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1、Hydrogen Production from Thermal Electricity Constraint ManagementNational Grid ESO&National Gas TransmissionA Network Innovation Allowance funded project2Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints1Executive summary 2Introduct

2、ion and approach 6What are thermal constraints?8Use of hydrogen to manage thermal constraints 14Support mechanisms 24Mapping tool 42Conclusions and next steps 44References and glossary of terms 48Appendix 1 Commercial model 52Appendix 2 Modelling constraints 58Appendix 3 Modular design 66Appendix 4

3、Injecting Hydrogen into the Gas Networks 74Appendix 5 Mapping tool 82ContentsSupport mechanismsMapping toolConclusions and next stepsAppendices2Executive summaryExecutive summaryArup,in partnership with National Grid Electricity System Operator(ESO)and National Gas Transmission(NGT),has investigated

4、 the technical,commercial,and economic case for electrolytic hydrogen production facilities to help manage thermal constraints on the electricity transmission system.As the electricity system has decarbonised over the last decade,large-scale renewables have connected onto the electricity transmissio

5、n network and significant further renewables are expected to connect,to achieve a net zero electricity system by 2035.A substantial amount of renewable generation is expected to come online in the north of the UK whereas the bulk of energy demand is likely to continue to be in the South.The electric

6、ity transmission network needs to be substantially reinforced to enable these power flows,with delivery taking at least 5-10 years for large transmission infrastructure upgrades given consenting and construction timeframes.In the interim,when there is significant renewable generation,regional power

7、flows can sometimes exceed the thermal capacity of electricity transmission assets,requiring the ESO to take action to maintain safe system operation.At present,the ESO will pay to turn down(constrain)renewable generation and to dispatch alternative(mostly fossil fuel)generation closer to the demand

8、.The cost of these thermal constraint actions,which are passed onto consumers through energy bills,have increased significantly and in 2022/23 totalled 1.5 billion.With thermal constraints on the transmission network expected to increase further over the next decade or more before being eased by net

9、work reinforcement,there is a strong case for alternative solutions to thermal constraint management in the next 10-20 years.Hydrogen production facilities could reduce regional thermal constraints by utilising electricity from renewables that would otherwise need to be constrained.The low carbon hy

10、drogen generated can then be used as an alternative to fossil fuels in industry,heating or transport to help decarbonise the UK economy.Introduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints3The technical and commercial viability of using hydrogen product

11、ion to manage thermal constraints on the electricity networkThis innovation project has determined that it is technically viable to operate a hydrogen production facility in a manner that allows it to support management of thermal constraints on the electricity network.Electrolysers,which use electr

12、icity to derive hydrogen(and oxygen)are able to react fast enough with response times varying between 10 seconds and 20 minutes,depending on the type of electrolysis technology.Electrolysis facilities in a hot or warm state can respond more rapidly than facilities that are completely cold i.e.restar

13、ting.However,from a commercial perspective,electrolysers are high capital cost equipment.Therefore,a hydrogen production facility would normally seek to maximise utilisation to recover initial investment costs i.e.running at or near to full capacity as much as possible.Thermal constraints will not b

14、e present on the electricity network for much of the time,even in very constrained areas reflecting the intermittent nature of renewable generation.This makes the commercial case for a hydrogen facility seeking to manage constraints challenging,even if the cost electricity during the times of constr

15、aints was very low or zero(or even negative prices).This project has found that under current market arrangements there is not a sufficiently strong commercial incentive for hydrogen production facilities to play an active role in thermal constraints management without additional support.An addition

16、al challenge is that currently most hydrogen customers,industrial and transport offtakers,require a steady or predictable hydrogen output profile.A hydrogen production facility that supports thermal constraints management will have a more variable production profile as it maps its production up and

17、down.Such a facility therefore either needs access to hydrogen storage(likely to be prohibitively expensive for more than small quantities)or an offtaker that can accept a varying production profile.This is most likely to be a connection to a gas network.Although some 100%hydrogen networks are plann

18、ed,during the timeframe when a facility such as this is likely to be required to manage thermal constraints(the next 10-15 years),blending into the existing gas network is likely to be the most feasible option.The case for a facility blending hydrogen into the gas network will depend on network loca

19、tion and will need to be worked out on a case-by-case basis.Through our investigations,we have found that there is a viable commercial case for hydrogen production facilities to help manage thermal constraints providing:There is an alternative electricity supply to draw upon when constraints are not

20、 available,to firstly increase utilisation and thus revenue generated from the electrolysers and secondly ensure electrolysers are warm enough to ramp up rapidly when required.This may mean hydrogen production facilities drawing energy from the grid during non-constrained times;There is access to a

21、flexible offtaker.The most likely available flexible offtake option is blending into the gas network either as a sole or secondary offtaker;and A support mechanism is in place that will incentivise hydrogen production facilities to connect in the right locations and maintain operational profiles tha

22、t will contribute to the management of thermal constraints in the electricity network.The design of this mechanism is critical to the commercial case and our proposed solution to a support mechanism is summarised below.Support mechanismsMapping toolConclusions and next stepsAppendices4The proposed c

23、ommercial solution:contract mechanismsToday,decisions over the location of hydrogen projects are a triangulation between multiple factors.This includes the location of the demand offtake,available water resources and an available electricity network grid connection that is able to provide low carbon

24、 electricity and/or availability of renewable generation that can be directly connected to the facility.Current electricity market arrangements,which are based on a single national power price,do not provide strong incentives to hydrogen production facilities to locate in areas where the electricity

25、 network is thermally constrained.Whilst a hydrogen production facility could provide demand response services during periods of constraints potentially via participation in the Balancing Mechanism and through bidding for existing ancillary services,this presents considerable commercial uncertainty.

26、The four contract options that have been considered are:Further,a hydrogen production facility needs to ensure that during periods where there are no thermal constraints on the electricity network,they do not expose themselves to additional price risk compared to if they were in a long-term Purchase

27、 Power Agreement(PPA).Under current arrangements,the investment risk lies with the hydrogen production facility and creates challenges for the competitiveness of the hydrogen produced in this way compared to alternative business model approaches.This project has looked at four potential contract mec

28、hanisms that would aim to limit the market risk exposure of hydrogen production facilities and ensure they are remunerated fairly for the whole system benefits they can provide to the electricity system.12a2b3Option 1:a utilisation payment(/MWh)which is received for every 30-minute settlement period

29、 that a facility provides a demand turn up in response to thermal constraints.Option 2b:this option is as per 2a however the payment does not vary seasonally between Autumn/Winter and Spring/Summer Option 3:a fixed payment(m)to be available and provide a response during periods of thermal constraint

30、s.Option 2a:an availability payment(kW),similar to the capacity market,whereby a facility is paid to be available for a defined period and then a utilisation payment(/MWh)for every 30-minute settlement period that a facility provides a demand turn up in response to thermal constraints.The utilisatio

31、n payment would be lower than option 1 to reflect that the facility also receives an availability payment.Under this option the availability and utilisation payments are higher in Autumn/Winter than Spring/Summer to reflect that constraint costs are likely to be more impactful in terms of system cos

32、t in Autumn/Winter than Spring/Summer.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints5Recommendations and next stepsThis project has found that with the right commercial arrangements in place hydrogen production facilities could su

33、pport thermal constraints management.For the business model to be viable,a production facility would utilise this contract mechanism as a secured revenue stream and would otherwise participate as normal in the market to secure low-cost electricity during periods in which thermal constraints are not

34、forecast to occur,for example participation in the balancing mechanism and procurement of electricity purchased in the spot power market and/or via a PPA.Each of the options provide a different allocation of risk and reward between the ESO(and consumers)and a production facility.Option 1 provides ce

35、rtainty over the price that will be received however does not provide certainty over the volume and the ESO will only be required to pay during periods of constraints.Whereas under options 2a and 2b there is certainty over the price and some volume certainty,however,there remains some volume uncerta

36、inty as the utilisation payment will only be paid during periods of constraints.This results in a more balanced allocation of risk between the ESO and the facility.Under Option 3,depending on the actual constraints,the risk allocation may see the ESO over pay if constraints are much lower than forec

37、asted or the facility incurring additional costs to run for more periods than expected if constraints are higher than forecasted.Under all options,the value of the contract(s)will be lower than the cost of constraining the renewables to ensure that the contract(s)delivers value for consumers and a w

38、ider whole system benefit.For all contract options the expectation is that,to create an investable business model,the contract would need to be secured ahead of a Financial Investment Decision(FID)on the hydrogen production plant which is likely to be three to four years ahead of commercial operatio

39、ns.It will also be critical for the production facility to receive a transmission or distribution connection that aligns with these timelines.More work will be required to understand what these arrangements may look like,to explore this further the following next steps are recommended:As part of the

40、 Constraints Collaboration Project,the ESO should further develop the contract details and engage with Ofgem on whether this could be delivered within the existing regulations.A full cost benefit analysis and socio-economic welfare should be undertaken to understand the range and the scale of benefi

41、ts that can be delivered through the contract and the impact on consumer bills.As part of this,an assessment should be undertaken of how competitive a hydrogen production facility would be compared to other technology types based on the detailed contract elements.Engagement with the Department for E

42、nergy Security and Net Zero(DESNZ)to consider whether the hydrogen production business models can be allocated in line with a constraints contract from the ESO.The whole system benefits that a facility that can contribute to management of thermal constraints should also be recognised in the hydrogen

43、 blending arrangements.As the blending arrangements are developed further steps could be taken to favour a hydrogen production facility that is providing genuine whole system benefits when blending capacity is allocated.A decision on blending on the transmission network should be taken as soon as po

44、ssible,for larger facilities the higher pressure network offers higher injection capacity and flexibility.Support mechanismsMapping toolConclusions and next stepsAppendices6Introduction and approachIntroduction and approachThe ESO manages the flow of electricity across the GB transmission network fr

45、om where electricity is generated to where it is consumed 24 hours a day,365 days a year.Whilst balancing the system,they are required to maintain the system within defined limits for safety purposes.The transmission assets that carry this electricity around the network have physical limitations on

46、how much electricity can be carried.To safely operate the system,these limits must be prevented from being reached,or even exceeded,to prevent a loss of supply across the network.In these circumstances,the ESO will take action to reduce(curtail)generation and then redispatch alternative generation i

47、n areas where the network limits have not been reached or exceeded.The costs associated with these actions are recovered within consumer bills as thermal constraint costs and results in a significant carbon system operability impact.Electricity transmission constraints are increasing year on year an

48、d are predicted to continue increasing.This is driven by the increase in new renewable generation,particularly offshore wind,connecting onto the network to achieve the UK Governments policy ambitions of 50GW of offshore wind by 2030 and a net zero electricity system by 2035.The majority of the offsh

49、ore wind is expected to connect in the North of the country,whereas the majority of demand is in the South.By 2030 some areas of the network will see peak electricity flows which are 400%greater than the current boundary capacity.The costs of managing thermal electricity constraint,by paying renewab

50、le generators in constrained areas to turn down,is expected to be between 500m and 3bn annually.1Constraints can be addressed through transmission network reinforcement.The transmission network operators,National Grid Electricity Transmission(NGET),SP Energy Networks and SSEN Transmission,have been

51、investing in their networks in line with the Holistic Network Design(HND)2.This investment is supported by Ofgems Accelerating Strategic Transmission Investment(ASTI),which is driving the delivery of a programme of network reinforcement projects by 2030.However,delivering network investment can be a

52、 lengthy process,given consenting and construction timeframes.As a result,there are limited near term levers to manage these increasing constraint costs and,with the volume of constraints currently on the grid,the ESO is looking for shorter term solutions to help manage the costs of constraints on b

53、ehalf of consumers.Executive summaryWhat are thermal constraints?Use of hydrogen to manage thermal constraints7The proposed solutionIn April 2023,Arup,working alongside the ESO and NGT,began an investigation into the possible role that electrolytic hydrogen production could play in reducing the impa

54、ct of thermal constraints on the electricity transmission network.Electrolytic hydrogen is produced through a chemical process,known as electrolysis,that uses an electrical current to separate the hydrogen from the oxygen in water.To be considered green,or low carbon,the electricity needs to be from

55、 a renewable source.Green or low carbon hydrogen has been identified as a key opportunity for decarbonising the UK Economy.The UK Governments Powering Up Britain3 policy included low carbon hydrogen at its core.This Network Innovation Allowance project has investigated the technical,commercial,regul

56、atory and economic case for electrolytic Hydrogen Production Facilities(HPFs)providing constraint management services to an electricity system operator.ScopeIn exploring the role that electrolytic hydrogen production could have on reducing the impact of thermal constraints,Arup completed multiple wo

57、rkstreams,each exploring the feasibility of an HPF in managing thermal constraints from different perspectives.Energy modelling a energy system model was produced to examine the potential size of constraints in the most constrained boundaries between 2023 2040.The model took into consideration the i

58、mpact of changing boundary capabilities over time as network reinforcements are delivered and the subsequent impact on power flows and operating profiles of generators,to provide a view of future constraint profiles and costs.Commercial analysis the commercial viability of an HPF utilising constrain

59、ed electricity was explored by outlining the commercial model of an HPF that uses thermal constraints energy and calculating the Levelised Cost of Hydrogen(LcoH)that a plant using thermal constraints energy could achieve.Technical analysis the ability of an electrolysis facility to respond to therma

60、l constraints was examined.This included exploring some modular HPF design concepts to assist in determining the characteristics and constraints of archetype plant designs.Offtakers the feasibility of hydrogen produced from the hydrogen production facilities being blended into the gas grid as well a

61、s any other alternative off-takers for the hydrogen produced.This took into consideration technical blending requirements as well as commercial and regulatory considerations.Location the potential location of production facilities was considered using a mapping tool.This looked at multiple factors,f

62、or example,the electricity system boundaries,location of electricity and gas grid and availability of water resources.Support mechanismsMapping toolConclusions and next stepsAppendices8What are thermal constraints?What are thermal constraints?Electricity system constraintsThe GB electricity transmis

63、sion system is used to transport electricity from where it is generated at scale to where demand users are located.As shown in Figure 1,the transmission system comprises of 400kV and 275kV levels in England and Wales(whereas in Scotland it comprises of 400kV,275kV and 132kV levels)and spans the brea

64、th of Great Britain.Currently,power flows are typically from the North(where there is significant generation)to the South(where large demand centres are located).As the electricity transmission system operator,it is the ESOs responsibility to ensure that the transmission system is balanced on a minu

65、te by minute,second by second basis,taking actions as a residual balancer if supply and demand are imbalanced.The GB electricity transmission system is used to transport electricity from where it is generated at scale to where demand users are located.Executive summaryIntroduction and approachUse of

66、 hydrogen to manage thermal constraints9Support mechanismsMapping toolConclusions and next stepsAppendices10Figure 1 GB electricity transmission system boundaries National GridWhat are thermal constraints?Executive summaryIntroduction and approachUse of hydrogen to manage thermal constraints11The el

67、ectricity transmission system is broken into different zones,separated by boundaries where power flow limitations may be encountered.The GB transmission system boundaries are shown in Figure 1.Electricity system constraints occur when the required electricity flow is greater than the capacity of a t

68、ransmission line across the boundary.To manage these constraints,the ESO will curtail and re-dispatch generation.As greater renewable generation connects to the network,these constraint costs increase to a point whereby the generation connecting,for example in Scotland,is requested to turn down thei

69、r generating output,as the power cannot flow across the boundary.This results in system costs,which are passed onto consumers,and in many instances fossil fuel generation is required south of the boundary.The costs of managing thermal constraints have grown significantly over the last 6 years,rising

70、 from 309m in FY2017/2018 to 1.5bn in FY2022/23 as shown within Figure 2.This has been driven by the increase in renewable generation,mainly in Scotland and Northern England,which the network was unable to then flow to demand centres in other areas of Great Britain.As identified within Figure 3,ther

71、e were significant constraints throughout 2022/23 across all boundaries.On days where there were constraints,on average,the cost of thermal constraints was 4.6m per day,with a maximum constraint cost of 62.1m experienced on 20th July 2022.By 2030,some areas of the network will see peak power flows t

72、hat are 400%greater than current boundary capability.As a result,the GBs thermal constraint costs are forecasted to reach between 500m to 3bn annually by 20304.These costs will be passed onto consumers through their energy bills.Therefore,there is a requirement to find alternative solutions,whilst n

73、etwork reinforcements are delivered,to minimise the cost of managing constraints on behalf of consumers.Figure 3 Daily thermal constraints costs for FY23(all boundaries)Figure 2 Annual thermal constraints costs from FY18 to FY2302004001,0006001,2001,6008001,400 m3094485461,1341,5042017/182020/212022

74、/232018/192021/224202019/20010203040506070 mJan2022Jan2023FebMarAprFebMarAprMayJunJulAugSepOctNovDecSupport mechanismsMapping toolConclusions and next stepsAppendices12Future constraints modellingAs part of this project,Arup have modelled future network constraint costs using PLEXOS Energy Modelling

75、 Software.Arup developed a model of the GB electricity system,which took into consideration the known network developments considered within the HND and the latest Electricity Ten Year Statement(ETYS)on future power flows and the operating profiles of generators.The cost of thermal constraints inclu

76、des two components:the cost of curtailing electricity generators due to thermal constraints behind the boundary and the cost of re-dispatching electricity generators to balance the resulting energy imbalance in front of the boundary.Based on our analysis of the ETYS 2022 and discussions undertaken w

77、ith the ESO,Arups analysis focused on the flows across Scotland and Northern England.Arup has modelled the constraint profile and cost of thermal constraints across boundaries B4,B5,B6,B7 and B8 between 2030 and 2040.These are the boundaries where the majority of constraints are expected going forwa

78、rd,as the planned network reinforcements would not be adequate to completely offset the steep increase in renewable generation deployment(mostly offshore wind).Figure 4 Total constraint cost between 2030 and 2040 for boundaries B0 to B8Figure 5 B0-B4 constrained volume profile 2035203020312032203320

79、3402004006008001,0001,200Constraint Costs(m)203520362037203820392040B0-B4B5B6B7-B801,000MW2,000Jan2025Dec2025NovOctSepAugJulJunMayAprMarFeb3,0004,0005,0006,0007,0008,0009,00010,000What are thermal constraints?Executive summaryIntroduction and approachUse of hydrogen to manage thermal constraints13Be

80、nefit of using demand to manage constraintsThis analysis has found that there is a benefit in using renewable electricity that would have otherwise been curtailed to deliver green hydrogen.Assets that are called by the ESO to resolve thermal constraints usually add a premium on prices when called up

81、on at relative short notice in the balancing mechanism(BM).The main system benefit identified for a hydrogen production facility is the saving achieved by removing the premium on prices that can be achieved by generators in the Balancing Mechanism.The analysis indicates that this premium for CCGT as

82、sets(which is the predominate technology currently used by the ESO to provide flexibility)is around 30%.This was derived by analysing historical system offer prices of CCGTs.For wind assets this is quite varied,and it is based on the assumptions listed in the“Market Power”scenario(see appendix 2).Ad

83、ding a hydrogen facility(or any other demand asset)acts to increase demand in a constrained region,meaning that this demand could be removed from the balancing mechanism and moved into the open market,such as the day-ahead market,because it is known upfront.With sufficient competition,generators sho

84、uld come forward and offer to meet this known increase in demand,again bringing forward generation from the balancing market to the open market.Bringing forward demand and supply to the open market and away from the balancing market creates savings by reducing the added price premium that generators

85、 would otherwise add when offering their units in the balancing market.As seen in Figure 4,the highest constraint costs and volumes are observed in B4 across the modelling horizon.B6 is the second highest until 2035.Post 2035,B7 and B8 costs surpass B6 costs.Following network reinforcements,driven b

86、y the HND and the ASTI framework,there is a slight dip in costs between 2030 and 2035.However,a significant increase in renewable generation connected above B4 leads to a jump in costs post 2035,mainly driven by an increase in offshore wind capacity.Similar to the observations presented on cost,2035

87、 and 2036 are the years with both the highest number of hours and the highest volume of constrained renewable generation in B0-B4.The increase in B7-B8 costs is mostly affected by increased renewable generation in Scotland,combined with additional generation added in the North of England.As a result

88、,there is an opportunity to explore how thermal electricity constraints could be used to produce low carbon hydrogen,rather than paying generators to turn down.Using hydrogen production to manage thermal constraints could have a positive impact on consumer bills,as well as provide a whole system ben

89、efit.Support mechanismsMapping toolConclusions and next stepsAppendices14Benefits of managing constraints through demand management worked exampleThe following provides a theoretical explanation of the benefits of managing constraints through demand management would work in practice.Please note that

90、 this is only an indicative scenario with illustrative numbers,and it should not be used as a quantification of savings but rather as a simulated example of how savings would be achieved in a single half hour.Further details of our analysis on avoided premium in the context of proposed contract mech

91、anism designs is detailed in the Support Mechanisms section.For the basis of this theoretical explanation,the following assumptions are made:In the example scenario where there is no Hydrogen facility present,the following occurs:CCGT A and Wind Farm are successful in the Day-Ahead(DA)auction which

92、clears at 90/MWh.This means both assets will receive 90/MWh to deliver 500MWh.CCGT-B is not successful as the clearing price is above its Short Marginal Cost(SRMC).This means that only CCGT-A and Wind Farm sell energy in the Day-Ahead auction.In real time the ESO has to instruct the wind farm to not

93、 generate due to a thermal constraint.The wind farm is eligible for support which is equal to 54/MWh,which they receive only if they generate.In reducing its output,the wind farm would theoretically need to recover the money of the lost subsidy and therefore bid in the BM at a price equal to the los

94、t subsidy of 54/MWh.As the Wind Farm is being constrained off behind the thermal constraint an energy imbalance results in front of the constraint.To resolve the imbalance,the ESO calls on CCGT-B in the Balancing Mechanism to generate 500MWh.CCGT-B offers its output in the BM at 130/MWh including a

95、premium of 30%on its actual SRMC.The actions above results in a total cost of 182,000 for this half hour for the consumer in this example.In the case where the Hydrogen facility or any other flexible asset is present,the following occurs:An additional 500MWh of flexible demand coming from the hydrog

96、en facility will participate in the DA auction.As a result,CCGT-A,Wind Farm and CCGT-B will all be successful in the auction.CCGT-B will now be the marginal unit clearing the auction at 100/MWh.The ESO does not need to take any action as the flexible demand facility will use the electricity that in

97、the event of a thermal constraint would have otherwise needed to be curtailed whilst the dispatch of CCGT-B has already been secured at DA stage to meet the additional demand.However,in this scenario the Wind Farm will still be paid 54/MWh as based on their subsidy scheme,the wind farm is paid a fix

98、ed amount of 54 for every MWh it generates and exports to the grid.The total cost of the actions described above would be 177,000 resulting in a saving of 5,000 for the half-hour.In essence this saving comes from the avoided premium that CCGT-B would charge if it had to be dispatched with short noti

99、ce in real time.What are thermal constraints?Executive summaryIntroduction and approachUse of hydrogen to manage thermal constraints15The charts below show the actions taken by the ESO in this example:Figure 6 Actions without H2 Facility5Figure 8 Actions with H2 facilityFigure 7 Price per MWh withou

100、t H2 facilityFigure 9 Price per MWh with H2 facility500500-500500500500Volume procured in DA auction(MWH)Volume procured in real time(MWH)Output(MWH)500500500500500500Volume procured in DA auction(MWH)Volume procured in real time(MWH)Output(MWH)Price received in auction(/MWH)Subsidy paid(/MWH)Cost p

101、aid in BM including oppurtunity cost(/MWH)00000909013054Price received in auction(/MWH)Subsidy paid(/MWH)Cost paid in BM including oppurtunity cost(/MWH)0000010054Figure 10 Total system cost with and without the H2 facility single half hour(illustrative)77,00050,00050,00045,00065,00072,000Total cost

102、(no H2 facility)Total cost(with H2 facility)182,000177,000CCGT ACCGT BWind farmSupport mechanismsMapping toolConclusions and next stepsAppendices16Use of hydrogen to manage thermal constraintsUse of hydrogen to manage thermal constraintsLow carbon hydrogen productionElectrolytic hydrogen is produced

103、 by using electricity to separate water(H2O)into hydrogen(H2).For this hydrogen to be low carbon,the electricity used must come from renewable sources such as wind and solar.As shown in Figure 11,this hydrogen can then be used in multiple sectors:In industrial processes,as a feedstock,or,in industri

104、al heating,as a low carbon alternative to natural gas;In transport,in hydrogen fuel cell electric vehicles(FCEV)or hydrogen combustion vehicles.In theory,hydrogen can be used in all road vehicles,in practice however it is more likely to be used in larger vehicles that need to travel long distances s

105、uch as HGVs,heavy industrial equipment buses,trains(where lines are not electrified);In shipping and aviation,either as hydrogen or as a key component in the manufacture of sustainable fuels;In domestic and commercial heating,as an alternative to natural gas;and In power generation,hydrogen could be

106、 used to generate electricity during peak times,effectively acting as a large battery,generated at times of high renewable production,then used to provide power during periods of low renewable electricity production and high demand.Hydrogen can be transported either through pipelines or tube trailer

107、s from the production location to the end user.Pipelines provide the most cost-effective way of transporting hydrogen at scale.In the shorter-term,up to 20%hydrogen volume can be blended into the existing natural gas network,with minimal changes to the network or gas appliances.An advantage of hydro

108、gen is,like natural gas,that it can be stored in large quantities in geological storage helping to balance the energy system.Executive summaryIntroduction and approachWhat are thermal constraints?17The UK Government sees hydrogen as an important decarbonisation option,as the UK delivers upon its net

109、 zero commitment by 2050.The Government has set an ambition to have 10GW of low carbon hydrogen by 2030.6 To support this ambition,the Government have introduced the hydrogen production business model(HPBM)to support the development of hydrogen as a clean and low-cost energy technology.The HPBM prov

110、ides ongoing revenue support to projects by covering the difference between the cost of making hydrogen and the price they can receive for the hydrogen,known as a strike price,over a 15-year period.To date,11 projects have been awarded CapEx and OpEx funding in the first Hydrogen Allocation Round(HA

111、R1)7 and the Government is currently running the process for HAR28.As part of HAR2,the assessment criteria for awarding support considers the impact on the electricity system,with projects encouraged to be located optimally to reduce system constraint costs and to utilise excess renewable generation

112、(thus providing a whole system benefit to consumers).In the assessment criteria,DESNZ highlighted that projects located in Northern areas would be considered to have the most positive impact on the electricity system,as shown in Figure 12.Figure 11 Hydrogen value chainFigure 12 Impact of the locatio

113、n of low carbon hydrogen on the electricity systemSource:DESNZABCDEFMost positiveImpact on the electricity networkABCDEFLeast positiveRenewable energyPower InfrastructureElectrolyserCompression(as required)Storage(as required)NetworkSmall local userPower GenerationConstrained energyIndustrial userSu

114、pport mechanismsMapping toolConclusions and next stepsAppendices18Hydrogen production using thermal constraintsA hydrogen production facility could use electricity from excess renewables to produce hydrogen by locating near to a constrained boundary and increasing generation at times of constraints.

115、Case StudyB6 boundaryCurrently,the B6 boundary,which geographically spans the border between England and Scotland,is constrained as the offshore wind north of the B6 boundary,at times,can produce greater electricity than can flow down to the large demand centres in Southern England.To support constr

116、aints within this area,a hydrogen production facility could be located anywhere north of the B6 boundary to provide demand when there is a system imbalance.When there are periods of network constraints,the production facility would increase its use of electricity and therefore its hydrogen productio

117、n.This would support the ESO in managing the imbalance between supply and demand and reduce the need for the ESO to instruct and pay renewable generators that connect north of the boundary to turn down.As the ESO balances the system on a half hourly basis,there are 48 half hourly periods within a da

118、y that the production facility may be able to turn up its demand to use the excess renewable generation(that would otherwise have been constrained).For example,if there were constraints during half hourly periods 1-6 and then 24-48,the production facility would be able to increase their demand durin

119、g periods 1-6,turn down during periods 7-23(as there are no constraints)and then turn back up during periods 24-48.B6 boundaryThe amount by which the production facility would increase its demand would depend on the volume of constrained electricity.For example,it may be that the constraint is great

120、er than the size of the facility and the hydrogen production facilities demand could increase to full capacity(100%).Alternatively,it could be that the size of the constraint is equal to 50%of the hydrogen production facilitys capacity and demand would only increase to 50%,with 50%of capacity unused

121、 if only using thermally constrained electricity as the electricity source.The number of constraints would vary within every half hour.Use of hydrogen to manage thermal constraintsExecutive summaryIntroduction and approachWhat are thermal constraints?19Today,decisions over the location and operation

122、 of hydrogen projects are a triangulation between multiple factors.This includes the location of the demand offtake,available water resources and an available electricity network grid connection(or the availability of renewable generation through a direct private wire connection).In considering the

123、feasibility of a hydrogen production facility utilising thermally constrained electricity,this investigation has looked at whether it is:technically feasible for the production facility to ramp up to provide a response during periods of constraints;and commercially viable to operate a hydrogen produ

124、ction facility in this manner,and what the offtake route for the hydrogen produced could be.Figure 13 Factors influencing an HPF responding to thermal constraintsResponse timesLocation and availability of network connectionTechnical requirementsCommercial strategyFacility utilisationFlexibility of o

125、fftakerElectricity pricesLow carbon electricitySupport mechanismsMapping toolConclusions and next stepsAppendices20The technical feasibility of the production facility to ramp upFor the facility to be able to respond to thermal constraints,the facility will need to turn up and down quickly in line w

126、ith signals from the ESO.There are three main technologies for producing hydrogen via electricity:Alkaline,Proton Exchange Membrane(PEM)and Solid Oxide Electrolyser Cell(SOEC).Currently,most projects use either Alkaline or PEM as an electrolyser technology,as these are more mature than SOEC technolo

127、gy.Table 1 presents the response times of hydrogen electrolysers in different states.In both a hot and warm state,the production facility would be able to respond reasonably quickly to a signal from the ESO to increase demand in the event of a constraint of the electricity network.The ESO acts as th

128、e residual balancer after the market closure,one hour ahead of real time.It is during this hour that the ESO would provide signals to providers to turn up demand.Whilst it is technically feasible to respond quickly,there are wider impact considerations on the production facility itself.Constantly ad

129、justing the settings of an electrolyser,whether its being turned up and down(or subjected to frequent cold starts to manage constraints),can have significant technical impacts.Such fluctuations can lead to increased wear and tear on the equipment,potentially reducing its operational lifespan.Moreove

130、r,abrupt changes in operation can affect the stability and efficiency of electrolysis processes,resulting in fluctuations in gas purity and output.Additionally,frequent cold starts can impose thermal stress on the system,potentially causing thermal expansion and contraction issues that may compromis

131、e the integrity of components over time.StateDefinitionPEM Response timeAlkaline Response timeHotA hot start refers to when the production facility is already producing hydrogen.10%per second and therefore can reach full capacity within a maximum of 10 seconds0.2%/s(atmospheric)to 10%/s(pressurised)

132、(8.3min-10sec startup)WarmA warm start refers to when the electrolyser is already consuming power to maintain specific temperatures and pressures within the electrolyser but there is not necessarily any hydrogen production.10%per second and therefore can reach full capacity within a maximum of 10 se

133、conds8 minutesColdA cold start refers to when the starting from no power to the electrolyser or any balance of plant components.5 minutes as it can ramp 20%per minute20 minutes(5%per minute)Table 1 Electrolyser response timesUse of hydrogen to manage thermal constraintsExecutive summaryIntroduction

134、and approachWhat are thermal constraints?21The commercial viability of operating a hydrogen production facility using thermal electricity constraintsTo be able to operate the hydrogen production facility in the flexible manner required to utilise thermally constrained electricity,a robust business m

135、odel is needed that allows the investor to recover the high capital costs of an electrolyser facility.Utilisation of the facilityIn terms of the frequency and number of constraints,this will be determined by the profile of thermal constraint electricity on the boundary that the production facility i

136、s located above.Figure 14 provides an illustration of the constraints experienced(GW)within a year on any one boundary,as indicated by the curve,and the subsequent load factor,hours of the year,that the production facility would operate.Area 2 indicates the periods during which an example 750MW prod

137、uction facility would be operating.In over 36%of the hours within the year,the production facility would be operating at full capacity utilising thermal constraints and,for a further 20%of the hours,the production facility would be operating but at a lower capacity.Overall,for around 60%of the hours

138、 in the year,the production facility would utilise thermally constrained,either at full capacity or to a lower capacity.Area 1 represents periods when there are constraints,however,the constraints are greater than the size of the production facility and therefore not resolved,assuming no other facil

139、ities or other mechanisms are used.Area 3 represents the periods where there are no thermal constraints and therefore it is not operating or using alternative power sources.Figure 14 Indicative load duration curve for one year(data within the graph is illustrative)0%25%50%100%0123456GWUnused powerUt

140、ilised powerNo constraint power available 1 2 3Available Power Boundary 6(GWh)Total Energy Consumed(GWh)Total Plant Rating(Electrolyser+BoP)Support mechanismsMapping toolConclusions and next stepsAppendices22Commercial StrategyA significant driver of the operating costs of a hydrogen production faci

141、lity are the electricity costs.A production facility will look to optimise their electricity costs to allow for their hydrogen to be competitive compared to other projects.The production facility can secure their electricity prices through several routes including the wholesale market,Balancing Mech

142、anism(BM),a PPA or Over the Counter(OTC)contracts.Currently,most current or planned electrolytic hydrogen projects are securing their electricity prices through renewable PPAs.Through a PPA,OTC contract or spot wholesale price,the HPF will pay positive prices for the electricity and look to secure t

143、he most competitive price available to provide stability for their business model.Through the BM,there is the opportunity for the facility to bid successfully at zero or negative prices.This would allow the hydrogen production facility to earn revenue by using electricity for hydrogen during periods

144、 of where electricity is constrained.However,the BM can be volatile and reflects real time fluctuations in demand and supply.As such,it does not guarantee any certainty on prices,nor that the hydrogen production facility would always be successful with their bidding strategy.For example,a hydrogen f

145、acility may expect zero or negative prices if forecasts indicate high amounts of wind generation but closer to real time,wind suddenly drops and prices become positive.Optimising between a PPA or OTC contracts and the BM provides the opportunity for the production facility to reduce its overall elec

146、tricity costs.However,to recover the overarching investment cost,an HPF may target a higher utilisation factor and may need to make last minute optimisation decisions,which may be more expensive had the facility procured a fixed electricity price through an alternative approach.This then leaves the

147、investment risk with the facility,as the balance of revenues and costs from participating in the balancing market will depend on how well a hydrogen production facility can optimise across different revenue streams.As a result,current arrangements do not provide sufficient incentive for a hydrogen p

148、roduction facility to locate in areas of constraints and provide a demand response during periods of constraints as there is too much risk with the investor when recovering the costs of the production facility.A significant driver of the operating costs of a hydrogen production facility are the elec

149、tricity costs.A production facility will look to optimise their electricity costs to allow for their hydrogen to be competitive.Use of hydrogen to manage thermal constraintsExecutive summaryIntroduction and approachWhat are thermal constraints?23Required flexibility of offtakerA hydrogen production

150、facility that uses thermally constrained electricity as described in this report is likely to have a varying hydrogen production profile,producing more hydrogen during times when the constrained electricity is available.To date,most hydrogen production facilities are being developed to supply a sing

151、le or a small number of clustered offtakers either for industrial process or for use in transport refuelling.These offtakers typically require a stable or predictable profile of hydrogen.An option to manage the flow of hydrogen to offtakers would be to use hydrogen storage facilities which are sized

152、 to be filled during periods of high production and emptied during low/no production.However,above ground hydrogen storage tanks can only offer limited storage,and larger geological storage facilities(such as in salt caverns)are limited.New geological underground hydrogen storage in salt caverns and

153、 other geological formations potentially offer a low unit cost solution for large scale storage,but the capital costs are likely to be too high for an individual project to absorb.Large scale underground storage is more likely to be part of a wider hydrogen network where costs can shared by a number

154、 of projects and customers.A more viable option for a hydrogen production facility with a varying production profile is a connection to a gas network.The ideal offtake solution would be a 100%hydrogen network which could take all the hydrogen a facility produced(within the limits of the pipeline cap

155、acity),these are currently planned near and within the industrial clusters and through National Gas Transmissions Project Union.However,100%hydrogen networks are likely to be limited in the next 10-15 years,therefore,in the short-to-medium term,blending into the existing gas network is likely to be

156、the most likely flexible offtake option.Electricity sourcing and the low carbon hydrogen standardFor the hydrogen produced to meet the Low Carbon Hydrogen Standard(LCHS),9 the hydrogen developer will need to evidence that the electricity source mix used will need to be sufficiently low carbon.The LC

157、HS allows for hydrogen projects to record electricity consumption as electricity curtailment avoidance.This lets the emissions of the electricity source during times where electricity is thermally constrained to be claimed at the regional or national GHG emissions figure(in CO2/KWh)during the releva

158、nt time period.For example,a hydrogen production facility using constrained electricity in the North of Scotland10 area can claim the North of Scotland regional system emissions figure published by National Grid ESO11 or Elexon12 as its electricity consumption during that time period.The emissions f

159、igure is likely to be at or near to zero during times of thermal constraints in areas with excess renewable generation.A hydrogen project that is located in constrained areas will want to claim regional rather than national emissions figures as the regional figure will reflect the(very low)emissions

160、 intensity of the electricity used much better than the national figure.The LCHS requires evidence of Bid Offer Acceptance within the Balancing Mechanism and metered electricity consumption data for each time period claimed.Support mechanismsMapping toolConclusions and next stepsAppendices24Using th

161、e gas network as a flexible offtakerGB has a comprehensive gas network delivering(near)100%natural gas to around 80%of residential homes and thousands of industrial and commercial customers.A hydrogen blend of up to 20%could be injected into the existing gas networks with limited alterations to the

162、network.The vast majority of current gas appliances could accept a blend of up to 20%hydrogen(by volume)without needing to be amended or replaced.A major advantage of blending as an offtaker is its flexibility.Hydrogen can be blended into the network when it is produced.Periods of no or reduced hydr

163、ogen production are not an issue as there is no specific off-taker reliant on the hydrogen from the facility.The volume of hydrogen you can blend at any particular point in the gas network will depend on a number of factors,including:the size and pressure of the pipeline,generally the larger size an

164、d pressure offers more injection capacity;the location,with network entry points generally offering greater capacity;and the distance to other blending facilities,if other blending facilities are close the blending limit would need to be managed.This is further explored in appendix 4.In December 202

165、3,the UK Government published a strategic decision on blending,where it announced that it intends to proceed with blending into the gas distribution networks subject to a safety assessment and subsequent finalisation of the economic assessment.In its decision,the UK Government stated that it saw two

166、 strategic roles for hydrogen blending;1.An offtaker of last resort-being able to accept hydrogen when there is excess production that is not required by the primary offtaker;and 2.As a strategic enabler where hydrogen production facilities are able to support the wider energy system by locating in

167、areas where there is excess constrained electricity.The decision stated that the HPBM would be the most appropriate mechanism to support hydrogen blending.In the first two rounds of HPBM,hydrogen blending has not been allowed as an offtaker.The UK governments future rounds will allow for blending to

168、 be considered as a qualifying offtake,as long as a projects use of blending as an offtaker aligns with the strategic roles outlined above.A hydrogen production facility that uses thermal constraints will be ideally placed to play a role as a strategic enabler.It is important to note that the UK Gov

169、ernments decision has been at distribution network level and there remains uncertainty about whether blending will be allowed at transmission level.Use of hydrogen to manage thermal constraintsExecutive summaryIntroduction and approachWhat are thermal constraints?25The appropriateness of using hydro

170、gen to manage thermal constraints The analysis conducted for this project has confirmed that is it technically possible for the electrolyser to turn up their demand quickly when there are periods of thermally constrained electricity.For this to be feasible,the production facility would need to have

171、a flexible offtaker who can take the hydrogen when its produced but does not need a constant supply of hydrogen.Of the offtakers considered,blending into the gas grid provides the flexibility that a facility turning up and down production will need and in the locations and time frame when its likely

172、 to be needed.Irrespective of the technical feasibility and offtaker viability,the challenge remains that,if the production facility locates in an area of where there is constrained electricity available and is only operating during periods of constraints,this is most likely to result in a low utili

173、sation of the production facility.This would prevent the production facility owner from sufficiently recovering the cost of investment and results in a higher cost of hydrogen produced compared to other business model approaches.However,by providing this capacity to the system operator,the productio

174、n facility could provide significant benefits in managing constraint costs.Therefore,for this business model to be viable,a support mechanism is necessary to incentive hydrogen production facilities to locate in areas of constraints and be actively involved in managing electricity transmission syste

175、m constraints.The production facility would need to have a flexible offtaker who can take the hydrogen when its produced but does not need a constant supply of hydrogen.Blending into the gas grid provides the flexibility that a facility turning up and down production will need.Support mechanismsMapp

176、ing toolConclusions and next stepsAppendices26Support mechanismTo incentivise HPFs to locate in areas of system constraints and to use the excess renewable generation,this project has identified and assessed potential support mechanisms that could be introduced.In considering the options,several fac

177、tors were reviewed,including:the ESOs system balancing responsibilities,hydrogen production facility requirements and the need to deliver value for money when managing constraints.ESOs system balancing responsibilitiesThe design of any potential support mechanisms is bound by the ESO licence,where t

178、he ESO is required to:ensure the efficient,economic,and coordinated operation of the electricity transmission system;and promote effective competition in the generation and supply of electricity,and promote efficiency in the implementation and administration of the balancing and settlement arrangeme

179、nts.Therefore,the ESO will need to demonstrate that any potential contract mechanism meets these requirements.The incoming National Energy System Operator(NESO)will have a broader licence and responsibilities,specifically to ensure that the system is economic,efficient,secure,and reliable,as well as

180、 achieving net zero.This will result in the NESO taking a more strategic and whole system approach to electricity and gas system operation.Hydrogen production facility requirementsTo be able to make an investment in the production facility to utilise the constrained electricity,a production facility

181、 will need a long-term contract that provides revenue certainty,alongside other revenue streams,to enable a hydrogen production developer to reach a FID.In the short to medium term,there is likely to remain a cost gap between hydrogen and carbon based fuels.The UK Government has introduced the Hydro

182、gen Production Business Model13(HPBM)to incentivise low carbon hydrogen production,by providing revenue support to hydrogen producers.It is expected that a hydrogen production facility that uses constrained energy will still require support through the HPBM.Delivers value in managing constraintsIn d

183、eveloping the mechanism,historic constraint costs were reviewed,and future constraint costs were modelled.Historically,the costs of thermal constraints management have been highest in terms of frequency and impact during the winter months,however,whilst less frequent in summer months,they can have a

184、 significant impact.A similar result is seen in the future constraint modelling results,with B4 experiencing significant constraint costs post 2030 across the years.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints27Support mechanism

185、sMapping toolConclusions and next stepsAppendices28The value of a support mechanismUnder the support mechanism,the hydrogen production facility would be incentivised and paid to turn up its demand during periods of constraints,as presented in Figure 15.Figure 15 How the mechanism would workHydrogen

186、OfftakerProvides a demand response to manage constraintsPays to change demand in response to thermal constraintsPays for hydrogen receivedProvides low carbon hydrogen to demand usersElectricity SystemOperator Excess GenerationDoes not instruct to turn down in the event of thermal constraintsIs not c

187、onstrained off and continues to provide generation to the systemAlternativeelectricity sourcesHydrogenProduction FacilityHHThrough alternative mechanisms(e.g.PPA)procures electricity in the event of no contstraintsIn the event of no constraints,provides alternative electricity sourcesExecutive summa

188、ryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints29Underpinning considerations for all mechanismsImplicit in the design of the mechanism is that:There will be a ceiling price for all options to ensure that the value secured through the mechanism wi

189、ll be lower than that of the constraint costs payments made by the ESO that would otherwise be incurred through the balancing mechanism.This is to ensure that the overall benefit to the electricity system delivered through the mechanism is greater than in the do nothing scenario of paying renewable

190、generators to turn down.In securing support through the mechanism,all demand units would need to meet prequalification requirements(specifically technical requirements)and a competitive process would be facilitated to allocate contracts.Contracts would be awarded based on best value for consumers co

191、nsidering the whole system.The mechanism would be aligned,where possible,to the new planning processes that are being developed,specifically the Centralised Strategic Network Plan(CSNP),which would consider alternative solutions.This contract could be utilised either by new facilities or by existing

192、 facilities as long as these are located in the right locations to support thermal constraints management.The optionsThis project has identified four contract mechanism designs:Utilisation payments Seasonally varying utilisation and availability payments Utilisation and availability payments that do

193、 not vary seasonallyFixed payment(either yearly or half-year)In assessing these options,the do-nothing option for comparison is the production facility participating in and being called upon through the Balancing Mechanism.The following provides an overview of how each of these options would work an

194、d the balance of risk and reward between the ESO/GB consumers and the hydrogen production facility(the demand provider).12a2b3Support mechanismsMapping toolConclusions and next stepsAppendices30Option 1Utilisation payment1OverviewUnder this option,demand assets connected to the network that can resp

195、ond during periods of constraints are paid an agreed utilisation payment(/MWh)for the duration of the constraints.The provider would inform the ESO ahead of time of their availability and the associated utilisation fee they would expect for the duration.Tenders will be paid on a pay as bid tender pr

196、ocess,with bids accepted from the lowest to the highest price until sufficient capacity has been secured.Contract lengthThe duration of the contract could vary in duration between 1 10 years.The length will be driven by the forecasted constraints profile certainty,this will take into consideration w

197、ider decisions regarding network investment,specifically expected network investment within the 10-year period that is likely to be impactful in reducing constraints.This contract would most likely be procured at T-1 years but could potentially be procured up to T-4 years.The contract would also be

198、available for facilities that relocate,that can demonstrate that their relocation does not have a material negative impact elsewhere on the system.For relocated facilities,the contract duration could be shorter depending on the ESOs assessment of future network infrastructure and constraint costs.Di

199、spatch periodsThis would have two instruction windows:21:00(day-ahead)for the period of 07:00 06:59 and 13:00(within day)for the period of 19:00 06:59.For instruction window 1,providers will have up to 10 hours to prepare for dispatch post instruct time,and 6 hours for window 2.Other design features

200、 To incentivise providers to respond through this rather than the Balancing Mechanism,these responses will be prioritised ahead of BM units.This prioritisation would not include a financial incentive.If providers confirm availability,they will be required to meet a minimum level of availability to r

201、eceive full utilisation payment.A penalty could be applied if the provider has committed to being available during periods of constraints but then utilises the Balancing Mechanism instead.This penalty would not be applied to factors outside of the control of the responder.Executive summaryIntroducti

202、on and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints31Option 2aSeasonally varying utilisation payment and availability payment2aOverviewIn addition to the utilisation payment discussed within option 1,the demand user would receive an availability payment similar

203、to the existing Capacity Market mechanism whereby the provider is paid a/MW to be available for defined periods.The availability payment(against an associated MW)would be defined and agreed ahead of the service period and in line with the contract duration.The utilisation rate(/MWh)would be scaled t

204、o consider the size of the availability payment.Under this option,the availability payment and utilisation payment would vary during autumn/winter and spring/summer periods to reflect the difference in impact and frequency of constraints during these periods.This seasonality reflects that the histor

205、ic constraints and the future modelled constraints are generally most impactful in terms of volume and costs during the autumn/winter period,and the provision of a demand response from the production facility during the autumn/winter period is likely to deliver greater value to consumers.Therefore,t

206、he total value of response in the autumn/winter period is higher than the spring/summer period.Contract lengthFor new facilities,the contract length would be 10 years,aligning with the timescales of known electricity network development as per the ETYS/CSNP network upgrades.The procurement of this c

207、ontract would be 4 years ahead of need(T-4 years),which would likely be in line with the hydrogen production facilities FID timelines.The contract would also be available for facilities that relocate,that can demonstrate that their relocation does not have a material negative impact elsewhere on the

208、 system.For relocated facilities,the contract duration could be shorter depending on the ESOs assessment of future network infrastructure and constraint costs.Dispatch periodsThis would have two instruction windows:21:00(day-ahead)for the period of 07:00 06:59 and 13:00(within day)for the period of

209、19:00 06:59.For instruction window 1,providers will have up to 10 hours to prepare for dispatch post instruct time,and 6 hours for window 2.Other design features The utilisation element of the contract could be capped and/or an expected utilisation profile could be provided within the technical spec

210、ification document.A penalty is applied during periods where the demand provider(the hydrogen production facility)is expected to be available but subsequently provides short notice that they are unavailable.As part of the contract terms,if providers confirm availability for a period,they will be req

211、uired to meet a minimum level of availability to receive the full utilisation payment.Support mechanismsMapping toolAppendicesConclusions and next steps32Option 2bAvailability payment and utilisation payment(year-round)2bOverviewThis option would be similar to option 2a,however,the utilisation and a

212、vailability would not vary seasonally,but would be fixed at the same level throughout the year.This would mean that the same amount of kWs is effectively secured for the year.Contract lengthFor new facilities,the contract length would be 10 years,aligning with the timescales of known electricity net

213、work development as per the ETYS/CSNP network upgrades.The procurement of this contract would be 4 years ahead of need(T-4 years),which would likely be in line with the hydrogen production facilities FID timelines.The contract would also be available for facilities that relocate,that can demonstrate

214、 that their relocation does not have a material negative impact elsewhere on the system.For relocated facilities,the contract duration could be shorter depending on the ESOs assessment of future network infrastructure and constraint costs.Dispatch periodsThis would have two instruction windows:21:00

215、(day-ahead)for the period of 07:00 06:59 and 13:00(within day)for the period of 19:00 06:59.For instruction window 1,providers will have up to 10 hours to prepare for dispatch post instruct time,and 6 hours for window 2.Other design features The utilisation element of the contract could be capped an

216、d/or an expected utilisation profile could be provided within the technical specification document.A penalty is applied during periods where the demand provider(the hydrogen production facility)is expected to be available but subsequently provides short notice that they are unavailable.As part of th

217、e contract terms,if providers confirm availability for a period,they will be required to meet a minimum level of availability to receive the full utilisation payment.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints333OverviewThis op

218、tion would see the provider receive a fixed value for a defined period for the level of response(in MW)they could make available to the ESO.The value received through the contract would be predetermined by the avoided premium in section 3.Contract lengthThis contract would be procured for 1 year per

219、iod only.Dispatch periodsThis would have two instruction windows:21:00(day-ahead)for the period of 07:00 06:59 and 13:00(within day)for the period of 19:00 06:59.For instruction window 1,providers will have up to 10 hours to prepare for dispatch post instruct time,and 6 hours for window 2.Other desi

220、gn features A penalty is applied during periods where the demand provider(the hydrogen production facility)is expected to be available but subsequently provides short notice that they are unavailable.As part of the contract terms,if providers confirm availability for a period,they will be required t

221、o meet a minimum level of availability to receive the full utilisation payment,or would be subject to a penalty payment.Option 3Fixed paymentSupport mechanismsMapping toolAppendicesConclusions and next steps34Utilisation payment calculation Based on the avoided constraint cost that was derived by Ar

222、ups modelling,the project has calculated the average utilisation payment(/MWh)between 2030 and 2040 for the constrained boundaries.The utilisation payment is the volume weighted average of the avoided premium involved in curtailing renewable electricity and ramping up flexible generation(CCGT in our

223、 analysis).This results in a volume weighted average of 22.40/MWh for the utilisation payment for the period between 2030 and 2040.This is the Base Case minus market power to incorporate the premium applied(plus CCGT ramp up cost),see appendix A2.This is the maximum figure and is also an indicative

224、figure and further modelling will be required to derive a more accurate figure;Arup expects that the actual number would be lower to take into consideration firstly that the contract should deliver a value below the cost of the do nothing scenario of just paying the constraints and liquidity within

225、the market should drive competitiveness in bid responses when securing the contract.Arup has assumed that the HPF would receive a 50%discount on the BSUoS costs to reflect the positive impact that they provide to the system.Availability payment calculationFor each asset,the total expected benefit be

226、tween 2030 and 2040 has been calculated.This was based on the volume of constraints avoided across the 10-year period,multiplied by the utilisation payment described above.The total volume was then divided by the asset capacity and the number of years to derive the maximum availability payment per a

227、nnum.For option 2b,Arup assumed that the asset would recover 70%of its revenue via the availability payment(i.e.multiply by 70%the total availability payment)and the rest via a reduced utilisation payment.For option 2a,Arup defined seasonal utilisation and availability payments by calculating the wi

228、nter and summer volume weighted average of the total renewable curtailment cost(utilisation payment).The values for the contract options are set out in Figure 16 for the three different electrolyser sizes Arup modelled:300MW,750MW and 1500MW.Figure 16 Estimated prices secured under the contract mech

229、anism optionsOption 3Receives 50%BSUoS DiscountAn annual payment of:A.5.8m B.14.09mC.25.60mOption 2bReceives 50%BSUoS Discount6.72/MWh per MW provided to the system Per kW:A.28.02 B.27.12C.24.65 Option 2aReceives 50%BSUoS DiscountA/W:6.87/MWh per MW provided to the systemS/S:6.41/MWhPer MW provided

230、to the systemA/W*Per kW A:19.85B:19.21C:17.46S/S*:Per kW:A:8.19B:7.93C:7.21Option 1Receives 50%BSUoS Discount22.40/MWh payment per MW provided to the systemElectrolyser Capacity(%)030%100%Baseload Capacity(not within contract)Capacity for contractUtilisation paymentAvailability/annual payment*Autumn

231、/Winter *Spring/SummerA.300MWB.750MWC.1500MWExecutive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints35The following provides a theoretical explanation of how the mechanisms would work in practice across multiple scenarios.For the basis of t

232、his theoretical explanation,the following assumptions are made:A hydrogen production facility has secured a contract with the ESO to make available up to 750MW of its capacity to support management of the thermal constraints.These 750MW are only utilised for constrained circumstances and do not have

233、 any other electricity input.Under options 2a and 2b,the production facility has received an availability contract for the full capacity of 750MW.At contract signing,the ESO would confirm the merit order for the assets that have secured a contract.For all scenarios,except scenario 4,the hydrogen pro

234、duction facility is assumed to be first in the merit order.Table 3 How the contract options would work in practiceScenario Option 1Utilisation paymentOption 2aSeasonally varying utilisation payment and availability payment Option 2bAvailability payment and utilisation payment(year-round)Option 3Fixe

235、d payment1.There is a constraint of 750MW in autumn/winterThe production facility would receive a utilisation payment for the capacity supplied of 750MW.The production facility would receive a utilisation payment for the 750MW and the winter/autumn availability payment for the 750MW.The production f

236、acility would receive a utilisation payment for the 750MW and an availability payment for the 750MW.The facility would receive the payment irrespective of the constraints that materialise.During this period,it would provide the capacity of 750MW.2.There is a constraint of 300MW in autumn/winterThe p

237、roduction facility would receive a utilisation payment for the 300MW.The production facility would receive a utilisation payment for the 300MW and the winter/autumn availability payment for the 750MW.The production facility would receive a utilisation payment for the 300MW and an availability paymen

238、t for the 750MW.As per scenario 1,the facility would receive the fixed payment irrespective of constraints.In this scenario,it would provide 300MW of demand.3.There is a constraint of 300MW in spring/summerAs per scenario 2As per scenario 2,however they receive the spring/summer availability payment

239、.As per scenario 2.As per scenario 2.4.There is a constraint of 750MW;The HPF is second in the merit order after another 500MW assetThe production facility would receive a utilisation payment for the 250MW.The production facility would receive a utilisation payment for the 250MW and the winter/autum

240、n availability payment for the 750MW.The production facility would receive a utilisation payment for the 250MW and an availability payment for the 750MW.As per scenario 1.In this scenario it would provide 3MW of demand.5.There is a constraint of 2GWThe production facility would receive a utilisation

241、 payment for the 750MW.The ESO also calls upon other assets within the merit order to manage the constraint.The production facility would receive a utilisation payment for the 750MW and the winter/autumn availability payment for the 750MW.The ESO may then also call upon other demand providing assets

242、 within the merit order.The production facility would receive a utilisation payment for the 750MW and an availability payment for the 750MW.Then,the ESO would also call upon other demand providing assets within the merit order.The facility would provide its full capacity of 750MW.The ESO may then al

243、so call upon other demand providing assets within the merit order.6 A period of no constraints in autumn/winter The production facility would receive no utilisation payment as it is not providing any demand.As scenario 1 except no utilisation payment.As scenario 1 except no utilisation payment.As wi

244、th all other scenarios,the provider would receive the fixed payment but only this time it would not provide any demand.Support mechanismsMapping toolConclusions and next stepsAppendices36As the contract is for periods of thermal constraints,it is expected that hydrogen production facilities would ta

245、ke actions to optimise their utilisation,and therefore their business model,during periods of no constraints.This optimisation is likely to only occur when the HPF is confident that it will not be called upon through the contract,to ensure it avoids any penalties for non-response.This optimisation w

246、ill be driven by the wider business model of the HPF but could include a PPA and/or providing responses through the BM.This wider optimisation is likely to increase the viability of the business model as it results in higher utilisation of electrolyser capacity.Contract allocation approachTo offer t

247、his contract mechanism to the market,an auction and an allocation window approach could be utilised.The approach that is most suitable varies depending on the timing of when the contract mechanism needs to be secured and the likely liquidity of the market.The viability of the auction approach will d

248、epend on whether there is sufficient liquidity within the market to encourage competition between bidders when determining their/MW and/MWh.In the event of limited or no competition,bidders could be incentivised to provide a higher bid price than they would have in the event of strong competition.Th

249、is higher price would ultimately mean that consumers would be faced with higher costs had competition incentivised bidders to provide a more competitive price.Depending on the boundary,it may be that there are less technologies located(or are planning to locate)in proximity to the boundary,and are a

250、ble to meet the requirements to result in a competitive auction.Thus,an auction approach may not deliver the best value for consumers.An alternative approach could be to utilise allocation windows and a whole system approach to the allocation of contract mechanism.Under the allocation approach,windo

251、ws would be used to invite providers to meet a defined system need.This approach is similar to the Cap and Floor Windows and the Network Options Assessment(NOA)Stability Pathfinder.The approach could be aligned with the new Centralised Strategic Network Plan(CSNP)14 process,which is expected to be i

252、ntroduced in 2026,as per Figure 17.Figure 17 New CSNP process including proposed allocation windowModel Future Supply&DemandFuture Energy Scenarios development to provide a view on supply and demand out to 2050.Need identifiedThrough the NESO planning process(transition or final CSNP)future supply a

253、nd demand are modelled to provide a view on system needs,including thermal constraints.The outputs of the system needs identification would be published to the market.Tender process to identify solutionsBased on the identified needs,the NESO would provide a tender to the market that invites non-netw

254、ork solutions.Based on the CSNP,this would provide a view for 500MW).The requirement to vary the blend volume poses a challenge but it is expected to be manageable.The benefit of grid injection for a HPF-TC is the ability to vary the volume injected to match the varying production profile.For this k

255、ey benefit to be realised there needs to be an ability to vary the blend percentage.Given the size of the gas flows at NTS level vs the size of likely HPF facilities,the percentage variance is likely to be relatively small(a few percent)and could be managed by the network.Deblending offers a way of

256、managing the blends of more hydrogen sensitive customers.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints73 The capex of a blending facility and grid connection is expected to be a relatively small part of overall project capex.Indi

257、cative analysis shows that blending and connection costs will be relatively small compared to the capex of the HPF itself.Connection and blending facility costs may represent around 4%of capex for a 50 MW electrolyser and this percentage falls as the facility size increases.These costs will have a v

258、ery small impact on the LCoH.Need to recognise the strategic role a hydrogen facility using constrained electricity could play in the wider electricity system.The role hydrogen production facility using constrained energy could plays in managing the electricity network brings strategic value over an

259、d above other hydrogen production facilities seeking to inject.This should be recognised and taken into when account when blending capacity is allocated.This value should also be recognised within the HPBM and in how hydrogen blending capacity is allocated.Blended hydrogen should be certified so tha

260、t it can be traded at a premium to natural gas,Hydrogen that is created from thermal constrained energy could potentially be treated as a more premium product than other forms of hydrogen to reflect its wider energy system benefits.Hydrogen developers will need evidence that the thermally constraine

261、d electricity it uses will be classed as low carbon in order to be traded as a green gas.Need a way for a Gas system operator to communicate to potential HPFs where they can inject hydrogen.There is set to be a free-market approach to hydrogen connections in theory allowing for hydrogen injection an

262、ywhere along the network.Although this opens up a number of locations it could unintentionally crowd out hydrogen production facilities that offer wider benefits as there may be other hydrogen blending facilities connecting nearby,preventing or restricting their hydrogen injection.AppendicesUK Gover

263、nment decision on blendingDuring the course of this innovation project,in December 2023,the UK Government published a strategic decision on blending,where it announced that it intends to proceed with blending into the gas distribution networks subject to a safety assessment and subsequent finalisati

264、on of the economic assessment.In its decision,the UK Government stated that it saw two strategic roles for hydrogen blending;1.An offtaker of last resort-being able to accept hydrogen when there is excess production that is not required by the primary offtaker;and 2.As a strategic enabler where hydr

265、ogen production facilities are able to support the wider energy system by locating in areas where there is excess constrained electricity.The decision stated that the HPBM would be the most appropriate mechanism to support hydrogen blending.In the first two rounds of HPBM,hydrogen blending has not b

266、een allowed as an offtaker.The UK governments future rounds will allow for blending to be considered as a qualifying offtake,as long as a projects use of blending as an offtaker aligns with the strategic roles outlined above.A hydrogen production facility that uses thermal constraints should be idea

267、lly placed to demonstrate that it aligns with these strategic aims and provides wider system benefits.It is important to note that the UK Governments decision has been at distribution network level and there remains uncertainty about whether blending will be allowed at transmission level.Larger hydr

268、ogen production facilities that can make the biggest impact on thermal constraints are more likely to need a connection at the higher pressure transmission network,which offers a higher hydrogen offtake capacity.Though the higher pressure systems(LTS)within the distribution network can also provide

269、this higher offtake.Support mechanismsMapping toolConclusions and next steps74Technical implications of blending The main limitation on hydrogen injection volumes is the volume blend percentage of hydrogen,which cannot exceed the 20%maximum,and,in practice,this percentage is likely to be even lower

270、in the short term(closer to 5%)due to the need to work within existing billing methodology frameworks.In theory,hydrogen could be blended anywhere along the gas network.However,in practice,for larger scale projects(more than 100MW)blending is more likely at higher pressures either into the NTS or th

271、e highest-pressure tiers of the distribution networks,the LTS.This is because the flow of gas at these pressures allows for significant volumes of hydrogen to be injected before the volume blend limit is breached.A simplified case study was carried out to estimate the amount of hydrogen that could b

272、e injected into the gas network based on three sizes of electrolyser:300MW,750MW and 1500MW these sizes were chosen for consistency with other parts of the study.Various assumptions were made around the configuration of the gas network and the electrolyser.The inputs and assumptions are summarised i

273、n Table 16.Figure 30 shows the hydrogen blend percentages for the different sizes electrolyser facilities studied,these were chosen with different amounts of electricity topped-up from the wholesale electricity market.This is the amount of electricity needed to meet a minimum operating load of eithe

274、r 20%,40%or 60%of the electrolysers total capacity.Note at 0%top up the facility is in effect only operating during constrained times and therefore has the biggest variance between minimum(0)and maximum capacity.The length of the bars represents the range in blend percentage at the point of injectio

275、n resulting from variation in the hydrogen injection rate.The results show that the hydrogen blend range does not exceed 20 vol.%for any of the electrolyser ratings considered.However if the blend percentage is set lower,e.g.at 5%to manage customer billing arrangements the blend range could impact t

276、hat threshold for the larger facilities.InputsAssumptionProximity of injection point to other injection pointsThere is no blending upstream affecting the assumptions below.Feeder diameter(NB)36 inch which is representative of a typical NTS gas pipeline with a diameter of 24-36”.Operating pressure70

277、barg which is representative of a typical NTS gas pipeline.Natural gas velocity20 m/s which is representative of a typical NTS gas pipeline.21Natural gas Wobbe Index(WI)50.9 MJ/Sm(WI is measured in mega joules per standard metre cubed based on GS(M)R standard conditions of 15 degrees and 1 atmospher

278、e pressure.Note that WI depends on source of gas).22Assumed natural gas temperature10CSize of electrolyser300MW,750MW and 1500 MW with no top up from the grid,20%top up,40%top up and 60%top up from the grid.Electrolyser Power Consumption57.5 kWh/kgBlend limit on LTS and NTS(%)20%by volumeTable 16 In

279、puts and assumptions in the case studyThe variability of blending increases for larger electrolysers,the higher the baseload capacity(i.e.the top-up)the lower the variation.A large variation in blend could have implications for any sensitive customers connected to the network who may struggle with v

280、ariations in blend.For this exercise a constant flow rate is assumed but in practice,the flowrate is likely to vary seasonally and will be lower in summer which would increase the percentage blend for the same rate of hydrogen injection.The pipeline size also varies around the network which would im

281、pact the flow rate and therefore the maximum hydrogen injection that can be accommodated.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints75AppendicesFigure 30 Expected hydrogen blend range in a 36”pipeline operating at 70 barg when

282、receiving hydrogen produced from electrolysers of different ratings1214241068Hydrogen Blend Range(vol.%)0020406002040600204060%Top-up300 MW=5 t/h(max hydrogen produced in tonnes per hour)750 MW=13 t/h)(max hydrogen produced in tonnes per hour)1500 MW=27 t/h(max hydrogen produced in tonnes per hour)T

283、he rate of hydrogen that can be injected will also depend on where in the network blending is occurring.The factors that will need to be taken into account include:The location of other blending facilities if there are other hydrogen blending facilities injecting hydrogen nearby then the blend rate

284、of both facilities will need to be managed and potentially limited in order to ensure the blend limit is not reached.The proximity to more sensitive customers there may be a small number of customers connected to the network which will either require 100%methane feedstock or will be highly sensitive

285、 to gas quality fluctuations.National Grid Gas is exploring deblending as an option for managing this issue23.Location is likely to be an important factor for deblending as the gas network will likely want to avoid having a blending facility immediately upstream of a deblending facility.The Wobbe In

286、dex(WI)of the gas-will also have an impact on the blend rate.In this example a gas with a relatively high WI is used.The WI of the gas will depend on the gas that is being inputted into the system.If the WI of the gas at the point that the hydrogen is blended is lower,than the maximum volume of hydr

287、ogen that can be injected would be reduced.This is because hydrogen has a lower WI and the current regulations state that the WI of gas must be between a certain range(47.2 and 51.4 MJ/m)though the lower limit is being reduced(to 46.5 MJ/m)which should allow for greater levels of hydrogen blending.B

288、lending at NTS entry points,such as St Fergus or Bacton,are expected allow the greatest amount of hydrogen to be injected.This is because there is a large amount of capacity available at NTS entry points.In summary blending hydrogen into the gas network is a potential route for a hydrogen production

289、 facility that uses thermally constrained energy but the ability to blend and the quantity of hydrogen that can be injected will vary depending on the location.The gas network will treat an application to blend on a case-by-case basis based on the factors outlined above.To support the development of

290、 hydrogen projects the networks(national Gas transmission and the distribution networks)should look to communicate where on their network there is likely to be blending capacity.The areas where there is likely to be capacity in the gas network(Scotland/North of England).Support mechanismsMapping too

291、lConclusions and next steps76Allowed blending limits At present,a 20%blend is the highest possible blend rate due to technical limits on domestic boilers.However,it is expected that a lower blend cap at around 5%is likely to be set initially due to the nascency of the hydrogen production market,to m

292、anage customer billing and support end users transition to hydrogen.Blending hydrogen into gas networks reduces the Calorific Value(CV)of the gas customers receive.This creates problems for estimating bills,as customers receiving higher blends would pay more per unit of energy than others.The Gas Sa

293、fety(Management)Regulations,GS(M)R,will need to be amended to accommodate hydrogen blending,beyond case-by-case exemptions.UK Government has signalled its intention to initially work within existing billing arrangements to enable blending to be rolled out quickly.Based on the analysis presented in t

294、he case study above,this may limit larger HPFs ability to blend hydrogen into gas networks as existing billing arrangements are expected to only accommodate blends of around 5%.24 25Another consideration is that HPFs using thermal constraint energy need to be able to vary the injection rate.The amou

295、nt of hydrogen that can be injected into the gas network will depend on the flow of gas within the network,which is higher in winter than in summer,driven by seasonal changes in demand.Even if hydrogen production remains steady,the blend percentage could vary during the year.This means that achievin

296、g a consistent blend will be extremely difficult.Based on the simple analysis above,the variance of blend percentages is likely to be relatively small and within blend limits for most sizes of electrolyser,except for larger facilities.It would be technically challenging for a HPF to turn production

297、up and down to maintain within blend limits,and commercially challenging to use storage as this would add significantly to project costs.Regulatory and commercial arrangements Existing regulations were originally designed for natural gas and,therefore,updates are required to recognise differences in

298、 hydrogen e.g.gas quality and safety arrangements.The exact nature of regulatory changes to enable blending is unknown.The UK Government indicates that it may initially prioritise changes that enable blending to be implemented quickly.This includes working within existing billing arrangements and al

299、locating new hydrogen connections on a first come first serve basis the free-market approach26.From the perspective of a hydrogen production facility that is providing electricity system benefits,it would be preferable for NGT and GDNs to take a more strategic approach to allocating blending capacit

300、y,with one of the criteria for allocation of capacity being the overall energy system benefits a facility is providing.This would also mitigate the risk under the free market approach,where subsequent new connections by other HPFs nearby may limit the amount of hydrogen a HPF using thermally constra

301、ined energy could inject which would reduce the benefit such a facility could offer to the electricity system and could even make such a project unviable.This approach requires assessing projects that provide wider energy system benefits as being of greater overall benefit to projects that are only

302、using blending as an offtaker of last resort and not providing any wider system benefits.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal constraints77Green certificatesGuarantees of Origins27 and Green Certificates28 can provide additional rev

303、enue streams by allowing hydrogen producers to earn a premium for producing hydrogen that is confirmed to be low carbon or green.This is likely to be important to the business model for an HPF.The UK Government has already defined the LCHS and plans to set up a Low Carbon Hydrogen Certification Sche

304、me by 2025.An HPF will need to prove that it meets the LCHS,and it can procure a certificate.It is therefore critical that any electricity procured as part of any contract with the ESO is classified as renewable or low carbon.The commercial viability of an HPF could be further improved if the LCHS r

305、ecognises wider benefits such as alleviating thermal constrains in addition to the carbon content of hydrogen.The UK Government signalled in its strategic decision in December 2023 that it will aim to take a decision on how certificates should be treated in a blending scenario,ahead of the launch of

306、 the LCHS.The UK Government has also decided to adopt a mass balance system for the LCHCS.This means that certificates can only be bought by consumers if they use green hydrogen it cannot(like the book and claim system)sell the certificates more widely,the government also proposes that on-selling ce

307、rtificates will not be allowed.This is because if hydrogen blended volumes are tradable,this could create a commercial incentive for hydrogen producers to prioritise blending over other off-takers,as they could extract a price premium for green gas certificates issued to gas shippers who could onwar

308、d trade to suppliers/retail markets.This would go against the Governments stated aim of blending being a reserve offtaker.These decisions could limit the premium that a hydrogen facility would be able to earn from any hydrogen blended into the gas networks.There is potentially a case to be made that

309、 a hydrogen production facility contributing to constraints management should be allowed to onward trade its certificates as it provides significant benefits to the wider energy system.Materiality of blending costsCapex costs are expected to represent the majority of costs associated with building a

310、nd connecting a blending facility to the gas network It is estimated that the direct capex costs of a blending facility are approximately 1m to 2.5m.The lower bound estimate of 1m is based on direct capex costs:the combined cost of the equipment,piping and infrastructure using the Aspen Capital Cost

311、 Estimator Software.The upper bound estimate of 2.5m is based on facility producing around 85,000 tonnes of hydrogen per year and is sourced from DESNZ29.In practice,capex costs will vary on a case-by-case basis.Other costs an HPF can expect are connection offer costs,which are expected to be less t

312、han 0.5m.Actual connections costs will depend on whether the connections process and costs will differ for hydrogen connections.The capex costs of building a blending facility are a relatively small in comparison to estimates of total capex costs of larger hydrogen production facility a 300MW has an

313、 estimated capex of 200m(excluding storage costs).As a result its estimated that blending facility costs will have a minor impact on the LCOH30 for all sizes of electrolyser considered in this report.It is important to note that,in practice,actual costs of an electrolyser and the costs of a blending

314、 facility will be location specific.AppendicesSupport mechanismsMapping toolConclusions and next steps78Appendix 5 Mapping toolThe final aspect of the project has been to assess where is best to locate any potential hydrogen production facility that will support the management of thermal constraints

315、.Utilising GIS technology,a map has been created to compare across a number of different datasets and overlays to provide a scale of preferable locations across GB for an HPF.MethodologyThroughout the development of the GIS mapping tool,there has been a refinement of the different weightings and pri

316、ority of each when layered onto GB.The weightings applied to the map reflect both the technical requirements of the hydrogen production facility itself to be able to safely run,but also the locational requirements of the of the hydrogen production facility,including where it is best situated to be a

317、ble to have most impact upon reducing the cost of thermal constraints upon the consumer and within close proximity of the chosen offtaker.For the mapping tool,6 variables have been agreed alongside the ESO,each given its own weighting,with number 1 given the highest priority descending down to numbe

318、r 6,which was deemed to have the lowest priority.In addition the map also excludes areas restricted by planning such as national parks and nature reserves etc.For the Five variables have been agreed alongside the ESO team,and each has been given a weighting from which the mapping tool has been devel

319、oped against.It should be noted that the Fuse app,from which the mapping tool has been developed,allows the user to edit the weighting applied to each variable so it can be used as a dynamic map.When setting up the variables,the user will have 100 weighting points to distribute across the variables.

320、To create the maps shown below(and in the main report)the following points have been assigned:1.Electricity Distribution Network Boundaries=35 points;2.Substation Proximity=25 points;3.Gas Network Proximity=15 points;4.Water Source Proximity=10 points;5.Industrial Users Proximity=10 points;and6.Moto

321、rway Network=5 points.Based on the weightings mentioned above,each of the 1km hex grids are then given a score out of 100 based on their appropriateness,with the darker green the grid,the more appropriate.To aid with the clear distinction between the different areas,the user can adjust the threshold

322、 of the hex grid.This allows the user to limit what areas are shown on the map based on their score.Figures 31 and 32 show the differences in the map when the threshold is gradually increased.Executive summaryIntroduction and approachWhat are thermal constraints?Use of hydrogen to manage thermal con

323、straints79VariableScoring MethodologyWeightingTransmission Network BoundariesNorth of B6 is the highest scoring;specifically the mapping tool has taken into consideration a more granular view of the boundaries based on the modelling results.The space between B8 and B6 scored slightly less.Due to the

324、 constraints being located predominately in the North of England and Scotland,any areas south of the B8 boundary are scored Zero.V.HighElectricity SubstationsProximity to substations is to be scored based on distance,with grading to be applied in 5km increments.I.e.0-5km=the best,5-10km=second best

325、etc.This process would be continued up to 50km where any further distance would be scored Zero.HighGas NetworkThe highest score to be given to the area within a 10km proximity of Grid entry points(For example,St Fergus).Forward area to be graded according to distance from the gas transmission or LTS

326、 network.30km lowest score(any facility at this range must require a DCO for development)MediumWater SourceGraded system based on distance from the coast or Main rivers,lakes,or lochs on a per KM basis.With each KM further away being scored less than the previous.LowIndustrial Demand PointsThis is c

327、ontinuous grade based on proximity to major carbon dioxide emitters in the UK.LowMotorway NetworkA 5km of a motorway potential transport offtaker in the futureLowestTable 17 GIS mapping tool variables and weightingsFuture use of the toolEach of the images shown above have been produced with a consis

328、tent weighting(applied to each of the weightings).The tool has been designed so that any user can have the ability to change the weightings,placing greater weight on certain variables compared to others.In each instance,the change in weightings will affect the output of the GIS tool.Currently,the we

329、ightings have been aligned with the gas grid being the offtaker of choice,with the motorway network and industrial users weighted lower.These can be updated depending on specific offtaker types and the primary offtaker.Data preparation and spatial analysisData processing for the HPF thermal constrai

330、nts tool involved a combination of ArcGIS Pro and Feature Manipulation Engine(FME).Initially,ArcGIS Pro was used for constraints mapping to identify relevant areas and exclude hex-grid cells intersecting with spatial constraints.Then,Euclidean distance calculations were performed in ArcGIS Pro to me

331、asure straight-line distances from each MCE variable.Next,FME was utilised to spatially filter hex-grid cells based on Euclidean distance measurements.Mean statistics were then applied in FME to calculate the average spatial unit values of the variables within each cell.Finally,the values were remap

332、ped to align with the scoring criteria specified in.This integrated approach ensured efficient data processing and accurate determination of suitable locations for the HPF thermal constraints tool.Category Variable Input Data SourceDistribution Network Boundaries High/Low Priority DNBs(Linear)NGESOE

333、lectricity SubstationsSubstations(Point)NGESO Gas network Gas Pipes(Linear)National Gas Water Rivers(Linear)Ordnance Survey,SEPA,DEFRA Industrial demand points Source Point Emitters(Point)DESNZ Motorway proximityOpen Road Motorways(Linear)Ordnance SurveyTable 19 Geospatial datasets inputs and sourcesAppendicesSupport mechanismsMapping toolConclusions and next steps80Figure 31 GIS mapping tool with