean? An OMS is the utility’s primary tool for managing outages – including locating outages, analyzing their causes, and restoring service. Using real-time data, an OMS enables the utility to identify and address outages as quickly and efficiently as possible. A customer communication component is incorporated to alert and update customers. Utilities rely on OMS systems to more effectively mitigate the impacts and frequency of outages – raising reliability scores and reducing operating costs. An OMS can be deployed as a component of an ADMS, and it is typically integrated with AMI, SCADA, and other systems to communicate and share data.
Providers: GE, Schneider Electric, Siemens, OSI, Oracle, Milsoft, Hitachi, Minsait ACS
Definition: Supervisory Control and Data Acquisition (SCADA) is used to monitor and control a plant, process or equipment. A typical SCADA system is made up of sensor / signal hardware, controllers, software, network, and communication. Source: IEEE
What does that mean? SCADA is the primary means by which utilities acquire data from and provide dispatch instructions to utility equipment. SCADA typically includes four parts: 1) instrumentation to measure data, 2) communications to share data, 3) a “master terminal unit” (MTU) to communicate control instructions, and 4) remote stations or “remote terminal units” (RTUs) to receive control signals and operate equipment accordingly. SCADA is the backbone by which secure monitoring and control is managed for utility equipment like generators, reclosers, capacitors, voltage regulators, switches, and transformers.
Providers: GE, Siemens, Schneider Electric, Honeywell, OSI, ABB, Rockwell Automation, Emerson Electric, Survalent
Definition: A Workforce Management System (WMS) helps utilities efficiently and cost-effectively manage utility field service calls. The WMS manages and enables field work requests, coordinating work across the full asset life cycle and fielding requests from other systems, including the ADMS, GIS, MDMS and EAM. Source: Gartner
What does that mean? A WMS or MWMS enables a utility to automate processes related to service call or other field work, including employee tracking, service order logging, dispatch, and more. A key goal of the workforce management system is to connect field workers to relevant data points – requiring close integration with other utility data systems.
Providers: Oracle, IFS, GE, SAP, Schneider Electric, Salesforce
With increasing decentralization, decarbonization, and digitalization of the grid, the landscape of utility software systems will continue to evolve. At Camus, our grid orchestration platform, for example, stretches beyond a standard DERMS to equip utilities with real-time grid awareness and value-based dispatch of DERs - known as DER Orchestration. Our platform’s one-way SCADA, AMI, and GIS integrations enable operators to find the best way to orchestrate distribution-connected resources for a more reliable, affordable, and sustainable power system.
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