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Open Access Publications from the University of California

Scholarly Works (14 results)

    LBL Publications (2004)
    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.
      Cover page: Bottom-up energy modeling
      • Article
      Lawrence Berkeley National Laboratory (2006)

      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.

        Cover page: Estimating energy-augmenting technological change in developing country industries
        • Article
        • Peer Reviewed
        LBL Publications (2019)
        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.
          Cover page: Exploring the relationship between planning and procurement in western U.S. electric utilities
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          • Peer Reviewed
          LBL Publications (2021)
          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.
            Cover page: Methods to Incorporate Energy Efficiency in Electricity System Planning and Markets
            • Article
            Lawrence Berkeley National Laboratory (2006)

            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.

              Cover page: Substitution and price elasticity estimates using inter-country pooled data in a translog cost model
              • Article
              Lawrence Berkeley National Laboratory (2002)

              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.

                Cover page: Contributions of weather and fuel mix to recent declines in U.S. energy and carbon intensity
                • Article
                • Peer Reviewed
                LBL Publications (2018)
                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.
                  Cover page: Long term load forecasting accuracy in electric utility integrated resource planningCreative Commons 'BY-NC-ND' version 4.0 license
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                  • Peer Reviewed
                  LBL Publications (2017)
                  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.
                    Cover page: Estimating the cost of saving electricity through U.S. utility customer-funded energy efficiency programs
                    • Article
                    LBL Publications (2016)
                    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.
                      Cover page: Load Forecasting in Electric Utility Integrated Resource Planning:
                      • Article
                      • Peer Reviewed
                      LBL Publications (2021)
                      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.
                        Cover page: A hybrid approach to estimating the economic value of power system resilience
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