Midwest ISO on Surviving the Summer of 2000: A Summit on Reliability.

Business Editors

WASHINGTON--(BUSINESS WIRE)--May 31, 2000

Text of speech delivered by Matthew C. Cordaro,

Ph.D., President & CEO, Midwest ISO 

Surviving the Summer of 2000: A Summit on Reliability

(Sponsored by the Edison Electric Institute and Energy Daily)

May 31, 2000

Washington, D.C.

RELIABILITY-WRAP UP:

OUTLOOK FOR THE SUMMER OF 2000

I am grateful for this opportunity to speak to you. As the CEO of the nation's largest ISO but one that is almost exactly one year from initial operation, I am in a somewhat ambiguous position. After more than thirty years in many aspects of the electric utility business, I know better than to make absolute predictions.

However, based on that experience, I can review what has happened, be a careful observer this summer, and suggest the ways I believe that the Midwest ISO will have a positive effect on future reliability.

I feel a little awkward quoting a politician, but Adlai Stevenson was right when he said, "We can chart our future clearly and wisely only when we know the path that has led to the present." For that reason to maintain a reliable supply of electricity in the summer of 2000 and beyond, we have to look back at last summer and what led up to the problems faced by providers and consumers.

The North American Electric Reliability Council (NERC) has documented system conditions that occurred during the summer of 1999 in their post-seasonal assessment. Going into that summer, there was an expectation, based on the information received from the regions, that conditions would be tight but manageable. Unfortunately, that turned out be an overly optimistic view.

As the summer unfolded, a combination of events contributed to problems in various parts of the Eastern Interconnection.

In summary, there were:

-- Above normal temperatures and humidity early in the season;

-- Insufficient operating reserves in early June in the

Northeast because several generating units were completing

their pre-summer maintenance programs and not available.

-- Fortunately, adjoining regions provided emergency

support, which averted the need to implement load

shedding.

-- High loading periods in late July that coincided with the

loss of either generation capacity or transmission

facilities in the Southeast.

-- The result was shedding of firm load on two occasions.

-- Atypical loading patterns on the transmission grid combined

with a lack of local voltage support that led to a number of

days in June, July and August when low voltage conditions

were experienced in the Northeast and Southeast.

-- The lack of local voltage support was due to either

generation not being available or generators providing

less than expected voltage support. And finally

-- The much-publicized distribution problem in the Chicago and

New York City areas, which resulted in the localized loss of

load.

Each of these events reflects some unique conditions that contributed to the overall problem; for the most part unusual weather conditions and equipment failures in addition to unanticipated conditions on the grid. Subsequent analyses of the events revealed that system operators could not respond effectively in some cases because they were unprepared to handle such events, and because in other cases they had incomplete information.

In order to anticipate what problems could arise in the summer of 2000, we need to be cognizant of system conditions that led to the 1999 problems and see what steps can we need to take to avoid similar occurrences. Earlier today we heard about the initiative co-sponsored by the Electric Power Research Institute (EPRI) and NERC where workshop participants identified areas for improvement this past spring.

At the risk of repeating what may have already been said, I will briefly summarize the three areas where workshop participants made recommendations for operational improvements.

The first recommendation was that the control area operators and security coordinators must receive timely and complete operating information and have the ability to use it in the analysis of system conditions. Operating personnel must know their own operating reserves and the amount of reserves available in adjoining areas, and must use realistic reactive limits in their power flow analysis. NERC's post-seasonal assessment of widespread low voltage problems in MAAC, ECAR, SPP, and parts of SERC identified the need for improved modeling, planning, and operating procedures related to voltage control.

Second, they recommended that there be improved coordination of activities among various control area operators and security coordinators. Effective coordination recognizes the existence of physical limits and requires an agreement between all parties to respect those physical limits. A transmission provider's flow-based review should include the limits on other transmission provider constrained facilities. When granting transmission service, it is no longer acceptable to base that decision solely on the availability of contract capacity which ignores the actual flows.

The workshop participants also concluded there was a need for improvement in training for operating personnel and that they must have the proper tools and remedial actions available to them. As the number of transactions has multiplied and the number of parties involved in those transactions increased, control area operators are spending more time on scheduling activities and less on ensuring the security of the system. Electronic scheduling is being developed as an alternative to the addition of operators and schedulers in control rooms.

There needs to be a conscious effort to adequately train operating personnel when such new processes are introduced. All too often, there is a fixed deadline for implementing new processes like electronic scheduling, and the testing and training phase gets reduced or eliminated in an attempt to get the project back on schedule.

The participants in the EPRI and NERC co-sponsored workshop did a good job identifying areas of improvement to enhance system security for summer 2000 and beyond. But we must now ask the question -- What is the best way to proceed in response to their recommendations?

Clearly, in the short run, it is the NERC security coordinators and the control area operators who will have to make the improvements. However, control area operators have limited capability to solve a regional or widespread problem; and while security coordinators may cover multiple control areas, many do not sell transmission service. What is needed is a combination of these within a large entity that is responsible for both functions -- an RTO.

Even if a particular control area were in a position to perform both a security function and administer a transmission tariff, it would still be limited by the size of the area and the information available to it from other areas. The only current exception to this constraint is the PJM-ISO, which does operate as a single control area.

The Midwest ISO control areas cross the boundaries of three NERC reliability councils -- ECAR, MAIN, and MAPP. All three have already performed seasonal security assessments that identify anticipated problems during the upcoming peak season. Based on the most recent combined NERC assessment, there is guarded optimism that the bulk transmission system in the Midwest is capable of handling this summer's demands for electricity.

The Midwest's control areas are relatively optimistic about conditions this coming summer because of improvements that have been made since last summer and because they will be less reliant on generation outside the region.

Physical improvements to the bulk transmission system that are in place include installation of three new Phase Angle Regulating transformers on the Michigan-Ontario interface to reduce unscheduled flows from Ontario into Michigan. The Michigan-Ontario interface and the Queenston Flow West interface in Ontario suffered multiple Transmission Loading Relief (TLRs) curtailments in past summers because of large parallel flows.

Also, shunt capacitors have been installed in the central Ohio and eastern Indiana areas to mitigate voltage drop conditions that can occur with the concurrent loss of AEP's Marysville 765-345KV transformer and Conesville generating plant.

If plans to complete ComEd's 345KV double circuit Lockport-Lombard line ahead of schedule succeed, that will improve import capability to the MAIN region and that portion of Wisconsin that is in the MAIN region.

An essential component of greater system security in the Midwest this coming summer is less reliance on generation outside the region than in past years. The nuclear plants in MAIN are in-service or expected to return from refueling before the summer peak. Also expected to be in service before the summer peak is AEP's Cook unit 2, which will provide 1060MW connected at 765KV that was not available last summer. Cook unit 1 will be offline. In addition, over 3000MW of new merchant plant capacity is scheduled to be available this summer in ECAR, and another 3000 in MAIN.

Even with these improvements, unplanned power plant outages or large unanticipated power flows within or through the regions could result in curtailments to maintain transmission system security. Unusual operating conditions this spring have already resulted in the need to make firm curtailments to some point-to-point transmission service.

In summary, there are reasons to expect the availability of electric power in the Midwest to be more stable than it was last summer. However, there is still reason to be concerned about the outlook for Summer 2000. There is no question that to many of those responsible there are still specific situations that could affect the system adversely.

For example, if ComEd is not able to complete the double 345KV circuits between Lockport and Lombard, Wisconsin's capability to import power is limited to 850MW from the West and 0MW from the South, if ComEd operates its units in the most economical manner. However, if an entity is willing to pay ComEd to operate less economically, up to 900MW can be received from the South by a re-dispatch of ComEd units. With the new lines, 1800MW will be available without sacrificing economy.

Additionally, the return to service of Cook 2 without Cook 1 creates a flow bias from the 765KV to the 345KV adversely impacting loadings on the Dumont and Cook 765-345KV transformers that could reduce transfer capability to the North and West.

While the Phase Angle Regulating (PAR) transformers on the Michigan-Ontario interface will mitigate unscheduled flows from Ontario into Michigan, they will increase the loadings on other critical facilities by redirecting flows that would have gone around the north end of Lake Erie into Michigan. The Lake Erie Security Process Working Group is developing an overall operating strategy to coordinate all control devices in the area around Lake Erie.

The merchant plant additions in ECAR and MAIN approximately match the ECAR and MAIN load growth projections for summer 2000. If the 6000 MW of merchant plant capacity being added is not in service by this summer, there will be no margin to allow for extremely hot weather or unplanned equipment outages. The return of the nuclear plants that were unavailable last year alone cannot meet the demands resulting from extreme conditions of heat and humidity.

And just to really test our mettle, limited snowfall this past winter and below normal rainfall this spring in the Midwest means that water levels are low in many of the region's lakes and rivers. This could result in limited output by those generating stations that depend on them for cooling water.

Looking toward the future, these are the types of problems that the Midwest ISO will have to deal with when it is fully operational in the last quarter of 2001. Although we cannot control temperature, ensure adequate rainfall -- and even an Act of Congress will not alter the laws of physics -- we will be endeavoring through integrated operation of existing resources and coordinated planning of needed system improvements to provide the infrastructure to maintain reliability and support a robust market in electricity.

No single entity exists today with the size and scope to perform such a function in the Midwest. When the Midwest ISO is operational in 2001, we will act as the security coordinator and tariff administrator for the entire MISO region that currently encompasses close to 300,000 square miles of service territory and will be even larger following our merger with the Mid-Continent Area Power Pool (MAPP).

Our control center under construction in Central Indiana will house a state-of-the art computer system that will be used to monitor real time information from both MISO members and adjoining regions. This integrated control center system (ICCS) will provide a wide-area view and will be tightly integrated with the system used to administer the regional transmission tariff.

The MISO has committed to perform a flow-based review when selling transmission service. Its computer system will perform state-of-the-art voltage analysis in both real time and when selling transmission service. We will monitor operating reserves and use realistic reactive limits.

The MISO will also coordinate transmission maintenance and be responsible for the development of the overall transmission plans.

We recognize the importance of using automated processes and tools that minimize the number of employees needed while still providing the response times needed by the market. Our computer system will include a back-end processor connected to the OASIS site to automate the selling of transmission service while honoring the provisions of the tariff. An electronic scheduling system will also be included in order to automate the entire scheduling process. The electronic scheduling system will reduce the coordination effort required of control areas, will provide a single location for schedule checkout and billing, and will be integrated with both e-tagging and the OASIS.

There is no doubt in my mind that during the summer of 2000 there is still the potential for a combination of events that could lead to occurrences of low voltages; and periods of time when certain loads may have to be shed. Portions of the Eastern Interconnection and California have already experienced some emergency notices in the first couple of weeks of May because of unusually warm weather while generators were still completing their spring maintenance cycles.

On the plus side, I am confident that the industry is better prepared to deal with this situation because of what was learned in 1999. I look at 2000 as a transition period where RTOs will be getting their operating organizations and systems in place to improve the reliability of the grid for the twenty-first century.

Moving beyond the summer 2000, I am convinced, as is FERC, that large RTOs are essential to minimize impediments to improved reliability and support a robust market in electricity. Exactly how many RTOs or exactly what configuration is best remains to be seen. That we may not have found the perfect solution should not deter us from moving ahead.

Nor should we hesitate because there are issues that we really haven't tackled yet. Agreement on the need for coordinated planning of additional transmission is only a first step. There are some pretty high hurdles before customers can reap the benefits. I know from recent, personal experience that it is not easy to site a new transmission line even when it will directly benefit the community where it is to be located. Generators, transmission providers, and end-users will all have a stake in effectively communicating the need for new lines as well as the answers to questions about financing, health and environmental concerns, impact on real estate values, and why don't you put it someplace else.

We can improve reliability and control costs; all it takes is intelligence, foresight, and teamwork.