Insurance moving away from risky fossil fuels.

From Bob Burton Coalwire

A global review of the power sector by a worldwide insurance advisory service states that it is getting harder and more expensive for power utilities to gain insurance coverage for their operations. They concluded that the outlook is “bleak” for utilities with a large share of coal capacity in their portfolio of assets. One company struggling to gain financial support is Adani, which failed to attract financial support for refinancing its North Queensland coal port, forcing the Adani family’s trust to provide funding.

Review of Power Sector by WTW

(Willis Towers Watson Public Limited Company is a British-American multinational insurance advisor company)

Four global challenges: risk implications for the power sector


When we prepared the 2021 Power Market Review, our focus was firmly on the energy transition and there seemed little that could derail it, not even COVID-19; in fact, the pandemic had reminded us of the need to protect ourselves and our planet against humanity’s impact on the world. Over a year later, while the energy transition remains our most significant challenge, we are facing a very different, much more immediate catastrophe in terms of the Ukraine-Russia conflict and its impact on overall global stability.

While the energy transition and the achievement of Net Zero targets by 2050 remains the most substantial challenge that we face, we now need to achieve this in a very different and more complex environment to the one we envisaged 12 months ago. The circumstances now also apply for the global community as a whole and to all sectors of the global economy. However, there are issues that arise from the recent events, that very specifically impact not only the power sector globally but also the Power insurance market on which our sector depends.

New technologies

It is becoming increasingly clear, both in terms of energy security for Europe and clean energy globally, that new technologies such as CCUS and hydrogen that have been talked about for a number of years (and that may have had some false dawns in the past) are now becoming key pillars in global energy and power strategies. However, this new world order for power will

require a huge investment in infrastructure to enable it to happen, including smarter, more interconnected grids.


Effect on the insurance market

All of these risks require the support of the insurance market to enable them. However, the market does face an unprecedented range of new risks to consider and insurers will have to invest both time and resources to ensure that they are able to manage these new risks, not only in terms of understanding of risk and innovation of coverage, but also in terms of the volume of projects to be considered.

These risks are wide ranging in terms of significance and our ability to understand and control them – at global community, government, corporate and individual levels. It is therefore essential at this time to take a step back and consider these factors so the sector can fully appreciate them, consider what options are available to better understand them and what measures are available to mitigate their impact on power companies’ businesses. In this article we focus on four key challenges:


  • The Russian-Ukraine conflict
  • Global inflation
  • The energy transition
  • Climate change


Challenge one: the Russian-Ukraine conflict

Geopolitics has never been such a major factor for the power sector and the insurance market. Of course we have felt its impact in the past, typically in more localised forms, but we are currently in the midst of a truly global energy crisis, the likes of which we have not experienced before.

10 months ago, global leaders were gathered in Glasgow for COP26, deciding the way forward through a challenging route to Net Zero by 2050. The energy crisis was already imminent but it was hardly referred to at all at the conference, as leaders tried to avoid any challenges that could distract the world from the commitment to the energy transition needed to achieve emissions targets. The energy crisis at that time was primarily driven by a combination of the economic bounce back from COVID-19 stimulating demand, a downturn in energy investment and production during the preceding years, together with a shift from coal to gas. Fast forward a year, and what was already a tight energy market is under significantly more pressure following the Russia-Ukraine conflict and the application of sanctions at a time when the energy transition continues to gather momentum.

The current situation is considered the first true global energy crisis. There have been previous crises but they have typically been limited to oil, such as the crisis of the mid-1970s. However this event is not only truly global but affects all energy sources, including oil, gas and coal, as well as electricity. The other differentiator is that this is likely to last some years, rather than just being a temporary blip that can be remedied through the implementation of short-term strategies.

Will the impact be temporary?1

In short, no. In a recent statement Markus Krebber, CEO of Germany’s largest power producer RWE (RWEG.DE), stated that power prices could take three to five years to fall back to lower levels and there are many that would consider this to be optimistic.2 However, it is widely accepted that the situation is going to get worse before it gets better, due to Russia’s strength in the global and European energy markets. Furthermore, it is not expected that Russia will stand down from its position on Ukraine anytime soon and the lead times required to put alternative arrangements in place that will neutralise the impact of lost Russian energy are considerable. The depth of the challenge lies in the extent of the reliance on Russian energy and the infrastructure around which the movement of large volumes of gas is based.

The EU depends on Russia for 24.4% of all its energy needs. The energy dependency on a specific country is dictated by the weight of the fuels in the energy mix and the extent of the reliance on imports of those fuels from a specific origin.

Source: php?title=EU_energy_mix_and_import_dependency#Energy_mix_ and_import_dependency

Geopolitics has never been such a major factor for the power sector and the insurance market. We are currently in the midst of a truly global energy crisis, the likes of which we have not experienced before.

Source: dependency

The main origins of EU energy imports have changed in recent years, yet Russia has maintained its position as the leading supplier to the EU of all the main primary energy commodities: natural gas, crude oil and hard coal.

EU countries’ different energy mixes and import dependencies create vastly different country-specific energy dependencies on Russia.

Natural gas, a major fuel for electricity production and heating in the EU, represented 23.7% of the EU’s gross available energy and had an import dependency rate of 83.6% in 2020, with imports of 400.6 billion cubic meters (bcm). The reliance of the European Union on Russian natural gas has increased over the last decade, reaching 41.1% of gross available energy derived from natural gas in 2020, making it the fuel with the highest exposure to Russian imports.


Natural gas consumption in the EU has remained broadly flat over the last ten years, reaching 399.6 bcm in 2020, but EU production fell to almost a third and the gap has been filled by increased imports. The EU received 46.1% of its natural gas imports from Russia, with other important providers including Norway, Algeria, Qatar, the USA, the United Kingdom, Nigeria and Libya, countries that make up collectively with Russia 90% of the EU’s total natural gas imports. These nations will become the replacement providers of gas when the infrastructure is in place.

What are the alternatives?3

The European Commission has issued its REPowerEU plan, which provides details on how it plans to end Europe’s dependence on Russian fossil fuels. This includes a longer term strategic plan that considers the various different elements that will need to be implemented to enable Europe to fully wean itself off Russian energy by 2030. However, it does contemplate being able to reduce Russian gas imports by as much as two thirds during 2022, although the landscape is

constantly changing. At the end of July, as Nord Stream 1 continued to experience substantial supply restrictions

due to an extended outage period of its compressors, EU states committed to restricting use of gas to 15% of the usual volumes, to give the EU the opportunity to build up its stored gas ahead of the higher-demand winter months.

Successfully managing such seismic shifts in supply and usage will be major achievements, considering Russia supplies 40% of the EU’s natural gas and 27% of its imported oil and has the largest gas reserves in the world; together, they earn it roughly €400 billion

a year. To assist, the EU plans to speed up its shift to green energy and to bring energy supplies in from other countries, but it will of course need the infrastructure

to deliver on this. As we know from major inter-country electrical interconnectors and pipeline projects such as Baltic Pipe (as well as LNG and renewable new-builds) these are projects that take many years to plan and construct. There is a strong focus on easing the legal and planning regimes that typically contribute to these delays, but this is work in progress and so regardless, there is no “quick fix”.

But speed is of the essence, with rising energy costs as Europe draws on gas from other sources around the world. This puts major financial pressure on economies – not only in Europe but globally – as they already begin to struggle with rising energy prices.

The REPowerEU strategy focuses on three key topic areas: improving energy efficiency, expanding the use of renewable energy and securing non-Russian suppliers of oil and gas.

  • Energy saving: The Commission report highlights energy saving as the “cheapest, safest and cleanest” way to reduce dependence on Russian The aim is to further reduce energy consumption in the EU from the original plan of a 9% cut to a 13% cut by 2030.
  • More green energy: The EU has earmarked €113 billion for a “massive scale up in renewables” and new hydrogen infrastructure, together with plans for new EU legislation to make it easier to build solar and wind The EU target for renewable energy has also been raised; the goal is for green energy to provide 45% of energy needs by 2030, up from 40%.
  • More gas and oil infrastructure4: To quickly diversify from Russian fossil fuels, the EU is investing up to €12 billion in pipelines and Liquified Natural Gas (LNG) terminals to improve access to gas and oil from other countries including Egypt, Israel and Nigeria.

Is turning to coal the answer?5

European leaders clearly believe they have little choice but to turn to coal. Europe’s biggest Russian gas buyers have raced to find alternative fuel supplies and burning more coal is clearly an option that is being planned for, particularly when the alternatives are considered, such as heating and lighting cuts in winter. Germany, Italy, Austria and the Netherlands have all signalled that coal- fired power plants could help see the continent through a crisis that has sent gas prices surging and added to the challenge facing policymakers battling inflation.

  • Netherlands: The Dutch government has activated the “early warning” phase of a three-part energy crisis plan that seeks to preserve gas stocks by removing caps on production levels at coal-fired energy plants.
  • Austria: In the event of emergency, the government has reached an agreement with Verbund for it to convert one of its gas-fired power plants to enable it to burn coal.
  • Germany: The German government has plans to reduce pressure on its gas storage levels and to boost power generation levels by up to 10 GW by keeping coal-fired power plants scheduled for closure on-line.
  • Italy: The Italian government has said it could declare a heightened state of alert on gas if Russia continues to curb supplies. Italy has stated that reductions

in Russian gas levels could result in a package of responses, including a request for increased imports from current suppliers, the rationing of gas for industrial users and the need for increased output at coal power plants.


Increasing energy costs

So what impact is all of this having on electricity costs?

Pricing increases and volatility have, unavoidably and unsurprisingly, been increasing in evidence during this period, creating huge pressure on electricity retailers, governments and, ultimately, households. The rapid increase in gas costs has driven electricity price rises across Europe as the impact on thermal power generation costs is felt. Increased grid interconnection between countries has also driven costs higher, even in countries with significant renewables resources. For example, Norway has recently benefitted from the ability to export excess clean energy but in turn their domestic power market (that has historically been sheltered from the impacts of the energy market fluctuations) has found itself under pressure from its output being available on the wider European market.

Despite increased reliance on renewables, thermal power generators still provide an essential role in plugging gaps that arise during days of low Renewables output or following unplanned outages around networks. The opportunity cost of these rapid response and grid- support services is high – the plants in questions have historically been the more efficient gas-fired CCGTs. They will have higher costs arising from cost of gas, but the higher efficiency will work to even greater effect for them at this time. As we have seen though for those countries that are being forced to burn less gas in their power stations, coal can be the only viable alternative in the short term.

If these pressures are combined with other factors such as climate change, fuel logistical challenges and unscheduled outages, it is not surprising that in Europe we are seeing price spikes, with German peak power prices for 2023 trading at over EUR500/ MW/h during

August and French Q4 peak power prices trading at over EUR1,000/ MW/h.7

However, for those countries that are heavily dependent on gas fired power this will still form a major part of the electricity mix while there is gas to burn, despite high prices. But this cost pressure, which is expected to remain for the next year at least, will inevitably serve to increase the focus on, and accelerate the shift towards, renewable power.

Challenge two: global inflation

Consumer price indexes8

Increased inflation is a factor across the globe, with rates increasing rapidly over the year since COVID-19 related lockdowns began to ease. The recovery in demand that followed, combined with supply chain and logistical constraints, has put significant upward pressure on pricing, with numerous and varied factors at play. These include the effects of lockdowns in China (the world’s largest supplier of goods), the devastation caused by the Russian-Ukraine conflict (Ukraine being a major food exporter to Europe, the Middle East and Africa) and the economic sanctions imposed on Russia (one of the world’s largest suppliers of oil and gas).

As can be seen from Figure 5 to the left, the rates of inflation can vary widely between various countries. However, for most countries the rate of inflation is now substantially higher than it has been for many years, reflecting the significance of the change in a global economy that has come to expect relatively stable prices. This is not the case for every country; for example three hyperinflationary countries, which had major problems with inflation even before the pandemic, have been omitted, including Venezuela at 222.3% in April, Turkey at 70%, and Argentina at 58%.

Commodity price inflation9

National inflation rates and specialist commodity rates that heavily impact the power sector are actually different things, with the latter being more exposed to global demand and markets.

If we take steel as a benchmark for the power sector, in June 2022 the World Steel Association (WSA) released its short range outlook for 2022 and 2023. WSA forecasts that demand will grow by 0.4 percent in 2022 to reach 1,840.2 Mt after increasing by 2.7 percent in 2021. In 2023, steel demand is expected to see further growth of 2.2 percent to reach 1,881.4 Mt.

Ongoing supply chain issues and COVID-19 waves aside, the economic recovery from the pandemic has come faster and stronger than anticipated. However, the outlook for the remainder of 2022 and 2023 remains uncertain against the backdrop of the Russia–Ukraine conflict.

For 2022, inflationary pressures will vary from region to region, depending on trade and financial exposure to Russia and Ukraine. However, it is clear that energy and commodity prices, including those related to steel production, are rising around the globe. Inflationary pressures will also continue to be impacted by reduced investment resulting from financial market volatility, rising interest rates and the wider economic uncertainty.

The forecast is based on the conflict being resolved during 2022 but with sanctions remaining in place during 2023 and beyond, which will continue to impact global trade flows and supply chains.


Insurance values and claims cost inflation 10

Inflation doesn’t only hit the business or its clients; it also has the potential to significantly impact the insurance market. It is for this reason that insurers have been so focussed on ensuring that inflationary provisions are adequately reflected at each renewal. It is difficult to fully assess the impact of higher inflation on claims at this stage, as the higher inflation environment has not been present for a sufficient amount of time to accurately measure this. However, this will inevitably feed through to higher claims costs.


In his company’s Global Claims Review 2022 issued on the 19th July 2022, AGCS Chief Claims Officer and

Board Member Thomas Sepp summarised the position as follows:


“Insurance claims from companies have become more severe over the past five years due to factors such as higher property and asset values, more complex supply chains and the growing concentration of exposures in one location, such as in natural catastrophe-prone areas.


“The future does not look brighter anytime soon. Companies and their insurers have shown resilience to weather the loss impact of the pandemic, but the

ongoing war in Ukraine, a spike in the cost and frequency of business interruption losses and the sustained elevated level of cyber claims are creating new challenges. At the same time, the top two causes of claims, fires and natural hazards, remain significant loss drivers for companies.

Last but not least, the impact of soaring inflation around the world will bring further pressure on claims costs.”


This concern is being felt by many insurers who are also looking more closely at property declared values. This includes business interruption, the impact of more volatile power markets and whether the positive impact of this on generators’ profits is being fully reflected in values.


Challenge three: the energy transition

The energy transition is seeing a major shift in focus and investment, not only towards renewables and battery storage but also additional new technologies that

will support ongoing thermal power generation. Key elements of this shift will be the development of CCUS and hydrogen.


This year has seen unprecedented advances for carbon capture, utilisation and storage (CCUS) technologies. In 2021, more than 100 new CCUS facilities were announced and the global project pipeline for CO2

capture capacity is on track to quadruple, a target that is essential to support the pathway to Net Zero by 205011. This is supported by CCUS being a key part of the IEA’s strategy for the achievement of Net Zero in view of its unique ability to deliver carbon emissions abatement

for heavy industry and existing energy sector activity, as well as commercial viability for the development of

low-carbon hydrogen. However, CCUS has suffered from previous false dawns as a result of unreliable government funding plans, such as the UK’s high-profile CCUS competition, that the UK government unexpectedly withdrew support for in 201512. So why can we be so sure, with its previous track record, that this time the pipeline will actually be delivered?


While CCUS certainly still faces challenges, the combination of strengthened climate goals, an improved investment environment and new business models

have set the stage for greater success in coming years. Indeed, 2021 generated unprecedented momentum behind CCUS; the growth in the project pipeline in 2021 represented a major departure from the years 2010 to 2017, when plans for CCUS facilities were being cancelled and the pipeline of potential projects shrank.

This trend only started to reverse in 2018, which saw a net increase of six planned projects. The Russian-Ukraine conflict and the focus this has brought on the need for

a diversified energy base and options has continued to energise the CCUS sector.


Hydrogen: an abundant fuel, with disruptive potential Low-carbon hydrogen is poised to play a key role in industries that feature heavy emissions which are

hard to abate, such as aluminium and steel. But for global hydrogen markets to emerge, massive scale- up is needed across production pathways using both renewable and fossil-based feedstocks, and transport costs need to come down.


That being said, the viability of hydrogen production varies between types and regions. Electrolysis- based hydrogen costs are at least double those for

conventional hydrogen in most regions, while gas- based hydrogen with CCS costs are closer to viability. But as renewable energy costs drop, electrolysis-based hydrogen has the potential over time to become the cheapest and dominant source. Indeed, it is already cheaper than gas-based hydrogen with CCS in the Middle East and Western Australia.


Production predominates around ports in Europe, the US Gulf Coast and East Asia, where Japan, South

Korea and China have aggressive hydrogen strategies aimed at long-term decarbonization and energy security. China recently published its first ever national hydrogen strategy, with its state-backed think tank expecting hydrogen to contribute to 20% of final energy consumption by 2060. Its plan is focused on boosting the supply of renewables-based hydrogen and making

it an economically viable option in the nation’s energy transition13.


Clean hydrogen project proposals have proliferated since 2020. European nations with strong gas industries and offshore carbon storage potential (e.g. Norway,

the UK) are backing CCS technologies for production of natural gas-based hydrogen, while those with lower carbon power systems (e.g. Germany, Spain, France)

tend to favour electrolysis for renewable hydrogen. Electrolysis projects are also planned where renewables are abundant and export potential is enticing, such as in the Middle East, Australia and Chile.


Over a third of funds under the EU’s EUR750 billion NextGenerationEU recovery plan are to finance goals set out in the European Green Deal, including those for

clean hydrogen. Low and zero-carbon hydrogen projects across Europe have submitted requests for this EU-level funding. Meanwhile, UK projects await details of how a 5GW national target by 2030 will be subsidized.

Challenge four: climate change

As stated earlier, climate change remains the world’s greatest challenge; the effects are already being felt in numerous ways that are having profound impacts on the power sector as well as society globally. This is not only in terms of operational impact and damage to assets but also in terms of output, particularly in respect of hydro power. The lack of reliability in terms of hydro is only serving to exacerbate power market pricing tension created by the global energy crisis.


Current examples also include high temperatures in Europe, causing stress with European power generators. In France, EDF have had concerns over the need to reduce output at four nuclear plants due to cooling water restrictions due to low water levels impacting cooling water usage. In Germany, generators of coal-fired plants have bene struggling to get coal barges down the Rhine, due to low water levels at critical points in the river.

Against this, as mentioned previously in the report, we are seeing significant price spikes, with French Q4 2022 and German 2023 wholesale prices trading at over EUR1,000/ MWh and EUR500/ MWh respectively.

Q4 peak power prices have more than doubled to over EUR500/MWh between mid-June and mid-July 2022 and French Q4 peak power prices are now trading at over EUR1,500/MW/h.14 Such pricing has been exacerbated by weather-impacted low hydro reserves around Europe

that have led to a reduction in hydro plant output. Similar hydrology factors are also being felt elsewhere around the world.

“As renewable energy costs drop, electrolysis based hydrogen has the potential over time to become the cheapest and dominant source.”


Impact of hotter temperatures on operations15 Changing weather patterns are creating challenges for power companies and have the potential to impact not only the businesses themselves but also the power markets in which they trade.


  • PV panels: For PV, light, not heat, is the source of power and PV panels are at their most efficient when the ambient temperature is Equally, efficiency improves on the nameplate rating as the temperature drops below 25°C.
  • Wind farms: Like hydros and water, a network that is highly dependent on wind power is exposed to climate risk. Wind speeds were milder than usual in Europe this year, so windmills across the bloc generated less electricity which worsened a crunch that sent power prices to record highs as utilities had to buy more coal and scarce, costly, natural gas.
  • Gas turbines: Gas turbine efficiency is also impacted by ambient temperature. Gas turbines rely on a temperature differential between the inlet and the exhaust, so the cooler the inlet temperature the more power a gas turbine can Temperatures above 15%, such as have been experienced around Europe recently, will therefore reduce plant output with hot days in excess of mid 30°C having the potential to reduce output to approximately 73%.
  • Thermal plant: We have touched on this in the introduction to the section but all thermal plant has to be cooled, generally with abstracted river or seawater that is discharged back into the river or sea after

use. River conditions can create major problems for generators, as dry conditions can mean the river is too low to abstract the necessary water. It may be because water temperature limits are breached at the discharge point, or because river water has already been warmed by the sun – especially when river levels are low – and the water is too warm to allow it to be abstracted for use in the power plant.

  • Hydropower: Healthy water levels are essential for hydro stations so that enough water is available to drive its turbines and maintain river In the summer, rivers can run much lower. Hydro plants may operate under restrictions that stop them from using water to generate at times when river water levels are low.
  • Network capacity: The actual amount of power that can be carried on transmission and distribution lines can vary according to the ambient temperature. It can also cause network cables to expand so transmission cables ‘sag’ further between transmission towers. Limits are set for all of these physical parameters, and they determine how much power can be transmitted.


Nat Cat exposures

There is no part of the globe that is not experiencing greater severity and frequency of natural catastrophe (Nat Cat) events. Other than the transmission and distribution sectors, which have long had exclusions against damage to overhead lines and cables for

this reason, the hydro power sector is also coming under particular pressure due to the exposure to both earthquakes and floods affecting its major structures. This sector is also one where a number of assets in operation are 50 to 100 years old and potentially

designed with different environmental pressures in mind.


Flood & drought16

In February 2022 the Journal Water issued findings of a study that showed the extent to which the environment and risks to which hydro assets globally are being exposed will change between now and 2050. The study used the WWF Water Risk Filter (WRF) and geospatial analysis to screen hydropower projects, both existing (2488 dams) and projected (3700 dams), for a variety of risks at a global scale and with a key focus on biodiversity risks, hydrological risks (water scarcity and flooding), and how those hydrological risks may shift with climate change, based on three scenarios.


In terms of water scarcity risk, the study found that approximately 26% of existing hydropower dams and 23% of projected dams are located within river basins that currently have medium to very high risk. However, those numbers are projected to increase by 32% and 20% respectively by 2050 due to climate change.

This is expected to especially applicable for projects located in eastern China, the Middle East, Morocco, the southwestern USA and India.


For flood risk, the study found that 75% of existing dams and 83% of projected dams are within river basins with medium to very high risk. However, the proportion

of hydropower dams in basins with the highest levels of flood risk is projected to increase by nearly twenty times (i.e. from 2% to 36% of dams). In addition, a large proportion of existing (76%) and projected hydropower dams (93%) are located in river basins with high or very high freshwater biodiversity importance. This was a high-level overview, intended to raise awareness of

broad patterns of risk, highlight trends, and guide more detailed studies.


The study also highlights the serious threat posed by planned hydropower to freshwater biodiversity.

Fragmentation of rivers by dams is one of the leading causes of the 84% collapse in freshwater species populations on average since 1970. Yet the analysis found that up to 80% of all planned dams are in areas with high or very high risk to freshwater biodiversity, such as the Amazon, Irrawaddy, Mekong and river basins across the Balkans.



IIn 2019, the east coast of Africa was hit by tropical cyclone Idai, one of the strongest southern tropical cyclones on record. Mozambique, Madagascar, Malawi and Zimbabwe experienced windstorm, heavy flooding and the loss of over 900 lives – the heaviest loss of life from such an event in 100 years.


The conditions that led to and intensified the impact of Idai are considered by many climate experts to have been climate change-related. The dynamics of several


factors coming together to increase the impact and losses (including secondary losses) arising from storms, are now well understood by experts, including those of the insurance sector. For Idai this included:


  • increased energy and rainfall from warmer air sea- surface temperatures
  • greater impact of storm-surge on coastal communities and lower-lying cities due to rising sea-levels
  • greater risk of flash-floods, arising from drought- related hard ground conditions


The frequency of higher intensity tropical cyclones is expected to increase (2019 saw the record for South Indian Ocean basin cyclones reaching hurricane intensity equalled, with 13 out of 18 reaching hurricane levels) which will put mounting pressure on African countries

to be prepared for future climate impacts on their electricity systems.

Implications for the Power insurance market

We have seen that the world has become more complex, not only for the global community but also for the insurance sector and especially the Power insurance market.


The challenges it has to face not only relate to those that have historically always been present, such

as operational risk, an aging generation fleet, new technology variants and natural catastrophes. There is now a whole new wave of challenges arising from the four key challenges outlined in this article.


This impact is being felt in many ways but ultimately it will place new pressures on the insurance market to not only understand and develop solutions for the new or developing risks but also to ensure that it understands those risks enough to create a sustainable market for these emerging or growing sectors. Below we have outlined how each of our four challenges will impact the Power insurance market.


Russian-Ukraine conflict

  • The impact on supply chains from an industrial downturn that may arise following reductions in gas flows from A reduction in gas flows to 15% of the usual levels will inevitably impact Europe’s ability to generate from gas; this will be exacerbated on days of low renewables output. When demand exceeds available power, users will have to be cut off to ensure the grid remains balanced. Residential customers and essential services will be prioritised, meaning industrial users will be cut off in line with an order of importance. Supply chains will be affected and the impact of this on the Power sector remains to be seen. It will be important for this to be monitored so that contingency plans can be put in place for key parts/supplies.
  • The increased investment in new assets and infrastructure that will facilitate reduced dependency on Russia. The increase in demand for an already resource-challenged contractor base has the potential to impact timescales, quality and cost. Similar upscaling of demand and production has often resulted in pre- and post-handover losses to the market from poor workmanship and project management failures during the construction phase. Attention to contract risk management, contractor management and quality assurance, will be needed to ensure risk is


  • The need to ensure that power wholesale market volatility and the impact of this on Business Interruption values is understood. Wholesale electricity prices are multiples of prior year values. While higher gas and carbon credit costs (typically “variable costs” for insurance purposes) account for a significant part of this rise, higher demand following the COVID-19 bounce-back, combined with lower Renewables output at times, is also enabling power generators to benefit from notably higher margins.

This has been problematic for insurers, who have had losses that are unexpectedly high compared to declared Gross Margin values. This is leading to

insurers trying to apply $/MWh price caps, which can only be avoided by greater clarity of how the declared values have been arrived at. The changing electricity market conditions need to be reviewed regularly with the company’s broker to ensure the basis of cover remains accurate.

  • The increase in coal use to the market and how insurer ESG principles will adjust to reflect and provide for this. The ESG-based withdrawal from coal by insurers and financiers and its impact on available insurance coverage terms has been well The current conditions in Europe, however, have created pressure on generators to bring back or increase

coal-fired output in line with governments’ emergency energy strategies. This is unlikely to be short-lived

and buyers and their brokers should be engaging with Insurers who have ceased to write new Coal business, to acknowledge that for a number of countries

of Europe, the “Social” element of ESG currently outweighs the “Environmental” considerations.

“We have seen that the world has become more complex, not only for the global community but also for the insurance sector and especially for the power insurance market.”

Global inflation

  • The impact on property values. In much the same way as the difficulties faced by insurers with BI values, the market is becoming increasingly aware of the impact of inflation on its Values need to be

reviewed and benchmarked with the company’s broker to ensure that they are adequate. For those risks where insurers have under-valuation concerns, Average Clauses are increasingly being applied.

  • Monitoring of inflation relevant to the applicable sector. As suggested earlier, there are various measures of inflation – over-estimating results in unnecessary costs, while under-estimating potentially results in inadequate limits and application of coverage restrictions such as To avoid this, it is important for power companies to have a good understanding of the rate most applicable to their sector and location, and to be able to explain this to

insurers, so they have greater confidence in the values declared.

  • Ensuring EMLs (Estimated Maximum Loss) maintain pace with the changing world. For “First Loss Limit” based programmes, limits should be based on accurate EML Those EMLs need to be regularly reviewed against expected loss levels, which will be impacted by inflation and supply chain issues. It is essential that buyers work with their brokers to ensure EMLs keep pace with the dynamics of the sector.

The energy transition

  • Understanding new risks arising from new technologies. Hydrogen, CCUS and Battery Storage will proliferate over the coming years, and yet at this stage the market has little true understanding of these As much as they may want to support the energy transition, the market will not bear risks it is not able to fully assess. This education process will not be straightforward; buyers that require bespoke, comprehensive cover, in good time to ensure projects are bankable, will need to start work now with their brokers and their engineers. This will enable them to provide valuable advise through the project design/ decision making process, assess the risk and worst case scenarios, commence programme design and facilitate the early engagement of potential markets.
  • Developing a deep understanding of business models

relating to new risks. With the energy transition comes not only new physical risks but also different business models – these will include varying revenue streams and regulatory regimes, which will depend on the technology and country in which the risk is located.

The legal and regulatory structure that sits around some of these risks can provide protections and risk limitations, including the potential for government indemnities, which will have a material impact on cover requirements and cost. The assessment of certain risks in different parts of the world (e.g. CCUS) will require the broker to have in-depth knowledge of the above,

in each territory, to ensure that the risk is presented accurately and clearly to the market, delivering optimum cover and pricing.


Climate change

  • The monitoring of the climate change related exposures and understanding implications for the business and future investment in the It is becoming increasingly apparent that climate change is having a profound effect on companies’ risks, both short and long term. This can range from losses arising from physical damage, to reductions in asset yields or even the stranding of assets following regulatory and

legal changes, for example emissions limitations. Some of the above will relate more to strategic decisions

and some, such as the physical loss, to insurable risk programmes – both are important. Later in the report we discuss the ways in which buyers can work with their brokers to identify, model and monitor climate risk.

  • The identification of Nat Cat exposure. As mentioned above, some of the risks are more business strategy related, but Nat Cat-related physical loss is a class

of cover for which capacity is being increasingly restricted as the market performance continues to deteriorate. The reinsurance market, on which many insurers rely to cover their own Nat Cat exposures, is not one that tends to fully reflect positive risk

management features. If the cost becomes difficult to accept, a thorough understanding of the true, reduced exposure that could help support reduction in limits becomes an essential part of a buyer’s armoury. Later in this Review, we discuss the tools available to support buyers through this challenge.


Conclusion: next steps

It is clear that the market’s ability to respond positively to this complex and fast changing world will depend heavily on how strongly it engages with buyers and brokers.


Understand the scale of the challenge

We address the issue of wider market conditions later in this Review, but strong underwriting governance remains a feature of this market and this can only be expected to increase rather than to soften in the future. Therefore, the reality is that buyers and their brokers have an obligation to understand the scale of this challenge and to put in place robust risk management strategies that will enable buyers to understand how all of these factors will play out for their respective organisations.


A broader range of ESG strategies

However, although it is important to note that the Russia- Ukraine conflict has had a profound effect on the Power sector and is demanding new strategies to manage its fallout, it is only one factor that has served to refocus

the attention on the need for self-sufficient, diversified, cleaner, more flexible and more resilient energy strategies. ESG and the energy transition continues to be at the heart of this and WTW regularly reports that this now requires a broader range of strategies than historically we have worked with.


Engineering and analytics will be key Engineering risk management will always remain core to our business, as the new technology will

demand greater understanding of the impact on risk of modifications (including retro-fitting of hydrogen to

gas fired plans), upgrades and prototypical designs and specifications. Analytics will also be key – indeed, the insight that well-designed risk models provide in a world


of changing climates, higher frequency and severity natural catastrophe events, globalised distribution of higher value assets and more complex supply chains and revenue streams, will become increasingly essential.


Effective long term investment strategies

However, ESG demands more. The focus on ESG highlights the risk of ineffective long-term investment strategies that fail to keep pace with the energy transition and the increasing demands of consumers, employees and investors. The impact of this will be catastrophic for those that underestimate its pace and impact – loss of market share, stranded assets, a lack of investment, an inability to secure support for insurance programmes, a miscommunication of progress to Net- Zero, reputational damage – all these factors ultimately lead to failure.


There has therefore never been a more important time for buyers to engage fully with their risk intermediary across all of their organisation’s activities and levels, to fully understand the range of services, support and insights available to help buyers navigate the challenges of the coming years.


Carlos Wilkinson is GB Head of Power & Utilities, Natural Resources, WTW London.


Pledge Your Vote Now
Change language