The IEEE Guide for Electric Power Distribution Reliability Indices (Standard 1366) was developed to facilitate uniformity in distribution service reliability indices and to aid in consistent reporting practices related to distribution systems, substations, circuits, and defined regions. Fear them, loathe them, or love them, but every electric distribution system professional should understand the indices and this standard as its “ratings” may at some point be used to characterize his/her organization or work.
Standard 1366 was issued in 1998 and updated several times since by the IEEE Distribution Design Working Group. It defines 12 reliability indices and provides guidance for calculating them. Possibly the most frequently monitored and reported indices include: System Average Interruption Frequency Index (SAIFI), which is how often the average customer experiences an interruption; System Average Interruption Duration Index (SAIDI) defined as the total number of minutes of interruption experienced by the average customer; and Customer Average Interruption Duration Index (CAIDI), which is the average time required to restore service.
One would think that comparing companies using carefully defined reliability indices would be straightforward. After all, the standard is rather detailed. However, a thorough review reveals areas of the standard that are a bit murky. For instance, Major Event Days (MEDs) are designated as catastrophic events that exceed reasonable design or operational limits of an electric power system, so individual utilities have leeway in defining what constitutes a MED on their system. Also, catastrophic events must affect at least 10% of the customers within an operating area, so the size of the utility or operating area affects the designation. Further, since SAIFI, SAIDI and CAIDI are hugely impacted by inclusion or exclusion of major interruption events, these metrics may not be as comparable between utilities as one would hope.
While practitioners continue a healthy debate regarding the definition and application of MED and Catastrophic Day data (see: Microsoft PowerPoint - Cat Days UW Pres 2012.pptx), the 1366 indices are nonetheless used universally to characterize distribution system reliability. EIA publishes an annual reliability file compiled from data collected on Form EIA-861, and many electric organizations appropriately track and celebrate improvements in the indices (APPA recognizes member utilities for reliability efforts | American Public Power Association). However, some pundits argue the best use of the 1366 indices is for self-evaluation rather than comparison among companies.
Design, construction, and operation, including myriad agency and self-imposed procedures and practices, contribute to distribution system reliability. Foundational factors relevant to reliability include system voltage, feeder length, overhead vs. underground routing, sectionalizing capability, fuse design, redundancy, conductor type/age and customers per feeder. Utilities may report data on a system basis, but most organizations collect data on a feeder/circuit, substation, or area basis. They recognize the increased burden of achieving data granularity can result in improved reliability insights.
Interruption data may be recorded/tracked using commercial software such as APPA’s eReliability Tracker Software, a SCADA system, an outage management system, automated metering infrastructure, utility created databases and even paper records. Further, a broad range of communication technologies are employed for retrieving distribution system data, including broadband, wireless, DSL and more. Collecting useful system reliability data is a large effort.
The major causes of interruption on most distribution systems are wildlife, weather, equipment failure and vegetation. Incidence data may reveal clear causation and an obvious solution such as the need for increased system redundancy, which can improve resiliency and contribute to lower SAIDI numbers. However, the issues underlying interruption data may be complex and solutions are often not straight-forward. For any given system modification, SAIFI and SAIDI may move in different directions. Even when these two indices are improved, CAIDI may move in the wrong direction (Microsoft PowerPoint - Without video IEEE 1366- Reliability Indices 2-2019.pptx). Thankfully, there are numerous reliability analysis asset management software tools on the market to help planning staff anticipate the impact of system modifications and procedural changes on performance indices.
The popular reliability indices mentioned above relate to sustained interruptions. By IEEE definition, that is an interruption of greater than five minutes. A growing facet of customer satisfaction relates to the incidence of momentary outages and power quality issues. This is a result of the increasing prevalence of sensitive electronic equipment and a growing variety of distributed energy resources (DERs) on distribution systems. IEEE uses the momentary average Interruption frequency index (MAIFI) to characterize short interruptions. Other standards and codes cover power quality issues such as frequency and harmonics, flicker, transients, and sag.
Collected over a representative period and Interpreted with care, distribution system interruption data and IEEE performance indices can provide valuable insights into the tradeoffs involved with reliability improvement measures. Having clear, system-based objectives in mind, as opposed to focusing on a single performance index or comparing indices between companies, may be of the greatest benefit to customers.
