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Does anyone care about rising redispatch costs?
Regional transmission organizations (RTOs) or independent system operators (ISOs) dominate the major power grids of North America, with the notable exceptions of the Southeast and Pacific Northwest. The Federal Energy Regulatory Commission (FERC) has been a strong advocate of RTOs as a way of opening access to the power grids and improving system reliability. The power grid obviously requires active, hands-on management to ensure system reliability, but even that has not been sufficient to prevent major outages. New rules put in place following the last major blackout put more teeth into reliability.
The purpose of this article is not to criticize system reliability but to highlight the more pervasive challenge today and for the future: Controlling the cost impact of decisions by grid operators on energy market participants. Here, as elsewhere, the law of unintended consequences is alive and well, as procedures put in place to avoid outages at almost any cost have the consequence of raising the overall cost of operations through rapidly rising congestion costs.
Consider a few examples.
Economic dispatch generally means choosing the lowest operating cost electricity generation supplies to meet electricity demand. For example, assume a 1,000-MW electricity demand in an hour, with five generating units to choose from. Units 1, 2, 3, and 4 are each 250 MW and cost $20/MWh to operate. Unit 5 also is 250 MW, but costs $30/MWh to operate. Using an economic dispatch approach to resource allocation would give preference to the least-cost unit sufficient to satisfy the requirement. Thus, in this example, economic dispatch would result in the decision to operate units 1-4 to meet the 1,000-MW load, leaving the more expensive unit 5 offline.
To make this economic selection of resources, grid operators need to have a transmission system capable of delivering the power from units 1 through 4 to the load. Continuing with our previous example, assume that the generation and load are connected via transmission according to the following:
With this arrangement, and all lines in service, the system can allow each of generators 1, 2, 3, and 4 to run full out to meet the 1,000-MW load. An operating reserve requirement equal to the largest single generator contingency ( i.e., the possible low of one of the 250-MW generators) is covered with the 250-MW spinning reserve unit. Generator 5, which is more expensive to operate, is not needed and can be shut down. This dispatch pattern can be considered to be a security constrained economic dispatch (SCED), since the system is designed to survive the loss of the largest single generator through the provision of spinning reserves with the 250-MW spin generator.
System operators also consider whether the loss of a transmission line might cause a problem. If the loss of any of the operating generators 1 through 4