The three largest California investor-owned utilities (IOUs) (em Pacific Gas and Electric Co., San Diego Gas & Electric Co. (SDGE), and Southern California Edison Co. (SCE) have circulated for...
Pricing the Grid: Comparing Transmission Rates of the U.S. ISOs
are required to both serve load and meet the transmission constraint.
An important feature of congestion pricing is that it almost always results in the total spot value of consumption being greater than the total spot value of generation. In Figure 4, for example, the value of consumption (measured by multiplying the load at each bus times the price at each bus) is $67,500, while the value of generation (measured by multiplying the generation at each bus times the price at each bus) is $49,500. The $18,000 difference represents congestion charges that, as discussed below, are indirectly returned to consumers through reduced transmission access charges.
Although the Northeastern ISOs all have nodal pricing of generation, they do not all have nodal pricing of loads. In particular, because of implementation challenges posed by nodal pricing, New York currently has zonal pricing of loads. For example, if Figure 4 had a "western zone" that included busses 1 and 2, all loads in the western zone would pay a price of $20 per megawatt-hour, which is a load-weighted average of the nodal prices in that zone. The disadvantage of zonal pricing is that it can lead to efficiency losses. When zonal pricing is applied to loads only, the efficiency losses will be slight if load is unresponsive to price (as is usually the case). If zonal pricing were applied to generation, however, the efficiency losses could be great because generation is usually very responsive to price. In Figure 4, for example, an eastern zone price of $20 per megawatt-hour would radically change dispatch at busses 1 and 2 and violate the constraint on line 1-3.
California finds a different solution to the problem of managing congestion among zones. Assuming that merchant C contracts to purchase 100 MW from merchant A, each merchant begins with a balanced schedule that has 900 MW of load and 900 MW of resources. To manage congestion, the ISO accepts bids for balanced redispatch by each merchant firm. Each bid indicates the resources that each merchant will redispatch.
Table 4 shows the merchant bids that correspond to Figure 3. Each bid is an offer to redispatch generation in a way that will reduce flows on line 1-3. The table's top line, for example, indicates an offer by merchant B to increase generator B3's output by up to 200 MW while reducing generator B1's output by the same amount. If merchant B exercises no market power, it will bid $24 for each megawatt-hour redispatched, which is the difference in the incremental costs of B1 and B3. Because of the power system configuration, each megawatt of the output shift from B1 to B3 will reduce the flow of line 1-3 by two-thirds of a megawatt - hence the power distribution transfer factor (PDTF) of -0.6667. Merchant B's 200-MW output shift therefore would reduce the line 1-3 flow by 133.33 MW (200 MW x 0.6667). The effective price per megawatt-hour of line flow reduction is $36 ($24/0.6667).
The ISO needs to find bids that give a total of 100 MW of congestion relief -