tion (SCADA) systems collect and transmit this information to control centers.²⁹ In most existing substations, the data can be sampled every few seconds, entered into a remote terminal unit (RTU), polled by the SCADA, and sent to the control center over relatively slow communications channels—usually microwave. In modern substations, some of which are already in place, the substation control and protection system is digital and the connectivity is through a local area network (LAN) within the substation. Data can be sampled many times per second, rather than once every few seconds. Most of the substation’s controllers and protection systems, known collectively as intelligent electronic devices (IEDs), are based on microprocessors, as are recording systems such as fault recorders and sequence-of-events recorders.

Monitoring of the state of the transmission system is best if the high-voltage substations are equipped with measurement systems that sample at rates of 60–120 times per second³⁰ and incorporate global positioning system (GPS) signals.³¹ Although the individual hardware costs of these measurement units are now very modest,³² the cost of retrofitting them into the thousands of existing substations will be significant.

There are approximately four times more low-voltage distribution substations than there are high-voltage substations. Although the sampling speed does not need to be as large, high-bandwidth communication will be needed in order to use these data for system control.

Existing customer billing meters could be replaced with microprocessor-based meters which could provide the customer with new buying options such as time-of-day pricing, and could increase end user efficiency. These meters could also allow control signals from the power company to be brought directly into appliances and equipment on the customer side for load management.