Search

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 impac

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 impac

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.

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.

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 process

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 process

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.

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.

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.

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.

Two general approaches have been used for the integrated assessment of energy demand and supply: the so-called bottom-up and top-down approaches. The bottom-up approach focuses on individual technologies for delivering energy services, such as household durable goods and industrial process technologies. For such technologies, the approach attempts to estimate the costs and benefits associated with investments in increased energy efficiency, often in the context of reductions in greenhouse gas (GHG) emission or other environmental impacts. The top-down method assumes a general equilibrium or macroeconomic perspective, wherein costs are defined in terms of losses in economic output, income, or gross domestic product (GDP), typically from the imposition of energy or emission taxes.

Two general approaches have been used for the integrated assessment of energy demand and supply: the so-called bottom-up and top-down approaches. The bottom-up approach focuses on individual technologies for delivering energy services, such as household durable goods and industrial process technologies. For such technologies, the approach attempts to estimate the costs and benefits associated with investments in increased energy efficiency, often in the context of reductions in greenhouse gas (GHG) emission or other environmental impacts. The top-down method assumes a general equilibrium or macroeconomic perspective, wherein costs are defined in terms of losses in economic output, income, or gross domestic product (GDP), typically from the imposition of energy or emission taxes.

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.

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.