The electric utility industry over time developed planning, operating, and design standards to address customer expectations of reliable service. These standards were at first local in perspective but, as interties were built and the interdependent nature of the system became apparent, many of the standards were expanded to a regional and then a national perspective.
Transmission lines cannot be added helter-skelter based solely on the profits for the owner. Locations and designs for new substations selected by the distribution systems must recognize the future of the transmission system that will supply them. One cannot design a reliable low-cost automobile by having separate uncoordinated designs for the brakes, the transmission, the engine, and other essential systems. The same is true for the transmission system. It must be designed as an integrated whole.
Since the effects of electrical disturbances can spread over a wide, multistate region, the need for regional coordination in planning and operation is obvious. As the new market rules for the electric system are developed, the concern is that the rules in any one area do not lower the local reliability standards and thereby impact or impair the reliability of the grid.
Concurrently, over the last century and continuing to the present, customer expectations of reliable service have also increased. Outages which once were common place are now considered unacceptable. Momentary interruptions, which at one time were noticed by only a few customers, now impact many customers because of the widespread use of computers and other electronic devices.
Underlying the industry’s approach to reliability was the realization that its efforts should be multidimensional:
All reflect, in one way or another, a view of an acceptable level of reliability. Generation planning standards have, in the past, been tied to a statistical measure. Standards for operating the generation and transmission systems are based primarily on the collective judgments of utility personnel. Over the years, these standards have been accepted and legitimized by local, state, and national regulators in rate cases and in after-the-fact reviews of outages. In many of these reviews, customer complaints over service reliability and over costs have caused modifications to aspects of individual standards. For example, problems with restoration times in some areas after major storms have led to requirements for detailed and publicized restoration plans reflecting customer inputs.
Attempts have been made to determine and set the level of transmission system reliability based on the reliability of each of the components of the system. Although appealing in theory, this effort flounders on the magnitude and variations in equipment that constitute a power system. The system is designed to reflect good engineering judgment. For example, an engineer can select a number of designs for a new bulk power substation depending on its criticality. The planner could select a substation with a breaker-and-a-half arrangement, which provides more redundancy and, hence, a higher level of reliability than a ring bus design provides.
Some specific examples of major blackouts from which lessons have been learned are listed below. This is by no means a comprehensive list but it does illustrate that large-scale blackouts are not uncommon.
One finds in the literature discussions of the customer’s willingness to pay for a greater level of reliability. There are two ways to give greater levels of service:
In select circumstances, a larger customer may be able to have a higher level of local distribution service by providing that customer with another distribution feeder or transformer, but extending the option to the typical customer would become cost prohibitive if individual distribution facilities were to be targeted to individual customers. The same logic applies to the transmission grid. Additionally, trying to distinguish between customers at the transmission level during dynamic conditions where instability occurs would be impossible under many conditions.
If the reliability problem is one of adequacy, that is, insufficient resources, when operating personnel have time to take corrective action, customers willing to pay a higher rate could be given preference when adjustments have to be made to restore the load–generation balance. Individual customers also could arrange for their supplier to maintain additional generating reserves for them at added cost. The process of implementing such a plan could rely on either financial mechanisms or physical mechanisms to disconnect customers not opting for higher levels of reliability.
GENERATION:
Prior to the restructuring of the industry, generating capacity was traditionally installed to meet a statistically determined reserve requirement, that is, an amount of installed capacity over and above the expected peak load obligation of the supplier. The amount of required reserve was related to a probability of loss of load. The precise determination was tailored to each system and reflected its planning and operating philosophies. The determination usually reflected, for each year, statistics on the reliability of its existing individual generators, the expectation of hourly peak loads, the amount of aid available from nearby systems, intra area transmission capabilities, and various levels of remedial actions by operators.
In the evolving industry, the question is unanswered of whether the level of installed generation capacity should be a design requirement or should be market determined. NERC removed from its planning criteria a requirement for a targeted installed reserve, relying instead on a market mechanism to set the installed generation reserve level. A number of regional entities have implemented a required generation reserve obligation. NERC is revisiting the issue.
Another important consideration in the installed generation picture is the diversity of the fuel supply. Consistent with costs, a diverse fuel generation mix supplies an additional level of reliability.
Relying on any one type of fuel, whether hydro, nuclear, coal, oil, solar, or wind can expose the system to common-mode outages. As examples, hydro systems are exposed to the impact of droughts, whereas coal- and oil-fired systems can be impacted by a number of disruptions including worker strikes, disruption in boat deliveries of fuel, and freezing of coal piles in the winter. Solar and wind power can obviously be impacted by weather conditions.
TRANSMISSION:
Transmission systems must be optimized in three dimensions in order to achieve the necessary reliability and minimum costs for electric power. They should be optimized “geographically,” that is, the transmission system must meet the needs of all who are served by the synchronous network, not just the needs of the profits of any one system, any one area, or any one region. Included in geographic optimization, transmission facilities must have a certain degree of physical separation to minimize the potential for common-mode failures. They must be optimized “functionally,” that is the transmission system must meet both generation requirements and the requirements of the distribution systems that they supply. These requirements must be balanced on an overall basis.
Finally, transmission systems must be developed to meet needs over a significant period of time since they cannot be changed once constructed. Transmission systems must be developed to not only meet needs this year, but well into the future. They must be optimized “chronologically.” Transmission systems are aging and rapidly growing less adequate.
The average age for transmission lines, transmission cables, circuit breakers, switch gear, substations, transformers, and other equipment is approaching 30 years, with some key facilities more than 75 years old. Maintenance requires equipment to be taken out of service. Transmission outages on our existing systems can be expected to continue to increase. It is growing increasingly difficult to schedule such outages without taking large reliability risks or incurring large cost penalties due to the inability to deliver low-cost power.
DISTRIBUTION:
Planning and operation of the distribution system is still done according to the standards and practices of individual utilities and reflect local reliability requirements and cost considerations. The robustness of the supply to a congested urban area will be considerably greater than that to a rural farm district. However, oversight of the local utility’s performance is usually exercised by state regulatory authorities.
It is not uncommon for post incident reviews to be held by regulators after significant local outages. In many areas, the use of incentive rates of return reflecting distribution system performance is becoming popular. Utility equipment design practices reflect standards developed by national organizations such as the Institute of Electrical and Electronics Engineers (IEEE).
Transmission lines cannot be added helter-skelter based solely on the profits for the owner. Locations and designs for new substations selected by the distribution systems must recognize the future of the transmission system that will supply them. One cannot design a reliable low-cost automobile by having separate uncoordinated designs for the brakes, the transmission, the engine, and other essential systems. The same is true for the transmission system. It must be designed as an integrated whole.
Since the effects of electrical disturbances can spread over a wide, multistate region, the need for regional coordination in planning and operation is obvious. As the new market rules for the electric system are developed, the concern is that the rules in any one area do not lower the local reliability standards and thereby impact or impair the reliability of the grid.
Concurrently, over the last century and continuing to the present, customer expectations of reliable service have also increased. Outages which once were common place are now considered unacceptable. Momentary interruptions, which at one time were noticed by only a few customers, now impact many customers because of the widespread use of computers and other electronic devices.
Underlying the industry’s approach to reliability was the realization that its efforts should be multidimensional:
- Plan the system to have enough generation, transmission, and distribution capacity
- Design the system to reduce the probability of equipment failure
- Operate the system to remain within safe operating margins
- Be prepared to restore the system quickly, in the event of a supply disruption in all cases, the industry’s efforts involve a trade-off between reliability and costs.
All reflect, in one way or another, a view of an acceptable level of reliability. Generation planning standards have, in the past, been tied to a statistical measure. Standards for operating the generation and transmission systems are based primarily on the collective judgments of utility personnel. Over the years, these standards have been accepted and legitimized by local, state, and national regulators in rate cases and in after-the-fact reviews of outages. In many of these reviews, customer complaints over service reliability and over costs have caused modifications to aspects of individual standards. For example, problems with restoration times in some areas after major storms have led to requirements for detailed and publicized restoration plans reflecting customer inputs.
Attempts have been made to determine and set the level of transmission system reliability based on the reliability of each of the components of the system. Although appealing in theory, this effort flounders on the magnitude and variations in equipment that constitute a power system. The system is designed to reflect good engineering judgment. For example, an engineer can select a number of designs for a new bulk power substation depending on its criticality. The planner could select a substation with a breaker-and-a-half arrangement, which provides more redundancy and, hence, a higher level of reliability than a ring bus design provides.
Some specific examples of major blackouts from which lessons have been learned are listed below. This is by no means a comprehensive list but it does illustrate that large-scale blackouts are not uncommon.
- 1965 in Northeast United States
- 1967 in Mid-Atlantic United States
- 1977 in New York City
- 1978 in France
- 1987 in Tokyo
- 1997 in California
- 1997 in New Zealand
- 2003 in Northeast United States122
- 2003 in London
- 2003 in Denmark/Sweden
- 2003 in Italy
- 2004 in Greece
- 2005 in Australia
- 2005 in Moscow
- 2006 in Europe
- 2006 in Tokyo
- 2007 in Victoria, Australia
- 2007 in South Africa
- 2007 in Colombia
- 2008 in Brazil
One finds in the literature discussions of the customer’s willingness to pay for a greater level of reliability. There are two ways to give greater levels of service:
- Provide more redundancy of supply to one customer than to another
- In the event of a disturbance or insufficient capacity, disconnect or interrupt the customer who does not pay a premium rate for electricity
In select circumstances, a larger customer may be able to have a higher level of local distribution service by providing that customer with another distribution feeder or transformer, but extending the option to the typical customer would become cost prohibitive if individual distribution facilities were to be targeted to individual customers. The same logic applies to the transmission grid. Additionally, trying to distinguish between customers at the transmission level during dynamic conditions where instability occurs would be impossible under many conditions.
If the reliability problem is one of adequacy, that is, insufficient resources, when operating personnel have time to take corrective action, customers willing to pay a higher rate could be given preference when adjustments have to be made to restore the load–generation balance. Individual customers also could arrange for their supplier to maintain additional generating reserves for them at added cost. The process of implementing such a plan could rely on either financial mechanisms or physical mechanisms to disconnect customers not opting for higher levels of reliability.
GENERATION:
Prior to the restructuring of the industry, generating capacity was traditionally installed to meet a statistically determined reserve requirement, that is, an amount of installed capacity over and above the expected peak load obligation of the supplier. The amount of required reserve was related to a probability of loss of load. The precise determination was tailored to each system and reflected its planning and operating philosophies. The determination usually reflected, for each year, statistics on the reliability of its existing individual generators, the expectation of hourly peak loads, the amount of aid available from nearby systems, intra area transmission capabilities, and various levels of remedial actions by operators.
In the evolving industry, the question is unanswered of whether the level of installed generation capacity should be a design requirement or should be market determined. NERC removed from its planning criteria a requirement for a targeted installed reserve, relying instead on a market mechanism to set the installed generation reserve level. A number of regional entities have implemented a required generation reserve obligation. NERC is revisiting the issue.
Another important consideration in the installed generation picture is the diversity of the fuel supply. Consistent with costs, a diverse fuel generation mix supplies an additional level of reliability.
Relying on any one type of fuel, whether hydro, nuclear, coal, oil, solar, or wind can expose the system to common-mode outages. As examples, hydro systems are exposed to the impact of droughts, whereas coal- and oil-fired systems can be impacted by a number of disruptions including worker strikes, disruption in boat deliveries of fuel, and freezing of coal piles in the winter. Solar and wind power can obviously be impacted by weather conditions.
TRANSMISSION:
Transmission systems must be optimized in three dimensions in order to achieve the necessary reliability and minimum costs for electric power. They should be optimized “geographically,” that is, the transmission system must meet the needs of all who are served by the synchronous network, not just the needs of the profits of any one system, any one area, or any one region. Included in geographic optimization, transmission facilities must have a certain degree of physical separation to minimize the potential for common-mode failures. They must be optimized “functionally,” that is the transmission system must meet both generation requirements and the requirements of the distribution systems that they supply. These requirements must be balanced on an overall basis.
Finally, transmission systems must be developed to meet needs over a significant period of time since they cannot be changed once constructed. Transmission systems must be developed to not only meet needs this year, but well into the future. They must be optimized “chronologically.” Transmission systems are aging and rapidly growing less adequate.
The average age for transmission lines, transmission cables, circuit breakers, switch gear, substations, transformers, and other equipment is approaching 30 years, with some key facilities more than 75 years old. Maintenance requires equipment to be taken out of service. Transmission outages on our existing systems can be expected to continue to increase. It is growing increasingly difficult to schedule such outages without taking large reliability risks or incurring large cost penalties due to the inability to deliver low-cost power.
DISTRIBUTION:
Planning and operation of the distribution system is still done according to the standards and practices of individual utilities and reflect local reliability requirements and cost considerations. The robustness of the supply to a congested urban area will be considerably greater than that to a rural farm district. However, oversight of the local utility’s performance is usually exercised by state regulatory authorities.
It is not uncommon for post incident reviews to be held by regulators after significant local outages. In many areas, the use of incentive rates of return reflecting distribution system performance is becoming popular. Utility equipment design practices reflect standards developed by national organizations such as the Institute of Electrical and Electronics Engineers (IEEE).