SummerReview 2023
WinterOutlook
2023-2024
ENTSO-E Winter Outlook 2023–2024 // 2
ENTSO-E Mission Statement
Who we are
ENTSO-E, the European Network of Transmission System Operators for Electricity, is the association
for the cooperation of the European transmission system operators (TSOs). The 39 member TSOs,
representing 35 countries, are responsible for the secure and coordinated operation of Europe’s
electricity system, the largest interconnected electrical grid in the world. In addition to its core,
historical role in technical cooperation, ENTSO-E is also the common voice of TSOs.
ENTSO-E brings together the unique expertise of TSOs for the benefit of European citizens by
keeping the lights on, enabling the energy transition, and promoting the completion and optimal
functioning of the internal electricity market, including via the fulfilment of the mandates given to
ENTSO-E based on EU legislation.
Our mission
ENTSO-E and its members, as the European TSO community, fulfil a common mission: Ensuring the
security of the inter-connected power system in all time frames at pan-European level and the
optimal functioning and development of the European interconnected electricity markets, while
enabling the integration of electricity generated from renewable energy sources and of emerging
technologies.
ENTSO-E Winter Outlook 2023–2024 // 3
Contents
Contents .......................................................................................................................3
Executive summary.......................................................................................................4
Introduction ..................................................................................................................5
General purpose of the seasonal outlooks ................................................................................................. 5
Developments since 2022........................................................................................................................... 5
Scenarios and assessments ....................................................................................................................... 6
Ukraine’s and Moldova’s systems are an integral part of the European Power System............................. 6
Coordination at the national, regional and European level.......................................................................... 6
Overview of the power system in winter 2023–2024......................................................8
Generation overview.................................................................................................................................... 8
Capacity evolution................................................................................................................................ 11
Planned unavailability of generation.................................................................................................... 12
Hydro availability.................................................................................................................................. 14
Demand overview...................................................................................................................................... 15
Network overview...................................................................................................................................... 18
Adequacy situation and gas need during winter 2023–2024 ........................................21
Reference scenario ................................................................................................................................... 21
Focus on adequacy under normal market conditions.......................................................................... 22
Focus on non-market resources .......................................................................................................... 24
Energy savings scenario............................................................................................................................ 26
Critical Gas Volume for Winter 2023–2024 .............................................................................................. 27
Expectations for Ukraine and Moldova power systems............................................................................ 29
Summer 2023 review ..................................................................................................30
Temperature overview............................................................................................................................... 30
Adequacy and other relevant events overview.......................................................................................... 31
Appendix 1: Methodological insights...........................................................................32
Appendix 2: Additional information about the study.....................................................34
Appendix 3: Additional information about the results...................................................36
Loss of Load Expectation and other annual metrics................................................................................. 36
Convergence of the results ....................................................................................................................... 37
Appendix 4: Demand reductions in the energy savings scenario ..................................38
ENTSO-E Winter Outlook 2023–2024 // 4
Executive summary
ENTSO-E Winter Outlook 2023–2024 highlights the overall favourable adequacy results, with only some
risks of electricity supply in remote areas including Ireland, Northern Ireland, Malta and Cyprus. Dedicated
non-market resources would help to alleviate those risks in Ireland and Malta. Finland may also face some
risk in the event of exceptionally adverse operational conditions combined with cold weather and high
unplanned outages. Regional risks are also identified in France, Belgium and Great Britain.
All the risks identified for the next winter season are driven by weather conditions. The challenges in Ireland
and Northern Ireland will depend on the availability of aging gas power plants, whereas Malta is more at risk,
especially in the event that interconnection with Italy falls under unplanned outage.
Regional risks in France, Belgium and Great Britain are driven by the sensitivity of the demand in France to
temperature and are present only under extreme weather conditions combined with high unplanned outages.
National studies confirm that Flow-Based Market Coupling would enable more imports, which would address
those risks.
Critical Gas Volume (CGV; gas required to ensure European power system adequacy) decreases
approximately by 10% compared with winter 2022–2023. CGV would decrease by a further 10% if energy
saving measures in line with the European energy saving targets (Council Regulation 2022/1854) of winter
2022–2023 are taken.
European power system trends since winter 2022–2023 are in line with the adequacy and CGV results:
generation fleet expands (conventional decreases, but RES increases notably) and planned outages are
lower, while demand remains stagnant. These conditions combined create favourable conditions for
adequacy and a lower reliance on gas generation.
The EU has filled gas storages to 90% of their capacity, surpassing the 1 November deadline by approximately
two and a half months. Storages were almost completely full in early November. This signals a strong
European winter preparedness and increases confidence in security of supply.
Since March 2022, Ukraine and Moldova have been synchronised with the Continental European power
system. The situation in Ukraine remains uncertain due to potential attacks on energy infrastructure,
according to national experts. Ukrenergo carried out an unprecedent restoration and renovation programme
to prepare for winter 2023–2024, including the increase of interconnection capacity with neighbours.
Furthermore, safety measures against missile strike threats were implemented to mitigate risks. The power
supply situation in Moldova is adequate but reliant on gas supplies and the availability of one single utility in
the Transnistrian region. Furthermore, the Moldovan power system operator faces challenges to balance the
system. A number of actions are being taken to mitigate such potential risks.
ENTSO-E, Ukrenergo and Moldelectrica continue to work together for the further integration of these systems
on technical and institutional levels after the successful emergency synchronisation in 2022 and continuous
increase of interconnection capacities.
The Winter Outlook is accompanied by a retrospect of last summer. No adequacy issues were recorded
during summer 2023 despite warm temperatures encountered, with heatwaves recorded in some regions.
Alert states were raised in Ireland and Northern Ireland due to tight supply margins, but wind generation and
import availabilities were sufficient to supply electricity consumers. Furthermore, Cyprus experienced a lack
of replacement reserves, but eventually averted any impact on electricity consumers.
ENTSO-E Winter Outlook 2023–2024 // 5
Introduction
General purpose of the seasonal outlooks
ENTSO-E’s Seasonal Outlooks investigate, at the pan-European level, the security of electricity supply ahead
of each winter and summer period. They are released twice a year, with a Summer Outlook in June and a
Winter Outlook in December. The role of the Outlooks is to identify when and where system adequacy — the
balance between supply and demand for electricity — is at risk. Outlooks are not forecasts of the future.
Rather, they identify potential resource adequacy risks at a specific point in time for the upcoming season
which can be addressed proactively with preparation or mitigation measures. The identified risks are based
on the assessment of a reference scenario and of various sensitivities which consider uncertainties that
could materialise.
The Outlooks are the product of cooperation between 39 European electricity Transmission System
Operators (TSOs). Because of their pan-European scope, the Outlooks complement the analysis carried out
in national and regional assessments, which provide a more detailed picture of adequacy at the local level.
They promote cooperation across Europe and between regional and national stakeholders. The seasonal
outlooks model the resource adequacy, not considering specific operational constraints such as grid stability
or voltage.
Performing the Seasonal Outlooks (Seasonal Adequacy Assessments) is one of ENTSO-E’s legal mandates
as specified in the Clean Energy Package and as defined in Article 9 of the Risk Preparedness Regulation
(Regulation (EU) 2019/941). ENTSO-E performs this assessment to inform national authorities, TSOs and
relevant stakeholders of the potential risks related to the security of electricity supply in the coming season.
The Seasonal Outlooks reflect the implementation of the Methodology for Short-term and Seasonal
Adequacy Assessments1
developed by ENTSO-E as per Article 8 of the Risk Preparedness Regulation and as
approved by ACER on 6 March 2020. Earlier Seasonal Outlooks (published before 2020) followed a different
methodology (deterministic approach).
The interconnected system is a key resource for wider system adequacy. ENTSO-E’s Winter Outlook gives
results for all ENTSO-E member systems. Data inputs and assumptions from neighbouring interconnected
countries are also integrated into the modelling. As in every Outlook, data are collected for Turkey and
included in the assessment. The system of Great Britain is strongly interconnected in the North Sea region,
and a dedicated collaboration has been set up with National Grid ESO to exchange data. Prospects of
adequacy in Ukrainian and Moldovan power systems were shared by the respective TSOs. Furthermore, their
system is considered an integral part of the European power system and considered as available for power
transits for adequacy. Other neighbouring systems beyond the ENTSO-E perimeter are modelled in a
simplified manner by defined hourly exchanges.
Developments since 2022
The situation in the European power system for winter 2023–2024 is far more certain than winter 2022–
2023; yet close screening and monitoring is required. This winter, Europe has much greater assurance
regarding fuel supply availabilities as supply routes were diversified or alternative supplies were identified by
many. Furthermore, nuclear availability and hydro stocks are in much better shape. Nevertheless, an
adequacy and Critical Gas Volume (CGV) analysis, just as for winter 2022–2023, is performed to ensure the
awareness and preparedness of European power system. All TSOs within ENTSO-E maintain close
coordination and contact with the European Commission (EC) and the Electricity Coordination Group (ECG)
on the prospects for winter 2023–2024.
1
https://eepublicdownloads.entsoe.eu/clean-documents/sdc-documents/seasonal/Methodology%20for%20Short-
term%20and%20Seasonal%2D0Adequacy%20Assessment%20-%20ACER%20Decision%2008-
2020%20on%20the%20RPR8%20.pdf
ENTSO-E Winter Outlook 2023–2024 // 6
Scenarios and assessments
This winter outlook assesses two scenarios: a reference scenario (with and without non-market resources)
in addition to an energy saving scenario. This energy saving scenario is mainly covered as a follow-up on
demand reduction targets set by the EC for the winter of 2022–2023 following the war in Ukraine and high
increases in energy prices. Such demand reduction targets are not set for winter 2023–2024 but insights on
an energy saving scenario would be beneficial for member states to assess the impact of such actions on
our electricity production, both on adequacy and on gas consumption levels.
In every scenario, both adequacy assessments and CGV assessments are shared in this report.
Ukraine’s and Moldova’s systems are an integral part of
the European Power System
Ukrenergo and Moldelectrica (the TSOs in Ukraine and Moldova respectively) are part of the European power
system and continue working further for the integration of these systems on various technical and
institutional levels. They have operated synchronously with the rest of continental Europe power systems
since 16 March 2022; whereas the Burshtyn Island (western part of Ukraine) has been operating
synchronously with continental Europe since 2003. Exchange capacities have continuously increased since
then. Furthermore, Ukrenergo and Moldelectrica enhance their contributions to various pan-European studies
– close contact was maintained even prior to the Russian invasion to Ukraine in February 2022, but since
then collaboration has increased to unprecedented levels.
Ukrainian and Moldovan national perspectives on the situation in winter 2023–2024 are presented in this
report. The situation remains uncertain and difficult to predict due to geopolitical threats. Russia’s war in
Ukraine continues to pose threats to energy infrastructure. Geopolitical tension in Moldova (Transnitria and
Gagauzia), in addition to the uncertainty of gas supplies in Moldova, creates additional uncertainty. These
systems rely on potential support from other European countries who are continuously investigating available
measures to increase support for these systems – especially during the most critical moments.
Ukrenergo and Moldelectrica collaborate with other European TSOs. Their power systems are anticipated to
be available to support the European power system if necessary. Even if resource availabilities in Ukraine and
Moldova remain uncertain, the transmission network should remain available for transit flows between other
European power systems.
Coordination at the national, regional and European level
Cross-border cooperation and close coordination at all levels will be key this winter to ensure that the
European power system maintains its balance between supply and demand:
On the European level
• Exchange on risk preparedness plans via the Electricity Coordination Group and Gas coordination
group;
• Winter outlook and updates: If impacting changes in European power system occur this winter,
updates to ENTSO-E’s winter outlook are possible;
• Following the winter outlook, the Short Term Adequacy (STA) process monitors the coming seven
days in a rolling-window to detect any adequacy issues on the cross-regional (Pan-EU) level;
• ENTSO-E is ensuring weekly Operational Coordination between all interconnected TSOs and Regional
Coordination Centres (RCCs) to enable fast communication and alignment, when necessary, for
operational processes; and
• Communication between ENTSO-E and ENTSO-G to align assumptions and messages between the
gas and electric Winter Outlook.
On the Regional level
ENTSO-E Winter Outlook 2023–2024 // 7
• Following the Cross-Regional STA process, in the event of the detection of scarcity situations, a
regional STA process exists managed by RCCs with the participation of concerned TSOs to
coordinate the proposal of adequacy remedial actions on a regional level; and
• TSOs and RCCs will coordinate during the whole winter to maximise cross-border capacities
regionally through an established operational planning coordination (OPC) process.
On the National level
• TSOs conducted national adequacy studies in parallel to the ENTSO-E winter outlook. These national
studies may use different sensitivities or focus more on extreme cases, such as the German
‘Extraordinary analyses winter 2022/2023’, where multiple stress elements coincide. National
studies can also consider more detailed constraints, such as internal transmission bottlenecks.
• Each Member State developed a dedicated Risk Preparedness Plan, which includes mitigation
measures. The member states set-up coordination with governments, National Regulatory
Authorities (NRAs) and key stakeholders to operate these mitigation measures.
ENTSO-E Winter Outlook 2023–2024 // 8
Overview of the power
system in winter 2023–2024
Generation overview
Compared to the previous winter, the generation capacity in Europe follows the same general trend of
increasing installed renewable generation and batteries while decommissioning thermal generation as gas.
This evolution is beneficial for the carbon footprint of the European electricity power system but should go
hand in hand with increased flexibility on the consuming sectors as cold days with low renewables tend to
get more problematic as this trend continues.
Figure 1 Generation capacity change over year: winter outlook 2023–2024 vs winter outlook 2022–2023
The generation capacity overview in Figure 2 shows that sufficient generation capacity to supply consumers
is available in most countries. However, generation unavailability (planned or unforeseen) and actual
renewable generation infeed have an impact, and some countries may rely more strongly on imports. For
example, Central Northern Italy (ITCN) is dependent on imports when renewable generation is low.
ENTSO-E Winter Outlook 2023–2024 // 9
Figure 2: Net generating capacity overview – comparison with highest expected demand
According to Figure 3, thermal net generating capacity (NGC) available on the market accounts for a bit less
than 40% of the total capacity of the European power system at the beginning of winter 2023. This is followed
by hydro, wind, and solar capacities, which constitute most of the remainder. In addition, the highest expected
demand2
is depicted with a small black square, and its value is given as a percentage of each study zone’s
NGC. In most of the study zones, the thermal NGC share is below 60%. This is especially noticeable in study
zones with high hydro capacities. Nevertheless, in some study zones (e.g. Western Denmark [DKW1],
Germany [DE00] and southern Sweden [SE04]), the thermal NGC share is low despite insignificant hydro
capacities. These systems are characterised by a high share of wind and solar generation. Demand Side
Response (DSR) resources are gaining volume in Europe. Nevertheless, DSR may be available for a limited
period of time only (e.g. few hours in a day) or at varying capacity. More DSR is likely to be available during
peak times, but this is not guaranteed.
2
Highest expected demand is computed by taking the highest value of the hourly demand 95th
percentiles. However,
the Seasonal Outlook assessment also considers that demand may even exceed the expected highest value as,
occasionally, new peak demand records are registered in Europe.
ENTSO-E Winter Outlook 2023–2024 // 10
Figure 3: Generation capacity mix at the beginning of winter 2023–2024 per study zones
Figure 4 shows which study zones have non-market resources available in addition to the corresponding
NGC. In the event of a lack of supply in the market, the activation of dispatchable non-market resources can
help address the adequacy challenges. Only seven countries utilise non-market resources. From largest to
smallest NGC, these are: Germany, Poland, the southern bidding zone of Sweden, Austria, Southern Ireland,
Switzerland and Malta. This report also assesses if these resources are sufficient to address the identified
adequacy issues (c.f. section ‘Adequacy situation and gas needs during winter 2023–2024’).
ENTSO-E Winter Outlook 2023–2024 // 11
Figure 4: non-market resources for coping with adequacy challenges in Europe3
Capacity evolution
Figure 5 shows that generation capacity in Europe grows during winter 2023–20244
, with a net increase of
approximately 32 GW, due mainly to the expansion of renewable generation capacity. Thermal generation is
decreasing due to the decommissioning of hard coal and lignite plants not being balanced by the increase of
gas-fired power plant generation capacity. However, in some exceptional cases decommissioned units might
be contracted as non-market resources to support adequacy or under other non-market schemes to provide
system services.
3
Parts of German non-market resources have a different primary purpose other than coping with resource adequacy
risks, such as grid stabilisation. In the event of adequacy issues in Germany, these may already be partly exhausted
for their primary purpose.
Poland has been contracting non-market DSR through their capacity markets. These resources can be activated only
under very specific conditions and not in a selective manner (i.e. all resources with a capacity market contract must
react during the stress events, i.e. both the generation and demand side). Hence, this non-market DSR is not
represented in seasonal outlook models, but reported here for informational purposes.
4
30 Oct 2023 – 31 March 2024
ENTSO-E Winter Outlook 2023–2024 // 12
Figure 5: Capacity evolution in winter 2023–2024
Planned unavailability of generation
Compared to last winter, the overall planned outage schedule is more favourable. Several effects can explain
this:
— A better situation regarding nuclear availability everywhere in Europe and especially in France
— A better situation regarding gas availability in IT, NL and UK
— Overall the same situation with hard coal, lignite and oil
ENTSO-E Winter Outlook 2023–2024 // 13
Figure 6: expected planned outages: for winter 2023–2024 vs winter 2022–2023
The planned unavailability of units considered in the assessment is presented in Figure 7. The planned
unavailability of generation units includes planned outages for maintenance purposes and mothballing. The
total planned unavailability in Europe decreases at the start of winter and arrives at its lowest value during
the month of January. Nuclear units show the highest level of unavailability among thermal technologies with
gas ranking second, followed by hard coal, lignite and oil.
Figure 7: Planned unavailability of thermal units
ENTSO-E Winter Outlook 2023–2024 // 14
Planned unavailability in northern countries tends to decrease during the coldest months when highest
demand is expected (i.e. in January and February). This can be observed in the cases of Italy or France, as
shown in Figure 8. The figure depicts the weekly ratio of thermal planned unavailability within each study
zone with respect to the total thermal NGC of the respective study zone. In some countries, very low amounts
of planned unavailability are foreseen for the whole winter period.
Figure 8: Weekly distribution of thermal planned unavailability relative to thermal NGC
Hydro availability
Concerning hydro storage levels at the beginning of winter, the projections are more favourable all over
Europe for winter 2023–2024. Figure 9 shows the hydro storage start levels. Please keep in mind that the
comparison is done between the input values of previous and actual winter outlooks and not between the
measured values of the previous winter compared to the inputs of this winter outlook.
ENTSO-E Winter Outlook 2023–2024 // 15
Figure 9: hydro storage level expectations: start of winter 2023–2024 vs winter 2022–2023
Demand overview
Over the past three years, both the COVID situation and the energy price crisis had a significant impact on
demand all over Europe. With both crises mitigated, it was important to rely on TSOs to provide qualitative
expectations for the next winter. A questionnaire conducted in July 2023 showed that electricity demand is
varying across Europe. Figure 10 shows that most of Europe expects similar demand regarding the previous
5 years’ statistics, showing a rebound after both crises, while other TSOs, such as France, expect a lower
demand following the demand reduction efforts of the previous winter.
An energy saving sensitivity, covering possible new demand reduction requirements in Europe or the overestimation
of demand, is covered in the results section.
ENTSO-E Winter Outlook 2023–2024 // 16
Figure 10: European TSOs’ expectation on electricity consumption and demand peaks against last 5 years’ statistics
The highest European demand is expected mid-January to mid-February, while actual weather conditions will
have a large impact.
Figure 11 shows a heat map by study zone, comparing the expected consumption in each week with the
highest expected weekly consumption in winter 2023–2024. The darker shades indicate low expected
consumption compared to highest expected consumption. Typically, the period at the start of the winter and
between 25 December and 1 January shows low weekly consumption while January and February show the
highest weekly consumption.
ENTSO-E Winter Outlook 2023–2024 // 17
Figure 11: Demand overview – evolution over winter 2023–24
Figure 12 shows workday consumption patterns per study zone by plotting the average demand relative to
the highest average demand in winter 2023–2024. The peak demand in Europe is mostly concentrated in the
morning and evening. In some study zones (e.g. Netherlands, Poland or Germany), no significant reduction
can be seen between these two peaks in the demand.
ENTSO-E Winter Outlook 2023–2024 // 18
Figure 12: Demand profile overview during Mondays–Fridays in summer 20235
Network overview
Compared to previous winter, only minor changes have been noticed in the maximum NTC in most of Europe,
in import and export. However, some infrastructure evolutions of the European network6
contribute to a
noticeable increase in import capacity for zones such as the Northern part of Italy, Slovenia and Hungary.
5
The UTC time convention was used.
6
Infrastructure projects in one country may have a positive and notable impact in the other countries.
ENTSO-E Winter Outlook 2023–2024 // 19
Figure 13 Import and Export capacity trends: winter 2023–2024 vs winter 2022–2023
For coming winter, Figure 14 shows the ratio of lowest import capacity to highest expected demand. It
indicates the extent to which systems may be capable of relying on the imports from abroad during supply
scarcity moments (if generation abroad is available).
High import capacity to demand ratio cannot predict whether a study zone is dependent on imports for
adequacy. For example, ITCN shows a high import capacity to demand ratio in addition to a low generation
capacity to demand ratio (c.f. Figure 2). This indicates that this region is dependent on imports. In contrast,
a low import capacity to demand ratio does not guarantee that the system is capable of supplying consumers
with domestic generation – for example Northern Italy (ITN1) has a low import capacity to demand ratio but
also a rather low generation capacity to demand ratio. Hence, imports to Northern Italy are important for its
adequacy as is confirmed by the simulations.
The evaluation of import capacities considers the planned unavailability of grid elements. However,
additional unplanned outages may constrain import capacities even further. Furthermore, import capacities
with non-explicitly modelled systems are not considered in the figure, but their contribution is assessed in
adequacy simulations7
.
7
These systems are modelled in a simplified manner by estimating the potential contributions of those systems to
the European power system or potentially needed imports from the European power system. Hence, information
concerning interconnection capacity and national assets is not used in the adequacy models and not collected.
ENTSO-E Winter Outlook 2023–2024 // 20
Figure 14: Import capacities per study zone: ratio between lowest import capacity and highest expected demand. C.f.
Figure 29 for details
ENTSO-E Winter Outlook 2023–2024 // 21
Adequacy situation and gas
need during winter 2023–
2024
ENTSO-E assesses the adequacy situation with two scenarios: the Reference scenario and Energy saving
scenario. In both scenarios, the CGV projections are calculated. The energy-saving scenario serves to
indicate the impact of potential demand reductions to achieve adequacy issues as well as on gas fuel
reliance.
The adequacy situation in winter 2023–2024 (Figure 15) highlights certain adequacy risks – i.e. the risk of
having to rely on non-market measures – in Ireland, Cyprus and Malta. A small regional risk is identified in
and around France, with the highest risk affecting Belgium and the UK. Traces of risks are also identified in
Finland. Results with energy saving measures suggest that risks could be significantly mitigated by these
measures. Only a small regional risk in and around France does not change drastically as demand
expectations for winter 2023–2024 in the reference scenario are already low.
Figure 15: Adequacy overview
The state of the power system is continuously changing and is different since the data collection (performed
in August 2023). For this reason, risks are continuously being monitored by TSOs and Regional Coordination
Centres (RCCs).
Reference scenario
The adequacy situation is assessed using a two-step approach. In the first step, adequacy under normal
market operation conditions is evaluated. In the second step, non-market resources, such as strategic
reserves, are included to assess whether these would be sufficient to solve the risks identified in the previous
step. The non-market resources can be activated to cope with structural supply shortages in the market.
ENTSO-E Winter Outlook 2023–2024 // 22
There are some risks of electricity supply in remote areas including Ireland, Northern Ireland, Malta and
Cyprus. Dedicated non-market resources would help to alleviate those risks in in Ireland and in Malta. Finland
may also encounter some risk in the case of exceptionally adverse operational conditions combined with
cold weather and high unplanned outages.
Small regional adequacy risk is identified in and around France (FR00), with the highest probability of
affecting Belgium and Great Britain. Efficiencies of Flow-Based Market Coupling, which are considered in
French8
and Belgian9
national adequacy assessments, suggest that these risks could be averted.
Figure 16: Adequacy overview
Focus on adequacy under normal market conditions
Figure 17 presents detailed adequacy risks under normal market operations. For most countries, the
adequacy risk is not identified. Risks are present in Ireland (IE00), Northern Ireland (UKNI), Cyprus (CY00) and
Malta (MT00), which have limited or no interconnection to the European continental network. These risks
suggest that systems may need to rely on non-market resources or operational measures to cope with supply
challenges to prevent load shedding.
A small regional adequacy risk is identified in and around France (FR00), with the highest probability of
affecting Belgium and Great Britain in the event of an extreme cold spell. However, the efficiencies of FlowBased
Market Coupling, which are considered in French10
and Belgian11
national adequacy assessments,
suggest that these risks could be averted. Nevertheless, TSOs will remain vigilant and, if necessary, will adopt
regional coordination measures to ensure optimal network operational planning measures being
implemented to address such risks. This supports the seasonal outlook methodology development
discussions in the TSO community, supporting the idea to implement Flow-Based Market Coupling
representation in the foreseeable future.
8
French national adequacy study
9
Belgian national adequacy study
10
French national adequacy study
11
Belgian national adequacy study
ENTSO-E Winter Outlook 2023–2024 // 23
Figure 17: Adequacy risk overview
The distribution of risks within the season is presented via visualisation of Loss Of Load Probability. No
common pattern could be observed as all systems with risks are rather distant from each other, and systemspecific
conditions may cause local adequacy issues. The only common pattern is identified around France
(France, Belgium, United Kingdom), where a small regional risk was identified.
Cyprus (CY00) may face risks in the event of adverse weather conditions and combined with unplanned
outages. The Cyprus system has no interconnection to the other power systems and must therefore rely on
domestic supply. Higher risks are identified in the period until January 2024, though those risks are mitigated
to some extent due to planned outage rescheduling performed until the publication of this report. If weather
conditions are favourable or at least not combined with high unplanned outages, no adequacy issues should
be recorded over winter 2023–2024 in Cyprus.
Ireland (IE00) is marked with adequacy risks throughout winter 2023–2024. These risks are driven by the
unplanned outages of aging powerplants and will depend on wind generation if such outages will occur. The
decommissioning of a 350 MW gas power plant in Northern Ireland before winter puts additional stress onto
the Irish system. This generation is supposed to be replaced by 700 MW gas power plants, which should
mitigate risks to a certain extent. However, this will happen only after winter 2023–2024. Meanwhile, Ireland
may rely on non-market resources (~500 MW), whose contribution is assessed further in the report.
The adequacy situation in Malta (MT00) should be monitored throughout the winter and especially if
significant unplanned outages of generation or interconnection with Italy are recorded. Adequacy in Malta is
typically carefully monitored every winter, and for this reason, Malta implemented specifically designed nonmarket
resources, which could be activated in the event of supply scarcity. The impact of these non-market
resources is presented in the following section.
The risks faced by Northern Ireland (UKNI) concentrate in late December and January but remain rather low
compared to the risks in Ireland. However, the situation should be closely monitored if weather conditions
are unfavourable in Northern Ireland or neighbouring systems.
ENTSO-E Winter Outlook 2023–2024 // 24
A small regional adequacy risk is identified in and around France (FR00), with the highest probability of
affecting Belgium and Great Britain. These risks are identified in January in the event of an extreme cold
spell.
Finland (FI00) risks are minute but suggest that supply margins in their system are low. This means that
electricity consumers might be affected by a combination of extreme weather conditions and high unplanned
generation or interconnection outages.
Figure 18: Adequacy weekly insights
Focus on non-market resources
Dispatching non-market resources reduces the magnitude of the risks (EENS), notably in Malta and Ireland.
In Malta it is significantly reduced when compared to the normal market operation and only traces of risks
remain as Malta relies on dedicated non-market resources (c.f. Figure 4).
The activation of these resources may depend on the existing legal frameworks12
. Figure 19 presents the
adequacy conditions with non-market resources while the Polish non-market DSR is excluded due to specific
conditions of activation.
12
The assessment considers pan-European cooperation when activating non-market resources, which means that
non-market resources in one country are also considered in another during scarcity (but also considering network
limitations). The actual activation of non-market resources abroad may depend on the existing legal framework.
ENTSO-E Winter Outlook 2023–2024 // 25
Figure 19: Adequacy risk overview – considering non-market resources
The distribution of risks in Figure 19 suggests that risks in Malta could not be addressed completely in
December (week 50). In addition, Malta should remain vigilant in January–February as residual risks prevail.
Risks in Ireland are completely addressed towards the end of the season, while risks in the rest of the winter
still remain. Risks in other zones remain unaffected.
Figure 20: Adequacy weekly insights—considering non-market resources
Figure 21 represents the impact of non-market resources. As already discussed, adequacy risks are
significantly mitigated in Malta and Ireland. However, the Figure 21 results also suggest that risks could also
be mitigated in areas where such measures do not exist but are accessible through interconnectors. Results
in Northern Ireland suggest that Irish non-market resources could contribute to addressing the risks; however,
this might be not possible due to legal restrictions on sharing these resources. Indeed, the activation of these
ENTSO-E Winter Outlook 2023–2024 // 26
resources may depend on the existing legal frameworks13
. Figure 21 presents the adequacy conditions with
non-market resources while the Polish non-market DSR is excluded due to specific conditions of activation.
Figure 21: Detailed adequacy overview – weekly LOLP and ENS14
Energy savings scenario
Energy saving measures if implemented to achieve European energy saving targets (Council Regulation
2022/1854), as in winter 2022–2023, would contribute to adequacy risk mitigation. Traces of risk would
disappear in Finland. Risks elsewhere would still remain, but would decrease substantially (risk
disappearance in Belgium suggests that the magnitude of small regional risk in and around France would
decrease). These energy saving measures could reduce the necessity to activate non-market resources, but
those would remain necessary in Ireland and Malta.
13
The assessment considers pan-European cooperation when activating non-market resources, which means that
non-market resources in one country are also considered in another during scarcity (but also considering network
limitations). The actual activation of non-market resources abroad may depend on the existing legal framework.
14
Results in Northern Ireland suggest that Irish non-market resources could contribute to addressing risks; however,
this might be not possible due to legal restrictions on sharing these resources.
ENTSO-E Winter Outlook 2023–2024 // 27
Figure 22: Adequacy risk overview – Energy savings scenario
The distribution of risks in Figure 23 suggests a similar pattern as in the reference scenario, though the risks
themselves decrease.
Figure 23: Adequacy weekly insights – Energy savings scenario
Critical Gas Volume for Winter 2023–2024
The Critical Gas Volume (CGV) decreases approximately by 10% compared with winter 2022–2023. Factors
such as the higher nuclear availability in Europe, the expansion of renewable production capacity and higher
hydro availability, in addition to stagnant demand, all indicate having to rely less on conventional gas powerplant
production to cover the demand peaks.
CGV projections consider the worst winter scenarios and inform electricity system adequacy. Actual volumes
may already be higher, depending on ancillary service demand, additional new unavailabilities and real market
behaviour, with some gas units not being last in the merit order. CGV could decrease by 10% if energy saving
measures to reduce consumption and peak demand comply with similar targets as approved by Council for
winter 2022–2023 (Council regulation 2022/1854). More information is given in in appendix 4.
ENTSO-E Winter Outlook 2023–2024 // 28
Figure 24: CGV analysis overview
The results also suggest that reliance on gas availabilities is particularly high in January and February if
weather conditions are not favourable.
1 – Max gas consumption. This is CGV.
2 – Gas consumption with 75%
probability of being below
3 – Most probable gas need
4 – Gas consumption with 75%
probability of being above
5 – Min gas consumption
Legend
Historical gas consumption
1 32 4 5
AGC(e) – average gas consumption
for electricity generation
CGV – critical gas volume to ensure
adequacy
Assumptions:
- Focus on winter period (December–
March) for both statistical and
simulated data
- Statistical data from Eurostat for the
5 recent winter periods (from winter
2014/2015 to winter 2018/2019)
- Spatial scope: ENTSO-E perimeter
(excluded UK, TR, UA)
- CGV is expressed in Gross Calorific
Values. NCV to GCV conversion is
performed by applying a 1.108 factor.
How to interpret the CGV chart
• Each orange dot represents a historical winter period of gas consumption for electricity generation. The
significant differences between periods are primarily related to temperature and climate conditions but can
also be influenced by the situation in the electricity market (prices, planned outages, changing generation
fleet, etc.).
• The AGC(e) (orange line) represents the average gas consumption for electricity generation for the 5
statistical years (orange dots).
• The maximum gas consumption corresponds to the gas volume necessary to ensure adequacy in the worstcase
simulated weather condition scenario. This maximum is indicated as the CGV to ensure adequacy.
• The dark and light purple colours represent the range of simulation outcomes of gas volume necessary to
ensure adequacy for a given year, depending on the climate conditions (the simulation uses 34 climate
condition scenarios). There is a 50% probability of a given year being in this range.
ENTSO-E Winter Outlook 2023–2024 // 29
Expectations for Ukraine and Moldova power systems
Russia’s military aggression against Ukraine, starting in February 2022, continues during 2023 and causes
increased levels of risk and uncertainty in Ukraine’s and Moldova’s energy systems. Power generation and
grid infrastructure availabilities in Ukraine are uncertain due to risks of attacks on these infrastructure
objects, which may determine the actual situation in Ukraine’s power system. Uncertainty over gas supplies
and electricity import availabilities are key concerns in Moldova.
Ukraine’s national analysis for the upcoming winter season demonstrates an acceptable level of adequacy
in the Ukrainian Integrated Power System, especially under conditions similar to the current situation.
However, it is important to note that achieving this adequacy level will necessitate higher than usual volumes
of natural gas consumption for electricity generation and some minimal required electricity imports
throughout the entire winter season. In the most precarious scenarios, which involve significant and hardly
predictable damage to generation equipment and grid infrastructure, there is a potential for increased
electricity imports and natural gas consumption. In extreme cases, these factors may even lead to the
necessity for demand shedding.
Moldova faces several system adequacy risks for the upcoming winter, including heavy dependence on gas,
uncertain imports from Ukraine and Romania, weak interconnections at the Romanian border, high reliance
on a single power source, and vulnerability to disturbances in the Ukrainian power system. Other concerns
include a lack of flexibility in the power system.
To prepare Winter 2023–2034, Moldova is taking proactive measures, including risk discussions with the
government, ANRE (National regulator), and key market actors, emergency state decisions for the Electricity
Market, nominating ‘Energocom’ as the sole buyer/seller for regulated utilities, implementing capacity
allocation at the MD–RO border, and upgrading infrastructure. These preparations, coupled with demand
reduction measures and gas stocking in Ukraine and Romania, aim to reduce the system risk significantly.
ENTSO-E Winter Outlook 2023–2024 // 30
Summer 2023 review
In general, no adequacy issues were recorded during summer 2023. Europe experienced hot summer months,
with extreme weather events in some regions. Heatwaves were experienced in Southern Europe from Spain
to the Balkans in July; from Portugal, France, Spain and Italy in August; and Belgium in September.
Southwestern Europe experienced wildfires in August, while Eastern Europe and Scandinavian countries
experienced significant flooding events. Scandinavia was also affected by Storm Hans in August.
The EU has successfully filled gas storage facilities to 90% of their capacity, surpassing the 1 November
deadline by approximately two and a half months. This effort, driven by the gas storage regulation introduced
in June 2022, aims to better prepare the EU for the upcoming winter season. Gas storage is crucial for
ensuring a secure gas supply in Europe, covering up to one-third of the EU's winter gas demand.
Temperature overview
During the summer of 2023, Europe witnessed unprecedented temperature anomalies (Figure 25). In June,
European temperatures were 0.74°C above the 1991–2020 average, with the highest anomalies observed in
northwest Europe. Conversely, the southern Balkans, Greece, Türkiye, and western Russia were colder than
average, with mixed conditions across Italy and Spain.
July continued this trend, with Europe experiencing a 0.38°C temperature anomaly, while globally, it was the
warmest month ever recorded. Heatwaves stretched from Spain to the Balkans, while much of northern
Europe had temperatures close to or below average.
August featured above-average temperatures in southern Europe, with Portugal, France, Spain and Italy
experiencing a heatwave. Globally, August 2023 was the hottest August on record, with a 0.71°C anomaly
above the 1991–2020 average.
September marked the culmination of this remarkable summer, with Europe experiencing a 2.51°C
temperature anomaly, making it the hottest September in the European record. Several countries in a band
from France to Finland recorded their warmest September on record. Meanwhile Belgium and the United
Kingdom reported unprecedented heatwaves in early September. Cooler temperatures were limited to the
continent's periphery, including Iceland, Svalbard, and parts of Greece and the Iberian Peninsula.
ENTSO-E Winter Outlook 2023–2024 // 31
Figure 25: Surface air temperature anomaly in Summer 2023 relative to the average for the periods 1991–2020 (for
June, July, August, and September)15
Adequacy and other relevant events overview
In general, no adequacy issues were recorded during summer 2023. Some countries faced unusual water
levels (low or high), change in electricity demand, and high photovoltaic (PV) output.
Austria experienced record-breaking hydroelectric production due to heavy rainfall, resulting in high exports
and reduced imports. The country is rapidly expanding renewable energy sources but faces challenges with
unreported PV installations affecting demand. Cyprus had a few hours of reduced reserve availability but
managed without significant adequacy issues. Finland had planned outage related capacity drops, but its
self-sufficiency in electricity generation is improving, driven by increased wind power.
Reduced gas deliveries from Russia had no impact on electricity generation. Greece saw a slight increase in
electricity demand, especially during heatwaves. Fires and severe storms caused localised outages.
However, no major adequacy issues were recorded.
Hungary recorded moderate system demand, high PV generation, and consequently a decrease of imports
during the summer. The country managed IT and network problems effectively, ensuring a reliable supply.
Ireland and Northern Ireland faced tight generation margins during the summer, leading to an alert state on
one occasion. Security of supply was maintained through renewable generation and interconnector support.
The Swiss network was highly loaded which required redispatch actions to mitigate bottlenecks. Unplanned
power flows and voltage regulation challenges occurred, but overall regulatory stability was maintained.
15
Copernicus Climate Change Service—Surface air temperature maps
ENTSO-E Winter Outlook 2023–2024 // 32
Appendix 1: Methodological
insights
Since the Summer Outlook 2020 report, ENTSO-E has significantly upgraded its methodology for assessing
adequacy on the seasonal time horizon.
This new methodology is described in the Methodology for Short-term and Seasonal Adequacy
Assessments16
. It was developed by ENTSO-E in line with the Clean Energy for all Europeans package and
especially the Regulation on Risk Preparedness in the Electricity Sector (EU) 2019/941, and it received formal
approval from the Agency for the Cooperation of Energy Regulators (ACER)17
. Although the implementation
of this target methodology will still require certain extensions in the coming year (for instance to include flowbased
modelling), the present Summer Outlook presents a major advancement.
Most notably, the seasonal adequacy assessment has shifted from a weekly snapshot based on a
deterministic approach to the well-proven, state-of-the-art, sequential, hourly Monte Carlo probabilistic
approach. In the Monte Carlo approach, a set of possible scenarios for each variable is constructed to assess
adequacy risks under various conditions for the analysed timeframe. Figure 26 provides a schematic
representation of this scenario construction process.
Figure 26: Scenarios assessed in Seasonal Outlooks
Scenarios are constructed, ensuring that all variables are correlated (interdependent) in time and space. To
ensure the highest quality of data in the assessments, they are prepared by experts working within dedicated
teams. A Pan-European Climate Database maintained by ENTSO-E ensures high data quality and consistency
across Europe.
Consequently, ENTSO-E has transitioned from a 'shallow' scenario tree, with limited severe and normal
conditions samples, to a 'deep' scenario tree that incorporates extensive interdependent weather data and
random unplanned outages. This generates a wide range of alternative scenarios spanning multiple weather
scenarios. Furthermore, an improvement in the methodology also enables the consideration of hydro energy
availability. Figure 27 illustrates the difference in the number of scenarios between the two modelling
approaches.
16
Methodology for Short-term and Seasonal Adequacy assessment
17
ACER decision (No 08/2020) on the methodology for short-term and seasonal adequacy assessments
ENTSO-E Winter Outlook 2023–2024 // 33
Figure 27: Scenario revolution – from deterministic to probabilistic
An adequacy assessment is conducted for each sample case on the seasonal time horizon, yielding a
probabilistic pan-European resource assessment. It identifies adequacy risks in each deterministic sample
and generates numerous consistent pan-European draws while identifying realistic adequacy risk. After the
Winter Outlook 2020–2021, further improvements were made, especially in the modelling of exchanges,
whereby new constraints on total simultaneous exchanges were implemented. In the Summer Outlook 2021,
simultaneous import and simultaneous export limitations were considered, as were limitations on country
position (or net exchange).
ENTSO-E Winter Outlook 2023–2024 // 34
Appendix 2: Additional
information about the study
Figure 28: Study zones
ENTSO-E Winter Outlook 2023–2024 // 35
Figure 29: Import capacity overview18
18
PLI0 represent import on the technical PL00 border with DE00/CZ00/SK00. It limits simultaneous import from
respective Study Zones to Poland. The same technical border is used for export purpose (PLE0) and export NTC
amounts to 1650 MW.
ENTSO-E Winter Outlook 2023–2024 // 36
Appendix 3: Additional
information about the results
Loss of Load Expectation and other annual metrics
Information about Loss of Load Expectation (LOLE) in the assessed season is presented in this appendix.
LOLE figures can be useful when comparing how adequacy evolved between editions of seasonal adequacy
assessments19
. However, readers are invited to interpret them carefully as LOLE is commonly known as an
annual metric, whereas in seasonal adequacy assessment, only a specific season (part of the year) is
considered.
LOLE analysis may lead to misleading conclusions when compared with Reliability Standards (existing or
under development in accordance with Article 26 of Regulation 2019//943). Some examples are given below,
assuming that the annual LOLE Reliability Standard20
is set and compared with seasonal LOLE:
• Seasonal LOLE can be lower than the Reliability Standard, but this does not mean that adequacy
within the assessed season complies with the Reliability Standard. For example, even a minor LOLE
value can indicate unusual risk in a Study Zone if the risk is identified in an unusual season (e.g. risk
in summer for a Northern country); and
• Seasonal LOLE can be higher than the Reliability Standard, but this does not necessarily mean that
the system design does not comply with the Reliability Standard. The expected situation in an
upcoming season could simply be one of the more constraining from a set of possible season
scenarios21
(e.g. if low water availability in hydro reservoirs and high generation unavailability is
expected at the beginning of the season).
It is worth considering whether the Reliability Standard is defined as a system design target or as an
operational system adequacy metric target. To meet the Reliability Target set for power system design
purposes, Europe relies initially on market signals (for supply and network investments) and, if those are
insufficient, market design corrections can be made (for example the establishment of complementary
markets such as Capacity Mechanisms). The latter market decisions are based on a several-year-ahead
framework22
, whereas seasonal outlooks relate to an operational timeframe which relies on the market
participants taking short-term corrective actions (e.g. change of planned outage schedules) in addition to the
TSOs utilising all available resources in the best manner to reduce the risks to the lowest possible level.
Therefore, it is important to understand the purpose of any metric to which Seasonal Outlook results may be
compared, and this is especially important for LOLE.
Considering the aforementioned background and interpretation limitations, LOLE figures can be found in the
main report content (Figure 17, Figure 19, Figure 22).
19
A comparison with past editions is not yet possible yet because this is the first time this measure has been reported
in a seasonal adequacy assessment.
20
The conclusions made for annual LOLE are also valid for any other annual metric.
21
The same applies for a particular historical supply scarcity. If hours when demand was shed exceed the LOLE set
by the Reliability Standard, this does not mean that system design does not comply with the Reliability Standard. LOLE
set by Reliability Standard simply indicates in how many hours demand shedding is acceptable (due to supply scarcity)
over a long time.
22
Monitored by the European Resource Adequacy Assessment in line with Article 23 of Electricity Regulation 2019/943
ENTSO-E Winter Outlook 2023–2024 // 37
Convergence of the results
In addition to seasonal LOLE results, we also publish the convergence overview, which shows that the
seasonal assessment has a high accuracy level.
Figure 30: Convergence overview23
23
The convergence overview shows that the seasonal assessment has a high accuracy level. The number of analysed
Monte Carlo samples was 700, one per scenario.
ENTSO-E Winter Outlook 2023–2024 // 38
Appendix 4: Demand
reductions in the energy
savings scenario
To account for the different evolutions of demand profiles in Europe next winter (c.f. Overview of the power
system in winter 2023/2024 – Demand overview), decreasing the total consumption and peak demand of
each TSO in a homogeneous manner across Europe would not be the correct method to achieve similar
energy saving targets as adopted by European Council for winter 2022–2023. For the energy savings
scenario, ENTSO-E therefore took another approach, validated by TSOs, of reducing the total consumption
and peak demand values for each country individually. Adjustment depended on their expectations of
consumption and demand peaks (Figure 10) for the coming winter – the higher they were from historical
averages, the more it was reduced. Displayed in both figures below are the reduction values applied to each
TSO demand data in function of their estimations for next winter.
Figure 31: Reductions applied to total consumption data
Figure 32: Reductions applied to demand data