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Prepared Witness Testimony The House Committee on Energy and Commerce
Blackout 2003: How Did It Happen and Why?
Full Committee on Energy and Commerce
Mr. Gordon van Welie
Introduction and Background Good Morning, Mr. Chairman and Members of the Committee. My name is Gordon van Welie, and I am the President and Chief Executive Officer of ISO New England Inc., the independent system operator of the bulk power grid that serves the six New England states. I am accompanied today by Stephen G. Whitley, ISO New England's Senior Vice President and Chief Operating Officer. By way of background, I joined ISO New England in 2000 after serving as Vice President and General Manager of the Power Systems Control Division of Siemens Power Transmission & Distribution LLC, where I worked closely with electric utilities on control systems involving generation and power supply reliability. An electrical engineer with a graduate business degree, I have twenty years of experience in the electric power industry in both the United States and South Africa. Steve Whitley has been in charge of ISO New England's operations since 2000. He was previously with the Tennessee Valley Authority ("TVA") for thirty years, starting as an electrical engineer and progressing through a variety of positions which gave him responsibility for control area operations, power supply, economic dispatch, system protection, transmission security and services, and dispatching for TVA's six-state service territory. He was also in charge of the planning, design, and construction of the TVA transmission system. He is currently Chairman of the Electric Power Research Institute Grid Operations, Planning and Markets Working Group. Steve is available for comment today regarding operational matters, including the effect of the blackouts in our region and ISO New England's response thereto. ISO New England's Role as Independent System Operator ISO New England, an independent, non-profit corporation, is responsible for the reliable daily operation of New England's bulk electric generation and transmission system, which supplies approximately 14 million people. The system has an installed capacity of more than 31,000 megawatts. There are more than 350 generators and plants and over 8,000 miles of high voltage transmission lines in our region, and we have 12 interconnections with neighboring systems in New York and Canada. ISO New England's mission also includes fair and efficient operation of the region's $4.5 billion wholesale electricity marketplace, and it has been tasked by the Federal Energy Regulatory Commission ("FERC") since 2000 to assess and plan for the regional system's short-term and long term reliability needs. Roles and Responsibilities in the Electric Power System Before addressing the Committee's specific questions, comment on today's restructured electric industry might be helpful. Different entities handle different functions in today's restructured electric industry. In New England, which constitutes one of the most mature and advanced electricity markets in the country, there are generators, transmission and distribution companies, marketers and the independent system operator. Generation is increasingly provided by unregulated entities who compete to sell their power into the marketplace, hoping to achieve satisfactory returns on their unregulated investments in generating plants. Transmission and distribution companies distribute electricity to customers on a regulated basis, using their own transmission and distribution lines, including protective devices which are designed to protect equipment in the event of power system disturbances and keep disturbances from spreading. These utilities earn an allowed return from rates which are a blend of transmission rates set by FERC and distribution rates established by state regulators. Marketers buy and sell generation to transmission and distribution companies. An independent system operator, sometimes operating through satellite control centers with differing degrees of authority and autonomy, administers the bulk transmission grid and dispatches power from generators onto the grid in accordance with system demands and reliability criteria. With several different players having replaced yesterday's vertically integrated utility, the need for clear delineations of responsibility and authority today is an increasingly pressing matter. The New England Power System Much of the bulk power system in New England was constructed on sound engineering principles in the late 1960's, and while it was constructed to accommodate future growth, the demand for power and the demands placed on it by competitive markets have outstripped the system's design. The market structure we administer in New England has been successful in attracting approximately 10,000 megawatts of new generation to the region since 1999, representing almost a third of the system load in peak season, and we believe the new standard market design we have just recently implemented provides more accurate market signals to incent the location of generation nearer to load centers. The market signals provided by the standard market design also more accurately value the availability of generation supply, such that in times of scarcity, wholesale market prices rise, which in turn creates an incentive for the building of new generation capacity. New generating plants sited in New England over the past five years have significantly increased regional generating capacity, but these plants have typically been built in less populous areas far removed from areas that are in the most need of generation. While this suggests the need for added transmission capability to get surplus power to customers, the increased investment in generation has not been matched by investments to upgrade the transmission grid. Our major problem in New England, and we are typical of many areas in the country, is therefore in delivering the power from generators to customers. Surplus generating capacity is not helpful if transmission cannot take it where it is most needed, nor can the economic benefits of a competitive market for electricity be fully realized if surplus generation cannot be accessed due to transmission constraints. Our ongoing planning efforts, which result in an annual planning document known as the Regional Transmission Expansion Plan, have identified three particular areas where major transmission improvements are needed: Southwest Connecticut, Northwest Vermont and Greater Boston. Nearly a billion dollars in new transmission projects are underway or planned to meet the needs of these transmission-constrained areas. Experience tells us that efforts to improve the transmission grid will run into problems. First, existing incentives for investment in new transmission may be inadequate in terms of return, certainty of recovery, and uncertainty of approval. Transmission investment must be made more attractive and process barriers must be reduced. Second, the regulatory approval process has become too long, too expensive and too uncertain. Potential transmission applicants need greater assurance that the approval process will be fair and efficient. Third, reliability has become politicized, and state regulatory bodies who must approve or deny applications for new transmission facilities and other equipment installations come under tremendous pressure in dealing with such applications. Politics should not be allowed to detrimentally affect reliable service. The Transmission Siting Approval Process As the Committee has invited comment which might help to prevent future disruptions, and as we believe siting and regulatory approval processes are relevant to efforts to install new transmission infrastructure needed for system reliability, we would like to offer observations and suggestions based on recent and pending regulatory proceedings in our region. A. The Siting Approval Process Needs More Efficiency In July, Connecticut regulators approved a 22-mile transmission line crossing five towns, the first leg of a 345kV loop which will relieve system inadequacies in Southwest Connecticut, the most affected area in our region during the blackouts. Despite general acknowledgement of the need to improve electric service in Southwest Connecticut, the transmission application was not well received by towns and residents along the proposed route when Northeast Utilities began pre-application consultation activities with municipalities in July, 2001. The result, after formal filing of the application in October, 2001, was grass roots pressure on the siting process, executive and legislative involvement in transmission siting issues, a one year legislative moratorium on the proceeding, a task force to review the siting of transmission facilities, and the passage of legislation which will add considerable time, expense and uncertainty to the transmission siting approval process in Connecticut. The line was ultimately approved in July, 2003 -- almost three years after it was filed. And this was after a hearing schedule which spanned several months, consideration of more than twenty proposals, and eventual consent by the applicant to use a less preferred underground cable technology for a considerable portion of the route. An approval proceeding involving the second leg of the 345kV loop, a 52 mile line, lies ahead. The full 345kV loop serving Southwest Connecticut will not be completed until 2008 at the earliest. In the meantime, customers will continue to be exposed to the possibility of service disruption and higher prices. There is clearly a need for a speedier, more efficient process for siting approval, especially as siting decisions in one state can affect the operation of the electric grid in several other states - as should be apparent from the events of August 14th. Since bulk transmission facilities operate in interstate commerce, it is appropriate to provide that if state regulators are unable to conclude siting proceedings within a certain amount of time, federal authorities should take over the process. States should certainly retain primacy in approving transmission siting, but we favor federal backstop authority when states cannot act in a timely manner. B. Mandatory Reliability Standards Will Benefit Regulators by Depoliticizing Reliability ISO New England contributed to the siting approval proceeding for the first leg of the 345kV loop in Connecticut by providing reliability studies comparing the ability of different proposals to meet the need for improved electric service in Southwest Connecticut. We used national reliability standards adopted by the North American Electric Reliability Council ("NERC") and regional standards adopted by the Northeast Power Coordinating Council ("NPCC"). Opponents of the proposed transmission line included state officials and affected towns who claimed that our reliability studies were flawed because our test cases assumed, in their estimation, that too many generator or transmission line outages could occur at the same time, thus subjecting the various alternatives under study to too many contingencies and overstressing them to unrealistic extremes. Even when opposing experts conceded that it was appropriate to overstress the system for planning purposes, they asserted that transmission lines should not be designed to deal with the more severe multiple contingency scenarios envisioned by planners. In effect, Connecticut siting regulators were being urged by governmental officials to approve a lower voltage transmission line than necessary to meet reliability standards. I mention this not as criticism of any particular party's right to present its views, but as an indication of the need to adopt mandatory reliability standards in order to fortify state siting officials against localized pressures to do less than what is necessary to assure reliability. I applaud the Connecticut Siting Council for reaching an appropriate decision in the face of considerable opposition, but mandatory reliability standards would have made their decision easier and should facilitate decision-making in other areas of the country. Responses to Committee Questions Q. What exactly were the specific factors and series of events leading up and contributing to the blackouts of August 14? As the blackouts began in other regions, it is difficult for me to speculate on the specific factors which contributed to them. I assume others are better able than I am to answer this question. As the Committee undoubtedly knows, the Department of Energy and the North American Electric Reliability Council ("NERC") are engaged in an intensive fact-gathering exercise to determine what happened, and I will be interested in their conclusions. Q. At what time did your company first become aware that the system was experiencing unscheduled, unplanned or uncontrollable power flows or other abnormal conditions and what steps did you take to address the problem? Were there any indications of system instability prior to that time? ISO New England control room operators first became aware that the system was experiencing a disturbance at 4:10 pm (EDT). There had been no prior indications of problems on the New England system prior to that time.
Q. Which systems operated as designed and which systems failed? In the recent disturbance which affected much of the Northeast, we were able to isolate most of the New England grid from the rest of the power system. The New England system was designed and maintained properly and worked as expected. Automatic protective relay devices on the transmission lines opened as intended, interrupted the transmission lines and opened the ties interconnecting our system with New York. This mechanical action separated most of New England from the disturbance to the west. While power was lost in limited areas, the rest of the system was rebalanced and saved from a system-wide collapse. Of the limited areas in our system which were affected, I would suggest that Southwest Connecticut was hardest hit because its transmission system is the weakest part of our New England system and it could not withstand the disturbance. The 115kV transmission lines serving Southwest Connecticut cannot carry as much load as the 345kV lines serving the rest of Connecticut. Thanks to extensive training in restoration and an annual system restoration procedure exercise, our operators were well prepared to bring back power. Our operators adhered to their training and used the tools available to them within clearly established lines of authority, and we were able to restore power to many customers in the limited areas in our system which were affected, mainly in Southwest Connecticut, within approximately 12 hours. I regret that any customer lost power, but I believe ISO New England did an outstanding job under the circumstances of August 14. The coordination within the Northeast Power Coordinating Council ("NPCC") was excellent throughout the disturbance and system restoration. Q. If events similar to those which happened on August 14, 2003 had happened a year ago, would the results have been the same? If similar events occur a year from now, do you anticipate having in place equipment and processes sufficient to prevent a recurrence of the August 14 blackout? Answering from the perspective of New England, being at the eastern edge of the disturbance, I would have expected similar results in our region if a similar set of events had occurred elsewhere a year ago. The protective relays in our system were audited by NPCC approximately a year ago and were in good condition, so I assume they would have worked. However, Southwest Connecticut's dependence on a 115kV transmission system would probably have made it similarly vulnerable. We have been deeply concerned over the last few years that Southwest Connecticut could experience significant outages because it is a major load center served by a very constrained transmission system. We simply cannot provide reliable service to a 3,500 megawatt load center with a 115kV transmission system. Until 2008, five full years from now, when installation of the full 345kV transmission line will hopefully be completed in Southwest Connecticut, we will continue to be concerned that this area could experience significant outages. As load continues to grow, it is my belief that events similar to those which occurred on August 14 could have similar effects in our region: most of the system would separate from adjacent systems, but Southwest Connecticut would remain challenged by its weak transmission system. Southwest Connecticut's growing demand for electricity has outpaced ISO New England's ability to assure reliable service to the people who live and work there. We have also identified Northwest Vermont and Greater Boston as areas of concern. I strongly support the regular maintenance program within New England and administered by NPCC to assure that all protective equipment is properly installed and in proper working order, and I advocate the continued thorough review and standardization of operating procedures and training so that both operators and equipment will be prepared to respond in the event of a recurrence a year from now. As noted, 345kV lines in certain areas of concern will not yet be in place next year but will eventually help in the event of a recurrence. Please see my comments below in response to the Committee's question regarding prevention of similar incidents in the future. Q. What lessons were learned as a result of the blackouts? ISO New England and the rest of the electric power industry in the Northeast are attempting to reconstruct exactly what happened, and the Department of Energy and NERC are working together to determine the causes of the blackout. We are still very much engaged in a learning exercise, and it may be appropriate to revisit this question after all the facts are established. In the meantime, we should probably all look closely at the way we operate our systems, the territory they cover, the decision-making structure and lines of authority, and applicable operating procedures and reliability standards. The operators at ISO New England know what the security limits are on the transmission system - thermal, voltage and stability. This knowledge is derived from both "on-line" and "off-line" software tools which are run periodically, in order to determine the security limits of the power system under a variety of operating conditions. The operators are trained to proactively operate within those limits in real time operation. They take immediate action when loading exceeds those limits, even if this means curtailing demand in a local area. I believe this operating posture was key to New England's ability to minimize the August 14 disruption and stay balanced following separation from the rest of the eastern power grid. Q. How can similar incidents in the future be prevented? The short answer is to increase the reliability of the electric system and to operate the system in a secure and analyzed state. We have several thoughts about how this objective should be accomplished. Upgrading infrastructure is an obvious priority, but the answer goes beyond that. We know that there are limits to public acceptance of transmission facilities and other infrastructure necessary for a reliable and uninterrupted supply of electricity. It is not realistic to expect reliability enhancements without infrastructure upgrades or improvement without investment, but aside from infrastructure issues we have a duty to maximize our ability to operate whatever system we have as reliably and cost effectively as we can. To this end, I would like to offer four policy recommendations which I believe will greatly improve the reliability of the bulk power grid. Policy Recommendations 1. There must be a single entity with clear operational responsibilities and authorities for the bulk power system in a region. ISO New England operating as a single control area fulfills this need for New England. Our area in New England is a manageable size, enabling us to operate with only four satellite control centers, without the need to yield operating autonomy to them. They provide information to the operators in our main control center, and the operating decisions are made by ISO New England. Creating a Regional Transmission Organization in New England will further define our operational responsibilities and authorities. In other areas of the country, size and operational responsibilities and authorities become very important considerations in creating and defining Regional Transmission Organizations. While it is difficult to describe what the "right" size of a regional area of control should be, size is nonetheless a very important consideration in creating Regional Transmission Organizations. A regional area of control must be large enough to track regional flows and have sufficient operational flexibility to be able to deal with a reasonably wide range of contingencies. However, as we have recently experienced, in an extreme emergency, operational control will rest on the shoulders of one or more human operators and, therefore, the area to be controlled cannot be too large. The accuracy of software tools supplied to operators are dependent on complex mathematical models, which in turn rely on accurate data being transmitted from the field. In emergency situations, these data sources can be compromised, thus further increasing the dependency on human interaction. In summary, there is a trade-off between size (in terms of regional "vantage point") and complexity, and achieving a reasonable balance between the two is paramount. In addition to size, clear operational responsibilities and authorities must be well defined. There must be documented a clear split of responsibilities between the Regional Transmission Organization and the transmission entities (including satellite control centers or control areas). Lack of clearly defined operational responsibilities between the Regional Transmission Organization and the participating transmission entities can be a major potential source of operational risk, particularly under emergency conditions. Cascading outages occur, as you have seen, in a matter of moments. There is no time for questions of overlapping responsibility, confusion of roles, or hesitant action. If you have only seconds to prevent voltage collapse and cascading, decisions regarding the redispatch of generation, reconfiguration and balancing of the system, and curtailment of transactions and firm load cannot be scattered among the system operator, satellite control centers, utilities and independent transmission companies. The control of the transmission system must be consolidated in one Reliability Authority which would not delegate its duties to underlying authorities and thus could be held clearly accountable for system operation. For this reason, we believe that reliability would be enhanced through proper implementation of the Regional Transmission Organization concept. The RTO, as an independent transmission provider, would have clear operational control and authority over the transmission grid in its region. The separation between planning for system reliability and implementing system reliability measures would be significantly narrowed, if not eliminated. 2. Reliability standards must become mandatory and operating procedures must be standardized. Adequate reliability standards do exist today, but to ensure regional reliability they must have teeth. Reliability standards must become enforceable, with penalties, to assure that appropriate, modern equipment will be in place, that it will be properly maintained by trained personnel, and that there will be enough personnel to operate and maintain the system in accordance with reliability standards. Clear standards for transmission operation are also necessary, with standardized grid management rules and operational procedures, including adequate security limits, so that operators in every region will be better positioned to coordinate actions with their counterparts elsewhere in response to critical events. Right now we have procedural seams between our regions, and standardized operating rules would help eliminate them. I would be glad to volunteer the procedures utilized by ISO New England as a detailed and well-proven model. A core principle embodied in these procedures is to operate the power system in a secure and analyzed state. To supplement the concept of seamless operating procedures, I would also suggest an overview system whereby the status of the entire grid, including actual voltages, power flows and scheduled transactions could be monitored at the NERC and provided to each RTO Reliability Coordinator in real time. Referring again to the incredible speed with which voltage collapse can cascade into widespread outages, the first line of defense protecting one system from a disturbance in an adjoining system is mechanical. Mandatory reliability standards will encourage Reliability Coordinators and control areas to assure the readiness of their security analysis and alarm systems at all times. Mandatory standards will promote proper maintenance to assure that such important equipment as protective relay devices will always respond to transmission trouble and interrupt faulted lines before they cascade into other systems. If automated protective mechanisms fail to contain a system collapse, the second line of defense against cascading outages is human, and the likelihood of appropriate human response will be greatly increased by standardized operating procedures. Control room operators must take immediate action to get and keep the system within safe operating limits. This will prevent cascading blackouts. They must be empowered to immediately adjust any or all generating and transmission resources. They must also be empowered to immediately take load off the system. Operators must have a reflexive mastery of these procedures and must follow them in times of crisis with confidence in the knowledge that their counterparts in adjacent systems are following the same procedures. 3. We must have new infrastructure, which means that we must provide new incentives for transmission owners to build new infrastructure. Right now the task of gaining approval for new transmission infrastructure is discouragingly costly, uncertain and time-consuming, with no assurance of regulatory approval and cost recovery, and clearly, the financial incentives for undertaking the task may not currently match the risks involved. Ways must be found to reduce process disincentives and assure appropriate investment incentives, including tax credits, to make transmission investments more attractive and to assure recovery of investment and an adequate return. Finally, it must be clearly understood that there will be significant costs for improving the reliability of the electric system, and that the costs will have to be paid by someone, most probably the customer who will ultimately benefit from both increased reliability and access to competitively priced electricity in an expanded marketplace. It is important to note that transmission infrastructure cannot, and should not, occur on an ad-hoc basis. It should occur pursuant to a deliberate evaluation of the overall adequacy of the bulk power system in a region, taking into account inter-regional dependencies. This can only be achieved with a systematic planning process, such as that currently employed by ISO New England and a number of other system operators. Such a planning process should also be mandatory, since it becomes the basis for exposing power system weaknesses on both a regional and national basis. 4. A balance must be struck between the interests of states to site transmission facilities and the importance of such facilities in the reliable operation of the regional electric system. A state should have the first opportunity to act upon any application for siting approval. However, in instances of serious transmission constraint or congestion, appropriate federal authorities should be empowered to issue permits for new transmission facilities if the public interest requires such a facility to relieve constraints and a state has failed within a reasonable time to act upon a permit application or has unreasonably conditioned approval of the project. Thank you for your consideration.
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