Growth in electric vehicle (EV) adoption has increased interest in using EV batteries as grid resources. Vehicle-to-Grid (V2G) technologies enable bidirectional power flows between electric vehicles and the electricity system and have demonstrated potential to support grid reliability and resilience in pilot programs worldwide. Despite demonstrated technical feasibility and system-level benefits for utility resource planning, broader V2G deployment remains limited. This study examines barriers to V2G adoption in the United States using qualitative evidence from 33 interviews with 42 stakeholders, including utilities, government agencies, original equipment manufacturers (OEMs), school districts, and participants in V2G pilot programs. We apply the Extended Unified Theory of Acceptance and Use of Technology (UTAUT2) as an organizing framework to examine adoption barriers across five constructs: facilitating conditions, effort expectancy, performance expectancy, price value, and social influence. Barriers related to facilitating conditions and effort expectancy emerge as the most salient, reflecting persistent challenges in standardization and interoperability across the V2G ecosystem, as well as concerns related to market development, infrastructure readiness, grid integration, and compatibility between vehicles and charging equipment. Performance expectancy follows, as stakeholders raise concerns about battery degradation, vehicle warranty implications, and vehicle availability in day-to-day operations. This study contributes to understanding barriers to V2G adoption and identifies policy-relevant pathways to reduce implementation challenges, including the development of interoperable standards and clearer institutional support. • Interviews with 42 experts identify key barriers to U.S. V2G deployment. • Non-uniform standards and interconnection processes limit V2G scalability. • UTAUT2 highlights facilitating conditions and effort expectancy as key barriers. • Utilities and OEMs face coordination and market-creation challenges. • Battery degradation, warranties, and value uncertainty constrain V2G adoption.

Achieving universal electricity access in rural areas remains a complex challenge in many developing countries, particularly for communities located within reach of existing distribution infrastructure but not yet connected. In such contexts, decision-makers must often choose between extending the main grid and deploying off-grid systems. This study presents a structured scoping review based on bibliographic sources, aimed at identifying how decision-making processes are supported in selection of rural electrificationstrategies, when both options are technically and economically viable. Following the PRISMA-ScR guidelines, a multi-phase filtering strategy was applied to the Scopus database, covering literature published between 2013 and 2024. A total of 3780 documents were initially retrieved, from which 136 were selected for in-depth analysis. Data extraction, co-citation mapping, keyword clustering, and thematic coding were used to classify the literature into five decision-related domains: technology selection, network configuration, system optimisation, policy frameworks, and multi-criteria methodologies. The review identifies recurring methodological patterns and systematises the decision-making criteria most frequently applied in rural electrification planning. It highlights that current approaches often treat grid extension and off-grid alternatives within isolated frameworks, despite their coexistence in practical planning scenarios. The analysis reveals significant gaps in the integration of technical, economic, social, environmental and institutional dimensions, as well as in the use of unified indicators that enable meaningful comparisons. These findings emphasise the need for more comprehensive frameworks that reflect the complexity of electrification choices in grid-adjacent rural areas and support more consistent, evidence-based planning processes. • A scoping review of 136 studies assesses decision-making in rural electrification planning. • Literature is categorised across five thematic domains using bibliometric and qualitative methods. • Decision-making tools lack integration of institutional and social dimensions. • Criteria used across studies remain heterogeneous and rarely comparable. • Findings reveal fragmented frameworks for planning trade-offs between grid and off-grid options.

This paper examines the increasing risks that bushfires and extreme weather events pose to electricity infrastructure and related systems, including climate-induced threats such as storms, floods, and heatwaves. These events cause extensive damage to transmission and distribution networks, leading to widespread blackouts, asset deterioration, and economic losses. Additionally, disruptions to electricity networks have broader societal implications, such as public health risks, transport failures, and economic instability, necessitating urgent adaptation measures. This paper highlights that traditional electricity infrastructure was designed for historical weather patterns and lacks the resilience needed to cope with these emerging climate threats. As part of this research, targeted consultations with key stakeholders were carried out with a view to gaining a deeper insight into the challenges faced by utilities in tackling resilience-related problems. The outcome of the consultations was a set of key findings, which were analysed and synthesised to provide relevant policy and technical recommendations for enhancing electricity infrastructure resilience. This paper puts forward a comprehensive set of recommendations aimed at fortifying Australia's electricity infrastructure resilience. Below is a summary of the key recommended actions. • Embed Resilience in Law and Regulation: Amend fundamental energy legislation to formally recognise resilience as a core objective, on par with reliability and affordability. This legal recognition would empower regulators to prioritise and enforce climate adaptation measures. In tandem, introduce an explicit statutory duty of care requiring electricity network providers to assess foreseeable climate risks and take reasonable steps to manage them. This places accountability on industry for proactive resilience planning. • Reform Funding and Incentive Structures: Establish funding mechanisms that support smaller-scale, pre-emptive resilience investments and streamline the regulatory approval process for these projects. Currently, networks can struggle to get funding for preventative works (like strengthening a substation against bushfires) under rules favouring large post-event capital projects. This paper recommends creating dedicated resilience funding allowances and simplifying the application and reporting requirements, especially for urgent minor works. • Enhance Coordination and Governance: Develop legal and regulatory mechanisms to enable joint planning and co-funded resilience projects across multiple network entities and jurisdictions. This paper suggests removing barriers that currently prevent Transmission and Distribution companies from pooling resources on resilience initiatives that span regions. A formal framework for cross-entity collaboration would encourage more strategic, system-wide interventions (such as strengthening key interstate interconnectors or sharing backup resources). Furthermore, this paper calls for establishing a national advisory body or expert panel on resilience that can guide consistent metric-setting, share best practices, and advise governments on emerging risks. • Strengthen Technical and Operational Measures: This paper advises recalibrating certain technical standards and practices to align with climate realities. For example, updating asset life and maintenance assumptions used in planning models – recognising that equipment may need replacement or reinforcement sooner under harsher conditions. Regulatory guidance should encourage more frequent asset inspections and upgrades in high-risk zones (such as coastal, bushfire-prone, or heat-vulnerable areas). This paper also recommends expanding the interconnectedness and flexibility of the grid. Enhancing inter-state energy transfer capabilities will allow surplus power to be rerouted to areas in need during emergencies, improving overall resilience and efficiency. Support for pilot projects in grid decentralisation (like community microgrids, distributed energy resources capable of islanding during disruptions, or distribution networks with islanding capabilities) is suggested as well, since localised energy systems can keep critical services powered even if the main grid is compromised. Taken together, these recommendations form a robust legal and policy roadmap complemented by practical engineering actions. They aim to align Australia's energy governance with the imperatives of a changing climate, ensuring that regulatory settings incentivise resilience and that network operators have the guidance and resources needed to implement protective measures.