Phil Davies - Senior Writer
Published July 1, 2007 | July 2007 issue
Figuring out whether, or by how much, renewable portfolio standards will drive up electricity rates is difficult because their effects tend to be obscured by other trends in the utility industry putting upward pressure on prices, including increasing capital spending on all types of generation, the rising cost of natural gas and unabated demand for power nationwide. But utilities and research groups have taken a stab at gauging the impact of RPSs on electricity markets, both in the district and in other parts of the country.
A 2006 study of the impact of injecting more wind power into Minnesota's energy mix projected slightly higher electricity rates at wind-penetration levels required by the state's "25 by 25" mandate. The study, commissioned by the Minnesota Public Utilities Commission, found that the average monthly household power bill could increase by as much as 1.4 percent by 2020.
However, this study measured only integration costs—the cost to utilities of "firming" intermittent wind power with reserve coal or natural gas generation, and of buying or selling electricity on the spot market to maintain steady power levels when the wind blows harder or softer than expected. Integration costs don't include the cost of wind electricity itself and the ripple effects of an RPS in the broader energy market.
Two studies have tried to predict the overall rate impact of RPSs in district states, using theoretical models. A recently released study for the Michigan Department of Environmental Quality examined the impact of a hypothetical RPS (Michigan has not enacted one) that required 15 percent of electricity sales to come from renewable sources by 2025. The upshot: Electricity rates could increase 3.6 percent by 2020 and continue to rise through 2025.
Another analysis, by the Union of Concerned Scientists in 2006, gauged the effect on power prices of Wisconsin's about-to-be-enacted RPS. Under one (now outdated) scenario in which the federal wind production tax credit expired in 2008, the study estimated that the 10-percent-by-2015 standard would add 18 cents to the average household's monthly power bill by 2011. After 2017 the typical consumer would save money.
The Wisconsin study was included in a research overview looking at RPS laws in 18 states. That 2007 meta-analysis for the U.S. Department of Energy (DOE) found that in 70 percent of the studies, including those assessing adopted or proposed RPSs in the Midwest and Great Plains, retail electricity rates rose no more than 1 percent because of mandates.
Taken as a whole, the integration analyses and overall cost-impact studies indicate that rate increases caused by mandates will be small, insignificant compared to the hikes that utility customers have become accustomed to absorbing every year or so. Higher prices attributable solely to RPSs may inflict pain on intensive power users, but probably not enough to lead to an exodus of industry to non-RPS states with cheaper power.
But such studies shouldn't be accepted as the final word on the rate impact of mandates. Their conclusions depend on myriad assumptions about the future capital costs of various types of generation, trends in fuel prices, the lifespan of tax credits and other factors that may prove wrong.
For example, the DOE meta-analysis found considerable variability in the results of state RPS studies; six predicted cost savings for the consumer, while two projected rate increases of over 5 percent. The DOE study also concluded that many of the studies had underestimated both the cost of wind farm construction and increases in the price of natural gas—countervailing market factors likely to heavily influence the marginal cost of pumping up renewable generation to satisfy mandates.
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