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Price Forecasting in Spot Markets: Hidden Risks in Single-Part Bidding

Fortnightly Magazine - October 15 1998

Spark Spreads:

What's Hidden by the Averages

Now let's turn to some real valuation experiences. Consider the case of gas-fired steam generation operating in a market based on single-part bidding rules. These units typically have incremental heat rates of 8,000 to 9,000 Btu/kWh, but average heat rates of more than 10,000 Btu/kWh. The reason for the high average heat rates is start-up and no-load costs. The customer who wants to value these units goes to a market price forecaster and says, "Give me some forecasts." Figure 2 is representative of the simulations a customer receives.

These prices are expressed in "spark spread" or market heat rate units, i.e., the electricity price divided by the gas price. The figure shows 24 hourly prices for each day of a "typical week" in a month. Market heat rate units are convenient for profitability analysis because they can be directly related to costs for any gas price. For ease of understanding, I have colored the prices in heat rate bands. (I refer to this scheme as the USA Today weather map of prices, a concept that should be familiar to business travelers.)

Now Figure 2, appears similar to Cases 1 and 2 in Table 1. Both forecasts have the same average value. In Figure 2, the average value is about 8,800 Btu/kWh (see the last cell at the bottom of the "Average" column on the right of each panel). One forecast (Fig. 2, Case 1) exhibits a lot more variance than the other did. I point out this difference to the vendor of the forecasts. He calls me back to say that the "smooth" one is correct (Fig. 2, Case 2) and that the other one is wrong. I thank him for his response. I wonder if he would have bothered to tell me if I hadn't asked.

Next I start to do my valuation. Here I am back to the case depicted in Figure 1, not Table 1. The cost structure of the marginal plants includes the start-up and no load costs (remember average heat rates are higher than incremental rates, a fact that is suppressed in Table 1). I know that the plants that I am valuing really can set the market price sometimes (notice that in the Table 1 examples for Cases 3 and 4 they never set the price). So if I am bidding these plants, and I know I can set the price sometime, I need to get my start-up and no-load costs back or I am losing money. If we were to generalize the Table 1 examples to include start-up and no-load costs, then these would have to be bid in prices. The profits estimated for Cases 3 or 4 would be reduced to account for these costs and the unit would have to bid the start-up, no-load costs in some way vaguely related to Figure 1. The unit probably would end up setting the market price at those bids some of the time.

Now in my real valuation problem, I am starting to get a little uncomfortable. If I