Battling the extreme: lessons learned from weather-induced disasters on electricity distribution networks and climate change adaptation strategies

Implications of climate change, including increasing global temperatures, varying precipitation patterns, rising sea levels, and more extreme weather phenomena place increasing pressure on electricity systems, increasing the potential of power disruption (IEA 2020). Extreme weather threatens mostly the overhead electricity distribution networks and constitutes one of the leading causes of interruptions. More specifically, based on ENTSO-E's monthly statistics for the period 2010–2016 (22 member states), most power outages in the European Union (EU) were caused by equipment or material failures (40%) as well as extreme weather and natural hazards (33%). Furthermore, 80% of these outages occurred as a result of failures at the distribution level (Prettico et al. 2019). This is because High Voltage (HV) pylons are principally designed to resist greater wind velocities, while the conductors, due to their height, are less susceptible to falling trees (ICF Consulting 2003).

For instance, the freeze caused in February 2021 by storm Uri in Texas, a state in the American South that is not used to such meteorological extremes, left more than 4.5 million customers (over 10 million people) without electricity at its peak, some for several days (Busby et al. 2021). The cold spell also affected other electricity-dependent services, i.e., water treatment and medical services. The economic losses from the energy not delivered and infrastructure damages were estimated to be close to £130 billion in Texas alone and approximately £155 billion for the entire state, possibly the most high-cost disaster in the history of the state (Gold 2022). In total, Texas faced outages of 30 GW since polar temperatures caused electricity consumption to spike, driving demand to unprecedented highs. That was far away from the ‘extreme’ winter planning scenario of the Independent System Operator (i.e., Electric Reliability Council of Texas – ERCOT) that was estimated at most 14 GW of outages. The mismatch between supply and demand forced ERCOT to firm load shed (blackouts) to millions of customers to avoid system collapse (Busby et al. 2021). According to ERCOT, failure of the entire Texas electricity network was only seconds or minutes away before the partial shutdowns.

Furthermore, between 12 and 18 July 2021, a storm complex over the European region struck Germany, Belgium, and surrounding countries, resulting in record-breaking precipitation amounts and extreme flooding. European summer floods were ranked as the most expensive weather disaster in Europe ($43 billion) (Masters 2022). The effects of precipitation were catastrophic, leading to flooding over all the rivers at the border between Germany, Luxembourg, and Belgium, i.e., rivers Ourthe and Sauer (Puca et al. 2021). In Germany, a month's rainfall fell within 48 h. According to post-incident study of the World Weather Attribution (2021), such an extreme 1-day rainfall is 1.2–9 times more likely to take place nowadays in comparison to a 1.2 °C cooler climate as a result of human-induced global warming.

Another example is Storm Arwen, which in November 2021 brought widespread disruption to the UK with winds reaching up to 98 mph in some regions and left over one million consumers without electricity. According to the Office of Gas and Electricity Markets (OFGEM), the Energy Regulator in the UK, around 82% of customers were reconnected within 24 h, almost 40,000 customers were without supply for more than 3 days, and nearly 4,000 remained off supply for over a week (OFGEM 2022). Most distribution networks in the country suffered from considerable damages, resulting in over 9,700 faults primarily caused by strong winds and fallen or broken trees.

At the same time, the decarbonization targets and electrification of transportation are expected to increase society's reliance on electricity and complicate electric power network operations. Indicatively, the renewable revolution, which constitutes the best way to tackle climate change, requires a fundamental rethink of how the grid operates since the intermittent generation of solar and wind power can cause a demand–supply mismatch. What is more, the requirement for the energy transition has altered energy flows and put heterogeneous players in the market, stressing more the networks. In parallel, power distribution grids are aging and were designed for climate bands that are now becoming outdated because of the changing climate and the resulting meteorological extremes, which has left infrastructure operating outside of its tolerance levels. It is noteworthy that, if targeted investments are not planned for equipment replacement and modernization, 40–55% of network assets could be over 40 years old by 2030 at the EU level (Monitor Deloitte et al. 2021), thus posing direct threats to the infrastructure and considerable knock-on impacts on the network users. Since consumers will increasingly depend on electric power in the next 30 years, the effects of potential disruptions are expected to increase, too.

The above challenges underline the necessity for solid and well-planned strategies in order to enhance security of electricity supply. Electric power systems must become more climate-resilient, efficient, and flexible to handle the massive integration of renewables, which is a prerequisite to achieve the net-zero target in time to mitigate the effects of climate change. Power system resilience is the capacity of the system to anticipate, withstand, absorb, respond to, adapt to, and recover from disturbances caused by High Impact, Low Probability (HILP) events (Bie et al. 2017). The research community and grid operators have recognized that traditional reliability studies are not sufficient to resist all extreme events at all times (Lin et al. 2018). Instead of passively responding to a disaster, there are many actions, processes, policies and procedures that can be adopted before, during, and after the event to safeguard the uninterruptible power provision to critical loads. Resilience also requires the network reconfiguration to face multiple threats and the improvement of response times (Karagiannis et al. 2017). However, according to the International Energy Agency (IEA), only a small percentage (16%) of IEA family countries have planned specific climate resilience enhancement actions across the electricity supply chain in their national portfolios (IEA 2020).

With an increasing awareness of climate threats and to effectively adapt to changing circumstances, power utilities should incorporate climate change in grid planning and identify how and to what extent extreme events (i.e., storms, floods, heatwave, etc.) affect the grid. Climate change should be incorporated in grid planning and the capacity of electricity networks to withstand extreme weather shocks must be enhanced. This can be achieved through initiatives and targeted interventions that should be taken across all functions of the electric power system, i.e., network design, construction, operations, and maintenance for mitigating risks from a changing climate perspective (Oleinikova 2022).

Based on the above, the objectives of the present review article are the following:

• First, investigate the impacts of extreme weather incidents that occurred in different regions of Greece over the last 6 years and led to major power disruptions; and

• Second, based on the impacts of each specific event on the network infrastructure, draw a set of technical solutions to adapt and mitigate the effects of similar future events.

In this phase, the next steps were followed:

• Step 1 – selection of cases: The research was undertaken in different and geographically dispersed regions that faced extreme weather incidents of different types, leading to severe network infrastructure damages and extensive power outages for the customers. The cases are described in Table 1.

• Step 2 – data collection: Qualitative and quantitative data were gathered through (i) interviews with the technical staff of the Network Operator's Service Unit that was responsible for the distribution networks affected per incident, as well as (ii) analysis of primary and secondary sources (i.e., press releases, official records, such as incident investigation reports of established Committees and formal incident reports submitted to the Regulatory Authority for Energy in Greece, known as RAE). According to the Code of Operation for the Interconnected Network, it is noted that the Network Operator in Greece is obliged to provide detailed reports to RAE for handling emergency situations. These emergencies are described as situations that affect over 20,000 network users while also their duration lasts for at least 30 min.

• Step 3 – case description/analysis of the study evidence: A report-based document was prepared for each study area, including key information regarding the event: network areas affected, number of technical staff deployed (own and contracted), equipment used, impacts on network infrastructure, factors that affected/contributed to network vulnerability, difficulties/challenges in the emergency response, as well as good practices and weaknesses in the disaster management cycle.

• Step 4 – Development of lessons learned and recommendations: The findings were discussed with senior technical experts of the Network Operator to identify solutions that can enhance network resilience. The experts were selected based on their practical experience in responding to emergencies as a result of extreme weather phenomena and on their level of technical knowledge of the distribution networks.

Benchmarking with other Network Operators at European and international level was also performed through literature review. The aim of the review was to further elaborate in a satisfactory way upon the lessons learned in phase 1 with regard to technical recommendations and organizational initiatives and also to strengthen the conclusions. Relevant literature was searched and studied, including journal articles, books, theses, reports from power utilities across the world, etc. Literature review provided a clear overview of the current state of resilience-enhancing solutions and their future. The findings were synthesized into a cohesive summary of existing knowledge in the field of resilience and climate change adaptation of electricity distribution networks.

Because of Greece's high vulnerability, in the following sections we will examine five real-life examples of different types of climate change-driven disasters in the Greek territory (thundersnow Elpis in 2022, heatwave and wildfires of 2021, snowfall Medea in 2021, cyclone Ianos in 2020, and flash flood in Mandra in 2017). The case study approach is employed to investigate the impacts of weather extremes on the distribution grid and capture lessons learned regarding technical solutions and disaster management best practices.

Elpis was a windstorm that influenced a large part of the Eastern Mediterranean region, triggering blizzard conditions in the mountainous regions of the country and snowfall in milder locations further south, like the city of Athens. The phenomenon lasted between 23 and 28 January 2022 and mainly influenced Attica, Evia, Crete, and the Cyclades islands. According to the alert issued by the Hellenic National Meteorological Service (HNMS), the main incident features were: (i) the very low temperatures (up to −18 °C); (ii) the unusually heavy snowfall that blanketed the northern suburbs of Athens, and even low altitude areas of the northern and eastern Greece and the Aegean islands; and (iii) the winds of 8–9 Bft. During Elpis, a rare phenomenon for Greece, that of a snowstorm (i.e., snowfall with lightning), was observed.

Insufficient coordination between the involved parties for the opening of roads with winter service/snow removal vehicles was a critical factor that affected recovery times. In regions of Attica with no or limited accessibility problems, damages were repaired without delays. In contrast, in municipalities with total or partial traffic interruption, there were delays in power restorations since the technical crews could not reach the damaged areas. It is noteworthy that already from the beginning of the phenomenon (January 24), many parts of the distribution network were completely inaccessible, even for inspection and restoration planning. It is typically stated that after the decommissioning of Attica tollway at noon on January 24, all crews operating in Eastern Attica were cut-off from the material supply line, while the heavy snowfall, in combination with many blocked and abandoned cars, caused severe road network disruptions in the main roads of the city. Hundreds of drivers were trapped for hours in their vehicles on Attica tollway, some counting to 24 h without food, water, and heating. This situation continued until January 27, making access to the Network Operator's vehicles difficult or even impossible. Due to the immediate intervention, at the dawn of January 25, 50% of the disconnected households in Attica were re-electrified, while on January 26, around 95% of the cut-off power supplies were re-electrified.

It is widely recognized nowadays that the combination of extreme temperatures, high winds, and dry weather conditions ignite and cause wildfires (Panteli et al. 2022). In fact, climate change and the subsequent rise in the ambient temperature are projected to increase the frequency and intensity of fires. The availability of burnable fuels for wildfires is also increased by prolonged dry seasons, thus making fires stronger, larger, and deadlier (Xystrakis et al. 2014). Studies have also shown that prolonged drought combined with a wet season with higher precipitation is particularly dangerous. Vegetation growth is favoured by rainfalls and the plants that die and dry out during an extended drought period can lead to accumulated burnable biomass that facilitates and strengthens the spread of the flames in comparison to typical wildfires (Xystrakis et al. 2014).

In the midst of the unprecedented heat and since almost all regions of Greece were characterized as categories 4 and 5 in the fire risk prediction maps, hundreds of wildfires broke out in various parts of the country over a period of around 25 days, burning a total of around 1,148,000 acres, i.e., 88% of the total burnt area (Hellenic Fire Service 2021). Among them, the Varybombi wildfire attracts particular interest because it was spread erratically in the northern suburbs of Athens, which is a densely populated area, and was outlined by massive spotting and pyroconvection (Giannaros & Papavasileiou 2022).

The megafire that devastated a large area in Varybombi was caused by an explosive mix of factors that led to its rapid, catastrophic spread in an environmentally significant area for the Attica basin, including (Lekkas 2021): (i) the climate conditions, i.e., low relative humidity, prolonged high air temperatures and drought; (ii) the mixed zone of the area (residential and forest); (iii) the high load of fuels that created mature conditions for ignition (it is noteworthy that according to tests conducted on the ground by the National and Kapodistrian University of Athens, humidity was found to have dropped 0.5 m from the surface); (iv) the Mediterranean vegetation, consisting of coniferous trees that create more favourable conditions for the fire spread (it is indicative that to cope with the heat, the pines threw additional needles on the ground, thus creating a thick layer of fuel, while based on the findings of a test and the respective analysis performed in the laboratory of the Aristotle University of Thessaloniki, a humidity of 6–7% was recorded in the needles); and (v) the morphology of the region, which on a large scale resembles a funnel between Mount Parnitha and Penteli area. The result of the above was the rapid spread of fires with a huge thermal load exceeding 1,000 °C and the easy passage of fire zones. The high thermal load led to the following situations: first, the water from the aerial resources to combat fires evaporated before it even reached the ground, and second, it forced firefighters to operate at a distance of at least 60 m.

Due to the damage caused by the wildfire in Attica to power lines, on the afternoon of 6 August, following a relevant order from the Independent Power Transmission Operator (IPTO S.A.), load shedding/cut-offs have been applied in rotation in Attica in order to ensure the stability and smooth operation of the mainland's electrical system. The power interruptions were of short duration (in a few cases, they exceeded 2 h), while the total cut-off power amounted to approximately 680 MW.

Because of the wildfires, over 4,000 wooden poles were burnt, while over 285 km of overhead MV and LV network were damaged and replaced. More specifically, within the first day of its occurrence, the fire in Varybombi caused the destruction of 230 poles (MV and LV) and damages to MV and LV networks of a total length of 10 and 30 km, respectively. Restoration works started immediately, and most damages had been restored by August 4. However, on August 5, the rekindling of the fire caused severe damages to the network in the area of Varybombi and also in other regions in the northern suburbs of Attica. The total damages in network assets from the fire were enormous: 9 MV lines with a length of 158 km and an LV network of 396 km were affected. In particular, 1,000 electricity poles, 15 km of MV network, 34 km of LV network, and 20 distribution substations were totally destroyed. Moreover, many burnt trees fell on the network infrastructure, provoking additional damages and faults.

The wildfires also impacted many other regions across the country. The destruction caused to the distribution network by the fires in Northern Evia was also significant, where around 1,500 poles were destroyed and a network of 100 km was damaged. The damage from the Peloponnese fires was also extremely extensive. More specifically, in the areas of Kalamata, Pyrgos, Sparta, Tripoli, and Achaia, around 1,450 poles and close to 123 km of network were destroyed and replaced.

For the restoration services in Varybombi, workforce outside Attica was also required and called to contribute. With the immediate mobilization of the Network Operator's crews and collaborating contractors, it became possible to re-electrify more than 90% of the interrupted services in the Peloponnese region until August 10, and more than 90% of the interrupted services in Evia and over 95% of the power supplies in Attica until August 11 (Figure 10). Until August 13, almost all consumers were re-electrified, either through the restoration of the network operation or through emergency generators. The total direct cost for the damage restoration on the electricity distribution network across the country is estimated to have exceeded 16,000,000 €.

Medea (13–17/2/2021) was an extreme cold invasion that caused snowfall in a big part of Greece, especially in Western Macedonia, Thessaly, Eastern Central Greece, and Crete. Very high snow levels were recorded, especially in Evia, Voiotia, Magnesia, and Attica where the snow level was up to 25 cm. The snowfall triggered power and water outages, severe transport disruptions, while many municipalities faced emergency situations. The total snowfall duration was 36 h in the Attica basin and 24 h in the centre of Athens. The temperature dropped to −25.1 °C (New Caucasus) in Western Macedonia and −20.4 °C in Ptolemaida. At the same time, there were stormy winds in the seas with the maximum gusts of Aeolus equal to approximately 100 km/h. Based on the HNMS's historical data, Medea caused the heaviest snowfall in the last 40 years in Greece, as presented in Table 2.

Depending on atmospheric and meteorological parameters (i.e., air temperature, precipitation rate, relative humidity, wind speed, liquid water content, etc.), various types of snow accretion can occur on overhead lines and outdoor substations. The shape, texture and weight of snow vary and depend on the prevailing weather conditions during the snowfall, while the consistency of water in snow affects its weight according to an analysis of the National Observatory of Athens. More specifically, the more water the snow contains, the heavier it is: wet snow, which occurs when air temperatures near the ground are close to 0 °C, is the heaviest due to the higher water content and weights almost seven times more (30 kg/m²) than the dry or fluffy snow that is the lightest of all (4 kg/m²), occurs at sub-freezing temperatures (several degrees below 0 °C), and can accumulate on exposed structures under low wind speed conditions. Regular snow, in slightly sub-zero temperatures, has almost three times the weight per m² of coverage (12 kg/m²) than that of the dry snow. The above comparative values for the three snow types refer to a snow height of 20 cm. Hence, impacts of the same volume of snow settled on trees and structures are more adverse when it is wet to a higher than usual degree.

The relatively higher temperatures of Medea snowfall resulted in greater water content in snowflakes and a significantly higher weight per surface unit. In addition, wet snow could not be easily swept away by winds near the ground, while wind velocity was much higher compared to past snowfalls. This has led to the collapse of a significant number of trees and branches. According to estimations of HEDNO's technical crews, there were approximately 1,500 falls of trees and branches on the MV and LV distribution networks in the Attica region, leading to the need for replacing about 150 broken poles (concrete and wooden). It is also noteworthy that more than 50% of the damages were caused by trees located on the other side of the road, highlighting the necessity of revising the vegetation management scheme and tree trimming practices.

Acknowledging the inconvenience experienced by thousands of customers, the Network Operator proceeded with the deduction of distribution network charges for February 2021 for the accounts of customers affected by the phenomenon, regardless of their electricity supplier. Moreover, post-incident assessment underlined the necessity to upgrade the call centre's capacity to respond in crisis situations and provide clear information to the consumers regarding estimated restoration times.

Based on the available observations, the intensity of the phenomenon ranks it in first place of its kind in the Mediterranean region (Lagouvardos et al. 2022).

The hurricane-like storm had severe effects on the distribution networks in the regions of Central Greece, especially in the prefectures of Karditsa, Magnesia, Larissa, Fthiotida, and Evritania. More specifically, more than 2,500 faults were announced by customers between 17 and 23 September in Central Greece. As a result, interventions were required in MV and LV networks of a total length of 17 km, while 144 poles (MV and LV) and ten overhead distribution transformers were replaced.

Throughout Karditsa prefecture, the heavy rainfall (around 188 mm) resulted in power interruptions to approximately 29,000 customers, while 114 underground substations flooded and shut down in the city of Karditsa (Figure 14). In general, indoor substations (some of them with pumping systems) can withstand limited water inflow. However, the unprecedented overflow after the destruction of the river Karabali embankment created the phenomenon of the ‘basin’, resulting in the increase of water level of up to 1 m in some places. On the morning of September 18, two-thirds of the city were flooded, and water could not be pumped for the first 24 h until the damage was repaired on the embankments of the river. Due to the change, in many cases, in the flow of the rivers and the widening of their banks, the overhead network was carried away, and restoration of damages was quite difficult. Furthermore, as the MV network was not routed in parallel with the road network, recovery times were significantly increased. Eleven backup power generators were transferred in Karditsa (total capacity of 6.5 MVA) to supply the LV departures of the distribution substations up to the replacement of the damaged equipment (transformers, MV electric boards, etc.). The recommendations of technical experts were focused on the need to install automation systems in high-risk indoor substations (i.e., advanced sensors, water level monitoring systems) for predicting possible faults and ensuring situation awareness in disasters.

Due to the stormy winds (90 km/h), extensive damage was also caused to the distribution networks in the Ionian islands of Ithaca, Cephalonia, and Zakynthos (in more than 450 points of the network), resulting in a complete power outage in Ithaca (supplied by the power lines of Cephalonia) and in the largest part of the other two islands. The most severe problems were in Ithaca and the northern part of Cephalonia, where fallen trees led to broken poles, cut power lines, and damaged power supply cables. Moreover, due to the devastating impacts on the road networks, the access to the electricity network to inspect and repair faults was impossible in many areas. On the above islands, restoration efforts were focused on networks of a total length of 1,148 km (MV) and 1,771 km (LV), respectively, while approximately 56 MV and 63,300 LV customers were affected.

Over 97% of the serious damage caused to the distribution network had been repaired by September 22 (1 day after the event ended). Nevertheless, the direct impact on grid infrastructure, including recovery cost, was estimated to be close to 200,000€ in Zakynthos, around 500,000€ in Cephalonia, and almost 400,000€ in the area of Karditsa.

Floods are very common and extremely dangerous natural disasters that can extensively damage properties and infrastructures and cause human losses. According to the scientific community, flooding phenomena have increased in recent years at a global level as well as in Greece as a result of climate change. The flash floods in Mandra (Athen's western outskirts), in 2017, having a return period of almost T = 150 years, constitute one of the most severe floods at country level (Mitsopoulos et al. 2022). Between 14 and 16 November 2017, successive storms caused rains and thunderstorms in a large part of Greece. The precipitation which appeared in the mountainous parts of the region provoked flash floods in the water basins of the area. The local roads became raging torrents of mud and debris, properties and businesses were flooded, and the traffic was disrupted in many parts of the Athens–Corinth highway and adjacent roads. The areas were declared to be in a state of emergency by the General Secretary for Civil Protection.

The duration of the storm that caused the flash floods was short and the precipitation was locally selective. Both features are typical characteristics of the storms triggering flash floods in the Mediterranean (Soulios et al. 2018). The extreme of the phenomenon was proven by the calculated rainfall of the IMERG algorithm (Integrated Multi-satellitE Retrievals for Global Precipitation Measurement) based on NASA's Global Precipitation Measurement mission which recorded all the spatio-temporal features of the storm. The corresponding height of the rain was estimated to be between 138.4 and 154.7 mm (Figure 15), and the total rainfall duration was approximately 7 h; thus, it can be marginally considered as a flash flood (Soulios et al. 2018). This rainfall corresponds to an amount equal to almost 40% of the yearly rainfall area (Nikolopoulos 2017).

Heavy torrential rains formed torrents due to which: (i) the ground receded, entraining the overhead electricity network, and revealing the underground network; (ii) cars, carried materials, etc., that entrained the overhead network were swept away. In the wake of the disaster, seven distribution substations and 36 poles (MV and LV) were replaced. Faults appeared in five transformers, and problems were located in 3 MV lines. Around 80 LV connections (households) were left without electricity, and three critical infrastructures (customers) were affected. To restore damages, a total of 50 people were mobilized. Because of debris, it was impossible to access many parts of the distribution network. Also, due to the size of the disaster, the responsible public authorities (i.e., Police, Fire Department) did not allow the Network Operator's technical staff to enter the affected areas. Another challenge during the response phase was the disruption of communications because of serious damage to a communications cable. To face this issue, a GSM modem was installed to enable wireless communication between the Distribution Dispatch Control Centre of the Attica Region and Mandra substation, while the telecommunications service provider managed to repair the cable damaged two months after the incident. The total power recovery took 3 days.

The post-incident evaluation revealed that the result of this weather extreme (both human losses and material damages) was determined by two axes: (i) first, the unprecedented amount of rain (which led to huge amounts of water and debris flooding the city) and the intense rapidity of the phenomenon in combination with the nature of the soil (that facilitated the intense runoff of water) and anarchist architecture; and (ii) secondly, the inadequacy of flood protection structural works. Indeed, there is no legal/regulatory framework for flood protection at national level in Greece. For the mitigation of distribution network damages, flood protection of high-risk substations was considered essential. Measures that were recommended included the installation of flood monitoring devices and sensors in substations, elevation of substations and control rooms above flood levels, creation of embankment levees and floodwalls, installation of water pumping systems, etc.

The key findings from the above case study analysis are summarized in Table 3, providing a comprehensive assessment of the impacts of different extreme weather incidents on various electricity distribution network assets (i.e., power lines, conductors, poles, substations, transformers, switching and control equipment, etc.) and indicative technical adaptation solutions. As frequency and intensity of such phenomena are anticipated to rise in future, understanding the sensitivity of specific grid components and their collective vulnerability to climate hazards is vital for the long-term planning of bespoke adaptations.

Climate change poses new technical and business risks to power utilities and grid operators because post-disaster network failure can bring about major direct/indirect economic losses, severely impact human life or lead to cascading effects in today's highly complicated and interconnected societies. Quick service restoration is of paramount importance for the recovery of a disaster-stricken region. Therefore, the concept of resilience becomes critical, especially in areas and countries that constitute climate change hotspots. Since passive adjustment is insufficient and leads to costly repairs, utilities should instead proactively adopt effective grid resilience strategies by allocating resources to prevention rather than post-incident corrections.

More specifically, grid operators can build resilience in three main axes:

• Improve system flexibility through investing in redundancy, reconfiguring network, deploying distributed energy resources, developing microgrids, and increasing customer participation to mitigate the effects of extreme incidents and limit the extent and duration of potential power outages (Section 4.2.1).

• Harden the network (Sections 4.2.2–4.2.7), i.e., increase its physical toughness and capacity to sustain extreme events by implementing appropriate interventions, such as replacing poles, shifting towards undergrounding of assets, developing flood defence schemes. Hardening strategies generally include appropriate building codes, siting methods, construction, inspection, maintenance, and operation practices (National Academies of Sciences, Engineering and Medicine 2017). Nevertheless, it is notable that hardening measures (i.e., undergrounding) can only be effective for a specific type of threat and may have an adverse impact in a different occasion (Panteli et al. 2017).

• Strengthen restoration effectiveness to reduce outage time to a minimum (Section 4.2.8).

Lessons learned from past disasters and best practices applied by power utilities at European and international level can be used to highlight policy-making initiatives as part of establishing a climate change adaptation pathway and indicate the focus areas of investments. The findings of literature review and benchmarking with the policies and experiences of other grid operators are analyzed in the following sections.

Recently, power utilities have focused on the climate resilience of the electricity network against extreme weather events by adopting various redundant designs. Adding redundancy to the electricity grid introduces flexibility and robustness and can increase its resilience, allowing increased rerouting during times of disruption (Asian Development Bank 2012). For instance, providing alternative power supply routes with the appropriate network configuration offers the ability to bypass damaged lines, thus diminishing the likelihood of cascading failures (Panteli & Mancarella 2015a). The installation of multiple circuits in parallel can be achieved using main and backup transformer units or by expanding the system's generation reserve capacity by deploying extra energy resources, either centralized or distributed (Daeli & Mohagheghi 2022). In Australia, following the bushfire on December 19, 2014, several parts of the grid may currently be run under N-3 security to avoid the risk of cascading in cases where bushfires occur nearby (Panteli et al. 2022). Another example includes the employment of additional (perhaps parallel) power lines and an increase in their capacity to handle higher loads upon failure of other network portions. However, these solutions are expensive and need a long time to be implemented.

As system hardening is usually expensive, the utilization of smart grid technologies should also be considered. The electricity network must also be made flexible enough to accommodate renewables and distributed energy resources. This can be achieved by expanding transmission capacity, building microgrids (for a better isolation of outages), implementing demand–response schemes, and enhancing forecasting and scheduling (Davis & Clemmer 2014). Distributed generation is less susceptible to weather-driven power interruptions because they can directly serve consumption without external lines (Campbell 2012). Batteries and other forms of energy storage, if combined with renewables (i.e., solar or wind) can also add flexibility since they store power and release it when required.

Collapsing overhead power cables cause temporary loss of power to consumers and bring about additional reparation costs for power providers. Underground cabling makes a network less susceptible to weather-related power outages or precautionary storm shutdowns since the overhead infrastructures (i.e., conductors, substations, etc.) are exposed to environmental stresses and physical loads associated with adverse weather conditions, mainly precipitation and wind storms, can be avoided. Distribution System Operators (DSOs) in Finland are investing substantially in underground cabling to comply with the outage requirements of the country's Electricity Market Act. Indicatively, Elenia, the second largest electricity DSO at national level, aims to achieve 75% undergrounding of its network by 2028 (Climate-ADAPT 2022a).

However, underground cables are not immune to failure in storms. For instance, underground cables are more vulnerable to surge flooding, which often follows hurricanes (Electric Power Research Institute 2015). In the wake of Hurricane Ivan in 2004, the wave action and storm surge on the Alabama coast physically uncovered and destroyed many miles of underground lines. As a result, some locations in the region were left without electricity for over a year (Rollins 2007). Moreover, undergrounding is not suitable for all environments and locations due to geologic (i.e., subsoil morphology) or other factors (i.e., places with a high-water table) (National Academies of Sciences, Engineering and Medicine 2017). On top of that, underground wires are more susceptible to corrosive storm surges.

Besides, locating a fault in an underground cable can be more complex and time intensive. According to a study issued by Edison Electric Institute in 2006, outages in the overhead lines in the State of Virginia in 2003 were 4–5 times more than those of underground ones, but the mean time of interruption for the latter was 2.5 times more that of the former (Johnson 2006). Moreover, based on a report published by the North Carolina Utilities Commission in 2003 for the reference period between 1998 and 2002, overhead systems experienced almost twice the outages of underground, but the average time of the overhead interruptions was 1.6 times shorter. The study also encompasses data suggesting that the outage benefit of underground networks reduces as the system ages. For instance, according to utility companies in Maryland, after 15–20 years underground systems were no longer reliable and were expected to go out in 25–35 years (Johnson 2006).

Last but not least, undergrounding is costlier in terms of installation than the overhead network, depending a lot on the type of ground surface where the cable is laid: soil, cement, asphalt, paving slabs, marble, etc. Another factor is that extra insulation is needed since the cables are usually laid only in one meter depth from the ground. There is also the requirement for additional land for the sealing end, where overhead lines are connected to. The estimated cost of burying power lines is almost 10–20 times higher than overhead cables (Griffin 2010), based on specific features, like topography, subsurface conditions, the availability of existing underground conduit, etc. Moreover, underground cable becomes more expensive for higher voltage levels in comparison to an overhead line, i.e., almost two times more for voltage levels up to 90 kV, three times more at voltages of 225 kV, but 10 times at 400 kV (ICF Consulting 2003). This increase varies across European countries. According to Panteli & Mancarella (2015a), the cost of burying overhead wires ranges from $500,000 to $2 million per mile. Besides, repairing and maintaining an underground network is also more expensive than the overhead one (North Carolina Utilities Commission 2003). Maintenance is also costlier, even more when the repair requires unearthing or bringing the line to the surface, or in flood prone regions.

Therefore, the advantages of burying power lines in some cases come at a cost that local populations are unwilling to undertake (Campbell 2012). For this purpose, a careful cost–benefit analysis should take place prior to any cabling project. Besides, selective undergrounding is considered to offer optimum return on investment, compared to a complete replacement. Several factors are considered to prioritize the parts of the network to be rebuilt underground, including network capacity, age, number of customers served, conditions or fault rate of the lines, customer outage cost, etc. (Ahmed 2020).

Electricity networks will be exposed to climate change hazards in the next years, and therefore, it is vital to revise building codes and design standards to enhance network planning to correlate hazard-vulnerability risk. Both existing and new energy infrastructure need additional protection, and future planning should consider that new capacity to be installed has to be scrutinized for the potential impacts of changing climate conditions on network design, construction, operation, and maintenance (ESPON 2009). This approach will reduce vulnerability to environmental alterations and improve knowledge related to climate risk management (Ebinger & Vergara 2011).

Rerouting power lines to regions less vulnerable to extreme weather is another strategy. Overhead, lines of a distribution grid are found in forests, particularly in rural areas. In typical circumstances, rerouting overhead lines away from trees along roadways will result in fewer faults and quicker fault repairs because the fault locations will be easier to reach. In this arrangement, the network's length remains constant, and there will be fewer branch lines because consumption is close to infrastructure (Ahmed 2020). Consequently, the chances of fault will be decreased. Moreover, a fault would be less likely to occur, and the rate of faults would reduce, if trees were on the opposite side of the overhead lines. Selective hardening of particular lines or line segments constitutes a key practice.

Preventive policies can also be applied to lower the likelihood of disruptions and/or outages. For example, expanding the spacing between phase conductors can lower the possibility of flashover caused by conductor slapping (Daeli & Mohagheghi 2022). In order to forecast conductor behaviour based on specified tension limits under changing loading conditions, advanced sag-tension calculations are also crucial. Overhead systems can be made resilient by reinforcing poles through the installation of guy wires, reducing span lengths, boosting safety factors while still using the current design loads, or raising design loads to higher values (Rollins 2007). Besides, locations that are vulnerable to specific climate hazards (climate change hotspots) must be avoided during the design stage, i.e., avoiding slopes will protect against landslides.

Following the 2021 Texas freeze, it became clear that the state's regulatory approach to energy should be revised, including investment in infrastructure weatherization (Busby et al. 2021). Power utilities' long-term planning should integrate climate change extremes' impact on asset performance and embed climate resilience into equipment specifications. In other words, DSOs should ensure that the equipment installed is fit for purpose over its lifespan and able to resist the temperature and climate extremes that are likely to occur in the upcoming decades, while still being capable of meeting the future network requirements. For instance, grid operators should revise standards to ensure that the forecasted alterations in ambient and extreme temperatures over the lifespan of all equipment are accounted for in network design, choose cables with improved moisture resistance, or evaluate and update cabling specifications so that the performance of joints is not impacted by any ground movements due to climate change. The design standards should be evaluated for each asset class to further prevent exposure to climate hazards when new assets are installed.

The range of loading conditions under which electricity network components operate depend on the properties of their elements. These limits include heat dissipation and are related to internal cooling mechanisms and ambient temperature. Components are sized to withstand peak load conditions (with some margin of safety). Exceeding safety margins can generate unneeded costs, so components should optimally be designed to operate at or close to their rated limits in case of peak loads (Ren et al. 2008). If peak loads rise and heat dissipation in decreased due to the increase in the ambient temperature, the safe load shedding is restricted, especially for transformers and overhead lines (Ward 2013; Panteli & Mancarella 2015b; Burillo et al. 2018). Once components are not derated (and the system is not operated in consistency with the new ratings), accelerated degradation, higher failure rates, and overall shorter lifespans will occur (Beard et al. 2010). Other climatic variables can also affect power ratings. For example, additional derating of the underground cables may be needed in case of drought because the soil thermal conductivity can be decreased (Ward 2013). Alterations in humidity can also diminish the efficiency of grounding at substations, making the need for further safety measures imperative (Panteli & Mancarella 2015b).

Indicatively, the ratings of overhead power lines at distribution level are outdated as they depend on research findings dating back 30 years. Recent testing of these assumptions has revealed that some of them are flawed since regional climatic variations or any other changes in climate patterns that may have occurred in the last 30 years are not considered. Therefore, existing distribution line ratings are now obsolete. Power line capacity is expected to be stressed by the projected alterations in climate. Increasing ambient temperatures across Europe can reduce the thermal rating of lines and causes the lines to sag. In response to temperature rise, DSOs can increase the rated design temperature standard of overhead lines (Climate-ADAPT 2022b). Towards this direction, the Western Power Distribution in the UK (now called National Grid) has raised the design temperature of recently installed overhead lines on wooden poles from 50 to 55 °C to support the expected temperature rise (Climate-ADAPT 2022b). Hence, utilities should review overhead line design guidelines and select conductors with hotter operating limits or low-sag conductors at the design stage. What is more, adaptation to increasing temperatures may require the revision of the specifications of the cooling systems of substations and transformers, involving retrofitting measures or improved shading (Asian Development Bank 2012). Network electronics should also be upgraded to withstand higher temperatures.

Upgrading grid components with stronger and more robust materials constitutes a principal strategy to ensure resistance in meteorological extremes. For distribution networks, wooden electricity poles are usually replaced by concrete, steel, or any other composite material (Panteli & Mancarella 2015a). In regions prone to high winds, poles should be strengthened with guy wires (U.S. Department of Energy 2010). The use of more stay wires with modified pole foundations is also recommended (Nicolas et al. 2019). Poles can be also supported using cross beams.

Twisted pair cabling presents advanced mechanical strength compared to bare conductors due to its external surface. Besides, in heavily wooded areas that are vulnerable to power interruptions, some grid operators use tree-resistant overhead conductors, i.e., specialized covered or insulated conductors or spacer cables (Asian Development Bank 2012; Nicolas et al. 2019; IEEE Power and Energy Society 2020). Spacer cables present high mechanical and electrical strength, which leads to reduced tree caused customer interruptions as a result of wet snow or ice. They are designed for heavy ice loading and are resistant to galloping. Moreover, they are supported by a high strength messenger acting as a shield wire against lightning (Bouford 2008).

Power utilities are increasingly using fibreglass crossarms in tangent (i.e., straight-line or slight-angle) and dead-end (i.e., terminating wire at the end of mainline or crossing) applications (IEEE Power and Energy Society 2020). Their main benefits include strength of around 30% higher in comparison with wooden ones and a much better dielectric strength, which hinders the tracking of stray electricity on overhead infrastructure (IEEE Power and Energy Society, 2020). Moreover, in lightning hotspots, lightning protection (i.e., earth wires, spark gaps) should be included (Asian Development Bank 2012).

In addition, silicon insulators are not fragile to shocks, have excellent insulation performance, high resistance to flashovers, outstanding tracking and erosion resistance and they are not affected by contamination. Link boxes in the form of a pillar in an above-ground position (instead of underground) protect from flooding, while also ensuring easy access for network operations. The installation of breakaway cables is an additional practice to prevent cascading failures of poles and limit restoration efforts (U.S. Department of Energy 2016). Other cutting-edge materials include prefabricated compact substations, special utility pole mounting brackets to avoid breaks, detachable power cords, etc. Some power utilities also focus on research and innovation projects to identify areas of future development. For instance, Northern PowerGrid (which is responsible for the distribution networks of Northeast England, Yorkshire and North Lincolnshire in the UK) has launched the ‘self-heal fluid’ project for the development of a self-healing cable fluid when exhibited in the air. Once the research work has been completed, Northern PowerGrid intends to implement this on its network. The self-heal fluid is expected to prevent water ingress to cables and, thus, faults (Northern PowerGrid 2021).

Recommendations may also include the use of smart equipment. For instance, smart transformers achieve the stability of the electricity networks by controlling power flow (Freedman 2011). Modern designs can also assist in decreasing losses by up to 80% and managing a broader range of environmental conditions. Furthermore, advanced generator-circuit-breaker technologies can clear short-circuit faults in tens of milliseconds. After the disastrous Black Saturday wildfires, the Australian state of Victoria took the initiative to promote the use of Rapid Earth Fault Current Limiters by grid operators, i.e., protection devices which can mitigate power line-induced fires by almost immediately decreasing fault current after it appears.

In case of flood, distribution substations can be shut down, thus interrupting power supply to thousands of consumers and other network infrastructure. Many recent flood events of large intensity have shown this risk, underlining the requirement to assess the impacts and enhance the flood resilience of substations. For instance, in the wake of the severe floods of summer 2007 in the UK, which resulted in the loss of energy supply to about half a million people, the government asked for the flood resilience evaluation of primary and higher voltage substations and the proposal of risk mitigation policies. Sir Michael Pitt's review of the 2007 floods also highlighted the need for resilience strengthening actions (Pitt 2008). A methodology for assessing flood risk and defence has been described in the Engineering Technical Report (ETR) 138 – ‘Resilience to Flooding of Grid and Primary Substations’ (Energy Network Associations 2018). This document provides industry guidelines related to resilience and outlines ways to incorporate the rising flood risk, risk assessment methods, practices for flood protection and cost–benefit analysis of the recommendations. It also describes data that should be gathered by grid operators to perform flood risk assessment, i.e., historical records, likelihood of coastal or pluvial flooding, the possible flood water depth, availability and effectiveness of flood protection measures, number of network users and critical customers that will be affected, etc.

Following the flood risk assessment, the National Grid Substation Flood Defence Framework was developed to improve the flood resilience of the power transmission network in Great Britain and safeguard security of supply. Based on the framework, protection is ensured by the application of a series of measures including flood barriers, portable flood defence measures, earth bunds, flood doors and gates, drainage systems and pumping stations, flood storage reservoirs, land management-based measures, etc. Broader areas with many high-risk substations should be entirely shielded against flooding events by adopting an effective combination of the above practices, i.e., building a perimeter hard flood wall around it (Climate-ADAPT 2022c).

In general, network structures with larger openings in rainwater catchment area should be reinforced. Elevating distribution boards and pillars of the substations in flood zones and waterproofing control rooms are also common practices. For underground substations, improvements in the construction of hatches can prevent water inflow. Monitoring of water level with flood monitoring devices and sensors that transmit alarms can act as early warning for intervention. Last but not least, facilities can be relocated to less vulnerable areas.

Protection measures are essential to prevent severe impacts and material damages, especially since flooding events are expected to increase because of climate change. It is indicative that in Bangladesh, which is very vulnerable to floods, investing $560 million in flood defence could prevent losses due to infrastructure damages of up to $1.6 billion (Oguah & Khosla 2017).

Network inspection and routine maintenance planning are both crucial to ensure the good health of critical components and should be scheduled regularly, keeping records, and producing relevant statistics with key findings. Networks in areas prone to extreme weather may require tighter inspection frequency. Moreover, DSOs should consider the natural disasters in their maintenance strategies and incorporate changing climate parameters into their maintenance planning (OSCE 2016). Scheduled maintenance should include regular inspection of the most vulnerable network assets, monitoring of climate indications according to equipment specifications, and implementation of the required preventive actions per climate risk. For instance, wooden poles should be regularly inspected for decay and rot, while concrete ones should be inspected for cracks that allow moisture ingress due to ice and oxidation of load-bearing reinforcement. Besides, focused maintenance should be applied to those network elements that the inspection has found to be in such need (prevention of faults), i.e., in case of leaning poles, sagging/taut/frayed lines, melted or burnt equipment, leaks, surface damage, heavy corrosion, etc.

Moreover, predictive maintenance (PdM) is a commonly adopted practice for managing physical assets which depends on operational data to decide whether an asset needs service. An efficient PdM programme constitutes a strategic element for utilities to reduce maintenance costs by predicting and preventing equipment failures and increase grid resilience, ensuring, at the same time, service continuity. PdM techniques are designed to determine the condition of equipment with data and sensors, predict failures, and estimate when maintenance is required. As a result, breakdowns are reduced. The introduction of new PdM technologies, such as resistographs and thermal cameras have accelerated the establishment of such methods. For instance, using thermal monitoring systems in substations can help to identify anomalies, create alarm on critical issues, and provide trended data on the asset status. Thermal imaging inspections are also important especially in critical sections of the network passing through forest or rural areas.

Contact of network assets with vegetation usually leads to power outages and causes infrastructure damage, arcing, or tree ignition which can provoke wildfires in case of favourable environmental conditions (Brockway & Dunn 2020). Many storm-related electricity supply outages are caused by trees contacting or damaging overhead networks. To reduce the possibility of power line contacts with trees, grid operators commonly trim tree branches to keep a right-of-way free of impinging vegetation (Campbell 2012). Condition monitoring of adjacent forests is essential for reducing tree-related disruptions in power grids since it helps to keep the rights-of-way without trees. In California, a country highly prone to wildfires, the effects of wildfires on lines are reduced by applying effective forest maintenance schemes (IEA 2020). Vegetation management in networks located in fire-prone areas is vital before the fire season to remove dry vegetation litter/fuel build-up. It is noticeable that, when well maintained, transmission corridors also provide a positive effect by creating firebreaks in the landscape (Nicolas et al. 2019). Moreover, the size, type, and health of the adjacent trees play, but also meteorological conditions and topological factors (i.e., type, quality, and dampness of the terrain) affect the risk rating. It is, though, proposed that all high, slender, weak, damaged, or tilted trees are replaced (Ahmed 2020).

In general, best practices related to vegetation maintenance should guide the revision of the existing policies.

A standard-based approach to organizational resilience is of paramount importance to improve the speed of customer restoration during weather-driven disasters. Key recommendations are summarized in Table 4 per disaster stage, considering the findings of case study analysis in Section 2 and lessons learned from other grid operators (OSCE 2016; American Public Power Association 2018; OFGEM 2022).

It is obvious that in the upcoming years climate change will test all states at a social and economic level. To mitigate these effects, the governments and critical infrastructure owners should be properly prepared and need to have built increased capacity in order to deal with climate hazard-induced disasters of increasing severity and frequency. Analysis of case studies in Greece confirms international experience and proves that electricity distribution networks are highly vulnerable to extreme weather incidents which put additional pressure on existing energy infrastructure. Aiming to provide uninterruptible power supply to the consumers, power utilities are constantly working on exploring multiple pathways for building highly resilient electric power networks through interventions at both technical and organizational level in order to shield the distribution network infrastructure, prevent cascading events and reduce their balance sheet risk.

Based on the best practice investigation performed in this paper, it can be concluded that a comprehensive resilience enhancement policy should include the following four pillars:

• Business operational measures. The operational measures are intended to strengthen the operational resilience of the system, ensuring improved preparedness (proactive stage) and effective response in case of an incident (reactive stage). The establishment of Standard Operating Procedures for emergencies and disasters plays a key role in this category. Other operational measures involve restoration techniques, adapted in extended power outages, as it is highly likely that there will be multiple failures in case of a natural disaster. For example, the effective organization and management of the technical crews to be deployed onsite can drastically reduce the time to restore power to the consumers.

• Strengthening (hardening) initiatives. Network strengthening measures focus on improving the resilience of infrastructure with the aim of making it less prone to extreme events. They include, among others, the undergrounding of overhead lines, the elevation of substations for flood protection, the reconstruction of specific network elements with more resilient materials, the relocation of critical network facilities to less vulnerable areas, as well as the construction of parallel lines or the addition of generating units that would not be required under normal operating conditions. Solutions in this category require large costs, making the strengthening of the entire network unsustainable. Therefore, it is fundamental to efficiently utilize a limited budget for targeted strengthening of the most sensitive parts of the system.

• Smart solutions. The smart solutions aim to provide the necessary flexibility to effectively deal with extreme events. Such measures are the exploitation of distributed generation combined with demand management, the use of local production and storage units, the use of mobile units (i.e., backup generators) for emergency situations, and the formation of microgrids, i.e., islands within the network that operate autonomously. These solutions make the distribution system less vulnerable to the loss of distribution lines and substations, as energy is generated and consumed locally and can power critical loads of lighting and security, emergency healthcare, water supply, etc. Also, the application of advanced digitization systems (i.e., GIS systems) can provide improved situational awareness throughout the phenomenon, thus enabling us to assess the level of damage and to define the priorities for rapid power restoration.

• Cross-domain synergies. The cooperation with third parties is of paramount importance to manage a crisis effectively. Power utilities can expand partnerships with local authorities, first responders and other critical infrastructure owners in order to organize awareness campaigns on emergency response, conduct joint emergency preparedness exercises and investigate options for effective onsite coordination. Collaboration with the scientific community at national level (i.e., universities, research institutes, etc.) is also significant; indicative actions include the funding of PhDs and studies with regard to vulnerability analyses and risk assessments of the electricity networks, etc. Finally, the participation in international forums and workshops can provide access to learning from past incidents and facilitate knowledge exchange.

Some of the aforementioned measures are relatively easy and low-cost, while others are particularly expensive and time-consuming. Given that it is impossible to design and build a power system that extreme and catastrophic weather events cannot damage, grid operators should weigh the costs and potential benefits and plan targeted investments that will promote fundamental resilience so that the system will ‘bend’ and not ‘break’ in case of such phenomena.

Data cannot be made publicly available; readers should contact the corresponding author for details.

The authors declare there is no conflict.