2019 transmission-outage coordination stats and goals

Since 2005, ISO New England has repositioned 129 transmission-outage requests to a more economic time, resulting in an estimated $218 million savings in congestions costs

Preventative maintenance is good practice for all types of equipment, from cars, to water heaters, to the power lines of the bulk power system. Participating transmission owners (PTOs) routinely maintain transmission lines and associated equipment for avoiding emergencies, accommodating the construction of new facilities, and addressing problems that arise. But the PTOs cannot take equipment out of service without first coordinating the outage request with the ISO.

Using its wide-area view of the system, its situational awareness of forecasted system conditions, and with consideration of all outage requests it receives for transmission and resources, the ISO assesses the potential reliability and economic impacts of requested outages and then schedules transmission outages around the region. Coordinated transmission-outage scheduling achieves a number of aims:

  • Maintain system reliability under expected and contingent conditions
  • Minimize congestion and overall costs to New England consumers
  • Provide timely information to market participants
  • Minimize conditions that could impede generator participation in the markets
  • Facilitate outage coordination with adjacent areas

Major types of transmission equipment outages

ISO New England Operating Procedure No. 3 (OP 3), Transmission Outage Scheduling, classifies several types of transmission equipment outages, the main ones as follows:

  • Planned—taking equipment out of service to conduct routine maintenance or to accommodate new construction. While outage requests submitted more than five days before their requested start date are considered planned outages, requests submitted from 21 days to 24 months in advance, called long-term outage requests, provide more  time for the ISO to measure the potential reliability and economic impacts of a proposed outage and to communicate this information to market participants. 
  • Unplanned—when equipment is forced out of service because a problem was discovered and the request for the outage did not meet the minimum notification requirements of a planned outage, as identified in OP 3. Unplanned outages can be emergency or forced outages:
    • Emergency outage—the obvious failure of a piece of equipment that comes out of service on its own or requires immediate operator intervention to remove it from service
    • A forced outage—the discovery of a problem that needs to be repaired as soon as any combination of crews, equipment, or corrective dispatch actions can be put in place for performing the work
An outage can last from a few minutes to several weeks or months, and it can be continuous or noncontinuous. Because of their urgency, requests for unplanned outages receive a higher scheduling priority than those for planned equipment outages. 

Outage-request stats for 2019
The ISO New England Transmission Equipment Outage Coordination 2019 report, summarizes outage stats for the year and measures metrics to assess and improve transmission-outage coordination. Key 2019 results are as follows:
  • In whole, the ISO processed 5,234 applications for transmission equipment outages, 8.3% fewer than in 2018.
  • Of the 3,986 requests submitted within the region in 2019, roughly 80% were for planned outages, 1.2% fewer than in 2018, and 20% were for unplanned outages.
  • The ISO studied and ultimately approved or disapproved 99.92% of all outage requests 48 hours before the outage’s planned start date, which is 24 hours more than the time requirement identified in OP 3.
  • The ISO repositioned 22 transmission equipment outages, resulting in $7 million dollars of congestion savings throughout the year.  
  • With the PTOs and local control centers submitting 86.0% of all transmission outage requests via the long-term process, the ISO’s 80% target for this goal was exceeded.
  • With 68.1% of the total requests for planned outages that could have an impact on economic dispatch and system reliability submitted at least 90 days before the outage start date, the ISO’s 60% target for this metric was exceeded.
  • Another target was to coordinate at least 85% of all transmission equipment outage requests as planned outages, although for 2019, 79.9% of all such requests were coordinated. This target was missed primarily because outage requests were submitted less than  five days of their start date and primarily due to equipment problems in the field.
  • The ISO received 65% of the cancellation notifications for planned transmission equipment outages before 10:00 a.m. the day before a scheduled start date (i.e., before the Day-Ahead Energy Market closed for bids and offers). The ISO thus met its minimal 65% target for this metric.
  • A “FERC metric” focuses on outages for transmission lines >200 kV that last at least five days. With 100% of planned outage requests for these lines submitted at least 30 days before the scheduled outage start date, the ISO exceeded its 2019 target of having at least 98% of these outages submitted in this timeframe.  
Long-term outage-coordination trends
Coordinated transmission-outage scheduling has accomplished the following through the years:
  • Increased the percentage of New England transmission equipment outage requests submitted at least 21 days in advance from 10.3% in 2005 to 76.0% in 2019
  • Increased the percentage of major transmission elements outage requests submitted at least 90 days in advance from 24.4% in 2009 to 70.5% in 2019
  • Increased the percentage of all transmission equipment outage requests submitted more than 90 days in advance from 23% in 2010 to 44.4% in 2019
  • Repositioned a total of 129 transmission-outage requests, resulting in an estimated $218 million savings in congestions costs since 2005
Governing documents  
The outage-coordination report serves as compliance with certain provisions of the Transmission Operating Agreements (TOAs) the ISO has with each PTO. The TOAs define the ISO’s authority to direct regional transmission facility operations and, among other provisions, annually assess transmission equipment outage coordination, the long-term impacts of the ISO’s rescheduling of transmission-outage requests, and the accuracy of transmission congestion cost estimates. Other documents governing the ISO’s transmission-outage coordination include Market Rule 1, which sets forth the scheduling, other procedures, and certain general provisions applicable to the operation of New England’s wholesale energy markets; the Federal Energy Regulatory Commission’s Order No. 2000; regional and national reliability standards; and ISO operating documents. The Transmission Outage Coordination Working Group oversees outage coordination governing documents and goals.
Find out more about the ISO’s transmission-outage scheduling.
Recent Publications & Events
system operations, transmission planning