This paper evaluates the impact of intermittent wind generation on hourly equilibrium prices and output, using data on expected wind generation capacity and demand for 2020. Hourly wind data for the period [1993][1994][1995][1996][1997][1998][1999][2000][2001][2002][2003][2004][2005] are used to obtain wind output generation profiles for thirty regions (onshore and offshore) across Great Britain. Matching the wind profiles for each month to the actual hourly demand (scaled to possible 2020 values), we find that the volatility of prices will increase, and that there is significant year-to-year variation in generators' profits. Above-average wind speeds lead to belowaverage prices, but annual revenues for British wind generators (producing more in the winter) are almost as great as for base load generators. In the presence of significant market power (the equivalent of two symmetric firms

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This paper uses a market equilibrium model to calculate how the mix of generating capacity would change if large amounts of intermittent renewables are built in Great Britain, and what this means for operating patterns and the distribution of prices over time. If generators bid their marginal costs, we find that the changes to the capacity mix are much greater than the changes to the pattern of prices. Thermal capacity falls only slightly in response to the extra wind capacity, and there is a shift towards power stations with higher variable costs (but lower fixed costs). The changes to the pattern of prices, once capacity has adjusted, are relatively small. In an oligopolistic setting, strategic generators will choose lower levels of capacity. If wind output does not receive the market price, then mark-ups on thermal generation will be lower in a system with large amounts of wind power.