Pub Date : 2025-02-01DOI: 10.1016/j.tej.2025.107459
İsmail Kavaz
This study undertakes a comprehensive analysis of the income and price elasticities of residential electricity demand for Türkiye, spanning from 1980 to 2018. By employing the Structural Time Series Modelling method, the short- and long-run factors of income elasticities are found as 0.20 and 0.32, while the corresponding price parameters are determined as −0.08 for the short-term and −0.14 in the long-term, respectively. These elasticity estimations are crucial for informing policy-making processes, particularly in strategizing for the residential sector in Türkiye. The inelastic nature of these estimates, being less than 1, suggests that electricity constitutes a necessary commodity within the residential sector of Türkiye. It implies a limited sensitivity of consumers to fluctuations in price and income, indicating that changes in these factors do not significantly alter residential electricity demand in Türkiye. Additionally, this study extends its insights by providing forecasts for residential electricity demand. The projections indicate that by the year 2030, the electricity demand within Türkiye’s residential sector is projected to range between 90 and 106 Terawatt-hours (TWh). This forecasted data serves as an essential tool for future planning and policy development in the context of residential electricity consumption.
{"title":"How income and price changes affect the electricity demand? Evidence from Türkiye’s residential sector","authors":"İsmail Kavaz","doi":"10.1016/j.tej.2025.107459","DOIUrl":"10.1016/j.tej.2025.107459","url":null,"abstract":"<div><div>This study undertakes a comprehensive analysis of the income and price elasticities of residential electricity demand for Türkiye, spanning from 1980 to 2018. By employing the Structural Time Series Modelling method, the short- and long-run factors of income elasticities are found as 0.20 and 0.32, while the corresponding price parameters are determined as −0.08 for the short-term and −0.14 in the long-term, respectively. These elasticity estimations are crucial for informing policy-making processes, particularly in strategizing for the residential sector in Türkiye. The inelastic nature of these estimates, being less than 1, suggests that electricity constitutes a necessary commodity within the residential sector of Türkiye. It implies a limited sensitivity of consumers to fluctuations in price and income, indicating that changes in these factors do not significantly alter residential electricity demand in Türkiye. Additionally, this study extends its insights by providing forecasts for residential electricity demand. The projections indicate that by the year 2030, the electricity demand within Türkiye’s residential sector is projected to range between 90 and 106 Terawatt-hours (TWh). This forecasted data serves as an essential tool for future planning and policy development in the context of residential electricity consumption.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"38 1","pages":"Article 107459"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150172","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.tej.2025.107460
Tanaya Saha
Electricity has an unswerving impact on financial sustainability of a country; hence, everybody must have equal access to electricity. However, in a developing country like India, the inequality in electricity distribution intensifies in the rural areas and gets further skewed with respect to gender. The skewness is owing to the differential gender needs. The study has attempted to empirically analyze the impact of rural electrification on gender inequality across rural areas of 36 Indian states and union territories over 2015–2019. Gender inequality is measured through the ratio of female and male rural labor force participation, while rural literacy gap and self-help group loans are taken as controls. The analysis is carried out at the aggregate level, followed by segregation based on presence or absence of women police stations, geographical regions, and quantiles. The results show that although rural electrification and other drivers of gender inequality can have positive impact on achieving rural gender equality in rural India, there is need of policies that can help in maximizing use of electrification.
{"title":"Assessing the impact of rural electrification on gender inequality in rural India: A state-level analysis","authors":"Tanaya Saha","doi":"10.1016/j.tej.2025.107460","DOIUrl":"10.1016/j.tej.2025.107460","url":null,"abstract":"<div><div>Electricity has an unswerving impact on financial sustainability of a country; hence, everybody must have equal access to electricity. However, in a developing country like India, the inequality in electricity distribution intensifies in the rural areas and gets further skewed with respect to gender. The skewness is owing to the differential gender needs. The study has attempted to empirically analyze the impact of rural electrification on gender inequality across rural areas of 36 Indian states and union territories over 2015–2019. Gender inequality is measured through the ratio of female and male rural labor force participation, while rural literacy gap and self-help group loans are taken as controls. The analysis is carried out at the aggregate level, followed by segregation based on presence or absence of women police stations, geographical regions, and quantiles. The results show that although rural electrification and other drivers of gender inequality can have positive impact on achieving rural gender equality in rural India, there is need of policies that can help in maximizing use of electrification.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"38 1","pages":"Article 107460"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143436893","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.tej.2025.107456
Abhiroop Chattopadhyay , Ann-Perry Witmer
There is an increasing recognition of the central role of energy equity and social justice in energy planning. Governments, utilities, planners, and the research community are working to advance a more nuanced understanding of energy equity, involving distributive, procedural, recognitional, and restorative aspects. Complete energy equity requires a holistic understanding of all these aspects, and energy planning should attempt to address them simultaneously. In practice, this can be challenging in contexts where the available pool of human and economic resources is limited. This article presents a case study of a community within the Navajo Nation to illustrate the challenges and implications in such contexts. The first challenge is the inevitable prioritization and compartmentalization of decision making due to the constraints imposed by the planners’ primary mandates, authority, place-based contextual factors, and available resources. The second – related – challenge is the impact of the resulting decisions on realized outcomes, and its effects on the community perceptions of – and confidence in – the planning institutions. The case study also finds that equity concerns of the utility’s end-customers may not always be uniform and are influenced by the customers’ perspectives, roles, responsibilities, and expectations. Thus, a more holistic view of energy planning is necessary to 1) capture the variations of equity opinions and priorities across all stakeholders, 2) to ensure that decisions and resource allocations by utilities, elected bodies, or governmental agencies occur on multiple fronts in a coordinated and transparent manner to advance energy equity targets.
{"title":"Practical energy equity decision making in resource-constrained communities: A case study in the Navajo Nation","authors":"Abhiroop Chattopadhyay , Ann-Perry Witmer","doi":"10.1016/j.tej.2025.107456","DOIUrl":"10.1016/j.tej.2025.107456","url":null,"abstract":"<div><div>There is an increasing recognition of the central role of energy equity and social justice in energy planning. Governments, utilities, planners, and the research community are working to advance a more nuanced understanding of energy equity, involving distributive, procedural, recognitional, and restorative aspects. Complete energy equity requires a holistic understanding of all these aspects, and energy planning should attempt to address them simultaneously. In practice, this can be challenging in contexts where the available pool of human and economic resources is limited. This article presents a case study of a community within the Navajo Nation to illustrate the challenges and implications in such contexts. The first challenge is the inevitable prioritization and compartmentalization of decision making due to the constraints imposed by the planners’ primary mandates, authority, place-based contextual factors, and available resources. The second – related – challenge is the impact of the resulting decisions on realized outcomes, and its effects on the community perceptions of – and confidence in – the planning institutions. The case study also finds that equity concerns of the utility’s end-customers may not always be uniform and are influenced by the customers’ perspectives, roles, responsibilities, and expectations. Thus, a more holistic view of energy planning is necessary to 1) capture the variations of equity opinions and priorities across all stakeholders, 2) to ensure that decisions and resource allocations by utilities, elected bodies, or governmental agencies occur on multiple fronts in a coordinated and transparent manner to advance energy equity targets.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"38 1","pages":"Article 107456"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143151178","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.tej.2024.107449
Igor Westphal
Load forecasting has increasingly relied on deep learning models due to their ability to capture complex non-linear relationships. However, these models require substantial amounts of data for effective training. Data sparsity during peak load periods can degrade the performance of deep learning models to the point that they under-perform much simpler models. To address this issue, this paper proposes a post-training specialization method in which several copies of the original deep learning model are retrained for specific forecasting tasks. Results indicate an increase in performance in all baseline models used in this paper, and the method can potentially improve the forecasting of current applications at a low computational cost.
{"title":"Short-term load forecasting with deep learning: Improving performance with post-training specialization","authors":"Igor Westphal","doi":"10.1016/j.tej.2024.107449","DOIUrl":"10.1016/j.tej.2024.107449","url":null,"abstract":"<div><div>Load forecasting has increasingly relied on deep learning models due to their ability to capture complex non-linear relationships. However, these models require substantial amounts of data for effective training. Data sparsity during peak load periods can degrade the performance of deep learning models to the point that they under-perform much simpler models. To address this issue, this paper proposes a post-training specialization method in which several copies of the original deep learning model are retrained for specific forecasting tasks. Results indicate an increase in performance in all baseline models used in this paper, and the method can potentially improve the forecasting of current applications at a low computational cost.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"38 1","pages":"Article 107449"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143150170","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2025-02-01DOI: 10.1016/j.tej.2025.107457
Farzan ZareAfifi, Ricardo de Castro, Sarah Kurtz
Recent studies show how a strategic shift towards daytime charging of electric vehicles (EVs) has the potential to be a powerful game-changer, leveraging flexible EV loads to maintain solar value on the grid and aligning EV charging energy load with solar generation. Also, recent studies show the benefits of expanding investment in daytime charging infrastructure and reforming time-of-use rates to promote daytime charging. By harmonizing energy consumption patterns with solar supply, we can increase the solar industry's economic appeal and sustain its growth trajectory while potentially reducing cost and improving convenience for charging vehicles that are parked during the day. This study integrates all these different studies and provides a comprehensive perspective on the benefits, challenges, and barriers to implementing daytime EV charging at scale.
{"title":"Aligning electric vehicle charging with the sun: An opportunity for daytime charging?","authors":"Farzan ZareAfifi, Ricardo de Castro, Sarah Kurtz","doi":"10.1016/j.tej.2025.107457","DOIUrl":"10.1016/j.tej.2025.107457","url":null,"abstract":"<div><div>Recent studies show how a strategic shift towards daytime charging of electric vehicles (EVs) has the potential to be a powerful game-changer, leveraging flexible EV loads to maintain solar value on the grid and aligning EV charging energy load with solar generation. Also, recent studies show the benefits of expanding investment in daytime charging infrastructure and reforming time-of-use rates to promote daytime charging. By harmonizing energy consumption patterns with solar supply, we can increase the solar industry's economic appeal and sustain its growth trajectory while potentially reducing cost and improving convenience for charging vehicles that are parked during the day. This study integrates all these different studies and provides a comprehensive perspective on the benefits, challenges, and barriers to implementing daytime EV charging at scale.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"38 1","pages":"Article 107457"},"PeriodicalIF":0.0,"publicationDate":"2025-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143151177","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.tej.2024.107441
Jeremy Twitchell
There is growing interest in deploying energy storage as a transmission asset (SATA), as evidenced by an evolving body of supportive policies and regulations and an expanding body of literature on the topic. Despite nearly two decades of evolution, however, transmission planning processes in the United States rarely consider storage alternatives and only a handful of projects have been selected. Regulators have assigned the responsibility of proposing non-transmission alternatives to non-utility participants in the planning process, so the sparse record of SATA projects may therefore result from a lack of specificity about the use cases for SATA and uncertainty about when it should be proposed. Extensive literature has been devoted to the topic of SATA, but much of it relies on definitions that are inconsistent with regulatory precedent and that exacerbate confusion. This paper reviews regulatory proceedings to define three types of energy storage assets than can interact with the transmission system: storage as a transmission asset, storage in place of a transmission asset (SIPTA), and dual-use energy storage. It then provides an inventory of use cases for SATA and SIPTA projects, using brief case studies to illustrate each use case. By clarifying the definition of SATA and its roles in transmission system planning, this work may be of use to transmission system planners and other participants in transmission planning processes to identify situations in which SATA alternatives merit consideration.
人们对将储能作为输电资产（SATA）进行部署的兴趣与日俱增，这体现在不断发展的支持性政策和法规，以及有关该主题的文献数量不断增加。然而，尽管经历了近二十年的发展，美国的输电规划过程却很少考虑储能替代方案，只有少数项目被选中。监管机构将提出非输电替代方案的责任分配给了规划过程中的非公用事业参与者，因此 SATA 项目的记录稀少可能是由于对 SATA 的使用案例缺乏明确性，以及对何时应该提出 SATA 的不确定性造成的。关于 SATA 的主题已有大量文献，但其中大部分依赖于与监管先例不一致的定义，这加剧了混淆。本文回顾了监管程序，以定义可与输电系统互动的三类储能资产：作为输电资产的储能、代替输电资产的储能 (SIPTA) 以及两用储能。然后，报告提供了 SATA 和 SIPTA 项目的用例清单，并使用简要案例研究来说明每种用例。通过澄清 SATA 的定义及其在输电系统规划中的作用，本报告可帮助输电系统规划人员和输电规划流程的其他参与者确定在哪些情况下值得考虑 SATA 替代方案。
{"title":"Energy storage as a transmission asset: Definitions and use cases","authors":"Jeremy Twitchell","doi":"10.1016/j.tej.2024.107441","DOIUrl":"10.1016/j.tej.2024.107441","url":null,"abstract":"<div><div>There is growing interest in deploying energy storage as a transmission asset (SATA), as evidenced by an evolving body of supportive policies and regulations and an expanding body of literature on the topic. Despite nearly two decades of evolution, however, transmission planning processes in the United States rarely consider storage alternatives and only a handful of projects have been selected. Regulators have assigned the responsibility of proposing non-transmission alternatives to non-utility participants in the planning process, so the sparse record of SATA projects may therefore result from a lack of specificity about the use cases for SATA and uncertainty about when it should be proposed. Extensive literature has been devoted to the topic of SATA, but much of it relies on definitions that are inconsistent with regulatory precedent and that exacerbate confusion. This paper reviews regulatory proceedings to define three types of energy storage assets than can interact with the transmission system: storage <u>as</u> a transmission asset, storage <u>in place of</u> a transmission asset (SIPTA), and <u>dual-use</u> energy storage. It then provides an inventory of use cases for SATA and SIPTA projects, using brief case studies to illustrate each use case. By clarifying the definition of SATA and its roles in transmission system planning, this work may be of use to transmission system planners and other participants in transmission planning processes to identify situations in which SATA alternatives merit consideration.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"37 7","pages":"Article 107441"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142552867","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.tej.2024.107446
Robert H. Schulte, Raymond J. Wahle
The Federal Energy Regulatory Commission (FERC) on May 13, 2024 issued its Order 1920: “Building for the Future Through Electric Regional Transmission Planning and Cost Allocation”. Years in the making and building on its previous Order 1000 and others, this 1363-page Order is being hailed as a landmark in promoting needed electric transmission development in the United States going forward. While establishing needed detailed requirements for transmission planning within regions, the Order stopped short of addressing interregional planning other than identifying issues related to it.
Expanding on the traditional concept of intraregional transmission planning, interregional planning offers advanced benefits including reduced production (fuel) costs, improved generation capacity sharing, increased clean energy supplies, reduced renewables curtailment, and improved reliability and resiliency by providing transmission support between regions.
On a parallel path, Congress has recently become very active in efforts related to encouraging interregional transmission. Multiple bills have been introduced the past two years, addressing permitting reform, requirements for interregional planning, specification of minimum interregional transfer capacity, and offering investment tax credits, among other topics. While Order 1920 is now subject to numerous appeals and lawsuits that will take time to be resolved, and the Congressional bills remain to be potentially combined and passed, these are all positive signs for interregional transmission development going forward.
Meanwhile, the authors have been engaged the past several years in working with multiple utilities toward development of the Power from the Prairie (PftP) interregional transmission project (www.powerfromtheprairie.com). While these utilities whom the authors recruited are a select few who can think outside their service territories toward potential interregional collaboration, significant challenges and obstacles still exist. These represent the real-world issues of whether interregional transmission can actually occur.
This article combines the content of FERC Order 1920 and the various Congressional bills with the on-the-ground experience with utilities thinking about doing interregional transmission. The authors conclude that there is much more FERC can and should do going beyond Order 1920, in concert with Congress and others, to enable interregional transmission development to happen. A “Road Map” of potential next actions by FERC is suggested. In addition, the need to form a new entity that takes a more holistic interregional transmission planning view to overcome current industry inertia is also discussed.
{"title":"What FERC should do to enable interregional electric transmission","authors":"Robert H. Schulte, Raymond J. Wahle","doi":"10.1016/j.tej.2024.107446","DOIUrl":"10.1016/j.tej.2024.107446","url":null,"abstract":"<div><div>The Federal Energy Regulatory Commission (FERC) on May 13, 2024 issued its Order 1920: “Building for the Future Through Electric Regional Transmission Planning and Cost Allocation”. Years in the making and building on its previous Order 1000 and others, this 1363-page Order is being hailed as a landmark in promoting needed electric transmission development in the United States going forward. While establishing needed detailed requirements for transmission planning <em>within</em> regions, the Order stopped short of addressing <em>interregional</em> planning other than identifying issues related to it.</div><div>Expanding on the traditional concept of <em>intra</em>regional transmission planning, <em>inter</em>regional planning offers advanced benefits including reduced production (fuel) costs, improved generation capacity sharing, increased clean energy supplies, reduced renewables curtailment, and improved reliability and resiliency by providing transmission support between regions.</div><div>On a parallel path, Congress has recently become very active in efforts related to encouraging interregional transmission. Multiple bills have been introduced the past two years, addressing permitting reform, requirements for interregional planning, specification of minimum interregional transfer capacity, and offering investment tax credits, among other topics. While Order 1920 is now subject to numerous appeals and lawsuits that will take time to be resolved, and the Congressional bills remain to be potentially combined and passed, these are all positive signs for interregional transmission development going forward.</div><div>Meanwhile, the authors have been engaged the past several years in working with multiple utilities toward development of the Power from the Prairie (PftP) interregional transmission project (www.powerfromtheprairie.com). While these utilities whom the authors recruited are a select few who can think outside their service territories toward potential interregional collaboration, significant challenges and obstacles still exist. These represent the real-world issues of whether interregional transmission can actually occur.</div><div>This article combines the content of FERC Order 1920 and the various Congressional bills with the on-the-ground experience with utilities thinking about doing interregional transmission. The authors conclude that there is much more FERC can and should do going beyond Order 1920, in concert with Congress and others, to enable interregional transmission development to happen. A “Road Map” of potential next actions by FERC is suggested. In addition, the need to form a new entity that takes a more holistic interregional transmission planning view to overcome current industry inertia is also discussed.</div></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"37 7","pages":"Article 107446"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142658421","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.tej.2024.107430
Giulia Ragosa
Advancing the integration of neighbouring power markets is widely identified in the literature as a key enabler of power system efficiency, flexibility, and variable renewable energy integration. Nonetheless, the existing economic literature offers only partial explanations of why greater market integration is difficult to achieve in the real world despite its evident advantages in terms of overall welfare, supply security, and competitiveness. It is argued that power market coupling is an inherently political process involving significant institutional contestation and adaptation, and hence requires a more nuanced political analysis to be fully understood. This paper adds to the existing literature by conducting a comparative political economy analysis of electricity market coupling processes in Britain, Italy, and California, spanning from 2013 to 2021. It seeks to unpack how differences in the political economy contexts of these jurisdictions influenced the electricity market coupling process with their respective neighbouring systems. The analysis draws on 86 key policy documents, and 53 in-depth interviews with senior power system stakeholders in the three jurisdictions. Results widely align with claims in the political economy literature that market coupling outcomes do not simply reflect the most efficient solution. While all three jurisdictions have shown a commitment to enhance regional integration of short-term wholesale energy markets, there is considerable variation in policy outcomes, particularly the extent to which different segments of the market have been coupled. These differences can largely be attributed to variations in the political economy contexts of the three jurisdictions, including multi-level governance structures, diplomatic relations with neighbouring countries, and interactions with national political priorities and contexts. The main implications for the governance of electricity market coupling are discussed in the conclusion.
{"title":"The political economy of electricity market coupling: Comparing experiences from Europe and the United States","authors":"Giulia Ragosa","doi":"10.1016/j.tej.2024.107430","DOIUrl":"10.1016/j.tej.2024.107430","url":null,"abstract":"<div><p>Advancing the integration of neighbouring power markets is widely identified in the literature as a key enabler of power system efficiency, flexibility, and variable renewable energy integration. Nonetheless, the existing economic literature offers only partial explanations of why greater market integration is difficult to achieve in the real world despite its evident advantages in terms of overall welfare, supply security, and competitiveness. It is argued that power market coupling is an inherently political process involving significant institutional contestation and adaptation, and hence requires a more nuanced political analysis to be fully understood. This paper adds to the existing literature by conducting a comparative political economy analysis of electricity market coupling processes in Britain, Italy, and California, spanning from 2013 to 2021. It seeks to unpack how differences in the political economy contexts of these jurisdictions influenced the electricity market coupling process with their respective neighbouring systems. The analysis draws on 86 key policy documents, and 53 in-depth interviews with senior power system stakeholders in the three jurisdictions. Results widely align with claims in the political economy literature that market coupling outcomes do not simply reflect the most efficient solution. While all three jurisdictions have shown a commitment to enhance regional integration of short-term wholesale energy markets, there is considerable variation in policy outcomes, particularly the extent to which different segments of the market have been coupled. These differences can largely be attributed to variations in the political economy contexts of the three jurisdictions, including multi-level governance structures, diplomatic relations with neighbouring countries, and interactions with national political priorities and contexts. The main implications for the governance of electricity market coupling are discussed in the conclusion.</p></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"37 7","pages":"Article 107430"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S1040619024000654/pdfft?md5=291c4971dda58240b6ffdfbaf7a1c05e&pid=1-s2.0-S1040619024000654-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142084318","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.tej.2024.107439
László Berényi , Éva Pintér , Nikolett Deutsch
Acceleration of the green transition is one of the prime overarching goals of the European Union, in which a specific role is allocated to renewable-based power generation. This paper examines the impact of energy transition plans on the long-term electricity security levels of the Visegrad Countries (V4). The analysis includes a calculation of Simplified Supply-Demand Index (SSDI) scores based on the official forecast of the European Network of Transmission System Operators for Electricity (ENTSO-E). Results indicate that the level of electricity security is expected to diminish in the V4 countries. Simulation-based sensitivity analyses were also conducted to highlight that SSDI scores are especially sensitive to the vulnerability of supply, infrastructure, and demand categories within the composite index.
{"title":"Dependency and diversity – Electricity transition and security in the Visegrad Group countries (V4)","authors":"László Berényi , Éva Pintér , Nikolett Deutsch","doi":"10.1016/j.tej.2024.107439","DOIUrl":"10.1016/j.tej.2024.107439","url":null,"abstract":"<div><p>Acceleration of the green transition is one of the prime overarching goals of the European Union, in which a specific role is allocated to renewable-based power generation. This paper examines the impact of energy transition plans on the long-term electricity security levels of the Visegrad Countries (V4). The analysis includes a calculation of Simplified Supply-Demand Index (SSDI) scores based on the official forecast of the European Network of Transmission System Operators for Electricity (ENTSO-E). Results indicate that the level of electricity security is expected to diminish in the V4 countries. Simulation-based sensitivity analyses were also conducted to highlight that SSDI scores are especially sensitive to the vulnerability of supply, infrastructure, and demand categories within the composite index.</p></div>","PeriodicalId":35642,"journal":{"name":"Electricity Journal","volume":"37 7","pages":"Article 107439"},"PeriodicalIF":0.0,"publicationDate":"2024-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S1040619024000745/pdfft?md5=50735b30c2519b8e8f84021b7c642d95&pid=1-s2.0-S1040619024000745-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"142164703","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2024-08-01DOI: 10.1016/j.tej.2024.107444
David Havyatt, David Johnstone
All forms of economic regulation rely on observing the regulated firm’s costs which necessitates estimating the firm’s cost of capital including the cost of equity. Performance-based regulation (PBR) combines increased efficiency incentives with explicit performance-achievement rewards. It is attracting both increasing academic attention and greater application in electricity regulation. The standard textbook approaches to the Capital Asset Pricing Model (CAPM) incorrectly describe the asset beta as simply a measure of risk. More correctly, it is a measure of risk per unit of expected return. This interpretation makes the use of the CAPM to determine allowed rates of return problematic. The incentives in Performance Based Regulation exacerbate this problem. Regulators who base part of their decision on "judgement" should rely more on that judgement and develop approaches that focus on regulatory, rather than market, outcomes.
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