Abstract: Several recent studies have used simulation models to quantify the potential effects of recent environmental regulations on power plants, including the Mercury and Air Toxics Standards (MATS), one of the US Environmental Protection Agency’s most expensive regulations. These studies have produced inconsistent results about the effects on the industry, making general conclusions difficult. We attempt to reconcile these differences by representing the variety of assumptions in these studies within a common modeling platform. We find that the assumptions, and their differences from the way MATS will be implemented, make a substantial impact on projected retirement of coal-fired capacity and generation, investments that are required, and emissions reductions. Almost uniformly, the actual regulation, when examined in its final form and in isolation, provides more flexibility than is represented in most models. We find this leads to a smaller impact on the composition of the electricity generating fleet than most studies have predicted.

Abstract: Implementation of new environmental regulations in the electricity industry has triggered concerns about system reliability. We find these regulations are unlikely to create the shock to the system as some worry. They lead to little change in generation capacity. The large costs associated with investments in pollution control technologies are partially offset by a decrease in the cost burden associated with tradable emissions allowances. The combined effects contribute to a 1 percent increase in retail electricity prices and a decrease in producer profits of about $3–$5 billion in 2020. Though it varies across scenarios and regions, over the simulation horizon, consumers pay approximately 70 percent of total costs. In 2020, for example, total annual costs are between $6.6 billion and $7.1 billion. The investment in pollution controls leads to substantial reductions in emissions of mercury and sulfur dioxide.

Abstract: A clean energy standard (CES) is a flexible approach to encouraging a cleaner technology mix for electricity production. The most recent federal CES proposal from Senator Bingaman would transform the way electricity is produced and result in substantial reductions in CO2 emissions with small national average electricity price effects through 2025. After 2025, electricity prices would increase substantially. The alternative compliance payment (ACP) for clean energy credit will be binding, and thus actual deployment of clean energy will fall short of the intended targets and cumulative emissions reductions by 2035 will be 12 percent smaller than they would be without an ACP. The small utility exemption from the CES requirements equates to roughly $29 billion in avoided electricity expenditures by the customers of exempted utilities in 2035 alone. Excluding power generated by existing nuclear and hydroelectric facilities from CES compliance responsibility raises electricity prices in competitive regions to the benefit of owners of existing nuclear and hydro capacity.

Abstract: The confluence of several pending environmental rulemakings will require billions of dollars of investment across the industry and changes in the operation of facilities. These changes may lead to retirement of some facilities, and there has been much debate about their potential effects on electricity reliability. Only very exceptional circumstances would trigger supply disruptions; however, the changes may affect electricity prices, the generation mix, and industry revenues. Coincident with these new rules, expectations about natural gas prices and future electricity demand growth are changing in ways that also will have substantial effects on the industry. This paper addresses these two sets of issues using a detailed simulation model of the U.S. electricity market. The findings suggest that recent downward adjustments in natural gas prices and electricty demand projections have a substantially larger impact on electricity prices and generation mix than do the new environmental rules.

Abstract: The electricity sector is responsible for roughly 40 percent of U.S. carbon dioxide (CO2) emissions, and a shift away from conventional coal-fired generation is an important component of the U.S. strategy to reduce greenhouse gas emissions. Toward that goal, several proposals for a clean energy standard (CES) have been put forth, including one espoused by the Obama administration that calls for 80 percent clean electricity by 2035 phased in from current levels of roughly 40 percent. This paper looks at the effects of such a policy on CO2 emissions from the electricity sector, the mix of technologies used to supply electricity, electricity prices, and regional flows of clean energy credits. The CES leads to a 30 percent reduction in cumulative CO2 emissions between 2013 and 2035 and results in dramatic reductions in generation from conventional coal. The policy also results in fairly modest increases on national electricity prices, but this masks a wide variety of effects across regions.

Abstract: The EPA will issue rules regulating greenhouse gas (GHG) emissions from existing steam boilers and refineries in 2012. A crucial issue affecting the scope and cost of emissions reductions will be the potential introduction of flexibility in compliance, including averaging across groups of facilities. This research investigates the role of compliance flexibility for the most important of these source categories—existing coal-fired power plants—that currently account for one-third of national emissions of carbon dioxide, the most important greenhouse gas. We find a flexible standard, calibrated to achieve the same emissions reductions as an inflexible approach, reduces the increase in electricity price by 60 percent and overall costs by two-thirds in 2020. The flexible standard also leads to substantially more investment to improve the operating efficiency of existing facilities, whereas the inflexible standard leads to substantially greater retirement of existing facilities.

Abstract: In this paper, we introduce a new top-down approach to modeling the effects of publicly financed energy-efficiency programs on electricity consumption and carbon dioxide emissions. The approach draws on a partial-adjustment econometric model of electricity demand and represents the results of a reverse auction for electricty savings from different levels of public investment. The model is calibrated to recent estimates of the cost-effectiveness of rate payer–funded efficiency programs at reducing electricity consumption. The results suggest that supply curves for conserved electricity are upward sloping, convex, and dependent on policy design and electricity prices. Under the scenarios modeled, electricity savings of between 1 and 3 percent are achievable at a marginal cost of $50 per megawatt hour (MWh) and a corresponding average cost of $25–$35/MWh.

Abstract: Three types of policies that are prominent in the federal debate over addressing greenhouse gas emissions in the United States are a cap-and-trade program (CTP) on emissions, a renewable portfolio standard (RPS) for electricity production, and tax credits for renewable electricity producers. Each of these policies would have different consequences, and combinations of these policies could induce interactions yielding a whole that is not the sum of its parts. This paper utilizes the Haiku electricity market model to evaluate the economic and technology outcomes, climate benefits, and cost-effectiveness of three such policies and all possible combinations of the policies. A central finding is that the carbon dioxide (CO2) emissions reductions from CTP can be significantly greater than those from the other policies, even for similar levels of renewable electricity production, since of the three policies, CTP is the only one that distinguishes electricity generated by coal and natural gas. It follows that CTP is the mostcost-effective among these approaches at reducing CO2 emissions. An alternative compliance payment mechanism in an RPS program could substantially affect renewables penetration, and the electricity priceeffects of the policies hinge partly on the regulatory structure of electricity markets, which varies across the country.

Abstract: We estimate residential electricity demand for different regions of the country, assuming that consumers respond to average electricity prices. We circumvent the need for individual billing information by developing a novel generalized method of moments approach that allows us to estimate demand based on household electricity expenditure data from the Consumer Expenditure Survey, which does not have quantity and price information. We find that price elasticity estimates vary across the four census regions—the South at –1.02 is the most price-elastic region and the Northeast at –0.82 is the least—and are essentially equivalent across income quartiles. In general, these price elasticity estimates are considerably larger in magnitude than those found in other studies using household-level data that assume that consumers respond to marginal prices. We also 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.