Fast forward to today’s partially deregulated electric power markets. Wholesale electric energy often is traded in various central markets, as well as among individuals in bilateral transactions....
Does anyone care about rising redispatch costs?
levels of “congestion charges” is causing stakeholders to conclude that some method needs to be designed to properly assign these “congestion charges” ( e.g., locational marginal pricing [LMP]-based congestion charges). In Global Energy’s view, these congestion charges can be largely avoided simply by choosing one of the steps 2-6 above rather than choosing step 1 when N-1 contingencies might indicate a problem.
Anecdotal Examples: Pre-ISO vs. Post-ISO
Example 1: Before ISO. Four units of coal-fired generation (Colstrip Units 1 through 4) were built in the 1970s and 1980s in eastern Montana primarily to provide power in Washington, Oregon, and western Montana. Owners of the plant needed to build (or cause to be built) a new transmission system sufficient to move the power. It was determined that a design that included two 500-kV transmission lines would not be sufficient to move all the power under certain fault conditions. Rather than spending more money for a more expensive system and rather than simply not running the plants at nameplate capacity, the owners chose to install a generation-dropping scheme that would trip one of the units if the particular N-1 contingency actually occurred. This is an example of non-ISO systems avoiding redispatch cost for low probability N-1 contingencies.
Example 2: Before ISO. In the Pacific Northwest, there often is a desire to move more power from British Columbia (BC) to the United States to displace higher-cost generation in the United States with lower-cost hydro generation in British Columbia. It became apparent that either more transmission would need to be built to accommodate higher transfer of power (under possible N-1 transmission outages) or generator dropping would need to be added to generators in BC to drop generation in the event an N-1 contingency occurs. These generator-dropping procedures have been agreed to and installed by the owners of the transmission and generation. This is an example of non-ISO systems avoiding redispatch costs for low probability N-1 contingencies.
Example 3: Before ISO. Southern California power providers often like to import cheaper power from the Pacific Northwest rather than operating more expensive generation in Southern California. For example, the Northwest/ Southwest DC line that runs from the Columbia River to Southern California can carry nearly 3,000 MW of power. If Southern California can load this line with 3,000 MW of low-cost power, it can avoid running higher-cost resources in Southern California. This is a least-cost benefit solution that appears to benefit all.
However, what if the 3,000-MW DC line trips off during a peak hour? Would that cause a problem? The answer is well known to be “yes.” But the loss of this line during a peak hour is a very low-probability event. It would be very expensive to choose to run units in Southern California every day rather than importing 3,000 MW of power from the Northwest. If the low-probability event actually occurs during the peak hour, the reasonable and most cost-effective course of action almost certainly would be to drop load for a short period of time until more expensive plants in Southern California can be