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U.S.-Canada Power Systems Outage Task Force Moves to Final Stage; Need to Strengthen Regional Grid Oversight Remains Paramount

The Department of Energy has announced that the U.S.-Canada Power Systems Outage Task Force will extend its comment period on the Interim Report: Causes of the August 14th Blackout in the United States and Canada to Feb. 11, 2004, in order to give the public full opportunity to present its views and recommendations. To date, the summary of comments has reached 67 pages.

The final report on the conclusions and policy recommendations associated with the blackout is still a month away. However, the lessons learned from the interim report continue to be debated as Congress, the Federal Energy Regulatory Commission and the electric power industry weigh the best policy approaches for assuring the reliability of the electric grid.

One key lesson from the interim report is that oversight of regional electricity grids should be more centralized and exercised over as wide an area as possible. This theme has resonated throughout the investigation and has been the subject of considerable focus. A second conclusion in the report is that early assertions that actions taken by competitive generators had a role in the blackout were erroneous.

Many causes of the blackout (listed below) have at their core the failure to recognize problems on the grid as they were spreading. This was due, in part, to inadequate communication protocols that restricted the ability of local control area operators and the regional system operator to observe the real-time status of transmission and generation facilities.

Of particular significance was the breakdown in the exchange and availability of system data regarding the condition of critical equipment and outage information. The breakdown was exacerbated by the regional system operator’s limited authority to take corrective actions.

For example, the report compared the “complexities” in sustaining reliable operations across the Midwest, in which the Midwest Independent Transmission System Operator (MISO) covers only a portion of the geographic area in question and is still in the nascent stage of operations, with the well-established system operations in the New England or Mid-Atlantic regions.
“In the Northeast Power Coordinating Council and the Mid-Atlantic Area Council, the independent system operator (ISO) also serves as the single control area operator for the individual member systems. In comparison, MISO provides reliability coordination for 35 control areas in the ECAR, MAIN and MAPP regions and [two] others in the SPP region…,” the report said.

The report notes that the lack of authority that MISO has over its control area members makes “day-to-day reliability operations more challenging.” It also cited deficient practices by FirstEnergy regarding traditional utility responsibilities as playing a role in the blackout (see below).

The report found that, “determining that the system was in a reliable operational state at that time is extremely significant for understanding the causes of the blackout. It means none of the electrical conditions on the system before 15:05 EDT was a direct cause of
the blackout. This eliminates a number of possible causes of the blackout, whether individually or in combination with one another, such as:

- High power flows to Canada;
- System frequency variations;
- Low voltages earlier in the day or on prior days;
- Low reactive power output from independent power producers (IPPs); and
- Unavailability of individual generators or transmission lines.”

The Task Force dismissed allegations from some quarters that competitive generators, also known as IPPs, or the presence of competition in electricity markets, played any role in the blackout or affected the reliability of the electricity grid.

“The suggestion that IPPs may have contributed to the difficulties of reliability management on August 14 because they don’t provide reactive power is misplaced,” the report said.

“What the IPP is required to produce is governed by contractual arrangements, which usually include provisions for contributions to reliability, particularly during emergencies. More importantly, it is the responsibility of system planners and operators, not IPPs, to plan for reactive power requirements and make any short-term arrangements needed to ensure that adequate reactive power resources will be available.”

The Task Force’s final report is expected in the next several weeks and will examine policy alternatives to help maintain the grid’s reliability looking forward. For more information, contact EPSA’s Jack Hawks at jhawks@epsa.org, or call (202) 628-8200.



Causes of the Blackout

The initiation of the Aug. 14, 2003, blackout was caused by deficiencies in specific practices, equipment and human decisions that coincided that afternoon. There were three groups of causes, as reported in the interim report:

Group 1: Inadequate situational awareness at FirstEnergy Corp. (FE). In particular:

A. FE failed to ensure the security of its transmission system after significant unforeseen contingencies because it did not use an effective contingency analysis capability on a routine basis.
B. FE lacked procedures to ensure that [its] operators were continually aware of the functional state of their critical monitoring tools.
C. FE lacked procedures to test effectively the functional state of these tools after repairs were made.
D. FE did not have additional monitoring tools for high-level visualization of the status of [its] transmission system to facilitate its operators’ understanding of transmission system conditions after the failure of [the] primary monitoring/alarming systems.

Group 2: FE failed to manage adequately tree growth in its transmission rights-of-way. This failure was the common cause of the outage of three FE 345-kV transmission lines.

Group 3: Failure of the interconnected grid’s reliability organizations to provide effective diagnostic support. In particular:

A. MISO did not have real-time data from Dayton Power and Light’s Stuart-Atlanta 345-kV line incorporated into its state estimator (a system monitoring tool). This precluded MISO from becoming aware of FE’s system problems earlier and providing diagnostic assistance to FE.
B. MISO’s reliability coordinators were using non-real-time data to support real-time flowgate monitoring. This prevented MISO from detecting an N-1 security violation in FE’s system and from assisting FE in necessary relief actions.
C. MISO lacked an effective means of identifying the location and significance of transmission line breaker operations reported by [its] Energy Management System (EMS). Such information would have enabled MISO operators to become aware earlier of important line outages.
D. PJM and MISO lacked joint procedures or guidelines on when and how to coordinate a security limit violation observed by one of them in the other’s area due to a contingency near their common boundary.