The decision to limit mercury provides cover for utilities reluctant to spend on controlling NOx and SO2, while boosting other companies
Pricing the Grid: Comparing Transmission Rates of the U.S. ISOs
pricing sets loss charges according to a mixture of marginal costs and total costs. MISO and (soon) California use two very different versions of this approach.
MISO uses a flow-based method to create a matrix of the estimated losses that accompany transactions from power resources in each zone to loads in each zone. This matrix is updated approximately every six months. The loss factors are intended to provide full recovery of the energy lost in transmission. For any given transaction, the same loss factor applies to all hours.
In California, each generator must provide energy to cover its allocated responsibility for losses. For each generator, this responsibility will be proportional to the marginal losses associated with its output. The generators' responsibilities will be scaled so that all generators together provide just enough energy to cover total losses.[Fn.1]
On the surface, the scaled marginal cost approach seems to be fairer than the other approaches. Unlike the pure marginal cost approach, the scaled approach does not levy loss charges that exceed the total costs of losses. Unlike the postage stamp approach, the scaled approach distinguishes loss charges according to how market participants cause losses.
But the MISO and California approaches differ in two significant ways. First, MISO differentiates losses according to the locations of both the generators and the consumers who are parties to a transaction, while California differentiates losses only according to the generators' locations. Second, MISO looks at the loss effects of transactions over a relatively long period of months, while California intends to consider loss effects over periods of hours.
It might seem that the New York and California approaches are similar because both reimburse market participants for the amount by which marginal cost-based loss revenues exceed the actual costs of losses. These two approaches really are quite different, however. New York returns the excess loss revenues to all consumers, as a credit against its scheduling and dispatch charge, while California returns the excess loss revenues only to the generators that cause losses. The result is that market participants that cause losses in New York see prices that reflect pure marginal costs, while those in California are charged prices reflecting a mixture of marginal costs and total costs.
To understand the differences among the three methods for pricing losses, consider the example of a simple power system with two busses connected by a single transmission line. Because transmission losses are always roughly proportional to the square of line flows, we assume for this example that the losses in this line are determined by the relationship
Losses = FLOW2 x 10-4
where FLOW is the average megawatt flow in the line. Table 3 illustrates, for two levels of flow, two key implications of this relationship - implications that are characteristic of transmission losses in general. First, average losses rise with flows. Second, marginal losses are exactly double average losses. The marginal loss rate of 5 percent, for example, means that if flow increases 1 MW, from 250 MW to 251 MW, losses will increase by 0.05 MW.
Now suppose, as illustrated in