ing to the EPA, the rule would reduce sulfur dioxide emissions by 71 percent and nitrogen oxide emissions by 52 percent from 2005 levels by 2014. EPA projects the utilities’ cost of compliance at $2.8 billion. The agency is still working on the new rule for ozone and plans to finalize it as well as revisit the transport rule in 2012.
Because the power sector has already significantly reduced its sulfur dioxide and nitrogen oxide emissions since 1990 when legislation first required a reduction in criteria pollutants, Dan Riedinger, a spokesman at the Edison Electric Institute, said “EPA’s new proposal would require dramatic reductions in power sector emissions, on top of major reductions to date, on a very short timeline.” The short timeline is likely to increase the cost of compliance because electric utility companies frequently make technology changes when they are down for scheduled maintenance. Major changes will increase that down time, resulting in less generation output and increased equipment cost to comply with the lower emissions rates. Any legislative or regulatory policy that would reduce existing coal-fired generation or further limit their emissions will almost certainly cause an increase in electricity prices.
Although the Federal government has yet to pass an RPS or a cap-and-trade program for electric utilities, some states have already enacted such programs. The Institute for Energy Research found that, in those states that have an RPS, electricity prices in 2009 were 39 percent higher than in states without an RPS.
State Programs, Generation Mix Changes, and Electricity Price Increases
In 2009, average electricity prices nation-wide increased by 1.5 percent, a small percentage, partially because of lower natural gas prices. However, some states saw double-digit price increases. For example, West Virginia had an 18 percent increase in average electricity prices, while Virginia customers saw an 11 percent increase. Coal generation in both states was lower, by 24 percent and 17 percent, respectively. In the case of West Virginia, the state has an RPS that requires investor-owned utilities with more than 30,000 residential customers to generate 25 percent of their retail electricity sales from alternate and renewable energy sources by 2025. Virginia does not have a legislated RPS, but has a goal to generate 15 percent of 2007 electricity sales from renewable energy by 2025.
Several states had large percentage decreases in coal generation. One such state was Ohio. Comparing 2009 to 2008, its coal generation went down by 13 percent; its natural gas generation went up by 87 percent; and its average electricity price went up by 6.9 percent. Ohio has an RPS that requires its utilities to provide 25 percent of their retail electricity supply from alternate energy sources by 2025. North Carolina and Pennsylvania are other states with an RPS whose coal generation went down (13 and 11 percent, respectively). In 2009, their natural gas generation went up by 18 and 56 percent, respectively, and their average electricity price went up 5 and 3 percent, respectively. Pennsylvania’s RPS requires its utilities to generate 18 percent of their electricity from alternate energy sources by compliance year 2020 (June 1, 2020 to May 31, 2021). North Carolina’s RPS requires investor-owned utilities to generate 12.5 percent of 2020 retail electricity sales from renewables by 2021, while municipal utilities and cooperatives must meet a target of 10 percent of renewable energy by 2018.
In 2007, the Governor of Kansas rejected a permit for a coal plant due to carbon dioxide emissions. That was the first such rejection of its kind. Kansas, a primarily coal generation state, lowered its coal generation by 5 percent and raised its natural gas generation by 17 percent, with an electricity price increase of 8 percent in 2009 over 2008. Besides its rejection of a permit for a coal-fired plant, Kansas also has an RPS that requires utilities to provide 20 percent of peak demand capacity (based on the average demand from the previous three y