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.

Abstract: The regulation of greenhouse gas emissions from the electricity sector within a cap-and-trade system poses significant policy questions about how to allocate tradable emission allowances. Allocation conveys tremendous value and can have efficiency consequences. This research uses simulation modeling for the electricity sector to examine different approaches to allocation under a cap-and-trade program in California. The decision affects prices and other aspects of the electricity sector, as well as implications for the overall cost of climate policy. An important issue is the opportunity for emission reductions in California to be offset by emission increases in neighboring regions that supply electricity to the state. The amount of emission leakage (i.e. an increase in CO2 emissions outside of California as a result of the program) varies with the regulatory design of the program.

Abstract: Identifying the factors that influence electricity demand in the continental United States and mathematically characterizing them are important for developing electricity consumption projections. The price elasticity of demand is especially important, since the electricity price effects of policy implementation can be substantial and the demand response to policy-induced changes in prices can significantly affect the cost of policy compliance. This paper estimates electricity demand functions with particular attention paid to the demand stickiness that is imposed by the capital-intensive nature of electricity consumption and to regional, seasonal, and sectoral variation. The analysis uses a partial adjustment model of electricity demand that is estimated in a fixed-effects OLS framework. This model formulation allows for the price elasticity to be expressed in both its short-run and long-run forms. Price elasticities are found to be broadly consistent with the existing literature, but with important regional, seasonal, and sectoral differences.

Abstract: Policies to cap emissions of carbon dioxide (CO2) in the U.S. economy could pose significant costs on the electricity sector, which contributes roughly 40 percent of total CO2 emissions in the U.S. Using a detailed simulation model of the electricity sector, we evaluate alternative ways that emission allowances can be allocated. Most previous emissions trading programs have allocated the major portion of allowances for free to incumbent firms. In the electricity sector this approach would lead to changes in electricity price that vary by region primarily based primarily on whether prices are market-based or determined by cost-of-service regulation. Allocation to customers, which could be achieved by allocation to local distribution companies (retail utilities) would recover symmetry in the effect of free allocation and lead to signficiantly lower overall electricity prices. However, this form of compensation comes with an efficiency cost that will increase the overall cost of climate policy.

Abstract: A variety of recent policy measures have been advanced to promote interregional power transmission investment in the United States; among these are the designation of corridors on federal lands in western states and the identification of national interest electric transmission corridors across the country. Although these corridors have been put forward as critical policy interventions to modernize an aging transmission system, their effectiveness could be undermined by parallel policies, such as renewable portfolio standards (RPSs), designed to alter the landscape for new investment in generation capacity. This paper presents the results of a scenario analysis of the relationship between the interregional power grid and renewables policies to evaluate 1) the effects of state and national RPS policies on interregional power flows and 2) the impacts of transmission expansion on the locations and types of new, renewable sources for electricity capacity additions. Using the RFF Haiku Electricity Market Model, we find that the locations of transmission corridors could have a significant impact on the location, type, and marginal cost of generation in the future. Conversely, a national RPS would induce interregional power flows across the country significantly different from those that would prevail in the absence of such a policy. In particular, a national RPS would promote western renewables and shift power flows to the East. Under either a set of state-level RPS policies or a national RPS, the majority of power flowing into California will come from the Pacific Northwest, not from the Southwest, which is where corridors are most abundant. Additionally, a national RPS could motivate more than 10 GW of new biomass capacity in the Southeast, but grid expansion could shift 6 GW of this capacity to the Plains states and western wind.

Abstract: Paradoxically, owners of existing generation assets may be better off paying for carbon dioxide emission allowances than having them distributed for free. This analysis shows that it takes just 7.5% of the revenue raised under an auction to preserve the asset values of existing generators.

Abstract: This paper considers how moderate actions to slow atmospheric accumulation of greenhouse gases from fossil fuel use also could reduce conventional air pollutants in the United States. The benefits that result would be “ancillary” to greenhouse gas abatement. Moreover, the benefits would tend to accrue locally and in the near term, while benefits from reduced climate change mostly accrue globally and over a time frame of several decades or longer. The previous literature suggests that changes in nitrogen oxides (NO_x) would be the most important consequence of moderate carbon policies. We calculate these changes in a detailed electricity model linked to an integrated assessment framework to value changes in human health. A tax of $25 per metric ton of carbon emissions would yield NO_x related health benefits of about $8 per metric ton of carbon reduced in the year 2010 (1997 dollars). Additional savings accrue from reduced investment in NO_x and SO₂ abatement in order to comply with emission caps. These savings sum to $4-$7 per ton of carbon reduced. Total ancillary benefits of a $25 carbon tax are estimated to be $12-$14, which appear to justify the costs of a $25 tax, although marginal benefits are less than marginal costs. At a tax of $75 per ton carbon, greater health benefits and abatement cost savings are achieved but the value of ancillary benefits per ton of carbon reductions remains roughly constant at about $12.

Abstract: We investigate the cost-effectiveness and distributional effects of a revenue-raising auction, grandfathering, and a generation performance standard as alternative approaches for distributing carbon emission allowances in the electricity sector. We solve a detailed national electricity market model and find the auction is roughly one-half the societal cost of the other approaches. This result holds under a variety of assumptions about the future state of economic regulation and competition in the electricity sector. The differences in the cost of the approaches flow from the effect of each approach on electricity price. Grandfathering is the best for producers but it imposes a substantial cost on consumers. The generation performance standard yields the lowest electricity price but highest natural gas price. The auction does better than the generation performance standard at protecting households and at preserving asset values for producers. It also yields revenues that can help meet other efficiency and distributional goals.

Abstract:

This paper analyzes the benefits and costs of policies to reduce nitrogen oxides (NO_x) emissions from electricity generation in the United States. Because emissions of NO_x contribute to the high concentration of atmospheric ozone in the eastern states that is associated with health hazards, the U.S. Environmental Protection Agency (EPA) has called on eastern states to formulate state implementation plans (SIPs) for reducing NO_x emissions. Our analysis considers three NO_x reduction scenarios: a summer seasonal cap in the eastern states covered by EPA’s NO_x SIP Call, an annual cap in the same SIP Call region, and a national annual cap. All scenarios allow for emissions trading. Although EPA’s current policy is to implement a seasonal cap in the SIP Call region, this analysis indicates that an annual cap in the SIP Call region would yield about 400 million dollars more in net benefits (benefits less costs) than would a seasonal policy, based on particulate-related health effects only. An annual cap in the SIP Call region is also the policy that is most likely to achieve benefits in excess of costs. Consideration of omissions from this accounting, including the potential benefits from reductions in ozone concentrations, strengthens the finding that an annual program offers greater net benefits than a seasonal program.

Abstract: The U.S. electric power sector is in the midst of two major regulatory changes. One is the change from cost-of-service regulation to competition as a means of disciplining electricity prices, often referred to as “electricity restructuring.” The other is the apparently increasing scope and stringency of environmental regulation; proposed tighter restrictions on nitrogen oxide (NO_x) emissions from existing generators are one recent example. We look at the effects of restructuring on three issues: (a) economic surplus and environmental quality, (b) the cost of NO_x control policies and who bears the costs, and (c) the cost-effectiveness of a seasonal and an annual NO_x cap in the SIP Call region. We find that without the NO_x cap, nationwide restructuring leads to higher NO_x and carbon emissions from the electricity sector. Adding either a seasonal or an annual NO_x cap-and-trade regime in the eastern United States mitigates the increase in NO_x emissions but has a much smaller effect on carbon emissions. The out-of-pocket compliance cost associated with achieving a seasonal or an annual NO_x cap is moderately higher with nationwide restructuring than without, but the changes in economic surplus are significantly higher. For a seasonal policy, most of the costs are borne by electricity consumers. For an annual policy, most of the incremental costs beyond those with seasonal controls are borne by producers. However, the economic benefits of nationwide restructuring more than offset the higher costs of controlling NO_x emissions in a more competitive environment. The foregone economic surplus is compared with the benefits resulting from NO_x emission reductions using an integrated assessment model of atmospheric transport and valuation of human health effects. We find an annual policy dominates a seasonal policy from a cost effectiveness perspective under limited restructuring, and even more strongly under nationwide restructuring.