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1、Winter Outlook Report6 October 2022Helping to inform the electricity industry and prepare for the winter aheadSince last winter the world has fundamentally changed with the invasion of Ukraine by Russia.With this backdrop the ESO presents the Winter Outlook.Building on the Early View of Winter,this

2、document presents a more detailed view focusing on the upcoming winter in Great Britain.This Winter Outlook covers the period from 31 October 2022 to 31 March 2023.The data freeze date for this outlook was 22 September 2022.This Winter Outlook is developed in the context of unprecedented turmoil and

3、 volatility in energy markets in Europe and beyond and,as we stated earlier in the year,shortfalls of gas in continental Europe could have a range of knock-on impacts in Britain.Therefore,in this Winter Outlook in addition to our Base Case,we also set out scenarios to illustrate the implications sho

4、uld some of those risks to security of energy supplies materialise.Our central view remains,as set out in the Base Case,that there will be adequate margins(3.7GW/6.3%)through the winter to ensure Great Britain remains within the reliability standard1,although we expect there to be days where we will

5、 need to utilise many of the tools in our operational toolkit,including use of system notices2.Given the scale of uncertainty and risks associated with the current geopolitical situation we have developed a range of new tools,including:Publishing an early view of winter to help the market understand

6、 risks contracting to retain approximately 2GW of coal fired generation that would otherwise have closed and introducing an innovative Demand Flexibility Service to incentivise customers to reduce consumption at periods when margins are tight.Notwithstanding the mitigation measures noted above,it is

7、 highly likely that the wholesale price of energy(both gas and electricity)will remain very high throughout the winter outlook period3.While our Base Case assumes that capacity across all providers(generation,storage,interconnection etc.)is available in line with commitments secured under the Capaci

8、ty Market,we have also modelled a scenario whereby the energy crisis in Europe results in electricity not being available to import into Great Britain from continental Europe.This could be due to a combination of factors,including a shortage of gas in Europe(which in turn limits power generation in

9、Europe)and/or generation unavailability(e.g.,due to a high level of outages across the French nuclear fleet).We have also considered the scenario where there is a shortfall of gas available in Great Britain.Executive summary2 2Fintan SlyeDirector,Electricity System Operator1 The reliability standard

10、 is 3 hours Loss of Load Expectation(LOLE).Modelling shows the Base Case LOLE to be 0.2 hrs,well within the standard.2 These would include Electricity Margin Notices(EMNs),Capacity Market Notices(CMNs)etc.3 This will also lead to higher balancing costs as the costs of each required action are linked

11、 to the wholesale price of electricity as bid into the Balancing Mechanism or offered for trades on interconnectors.Executive summary3 3Our first illustrative scenario examines what would happen if there were no electricity imports from continental Europe4.In this scenario we would deploy our mitiga

12、tion strategies dispatching the retained coal units and our Demand Flexibility Service.By securing 4GW5through these actions,we would maintain adequate margins and mitigate impacts on customers.Our Demand Flexibility Service is new and innovative,and we have worked with suppliers,aggregators,industr

13、y,Ofgem and BEIS on the design to ensure it is ready for the winter and capable of delivering the required level of participation and response(2 GW+).It will launch on 1 November,and we are encouraging suppliers and aggregators to work with their customers to ensure the highest levels of engagement

14、and participation.We see particular potential from commercial organisations who can shift their load from peak hours and have had positive feedback from British companies on this.Without the Demand Flexibility Service,we would expect to see a reduction in margins.In this scenario on days when it was

15、 cold(therefore likely high demand),with low levels of wind(reduced available generation),there is the potential to need to interrupt supply to some customers for limited periods of time in a managed and controlled manner.However,we expect the mitigations outlined above to be effective.A second,more

16、 extreme scenario,looks at a hypothetical escalation of the energy crisis in Europe such that there is insufficient gas supply available in Great Britain(in addition to no electricity available to import from continental Europe as per above scenario).In the unlikely event that escalation of the situ

17、ation in Europe means that insufficient gas supply were to be available in Great Britain this would further erode electricity supply margins6potentially leading to interruptions to customers for periods.All possible mitigating strategies,including our new measures,would be deployed to minimise the d

18、isruption.Overall,this is likely to be a challenging winter for energy supply throughout Europe.We have taken extensive measures to try to mitigate the impacts for British consumers and expect that,under our base case,margins will be adequate.Nevertheless,there remain scenarios,driven principally by

19、 factors outside of Great Britain which could impact upon British electricity supplies.Plans are in place to ensure the impact is minimised and the overall security and integrity of Britains energy systems are protected.This document only covers the electricity outlook for the winter ahead;the Gas W

20、inter Outlook can be found here.For more information,you can email us at 4 The scenario assumes no electricity imports available from France,Netherlands and Belgium;1.2 GW imports from Norway;0.4 GW exports to Northern Ireland&Ireland.5 We expect the additional coal units to provide 2 GW and therefo

21、re the Demand Flexibility Service would need to provide 2 GW.6 Due to the curtailment of gas supplies to gas fired power stations in GB for example CCGTs etc.Executive summary3Base case5Winter scenarios 8Scenario 19Scenario 210Demand 11Supply 12Europe and interconnected markets14Market prices 18Appe

22、ndices 19Glossary214 4Executive summary2Base case5Winter scenarios 8Scenario 19Scenario 210Demand 11Supply 12Europe and interconnected markets14Market prices 18Appendices 19Glossary21ContentsThe de-rated margin of 3.7GW(6.3%)is similar to both our Early View of Winter and margins that we have had in

23、 recent years.The Base Case loss of load expectation(LOLE)is around 0.2 hours/year,which is within Reliability Standard of three hours per year set by Government.Our base case assumes electricity imports from Europe are available at times when we need them to meet demand,delivering in line with thei

24、r Capacity Market agreements,and that there is no disruption to gas supplies.Our base case does not assume any material reduction of consumer demand due to high energy prices.It does not include any of our mitigation measures such as coal contracts or the Demand Flexibility Service as we would not e

25、xpect to deploy them here.The chart in Figure 2 shows the de-rated margins included in previous Winter Outlook Reports and highlights how this years de-rated margin is similar to those in some recent winters(e.g.2015/16,2016/17 and 2021/22).If there are some tight periods this winter,we may need to

26、use our standard operational tools such as issuing Electricity Margin Notices(EMNs).Capacity Market Notices(CMNs)may also be issued.We expect there to be sufficient available supply to respond to these signals to meet demand.System margins are expected to be adequate in our Base Case.Notwithstanding

27、 this we expect there may be days when we need to use our operational tools.Figure 1.Supply margin in relation to generation capacity and demand5 5Base Case/System marginsFigure 2.Historic de-rated margin forecasts made ahead of each winter in the Winter Outlook Report(i.e.not out-turns)11 Includes

28、additional reserves(Supplemental Balancing Reserve and Demand Side Balancing Reserve SBR and DSBR)of 2.4 GW and 3.5 GW procured in 2015/16 and 2016/17 respectively.How our assessments are developedAs we get closer to winter,we move from an assessment that considers the winter as a whole,to one where

29、 we consider much greater temporal granularity on a week-by-week and day-by-day basis.This is our operational modelling.It includes actual plant outages,current weather patterns and price differentials that drive interconnector flows.It is based on transmission demand and generation,and therefore re

30、presents the perspective from our control room based on what the market is currently intending to provide(i.e.before use of our operational tools).Our operational modelling helps to identify when tight periods are most likely to occur,and to indicate when we may need to use our operational tools to

31、manage margins.These periods do not necessarily occur at times of peak demand.This view will change throughout winter,based on weather and changes to plant outages.Our Base Case operational view assumes imports from Continental Europe in line with Capacity Market agreements.It also assumes 750MW exp

32、orts to Ireland,which is based on long-term historic flows.However,we have observed that the flows on Irish interconnectors have become much more variable in recent years(see page 17)and could reverse direction in the event of tight periods in Great Britain,responding to market signals.Our Base Case

33、 operational view does not include potential market responses to higher demand or tighter conditions,such as power stations increasing their output levels for short periods.Nor does it include our mitigation measures for winter(i.e.the contingency coal contracts or the Demand Flexibility Service).Du

34、ring periods of low operational surplus,generators may be incentivised to reschedule planned outages by Capacity Market obligations or through revenue opportunity from higher market prices.ACS demand has historically always occurred between the first week in December and the first week in February,b

35、ut never during the Christmas fortnight or on a weekend.This winter we expectnormalised weather corrected transmission system demand to be met in the Base Case before using any operational toolsAverage Cold Spell(ACS)transmission demand to be met under our base case with utilisation of our operation

36、al tools(e.g.system notices)normalised peak transmission demand to occur in mid December or early January,based on our latest forecaststhe minimum operational surplus is currently projected to be lowest in mid-December when these forecasts are combined with current generator submissions.Our base cas

37、e operational view shows sufficient operational surplus for each week of winter.Figure 3.Day-by-day view of operational surplus for winter 2022/23(based on market data submissions from 22 September)6 6Base Case/Operational SurplusWe expect to have sufficient operational surplus throughout winter in

38、our Base Case,even when we consider the expected natural variation of demand,wind and outages.This winter we expectto have sufficient operational surplus throughout winter when routine tools such as margin notices are used tight margins to be likely throughout December to mid-January(excluding the C

39、hristmas period).Base Case/Credible rangeFigure 4.Range of outcomes for the daily operational surplus in our Base Case under different supply and demand conditions7 7Did you know?Figure 3 shows a particular view of generation and demand from which you can extract a single view of operational surplus

40、.However,a single view is not appropriate in assessing the potential risk due to natural variation in demand,wind,outages etc.The analysis behind Figure 4 considers a situation under typical conditions,using average weather conditions for demand,average availability for conventional generation and a

41、verage wind conditions when margin is tight.To explore the variation around this central view,we simulate many possible scenarios for weather,demand,conventional generation availability,wind generation output and interconnector availability and,for each of these scenarios,we calculate the daily surp

42、lus time series across the entire winter for that scenario.We do not include any actions that could be taken by the ESO.Figure 4 shows the forecast of daily surplus under our Base Case,with the shaded region representing the credible region within which the surplus can fluctuate.It is important to n

43、ote that,although on any given day the fluctuation can reach the lower bound(or dip below it),it is not credible that surplus will remain at the lower bound level for the entirety of the winter.We look at a day-by-day analysis,finding the daily credible range of values for the surplus.By credible we

44、 mean a 90%confidence bound for the day-by-day fluctuations in surplus between 5%and 95%The modelling here considers the natural variation of forced outages.Planned outages are assumed to be in line with those declared through REMIT at the time of the data freeze for this report.This modelling also

45、assumes that,for continental interconnectors,market forces will allow flow into GB of whatever interconnector capacity is available after unplanned outages.Winter scenarios Scenario 1:Reduced electricity imports from EuropeDue to risks created by the invasion of Ukraine by Russia,we have modelled a

46、scenario where the energy crisis in Europe results in electricity not being available to import into Great Britain from continental Europe at times when we need it.This could be due to a combination of factors,including a shortage of gas in Europe(which in turn may limit power generation in Europe)a

47、nd/or generation availability(e.g.due to a high level of outages across the French nuclear fleet).This scenario assumes no electricity imports from France,Belgium and the Netherlands for the whole winter.We continue to assume 1.2GW imports from Norway,with a total of 0.4GW sustained exports to North

48、ern Ireland and Ireland.In this scenario we would need to deploy our mitigation strategies,and so we assume the additional coal units(around 2GW)are available to dispatch by the ESO and the Demand Flexibility Service is deployed(delivering around 2GW).In addition to our Base Case,we have set out two

49、 scenarios to illustrate the risks and uncertainties for winter.These scenarios are not forecasts and they do not indicate an expectation or likelihood of these situations materialising.8 8Scenario 2:Reduced electricity imports from Europe combined with insufficient available gas supply in Great Bri

50、tainWe have also considered a situation where there is a shortfall of gas supply available in Great Britain.In addition to the assumptions of Scenario 1,we have chosen to model a two-week period in January in which around 10GW CCGTs are unavailable due to a gas shortage.We continue to assume the add

51、itional coal units(around 2GW)are available to dispatch by the ESO and the Demand Flexibility Service is deployed(delivering around 2GW).We have modelled this scenario to illustrate the impact on the electricity system if there is insufficient gas supply available in GB.For further details on the Ga

52、s Winter Outlook,please refer National Grid Gas Transmissions 2022/23 Winter Outlook Report.In this scenario we assume that we have no electricity interconnector imports from France,Belgium and the Netherlands(these are assumed to provide a de-rated capacity of 3.9GW in the Base Case).It is assumed

53、that we import 1.2GW from Norway and export 0.4GW to Northern Ireland and Ireland.In this situation we would deploy both the contingency coal contracts(around 2GW)and the Demand Flexibility Service(assumed around 2GW).This would result in a de-rated margin of 3.3GW(5.7%)with an LOLE of 0.5 hours/yea

54、r,broadly similar to our Base Case.Without sufficient take-up of the Demand Flexibility Service,we would still expect margins1to be within the Reliability Standard of three hours LOLE per year.In this case,there may be days when it was cold(therefore likely high demand),with low levels of wind(reduc

55、ed available generation),where there is the potential to need to interrupt supply to some customers for limited periods of time in a managed and controlled manner.However,our expectation is that our mitigation measures will be effective.Credible range for surplusFigure 6 shows the variation in opera

56、tional surplus for Scenario 1.It uses the same approach as outlined on page 8 to reflect the natural variation of demand,wind and outages,for the assumptions set out for this scenario.It assumes contingency coal contracts and the Demand Flexibility Service are deployed.The tightest periods are from

57、late November to January,where the daily margin often drops below zero.This does not mean that there will be interruption to supply.It means that it is more likely we will need to use our operational tools at these times(e.g.system notices).In deploying both the contingency coal contracts and the De

58、mand Flexibility Service,we would expect to mitigate the risk of supply disruption to customers.We expect to use coal contracts and our Demand Flexibility Service to maintain adequate margins if imports from Europe are not available when we need.Figure 5.Supply margin in relation to generation capac

59、ity and demand for Scenario 19 9Scenario 1/Reduced electricity imports from EuropeFigure 6.Range of outcomes for the daily operational surplus in Scenario 1 under different supply and demand conditions1Assuming 0GW from the Demand Flexibility Service results in a de-rated margin of 2GW/3.3%with an L

60、OLE of 2.4 hours/year.The shift in margin is less than the 2GW from DFS due to the way wind(which is variable)is represented as a single number through its Equivalent Firm Capacity(EFC)in the margin.The EFC value changes with system tightness even though we model its full variability in the LOLE cal

61、culation in the same way.In this scenario we assume the same assumptions as Scenario 1,but with an additional 10GW CCGTs unavailable for a two-week period in January1.These assumptions have been chosen to illustrate the potential impact on the electricity system if there was insufficient gas supply

62、in Great Britain.As this scenario only considers a specific,limited time period within the winter,we can only consider it using the modelling for our operational view.We are unable to provide a de-rated margin or LOLE value for this scenario.Credible range for surplusFigure 7 shows the variation in

63、operational surplus for Scenario 2.Coal contingency contracts(around 2GW)and the Demand Flexibility Service(around 2GW)are both assumed to be deployed.The impact of this is evident from the large negative surplus on the chart.The magnitude of this surplus is such that we would not expect there to be

64、 a sufficient response from the rest of the market to prevent interruptions to consumer supplies.Should this scenario happen,it may be necessary to initiate the planned,controlled and temporary rota load shedding scheme under the Electricity Supply Emergency Code(ESEC).In the unlikely event we were

65、in this situation,it would mean that some customers could be without power for pre-defined periods during a day generally this is assumed to be for 3 hour blocks.This would be necessary to ensure the overall security and integrity of the electricity system across Great Britain.All possible mitigatin

66、g strategies would be deployed to minimise the disruption.The extent of rota load shedding would depend on the number of CCGTs that are unavailable and the duration for which there is insufficient gas to meet power station demand.If there is insufficient gas in GB for power generation combined with

67、reduced electricity imports from Europe then this could erode security of supply margins.1010Scenario 2/Reduced electricity imports from Europe combined with insufficient gas supply in Great Britain Figure 7.Range of outcomes for the daily operational surplus in Scenario 2 under different supply and

68、 demand conditions1We have arbitrarily assumed 9 23 January 2023Demand/Normal peak demandThis winter we expectweather corrected peak transmission system demand(TSD)to be 45.3GW,based on assumptions in Table 1.minimum demand under normal weather conditions to be 20.7GW(assuming no interconnector expo

69、rts overnight).triad avoidance of up to 0.8GWWeather corrected peak demand for winter 2022/23 is expected to be lower than the previous winter,but higher than winter 2020/21 which was affected by COVID-19 restrictions.Weather corrected minimum demand is expected to be greater than last winter.Transm

70、ission connected power station demand600MWBase case interconnector exports to Ireland(at time of peak)750MWEmbedded wind capacity6.5GWEmbedded solar capacity13.1GWPumped storage(at time of peak)0GWDid you know?The ESO is currently consulting with the energy industry on proposals for a new Demand Fle

71、xibility Service to run between November 2022 and March 2023.This service will incentivise consumers and businesses to reduce or reschedule their electricity use away from peak times.The service will be offered by suppliers and aggregators to their customers.This could reduce peak demand below level

72、s shown in the forecast in Figure 8 by up to around 2GW.Figure 8.Historical and forecast normalised weekly peak winter demand11 Data is adjusted for interconnector export,historical data is weather corrected,forecast uses normal weather.1111Table 1.Assumptions for weather corrected peak TSD demandSu

73、pply/OverviewAdditional coal fired generationAt the request of the Department for Business,Energy and Industrial Strategy the ESO has signed three contracts with EDF,DRAX and Uniper to provide additional coal generation this winter.Note,Figure 9 excludes this additional coal capacity.These contracts

74、 will enable the ESO to directly instruct units at West Burton A,Ratcliffe and Drax to provide around 2GW additional de-rated capacity to support the system this winter if required.These contracts are only intended to be used after all other commercial options.This could be in response to a generati

75、on shortfall over an extended period of time or a short-term margin issue.This winter we expectlower available generator capacity than last year,driven by reductions in nuclear and coal capacity available over the wintergenerator reliability to be broadly in line with recent winters(Table 2)remainin

76、g coal-fired generation to potentially run more frequently due to high gas prices(but for overall levels of coal generation to remain low due to continued reductions in capacity levels)We currently expect sufficient levels of generation and interconnector imports to meet demand throughout the winter

77、 under our base case.Breakdown ratesThe assumed breakdown rates are based on historic data to reflect how generators performed against their planned availability during peak demand periods over the last three winters(see Table 2).For nuclear and biomass,the three-year rolling average has increased w

78、hen last winter was accounted for.For wind generation,we assume an Equivalent Firm Capacity(EFC)of 16%.Table 2.Breakdown rates by fuel type(based on a 3-year rolling average)1212Assumed Breakdown RatePower Station Fuel Type21/2222/23Coal11%10%CCGT6%6%Nuclear9%10%OCGT5%7%Biomass5%6%Hydro9%8%Wind(EFC)

79、17%16%Pumped storage3%3%Supply/Daily viewDid you know?Figure 9 shows a daily view of generation based on generator submissions of availability which is different to our calculation of de-rated margin for the winter on page 5.Our generation forecasts are based on published availability data broken do

80、wn to a half-hourly profile,to which we apply a breakdown rate for each fuel type,to account for unexpected generator breakdowns,restrictions or losses close to real-time.We currently expect sufficient levels of generation and interconnector imports to meet demand throughout the winter under our bas

81、e case.1313Figure 9.Daily generation availability by fuel type(based on market submissions and including breakdown rates)Europe and interconnected markets/OverviewDid you know?Figure 10 shows last years average interconnector flows at peak times,and during periods when operational surplus was below

82、2GW.These,alongside the expected prices(see page 16)are used to help inform our expectations for interconnector flows this year.The new NSL interconnector was operating at restricted capacity for part of last winter,but is now running at full capacity and is expected to import to GB especially at ti

83、mes of tight margins.Since last winter the ElecLink interconnector between GB and France has also come into service.This winter we expectforward prices,including peak prices,in GB to be below some of those in continental Europe across parts of the winter periodincreased exports to Continental Europe

84、 across much of the winter period driven by price differentials outside of times of system stressnet imports from Norway across the NSL interconnector across the winter period,particularly at peakimports into GB at peak times of tight margins or stress on the GB system.We dont expect interconnectors

85、 to be exporting to Europe if this would mean we were unable to meet GB demandMoyle and EWIC typically export from GB to Northern Ireland and Ireland during peak times,although at substantially less than maximum capacity due to high demand on the GB system.When operational surplus is particularly ti

86、ght,exports to Northern Ireland and Ireland are expected to reduce to zero,and could even provide imports to GB.We expect more exports across the interconnectors to continental Europe from GB than in past winters.Figure 10.Historical flows on the interconnectors for winter 2021/221414Winter 2021/22W

87、inter 2021/22Europe and interconnected markets/Peak flows analysis1.Physical capabilitiesInterconnector capability will be affected by the outages set out in the table below.The ongoing IFA outage is a result of a fire last autumn that led to reduced capacity,it is expected to come back to full capa

88、city by mid-December.Since last winter the ElecLink interconnector between GB and France has also come into service.Our assumptions around peak flow of electricity on the interconnectors depend on a number of factors.InterconnectorMaximum capacityPlanned outagesAvailable capacity during outageIFA2GW

89、21/10/21 30/10/221GW31/10/22 15/12/221.5GWIFA21GWn/aBritNed1GWn/aNemo Link1GWn/aEWIC500MWn/aMoyle500MWn/aNSL1.4GWn/aElecLink1GWn/a2.Capacity MarketInterconnectors have secured agreements in the Capacity Market(CM)in the T-31auction for 2022/23 as set out in Figure 11 below.While we expect increased

90、exports this winter to continental Europe,at times of tight margins or stress in GB(e.g.,when a Capacity Market Notice was issued)we would expect to see flows into GB.Our Base Case assumes interconnectors deliver in line with their CM obligations.We have also assessed the risks and uncertainties of

91、reduced imports from Continental Europe through our first scenario.Figure 11.Capacity Market agreements for interconnectors in Delivery Year 2022/231515Table 3.Planned interconnector outages at time of analysis1 Due to the suspension of the Capacity Market,a T-3 auction was run for delivery in 2022/

92、23 rather than a T-4 auctionEurope and interconnected markets/Peak flows analysis3.European forward pricesElectricity flows through the interconnectors are primarily driven by the price differentials between the markets.Quarter ahead forward prices for baseload electricity during winter 2022/23 in G

93、B are below those in the French and Dutch,but above those in the Belgian markets(see Figure 12).We therefore expect exports across the interconnectors to France and the Netherlands at times across the winter.Figure 13 shows forward prices for peakload electricity during winter 2022/23,in which GB pr

94、ices are ahead of those in the Dutch market but significantly below prices in France.This indicates we may see exports to France at peak times over the winter.However,should GB experience some tight/stress periods,we would expect GB prices to escalate and interconnectors to import in line with Capac

95、ity Market obligations.We dont expect interconnectors to export to Europe if this would mean we were unable to meet GB demand;they would import or float in this situation.4.Network access constraintsTransmission outages in the regions with interconnectors could cause power flow constraints resulting

96、 in disruption to interconnector flows,particularly in the South East.This has already been challenging to manage over the summer.5.Nuclear availability in FranceFigure 14 shows French nuclear outages for the winter ahead against historical outages.While outages are high at the beginning of the wint

97、er period they are expected to drop to around 5GW(around 8%of capacity2)by January 2023.We expect these outage levels,combined with high French market prices,to lead to exports to France across much of the winter.Figure 14.The impact on French nuclear capacity from planned outages in 2022/23 and act

98、ual outages in recent years3Figure 12.Winter 2022/23 electricity baseload Figure 13.Winter 2022/23 electricity peak forward prices116161Figure 12 uses data from Bloomberg.Peak forward prices were only given for GB and France in Bloomberg,therefore Figure 13 uses data taken from Argus,which includes

99、prices for the Netherlands.Lower liquidity means no peakload forward prices were available for Belgium.2Total French nuclear capacity is 61.4GW this winter.3 https:/www.edf.fr/en/the-edf-group/who-we-are/activities/optimisation-and-trading/list-of-outages-and-messages/list-of-outagesOverview of Euro

100、pean interconnectorsBased on forward prices for the 2022/23 winter products,we expect imports into GB at peak times from Norway,the Netherlands and Belgium under normal network operating conditions.We may see greater levels of export to France at peak times than in previous years.Despite day ahead b

101、aseload prices in France exceeding GB prices on a number of occasions last winter we saw only limited exports to France at peak last winter,as shown in Figure 15.Europe and interconnected markets/Historic flowsOverview of Irish interconnectorsDuring peak times through winter 2022/23,we expect a simi

102、lar proportion of exports to imports across the Moyle and EWIC interconnectors to Ireland.This may,however,be reversed during periods of high wind and system stress.Figure 16 shows examples of where market conditions and weather variance affected flows last winter.Last winter we saw imports at peak

103、times throughout the winter,despite day ahead baseload prices in France sometimes exceeding those in GBFigure 16.Daily peak time flows across the Irish interconnectors in winter 2020/21(positive MW values mean imports into GB)17171Figure 15 peak forward prices were not provided for weekend days so i

104、nterpolation was used to predict these values.Flows are out-turn values.Figure 15.Daily peak time flows across the continental interconnectors in winter 2021/22(positive MW values mean imports into GB)1Market prices/Winter viewDid you know?Traditionally power plants have bid into the Balancing Mecha

105、nism at prices which largely reflected the marginal cost of running the plant over that period.Capital and operational costs are generally recouped over a longer period through forward markets and/or long-term contracts.Last winter saw significantly increased prices over the year before and this win

106、ter has much higher market prices still,with baseload prices several times higher than last winter,although having dropped by a third from a peak of over 800/MWh at the end of August.We commissioned an independent review of the balancing market and have provided the report to Ofgem.This is available

107、 here.We are also enhancing our market monitoring activities this Winter.This winter we expectforward prices in GB to be higher than last year across the winter period(Figure 17).This is due to external pressures,particularly very high gas prices.days with tight margins to see spikes in the balancin

108、g mechanism.During periods of tight system margins,energy prices increase to reflect the scarcity of the resource,particularly when margin notices are issued.Forward wholesale electricity prices are significantly higher than last year.In addition,tight margin days are likely to see significant price

109、 spikes in the Balancing Mechanism.Figure 17 Historically traded quarter-ahead GB winter ahead forward electricity baseload prices for Winter 2020/21,Winter 2021/22 and Winter 2022/23 taken from Argus118181 The numbers shown in Figure 17 are historical traded prices not forecasts.Trading does not ta

110、ke place on weekends or bank holidays so these values have been interpolated.Appendix/Margin noticesElectricity Margin Notices(EMNs)are one of our operational tools to manage margins.They are based on operational margins which are calculated from transmission system demand and transmission system ca

111、pacity.Capacity Market Notices(CMNs)are issued automatically.They act as a notice for providers with Capacity Market agreements to deliver in line with their CM obligations for the indicated settlement period(s).If the CMN remains in place,the providers who do not deliver in line with their obligati

112、ons may be subject to penalties in accordance with the CM Rules.They are issued automatically and are not considered as one of our operational tools.They are based on Capacity Market margins which are calculated from whole system demand and whole system capacity(including Distributed Energy Resource

113、s(DER).While having similar intentions in stimulating a market response for tight periods,EMNs and CMNs should be considered as being part of two separate processes:the operational processes used by our control room to operate the system in real-time,and the CM penalty process.They serve different p

114、urposes,and are not part of the same sequential process.The ESO is working with Ofgem to improve the communication of system notices.This is an ongoing process and more detail will be published in due course.Electricity Margin Notices(EMNs)and Capacity Market Notices(CMNs)are used to highlight to ma

115、rket participants when margins are looking tight ahead of real-time.They are intended to stimulate a market response through,for example,additional generation being made available.They dont indicate that demand will not be met.1919There are a number of significant differences between the operational

116、 System Warning messages(such as EMNs)and Capacity Market Notices:1.Trigger-Capacity Market Notices are issued based on an automated system margin calculation using data provided by market participants,whereas System Warnings are manually issued by the ESO control room using engineering judgement ba

117、sed on experience and knowledge of managing the electricity transmission system.2.Threshold-Capacity Market Notices are triggered where the buffer between available generation and the total of forecast demand and Operating Margin falls below a threshold.The threshold is taken from the Capacity Marke

118、t Rules.System Warnings are triggered by varying volumes,for example an EMN may be issued where ESO expects to utilise a certain amount of its Operating Margin.3.Constraints-The Capacity Market Notice calculation does not take account of any transmission system constraints that may be preventing cap

119、acity from accessing the network.System Warnings however do take such constraints into account.4.Lead time-Capacity Market Notices are initially issued four hours ahead of when the challenge is foreseen.System Warnings can be issued at any time but we would generally expect to issue a first EMN at t

120、he day ahead stage.For more information about margins and margin noticeshttps:/ surplus analysisHow the operational surplus is calculated and usedFor the operational surplus analysis,we plan based on the operational data submitted to us.We are not just looking at the capacity provided via the Capaci

121、ty Market(a market tool that helps to set us up for winter),but also at the supply that is forecast to be available on a day-by-day basis.To do this we need to consider a more granular view of the winter.We consider a daily view as we get closer to real-time and start assessing the daily views in Au

122、gust ahead of the Winter Outlook Report publication in October.The Winter Outlook Report includes a daily view of margins for the winter,as well as information on the effects of variability and the likelihood of tight operational margins.The operational data includes information relating to planned

123、plant outages,the impact of weather(e.g.on wind and demand)and flows on interconnectors.As generators can also have unplanned outages,we also apply breakdown rates based on averages of the last 3 winters.In addition,we study the effects of variability of all relevant factors,particularly weather,ren

124、ewable resource and unplanned outages.The operational data may be different from the assumptions based on historic data/long-term averages used for the winter view of margin.The operational surplus also considers grid constraints and largest loss requirements.In the central daily view we use a low w

125、ind scenario,so the grid constraints play only a small part in the calculation.When we consider the credible range of values,grid constraints become more significant.The operational surplus helps us to identify when we might have tight periods.However,the operational data provided to us changes thro

126、ughout the winter.There may be some tight periods that are apparent a week in advance;others may not become apparent until much closer to real-time(e.g.day ahead or on the day itself).These assessments of security of supply are used to support decisions taken in operational timescales(e.g.whether to

127、 issue an EMN).Our operational surplus analysis represents the markets current intentions(i.e.based on market submissions before we take actions).This analysis is based on market submissions as of 22ndSeptember.It is a dynamic view that changes throughout winter and,as such,we will be providing regu

128、lar updates at the ESO Operational Transparency Forum.It provides insight on the periods when we may need to send market signals/use tools to ensure there is enough generation on the system to meet demand and contingency requirements.The periods of tightest margins do not necessarily occur at times

129、of peak demand but rather when supply is lowest relative to demand.2020Glossary2121Average Cold Spell(ACS)ACS methodology takes into consideration peoples changing behaviour due to the variability in weather(e.g.more heating demand when it is colder)and the variability in weather dependent distribut

130、ed generation(e.g.wind generation).These two elements combine have a significant effect on peak electricity demand.Balancing MechanismThe Balancing Mechanism is a tool which we use to balance electricity supply and demand.It allows participants to set prices for which they will increase or decrease

131、their output if requested by the ESO.All large generators must participate in the BM,whereas it is optional for smaller generators.Balancing Mechanism Unit(BMU)A unit which participates in the Balancing Mechanism.Baseload electricityA market product for a volume of energy across the whole day(the fu

132、ll 24hrs)or a running pattern of being on all the time for power sources that are inflexible and operate continuously,like nuclear.Breakdown rates A calculated value to account for unexpected generator unit breakdowns,restrictions or losses close to real time.Forecast breakdown rates are applied to

133、the operational data provided to the ESO by generators.Rates are based on how generators performed on average by fuel type during peak demand periods(7am to 7pm)over the last three winters.BritNedBritNed Development Limited is a joint venture between Dutch TenneT and British National Grid that opera

134、tes the electricity link between Great Britain and the Netherlands.It is a bi-directional interconnector with a capacity of 1,000MW.You can find out more at .Capacity Market(CM)The Capacity Market is designed to ensure security of electricity supply.It provides a payment for reliable sources of capa

135、city,alongside their electricity revenues,ensuring they deliver energy when needed.Capacity Market Notice(CMN)Based on Capacity Market margins which are calculated from whole system demand and whole system capacity.For more information about margins and margin notices see:https:/ Combined Cycle Gas

136、Turbine(CCGT)A power station that uses the combustion of natural gas or liquid fuel to drive a gas turbine generator to produce electricity.The exhaust gas from this process is used to produce steam in a heat recovery boiler.This steam then drives a turbine generator to produce more electricity.Cont

137、ingency coal contractsAt the request of the Department for Business,Energy and Industrial Strategy the ESO has signed three contracts with EDF,DRAX and Uniper to provide additional coal generation this winter.More details can be found here:https:/ flexibility serviceThe ESO is currently consulting w

138、ith the energy industry on proposals for a new Demand Flexibility Service to run between November 2022 and March 2023.This service will incentivise consumers and businesses to reduce or reschedule their electricity use away from peak times.The service will be offered by suppliers and aggregators to

139、their customers.More details can be found here:https:/ suppressionThe difference between our pre-Covid forecast demand levels and the actual demand seen on the system.We have not included any Covid-related demand suppression this winter.Glossary2222De-rated margin for electricityThe sum of de-rated

140、supply sources considered as being available during the time of peak demand plus support from interconnection,minus the expected demand at that time and basic reserve requirement.This can be presented as either an absolute GW value or a percentage of demand(demand plus reserve).The formula was revis

141、ed in winter 2017/18 to include distribution system demand,and in winter 18/19 to better account for interconnection.See our previous publications for further details(https:/ Energy Resources(DER)Resources connected to the distribution network which can generate or offtake electricity.East West Inte

142、rconnector(EWIC)A 500MW interconnector that links the electricity transmission systems of Ireland and Great Britain.You can find out more at 1000MW interconnector that links the electricity transmission systems of France and Great Britain.You can find out more at https:/www.eleclink.co.uk/.Embedded

143、generationPower generating stations/units that are not directly connected to the National Grid electricity transmission network and for which we do not have metering data/information.They have the effect of reducing the electricity demand on the transmission system.Electricity Margin Notice(EMN)Base

144、d on operational margins which are calculated from transmission system demand and transmission system capacity.For more information about margins and margin notices see:https:/ Firm Capacity(EFC)An assessment of the entire wind fleets contribution to capacity adequacy.It represents how much of 100 p

145、er cent available conventional plant could theoretically replace the entire wind fleet and leave security of supply unchanged.Float/FloatingWhen an interconnector is neither importing nor exporting electricity.Forward pricesThe predetermined delivery price for a commodity,such as electricity or gas,

146、as decided by the buyer and the seller of the forward contract,to be paid at a predetermined date in the future.Grid CodeThe Grid Code details the technical requirements for connecting to and using the National Electricity Transmission System(NETS).GW Gigawatt(GW)A measure of power.1GW=1,000,000,000

147、 watts.InterconnectorElectricity interconnectors are transmission assets that connect the GB market toContinental Europe and Ireland.They allow suppliers to trade electricity between thesemarkets.Interconnexion FranceAngleterre(IFA)A 2,000MW link between the French and British transmission systems.O

148、wnership is shared between National Grid and Rseau de Transport dElectricit(RTE).See more at https:/ FranceAngleterre 2(IFA2)A 1,000MW link between the French and British transmission systems commissioned in 2020.Ownership is shared between National Grid and Rseau de Transport dElectricit(RTE).See m

149、ore at https:/ factors The amount of electricity generated by a plant or technology type across the year,expressed as a percentage of maximum possible generation.These are calculated by dividing the total electricity output across the year by the maximum possible generation for each plant or technol

150、ogy type.Loss of Load Expectation(LOLE)LOLE is the expected number of hours when demand is higher than available generation during the year before any mitigating/emergency actions are taken but after all system warnings and System Operator(SO)balancing contracts have been exhausted.It is important t

151、o note when interpreting this metric that a certain level of loss of load is not equivalent to the same amount of blackouts;in most cases,loss of load would be managed by actions without significant impacts on consumers.The Reliability Standard set by the Government is an LOLE of 3 hours/yearMinimum

152、 demandThe lowest demand on the transmission system.This typically occurs overnight.MoyleA 500MW bi-directional interconnector between Northern Ireland and Scotland.You can find out more at www.mutual-.MW Megawatt(MW)A measure of power.1MW=1,000,000 watts.Nemo Link A 1GW HVDC sub-sea link between GB

153、 and Belgium.See more at https:/www.nemolink.co.uk/.North Sea Link(NSL)A 1.4GW HVDC sub-sea link from Norway to GB commissioned this October.See more at https:/ transmission demandThe demand seen on the transmission system,forecast using long-term trends and calculated with the effects of the weathe

154、r and the day of the week removed as appropriate.This takes into account the power used by generating stations when producing electricity(the station load)and interconnector exports.Normalised peak transmission demandThe peak demand seen on the transmission system,forecast using long-term trendsand

155、calculated with the effects of the weather and the day of the week removed asappropriate.This takes into account the power used by generating stations whenproducing electricity(the station load)and interconnector exports.Operational surplusThe difference between the level of demand(plus the reserve

156、requirement)andgeneration expected to be available,modelled on a week-by-week or day-by-day basis.It includes both notified planned outages and assumed breakdown rates for each powerstation type.OutageThe annual planned maintenance period,which requires a complete shutdown,duringwhich essential main

157、tenance is carried out.Peakload electricityA market product for a volume of energy for delivery between 7am and 7pm onweekdays.Pumped storageA system in which electricity is generated during periods of high demand by the use of water that has been pumped into a reservoir at a higher altitude during

158、periods of low demand.Reactive powerThe movement of energy across a network which is measured in MVAr.Different types of network assets and generators can generate or absorb reactive power.The flows of reactive power on a system affect voltage levels.REMITREMIT data is information provided by market

159、 participants to comply with Article 4 of Regulation on Wholesale Energy Market Integrity and Transparency(REMIT)Regulation(EU)1227/2011.GlossaryGlossary2424RenewablesElectricity generation from renewable resources,which are naturally replenished,such as sunlight or wind.Reserve requirementTo manage

160、 system frequency,and to respond to sudden changes in demand and supply,the ESO maintains positive and negative reserve to increase or decrease supply and demand.This provides head room(positive reserve)and foot room(negative reserve)across all assets synchronised to the system.Rota load sheddingSch

161、eduled disconnection and reconnection of electricity supplies in an electricity supply emergency,as set out in the governments Electricity Supply Emergency Code(ESEC).Seasonal normal weatherThe average set of conditions we could reasonably expect to occur.We use industry agreed seasonal normal weath

162、er conditions.These reflect recent changes in climate conditions,rather than being a simple average of historic weather.Short Term Operating Reserve(STOR)At certain times of the day,we may need access to sources of extra power to help manage actual demand on the system being greater than forecast or

163、 unforeseen generation unavailability.STOR provides this reserve.System Operator Transmission Code(STC)The System Operator Transmission Owner Code defines the relationship between the Transmission Owners(TOs)and the ESO.Technical capabilityThe capacity of connected plant expected to be generating in

164、 the market,based on the Capacity Market auctions and another sources of market intelligence,but not taking any account of potential breakdown or outage.Transmission System Demand(TSD)Demand that the ESO sees at grid supply points,which are the connections to the distribution networks.Triad avoidanc

165、e When demand side customers reduce the amount of energy they draw from the transmission network,either by switching to distributed generation sources,using on-site generation or reducing their energy consumption.This is sometimes referred to as customer demand management but we refer here to custom

166、er behaviour that occurs close to anticipated Triad periods,usually to reduce exposure to peak time charges.TriadsThe three half-hourly settlement periods with the highest electricity transmission system demand.Triads can occur in any half-hour on any day between November and February.They must be s

167、eparated from each other by at least ten days.Typically,they take place on weekdays around 4.30 to 6pm.Underlying demandDemand varies from day to day,depending on the weather and the day of week.Underlying demand is a measure of how much demand there is once the effects of the weather,the day of the

168、 week and distributed generation have been removed.VoltageUnlike system frequency,voltage varies across different locations on the network,depending on supply and demand for electricity,and the amount of reactive power in that area.Broadly,when electricity demand falls,reactive power increases and t

169、his increases the likelihood of a high voltage occurrence.Weather corrected demand The demand expected or out-turned with the impact of the weather removed.A 30-year average of each relevant weather variable is constructed for each week of the year.This is then applied to linear regression models to

170、 calculate what the demand would have been with this standardised weather.Western High Voltage(HVDC)Link(WLHVDC)The Western Link uses DC technology to reinforce the UK transmission system and move electricity across the country in very large volumes between Hunterston in Scotland and Deeside in Nort

171、h Wales.Winter period The winter period is defined as 1 October to 31 March.2525Join our mailing list to receive email updates on our Future of Energy us with your views on the Winter Outlook Report at: and we will get in touch.You can write to us at:Energy InsightsElectricity System OperatorFaraday

172、 HouseWarwick Technology ParkGallows HillWarwickCV34 6DAElectricity System Operator legal noticePursuant to its electricity transmission licence,National Grid Electricity System Operator Limited is the system operator of the national electricity transmission system.For the purpose of this outlook do

173、cument,the terms“we”,“our”,“us”etc.are used to refer to the licensed entity,National Grid Electricity System Operator Limited.National Grid Electricity System Operator Limited has prepared this outlook document pursuant to its electricity transmission licence in good faith,and has endeavoured to pre

174、pare this outlook document in a manner which is,as far as reasonably possible,objective,using information collected and compiled from users of the electricity transmission system together with its own forecasts of the future development of those systems.While National Grid Electricity System Operato

175、r Limited has not sought to mislead any person as to the contents of this outlook document and whilst such content represent its best view as at the time of publication,readers of this document should not place any reliance on the contents of this outlook document.The contents of this outlook docume

176、nt must be considered as illustrative only and no warranty can be or is made as to the accuracy and completeness of such contents,nor shall anything within this outlook document constitute an offer capable of acceptance or form the basis of any contract.Other than in the event of fraudulent misstatement or fraudulent misrepresentation,National Grid Electricity System Operator Limited does not accept any responsibility for any use which is made of the information contained within this outlook document.