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Last Summer's "Pure" Capacity Prices

Fortnightly Magazine - December 1997

WHOLESALE POWER PRICES DURING THE SUMMER OF 1997 REACHED LEVELS MUCH higher than in 1996 - higher than the variable fuel costs of even the costliest units (see Figures 1 and 2). This situation has confounded many observers. Many thought, in spite of forecasts to the contrary, that markets would continue to exhibit excess capacity for years to come. They thought need for new capacity was distant and that hourly markets would not see premiums in excess of fuel costs for marginal units - the so-called "pure" capacity premium - for years to come.

The evidence is in. It indicates that regional power markets will come into balance sooner than expected - certainly faster than many regulatory authorities had thought. New rules governing capacity expansion are not in place. Power companies will remain skeptical and hesitant to move until the rules are set. This situation creates the possibility of a turbulent transition to equilibrium in power markets (see Figure 3). Specifically, average annual prices might end up higher than what one would see during a smooth transition.

Why a Capacity Premium?

In any price-based system, the capacity premium is necessary to encourage power plant supply expansion in a competitive market. Without the premium, marginal power plants need only to meet the annual peak and ensure reliable supply would not be economic. Since their variable costs would equal the power price, they would not earn enough to pay their fixed costs (e.g., non-fuel O&M). If variable costs should exceed the power price, then power plants would shut down.

Two years ago, in a prior study in Public Utilities Fortnightly, I predicted how wholesale prices might respond,[fn1] with demand catching up with generation supply. The article anticipated that hourly wholesale prices would develop a "hidden" premium over marginal fuel costs known as the "pure" capacity price. This premium emerges in peak demand hours in which the chance of a shortage of generation capacity becomes significant (see Figure 4). The premium reflects the results of an auction of remaining capacity to marketers or buyers trying to avoid a blackout. Physically, this premium represents the net effect of many different customers choosing to allow their load to be curtailed remotely in exchange for lower power prices.

Simulation models for wholesale prices must operate in two modes, energy and capacity. In nearly all hours per year, models only need to calculate the fuel costs of the marginal power plant (i.e., the last plant to be dispatched). In the remaining few, however, models must calculate the shortage or "pure" capacity premium. Mathematically, this second model involves assessing the loss of load probability (LOLP) in each hour multiplied by the expected price that clears the market. (In anticipation of this new structure, ICF's pricing models contain an LOLP function.fn2) The results of a simulation of the premium are shown for an eastern U.S. regional power market (see Figure 5). Just as there was a spike in this past summer's price, the simulated premium is also concentrated during the summer peak.

Today's peak prices reflect a process in which wholesale

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