Hydrogen Production from ThermalElectricity Constraint Management National Grid ESO & National Gas Transmission A Network Innovation Allowance funded project Executive summary2Introduction and approach6What are thermal constraints?8Use of hydrogen to manage thermal constraints14Support mechanisms24Mapping tool42Conclusions and next steps44References and glossary of terms48Appendix 1 Commercial model52Appendix 2 Modelling constraints58Appendix 3 Modular design66Appendix 4 Injecting Hydrogen into the Gas Networks74Appendix 5 Mapping tool82 Executive summary Arup, in partnership with National GridElectricity System Operator (ESO) and NationalGas Transmission (NGT), has investigatedthe technical, commercial, and economic casefor electrolytic hydrogen production facilitiesto help manage thermal constraints on theelectricity transmission system. cost of these thermal constraint actions, which arepassed onto consumers through energy bills, haveincreased significantly and in 2022/23 totalled £1.5billion. With thermal constraints on the transmissionnetwork expected to increase further over the nextdecade or more before being eased by networkreinforcement, there is a strong case for alternativesolutions to thermal constraint management in thenext 10-20 years. As the electricity system has decarbonised overthe last decade, large-scale renewables haveconnected onto the electricity transmissionnetwork and significant further renewablesare expected to connect, to achieve a net zeroelectricity system by 2035. A substantial amount ofrenewable generation is expected to come onlinein the north of the UK whereas the bulk of energydemand is likely to continue to be in the South.The electricity transmission network needs to besubstantially reinforced to enable these powerflows, with delivery taking at least 5-10 years forlarge transmission infrastructure upgrades givenconsenting and construction timeframes. Hydrogen production facilities could reduceregional thermal constraints by utilising electricityfrom renewables that would otherwise need to beconstrained. The low carbon hydrogen generatedcan then be used as an alternative to fossil fuels inindustry, heating or transport to help decarbonise theUK economy. In the interim, when there is significant renewablegeneration, regional power flows can sometimesexceed the thermal capacity of electricitytransmission assets, requiring the ESO to take actionto maintain safe system operation. At present, theESO will pay to turn down (constrain) renewablegeneration and to dispatch alternative (mostlyfossil fuel) generation closer to the demand. The The technical and commercialviability of using hydrogen productionto manage thermal constraintson the electricity network This is most likely to be a connection to a gasnetwork. Although some 100% hydrogen networksare planned, during the timeframe when a facilitysuch as this is likely to be required to managethermal constraints (the next 10-15 years), blendinginto the existing gas network is likely to be the mostfeasible option. The case for a facility blendinghydrogen into the gas network will depend onnetwork location and will need to be worked out ona case-by-case basis. This innovation project has determined that it istechnically viable to operate a hydrogen productionfacility in a manner that allows it to supportmanagement of thermal constraints on the electricitynetwork. Electrolysers, which use electricity toderive hydrogen (and oxygen) are able to react fastenough with response times varying between 10seconds and 20 minutes, depending on the type ofelectrolysis technology. Electrolysis facilities in ahot or ‘warm’ state can respond more rapidly thanfacilities that are completely ‘cold’ i.e. restarting. Through our investigations, we have found thatthere is a viable commercial case for hydrogenproduction facilities to help manage thermalconstraints providing: •There is an alternative electricity supply todraw upon when constraints are not available,to firstly increase utilisation and thus revenuegenerated from the electrolysers and secondlyensure electrolysers are ‘warm’ enough to rampup rapidly when required. This may meanhydrogen production facilities drawing energyfrom the grid during non-constrained times; However, from a commercial perspective,electrolysers are high capital cost equipment.Therefore, a hydrogen production facility wouldnormally seek to maximise utilisation to recoverinitial investment costs i.e. running at or near to fullcapacity as much as possible. Thermal constraintswill not be present on the electricity network formuch of the time, even in very constrained areasreflecting the intermittent nature of renewablegeneration. This makes the commercial case for ahydrogen facility seeking to manage constraintschallenging, even if the cost electricity duringthe times of constraints was very low or zero (oreven negative prices). This project has found thatunder current market arrangements there is nota suffici