Since 2007, US coal-fired electricity generation has declined by a stunning 25 percent. Detailed daily unit-level data is used to examine the joint impact of natural gas prices and wind generation on coal-fired generation and emissions, with a focus on the interaction between gas prices and wind. This interaction is found to be significant. Marginal responses of coal-fired generation to natural gas prices (wind) in 2013 were larger, sometimes much larger, than the counterfactual with 2008 wind generation (gas prices). Additionally, these factors jointly account for the vast majority of the observed decline in generation and emissions. (JEL L94, L95, Q35, Q38, Q42, Q53)

Renewable electricity policies promote investment in renewable electricity generators and have become increasingly common around the world. Because of intermittency and the composition of other generators in the power system, the value of certain renewables-particularly wind and solar-varies across locations and technologies. This paper investigates the implications of this heterogeneity for the cost effectiveness of renewable electricity prices as compared to one another and to a carbon dioxide emissions price. A simple model of the power system shows that renewable electricity policies cause different mixes of investment in renewable and other generator technologies. Policies also differ according to their effect on electricity prices, and both factors cause the cost effectiveness to vary across policies. We use a detailed, long-run planning model that accounts for intermittency on an hourly basis to compare the cost effectiveness for a range of policies and alternative parameter assumptions. The differences in cost effectiveness are economically significant, where broader policies, such as an emissions price, outperform renewable electricity policies. JEL codes: L94, Q48, Q52. * We are grateful to the Heising-Simons foundation for supporting this research.

A cointegrated vector autoregressive (CVAR) model is estimated to determine the dynamic relationship between Nordic wholesale electricity prices and EU emissions trading scheme (EU-ETS) CO2 allowance prices. An impulse response analysis reveals that electricity prices have large short-term responses to CO2 price shocks, but that this response dampens over time. Using hourly Nordic electricity spot market prices, I find that the value of short-term response of electricity prices to a shock in CO2 prices in off-peak hours is consistent with expected values for near complete pass-through of CO2 emission costs when coal-generated power is at the margin. Likewise, the estimates reveal that peak hour electricity price responses to CO2 price shocks are as expected for a market that has near complete pass-through of CO2 emission costs when natural gas-generated power is at the margin. These results further suggest the Nordic electricity market is pricing as a competitive market.

No abstract

The recent push for a federal energy policy that could substantially change electricity prices in the U.S. highlights the need to obtain accurate residential electricity demand estimates. Many electricity demand estimates have been obtained based on the assumption that consumers optimize with respect to known marginal prices, but increasing empirical evidence suggests that consumers are more likely to respond to average prices. Under this assumption, this paper develops a new strategy based on GMM to estimate household electricity demand. Our approach allows a national-level demand estimation from publicly available expenditure data and utility-level consumption data, complementing studies that use individual billing data which are richer yet often proprietary. We estimate the price elasticity near-1, which is at the upper end (in magnitude) among the estimates from previous studies. We apply our elasticity estimates in a U.S. climate policy simulation to determine how these elasticity estimates alter consumption and price outcomes compared to the more conservative elasticity estimates commonly used in policy analysis.