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Estimates of the economic impact of widespread, long duration (WLD) power interruptions can be used to prioritize and justify significant investments in power system resilience. This report presents estimates of this type for WLDs originating within the Commonwealth Edison (ComEd) service territory. The intended audience for this research includes utility executives and technical staff, regulators, and government agencies.This project involved surveying ComEd customers to understand how they might respond when confronted with a WLD power interruption. The research team used the survey responses to calibrate a state-of-the-art regional economic model (“POET”) to estimate economic impacts to households and 38 industry sectors across 17 impacted micro-regions (individual counties or aggregations of counties) within ComEd’s service territory and beyond. We ran one-day, three-day, and 14-day interruption duration scenarios each with varying geographic extents as well as estimated the benefits of deploying additional backup generation across the service territory. The results were then compared to a “business as usual” scenario assuming that no interruption occurred. There are six key findings from this analysis:-There may be significant losses to gross output (business revenue), gross domestic product, and household consumption during WLD interruptions, especially multi-day interruptions that occur across all of ComEd, Cook county, or the suburbs of Chicago.-The wholesale trade and transportation sectors appear to be highly sensitive to power interruptions—losses to these sectors are large relative to the losses observed across the entire economy.-Several sector-region combinations—e.g., the transportation sector in Cook county—are very sensitive to interruptions.-High-income households experience proportionately larger losses to consumption during a one-day power interruption, but low-income households experience proportionately larger losses during the longest power interruptions.-Increasing the amount of backup generation deployed across ComEd’s service territory provides significant net benefits to system-wide gross domestic product, gross output, and household consumption relative to the existing amount of backup generation already being used.-Some micro-regions (e.g., Dekalb and Kendall counties), sectors (e.g., wholesale trade, transportation), and low-income households in Cook county may especially benefit from targeted resilience interventions.We recommend that decision-makers consider running cost-benefit analyses using each of the economic metrics presented in this report independent of one another to evaluate the robustness of the insights that each of these estimates may provide. In addition to this report, we developed a tool that will allow ComEd staff and other decision-makers to visualize the full suite of results using an easy-to-interpret, user interface. We hope that the findings from this research effort will provide valuable insights to ComEd, policymakers across Illinois, and other stakeholders who have an interest in the resilience of the power system.

The costs that power interruptions impose on customers and society have emerged as essential considerations for decision-making about power system reliability and resilience. While the direct costs of localized and relatively short-duration power interruptions are well-understood, little is known about the full impact of widespread and long-duration power interruptions, especially the indirect costs and related economy-wide impacts of these events. As a result, the costs of widespread and long-duration power interruptions are generally not or only incompletely considered in utility planning activities. This paper describes a new approach for estimating the economic costs of widespread and long-duration power interruptions. This method involves using survey responses from utility customers to calibrate a regional economic model that can estimate both the direct and indirect costs of these events. Including better estimates of these costs will enhance both the comprehensiveness and completeness of the considerations relied on to support utility planning decisions, especially on grid-hardening strategies and other capital-intensive investments in electricity sector resilience.

Electric utilities, independent system operators and regional transmission operators (ISO/RTOs) have acquired significant levels of energy efficiency over several decades. The predominant approach utilities use to consider energy efficiency in electricity system planning and ISO/RTOs use in wholesale electricity markets is to reduce load forecasts to account for estimated impacts of relevant policies and programs. But an increasing number of states and utilities are interested in improved analysis of energy efficiency in electricity system planning and wholesale electricity markets. This report describes how to consider energy efficiency as a potential resource for the future by allowing it to compete with all other electricity system resources.Increasing levels of wind and solar, growth in peak demand, and electrification of transportation and other new loads have increased the need for a more flexible and responsive electricity system. Considering energy efficiency as a resource option can support these and other electricity system objectives, including grid reliability, reduced electricity costs, energy efficiency targets, and lower air pollutant emissions.The October 2019 slides were presented at the American Council for an Energy Efficient Economy Energy Efficiency as a Resource conference and provide an overview of the report. Portions of the report were included in the American Council for an Energy Efficient Economy Energy Efficiency 2020 Summer Study paper, Planning for the Grid of Tomorrow: Energy Efficiency as a Resource in Utility Resource Plans.

The risks of long-duration, widespread interruptions (LDWIs) in electrical power are a concern of U.S. regulators, the electric power industry, and stakeholders. Those responsible for making decisions about increasingly costly investments to prevent such interruptions and to facilitate rapid recovery when they do occur need relevant information on which to base those decisions. Although a number of studies have examined the physical and engineering impacts of extreme weather and other precipitating events on the bulk power system, decision makers evaluating investments in preventive strategies need information on the costs of past power interruptions and the benefits of preventing them in the future. This paper contributes to addressing this need by offering six case studies that detail the economics, at the level of the utility service territory, of power interruptions caused by extreme weather and lasting from a few days to several weeks. These intermediate-duration interruptions have been, and will continue to be, the most common type of major electric power disruption. They are longer than the short-term disruptions addressed in utility reliability planning, but not as long or widespread geographically as the national-scale interruptions with durations of many weeks, months, or longer that have been examined in some recent studies. Through case studies, we are able to address the following five questions that have important policy and long-term planning implications for reducing power system vulnerabilities:1. How do utilities assess the costs of system damage caused by extreme weather and the costs of recovering from this damage?2. How do utilities estimate customer costs of past power interruptions?3. How do utilities or others estimate the costs and benefits of investments to reduce power system vulnerabilities to future extreme weather events?4. How do utilities and regulators use the concept of resilience in economic assessments of extreme weather impacts and the value of preventive investments?5. How do regulatory processes influence utilities’ economic analysis related to power interruptions?Finally, the case studies reveal a number of areas in which further research could be beneficial to utilities and regulators dealing with risks associated with LDWIs.

Load Serving Entities (LSEs) can procure electricity from their owned generation or purchase it on bilateral or centrally organized markets. Electric utility procurement decisions have important implications for resource adequacy, which is gaining attention especially in the Western U.S. However, there is little or no research on trends of utility procurement practices, and the role that wholesale market transactions can have for resource adequacy and other applications. This paper leverages information from the U.S. Department of Energy’s Energy Information Administration, Berkeley Lab’s Resource Planning Portal, and structured interviews with regulatory and utility staff. We find that use of market transactions to meet electric energy needs has been increasing across U.S. LSEs. The reasons for this trend include a general stagnation in building owned resources, a preference towards contracting renewable energy resources to meet RPS targets, and the lower relative cost of wholesale market electricity. Among market transactions across different time scales, short-term transactions were prevalent in Western U.S. LSEs until the 2008 recession, and thereafter declined to about a quarter of total purchases. In contrast, long-term market transactions have become more prevalent and resource planning reports project the share of these transactions in the procurement mix may continue to increase. Results suggest resource adequacy obligations may drive preferences for asset ownership more than a profit incentive. We also recommend improving the planning to procurement connection by reflecting in planning assumptions the operational constraints of market transactions. These results provide insights on key issues in electric utility procurement that could improve overall market efficiency, respond to rapidly changing industry conditions, and identify practices that LSEs and regulators should consider incorporating into their long-term transmission and capacity planning processes.

Integrated resource planning is an important regulatory process used in many U.S. states to formulate and evaluate least-cost and risk-assessed portfolios to meet future load requirements for electric utilities. In principle, effective implementation of integrated resource planning seeks to assure regulators and the public that utility investment decisions, given uncertainty, are as cost-effective as possible. However, there is no empirical assessment on the effectiveness of integrated resource planning and its implementation. This paper compares planning outcomes and actual decisions for twelve utilities across the Western U. S. from 2003 to 2014. The authors find that subsequent plans differ significantly due to changes in the planning environment, which limited amount of information produced during planning is ultimately used during the procurement process, and that the latter process relies extensively on the most recent information available for decision making. These findings suggest that states' integrated resource planning rules and regulations mandating long-term planning horizons with the same analytical complexity throughout the planning period may not create useful information for the procurement process. The social value of a long-term planning process that departs from procurement and the balance between transparency and complexity of the planning and procurement processes is an open question.

Forecasts of electricity consumption and peak demand over time horizons of one or two decades are a key element in electric utilities’ meeting their core objective and obligation to ensure reliable and affordable electricity supplies for their customers while complying with a range of energy and environmental regulations and policies. These forecasts are an important input to integrated resource planning (IRP) processes involving utilities, regulators, and other stake-holders. Despite their importance, however, there has been little analysis of long term utility load forecasting accuracy. We conduct a retrospective analysis of long term load forecasts on twelve Western U. S. electric utilities in the mid-2000s to find that most overestimated both energy consumption and peak demand growth. A key reason for this was the use of assumptions that led to an overestimation of economic growth. We find that the complexity of forecast methods and the accuracy of these forecasts are mildly correlated. In addition, sensitivity and risk analysis of load growth and its implications for capacity expansion were not well integrated with subsequent implementation. We review changes in the utilities load forecasting methods over the subsequent decade, and discuss the policy implications of long term load forecast inaccuracy and its underlying causes.

The program administrator and total cost of saved energy allow comparison of the cost of efficiency across utilities, states, and program types, and can identify potential performance improvements. Comparing program administrator cost with the total cost of saved energy can indicate the degree to which programs leverage investment by participants. Based on reported total costs and savings information for U.S. utility efficiency programs from 2009 to 2013, we estimate the savings-weighted average total cost of saved electricity across 20 states at 0.046 per kilowatt-hour (kW h), comparing favorably with energy supply costs and retail rates. Programs targeted on the residential market averaged 0.030 per kW h compared to 0.053 per kW h for non-residential programs. Lighting programs, with an average total cost of 0.018 per kW h, drove lower savings costs in the residential market. We provide estimates for the most common program types and find that program administrators and participants on average are splitting the costs of efficiency in half. More consistent, standardized and complete reporting on efficiency programs is needed. Differing definitions and quantification of costs, savings and savings lifetimes pose challenges for comparing program results. Reducing these uncertainties could increase confidence in efficiency as a resource among planners and policymakers.

Integrated resource planning (IRP) is a process used by many vertically-integrated U.S. electric utilities to determine least-cost/risk supply and demand-side resources that meet government policy objectives and future obligations to customers and, in many cases, shareholders. Forecasts of energy and peak demand are a critical component of the IRP process. There have been few, if any, quantitative studies of IRP long-run (planning horizons of two decades) load forecast performance and its relationship to resource planning and actual procurement decisions. In this paper, we evaluate load forecasting methods, assumptions, and outcomes for 12 Western U.S. utilities by examining and comparing plans filed in the early 2000s against recent plans, up to year 2014. We find a convergence in the methods and data sources used. We also find that forecasts in more recent IRPs generally took account of new information, but that there continued to be a systematic over-estimation of load growth rates during the period studied. We compare planned and procured resource expansion against customer load and year-to-year load growth rates, but do not find a direct relationship. Load sensitivities performed in resource plans do not appear to be related to later procurement strategies even in the presence of large forecast errors. These findings suggest that resource procurement decisions may be driven by other factors than customer load growth. Our results have important implications for the integrated resource planning process, namely that load forecast accuracy may not be as important for resource procurement as is generally believed, that load forecast sensitivities could be used to improve the procurement process, and that management of load uncertainty should be prioritized over more complex forecasting techniques.

Assumptions regarding the magnitude and direction of energy-related technological change have long been recognized as critical determinants of the outputs and policy conclusions derived from integrated assessment models. Particularly in the case of developing countries, however, empirical analysis of technological change has lagged behind simulation modeling. This paper presents estimates of sectoral productivity trends and energy-augmenting technological change for several energy-intensive industries in India and South Korea, and, for comparison, the United States. The key findings are substantial heterogeneity among both industries and countries, and a number of cases of declining energy efficiency. The results are subject to certain technical qualifications both in regards to the methodology and to the direct comparison to integrated assessment parameterizations. Nevertheless, they highlight the importance of closer attention to the empirical basis for common modeling assumptions.

Pooled data across several developing countries and the U. S. were used to estimate long-run substitution and price elasticities in a translog framework for the paper, iron and steel, and aggregate manufacturing industries. While the quality of the estimates varies across the several industry-specific models, the results suggest higher values for these elasticities than appear commonly used in integrated assessment models. Estimates of own-price elasticities of energy range from - 0.80 to - 1.76 and are comparable to estimates from previous econometric studies in the context of developed countries (- 0.77 to - 0.87). Substitution elasticities show wider variation across countries and industries. For energy and capital they range from -1.96 to 9.80, for labor and energy from 2.61 to 7.11, and for energy and material from - 0.26 to 2.07.

A recent (1996-2000) acceleration of declines in energy and carbon intensity in the U.S. remains largely unexplained. This study uses Divisia decomposition and regression to test two candidate explanations - fuel mix and weather. The Divisia method demonstrates that fuel mix does not explain the declines in carbon intensity. The fuel mix, both overall and for electricity generation, became slightly more carbon intensive over the study period (though the slight trend reversed before the end of the period). A regression-based correction to the Divisia indices, accounting for variation in heating- and cooling-degree-days, indicates that warmer weather accounts for about 30 percent of the total declines. This leaves declines of more than 2 percent per year (and an acceleration of more than 1 percent over previous decade) remaining to be explained.

Power industry stakeholders are devoting increasing attention to the risks of long-duration, widespread interruptions (LDWIs) in electricity service. There is concern that these risks are heightening due to more frequent and severe extreme weather events. Numerous studies have examined various aspects of the problem, primarily from an engineering and conceptual perspective. This is the first of two papers reporting the results of a study of LDWIs that focuses on their economic aspects, takes an empirical approach, and includes consideration of institutional factors affecting utilities' efforts to reduce their vulnerabilities to these disruptions. This paper presents background on the problem, including cost concepts relevant to economic valuation of measures to reduce the risks of LDWIs, valuation methods, and the role of the concept of 'resilience' in shaping analysis in this area. This material provides context and motivation for the second paper, which reports on a series of case studies. [ABSTRACT FROM AUTHOR]

Many economists question engineering-economic studies aimed at demonstrating anomalously slow diffusion of energy-efficient technology and the benefits of regulations to promote such technology. One argument against such studies is that standard techniques of engineering economics are either inappropriate or are routinely misapplied in assessing the performance of the market for energy efficiency. This paper takes account of such critiques in presenting engineering-economic evidence on the diffusion of energy efficiency improvements. It examines the engineering and economic characteristics of standard and energy-efficient magnetic ballasts for fluorescent lighting. Efficient magnetic ballasts represent an excellent investment for 99 percent of the commercial building floor stock and a moderately good investment for 0.7 percent of the commercial floor stock. Still, in the 1980s these ballasts were being adopted only at a rate commensurate with the enactment of appliance efficiency standards in various states. In this case, solid empirical evidence supports skepticism about the effectiveness of the market mechanism in promoting cost-effective energy efficiency improvements and about the benefits of regulation to counteract this shortcoming., I. INTRODUCTION When Galileo first investigated the motion of falling bodies, he conducted what the Aristotelian clerics regarded as a heretical thought experiment. He imagined a world in which friction [...]

Previous studies have proven that many consumers investing in energy efficiency gain high implicit discount rates that substantially exceed market interest rates for borrowing and saving. This observation has been explained by applying the concept of option value adapted from the finance theory. However, the concept does not provide adequate explanation for the pattern in energy-efficiency investments.

Empirical studies provide compelling evidence that economic agents do not adopt the complete range of energy-efficient technologies that are cost-effective under prevailing prices and market conditions. Analysts commonly attribute this anomaly to the use of high discount rates in energy-related decisions - an interpretation that is difficult to reconcile with standard models of rational choice. This paper recasts the controversy from the perspective of economic theory and finds that market failures related to asymmetric information, bounded rationality, and transaction costs are major contributors to the so-called 'efficiency gap.', I. INTRODUCTION Markets for energy-using equipment are marked by a seeming anomaly: households and firms routinely pass up investments in energy-efficient technologies yielding rates-of-return well above those available on standard [...]

A framework for identifying technical evidence of market failures on energy-efficient improvements is developed. The methodology is applied to examples of cost-effective, energy-efficient technologies hampered by market imperfections, thus demonstrating the presence of market failures. This empirical evidence that reinforces skepticism about the efficacy of the market mechanism in the adoption of energy-efficient improvements can be used by economists, policy analysts and technologists examining market failures related to energy efficiency and thus, in formulating policy that tackles these failures.

The debate between 'engineering' and 'economic' approaches to energy analysis clouds major issues concerning the cost-benefit analysis of policies that encourage the adoption of energy-efficient technologies. The engineering approach, however, has economic basis as it is grounded on the least-cost provision of energy and the potential economic gains from energy-efficient technologies. Thus, the existence of market failures is suggested by evidence that 'market barriers' hamper the adoption of cost-effective and energy-efficient technologies.