Assessing Changes in the Reliability of the U.S. Electric Power System

Abstract

Recent catastrophic weather events, existing and prospective federal and state policies, and growing investments in smart grid technologies have drawn renewed attention to the reliability of the U.S. electric power system. Whether electricity reliability is getting better or worse as a result of these or other factors has become a material issue for public and private decisions affecting the U.S. electric power system. This study examines the statistical relationship between annual changes in electricity reliability reported by a large cross-section of U.S. electricity distribution utilities over a period of 13 years, and a broad set of potential explanatory variables including various measures of weather and utility characteristics.We find statistically significant correlations between the average number of power interruptions experienced annually by a customer and a number of explanatory variables including wind speed, precipitation, lightning strikes, and the number of customers per line mile. We also find statistically significant correlations between the average total duration of power interruptions experienced annually by a customer and wind speed, precipitation, cooling degree-days, the percentage share of underground transmission and distribution lines. In addition, we find a statistically significant trend in the duration of power interruptions over time-especially when major events are included. This finding suggests that increased severity of major events over time has been the principal contributor to the observed trend.Assessing Changes in the Reliability of the U.S. Electric Power System │ii AcknowledgmentsThe work described in this report was funded by the Office of Electricity Delivery and Energy Reliability, National Electricity Delivery Division of the U.S. Department of Energy (DOE) under Contract No. DE-AC02-05CH11231. The authors are grateful to David Meyer for his support of this research.We gratefully acknowledge a number of individuals who provided technical assistance, constructive advice, and/or encouragement at various points during this project: Amber Armentrout (Ventyx), William Morrow, Peter Cappers, Annika Todd, Liesel Hans, and Anna Spurlock (Lawrence Berkeley National Laboratory), Alex Hofmann, Mike Hyland (APPA), Marek Samotyj (EPRI), Bernard Neenan (Neenan Associates), Caitlin Callaghan, Rakesh Batra, and David Ortiz (DOE), Seth Blumsack (Pennsylvania State University), James Bouford (Quanta-Technology), Brett Efaw (Idaho Power), Larry Conrad (Conrad Technical Services), and John Weyant (Stanford University). We thank Dana Robson and Danielle Callaghan for their assistance with formatting the final version of the report and disseminating the results to interested stakeholders.Peter would like to thank the LBNL Tuition Assistance Program for indirectly supporting this research project. Finally, we are indebted to staff at the electric utilities and public utility commissions who shared reliability performance metrics and other insightful information with us in the early ...

A method to estimate the costs and benefits of undergrounding electricity transmission and distribution lines

“…Fig. 1 shows the average SAIFI values for all Texas utilities used in the Larsen et al (2015) study without and with major events (i.e., severe storms) included. The pronounced effect of major events on the frequency of outages can be seen in this figure.…”

“…The avoided costs from a more reliable electrical grid were derived by (1) applying an econometric model developed by Larsen et al (2015) to estimate the total number of outages-under the status quo-from now until 2050; (2) estimating the total number of outages-for the undergrounding alternative-by gradually removing the effect of weather on this same econometric model as the share of undergrounded line miles increases each year; (3) assigning a dollar value for the total number of annual customer-outages for both alternatives; and (4) subtracting the outage-related costs for the undergrounding alternative from the outage costs for the status quo to determine the dollar value of reduced outages. Larsen et al (2015) develop an electric utility reliability model that correlates annual measures of weather (heating degree-days, cooling degreedays, lightning strikes, wind speed, and precipitation), utility T&D expenditures, delivered electricity, presence of outage management systems, number of customers per line mile, and share of underground miles to the frequency of power outages (Outages t StatusQuo) across the United States …”

“…The model coefficients (and intercept) from Larsen et al (2015) were used along with average values of historical weather and other model inputs that are relevant for Texas (see Technical Appendix) to estimate the future number of outages for Texas IOUs for the status quo.…”

“…Transparent assessments of the costs and benefits of undergrounding and other grid-hardening activities are useful to policymakers interested in enabling the long-term resilience of critical electricity system infrastructure (Executive Office of the President, 2013a). Larsen et al (2015) found that U.S. power system reliability is generally getting worse over time (i.e., average annual interruption durations are increasing), due in large part to impacts associated with increasingly severe weather. This study also found that customers of utilities with a relatively larger share of underground line miles typically experienced less frequent and total minutes of power interruptions when compared to utility customers in places that had a lower share of undergrounded line miles.…”

“…The purpose of this study is to expand on research by Larsen et al (2015) by systematically evaluating a policy that requires investorowned utilities (IOUs) to bury all existing and future transmission and distribution lines underground. More specifically, this analysis will attempt to address the following questions:…”