The Economics of Energy Markets
April 13, 2016
Richard G. Newell of Duke University, Meredith Fowlie of University of California, Berkeley, and Christopher R. Knittel and James M. Poterba, both of MIT, Organizers
Christiane J.S. Baumeister, University of Notre Dame; Reinhard Ellwanger, Bank of Canada; and Lutz Kilian, University of Michigan
Did the Renewable Fuel Standard Shift Market Expectations of the Price of Ethanol?
It is commonly believed that the response of the price of corn ethanol (and hence of the price of corn) to shifts in biofuel policies operates in part through market expectations and shifts in storage demand, yet to date it has proved difficult to measure these expectations and to empirically evaluate this view. Baumeister, Ellwanger, and Kilian utilize a recently proposed methodology to estimate the market's expectations of the prices of ethanol, unfinished motor gasoline and crude oil at horizons from three months to one year. The researchers quantify the extent to which price changes were anticipated by the market, the extent to which they were unanticipated, and how the risk premium in these markets has evolved. They show that the Renewable Fuel Standard (RFS) is likely to have increased ethanol price expectations by as much $1.45 in the year before and in the year after the implementation of the RFS had started. Their analysis of the term structure of expectations provides support for the view that a shift in ethanol storage demand starting in 2005 caused an increase in the price of ethanol. There is no conclusive evidence that the tightening of the RFS in 2008 shifted market expectations, but the researchers' analysis suggests that policy uncertainty about how to deal with the blend wall raised the risk premium in the ethanol futures market in mid-2013 by as much as 50 cents at longer horizons. Finally, the researchers present evidence against a tight link from ethanol price expectations to corn price expectations and hence to storage demand for corn in 2005-06.
Sharat Ganapati, Yale University; Joseph S. Shapiro, Yale University and NBER; and Reed Walker, University of California at Berkeley and NBER
Energy Prices, Pass-Through, and Incidence in U.S. Manufacturing
This paper uses plant-level production data from a set of U.S. manufacturing industries to study how changes in energy input costs for production are shared between consumers and producers via changes in product prices (i.e., pass-through). Ganapati, Shapiro, and Walker show that in markets characterized by imperfect competition, cost pass-through and two other estimable statistics are sufficient to characterize the relative change in welfare between producers and consumers due to a change in input costs. They find that increases in energy prices lead to higher plant-level marginal costs and output prices but lower markups. Pass-through is therefore incomplete, with estimates centered around 0.75. The researchers' confidence intervals reject both zero pass-through and complete pass-through. They find heterogenous incidence of changes in input prices across industries, ranging from consumers bearing a third of the burden in gasoline refining to consumers bearing large majorities of the burden in other industries.
Karen Clay, Carnegie Mellon University and NBER; Akshaya Jha, Carnegie Mellon University; Nicholas Muller, Middlebury College and NBER; and Randall Walsh, University of Pittsburgh and NBER
External Economies of Shipping Energy Fuels
The discovery and development of crude oil in the Bakken region of North Dakota created the need to move oil to refineries around the country. Movement of oil by rail has been enormously controversial, as has development of new pipeline infrastructure to move oil. One problem for the current policy debate has been the lack of information on the relative social costs of moving oil by the above methods. Clay, Jha, Muller, and Walsh address this gap by creating estimates of the greenhouse gas and air pollution costs and population and property risks of moving crude to refineries using current rail and pipeline routes. The analysis draws on government and industry data sets to provide information on routes, route volumes, locomotive emissions, electricity emissions associated with pumping oil through pipelines, and population and property values within 0.5 miles of the routes. Pipeline emissions created by electricity generation will be calculated using the approach developed by Graff-Zivin, Kotchen, Mansur (2014) and used subsequently by Holland et al., (2015). The greenhouse gas and air pollution costs will be computed using the AP2 integrated assessment model. Data from the federal Pipeline and Hazardous Materials Safety Administration on rail and pipeline accidents will be used to inform property and population risks.
Richard G. Newell, and Brian C. Prest, Duke University
Informing SPR Drawdown Policy Using Futures Strips
Joseph E. Aldy, Harvard University and NBER
Boutique Fuel Markets and Security-Environment-Economic Trade-offs
Since the emergence of boutique fuel regulations 25 years ago, U.S. gasoline markets have been segmented based on fuel content regulations, which make these markets less resilient to supply shocks because neighboring markets do not have regulation-compliant fuels to export to those experiencing a shock. Hurricanes have knocked out refineries and pipelines resulting in supply shocks to markets "at the end of the pipeline" far from the direct impacts of the storms. Aldy investigates the impacts of EPA authority to waive these regulations which has occurred approximately 60 times since 2005 on local air quality, public health outcomes, and fuel prices. These analyses can inform a welfare analysis of policies that temporarily suspend air quality regulations relative to other interventions to address supply shocks, such as product-based strategic petroleum reserves.
Frank A. Wolak, Stanford University and NBER
Managing Reliability Risk and the Consumer and Producer Cost of Intermittent Renewables Integration
An increasing number of jurisdictions have substantial renewable energy goals for their electricity sectors. For example, 29 U.S. states have renewables portfolio standards that typically require electricity retailers to purchase a certain fraction of their wholesale energy from qualified renewable generation resources. However, investors in the intermittent renewable generation units that qualify for these programs have little incentive to manage the increase in operating reserves and load-following generation units caused by their location and capacity choice decisions. Wolak formulates the investment decisions of renewable generation owners as a portfolio choice problem and derives several measures of the magnitude of the "system reliability externality" for the California electricity market. Locationally differentiated grid interconnection charges for renewable generation units are derived that internalize this reliability externality.
Steven E. Sexton and Bryan Bollinger, Duke University, and Kenneth Gillingham, Yale University and NBER
Household Demand for Solar PV and Price Discriminating Subsidies
Federal, state, and local planners provide billions of dollars in incentives to encourage the adoption of rooftop solar photovoltaics by various subsidy instruments, including tax credits, rebates, and net energy metering policies. Sexton, Bollinger, and Gillingham investigate the potential for planners to improve program efficiency and equity by segmenting the market for rooftop solar based on observable household characteristics and employing incentive instruments to which households are most responsive. Using address-level solar PV adoption data, along with home and household characteristics, the researchers estimate a model of rooftop solar demand from which adoption elasticities with respect to various incentive types and household-specific estimates of willingness to pay are derived. They then simulate the outcomes of incentive programs designed to achieve various planner objectives, e.g., maximize social welfare or achieve distributional equity.
Gabriel E. Lade and Ivan J. Rudik, Iowa State University
Prices, Quantities, and Gas Capture Infrastructure: Reducing Flaring in North Dakota
Oil wells typically produce natural gas liquid (NGL) co-products in addition to crude oil. In the absence of onsite infrastructure to process, use, or capture and transport these lighter hydrocarbons, firms often resort to flaring them. Flaring involves burning NGLs at the well site, and has increased substantially in the United States with the advent of unconventional oil production. The problem is particularly acute in the North Dakota Bakken and Three Forks shale formations where flaring in the oil patch is visible from space at night. Lade and Rudik study the effects of a 2015 North Dakota regulation that limits flaring at wells after 90 days of production. They estimate the impact of the regulation on the amount of NGLs flared, firms' oil production, and the development of infrastructure to capture and process NGLs. To do so, the researchers take advantage of a unique, well-level production dataset that comprises nearly 10,500 horizontally fractured wells drilled in North Dakota since 2007. In addition to studying the efficacy of North Dakota's regulation, they take advantage of historical variation in the relative prices of natural gas and oil since 2007 to study the potential efficacy of price-based instruments in reducing flaring and increasing the speed with which firms install gas capture infrastructure.