Regulators across the country are relying on conservation-potential assessments to guide their policy decisions. Models based on macroeconomic analysis, end-use forecasting and accounting...
Price Forecasting in Spot Markets: Hidden Risks in Single-Part Bidding
The California Power Exchange doesn't solicit separate bids for plant start-up, spinning reserve or base load operation. That can make spark spreads a bit misleading
IT SHOULD COME AS NO SURPRICE THAT THE PROSPECT OF electric competition has created a huge demand for price forecasting services. To their credit, the forecasters have obliged, supplying an abundance of tools and techniques. Do the forecasts serve the needs of those who would use them?
Some might wish to use a price forecast to assign a value to assets. They may wish to buy some of the many generating plants that utilities have decided to sell as part of a settlement to allay stranded costs of alleged market power. Ordinarily, a plant's value reflects the income stream it will produce. Forecasting that income requires an estimate of both market price and the plant's production profile. Moreover, any useful forecast must take volatility into account. It has been argued empirically, in fact, that electricity shows more volatility than other markets, including other energy markets.
Unfortunately, however, real market prices are much more complex than the simple supply-and-demand diagrams of elementary economics texts. Yes, supply and demand remains important, but so are the details of market structure. And in the newly evolving electricity markets, structure is still in question. Valuation becomes especially difficult, for example, when the assets in question are the very units that, when bid into the market, actually help set the prevailing price. To know the price requires, at the very least, that we know the market rules.
The problem begins with the separation of prices from costs. Not all models make this separation. Those that do not typically will set a price at the short-run marginal cost, or SRMC, also known as incremental cost. For competitive electric markets, however, SRMC pricing is incorrect. It is not consistent with the economic reality of the steam-fired generators that set electricity prices most of the time. These generators exhibit average costs that typically run higher than incremental cost. In the world of regulation, SRMC pricing was efficient, because someone (usually the ratepayer) would pick up all those other nonvariable operating costs (perhaps in a fuel adjustment clause). Under competition, however, prices must recover those costs since there won't be a fuel adjustment clause. Consider how this problem is addressed in the pricing rules used in the market for England and Wales.
The market operator in England and Wales takes bids from suppliers that include three different cost elements, representing three types of plant operation:
1. Base Load. Reflects incremental operating costs only (SMRC), excluding costs for plant start-up or costs to maintain inefficient production at low output levels during no-lead periods.
2. Peaking Capacity. Reflects start-up costs for immediate dispatch during high-load hours.
3. Spinning Reserve. Reflects both start-up and no-load costs (SUNL) - i.e., including the costs of inefficient production at low output levels.
The operator then runs a standard unit commitment program to determine which bids minimize total costs. Then the operator must mark up the price for base load capacity that operates during