Inter-Control Center Communications protocol (ICCP or IEC 60870/TASE.2) is the de facto standard worldwide for control-center communication in the electric power sector. It enables data exchange inside utility systems as well as between utilities and power pools, regional transmission organizations (RTOs), independent system operators (ISOs) and nonutility generators. ICCP, or TASE.2 protocol, allows for the exchange of real-time and historical data including status, measured values, scheduling data, operator commands, and more. The ICCP protocol is based on Manufacturing Message Specification (MMS or ISO 9506) and allows for both client and server roles. ICCP and MMS allow for TCP/IP connections to be inbound, outbound, or both—irrespective of the client/server role.
Today many of us take real-time communication and data for granted. Pre-1990s, this was not the case. ICCP began in 1991 as an effort by power utilities, data exchange protocol support groups (WSCC, IDEC, and ELCOM), EPRI, consultants, and SCADA/EMS vendors to develop a comprehensive, global standard for real-time data exchange within the electric power utilities industry that was fully ISO compliant.
Before ICCP, utilities relied on in-house or proprietary, non-ISO standard protocols such as WEIC, ELCOM, and IDEC to exchange real-time data. The Utility Communication Specification (UCS) Working Group was formed that year to develop the protocol specification, develop a prototype implementation, test the specification, submit the specification for standardization, and perform interoperability tests among the developing vendors.
The ICCP history started in May of 1991, when the IEC Technical Committee 57 Working Group 07 (TC57 WG07) asked the WSCC Communications Task Force to create WSCC guidelines for international standardization. This group felt a better solution would be to bring together the four competing standards (WSCC, IDEC, ELCOM, and MMS) to develop a fully ISO compliant standard.
In September of 1991, the first Utility Communications Specification (UCS) meeting was convened. Any utility, vendor, or organization who was committed to developing a comprehensive standard was welcome to attend. The meeting had two main outcomes. The attendees 1) recognized several benefits of a combined effort to create a communications standard, and they 2) created a task force to complete the work of creating a standard.
In 1991, the Utility Communications Specification (UCS) determined multiple benefits of a combined effort to create a communications standard for the utilities industry. These benefits include
Over the next several months, the task force worked through internal meetings and meetings with industry standards organizations such as International Electrotechnical Commission (IEC) working groups, Institute of Electrical and Electronics Engineers (IEEE), and National Institute of Standards and Technology (NIST). During these meetings, the task force balanced the options of making the WSCC and IDEC protocols compatible to communicate versus defining the requirements for a new protocol. They determined it would be more productive to work on a new protocol and conducted a feasibility study of MMS.
The UCS working group completed a benchmark of MMS to determine the overhead of MMS running ICCP blocked, periodic messages. The preliminary results showed a 6% to 10% increase in transmitted bits/message when using MMS for the ICCP messaging service versus a custom approach of bypassing the presentation layer. This would not increase the recurring costs of network media to any significant amount. Based on the results of the benchmark, the UCS working group approved the use of MMS for UCS/ICCP.
Once the feasibility study demonstrated MMS was a viable upper-layer alternative to custom software, the working group directed it efforts to three areas: 1) developing the functional specification for a new protocol utilizing MMS; 2) determining how the protocol could be demonstrated; and 3) deciding to whom it would be submitted for acceptance as a standard.
UCS submitted ICCP to the IEC Technical Committee (TC) 57 Working Group (WG) 07 as a proposed protocol standard. At the same time, WG-07 was also considering a standard based on ELCOM (ELectricity utilities COMmunications)-90 over ROSE. TC-57 chose a dual protocol approach. This allowed for an implementation that would meet 1992’s European Common Markets requirements and the long-term development for a more comprehensive protocol. TC-57 designated the protocol based on ELCOM-90 as TASE.1 (Tele-control Application Service Element-1) and the protocol based on ICCP over MMS TASE.2.
Under EPRI’s Integrated Utility Communications Project, a series of demonstrations and associated seminars were conducted. One demonstration included implementing and testing the protocol at Western Area Power Administration’s (WAPA) Loveland Area Office and at Ohio Edison Company, with a third node at a vendor to demonstrate routing and networking capabilities.
Live data between the WAPA control center in Loveland, Colorado, and Ohio Edison's control center at Wadsworth, Ohio, was transferred via the new ICCP over a communication network linking the two control centers with a node located at the vendor in Florida. Data flowed directly between the utilities or via the node at the vendor under control of the MMS/OSI-based protocol.
The demonstration was completed in late 1994 and was based on major blocks of ICCP functionality including the exchange of control center objects and remote operator communications. Over time the ICCP standard has been refined, but it remains as the preferred standard for control centers.
In September of 2020, the Federal Energy Regulatory Commission (FERC) approved final rule Order 2222 (PDF). This rule enables distributed energy resource (DER) aggregators to compete in all regional organized wholesale electric markets. The intent of the action is to empower new technologies to come online and participate on a level playing field, further enhancing competition, encouraging innovation, and driving down energy costs for consumers.
DERs are located on the distribution system, a distribution subsystem, or behind a customer meter. They range from electric storage and intermittent generation to distributed generation, demand response, energy efficiency, thermal storage, and electric vehicles and their charging equipment.
The final rule enables these resources to participate in the regional organized wholesale capacity, energy, and ancillary services markets alongside traditional resources. Multiple DERs can aggregate to satisfy minimum size and performance requirements that they might not meet individually. It also means greater demand for ICCP connectivity from all the aggregated resources coming online to participate in energy markets per the data and control requirements of each ISO/RTO.
ICCP allows the exchange of real-time and historical power system monitoring and control data. This includes measured values, scheduling data, energy accounting data, and operator messages. Data exchange can occur between multiple control center EMS systems; EMS and power plant DCS systems; EMS and distribution SCADA systems; EMS and other utility systems; and EMS/SCADA and substations.