System operators coordinate their actions through regional reliability councils of the North American Electric Reliability Corporation (NERC). NERC’s mission is to ensure that the electrical transmission grid in North America is reliable, adequate, and secure. NERC is an umbrella organization made up of six regional reliability councils. The entities that belong to the reliability councils account for almost all of the electricity supplied in the U.S., Canada, and a portion of Baja California Norte in Mexico. NERC sets forth general standards for operations to ensure reliability, and each reliability council then adapts these standards for its own system operators to follow. Historically dominated by utilities, the regional councils opened their memberships to independent power producers and power marketers in 1994. Members now include transmission owners, ISOs, load serving entities, utilities, merchant generators, marketers, end users, and government agencies.
The Regional entities are:
- Midwest Reliability Organization (MRO)
- Northeast Power Coordinating Council (NPCC)
- ReliabilityFirst (RF)
- SERC Reliability Corporation (SERC)
- Texas Reliability Entity (TRE)
- Western Electricity Coordinating Council (WECC)
In the U.S., the Energy Policy Act of 2005 gave the Federal Energy Regulatory Commission (FERC) jurisdiction over reliability standards with the intent of changing them from voluntary to mandatory. In 2006, FERC certified NERC as the Electric Reliability Organization (ERO) responsible for developing and enforcing mandatory electric reliability standards under the Commission’s oversight. In 2007, NERC began the process of filing reliability standards at FERC, and many of these were approved late in the year.
Reliability standards set forth by the regional councils require control areas to maintain a balance between generation and load under normal conditions, re-establish the generation-load balance within 15 minutes of unexpected failure of a generator or transmission line, maintain frequencies and voltages within specific bounds, maintain generation reserves to respond to any disturbances, and avoid overloading transmission lines.
These reliability standards require system operators to plan not only for forecast demand needs plus a reserve factor to cover mis-forecasting, but also for contingencies for outages of system components (power plants or transmission lines). Thus, the standards require control areas to maintain a certain amount of available reserves equal to the greater of:
- A percentage of forecasted loads, or
- The most severe single contingency of generation or transmission loss.
These reserves must be available to quickly bring supply and demand back into balance should there be an unexpected outage of either generation or transmission.