Delivering a reliable decarbonised
power system
March 2023

Delivering a reliable decarbonised power system
March 2023

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2

Contents
Acknowledgements

4

The Committee

5

Executive summary9

Chapter 1: Setting the context for the future power system27

1. Historical trends in demand and emissions

29

2. Future changes to demand and supply

31

Chapter 2: Delivering a reliable decarbonised power system45

1. What flexibility is needed?

47

2. Types of flexibility and options for the flexibility capacity mix

50

3. Facilitating delivery and addressing risks

63

4. Indicators for measuring progress

73

Chapter 3: Implications for hydrogen production, use and infrastructure77

1. Hydrogen demands in the future energy system

79

2. Implications for hydrogen supply

87

3. Hydrogen infrastructure102

4. Implications for fossil fuel consumption

109

5. Indicators for monitoring progress

113

Chapter 4: The need for climate resilience119

1. Climate and weather risks to a decarbonised energy system121

2. Delivering a climate-resilient decarbonised energy system

125

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Delivering a reliable decarbonised power system

Acknowledgements
The Committee would like to thank:
The team that prepared this report and its analysis: Owen Bellamy, Rachel Hay,
Robbie Herring, Alex Isard, Cara Labuschagne, David Joffe, Richard Millar andChris Stark.
Other members of the Secretariat who contributed to this report: Sasha Abraham,
Ramesh Deonarine, Joshua Deru, Tom Dooks, Kirsty Girvan, Daisy Jameson, Luke
Maxfield, Chloe Nemo Ramirez, Marcus Shepheard and Sophie Vipond.
The organisations that have produced supporting research for this report: AFRYManagement Consulting, including: John McShane, Gareth Davies, Alessandro
Crosara, and John Perkins.
A wide range of stakeholders, including public and private bodies who engaged
with us, shared evidence, reviewed analysis or met with the Committee bilaterally.

Baroness Brown has disclosed on her Register of Interests a number of organisations
with interests in renewable energy. As Chair of the Adaptation Committee,
Baroness Brown’s contribution has focused on the resilience and adaptation
aspects of this report.

Acknowledgements

4

The Committee

The Rt. Hon John Gummer, Lord Deben,
Chair
Lord Deben was the UK’s longest-serving Secretary ofState for the Environment (1993 to 1997). He has held
several other high-level ministerial posts, including
Secretary of State for Agriculture, Fisheries and Food (1989
to 1993). Lord Deben also runs Sancroft, a corporate
responsibility consultancy working with blue-chipcompanies around the world on environmental, socialand ethical issues.

Professor Keith Bell
Keith Bell is a co-Director of the UK Energy ResearchCentre (UKERC), a Chartered Engineer and a Fellow of
the Royal Society of Edinburgh. He has been at the
University of Strathclyde since 2005, was appointed to
the Scottish Power Chair in Smart Grids in 2013 and has
been involved in energy system research incollaboration with many academic and industrial
partners.

Professor Michael Davies

Professor Piers Forster

Michael Davies is Professor of Building Physics andEnvironment at the UCL Institute for Environmental Design
and Engineering (IEDE). At UCL his research interests relate
to the complex relationship between the built
environment and human wellbeing. He is also Director of
the Complex Built Environment Systems Group at UCL anda member of the Scientific Advisory Committee of‘Healthy Polis’.

Piers Forster is Director of the Priestley International
Centre for Climate and Professor of Physical Climate
Change at the University of Leeds. He has played asignificant role authoring Intergovernmental Panel on
Climate Change (IPCC) reports, and is a coordinating
lead author role for the IPCC’s sixth assessment report.

5

Delivering a reliable decarbonised power system

Paul Johnson CBEProfessor Corinne Le Quéré FRS

Paul Johnson is Director of the Institute for Fiscal Studies
and a visiting professor at University College London (UCL).
He is widely published on the economics of public policy,
and he co-wrote the ‘Mirrlees review’ of tax systemdesign. He was previously Chief Economist at the
Department for Education (2000 to 2004).

Corinne Le Quéré is a Royal Society Research Professor
at the University of East Anglia (UEA), specialising in theinteractions between climate change and the carbon
cycle. She was lead author of several assessment reports
for the UN’s Intergovernmental Panel on Climate
Change (IPCC) and she currently Chairs the French
Haut Conseil pour le Climat.

Baroness Brown of Cambridge DBE FRSChair, Adaptation Committee

Dr Ben Caldecott

Baroness Brown of Cambridge DBE FREng FRS (Julia King) isan engineer, with a career spanning senior engineeringand leadership roles in industry and academia. She
currently serves as Chair of the CCC’s Adaptation
Committee; non-executive director of Ceres Power,Ørsted and Frontier IP; Chair of the Carbon Trust; andChair of the House of Lords Science and Technology
Select Committee.

The Committee

Ben Caldecott is the founding Director of the Oxford
Sustainable Finance Group and the inaugural Lombard
Odier Associate Professor of Sustainable Finance at the
University of Oxford. Ben is also the founding Director
and Principal Investigator of the UK Centre for Greening
Finance & Investment (CGFI), established by UK
Research and Innovation in 2021 as the national centre
to accelerate the adoption and use of climate andenvironmental data and analytics by financial
institutions internationally.

6

Professor Richard Dawson

Professor Nathalie Seddon

Richard Dawson is Professor of Earth Systems Engineeringand Director of Research in the School of Engineering at
Newcastle University. Over the last two decades his
research has focused on the analysis and management ofclimatic risks to civil engineering systems, including thedevelopment of systems modelling of risks to cities,
catchments and infrastructure networks.

Nathalie Seddon is Professor of Biodiversity and Founding
Director of the Nature-based Solutions Initiative in the
Department of Biology at the University of Oxford.
Nathalie trained as an ecologist at Cambridge University
and has over 25 years of research experience in a rangeof ecosystems across the globe. As a University Research
Fellow of the Royal Society, she developed broadresearch interests in the origins and maintenance of
biodiversity and its relationship with global change.

Professor Swenja Surminski
Swenja Surminski is Chair of the Munich Climate Insurance
Initiative, Managing Director Climate and Sustainability at
Marsh McLennan and Professor in Practice at the
Grantham Research Institute at the London School of
Economics (LSE). Her work focuses on capacity building
and knowledge transfer between science, policy andindustry, building on her work in industry and as advisor togovernments, private sector and civil society, including as
Visiting Academic at the Bank of England.

7

Delivering a reliable decarbonised power system

Executive summary

Delivering a reliable and resilient
decarbonised power system

9

Delivering a reliable decarbonised power system

Introduction and key messages
A decarbonised power system is the central requirement for achieving Net Zero.
Access to reliable, resilient and plentiful decarbonised electricity – at an affordable
price to consumers – is key to a thriving modern economy, less dependent on
imported oil and gas. That goal is now within sight; the UK Government has
committed to decarbonise electricity supply by 2035, in line with the Climate
Change Committee’s advice. However, the Government has not yet provided acoherent strategy to achieve its goal nor provided essential details on how it willencourage the necessary investment and infrastructure to be deployed over the
next 12 years.
The cascading impacts of electricity failure are already significant. These willcontinue to grow as the economy becomes increasingly electrified and as
extreme weather events become more common and severe. Critical services suchas telecoms, banking and infrastructure already depend on a reliable and resilientelectricity system. This dependency will grow to other areas with the continued
digitalisation of the economy and the spread of electrified technologies totransport, home heating and industry. In our increasingly electrified society, thelow-carbon transformation must have resilience embedded throughout. Morefrequent and intense weather events such as heatwaves, droughts and floods
must be anticipated alongside other likely changes to weather. These include
possible changes to wind conditions, increasingly critical to the function of thewhole energy system.
This report illustrates what a reliable, resilient, decarbonised electricity supply
system could look like in 2035, and the steps required to achieve it. It provides new
insights and new advice on how such a system can be achieved by 2035, using
real weather data and hourly analysis of Great Britain’s power system (Northern
Ireland is part of the all-Ireland system). It also looks at the implications forhydrogen.
A decarbonised power system by 2035 is achievable, but it requires that barriers to
swift deployment of critical infrastructure are removed, and policy gaps remedied.
This will open the path to major new investment in renewable generation andinfrastructure. It can also support essential flexible low-carbon technologies – thesemust remain a critical priority for Government alongside the delivery of renewables
and nuclear.
The 2035 electricity system envisaged in this report would maintain energy security,
while coping with the expected increase in electricity demands and potentiallylong periods of low wind. The consequent dramatic reduction in gas consumption
would also cut our exposure to volatile international fossil fuel markets, with greater
reliance on homegrown low-cost renewables. These conclusions have newsignificance following the recent period of heightened energy insecurity.
•

A reliable, resilient, decarbonised electricity system can be delivered by
2035. This is needed to deliver emissions reductions in line with the path to
Net Zero, while ensuring a reliable and resilient electricity supply andsubstantially reducing the UK’s dependence on imported fossil fuels.
However, achievement of this goal rests on a series of urgent changes:– Careful system-level and asset-level planning and design is neededfrom the outset to ensure that a decarbonised system, with a higher
degree of weather-dependence, can be made reliable and resilient.
The Government must take on the role of designing the overall systemor delegate clearly to another body with the powers and capacity to
do so.

Executive summary

10

– A number of processes – including planning, consenting andconnections – must be urgently reformed to deploy infrastructure at
sufficient speed to deliver the required range of system components
by 2035. Infrastructure build rates, both for generation and network
capacity, will need to exceed what has been achieved historically ina number of areas and represent large increases relative to today.
Given the level of investment needed, we must not miss theopportunity to build in system-and asset-level resilience from the start.
Reformed processes must ensure infrastructure is built to be resilient tothe changes in UK weather (including flood risks and heat extremes)that will occur over its lifetime.
– Delivering the portfolio of low-carbon flexibility and back-up capacity
needed will require new regulations, incentives and business models.
These must be put in place with urgency to enable the necessary
investment decisions to be taken on a timely basis and at theappropriate scale. Regulatory frameworks and market design must be
fit for purpose and capable of galvanising the £300-430 billion of
investment 1 required and the supporting supply chains.
– There is an important role for Government in setting strategic direction
for power and non-power uses of hydrogen. Hydrogen infrastructure
will be required regardless of decisions in 2026 on its potential use forheat in buildings – the Government should identify a set of low-regret
investments that can proceed now. Decisions on hydrogentransmission and the development of business models for hydrogentransportation and storage should be fast-tracked, given long leadtimes associated with hydrogen storage. Delays in the delivery ofhydrogen infrastructure could limit the role for hydrogen in the 2035
energy system, including its role to provide low-carbon back-up
capacity. If hydrogen use in the electricity system is towards the highend of its potential range, the Government’s targets for hydrogenproduction capacity in 2030 look insufficient.
•

The Government must give equal focus to low-carbon flexible solutions as
to the full delivery of its existing renewables and nuclear commitments.
This is vital to ensuring the future variable renewable-dominated electricity
system is reliable and resilient to potential future weather extremes.
– In a typical year, a balanced supply mix could comprise around 70%of annual generation from variable renewables (primarily offshorewind), complemented by around 20% from relatively inflexible
generation such as nuclear and bioenergy with carbon capture andstorage (BECCS). The remaining generation will need to come fromlow-carbon back-up generation (e.g. hydrogen-fired turbines andfossil gas plants with carbon capture and storage – CCS) alongsideother forms of flexibility.
– However, variations in both wind output and electricity demand,necessitate system design which is resilient not only to average
weather, but to plausible future extreme weather and demand
scenarios. Changes in the frequency and intensity of large-scalewind droughts due to climate change cannot be ruled out based on
current evidence and need to be considered in system design andstress testing.

11

Delivering a reliable decarbonised power system

– Our modelling suggests that a portfolio of low-carbon flexibility
solutions, including responsive demand (e.g. smart electric vehicle
charging), interconnection, storage and low-carbon back-up plants
can provide much of the flexibility needed, even under modelled lowwind sensitivities. Within this, both gas CCS and hydrogen-fired backup plants are likely to be needed.
– The Committee regards a small amount of remaining unabated fossil
gas capacity in 2035 as compatible with a decarbonised powersystem, with its occasional use acting to balance the system andensure security of supply. The impact is expected to be small in termsof annual emissions and generation shares (meeting up to around 2%of annual electricity production in 2035). A system without the use of
unabated gas may be possible in 2035, but is likely to increase costs
and delivery risks. Ensuring that sufficient gas capacity is on the system
to accommodate a plausible range of future weather extremes (andfuture-proofed to be CCS / hydrogen-ready as far as possible) needs
to be considered now as part of a strategy for system design.
•

Decarbonising and expanding the electricity system will rapidly reduce theUK’s dependence on imported oil and gas, reducing in turn our exposure tovolatile international prices.
– Decarbonisation of the energy system, through deployment of zerocarbon generation such as wind and solar and reduced end-uses offossil fuels through electrification of buildings, transport and industry,
will lead to a rapid reduction in the UK’s demand for fossil fuels.
– However, pushing out all fossil fuel use in electricity and hydrogen
supply by 2035 currently looks implausible, given constraints on thefeasible build-out of zero carbon capacity. Even when achieving adecarbonised system by the mid-2030s, the GB electricity system will
still require significant volumes of fossil gas for use with CCS, whether inpost-combustion power plants or ‘blue’ hydrogen production to fuelhydrogen turbines. Demand for fossil gas with CCS can be expected
to reduce to 2050 as non-fossil (e.g. green) hydrogen displaces blueand energy end-uses decarbonise further.

•

Transforming the electricity system provides opportunities for growth.
Currently, over 31,000 people across the UK are employed in offshore windalone – this is set to rise to 97,000 by 2030, driven by £155 billion in private
investment, with further investment and employment in solar and onshore
wind. There are opportunities for the UK to become a global leader inemerging technologies such as floating offshore wind, which is estimated tohave the potential to deliver £43.6 billion in UK gross value add (GVA) by
2050. 2 There are also opportunities for innovation, investment andemployment across electricity storage, hydrogen infrastructure, smart
charging of electric vehicles, flexible heating systems, electricity networks
and interconnection.

Executive summary

12

The rest of this executive summary provides more detail in a number of these areas:(a) Future electricity demand(b) Reliable, resilient and decarbonised system design(c) Hydrogen supply and infrastructure(d) Reducing dependence on fossil fuel imports(e) Delivery challenges(f) Recommendations(g) This report(a) Future electricity demand
A substantially electrified economy will bring major energy efficiencies as we moveaway from wasteful fossil-fuelled technologies. Nevertheless, electricity demand is
expected to increase with the electrification of key sectors such as transport,
buildings and industry. In the CCC’s Balanced Pathway for the Sixth Carbon
Budget, there is a 50% increase in electricity demand by 2035 and a doubling inelectricity demand by 2050 (with some CCC pathways projecting as much as atrebling by 2050) (Figure 1). Alongside this, continued digitalisation is expected tofurther embed the critical role of electricity to the functioning of the UK economy.

Figure 1 Electricity demand in the Balanced
Pathway700
600

TWh per year

500
400
300
200
100
0
2010

2015

2020

2025

Buildings
Industry
Historical demand

2030

2035

2040

Surface Transport
Other
Current demand

Source: BEIS (2022) Energy Trends; CCC (2020) The Sixth Carbon Budget.
Notes: Other category includes agriculture, aviation, direct air capture and shipping.

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Delivering a reliable decarbonised power system

2045

2050

(b) Reliable, resilient and decarbonised system design
Alongside the growth in demand for electricity as we electrify energy end-uses,
supply will change too: low-cost variable renewables, especially offshore wind,should form the backbone of the future system, supplemented by a range ofcomplementary solutions.
A balanced supply mix could comprise around 70% of annual generation fromvariable renewables, complemented by around 20% from inflexible generationsuch as nuclear and BECCS and the remaining generation from low-carbon backup generation and other forms of flexibility (Figures 2 and 3). There should be norole for large-scale unabated biomass generation beyond expiry of existing subsidy
support in 2027.
The Energy Security Strategy (ESS) sets out strong ambitions for the contributions ofrenewables and nuclear, but the Government has not yet published detail on how
this generation will be complemented by low-carbon forms of flexibility to ensure areliable and resilient decarbonised system. The modelling for this report indicatesthe range and scale of investments required to achieve this.
While these ambitions entail greater weather-dependence and increased
exposure to outages due to weather extremes, our analysis shows that a
decarbonised system, with a higher degree of weather-dependent generation,
can be made both reliable and resilient. Achieving this will require careful system
planning and design, rapid infrastructure build and policy change.
It is critical that the system is designed from the outset to be resilient to extreme
weather, including low wind years and wind droughts. It is also essential to have
solutions that can cope with extended periods of low renewable generation while
continuing to meet demand. This must be informed by historical precedentalongside further research on the expected impacts of climate change:•

Having offshore wind as the backbone of the future system is beneficial, as
its average output across the year is seasonally correlated with the patternof demand – generating more in winter than in summer – particularly as weelectrify heating. However, there will be periods of low wind output, so while
there may be less need for solutions to deal with seasonal swings indemand (e.g. long-term storage) it creates a need to ensure that demandcan still be met during the occasional extended (e.g. up to multi-week)
periods of low wind generation.

•

For periods when output from variable renewables and nuclear isinsufficient to meet demand, our modelling suggests that a portfolio of lowcarbon flexibility solutions can meet the remainder of demand (i.e. ‘residual
demand’) to provide a reliable, fully decarbonised supply for the large
majority of the time (Figure 4).
– Smart shifting of demand can help to smooth peaks in demand andabsorb excess supply (e.g. through controlled timing of electric vehicle
charging, or use of heat pumps and smart appliances). The potential
for this will grow over the coming decades as the electrification oftransport and heating increases. Consumers can also be encouraged
to reduce their demand in response to price signals.
– Storage solutions will be important to take in electricity at times of
surplus and keep it for when it is needed. While batteries (including
those within electric vehicles) provide useful storage services on an

Executive summary14

hours-to-days basis, other solutions will be required to provide storage
at the multi-week scale to help manage extended lulls in wind output.
– In particular, the use of surplus generation via electrolysis to producehydrogen, in combination with its long-term storage and use inturbines as back-up capacity, looks to have an important role. This
provides power on demand in a low-carbon way, both to meet peaks
in demand and to compensate for periods of lower wind output.
– For low-carbon back-up plants with relatively high load factors (e.g.
operating for around half the hours of the year), hydrogen willcompete with use of gas plants with CCS. In this report, in order to betechnology-neutral while the relative long-run costs remain uncertain,
we combine hydrogen turbines and gas CCS plants into a category
called ‘low-carbon dispatchable’ generation.
– Interconnection of the power grid to neighbouring markets enables
imports when this is cheaper and provides a market for surplus
generation, enabling more efficient use of electricity across theEuropean system. However, there is potential for the GB system andneighbouring countries to be simultaneously impacted by weather
extremes at times, potentially limiting potential for cross-border trade.
We consider the occasional use of a small amount of unabated gas capacity (forup to around 2% of annual electricity production in 2035) to be consistent withensuring security of supply in a cost-effective manner without excessive adverse
impact on emissions. It is for Government to decide how much headroom
capacity to build into the system to account for a range of plausible future
extreme weather patterns, to ensure security of supply.

Figure 2 Electricity generation mix to 2035 in theCentral scenario
700

TWh per year

600
500
400
300
200
100
0
-100

2025
Nuclear
BECCS
Onshore wind
Dispatchable low-carbon
Net imports

2030

2035
Other
Offshore wind
Solar
Unabated gas

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Figures are before losses through the transmission and distribution system. ‘Other’ includes Combined Heatand Power (CHP) and unabated biomass. Dispatchable low-carbon includes gas CCS and hydrogen. Analysis isrepresentative of a ‘normal’ weather year.

15

Delivering a reliable decarbonised power system

Figure 3 Electricity capacity mix to 2035 in theCentral scenario
300
250

GW

200
150
100
50
0

2025

2030

Nuclear
BECCS
Onshore wind
Dispatchable low-carbon
Storage2035
Other
Offshore wind
Solar
Unabated gas
Interconnectors

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: ‘Other’ includes Combined Heat and Power (CHP) and unabated biomass. Dispatchable low-carbon
includes gas CCS and hydrogen. Analysis is representative of a ‘normal’ weather year.

Figure 4 Meeting the highest four-week period ofresidual demand in 2035 (Central scenario)
80
60

GW

40
20
0
-20
-40

1

4

7

10

13

16

19

22

25

28

Day
Electrolysis
Other
Unabated gas
Grid storage
Residual demand

Exports
Low-carbon dispatchable
Imports
Demand flexibility

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Residual demand is demand required to be met after taking account of generation from renewables,
nuclear, BECCS, and other inflexible generation. Dispatchable low-carbon generation includes gas CCS andhydrogen. Chart based on 2012 weather patterns, representing a ‘normal’ weather year.

Executive summary

16

(c) Hydrogen supply and infrastructure
In the modelling for this report, the production, storage and use of low-carbonhydrogen plays an essential role in achieving the 2035 goal of a reliable, resilient
decarbonised power system.
While the precise balance between use of hydrogen-fired turbines and fossil gas
plants with CCS in the power sector remains uncertain, some use of somehydrogen to provide on-demand power to meet peaks and back-up renewables
appears necessary. This is likely to lead to a very variable demand for hydrogen in
the power sector, necessitating the use of hydrogen storage to ensure that thenecessary hydrogen is available (Figure 5).

Figure 5 Variation across the year in daily averagehydrogen demand (2035)
40
35
30

GW

25
20
15
10
5
0

Industry

Shipping

Power - CHP

Power - CCGT/GT

Other non-power

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility; CCC analysis.
Notes: Central scenario from AFRY modelling using annual values from CCC Balanced Pathway. Building demandfor hydrogen has not been seasonally profiled as part of this modelling, and as such ‘Other non-power’ demandpresented here for 2035 is flatter than would be expected in reality. Hydrogen use for buildings in AFRY’s Central
scenario remains limited to 1.5 TWh in 2035.

Some level of hydrogen use is also necessary in the wider economy, todecarbonise applications that cannot be easily electrified such as industry andshipping (e.g. as ammonia).
There remains uncertainty around the scale of future hydrogen use in power andend-use sectors, but the volumes of hydrogen produced and used in the powersystem alone by 2035 have potential to be substantial.
•

17

Government targets for hydrogen production capacity by 2030 need to beclarified, but currently they look to be at the lower end of what may berequired for hydrogen to play a central role in providing low-carbon
dispatchable power by 2035.

Delivering a reliable decarbonised power system•We have not attempted to define the appropriate balance of hydrogenand gas CCS for low-carbon back-up capacity, but a mix of the two is likely
to be sensible. Build rates for hydrogen production seem infeasible if ahydrogen-only approach is taken, while a portfolio approach would help tomanage risks relating to delivery of technologies that have not yet beencommercially deployed. Strategic decisions around infrastructure build
which determine the deliverable balance of hydrogen and gas CCS are
required urgently.

•

It appears implausible that all UK hydrogen demand could be met fromdomestic non-fossil production by 2035, given likely limits on the rate at
which renewable generation capacity can feasibly be built. Zero-carbon
electricity must be prioritised for displacing unabated fossil generation andmeeting increasing demands from electric vehicles and heat pumps.
Hydrogen production can require significant water use – if hydrogenproduction is located in regions projected to be at risk of water stress infuture (typically the south and east of England) water availability may also
be a constraint on how much hydrogen can be produced, particularly attimes of drought.

•

Hydrogen availability therefore remains a key risk for future UK Net Zeroscenarios with high levels of hydrogen use outside of the power system (e.g.
scenarios with extensive use of hydrogen for heat in buildings). It is likely thatany additional energy for this extra hydrogen use would need to beimported, whether through increased imports of fossil gas for blue hydrogenproduction with CCS or through imported renewable energy. For thesescenarios to be viable, it would need to be clear that hydrogen with
sufficiently low lifecycle emissions can be sourced at the necessary scale,
while not risking security of supply or excessive exposure to volatile fossil fuelmarkets.

There is an important role for Government in setting strategic direction for power
and non-power uses of hydrogen. Hydrogen infrastructure will be required
regardless of decisions in 2026 on its use for buildings heat – the Government
should identify a set of low-regret investments that can proceed now and fasttrack business models to deliver it.

(d) Reducing dependence on fossil fuel imports
The UK is already a net importer of fossil gas, and production is projected tocontinue to fall over coming decades. A key aim of the ESS is to reduce the UK’s
dependence on imported oil and gas, thereby reducing exposure to volatileinternational prices. The Government has set a target for the UK to be a net energy
exporter by 2040.
The decarbonisation of the electricity system, together with its expansion to meet
new demands through electrification of transport, buildings and industry, will cut
the UK’s fossil fuel consumption rapidly, at a similar rate to the decline inproduction.
The UK will therefore continue to be a net importer of fossil gas over coming
decades. Supplies of gas from UK production are expected to be insufficient tomeet even falling demands for gas in existing uses as we decarbonise: buildings,
industry – including as a chemical feedstock – and unabated use in electricity
generation, until the late 2040s (Figure 6).

Executive summary

18

Further fossil gas demands on top of these uses (in new facilities with CCS forenergy production, whether of electricity or hydrogen) will increase the amount ofgas imports by a corresponding amount. Uses of fossil gas with CCS can therefore
effectively be considered to be using imported gas.
Reducing our reliance on gas imports and becoming an overall net exporter ofenergy depends on building out a large amount of zero-carbon generation
capacity, as well as pursuit of energy efficiency and efficient electrification acrossthe buildings, industry and transport sectors. Using hydrogen in place of efficientelectrification (e.g. instead of heat pumps for buildings) would be a much lessefficient use of domestic energy resources, leading to greater need for imported
energy to supplement them.
The modelling for this report does not include the potential for hydrogen to be
produced from non-grid-connected green hydrogen production in the UK or for
extra green hydrogen to be supplied via imported energy. To the extent that this ispossible, the UK’s reliance on imports of fossil gas can be reduced.

Figure 6 Annual GB gas usage in the Central
scenario and our Balanced Pathway (TWh)800
700

Gas demand (TWh)

600
500
400
300
200
100
0
Hydrogen

2025
Power

2030
Industry

2035
Buildings

2040

2050

Projected North Sea Gas Production

Source: AFRY Central Scenario, CCC (2020) Sixth Carbon Budget Balanced Pathway; NSTA (2022) August 2022 oiland gas production projections.
Notes: Gas demands in buildings and industry taken from the CCC’s Balanced Pathway; those for power andhydrogen are taken from AFRY’s Central scenario modelled for this report.

19

Delivering a reliable decarbonised power system

(e) Delivery challenges
Delivering a decarbonised electricity system by 2035 is a critical national delivery
milestone for Net Zero. Delivery and deployment of infrastructure must be
achieved at a much greater pace than the present regulatory, planning andconsenting regimes can achieve.
Infrastructure build rates in a number of areas represent large increases on current
capacity (Figure 7) and need to exceed what has been achieved historically. The
Government plans to increase offshore wind capacity by four times over current
levels by 2030, and solar by five times by 2035. While the build rate this implies forsolar remains close to historical peak, for offshore wind it implies annual build rates
around 40% higher than emerging data on the 2022 peak. On nuclear,
Government has ambitions to increase investment dramatically relative tohistorical levels.

Figure 7 Zero-carbon capacity in the scenarios(2035)
80
70
60

GW

50
40
30
20
10
0

NuclearCurrent capacity

Onshore wind

Offshore wind

Sixth Carbon Budget

Solar

Energy Security Strategy

Source: BEIS (2022) Energy Trends Table 6.2, BEIS (2022) Digest of UK Energy Statistics Table 5.11, BEIS (2022) British
Energy Security Strategy, CCC (2020) The Sixth Carbon Budget, CCC analysis.
Notes: ESS nuclear capacity ambition is for up to 24 GW by 2050 with one project to final investment decision thisParliament and two in the next; deployment therefore assumed to be relatively backloaded and follow CCC
Balanced Pathway in the medium-term. No ESS bar shown for onshore wind as no firm capacity commitment.
Offshore wind ambition in ESS is up to 50 GW by 2030.

Executive summary

20

The network and storage infrastructure needed to support a decarbonised system
will also be very significant, with build required for the transport and storage ofelectricity, hydrogen and CO2.
•

For instance, the scale of transmission reinforcement needs continues to beassessed by National Grid. It has stated that, in order to support theGovernment target of up to 50 GW of offshore wind by 2030, in the next
seven years it will have to install more than five times the amount oftransmission infrastructure in England and Wales than has been built in thelast 30 years. 3 The requirements in Scotland will add to this further. *•The analysis undertaken for this report found that in order to facilitate thedelivery of the decarbonised system, all the electricity transmission network
boundaries examined would be expected to require some level ofreinforcement, with an average doubling of their capability required
between 2025 and 2035.

The transition will also require a number of technologies that have not yet been
deployed commercially in the UK to be brought to significant commercial scale,including CCS, low-carbon hydrogen production and storage, and hydrogenfuelled generation.
This will not be achieved without a strategic programme of reform, making
regulatory frameworks and market design fit for purpose and capable ofgalvanising the £300-430 billion of investment required, while also removing
significant barriers such as in the planning and connections processes.
It is imperative that resilience to the effects of climate change is built into this asset
investment programme from the start. Much of the UK’s Net Zero electricity system
is yet to be built and requires significant additional investment to replace many
existing generation assets as well as significantly expand the system. During thisrenewal of the electricity system capital stock it is vital that the system and assets
are built to be sufficiently resilient to future climate conditions. This will requireappropriate governance arrangements for resilience, systematic risk assessment(underpinned by further research and reporting) and appropriate resilience
standards across the system. If climate resilience is neglected in this investment,
there is significant risk of locking in increased climate vulnerability or additionalcosts later on.

(f) Recommendations
In assessing the path from here to a reliable, resilient, decarbonised system by
2035, it is clear that actions in a wide range of areas are required. While some arein train and on track, others need to be accelerated. There are also gaps in thecurrent set of actions, and roles and responsibilities in delivering the system needclarification. Below we set out summaries of our recommendations, with fullrecommendations set out in the course of the report (Table 1).

*

21

The transmission network is the higher-voltage network for long-distance transfer of power, distinct from the
distribution network which is the lower-voltage local network.

Delivering a reliable decarbonised power system

Table 1
Recommendations
Location

Priority recommendations

Owner (Timing)

Ch 2, Section 3

Publish a comprehensive long-term strategy for the delivery of a decarbonised,resilient, power system by 2035.

DESNZ (2023)

Ch 4, section 2(d)Set out, in NAP3, the Government’s vision for what a well-adapted and climateresilient energy system will look like.

Defra (2023)

Ch 2, section 3(a)Clarify urgently and formalise the institutional responsibilities of the FSO, Ofgemand Ministers, for strategic planning and delivery of the decarbonised, resilientsystem.

DESNZ (2023)

Ch 4, section 2(d)Conduct a review of governance arrangements for resilience to climate hazards
in the energy system, to ensure they are fit for the new expanded and morediverse low-carbon system given increasing societal reliance on electricity.

DESNZ, Ofgem(2024)

Ch 2, section 3(a)Develop a long-term cross-sectoral infrastructure strategy to adapt and build
respectively the distribution of liquid and gaseous fuels, electricity, CO2 and heat
networks over the next decade.

DESNZ, FSO (by2025 at thelatest)

Ch 2, section 3(a)Identify a set of low-regret electricity and hydrogen investments that canproceed now.

DESNZ, FSO (by2024 at thelatest)

Ch 2, section 3(a)Create a Minister-led infrastructure delivery group, advised by the new Electricity
Networks Commissioner, to ensure enabling initiatives for energy infrastructurebuild are taken forward at pace, and necessary policy changes are
implemented across the UK, to deliver a decarbonised and resilient powersystem by 2035.

Electricity
Networks
Commissioner,
UK, Scottish &WelshGovernments(2023)

Ch 2, section 3(b)Through the Review of Electricity Market Arrangements, develop a strategy assoon as possible on market design for the medium- to long-term for a fully
decarbonised, resilient electricity system in the 2030s and onwards.

DESNZ (2023)

Ch 3, section 2(e)Finalise funding mechanisms and allocate funding to support the developmentof 10 GW of low-carbon hydrogen production by 2030.

DESNZ (2023)

Ch 3, section 3(c)Fast-track the development of new business models for hydrogen transportationand storage infrastructure, with a view to keeping options open for larger scalehydrogen use by 2030.

DESNZ (2023)

Ch 1, section 2

Identify and address potential key supply chain bottlenecks for delivering up to
50 GW of offshore wind by 2030.

DESNZ (2023)

Ch 1, section 2

Ensure that large-scale unabated biomass power plants are converted to
BECCS as early as feasible, and are not given extended contracts to operateunabated at high load factors beyond 2027.

DESNZ (2023)

Chapter 1

Executive summary22

Location

Priority recommendations

Owner (Timing)

Ch 2, section 2

Ensure new gas plant are genuinely CCS- and / or hydrogen-ready as soon
as possible and by 2025 at the latest.

DESNZ (2025 at
the latest)

Ch 2, section 2

Ensure that future system design explicitly plans for the range of climate hazards
that will face the energy system over its lifetime.

DESNZ, Ofgem,
FSO (ongoing)

Ch 2, Section 3

Publish the second transitional Centralised Strategic Network Plan, identifying thestrategic investments required for a decarbonised and resilient electricity system
in 2035 and delivery of Net Zero.

ESO/FSO (2023)

Ch 3, section 2(e)Finalise and deliver the CCUS Transport and Storage Regulatory Investment
business model, consistent with the Government's ambition to establish at least
two CCS transport and storage clusters in the mid-2020s.

DESNZ (Q12023)

Ch 3, section 2(e)De-risk the future Carbon Capture and Storage project pipeline by launching
the next cluster selection process as soon as possible.

DESNZ (Q12023)

Ch 3, section 2(e)Publish a plan for CO2 transport from dispersed sites.

DESNZ (2023)

Ch 3, section 3(c)Publish a site-specific plan for distribution and storage of hydrogen and otherlow-carbon infrastructure outside of clusters.

DESNZ (Q12023)

Ch 4, section 1(c)Commission further research to improve understanding of how climate change isaltering key weather hazards that will impact the energy system.

DESNZ, UKRI,
Defra (ongoing)

Ch 4, section 1(c)Coordinate a systematic assessment of risks posed from cascading impacts
across multiple sectors due to failures of the decarbonised energy system as partof the next round of the Adaptation Reporting Power.

Defra (2025)

Ch 4, section 1(c)Require all energy system organisations to report under the Adaptation
Reporting Power.

Defra (2023)

Ch 4, section 2(a)Develop a pathway to setting appropriate minimum resilience standards (bothat asset and system level) to relevant climate hazards identified in the UK
Climate Change Risk Assessment (CCRA), covering all relevant parties.

DESNZ, Cabinet
Office (by 2028
at latest)

Ch 4, section 2(d)Designate Ofgem and parties responsible now and in the future (including the
new Future System Operator) for the maintenance of energy sector codes andstandards, with a clear mandate to ensure climate and weather resilience.

DESNZ, Ofgem(2024)

Ch 4, section 2(d)Extend requirements for reporting on outages to include the cause, duration andmagnitude of all outages.

Ofgem, DESNZ(2024)

Chapter 2

Chapter 3

Chapter 4

23

Delivering a reliable decarbonised power system

(g) This report
In the Sixth Carbon Budget, the Committee recommended that electricity supply
should be fully decarbonised by 2035, subject to ensuring security of supply. The
Government subsequently adopted this commitment as part of their Net Zero
Strategy.
The Government’s Energy Security Strategy (ESS) set out strong ambitions for thecontributions of renewables and nuclear. Taking the Government’s Energy Security
Strategy (ESS) as the starting point, this report considers:•

What mix of further solutions will be needed to run a secure, reliable andresilient decarbonised electricity system by 2035, taking account of thepotential for future electrification of sectors such as transport and homeheating.

•

Several of the wider enabling factors required, including network andsystem planning and changes to the design of electricity markets.

•

The implications of a decarbonised electricity system for hydrogen use, how
it is produced and the infrastructure required to support it.

•

How to manage climate-related risks to the energy system, given theincreasing dependence of the future economy on clean electricity.

•

Delivery risks and the actions needed to address them.

The report is organised in four chapters:
1. Setting the context for the future power system
2. Delivering a reliable decarbonised power system
3. Implications for hydrogen production, use and infrastructure
4. The need for climate resilience

Executive summary24

Endnotes
1 BEIS (2021) Net Zero Strategy: Build Back Greener,

https://www.gov.uk/government/publications/net-zero-strategy
2 Offshore Renewable Energy Catapult (2021) Industrial leadership – unlocking the UK’s floating

wind potential, https://ore.catapult.org.uk/?orecatapultreports=industrial-leadershipunlockinguks-floating-wind-potential
3 National Grid (2022) 2022/23 Half Year Results Statement,

https://www.nationalgrid.com/document/148586/download.

25

Delivering a reliable decarbonised power system

Chapter 1

Setting the context for the future
power system
1. Historical trends in demand and emissions

29

2. Future changes to demand and supply

31

27

Chapter 1: Setting the context for the future power system

Introduction
The decarbonisation of the electricity system has been one of the biggest
successes in UK decarbonisation to date, with rapid progress made in reducing
emissions from electricity supply. Emissions have fallen by 69% since 2010, largely
reflecting a move away from coal and the success of developing offshore wind asa cheap and scalable form of zero-carbon generation. Over this period,
considerable advances have also been made in understanding how adecarbonised electricity system can be delivered and operated – and this is now
within grasp.
In this chapter we set out progress to date, before looking ahead to the expectedchanges in demand and zero-carbon supply as we transition to a resilient Net Zeroeconomy by 2050.
We set out our analysis in this chapter in two sections:
1. Historical trends in demand and emissions
2. Future changes to demand and supply

Chapter 1: Setting the context for the future power system28

1. Historical trends in demand and emissions
UK emissions from electricity
have fallen by 69% since 2010,reflecting improved energy
efficiency and a move awayfrom coal.

UK electricity demand and emissions have both fallen since 2010, by 13% and 69%
respectively, largely reflecting improved energy efficiency and a move away fromcoal:•

Coal was replaced by gas in the 1990s and by renewables in the 2010s,
such that it now only represents 2% of electricity generation (Figure 1.1). The
Government has committed to phasing out its use by the end of 2024. Lowcarbon generation has grown significantly over the last decade and is now
over half of annual electricity generation. As a result, the emissions intensityof electricity generation has fallen to 200 gCO2/kWh in 2021, a reduction of
60% since 2010.

•

In addition, UK electricity demand has been falling by around 1% per year
over the past decade, and is now 13% lower than in 2010. A key reason forthis is the continued improvement and uptake of energy-efficient
appliances and lighting.

•

The combination of decreasing emissions intensity and falling demand has
resulted in a reduction in emissions of 69% from 2010 to 2021 (Figure 1.2).

Figure 1.1 Historical electricity generation mix
90%

Share of generation

80%
70%
60%
50%
40%
30%
20%
10%
0%
1990

1995

2000

Coal
Source: BEIS (2022) Energy Trends; CCC analysis.

29

Delivering a reliable decarbonised power system

2005
Gas

2010

2015
Low-carbon

2020

Figure 1.2 Historical emissions from electricity
supply180
160

MtCO2e per year

140
120
100
80
60
40
20
0
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Source: BEIS (2022) Provisional UK greenhouse gas emissions national statistics 2021; BEIS (2022) Final UK greenhousegas emissions national statistics: 1990 to 2020; CCC analysis.

Chapter 1: Setting the context for the future power system30

2. Future changes to demand and supply(a) Future demand for electricity
In the future, overall energy
demand is expected to fall, but
electricity demand is projected
to rise as we electrify the
economy - rising 50% by 2035
and doubling by 2050.

This, alongside continued
digitalisation, will drive greater
economic and strategic
dependence on a secure,reliable and resilient electricity
supply.

In the future we expect overall energy demand to fall, but electricity demand toincrease significantly as key sectors switch from fossil fuels to electricity. Our Sixth
Carbon Budget analysis included a range of scenarios reflecting different patternsof electrification of the economy out to 2050, consistent with Net Zero.
•

The Balanced Pathway scenario, upon which the budget was based, has
annual electricity demand around 50% higher than pre-Covid levels in 2035
and around 100% higher by 2050 (Figure 1.3), incorporating theelectrification of surface transport, heating, and industry.

•

The forms of electrification included in the Sixth Carbon Budget Balanced
Pathway scenario are typically very efficient compared to their fossil fuelequivalents. Total energy demand in the Balanced Pathway falls by arounda third by 2050, and by up to half in other scenarios, reflecting thisefficiency improvement as well as some reductions in demand.

Electrification of the economy to this extent, alongside continued digitalisation, will
drive greater economic and strategic dependence on a secure, reliable andresilient electricity supply.
There is the potential for further use of decarbonised electricity beyond that
included in the Balanced Pathway, such as electrolytic hydrogen production atscale, powering direct air capture of CO2 and production of synthetic aviation
fuels. These could become feasible with significant further falls in the costs of zerocarbon electricity (e.g. a further halving compared to today’s costs of wind andsolar). Our Widespread Innovation scenario, which assumes such cost reductions
and deployment of less-efficient electricity-based decarbonisation, has electricity
consumption reaching three times current levels by 2050.

31

Delivering a reliable decarbonised power system

Figure 1.3 Electricity demand in the Balanced
Pathway700
600

TWh per year

500
400
300
200
100
0
2010

2015

2020

2025

2030

Buildings
Industry
Historical demand

2035

2040

2045

2050

Surface Transport
Other
Current demand

Source: BEIS (2022) Energy Trends; CCC (2020) The Sixth Carbon Budget.
Notes: Other category includes agriculture, aviation, direct air capture and shipping

Alongside the changes in demand that we can expect to see from electrification
as we decarbonise, demand will also be affected by the changing climate. The UK
climate is set to change over the period to 2050, regardless of UK progress towards
Net Zero. Hotter, drier summers and warmer, wetter winters will be more likely andtemperature extremes will become more intense and frequent in the decades to2050. Significant cold events in winter will remain possible. 1
Demand will also be affectedby the changing climate, withan increased demand forcooling in summer and a likely
reduction in heat demand in
winter.

Some of the changes in climate and weather patterns will drive changes in energy
demand, including an increased demand for cooling in summer and a likely
reduction in demand for heating in winter. These changes are not expected to besignificant in the context of overall demand, and have been accounted for in our
Sixth Carbon Budget analysis which has in turn informed the modellingunderpinning this report:•

In our Sixth Carbon Budget analysis, we assume increases in average wintertemperatures to 2030 result in a 6.6% reduction in demand for spaceheating (before consideration of changes in energy efficiency and heating
technologies).* We hold this reduction constant from 2030 to 2050.† Later inthe century, and particularly under higher levels of global warming,
reductions could be significantly greater.‡,2*

Based on the average from an ensemble of UK regional climate projections, using Met Office analysis of Heating
Degree Day data derived from the 2018 UK Climate Projections, calculated for a 15.5°C threshold and based on the
RCP8.5 pathway – note that the outputs are similar for any emissions scenarios before 2050 (Riahi et al 2007).

†

Our residential heat analysis is based on an assessment of end state technology mixes in 2050, which are thendeployed over the trajectory to 2050. While further warming after 2030 is expected, we hold the heat demand
reduction constant to ensure that the technologies deployed in our modelling are able to meet the heat demands
expected from 2030 onwards.

‡

For example, Heating Degree Days (the number of days with average air temperatures below 15.5°C) – which is a
proxy for heating demand - are projected to fall by 10% below the average of 2000-2017 at a global warming levelof 2°C above pre-industrial levels, 20% at 3°C and 30% at 4°C when averaged across the UK as whole.

Chapter 1: Setting the context for the future power system32•Despite these changes, future electricity demand is still likely to be highest
in winter, as is the case today (Figure 1.4).
– Electricity consumption for heating in the Balanced Pathway adds
around 45 TWh to annual electricity demand in 2035, an addition
equivalent to 16% of total current UK electricity consumption.
– Electricity demand for air conditioning remains likely to be smaller thanthe demand for heating. While our Balanced Pathway assumes 5 TWhof new demand for cooling in residential buildings by 2050, it includes
around 145 TWh demand for heat pumps to heat buildings. *,3Heatwaves will have potentially serious impacts on health and productivity(around 3,000 excess deaths were linked to raised temperatures in 2022 – almost
exclusively in people aged over 65), and also driving economic costs associatedwith heat-related mortality and illness. †,4,5
It will therefore be important that increased mechanical cooling in residential andnon-residential buildings features in Government plans for adapting the UK tohigher temperatures, along with passive cooling, behaviour change andemergency response plans. It is expected that it will largely fall to homeowners andoccupants to pay for this (passive and mechanical) cooling, although publicfunding may be required for those in areas of high climate risk and low incomes. 6

33*

Cooling demand assumption aligned with Energy Systems Catapult’s projections, based on an increase in energy
demand for cooling calibrated to levels for households in EU countries which currently experience similar levels of
Cooling Degree Days to those predicted for the UK in 2050. Some estimates remain higher – a recent study by BEIS
estimated between 6-12 TWh pa of additional power demand for cooling in summer, in low and high emissions
scenarios, see BEIS (2021) Cooling in the UK: Research Study. Given their scale, heat demand has been seasonallyprofiled but additional demand for air conditioning has not.

†Despite a limited UK-specific evidence base, one study suggests that a 2°C warming trajectory could cost around
0.4% of economic output for London in a warm year due to a reduction in productivity.

Delivering a reliable decarbonised power system

Figure 1.4 Seasonal electricity demand in 2019and 2035
1800
1600

GWh per day

1400
1200
1000
800
600
400
200
0

SpringSummer2019

AutumnWinter2035

Source: BEIS (2022) Energy Trends; CCC (2020) The Sixth Carbon Budget; AFRY (2023) Net Zero Power and Hydrogen:
Capacity Requirements for Flexibility.
Notes: Winter includes January, February and December. Spring: March, April and May. Summer: June, July andAugust. Autumn: September, October and November. Given their scale, heat demand has been seasonallyprofiled but additional demand for air conditioning has not.

(b) A low-carbon technology mix(i) The need for bulk low-carbon generation
In the future, demand will be
met primarily by renewables,with a role for nuclear
alongside this. Significant
expansion is planned, at rates
faster than have beenachieved before.

In the future we expect electricity demand to be met primarily through bulk
zero-carbon generation at scale,* with variable renewables forming the
backbone of the system as the cheapest form of low-carbon electricity
generation. Significant expansion of these technologies is planned (Figure 1.5):•

Variable renewables (i.e. wind and solar) are now the cheapest form ofelectricity generation, given cost reductions over the past decade. The
Government has significant expansion plans.
– The most recent auction results for low-carbon contracts delivered
prices for offshore wind, onshore wind and solar ranging from £37
to £46/MWh.† We have assumed the same (relatively conservative)
potential for future cost reduction as in our Sixth Carbon Budget
Balanced Pathway scenario, to around £35/MWh in 2050 acrossvariable renewable technologies.

*

Generation, quoted in TWh, measures the output from a given level of capacity, quoted in GW. This varies bytechnology depending on load factor (i.e. what proportion of total hours in the year it generates for). For example,
solar has a load factor of around 10% reflecting that it is sunniest around midday and does not generate overnight,
whereas nuclear has a load factor of around 90% reflecting that it is relatively inflexible.

†

In 2012 prices. As with levelised costs, these do not reflect the wider costs of integrating variable renewables into theelectricity system (e.g. for system infrastructure and flexible back-up). These costs might add £10-20 per MWh (seesection on BECCS below). The modelling for this report was undertaken on a system-wide basis meaning that thesecosts are fully incorporated in the analysis (see Box 2.1).

Chapter 1: Setting the context for the future power system34

– The Government plans to increase offshore wind capacity by fourtimes over current levels by 2030, and solar by five times by 2035. On
average this requires 4.5 GW per year of offshore wind to be installed
and 4.3 GW per year of solar.
– These build rates remain above historical annual peak build rates, with
4.1 GW of solar having been achieved historically and emerging datasuggesting 2022 was a record year for offshore wind deployment at 3.2
GW. 7 Around 100 GW of offshore wind is in the pipeline, including 14
GW under construction or with support secured for a route to market.
Concerted action will be required to deliver this, including on
removing supply chain bottlenecks and improving network
connections (e.g. through progressing the work of the Offshore
Transmission Network Review).
– Other renewables (e.g. tidal) may be able to play a role but are
currently relatively expensive.
Recommendation

Owner (timing)

Identify and address potential key supply chain bottlenecks for delivering up to 50 GW of offshore
wind by 2030, including for investment in ports, adequate vessel capacity, manufacturing
capability and floating wind. Take opportunities to link supply chain action to key decision points inoffshore leasing and Contract for Difference auctions.

DESNZ (2023)•

Nuclear can provide valuable zero-carbon generation at scale. While it isrelatively expensive on a levelised cost basis * and has a relatively inflexible
supply profile, it could have a role in hydrogen production (which in turncan support system flexibility) and the provision of other system services. The
Government is aiming to bring forward new projects, and funding
innovative new types of nuclear.
– The new nuclear plant Hinkley Point C, which is currently underconstruction, has a low-carbon contract for around £90/MWh (in 2012
prices). As in the Balanced Pathway, in the longer-term we assume
costs for new plants could fall by around one-third to £60/MWh,broadly in line with the nuclear sector deal ambition.
– The Government aims to take one project to a final investment
decision this Parliament, and two projects in the next Parliament. They
are setting up a new body, Great British Nuclear, to help deliver this,and providing funding for new nuclear technologies including small
modular reactors (SMRs) and advanced modular reactors (AMRs). The
Balanced Pathway assumes two of these projects are online by 2035.
To the extent this is not feasible, additional generation would be
required from a combination of other low-carbon sources.

*

35

And noting offshore wind would still be competitive in comparison to nuclear even after system integration costs aretaken into account.

Delivering a reliable decarbonised power system

Figure 1.5 Zero-carbon capacity in the scenarios(2035)
80
70
60

GW

50
40
30
20
10
0

NuclearCurrent capacity

Onshore wind

Offshore wind

Sixth Carbon Budget

Solar

Energy Security Strategy

Source: BEIS (2022) Energy Trends Table 6.2; BEIS (2022) Digest of UK Energy Statistics Table 5.11; BEIS (2022) British
Energy Security Strategy; CCC (2020) The Sixth Carbon Budget; CCC analysis.
Notes: ESS nuclear capacity ambition is for up to 24 GW by 2050 with one project to final investment decision thisParliament and two in the next; deployment therefore assumed to be relatively backloaded and follow CCC
Balanced Pathway in the medium-term. No ESS bar shown for onshore wind as no firm capacity commitment.
Offshore wind ambition in ESS is up to 50 GW by 2030.

(ii) The role for biomass with carbon capture and storage(BECCS)
Sustainable bioenergy withcarbon capture and storage is
expected to play a role,running inflexibly on a similarbasis to nuclear.

BECCS from sustainable feedstocks provides both decarbonised electricity
generation and a form of engineered greenhouse gas removals. BECCS is
expected to run inflexibly, similarly to nuclear, due to its relatively high capitalintensity and the value of the removals it provides alongside the electricity.
Subsidies for large-scale unabated biomass generation were put in place early inthe last decade, at a time when costs of low-carbon generation from a range ofsources were relatively high, and when there was an opportunity for coal units tobe converted to burn sustainably-sourced biomass. This was appropriate as aninterim measure, but sustained use of large-scale biomass generation is notcompatible with the path to Net Zero.
Unabated biomass generation is counted as zero-emission at the point of use, buteven sustainable biomass supplies have significant lifecycle greenhouse gas
emissions. Furthermore, large-scale biomass plants are large point-sources of CO2
emissions, which provides an opportunity for conversion to BECCS plants. Such a
conversion provides a very good use of finite sustainable biomass supplies inclimate terms (Box 1.1).

Chapter 1: Setting the context for the future power system

36

Due to constraints onsustainable supply and highcosts, unabated biomass
should not be part of the leastcost decarbonised electricity
system which should be largelyin place by 2030.

In addition to constraints on the supply of sustainable biomass, the relatively highcosts of unabated biomass generation compared to other low-carbon forms ofgeneration mean that unabated biomass is not part of a least-cost decarbonised
electricity system that should be very largely in place by 2030. The existing lowcarbon contract for unabated biomass generation has a price of £100/MWh (in2012 prices). As a form of bulk decarbonised generation, unabated biomass is
considerably more expensive than wind and solar, even after allowing for the
additional costs of managing their variability, which might add £10-20 per MWh ofrenewable generation. 8
Unabated biomass capacity could, in principle, be used at low load factors to
support the operation of variable renewables. However, existing biomass plants
currently have a subsidy regime that encourages them to run for as many hours as
possible rather than operating flexibly in a back-up role.
The CCC’s Balanced Net Zero Pathway, which underpinned our recommendations
on the 2030 Nationally Determined Contribution to the UN process and the Sixth
Carbon Budget, sees existing unabated biomass capacity switching over to using
CCS (i.e. becoming BECCS) in the second half of the 2020s. Over the period to2050, biomass supplies switch largely to UK-grown feedstocks. In the Government’s
Net Zero Strategy, at least 5 MtCO2 is being removed from the atmosphere andstored annually by 2030 and around 80 MtCO2 annually by 2050.
At the time of writing, we have not yet seen the Government’s Biomass Strategy,
which was due by the end of 2022. We expect this to confirm the important role for
BECCS, with sustainable feedstocks, in reaching UK Net Zero, and an increasing
share of UK feedstocks over time.
The Energy Prices Act gave the Government powers to award Contracts forDifference (CfDs) to existing generators. These powers should not be used in a waythat extends subsidies for large-scale unabated biomass electricity generation atvery high load factors beyond the scheduled expiry of existing Renewables
Obligation and CfD support in 2027.

Recommendation

Owner (timing)

Ensure that large-scale unabated biomass power plants are converted to BECCS as early as
feasible, and are not given extended contracts to operate unabated at high load factors beyond
2027.

DESNZ (2023)

Large-scale unabated biomass
power plants should be
converted to BECCS as early as
feasible, and should not be
operating at high load factors
beyond 2027.

Box 1.1
The role for BECCS in the transition to Net Zero
The CCC considered the best uses of biomass in our 2018 Biomass report, as did BEIS in its
2021 Biomass Policy Statement. Both reviews concluded that the use of finite sustainablebiomass for unabated electricity generation (i.e. without CCS) is not appropriate on along-term basis, and that it is important to develop domestic biomass supply chains.
•

37

Sustainable sources of biomass are finite, so the use of biomass must be limited andfocused on those applications that maximise its contribution to Net Zero. In the 2010s,
this was achieved by using biomass to displace coal generation, through converting
coal units to biomass. However, by the second half of this decade, once coal has
been phased out and CCS infrastructure is available, the best use of sustainablebiomass resources will shift to using bioenergy with CCS (BECCS), for a range ofapplications (e.g. power generation, hydrogen production, aviation fuel production)(Figure B1.1).

Delivering a reliable decarbonised power system

•The UK should also shift from relying primarily on imported biomass for power
generation to developing domestic supplies as much as possible. It is challenging toensure that biomass imported to the UK meets the necessary sustainability standards,
given the lesser regulatory oversight that is possible around land use and forest
management in other countries. Internationally tradable sustainable solid biomass
resources are also finite, so a substantial UK dependence on imports would risk taking
more than a fair share of this valuable global decarbonisation resource. In turn, as
countries pursue Net Zero, competition for finite sustainable biomass could drive up
international biomass prices, meaning that biomass imports become increasingly
expensive over the period to 2050.

Although combustion of biomass is accounted for as carbon-neutral under standard
greenhouse gas accounting rules, biomass does have significant other emissions whenlooking across the full supply chain. Estimates of the lifecycle emissions of unabatedbiomass generation in the UK, submitted by generators to Ofgem, are typically around
125 gCO2e/kWh (on a scope that excludes any emissions relating to changes in forest
carbon stocks). This is considerably higher than the lifecycle emissions of wind, solar andnuclear generation, which are no higher than 35 g/kWh for wind, nuclear and most formsof solar PV generation. Fitting CCS to biomass plants would mean that these plants
provide net removals of CO2 from the atmosphere. While the costs of generation will behigher than for unabated biomass, the emissions benefits of capturing and storing theCO2 make baseload BECCS plants a justifiable part of a decarbonised electricity systemprovided the biomass is sourced in a sustainable way.

Figure B1.1 Estimated GHG abatement peroven dried tonne of biomass across different
applications
Industrial uses with CCS(displacing gas with CCS)
Industrial uses with CCS(displacing coke/coal with CCS)
Hydrogen with CCS(displacing gas reforming with CCS)Electricity with CCS(displacing low-carbon generation)
Aviation biofuels with CCS(displacing fossil kerosene)
Car biofuels with CCS(displacing electric vehicles)

Industrial uses
(displacing coke & coal)
Aviation biofuels(displacing fossil kerosene)

0.0

1.0

2.0

3.0

tCO2e/MWh
CO₂ sequestered

CO₂ displaced

Source: CCC (2018) Biomass in a low-carbon economy.
Notes: This chart shows estimates of GHG abatement provided by an oven-dried tonne of biomass used invarious sectors, considering the most appropriate counterfactual (i.e. what we would expect it to be
displacing, long-term). We have shown abatement broken down by sequestered carbon (the amount of CO₂
stored and/or not released into the atmosphere due to CCS technology) and displaced carbon (the amountof CO₂ that would have been emitted to the atmosphere in the counterfactual case had biomass not beenused). The underlying calculations do not include biomass lifecycle emissions.
Source: Ofgem (2022) Biomass Sustainability Dataset 2021-21 (https://www.ofgem.gov.uk/publications/biomasssustainability-dataset-2020-21); UNECE (2021) Life Cycle Assessment of Electricity Generation Options((https://unece.org/sites/default/files/2021-10/LCA-2.pdf); CCC (2018) Biomass in a low-carbon economy.

Chapter 1: Setting the context for the future power system38

(iii) The role for low-carbon flexibility
In order to deliver a reliable
and resilient system, thisinflexible low-carbon
generation will need to becomplemented by low-carbon
flexibility, which will play anincreasingly important systemrole.

Given the relative inflexibility of variable renewables and nuclear generation, thesewill need to be complemented by various forms of flexibility, in order to manage
the electricity system over the necessary timescales (see Chapter 2).
The role of bulk non-fossil fuel generation will grow over time. Over the rest of thisdecade, its main role will be displacing unabated gas-fired generation andreducing emissions from the power sector. Over time, and especially beyond 2035,
the primary role for additional capacity will be meeting new demands forelectricity as the economy further electrifies, reducing emissions in the transport,
buildings and industry sectors.
A shift towards variable renewables in providing the majority of electricity has
implications for the energy system:•

The variable nature of renewable generation means that flexibility will
become increasingly important across a range of timescales:– Short-term variability. On the scale of minutes to hours, fast response
flexibility will be important to manage predictable fluctuations inweather patterns. These fluctuations may be correlated with demand
to a certain extent (e.g. solar generation and cooling demand in the
middle of the day).
– Medium-term variability. On daily to weekly timescales, planning forflexibility will be needed to manage longer-lasting weather
fluctuations (e.g. wind droughts) and for the possibility that these might
be more intense and frequent in future.
– Longer-term variability. Monthly to yearly variability (e.g. in windspeeds) is possible given weather patterns, affecting the amount of
production required from other sources. Seasonal variability ispotentially less of an issue in future given the correlation of offshore
wind generation with seasonal demand patterns (i.e. both are highest
in winter, see Figure 1.6), although some planning will still likely berequired given the dependence of the economy on variablegeneration.

•

Power from variable renewables will start to exceed demand. Ourmodelling suggests that the Government’s ambitions for variable
renewables will mean that the power available from renewables exceeds
demand in around one-third of hours in 2035.
– The demand required from other sources in these periods will be
negative, and there will no longer be a positive minimum level ofdemand that would allow other generation to run continuously asbaseload.
– To complement the variability of a very large capacity of renewables,
other sources of power must be capable of running flexibly, with theability to ramp output up and down and be easily shut down and restarted, if surpluses during high wind periods are to be managed.

39

Delivering a reliable decarbonised power system

Figure 1.6 Seasonal demand and renewablegeneration in 2035
1600
1400

GWh per day

1200
1000
800
600
400
200
0

SpringSummerOffshore wind
Solar

AutumnWinterOnshore windElectricity demand

Source: CCC (2020) The Sixth Carbon Budget; AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements
for Flexibility.
Notes: Figure shows renewable generation in 2035 based on the modelling undertaken for this report. It reflects thecapacity ambitions set out in the Government’s ESS (e.g. up to 50 GW of offshore wind in 2030). Electricity demandis based on the Sixth Carbon Budget Balanced Pathway scenario. Not all renewable generation is used to meetelectricity demand (e.g. some is used to produce electrolytic hydrogen). Winter includes: January, February andDecember. Spring: March, April and May. Summer: June, July and August. Autumn: September, October andNovember. Given their scale, heat demand has been seasonally profiled but additional demand for air
conditioning has not. Analysis is representative of a ‘normal’ weather year.

(c) Managing climate risks
A changing climate will bringincreased and new supply-siderisks for the energy system.

A changing climate will bring increased and new supply-side risks for the energy
system, which will need to be effectively managed:•

Potentially large-scale and correlated loss of wind generation during winddroughts.

•

Temporary loss of capacity due to damage from storms, winds, and floods.

•

Generation efficiency reductions and the reduction of electricity network
thermal ratings (i.e. the capacity to carry power) during heatwaves.*•

Loss of thermal generation capacity due to lack of water supply for coolingand other production processes during periods of drought.

Planning for some of these risks poses new challenges, as the evidence projectingchanges in some important weather hazards, including storms, wind strength andwind regimes, remains uncertain (Box 1.2).

*

Sagging electricity wires during heatwaves can also be dangerous to those around them under certain conditions.

Chapter 1: Setting the context for the future power system40

As the UK moves towards a significant reliance on wind for electricity generation(particularly from the North Sea), it becomes more important to understand windspeeds and wind droughts in order to operate power systems reliably.
The possibility of more frequentand severe wind droughts due
to global climate change
cannot be ruled out. Futuresystem design must therefore
plan for these, and otherclimate risks.

Wind droughts (extended periods of low-wind conditions) already occur in the UK.
For example, January 2021 saw the lowest wind speeds for at least 20 years and as
a result offshore wind generation was 16% lower than the same period a year
before. Evidence from the latest set of UK climate projections on the impacts ofclimate change on future wind speeds around the UK suggests no clear signal forsignificant change in generation potential in winter, when the most electricity isneeded and generated. These projections do show the potential for declines inwind power generation in other months, although there is a need for new
evidence to assess these risks appropriately. 9
The possibility of more frequent and severe wind droughts due to global climatechange cannot be ruled out and needs to be considered within robust planning
for a resilient future electricity system. We have therefore undertaken dedicatedanalysis on how the system should be designed to cope with low wind periods anddroughts. These are discussed further in Chapter 2.
Implications of reduced water availability depend greatly on the success ofadaptation measures by 2050 to reduce water demand (across all abstractors ofwater), improve the efficiency of the water system and find new sources of supply.
They will also depend on the electricity system pathway to Net Zero. Without
significant additional adaptation efforts there will be an increased occurrence ofdrought, constraining water abstraction for energy production, particularly inEngland and parts of Wales.
Modelling of projections in water use in electricity and hydrogen production to2050 concludes that there is considerable uncertainty in future energy sector
potential water needs at regional geographic scale. * This depends on the range ofpathways that are compatible with Net Zero by 2050 and the location of largescale hydrogen production facilities within the country. † Hydrogen production
accounts for a significant proportion of future water use.
Overall, water consumption for energy production is projected to reduce until
2025, after which it is projected to increase to 2050 as hydrogen production ramps
up. 10 In general, the modelling finds the range of use post-2035 often exceeds thatin the 2018 baseline year. Given projected constraints on future water availability
due to climate change, this is an area of significant concern. It is essential thatwater availability considerations are reflected in energy policy delivery for Net
Zero, and that hydrogen production is integrated within cross-sector regional
planning for water usage.
It is also possible that, rather than use in turbines for electricity generation,hydrogen could instead be used to generate electricity using fuel cells, enabling
the water from the process to be captured rather than emitted into theatmosphere as vapour.
These uncertainties make it even more important that climate resilience is fully
incorporated into Net Zero delivery. Chapter 2 looks in more detail at the risks ofwind droughts and low-wind years and how they can best be managed.

41*

Modelling based on 2020 Future Energy Scenarios and CCC Net Zero pathway scenarios.

†

The east and south-east of England are expected to be where risks of water shortages are most significant.

Delivering a reliable decarbonised power system

Chapter 4 looks in more detail at the future risks of weather-related failures in thecontext of climate change, and what is required to make the system resilient tothese risks.
Box 1.2
Uncertain climate impacts & implications for supply
Storms. Storms are an important climatic impact driver for the UK. Recent storms havedemonstrated the potential impacts on the electricity system and knock-on impacts
which can cascade across society (see Chapter 4). Recent studies assessed for the UK’s
Third Climate Change Risk Assessment (CCRA3) concluded that there is no clear
observational evidence for increased UK storminess. 11 Trends in storm activity depend on
the time period analysed. The apparent increase in storminess between 1960 and 1990 ispart of a longer-term record that reveals significant multi-decadal variability. Moreresearch is needed to address this important question for the UK and to better understandthe potential for changes in future UK storminess.
High wind speeds. Wind turbines are designed to stop operation when wind speeds
exceed a certain level, typically around 25 ms-1 (around 56 mph), to avoid mechanicaldamage from excess stress. A weather front passing across the country with wind speeds
consistently above that level can therefore lead to total wind generation dropping,potentially to near zero, in just a few hours. In an electricity system with a large share ofgeneration from co-located offshore wind, the drop in available generation from such
events could be significantly greater than the variations the system operator is
accustomed to managing today and would require a large amount of replacement
generation to be ramped up sufficiently quickly. Similarly to storminess, there is currently
no observational evidence for changes in the occurrence of strong wind gusts in the UK
and limited understanding of possible future changes. CCRA3 identified this as an areafor further investigation in order to understand the possible implications on energy system
resilience.
Wind droughts. Wind droughts are extended periods of low-wind-speed conditions.
Through summer and early autumn 2021, Europe experienced a long period of dry
conditions and low wind speeds. April to September 2021 was the least windy period formost of the UK and parts of Ireland in the last 60 years. 12 SSE stated that its renewableassets produced 32% less energy than expected. In 2018, the power available from wind
generation was reduced for a sustained period during the summer heatwave. National
Grid reported that wind power production was down from 12.9% to 10.4% of total
electricity production in summer 2018, when compared to 2017, despite 10% moreinstalled wind generation capacity. CCRA3 assessed the observed seasonal changes innear surface wind speeds (1981-2000) and UK climate projections for wind under 2ºC, 3ºC
and 4ºC warming thresholds (UKCP09 regional model, UKCP18 regional model and CMIP5
global model). The analysis concluded that in winter there is a large spread and no clear
signal across the three sources of evidence, that would imply robust changes in windenergy supply. In other seasons there is a consistent, but small, signal of weaker winds,
except in summer where the declines are larger, especially in the UKCP18 results. Further
research into the impacts of climate change on future maximum wind speeds and theseasonal change of wind speeds would enable a better understanding of the extent of
any adaptation shortfall associated with wind related impacts.
Lightning. Lightning strikes can and do have large-scale impacts on the electricity system.
A lightning strike on a transmission line triggered the large-scale outage in South-East
England in 2019 when a number of generators responded to the voltage fluctuation
incorrectly, with large cascading impacts. Lightning strikes are also an important cause of
wildfire, which could have impacts on the electricity system. However, there is currently
conflicting evidence suggesting significant changes in the frequency of lightning strikes
over coming decades. Long-term uncertainty also exists for other hazards, such as sealevel and coastal storm surges.
Source: Slingo, J. (2021) Latest scientific evidence for observed and projected climate change. In: The third UK
Climate Change Risk Assessment Technical Report [Betts, R.A., Haward, A.B. and Pearson, K.V. (eds.)] Prepared for
the Climate Change Committee, London; World Climate Service 2021.

Chapter 1: Setting the context for the future power system

42

Endnotes
1 Met Office (2022) UK Climate Projections: Headline Findings,

https://www.metoffice.gov.uk/binaries/content/assets/metofficegovuk/pdf/research/ukcp/ukc
p18_headline_findings_v4_aug22.pdf.

2 Hanlon, H. M., D. Bernie, G. Carigi, and J. A. Lowe, J.A. (2021) Future Changes to high impact

weather in the UK. Climatic Change DOI 10.1007/s10584-021-03100-5.

3 Robert Sansom for Energy Systems Catapult (2020) Domestic heat demand study, https://esc-

production-2021.s3.eu-west-2.amazonaws.com/2022/01/ESC-Energy-Digitalisation-TaskforceReport-2021-web.pdf.

4 ONS (2022) Excess mortality during heat-periods: 1 June to 31 August 2022,

https://www.ons.gov.uk/peoplepopulationandcommunity/birthsdeathsandmarriages/deaths/ar
ticles/excessmortalityduringheatperiods/englandandwales1juneto31august2022.

5 Costa et al. (2016) Climate change, heat stress and labour productivity: A cost methodology forcity economies, Centre for Climate Change Economics and Policy Working Paper No. 278.

6 CCC (2023) Investment for a well-adapted UK,

https://www.theccc.org.uk/publication/investment-for-a-well-adapted-uk/

7 RenewableUK - Only two turbines installed in England last year, while new UK offshore windcapacity hit new record (https://www.renewableuk.com/news/630636/Only-two-turbinesinstalled-in-England-last-year-while-new-UK-offshore-wind-capacity-hit-new-record.htm)

8 CCC (2019) Net Zero – Technical Annex: Integrating variable renewables into the UK electricity

system, https://www.theccc.org.uk/wp-content/uploads/2019/05/Net-Zero-Technical-AnnexIntegrating-variable-renewables.pdf.

9 Slingo, J. (2021) Latest scientific evidence for observed and projected climate change. In: The

third UK Climate Change Risk Assessment Technical Report [Betts, R.A., Haward, A.B. andPearson, K.V. (eds.)] Prepared for the Climate Change Committee, London.

10 Joint Environmental Programme (2021) Projections of water use in electricity and hydrogenproduction to 2050, under the 2020 future energy and CCC scenarios – regional analysis,
https://www.energy-uk.org.uk/index.php/publication.html?task=file.download&id=8157.

11 Slingo, J. (2021) Latest scientific evidence for observed and projected climate change. In: The

third UK Climate Change Risk Assessment Technical Report [Betts, R.A., Haward, A.B. andPearson, K.V. (eds.)] Prepared for the Climate Change Committee, London.

12 World Climate Service 2021.

43

Delivering a reliable decarbonised power system

Chapter 2

Delivering a reliable
decarbonised power system
1. What flexibility is needed?

47

2. Types of flexibility and options for the flexibility capacity mix

50

3. Facilitating delivery and addressing risks

63

4. Indicators for measuring progress

73

45

Delivering a reliable decarbonised power system

Introduction
A low-cost renewables-based system will need a range of flexible low-carbon
solutions to ensure reliable and resilient electricity supply.
In this chapter we set out the options for low-carbon flexibility and how these cancomplement a renewables-based system to deliver reliable and securesupply. Using these scenarios we present a range of indicators for monitoring
progress towards the 2035 objective, as part of our annual reporting to Parliament.
We do this in four sections:
1. What flexibility is needed
2. Types of flexibility and options for the flexibility capacity mix
3. Facilitating delivery and addressing risks
4. Indicators for monitoring progress

Chapter 2: Delivering a reliable decarbonised power system46

1. What flexibility is needed?
Low-carbon flexibility will be needed on a range of timescales, to ensure thesystem is balanced both in the shorter-term (e.g. seconds, minutes, hours) and thelonger-term (e.g. days and weeks).
We commissioned theconsultancy AFRY to undertakemodelling to inform anassessment of the flexibility
requirements for adecarbonised system by 2035.

We commissioned the consultancy AFRY to undertake modelling to inform anassessment of the flexibility requirements for a decarbonised system by 2035 (Box2.1) and beyond to 2050.
Box 2.1
Modelling to assess the flexibility requirements for a decarbonised, reliable and resilientelectricity system
Our approach to assessing the flexibility requirements for a decarbonised system is basedon modelling undertaken by AFRY, incorporating the following key high-level features:•

Hourly representation of demand and generation, optimising the power andhydrogen production and storage systems simultaneously. Technologies aredispatched to give a minimum cost of electricity.

•

11 geographic zones across Great Britain and simultaneous modelling of panEuropean interconnected markets, accounting for the geographic coverage of
weather systems, with weather patterns at 15 km2 resolution.

•

Five historical annual weather patterns used to simulate each future year, and awider selection available for sensitivity testing, to reflect a range of possible
outcomes for uncertain, weather-driven features of power systems.

•

Investment (e.g. by type and location for new generation capacity, transmission grid
reinforcement, and the production, storage and transmission capacity of hydrogen)determined endogenously to give the economically optimal, least-cost, system
reflecting the range of weather patterns.

•

In all scenarios the following constraints must be met:
– Security of supply required to ensure lower than three hours of loss of load
expectation, in line with Government requirements.
– All investment options required to respect resource potentials and build rate limits.
– Ancillary service requirements met, including short-term operating reserve,
regulating reserve, and frequency response and inertia.

The modelling used the capacities for renewables and nuclear from the ESS, with theflexibility options required to balance the system then optimised around these. Key input
assumptions included the following:

47•

Fixed capacity assumptions were drawn from the ESS, with 50 GW of offshore wind in
2030 (assumed to rise to 115 GW in 2050), 70 GW of solar PV in 2035 (assumed to riseto 105 GW in 2050), and 24 GW of nuclear in 2050. Additionally, 28 GW of onshore
wind were assumed in 2035, rising to 31 GW in 2050, with 2.5 GW of BECCS and 21
GW of interconnection capacity based on National Grid’s Network Options
Assessment.

•

Technology costs were based on the Sixth Carbon Budget Balanced Pathway
assumptions, supplemented by AFRY for those options not covered in the Sixth
Budget (see Chapter 1 and Tables 2.1 and 3.1).

•

Carbon values were taken from the Government’s Green Book for a Net Zeroconsistent pathway, reaching £300/tCO2 in 2035 and £380/tCO2 in 2050 (in 2020
prices).

Delivering a reliable decarbonised power system•Fossil fuel prices were based on the Sixth Carbon Budget assumptions, including gas
prices of around 2.5 p/kWh over the period to 2050 (in 2020 prices). We investigated
the impact of significantly higher and sustained gas prices, but given all scenariosvery significantly reduce gas use, other factors (e.g. technology build rates) were
found to be more significant in driving outcomes. As a result, and given uncertainty
surrounding the future gas price profile, Sixth Carbon Budget assumptions were used.
To the extent that gas prices are higher than were assumed based on projections in
2020, decarbonisation costs will be lower.

•

Electricity and non-power hydrogen demands were based on the Sixth Carbon
Budget scenarios. Hydrogen demand in power was determined by the model’ssimultaneous optimisation of the power and hydrogen systems.

In conjunction with AFRY, we developed a range of scenarios and sensitivities thatcombined these assumptions in different ways.
•

The Core (Central, High and Low) scenarios use the capacities from the ESS and vary
electricity and hydrogen demands.
– The Central scenario uses electricity and hydrogen demands from the Balanced
Pathway.
– The High scenario uses demands from the Widespread Innovation scenario.
– The Low scenario uses demands from the Headwinds scenario.

•

In order to account for uncertainty in the indicator ranges, and to stress-test theresults, a range of sensitivities were undertaken.
– The indicators, and ranges quoted throughout this report (unless otherwise stated)reflect the Core scenarios and a subset of the sensitivities, selected with a view toreflecting the range of outcomes which might be achieved pending uncertainty.
– The indicator range included sensitivities on the impact of different assumptions on
policy (e.g. different uses for biomass), technology (e.g. potential for hydrogen
conversion of existing gas plant and additional progress in grid storage
technologies), market developments (e.g. progress in renewable and nuclear
build, the balance between hydrogen and gas CCS in low-carbon dispatchable
power) and weather/security of supply considerations (e.g. low wind).

Further detail is set out in the accompanying technical report by AFRY, available on our
website at www.theccc.org.uk.
Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.

A significant amount of lowcarbon flexibility is expected tobe needed in a typical year,
both to meet residual demand,and absorb surplus supply.

The modelling undertaken for this report suggests a significant amount of lowcarbon flexibility will be needed in a typical 2035 weather year, * with flexibility
expected to be utilised in around half of days and hours to meet residual
demand, † and in around half of days and hours to absorb surplus electricity supply(Figure 2.1).

*

All hourly modelling results are shown applying 2012 weather patterns to 2035. 2012 was judged by AFRY to be
representative of a typical weather year, but does not take account of any future changes in climate.

†

Residual demand is defined as the difference between demand at a particular point in time and the power
available at that time from wind, solar, BECCS and – by virtue of its relative inflexibility – nuclear. It therefore
represents, when it is a positive value, the demand to be met from flexible, schedulable sources or, when it isnegative, the power available for use by flexible demand, export or storage.

Chapter 2: Delivering a reliable decarbonised power system

48

Figure 2.1 Residual electricity demand in 2035

Propotion of total hourly demand (%)

100%
80%
60%
40%
20%
0%
-20%
-40%
-60%
-80%

-100%

1

2,191

4,381

6,570

8,760

Hours in year
Positive residual demand

Negative residual demand

Source: CCC analysis based on AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Figure shows hourly residual demand for the Central scenario in 2035, ordered from highest to lowest andadjusted to reflect the proportion of total electricity demand in that hour. Positive residual demand means there isnot sufficient renewable, nuclear, BECCS and other inflexible generation to meet demand. Negative residual
demand means generation from these sources exceeds demand.

49

Delivering a reliable decarbonised power system

2. Types of flexibility and options for the flexibility capacity mix(a) Options for providing low-carbon flexibility
There are a wide range ofoptions for providing lowcarbon flexibility, including
demand flexibility, generation,
storage and interconnection.

There are a wide range of potential options for providing low-carbon flexibility,
across the different timescales that are required:•

Demand. Managing demand can help reduce the need for use ofgeneration or storage (particularly at peak demand periods) as well as
minimising the amount of network capacity needed, without affecting
consumers’ quality of service provision. In doing so demand management
can both reduce costs and improve security of supply.
– Smart demand shifting can help to smooth peaks in demand andabsorb excess supply (e.g. through controlled timing of electric vehicle
charging, and smart management of heat pumps and appliances).
The potential for this will grow in future as the deployment of thesetechnologies increases, driven by the growth of smart-enabledtechnology and the electrification of transport and heating inbuildings.
– Demand response. Consumers, both residential and commercial, canparticipate voluntarily in markets to reduce their demand in response
to price signals or automatic controls. Around 0.5 GW of commercial
demand response has been contracted through the capacity market.
– Electrolytic hydrogen production. By providing a source of demand,
producing hydrogen via electrolysis can help to absorb electricity
surpluses when available supply exceeds demand. However, it may
not be a fully flexible option given business models and the need tomaintain production efficiencies.

•

Generation. Dispatchable options for providing low-carbon flexibility
through back-up generation include gas with carbon capture and storage(CCS) and hydrogen-fired turbines.
– Gas CCS. These gas plants have additional technology fitted tocapture the CO2 emitted, and therefore need access to CO2 storage
and transport infrastructure. The capture process incurs an efficiency
and cost penalty, meaning it is likely to be more cost-effective to run
these plants relatively consistently rather than ramping up to meetpeaks in demand.
– Hydrogen-fired turbines. These are similar to conventional gas turbinescurrently used in electricity generation, but substituting hydrogen gas
for natural gas. This can be a low-carbon solution provided that thehydrogen is produced in a low-carbon way. Existing gas plants canalso potentially be converted to use hydrogen. 1 Hydrogen-fired
turbines are likely to have similar characteristics to existing gas turbines,
and therefore could play a similar role in the electricity system byproviding both mid-merit and peak generation.

Chapter 2: Delivering a reliable decarbonised power system

50•Storage. These options can capture energy, typically when it is cheap, toprovide electricity in periods when demand is higher, and electricity is morevaluable. They can operate on short to long timescales, to provide flexibility
when it is most valuable.
– Shorter-term. Lithium-ion batteries can provide flexibility by discharging
power on timescales from minutes to hours. Currently around 2 GW ofgrid connected battery storage is operational in the UK.
– Medium-to-longer-term. A number of storage options could operate
on timescales covering hours to days and weeks or longer.
• Pumped storage and compressed air energy storage (CAES) aremature technologies, with 2.5 GW of pumped storage currently
installed in the UK and CAES installed overseas. 2• Gas CCS and hydrogen, enabled by appropriate levels of gas
and/or hydrogen storage (or imports) could play a longer-term roleover weekly timescales or more.
• A range of other storage technologies exist at different – andgenerally earlier - stages of commercialisation. These include liquid
air storage, flow batteries, flywheel and gravity storage, andthermal storage technologies.

•

Interconnection of the electricity grid to neighbouring markets enables
imports of electricity when it is cheaper to do so, and provides a market forsurplus generation. Currently there is 8.4 GW of interconnection
capacity. Generation in neighbouring markets will also be impacted byclimate and weather extremes, potentially impacting their ability to export
to the UK at particular times. *Table 2.1 sets out the characteristics of the flexibility options included in ourmodelling, which focuses on those options closer to market deployment.
Table 2.1
Options for flexibility in a decarbonised power system
OptionPotential
to be
zerocarbon?

Techno-economic modelling assumptions
Duration

Efficiency(%)

Cost in 2035(£2012)Financial
lifetime(years)Unabated gas

No

Weeksseasons57

170 18025•

Mature technology,
deployed at grid scale

Gas CCS

Lowcarbon

Weeksseasons

50

75 - 9025•

Demonstrated but not yet
commercialised•

Several projects underway
through UK Track 1 cluster

*

51

£/MWh

StatusFor example, Electricity provider EDF was forced to reduce output at its nuclear power stations on the Rhône andGaronne due to river temperatures increasing during a heatwave in summer 2022. This was to comply withregulation following the 2003 heatwave in France, which ensures that the water used to cool plants does not affectwildlife when it is pumped back out. This came at a time when many of EDFs reactors were shut down formaintenance, resulting in its lowest output levels for 30 years. Nuclear output in France fell by 15% in the first six
months of the year, while drought and unusually low river levels meant hydroelectricity production declined by 23%.

Delivering a reliable decarbonised power system

Hydrogen
New BuildYes

Weeksseasons

55

90 125Retrofit

Yes

Weeksseasons

55

65 100Batteries

Yes

Minuteshours

85

260 980

PumpedYes

Hoursdays

85

1290 1830

Compressed air

Yes

Hoursdays

60

Liquid air

Yes

Hoursdays

Yes

Hoursseasons25•

Based on mature unabated
gas technology buthydrogen versions not yet
deployed at scale•

UK projects planned,
including near industrial
clusters

15•

Mature technology
deployed at grid scale in
the UK

30•

Mature technology
deployed at grid scale in
the UK860 1420

25•

Technology deployedoverseas but not yet in theUK60

900 1050

25•

Demonstrated but not yet
commercialised

78

22

30

•

Alkaline electrolysers are amature technology•

Proton Exchange
Membrane electrolysers
have been demonstrated
but not deployedcommercially•

Smart meters and halfhourly metering planned for
mid-2020s to enable smart
flexibility•

Electric vehicles and heatpumps commercialised•

Mature technology
deployed at grid scale in
the UK£/MWh

25

Storage£/kW

DemandElectrolysis

Smart response

Yes

Hours

£/MWh

N/A

Other
Interconnection

Yes

Up to
seasonal

N/A

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility; CCC analysis.
Notes: Levelised costs include value of carbon in 2035 applied to any unabated emissions, gas price range from the Sixth Carbon Budget, and loadfactors consistent with the Central scenario from this report. Unabated gas and hydrogen shown for CCGT plant. Efficiency column represents plant
efficiencies, and in the case of hydrogen does not reflect the efficiencies associated with the hydrogen production process (see Table
3.1). Levelised costs shown for generation technologies and capital costs for storage technologies. Storage technologies and costs not directlycomparable, given different storage durations and hence system roles.

Chapter 2: Delivering a reliable decarbonised power system52

(b) What a reliable and secure renewables-based system looks likeA renewables-based system,complemented by a suitableportfolio of low-carbon
flexibility, can provide a secureand reliable supply of energy.

A renewables-based energy system in Great Britain offers low emissions by making
the most of abundant natural resources. If complemented by a suitable portfolio of
low-carbon flexibility options, a renewables-based system can provide a secureand reliable supply of energy. In this section, we set out the results of our analysis,
demonstrating this to be true both for a normal weather year, and when testing
more extreme weather scenarios, particularly around wind droughts.

We consider that use of a small
amount of unabated gas toensure security of supply (up toaround 2% of annual electricity
production) would be costeffective and consistent withthe delivery of a decarbonised
system by 2035.

We consider that use of a small amount of unabated gas (up to around 2% ofannual electricity production) to ensure security of supply would be cost-effective
and consistent with the delivery of a decarbonised system by 2035. A system
without the use of unabated gas may be possible in 2035, but is likely to increase
costs and delivery risks.

A decarbonised electricity
system is cost-effective and willbring wider benefits, including
for energy security andeconomic growth.

A decarbonised system such as we describe in this section is cost-effective and willbring wider benefits, including for energy security and economic growth:•

Cost-effective. A decarbonised system in 2035 with a small amount of
unabated gas (up to around 2% of generation) is cost-effective, reflecting
the low cost of renewables compared to unabated gas, with thesemeeting the majority of demand. Although their variability does impose
costs on the wider system, these are manageable with the combination of
low-carbon flexibility options, given that these only make up a relatively
small proportion of generation (e.g. less than 10% over the year as a whole)and capacity.

•

Energy security. The 2035 electricity system envisaged in this report would
maintain energy security, while coping with the expected increase inelectricity demands and periods of low wind. The consequent dramatic
reduction in gas consumption would also cut our exposure to volatileinternational fossil fuel markets, with greater reliance on homegrown lowcost renewables (see Chapter 3, section 4). These conclusions have newsignificance following the recent period of heightened energy insecurity.

•

Economic growth. Currently, over 31,000 people across the UK are
employed in offshore wind alone – this is set to rise to 97,000 by 2030, drivenby £155 billion in private investment, with further investment andemployment in solar and onshore wind. 3 There are opportunities for the UK
to become a global leader in emerging technologies such as floating
offshore wind, which is estimated to have the potential to deliver £43.6
billion in UK gross value added (GVA) by 2050. 4 There are also opportunities
for innovation, investment and employment across electricity storage,hydrogen infrastructure, smart charging of electric vehicles, flexible heating
systems, electricity networks and interconnection.

(i) Running a reliable and secure renewables-based system in2035
In a typical year by 2035,
variable renewables are
expected to produce around
70% of generation, with otherinflexible sources such as
nuclear and BECCS
contributing around 20%.

Demand can be met by a diverse range of solutions. The modelling illustrates thatin a normal weather year, variable renewables (i.e. solar and wind) and otherrelatively inflexible sources (e.g. nuclear and BECCS) produce around 70% and 20%
of total generation respectively, across the year as a whole.

53

Delivering a reliable decarbonised power system

Flexible solutions are needed
for the remainder. Different
solutions play different roles
and no one solution will provide
all the flexibility required. A
portfolio approach is needed.

While these forms of generation can provide most of the electricity required acrossthe year, there are times at which they need to be supplemented by low-carbon
flexible solutions. Different solutions play different system roles, and no one solution
provides all the flexibility that is required. A portfolio approach, relying on a rangeof established and emerging technologies, is therefore likely to be important.
•

On an annual basis in 2035 (Figure 2.2), around 40 TWh of low-carbon
dispatchable generation is used in the Central scenario, supported by 17
GW of dispatchable low-carbon capacity. Similar amounts are exported
and used for producing electrolytic hydrogen respectively, which helps
manage times of surplus.
– Low-carbon back-up technologies provide around 40 TWh ofgeneration in the Central scenario, within a range of 25-60 TWh acrossthe range of scenarios used for our indicators.
• This is made up of 30 TWh of hydrogen generation (with a range of
15-45 TWh) and 10 TWh of gas CCS (with a range of 0-20 TWh).
• Given uncertainty over the appropriate mix of hydrogen and gas
CCS generation, and the fact that these can play similar system
roles, we group these technologies together as low-carbon
dispatchable generation in our charts below, and for the purposesof our indicators.
– At other times, when there is surplus generation, a similar amount ofenergy is used in the Central scenario and ranges for production ofelectrolytic hydrogen.
– Across most scenarios GB is a net exporter of electricity, with up to 35
TWh exported in the Central scenario. A small contribution of
unabated gas (up to around 2% of annual electricity production) isused to help meet peak demands, with storage and smart demand
management making a similar contribution.
– The Central scenario has 17 GW of dispatchable low-carbon capacity,with a range of 12-20 GW across the indicator scenarios.
• Dispatchable low-carbon capacity is made up of 14 GW ofhydrogen plants (with a range of 8-16 GW) and 2 GW of gas CCS
plants (with a range of 0-5 GW).
• The average build rate for new dispatchable low-carbon capacityfrom the late-2020s until 2035 is 1.1 GW per year in the Central
scenario, with a range of 0.6-1.5 GW per year across the indicatorscenarios and a peak annual build rate of 3.3 GW per year. This iswithin the historical peak annual build rate for unabated gas
Combined Cycle Gas Turbines (CCGT) of 3.7 GW.
– The Central scenario has 11 GW of grid storage output capacity (witha range of 10-19 GW), and 41 GWh of grid storage capacity (with arange of 30-366 GWh).**The output capacity of grid storage (GW) represents the maximum rate of discharge which can be achieved, while
grid storage capacity represents the total amount of energy stored (GWh).

Chapter 2: Delivering a reliable decarbonised power system54• The large range for grid storage capacity is reflective of thedifferent technologies available, with the upper bound illustrating a
scenario with use of longer-duration CAES technologies (whichtake advantage of the same geological structures as salt caverns,
enabling large increases in the total amount of energy that can be
stored).
• The average build rate for grid storage capacity is 0.5 GW per year
from the late-2020s until 2035, with a range of 0.2-1.4 GW per year
and a peak annual build rate of 1.5 GW. In recent Capacity
Market auctions 2.3 GW of new-build battery capacity won
contracts for 2023/24 and 5 GW for 2026/27. This will more thandouble GB battery capacity by next winter. In addition, there isaround 50 GW of capacity in the pipeline.
•55

On a seasonal basis in 2035 (Figure 2.3), the generation mix reflects thepattern of demand and supply, with higher demand in winter wellcorrelated with higher generation potential from offshore wind but also
requiring increased contributions of dispatchable generation. The higher
levels of generation in autumn and winter also allow for increased exports.

Delivering a reliable decarbonised power system

Figure 2.2 Electricity generation and capacity mix
to 2035 in the Central scenario(a) Generation
700

TWh per year

600
500
400
300
200
100
0
-100

2025

2030

Nuclear
BECCS
Onshore wind
Dispatchable low-carbon
Net imports

300

2035
Other
Offshore wind
Solar
Unabated gas(b) Capacity

250

GW

200
150
100
50
0

2025
2030
Nuclear
BECCS
Onshore wind
Dispatchable low-carbon
Storage2035
Other
Offshore wind
Solar
Unabated gas
Interconnectors

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Figures are before losses through the transmission and distribution system. ‘Other’ includes Combined Heatand Power (CHP) and unabated biomass. Dispatchable low-carbon includes gas CCS and hydrogen. Analysis isrepresentative of a ‘normal’ weather year.

Chapter 2: Delivering a reliable decarbonised power system

56

Figure 2.3 Seasonal generation mix in 2035 in theCentral scenario

GWh per day

2000
1500
1000
500
0
-500

SpringSummerElectrolysis
Nuclear
BECCS
Onshore wind
Dispatchable low-carbon
Imports

AutumnWinter

Exports
Other
Offshore wind
Solar
Unabated gas

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Figures are before losses through the transmission and distribution system. ‘Other’ includes Combined Heatand Power (CHP) and unabated biomass. Dispatchable low-carbon includes gas CCS and hydrogen. Chart basedon 2012 weather patterns, representing a ‘normal’ weather year. Winter includes: January, February andDecember. Spring: March, April and May. Summer: June, July and August. Autumn: September, October andNovember.

There is no need to trade-off
decarbonisation, reliability andresilience. Meeting residual
demand is manageable on awide range of timescales, costeffective and with a small
amount of unabated gas at
the margin in 2035 (up toaround 2% of annual electricity
production). A system without
the use of unabated gas may
be possible in 2035, but is likely
to increase costs and delivery
risks.

57

There is no need to trade-off decarbonisation, reliability and resilience. Meeting
residual demand is manageable on a wide range of timescales, and costeffective with a small amount of unabated gas at the margin in 2035 (up toaround 2% of annual electricity production). A system without the use of unabatedgas may be possible in 2035, but is likely to increase costs and delivery risks.
•

Figure 2.4 shows hourly generation in the modelled four-week period in 2035
with the highest total of residual demand that needs to be met. Over thisfour-week period, demand is met through a combination of different lowcarbon flexibility options and some unabated gas.

•

Figure 2.5 shows hourly generation in the modelled four-week period in 2035
with the lowest total of residual demand. Over this four-week period, surplus
electricity generation, shown as negative residual demand, is primarily
absorbed by electrolysis for hydrogen production, grid connected storage,
and exports to interconnected markets.

•

Our modelling shows how low-carbon dispatchable power such ashydrogen or gas CCS, combined with storage of those gases, andoccasional use of unabated gas capacity (up to around 2% of electricity
production annually), can be utilised to ensure security of supply consistent
with a decarbonised system. A system without the use of unabated gas
may be possible in 2035, but is likely to increase costs and delivery risks.
However, in the longer-term there should not be a role for unabated gas
and there is more scope to sufficiently develop alternatives and address
potential delivery risks.

Delivering a reliable decarbonised power system

– Under the Central scenario, around 2% of generation (10 TWh) comesfrom unabated gas, which is cost-effective even with the high value ofcarbon assumed in 2035 (i.e. around £300/tCO2). This is achieved witharound 12 GW of unabated gas plants operating at low load factorsof around 10%.
– We have also explored a scenario with no unabated gas generation
at all in 2035. Compared to the Central scenario, this requires anadditional 11 GW of low-carbon dispatchable capacity and an
additional 6 GW of storage capacity (e.g. batteries) to be installed. It
would also require additional accompanying infrastructure (e.g. CO2transport and storage, hydrogen production). This may be possible but
is likely to increase costs and delivery risks.

Figure 2.4 Meeting the highest four-week periodof residual demand in 2035 (Central scenario)
80
60

GW

40
20
0
-20
-40

1

4

7

10

13

16

19

22

25

28

Day
Electrolysis
Other
Unabated gas
Grid storage
Residual demand

Exports
Low-carbon dispatchable
Imports
Demand flexibility

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Residual demand is demand required to be met after taking account of generation from renewables,
nuclear, BECCS, and other inflexible generation. Dispatchable low-carbon generation includes gas CCS andhydrogen. Chart based on 2012 weather patterns, representing a ‘normal’ weather year.

Chapter 2: Delivering a reliable decarbonised power system

58

Figure 2.5 Meeting the lowest four-week period ofresidual demand in 2035 (Central scenario)
40
30
20

GW

10
0
-10
-20
-30
-40
-50

1

4

7

10

Electrolysis
Other
Imports
Grid Storage
Residual demand

13

16
Day

19

22

25

28

Exports
Low-carbon dispatchable
Unabated gas
Demand flexibility

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Residual demand is demand required to be met after taking account of generation from renewables,
nuclear, BECCS, and other inflexible generation. Dispatchable low-carbon generation includes gas CCS andhydrogen. Chart based on 2012 weather patterns, representing a ‘normal’ weather year.

A decarbonised, reliable andresilient system in 2035 remains
feasible even when tested bymore extreme weather
scenarios, particularly aroundwind droughts.

A decarbonised, reliable and resilient system in 2035 remains feasible even whentested by more extreme weather scenarios, particularly around wind droughts:•

Wind droughts already occur in the UK. Current evidence on the impacts ofclimate change on future wind suggests no significant change in energy
supply in winter, when the most electricity is needed and generated. Thereis potential for declines in wind energy supply in other months, though there
is a need for new evidence to assess these risks appropriately.
– Winter is when most electricity is needed. It is also the season whenmost is generated from wind farms, and this is expected to remain thecase as the climate changes. The latest available evidence on theimpacts of climate change on future wind speeds concludes there is
not yet strong evidence to robustly project changes in the frequency
and severity of future wind variability around the UK in winter.
– In autumn and spring there is a consistent, but small, expectation of
weaker winds in future.
– In summer, the expected declines in wind generation due to climatechange are larger, although more evidence is needed. 5

59

Delivering a reliable decarbonised power system•We cannot rule out wind droughts, so we need to plan for them. As part ofthe modelling undertaken for this report, we have tested additional
sensitivities examining the impact of reduced wind generation. One looks
at the impact of a low wind year, and one looks at an extended period of
low wind.
– We have tested the impact of a low wind year, using weather patterns
from 2010, which is judged to have been a 1-in-50 low wind year.
– We have also tested a scenario of an extended 30-day period of winddrought. This scenario builds on the low wind year and looked over theperiod 2009-2019 to combine the 30-day period of highest residual
demand with the 30-day period of lowest wind load factors. This isdesigned to test a more extreme scenario * and does not have ahistorical precedent, but effective resilience planning requiresconsidering potential impacts outside the historical record.

When optimising the system
around a low wind year,
unabated gas use remains
around 2% of generation
supported by 3 GW ofadditional dispatchable lowcarbon capacity. Levels wereshown to be only slightly higher
in the case of a very extreme
wind drought.

– The analysis shows when optimising the system around a low wind
year, similar levels of unabated gas capacity and use are seen as in
the Central scenario, representing around 2% of generation served by
11 GW of capacity. When optimising the system around an extreme
extended wind drought, higher levels of unabated gas generation (3%of total generation) and capacity (25 GW) are required in the model
to maintain security of supply. Both scenarios also build some
additional dispatchable low-carbon capacity beyond the Central
scenario (3 and 5 GW respectively).

There remains a decision for
Government around security ofsupply and how muchallowance to build into thesystem to account for
uncertainties around future
weather. Further work isneeded to determine this.

There remains a decision for Government around security of supply and how muchallowance to build into the system to account for uncertainties around future
weather. That our low-wind sensitivities build more overall capacity than theCentral scenario suggests some potential for less secure supply were only thecapacities in the Central scenario available. Recent work by National Grid
confirms security of supply for a decarbonised system can be met even in extreme
cases with a portfolio of low-carbon options, 6 but further work is needed todetermine what reasonable allowance should be made for weather extremes.

The broad alignment between
the required unabated gas
capacity suggested by ourmodelling to 2035, and thecapacity already expected to
be on the system, reinforces
the importance of ensuring
new capacity is future-proofed
as soon as possible.

Nevertheless, the broad alignment between the required unabated gas capacity
suggested by our modelling to 2035, and the capacity already expected to be on
the system (Figure 2.6), † reinforces the importance of ensuring new capacity is
future-proofed as soon as possible.
As part of our Sixth Carbon Budget advice, we recommended that new gas plants
be made properly CCS- and/or hydrogen-ready as soon as possible and by 2025
at the latest.
Government intends to publish a consultation on updated Decarbonisation
Readiness proposals shortly which would require new-build and substantiallyrefurbished combustion power plants to be built in such a way that they can easily
decarbonise by converting to either hydrogen generation or carbon capture
within the plant’s lifetime.

*For example, in comparison, a recent study for National Grid testing weather extremes in a decarbonised systemfound no ‘critically tight periods’ beyond six days duration in 2035.

†

Comprising existing capacity still expected to be on the system by 2035, plus planned capacity with approval.

Chapter 2: Delivering a reliable decarbonised power system

60

Figure 2.6 Unabated gas capacity to 2035
35

Capacity (GW)

30
25
20
15
10
5
0

Installed
capacity

Expected
capacity

2021
Unabated gas

Indicator range Indicator range- low- high2035
Low-carbon dispatchable

Source: BEIS (2022) Digest of UK Energy Statistics; National Grid (2023) Transmission Entry Capacity (TEC) Register;
CCC analysis; AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: Expected unabated gas capacity has been determined by considering the lifetime of all existing and future
plants with approval. We have assumed that plants in operation after 2030 and located near to an industrial cluster
will have opportunities to be converted to hydrogen. Analysis only considers major power producers (companies
whose prime purpose is the generation of electricity). The low and high indicator ranges have been taken from the
AFRY Grid Storage sensitivity and High scenario, respectively. Low-carbon dispatchable capacity includes newbuild gas CCS and hydrogen, plus conversion of some existing gas CCGT to hydrogen CCGT.

Recommendation

Owner (timing)

Ensure new gas plants are genuinely CCS- and/or hydrogen-ready as soon as possible and by 2025
at the latest.

DESNZ (2025 at
the latest)(ii) Planning appropriately to account for weather-related
uncertainty
In order to ensure adecarbonised electricity system
can be made secure androbust to weather risks, system
planning will need to consider
geographic diversity in supply,
building the evidence base on
risks, and stress-testing. Systemdesign must plan for the rangeof climate hazards that will
face the energy system over its
lifetime.

The modelling for this report has illustrated how a decarbonised system in 2035 canbe made secure and robust to weather risks through a portfolio of low-carbon
flexibility options, including dispatchable plants, smart demand management,
storage and interconnection, alongside a small amount of unabated gas.
The following approaches will need to form part of system planning, in order todeliver these outcomes:•

61

Increasing geographical diversity: The more diverse the source of supply,
the lower the proportional impact of any single failure. Increasing
geographical diversity, particularly in meeting Government commitments
to increase offshore capacity, can help to manage the impact of regional
wind droughts.

Delivering a reliable decarbonised power system

A recent study by Regen found that balancing offshore wind capacity
between east and west coasts offers multiple benefits, including moreconsistency and reduced variability of total available GB generation, withno reduction in total energy generation (yield) per year. 7•

Building the evidence base: Further research on the impacts of climatechange on future wind speeds and the seasonal change of wind speeds
would enable a better understanding of what further adaptation action
might be needed to prepare for wind-related impacts. National Grid ESO
has recognised the importance of new datasets to understand risks due toweather patterns and ensure adequacy in a fully decarbonised system withhigh levels of weather-dependent generation.8•

Stress testing:– In order to maximise resilience, understanding of future weatherrelated extremes needs to be factored into decisions on future energy
system design. System operators can stress-test future supply using
credible examples of observed low-wind conditions and up-to-dateevidence on future climate impacts on wind.
– A recent project between the Met Office, the National Infrastructure
Commission and the CCC has developed a dataset of adverse
weather scenarios, presenting a range of possible extreme events andthe effects of future climate change.9 These present a set of extreme
events that can be used to stress test the resilience of a future highly
renewable system to extreme weather and climate conditions.

Recommendation

Owner (timing)

Ensure that future system design explicitly plans for the range of climate hazards that will face theenergy system over its lifetime. This includes those hazards expected with high confidence (such as
higher temperatures, reduced water availability and flooding) in addition to low-likelihood highimpact scenarios (such as more frequent and severe wind droughts and storminess). Planningshould include consideration of concurrent hazards and hazards with the potential to impact
multiple interconnected countries simultaneously.

DESNZ, Ofgem,
FSO (ongoing)

The objective for Government is now to ensure that all aspects of the powertransition are delivered at the speed and scale necessary to ensure a secure anddecarbonised system by 2035. That includes the bulk zero-carbon capacity (i.e.
renewables and nuclear) the Government has committed to, as well as a portfolioof low-carbon flexibility solutions and the required enabling conditions such as
sufficient network capacity.

Chapter 2: Delivering a reliable decarbonised power system62

3. Facilitating delivery and addressing risks
The scale of build required,when taken across the rangeof system components, isunprecedented. A
decarbonised power system by2035 is achievable, but it
requires that barriers to swift
deployment of criticalinfrastructure are removed,
and policy gaps remedied.

The scale of build required, when taken across the range of system components, isunprecedented. A decarbonised power system by 2035 is achievable, but it will
require removal of barriers to the swift deployment of critical infrastructure, andpolicy gaps to be remedied.
While many of the scenarios modelled for this report take the levels of renewable
and nuclear deployment set out in the ESS as their starting point, achieving thisalongside the flexibility required is a very significant undertaking. It will require aconcerted push in a wide range of areas, alongside rapid action to address
barriers, if the required pace is to be achieved.
•

As set out in Chapter 1, the Government plans to increase offshore windcapacity by four times over current levels by 2030, and solar by five times
by 2035. While this implies a build rate for solar close to the historical peak,for offshore wind it implies annual build rates around 40% higher thanemerging data on the 2022 peak.

•On nuclear, Government has ambitions to dramatically increase
investment relative to historical levels. Where it is not feasible to deliver onthese ambitions, additional generation would be required from a
combination of other low-carbon sources.

•

Our scenarios envisage a strong role for demand-side response, boththrough transport demand shifting and heat demand shifting, which will
require sufficient consumer engagement and uptake, facilitated by smart
technology and appropriate price signals.

•

As stated in Chapter 2, the required build rates for new dispatchable lowcarbon capacity (gas CCS or hydrogen) are projected to remain within thebounds of historical peak annual build rates for unabated gas CCGT, but
are reliant on immature technologies.

CCS is a necessity for delivering a decarbonised power system by 2035 (whether inpost-combustion power plants or blue hydrogen production), for engineered
greenhouse gas removals and for the delivery of Net Zero more broadly. However,it has yet to be delivered at scale in the UK. In our 2022 Progress Report toParliament we noted Government ambitions to deliver CCS have been subject torepeated cancellations and delays. Low-carbon hydrogen production andstorage, and hydrogen-fuelled generation have also yet to be delivered atsignificant commercial scale.
Alongside this, the challenge of delivering the network and storage infrastructure
required to support a decarbonised system will be very significant, with build
required for the transport and storage of electricity, hydrogen and CO2.
Due to the scale andcomplexity of the task, and theinherent interdependencies,
this can only be achieved
through a co-ordinated andstrategic approach to delivery,
with appropriate oversight. The
Government must urgently
publish a strategy for thedelivery of a decarbonised,resilient power system by 2035.

63

Due to the scale and complexity of the task, and the inherent interdependencies,
delivery of a decarbonised resilient power system by 2035 can only be achieved
through a co-ordinated and strategic approach to delivery, with appropriate
oversight.

Delivering a reliable decarbonised power system

The Government has not yet provided a coherent strategy to achieve its goal nor
provided essential details on how it will encourage the necessary investment andinfrastructure to be deployed over the next 12 years. This is urgently needed.
•

In 2020, as part of our Sixth Carbon Budget advice, and in our subsequent
Progress Reports to Parliament, we have recommended Government
develop a long-term strategy for the phase out of unabated gas and thedelivery of a decarbonised electricity system by 2035.

•

The need for this has been echoed by the National Audit Office (NAO) who
have identified the risks associated with a lack of a delivery plan. The NAO
has also noted the need for management of performance and risks to bebetter joined up and aggregated across DESNZ’s energy portfolio (noting
there are seven teams across three top-level groups responsible fordecarbonising the power sector). 10

Recommendation

Owner (timing)

Publish a comprehensive long-term strategy for the delivery of a decarbonised, resilient, powersystem by 2035. This should comprise a portfolio approach to developing the full range of lowcarbon flexibility options, including demand flexibility, storage, hydrogen, gas CCS andinterconnection capacity. It should set out how the low-carbon flexibility required to replace
unabated gas will be delivered (12-20 GW of low-carbon dispatchable capacity by 2035), as well
as clarifying any minimal residual role unabated gas is expected to play by 2035 (up to around 2%of annual electricity production) and the strategy for unabated gas phase out. It must set out plans
and contingencies for addressing key risks on a co-ordinated basis (e.g. network development andconnections, planning and consenting, CCS, hydrogen and nuclear).

DESNZ (2023)

The planning and delivery of the very significant network infrastructure needed,alongside the necessary reforms to market design to mobilise investment and todrive efficient operation of the system, remain among the most significant
challenges faced for delivery.

(a) Network and system planning(i) Electricity network needs
As we move to an increasingly renewables-based system, growing quantities ofgeneration are expected to be located further from centres of demand (Figure
2.7).
Where there is insufficient network capacity to transport this generation, there is arisk of wasted supply (or less-efficient use of that supply where it must be diverted
into energy storage with associated efficiency losses), and increased costs and/or
emissions where additional generation is required closer to the demand source.

Chapter 2: Delivering a reliable decarbonised power system

64

Figure 2.7 GB regional annual demand and RES
generation (TWh) in 2035

300

300

200

200

100

100

0

DemandRES
generation
Scotland0

DemandRES
generation
Northern England and Wales

300

300

200

200

100

100

0

DemandRES
generation

Southern England and Wales0

DemandRES
generation

Eastern England

Source: Central scenario, AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.
Notes: 2012 weather patterns were used in this analysis. Total power demands for England, Scotland and Wales basedon CCC analysis, and divided among the respective zones using the current demand split, with additional demand
from electrolysers an output of modelling. Regarding supply, existing capacity allocated in line with current
deployment, with additional renewable deployment informed by planned capacity, repowering of existing sites andpotential further development of current locations. Renewable generation profiles developed using location-specificanalysis considering historical profiles for plants in each energy zone, local wind variability and speed. Nuclear
deployment agreed in discussion with CCC. Location of remaining capacity subject to optimisation, taking into
account constraint management, TNUoS cost and other relevant factors.

Very large investments in
network capacity are
expected to be needed tosupport the transition.

The analysis undertaken for this report, and work by others such as National Grid
Electricity System Operator (ESO) in its Pathway to 2030, illustrate the need for verylarge investment in transmission network capacity as we transition to a resilient
decarbonised system. Significant distribution network investment is expected to beneeded alongside this.
•The modelling undertaken for this report considered the transmission-levelnetwork needs associated with the scenarios.
– Planning and identification of transmission investment needs involves
splitting the UK transmission system into ‘zones’, with the boundaries
between these zones reflective of where the main bottlenecks lie.
These change over time as the network is reinforced and network
users’ needs change.
– A number of boundaries have been identified by the ESO as being
particularly critical to the facilitation of a decarbonised electricity
system by 2035. The network’s capability to transfer power across theseboundaries, relative to future need, has been assessed in the analysis
we commissioned from AFRY. **65

Boundaries assessed in modelling undertaken by AFRY based on 2021 Network Options Assessment. While capacity
can be defined as the physical MW capacity of the asset, boundary capability is defined as the maximum MW flowthat can be transferred across a boundary while maintaining compliance with the National Electricity Transmission
System Security and Quality of Supply Standards. Limiting factors on transmission capacity include thermal circuit
ratings, voltage constraints and dynamic stability.

Delivering a reliable decarbonised power system

– The analysis used assumed costs of reinforcement. An optimisation wasthen undertaken, considering generation dispatch, network utilisation,
alternative energy transport solutions (such as electrolysis / transport /storage of hydrogen via pipelines, charging power storage
technologies, and a degree of renewable curtailment) and network
reinforcement.
•

The modelling undertaken for this report found that in order to facilitate thedelivery of the decarbonised system, all the electricity transmission network
boundaries examined would be expected to require some level ofreinforcement, with an average doubling of their capability required
between 2025 and 2035 (Table 2.2). *– The disproportionately large growth in network capacity, relative tothe growth in demand (a 50% increase by 2035) is driven largely by thegeographical disparities between supply and demand.
– Increased temperatures, not factored into the network modelling,
would require even greater strengthening of network capacity.

*•

The scale of transmission reinforcement needs continues to be assessed by
National Grid amongst others, who have stated that, in order to support theGovernment target of 50 GW of offshore wind by 2030, in the next sevenyears it will have to install more than five times the amount of transmission
infrastructure in England and Wales than has been built in the last 30
years. 11 The requirements in Scotland will add to this further.

•

While the modelling undertaken for this report focuses on transmission
needs, distribution networks will need reinforcement alongside this. Growthin demand, driven in particular by the electrification of transport and heat,
will lead to a need for significant distribution network investment. The scaleremains uncertain in the context of data limitations around low voltage
network utilisation, and decisions yet to be taken on the decarbonisation ofhome heating, but Government figures (calculated prior to publication of
the Energy Security Strategy) put the potential investment required by 2050
at between £60-180 billion. 12 Engagement with Distributed Network
Operators (DNOs) undertaken for our Sixth Carbon Budget advice
highlighted the importance of strategic planning and co-ordination if therequired build is to be achieved. 13

While the modelling assesses an approximately optimal level of capacity required in each year (tracking growth indemand and supply), in reality the number of upgrades should be minimised, future-proofing in anticipation of
future needs.

Chapter 2: Delivering a reliable decarbonised power system

66

Table 2.2
GB transmission network reinforcement by zone in Central scenario (GW)
Boundary

2022

2025

2028

2030

2035

B2

3.3

3.8

4.5

6.0

6.9

B4

3.4

4.3

4.7

6.5

11.5

B6

6.3

7.7

10.7

12.7

14.5

B7a

9.7

10.5

11.2

13.2

18.2

B8

11.1

13.0

14.5

16.5

21.0

EC5

3.4

3.5

12.5

16.0

20.7

LE1

9.7

9.7

10.5

12.0

14.1

SC1

3.2

6.1

8.5

10.0

15.0

SC3

7.3

6.7

7.4

7.4

7.4

SW1

3.0

2.9

2.9

2.9

4.7

Total

60.3

68.2

87.4

103.2

134.0

Source: Central scenario, AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.

The scale of investment required at both transmission and distribution level has thepotential to be minimised where the locations of demand and generation can be
optimised, and where full use is made of flexible solutions, facilitated by welldesigned market mechanisms. However, the scope for optimising will necessarily
be constrained by wider considerations.

67•

Decisions on the location of generation developments will impact the levelof transmission investment required. However, these decisions are afunction of a wide range of factors including planning, generation potential
and geographical diversity in the case of wind (key for helping to manage
the impact of regional wind droughts).

•

Flexibility of demand and distributed resources such as local-scale
generation and storage can, depending on the precise location, lead to a
reduced need for distribution network reinforcement.

•

Both generation and network capacity need to be practically deliverable
in the timescales required to meet the 2035 target and accommodate
further growth in electricity demand, not just theoretically optimal. This is
likely to place constraints on location of generation and the nature of
network reinforcement.

Delivering a reliable decarbonised power system

(ii) The role for strategic investment and planning
Strategic investment will be key
to timely and cost-effective
delivery. The network should bedesigned and built anticipating
major new sources ofgeneration and demand to
2050.

Strategic planning andinvestment must also ensurethat infrastructure is resilient tothe changing climate.

There is a need for the
institutional responsibilities of
the FSO, Ofgem and Ministers
to be formalised in these areas
and more broadly, clearlydelineating respective roles inthe strategic planning anddelivery of a decarbonised,resilient system.

Strategic investment will be key to timely and cost-effective delivery. The network
should be designed and built anticipating major new sources of generation anddemand to 2050.
•

We have previously advised that the cost of upgrading distribution networks
is relatively insensitive to the size of the capacity increase as most of thecost is in the civil works rather than the equipment (e.g. larger cables).

•At transmission level too, there is scope to maximise efficiency and minimise
costs and disruption where networks can be future-proofed on the basis of
anticipated future needs, avoiding the need for repeated upgrades.

•

Wherever possible, when grid capacity is increased this should be to a levelsufficient to avoid having to upgrade the capacity again prior to 2050.

Strategic planning and investment must have a view to both delivering theinfrastructure required to meet our climate change targets and ensuring that
infrastructure is resilient to the changing climate.
•

While IT, protection and control equipment used on the network may
typically only have a 10-year life, most network assets should last 40-60
years. This means that the investments in the transmission network expansion
and upgrades to the distribution network required in the next few years will
likely be in use through to 2050 and beyond.

•

Climate hazards will pose an increasing risk to network infrastructure overthe coming decades, with heatwaves giving rise to reductions in electricity
network thermal ratings (the capacity to carry power), and hazards such as
flooding and high winds capable of causing losses in network capacity.
These risks are discussed further in Chapter 4.

•

Given the scale of network build required, mitigation and adaptationneeds must be considered holistically in strategic planning and investment.

There is a need for the institutional responsibilities of the FSO, Ofgem and Ministers
to be formalised in these areas and more broadly, clearly delineating respectiveroles in the strategic planning and delivery of a decarbonised, resilient system.
•

It is important Ofgem and the FSO have formalised responsibilities in respectof the statutory Net Zero target, and ensuring climate and weather
resilience, to ensure these outcomes can be prioritised accordingly.

•

We set out above that due to the scale and complexity of the task, and theinherent interdependencies, a decarbonised power system can only beachieved through a co-ordinated and strategic approach to delivery. This
includes ensuring clear respective roles in delivery for the Government,
Ofgem and the FSO.

•

Careful system-level and asset-level planning and design will be neededfrom the outset. The Government must take on the role of designing theoverall system or delegate clearly to another body with the powers andcapacity to do so.

Chapter 2: Delivering a reliable decarbonised power system

68•Future System Operator (FSO) roles have yet to be finalised, but areas
identified for potential future roles and functions include hydrogen, CCUS,
and heat decarbonisation amongst others. 14 This report demonstrates theclear value in having an integrated view across electricity, gas andhydrogen sectors given interdependencies. We set out later in this section
the value of a cross-sectoral perspective, which accommodates CO2 andheat networks in addition.

Recommendation

Owner (timing)

Clarify urgently and formalise the institutional responsibilities of the FSO, Ofgem and Ministers, forstrategic planning and delivery of a decarbonised, resilient energy system. As part of this, Ofgem’s
objectives and duties must be updated to drive explicitly the delivery of the statutory Net Zerotarget, and to ensure climate and weather resilience. In addition to its Net Zero objective, the FSO
must have responsibility for ensuring weather and climate resilience through its strategic planningrole. The critical role of strategic investment in delivering these outcomes must be recognised, withappropriate mandates and powers for Ofgem and the FSO. The formalisation of responsibilities
should be implemented through the Energy Bill and revisions to the Strategy and Policy Statement.
As part of the phased approach to the implementation of the FSO, expanding the remit withrespect to hydrogen should be considered as a priority.

DESNZ (2023)

A range of work is ongoing to identify strategic investment needs. Ofgem, DESNZ,
the ESO and the network owners have been working on processes to identify the
key transmission network developments needed and inform a ‘Centralised
Strategic Network Plan’ (CSNP), building on the ‘Holistic Network Plan’ (HND) andthe ‘Network Options Assessment’ (NOA) process. There are currently challenges in
identifying transmission network development needs with the level of precisionneeded to define projects and advance them in a timely manner. These must be
overcome, with the CSNP giving sufficient foresight and confidence in needs, suchthat development projects can be rapidly advanced.
Recommendation

Owner (timing)

Publish the second transitional Centralised Strategic Network Plan, identifying the strategic
investments required for a decarbonised and resilient electricity system in 2035 and delivery of Net
Zero. Provide a robust treatment of uncertainty and sufficient, clear information for network
development projects to be advanced in a timely manner. Ensure such projects are designed tobe resilient to a changing climate.

ESO/FSO (2023)

In addition to ongoing
electricity network strategicplanning, we strongly support
the call made in the Mission
Zero review for a long-termcross-sectoral infrastructure
strategy, which should bedelivered by 2025 at the latest.

69

In addition to ongoing electricity network strategic planning, we strongly support
the call made in the Mission Zero review for a long-term cross-sectoral infrastructure
strategy. This should be delivered by 2025 at the latest, following the second
National Infrastructure Assessment (planned for 2023), and drawing on the adviceof the FSO (planned to be established by 2024).
•

We consider it important that the scope should be extended to cover heat
networks, given the interactions with decisions on electricity and hydrogen
infrastructure which will be needed for heat decarbonisation.

•

In addition to being critical to timely delivery, a coordinated plan acrossliquid and gaseous fuels, electricity, CO2 and heat networks has potential todrive significant efficiency savings. For instance, where streets only need be
dug once for the purposes of multiple co-ordinated infrastructure upgrades.

Delivering a reliable decarbonised power systemA key early aim should be toinform and narrow the spacefor future decisions onhydrogen use, by identifying
which areas are unlikely to besuitable for hydrogen (enabling
electrification to be
progressed), alongside theidentification of potential
candidate areas for hydrogen.
This should be used to inform aset of low-regret investmentsthat can proceed immediately.

•This assessment should be on a whole-system basis (considering liquid andgaseous fuels, electricity, CO2 and heat networks) and looking acrosseconomy-wide decarbonisation needs (including buildings, industry andtransport).

•

Building on our previous recommendations, a key early aim of this strategy
process – published by 2024 at the latest (either prior to, or as part ofpublication of the strategy as a whole) – must be to inform and narrow thespace for future decisions on hydrogen use and identify low-regretshydrogen and electricity infrastructure development.
– This should include identification of areas that are unlikely to besuitable for hydrogen, such that electrification and other alternatives
can be progressed, alongside the identification of potential
candidate areas for hydrogen.
– It should include consideration of hydrogen infrastructuredevelopments, such as on storage and transmission, that are lowregret regardless of subsequent decisions on use of hydrogen forbuildings heat.
– This should be used to inform a set of low-regret hydrogen andelectricity infrastructure investments that can proceed immediately.

Recommendation

Owner (timing)

Develop a long-term cross-sectoral infrastructure strategy to adapt and build respectively the
distribution of liquid and gaseous fuels, electricity, CO2 and heat networks over the next decade.
This should be led by DESNZ, drawing on the advice of the FSO and building on the findings of theforthcoming National Infrastructure Assessment. It must have a view to facilitating Net Zero while
ensuring climate and weather resilience. A key aim should be to inform and narrow the decision
space for future decisions on hydrogen use.

DESNZ, FSO (by2025 at the latest)

Identify a set of low-regret electricity and hydrogen investments that can proceed now. Either priorto, or as part of publication of the cross-sectoral infrastructure strategy, identify on a whole systemand economy-wide basis which areas are unlikely to be suitable for hydrogen (such thatelectrification and alternatives can be progressed), alongside potential candidate areas forhydrogen. This should be used to inform a set of low-regret investments that can proceed
immediately.

DESNZ, FSO (by2024 at the latest)(iii) Expediting build
A number of processes –including planning, consenting
and connections – must be
urgently reformed to deploy
infrastructure at sufficient
speed. A wide number ofenabling initiatives are alreadyin train, but their criticality
necessitates effective
oversight. We consider a
Minister-led delivery groupwould best support timely
progress.

A number of processes – including planning, consenting and connections – must
be urgently reformed to deploy infrastructure at sufficient speed to deliver therequired range of system components by 2035. Infrastructure build rates, both forgeneration and network capacity, will need to exceed what has been achieved
historically in a number of areas and represent large increases relative to today.
Given the level of investment needed, we must not miss the opportunity to build in
system- and asset-level resilience from the start. Reformed processes must ensure
infrastructure is built to be resilient to the changes in UK weather (including flood
risks and heat extremes) that will occur over its lifetime.
The Electricity Networks Commissioner, appointed by BEIS, has been tasked withfinding ways of speeding up the delivery of new transmission network capacity
and is considering the whole process from identification of need, to acquisition ofplanning consents and procurement, construction and commissioning.
Chapter 2: Delivering a reliable decarbonised power system70Given that there are separate consenting and planning regimes for electricity
infrastructure in Scotland, and in England and Wales, a key part of this role will beco-ordinating effectively between UK and devolved administrations.
A wide number of enabling initiatives are already in train. However, their criticality
necessitates effective oversight and commitment to implementation if timelines
are to be met. We consider a Minister-led delivery group, with the Electricity
Networks Commissioner in an advisory role, would best support timely progress.
Recommendation

Owner (timing)

Create a Minister-led infrastructure delivery group, advised by the new Electricity Networks
Commissioner, to ensure enabling initiatives for energy infrastructure build are taken forward atpace, and necessary policy changes are implemented across the UK, to deliver a decarbonised
and resilient power system by 2035. This should bring together key senior parties in DESNZ, Ofgem,
Defra, DLUHC, the Scottish and Welsh Governments, the FSO and asset owners, to deliver necessary
policy changes and monitor progress across the initiatives so that swift action can be taken whererequired to expedite progress. Priorities include overhauling planning and consenting (withstrategically important projects prioritised); adequately resourcing regulatory, planning andenvironmental consenting bodies; reforming the connections process; driving strategic investment;
and ensuring the necessary strategic planning and skills/supply chain development is taking place.

Electricity
Networks
Commissioner,
UK, Scottish, andWelsh
Governments(2023)(b) Market reform
Decarbonising the power
sector by 2035 – and realising
the benefits of cleaner,cheaper power - will bringchallenges which current
market arrangements andpolicy are not designed for.

Decarbonising the power sector by 2035 – and realising the benefits of cleaner,cheaper power - will bring challenges which current market arrangements andpolicy are not designed for, including:•

Changing cost structures, towards assets with high capital costs and low
marginal costs.

•

The need to encourage and reward system flexibility, through both supply
and demand sides.

•

The need to phase out unabated gas, subject to security of supply (withany remaining unabated gas plants operating at very low load factors,
raising questions around appropriate frameworks for cost recovery).

The case for decarbonisation, and for market reform to enable consumers torealise the benefits of it, has been strengthened further over the past year in thecontext of Russia’s war in Ukraine and the current affordability challenge.
The Government published its first consultation on the Review of Electricity Market
Arrangements (REMA) in 2022, setting out the case for change and an initialassessment of the options.
The CCC convened a highlevel Expert Group on market
reform. A key conclusion of thegroup was that in order toavoid an investment hiatus, anevolutionary approach tomarket reform is needed in thenear-term, with any more
fundamental reforms
considered for the 2030s.

71

In its advisory role to Government, the CCC convened a high-level Expert Groupon market reform, to feed into the REMA consultation. 15 The Group identified thefollowing priority areas for REMA against the key challenges identified:•Incentivising low-carbon investment: Contracts for Difference should be
retained but evolved to reduce dispatch distortions.

•

Security of supply: Changes to the Capacity Market will be needed toaddress the energy duration challenge, not just peak capacity adequacy,
and to phase-out non-low-carbon solutions.

Delivering a reliable decarbonised power system•Operating a low-carbon electricity system: The energy mismatch(extended shortfalls in some periods, excess supply in others) needs to beaddressed, with more accurate market signals for curtailment.

•

Locational signals: There is a case for stronger locational signals in thewholesale market to improve dispatch efficiency, and potentially tostrengthen investment signals. The appropriate level of locational
granularity needs to weigh up the benefits, against the degree of market
disruption and whether other mechanisms can achieve similar outcomes,
particularly in investment timeframes.

•

Whole-system coordination: Changes in the wholesale market must take
into account potential changes in governance arrangements for the
distribution system and emergence of markets at the distribution level.

•

Customers and affordability: Market design needs to unlock flexibility fromsmall-scale assets through effective customer engagement. Any market
reform should aim to improve affordability through efficient signals,
maximising competition and promoting transparency.

Key conclusions of the Expert Group were that:

It is important that the new
regulations, incentives andbusiness models required are
put in place with urgency toenable the necessary
investment decisions to betaken on a timely basis and at
the appropriate scale.

•

Current policies are not sufficient alone to meet the challenges identified
for fully decarbonising electricity generation and delivering Net Zero.

•

The biggest challenge for the 2020s will be mobilising the huge investment
needed in low-carbon generation, storage and networks; with the biggest
challenge for the 2030s being the efficient operation of the decarbonised
electricity system (with a much more dynamic demand-side).

•

In order to avoid an investment hiatus, an evolutionary approach is neededin the near term (2020s), with any more fundamental reforms, such as full
locational marginal pricing and centralised dispatch, considered for the2030s.

It is notable that since the group was convened, the investment climate isreported to have become even more challenging as a result of inflationarypressures driven by Russia’s war in Ukraine, and competition for finance driven by
the US Inflation Reduction Act and EU Green Deal Industrial Plan. Alongside thesuccessful, timely and cost-effective delivery of a reliable and resilient
decarbonised system, market reform should look to maximise economic
opportunities; ensure fair access to and affordability of energy; support regional
development; and provide appropriate protection for natural capital andecosystem services. It is important that the new regulations, incentives andbusiness models required are put in place with urgency to enable the necessary
investment decisions to be taken on a timely basis and at the appropriate scale.
Regulatory frameworks and market design must be fit for purpose and capable ofgalvanising the £300-430 billion of investment required and the supporting supply
chains.16

Recommendation

Owner (timing)

Through the Review of Electricity Market Arrangements, develop a strategy as soon as possible onmarket design for the medium- to long-term for a fully decarbonised, resilient electricity system inthe 2030s and onwards. It is essential that in introducing changes to market arrangements, this isdone in a way that does not deter the investment required to deliver a decarbonised system by
2035.

DESNZ (2023)

Chapter 2: Delivering a reliable decarbonised power system72

4. Indicators for measuring progress
We have developed aprovisional set of indicators
against which we plan tomonitor progress towards 2035,
with ranges to reflect
uncertainty. We will be keeping
the set of indicators underreview, including considering
any other areas where futureindicators may be needed.

We have set out below a provisional set of indicators against which we plan tomonitor progress towards 2035 (Table 2.3).
The range in these indicators reflects a subset of the scenarios and sensitivities
modelled for the purposes of this report, selected with a view to reflecting therange of outcomes which might be achieved pending uncertainty. This includes
uncertainty around:•

Future demand;•

Policy choices (e.g. different uses for biomass, the use of hydrogen acrossthe economy);•

Technology (e.g. potential for hydrogen conversion of existing gas plants);•

Market developments (e.g. progress in renewable and nuclear build, thebalance between hydrogen and gas CCS in low-carbon dispatchable
power; and•Weather/security of supply considerations (e.g. low wind).

Where ranges are quoted throughout this report, they reflect these scenarios andsensitivities unless otherwise stated. We will be keeping the set of indicators underreview, including considering how best to monitor progress in the context of theindicator ranges, and considering any other areas where future indicators may beneeded (e.g. in relation to network build).
Indicators relating to hydrogen production and storage, and CCS are set out at
the end of Chapter 3. Indicators for climate resilience will be discussed in theenergy chapter of our upcoming Adaptation Progress Report to Parliament inMarch 2023.
The most up-to-date list of indicators will remain visible in our published monitoring
framework. 17

73

Delivering a reliable decarbonised power system

Table 2.3
Indicators for low-carbon flexibility to 2035
Indicator

Unit

2025

2028

2030

2035

Unabated gas share of generation%

18 - 23

4-7

4-5

1-2

In operation

GW

0

3-6

9 - 1312 - 20

Under construction

GW

3-6

7-8

2-4

2-8

In development

GW

8 - 11

2-5

3-7

2-7

Output capacity

GW

7

8-9

10 - 1110 - 19

Capacity

GWh24

26 - 100

30 - 159

30 - 366

%

1

2-3

3-4

4-5

Dispatchable low-carbon capacity

Grid storage

Other
Active demand response as shareof total demand

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.

Chapter 2: Delivering a reliable decarbonised power system

74

Endnotes
1 GE (2022) Hydrogen for power generation: Experience, requirements, and implications for use ingas turbines, https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gas-turbines.

2 Parliamentary Office of Science and Technology (2022) POSTnote 688: Longer Duration Energy

Storage, https://post.parliament.uk/research-briefings/post-pn-0688/.

3 Offshore Wind Industry Council (2022) Offshore Wind Skills Intelligence Report,

https://www.owic.org.uk/publications

4 Offshore renewable Energy Catapult (2021) Industrial leadership – unlocking the UK’s floating

wind potential, https://ore.catapult.org.uk/wp-content/uploads/2021/09/7527-Catapult-Report%E2%80%93-Industrial-Leadership-FINAL.pdf.

5 Slingo, J. (2021) Latest scientific evidence for observed and projected climate change. In: The

third UK Climate Change Risk Assessment Technical Report [Betts, R.A., Haward, A.B. andPearson, K.V. (eds.)] Prepared for the Climate Change Committee, London.

6 National Grid ESO (2022) Resource adequacy in the 2030s,

https://www.nationalgrideso.com/document/273781/download.

7 Regen (2022) Go West! An analysis of the energy system benefits and implications of a moregeographically diverse offshore wind portfolio, https://www.regen.co.uk/publications/go-west/.

8 National Grid ESO (2022) Resource adequacy in the 2030s,

https://www.nationalgrideso.com/document/273781/download.

9 Met Office, NIC, CCC (2021) Adverse Weather Scenarios for Future Electricity Systems:

Developing the dataset of long-duration events, https://nic.org.uk/app/uploads/Met-OfficePhase3b_report_FINAL-Ramping-events.pdf.

10 National Audit Office (2023) Decarbonising the power sector, https://www.nao.org.uk/work-in-

progress/decarbonising-the-power-sector/.

11 National Grid (2022) 2022/23 Half Year Results Statement,

https://www.nationalgrid.com/document/148586/download.

12 BEIS (2022) Electricity Networks Strategic Framework, Appendix I: Electricity Networks Modelling,https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1096248/electricity-networks-strategic-framework-appendix-1-electricity-networksmodelling.pdf.

13 CCC (2020) Policies for the Sixth Carbon Budget and Net Zero, https://www.theccc.org.uk/wp-

content/uploads/2020/12/Policies-for-the-Sixth-Carbon-Budget-and-Net-Zero.pdf.

14 BEIS and Ofgem (2022) Future System Operator, Government and Ofgem’s response to

consultation,
https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1066720/future-system-operator-consultation-govt-response.pdf.

15 Sinclair (2022) Net Zero Electricity Market Design Expert Group report,

https://www.theccc.org.uk/publication/net-zero-electricity-market-design-expert-group/.

16 BEIS (2021) Net Zero Strategy: Build Back Greener,

https://www.gov.uk/government/publications/net-zero-strategy.

17 CCC (2022) Monitoring Framework, https://www.theccc.org.uk/publication/ccc-monitoring-framework/.

75

Delivering a reliable decarbonised power system

Chapter 3

Implications for hydrogenproduction, use and infrastructure
1. Hydrogen demands in the future energy system

79

2. Implications for hydrogen supply

87

3. Hydrogen infrastructure102

4. Implications for fossil fuel consumption

109

5. Indicators for monitoring progress

113

77

Delivering a reliable decarbonised power system

Introduction
Hydrogen has a crucial role to play in decarbonisation of the energy system. It will
be needed for hard-to-decarbonise sectors such as industry and shipping and is
expected to have a role in power generation (as discussed in previous chapters)
although the scale of this remains uncertain.
In this chapter, we build on the analytical findings of previous chapters, examining
what hydrogen demands in a future system could look like across power and nonpower uses, and the range of ways those demands can be met.
We will then consider what this implies for the infrastructure required to transportand store hydrogen.
We present a range of indicators for monitoring hydrogen production and storage
progress towards the 2035 objective, which will be used as part of our annual
reporting to Parliament.
This chapter is set out in five sections:
1. Hydrogen demands in a future energy system
2. Implications for hydrogen supply
3. Hydrogen infrastructure
4. Implications for fossil fuel consumption
5. Indicators for monitoring progress

Chapter 3: Implications for hydrogen production, use and infrastructure78

1. Hydrogen demands in the future energy system
In this report, we consider the role of hydrogen not only in the electricity sector, butalso the demand for hydrogen from across the economy, and how thosedemands can be met.
Hydrogen is likely to have anumber of roles in the futureenergy system; decarbonising
applications that cannot beeasily electrified and helping tomanage the power system.

Hydrogen is likely to have a number of roles in the future energy system:•

Decarbonising applications that cannot be easily electrified.

•

Decarbonising at least some current industrial gas combined heat andpower (CHP) plants, providing low levels of power generation.

•

Providing flexibility in the power sector to store excess power and generate
on-demand to back up variable renewables.

The latter two roles are represented as outputs of the modelling AFRY has
undertaken for this report. Non-power demands for hydrogen were provided by
the CCC as an input to the modelling (based on Sixth Carbon Budget scenarios),
enabling simultaneous optimisation of the power and hydrogen production andstorage systems. Before stepping through the findings of this work, we set out below
the hydrogen production and storage assumptions used by AFRY in their modelling(Table 3.1).

79

Delivering a reliable decarbonised power system

Table 3.1
Options for hydrogen in a decarbonised power system
OptionPotential
to be
zerocarbon?

Techno-economic modelling assumptions

StatusDuration

Efficiency(%)

Cost in 2035(£/MWh,£2012)

Financial
lifetime(years)Autothermal
reforming of
natural gas(ATR) CCS

Lowcarbon

N/A

77

48

30

•

Has been demonstrated but
not deployed commerciallyElectrolysis

Yes

N/A

78

22

30

•

Alkaline electrolysers are amature technology•

Proton Exchange Membraneelectrolysers have been
demonstrated but not
deployed commercially

Production

Biomass
gasification CCS

Negativecarbon

N/A

55

61

30

•

Has been demonstrated
without CCS

Salt cavern

Yes

240
hours

95

4.1 – 5.940•

Mature technology, notdeployed at scale

Medium-pressure
tank

Yes

6 hours

95

2.6

40

•

Mature technology

Storage

AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility; CCC analysis.
Notes: All efficiencies are on a HHV basis. Exact costs depend on the technology load factor and have been informed here based on the average loadfactors across the full range of AFRY scenarios. Storage durations refer to the length of time that the store can be emptied for at the maximum emptying
rate. While it is recognised that different salt caverns can have different durations, all the salt caverns used in the modelling have been assumed to havea 10-day duration.

(a) Hydrogen demand outside the power sector
Non-power hydrogen demandvaries significantly across our
Sixth Carbon Budget scenarios,
ranging from 25-127 TWh in
2035 and 123-375 TWh in 2050.

Non-power hydrogen demand varies significantly across the scenarios from our
Sixth Carbon Budget advice. These range from 25 TWh in 2035 for the Widespread
Engagement scenario to 127 TWh for the Tailwinds scenario (Figure 3.1). The range
by 2050 is 123-375 TWh. Our Sixth Carbon Budget Balanced Pathway scenario
remains a relatively moderate scenario for hydrogen use, reflecting our advice on
the need for widespread electrification. Hydrogen has a smaller but crucial role indecarbonising those areas where it is likely to be infeasible or prohibitively
expensive to pursue electrification.
•

In 2035, non-power hydrogen demand in the Balanced Pathway is 65 TWhwith manufacturing and construction (30 TWh) and shipping (22 TWh,potentially as ammonia) being the largest of these sectors. Together theyaccount for 80% of non-power hydrogen demand.

Chapter 3: Implications for hydrogen production, use and infrastructure80

•

Our Sixth Carbon Budget Balanced Pathway assumes a limited role forhydrogen in buildings (11% of homes using hydrogen for heat, primarily as
part of a hybrid heating system including a heat pump), heavy
electrification of surface transport (apart from a small role for hydrogen insome HGVs) and a balance of electrification and hydrogen for
manufacturing.

•

In our Balanced Pathway, we projected that the UK’s non-power hydrogen
demands will grow steadily throughout the 2030s and 2040s, from 66 TWh in
2035 to 117 TWh in 2040 and 204 TWh in 2050.

Figure 3.1 Non-power hydrogen demands in the
Sixth Carbon Budget scenarios for 2035
Hydrogen demand (TWh)

140
120
100
80
60
40
20

Surface transport
Manufacturing and Construction
Other

Tailwinds

Widespread
Innovation

Widespread
Engagement

Headwinds

Balanced
Pathway0

Buildings
Shipping

Source: CCC (2020) Sixth Carbon Budget.

The analysis in this report uses ranges which reflect scenarios and sensitivities basedon demands for electricity and hydrogen in the Balanced Pathway, Headwinds
and Widespread Innovation.
The Balanced Pathway assumes relatively little use of hydrogen for heatingbuildings. Instead, buildings primarily rely on electrification of heating – at bothbuilding-scale and via heat networks – using mainly heat pumps with asupplementary role for smart resistive (i.e. lower-efficiency) heating. This adheres tothe principle set out in our 2018 Hydrogen Review that electrification of energy
end-uses should be pursued where feasible, given the challenges of supplying lowcarbon hydrogen at scale, with hydrogen prioritised to displace fossil fuels where
electrification is not feasible. 1
In our Balanced Pathway, there
was only a small role forhydrogen in heating buildings.
However, much larger roles forhydrogen have been
conceived of.

In the Balanced Pathway, there is only 1.6 TWh of hydrogen demand in thebuildings sector in 2035 and 22.4 TWh in 2050, with the demand coming primarily
from its role in hybrid heat pump systems (comprising a heat pump and ahydrogen boiler operating as a back-up).

81

Delivering a reliable decarbonised power system

However, much larger roles for hydrogen in heating buildings have been
conceived of, which would lead to much higher consumption of hydrogen frombuildings. In our Headwinds scenario, there is a greater deployment of hydrogenboilers with 71% of homes using hydrogen for heat in 2050 (compared to 11% in the
Balanced Pathway). The resulting demands for hydrogen would be 44 TWh in 2035
and 182 TWh in 2050.
Higher levels of demand forhydrogen from buildings would
likely increase dependence on
imported energy considerably.

These much higher levels of demand for hydrogen from buildings would likely
increase dependence on imported energy considerably (see section 2 below). In
order for this to be a reasonable option, it would need to be clear that hydrogenwith sufficiently low lifecycle emissions can be sourced at the necessary scale,
while not risking security of supply or excessive exposure to volatile fossil fuelmarkets.
In our previous analysis, we have assumed that the hydrogen supply gap is filled bydefault with domestic production from fossil gas with carbon capture and storage(CCS) (i.e. blue hydrogen). Blue hydrogen supply, particularly at the Headwinds
scale (or above), comes with numerous challenges. These include: lifecycle
emissions savings well below 100%, dependence on imported gas, and therequirement for large-scale infrastructure for CCS (see section 2 below).

Recent evidence has emergedthat indicates fugitivehydrogen emissions have astronger warming effect thanpreviously thought, raisingpotential concerns over the
climate impacts of puttinghydrogen into gas distribution
grids.

Evidence published in 2022 indicating a considerably stronger warming effect offugitive hydrogen emissions, raises further concerns that putting hydrogen into gas
distribution grids may have negative impacts on the climate (Box 3.1), dependingon the hydrogen leakage rates that could be expected.
Developments since our Sixth Carbon Budget advice, on the evidence regardinghydrogen’s impact as an indirect greenhouse gas and the spike in internationaland UK fossil gas prices, provide further support for the limited role for hydrogen inbuildings decarbonisation; especially in the case that UK blue hydrogenproduction is the main option to fill the supply gap. The Government is planning to
make decisions on the respective roles for electrification and hydrogen in heatingin 2026. 2
Box 3.1
Recent evidence on the indirect warming effect of fugitive hydrogen
There is increasing evidence relating to hydrogen’s role as an indirect greenhouse gas.
While hydrogen is not a strong absorber of infrared radiation and does not directly
contribute to the greenhouse effect itself, it interacts with other chemicals in theatmosphere that lead to an increase in the atmospheric lifetime of other greenhouse gas
emissions. Hydrogen reacts with, and consequently depletes, hydroxyl radicals in theearth’s atmosphere, which play an important role in reducing the lifetime of methane.
Increased levels of hydrogen in the atmosphere then reduce the ability of the hydroxyl
radicals to control methane, indirectly increasing the warming effect of methane in theatmosphere. While this effect has previously been considered at the troposphere – thelowest layer of the earth’s atmosphere – new evidence has explored the effect at thestratosphere – the second lower layer of the earth’s atmosphere – and estimates that the
GWP of hydrogen may be higher than initially thought. Greater attention may therefore
need to be given to hydrogen leakage and its role offsetting some of the benefits of ahydrogen-based economy. However, it is currently not possible to quantify hydrogenleakage and its scale is therefore uncertain. The recent evidence has not yet been
considered in our analysis and will be explored in further detail in our future work.
Source: BEIS (2022) Atmospheric implications of increased hydrogen use; Frazer-Nash Consultancy (2022) Fugitivehydrogen emissions in a future hydrogen economy.

Chapter 3: Implications for hydrogen production, use and infrastructure82

(b) Hydrogen demand in the power sector
Hydrogen also has a potentially key role in electricity generation, particularly inreaching the 2035 decarbonisation target. The modelling commissioned for thisreport estimates that hydrogen demand from the power sector could peak in the2030s and decline over the course of the 2040s, as the balance between
renewables and low-carbon back-up shifts.
Hydrogen is well suited to decarbonise at least some current CHP plants, providing
small levels of power as a by-product of any heat production outside the power
sector. Demand for hydrogen CHP is likely to be focused in the industrial sector but
could also exist in the buildings sector, with its use in the latter depending on
decisions on the role of hydrogen for heating.
Hydrogen can play animportant role in the power
sector by providing flexibility
options to manage both
deficits and surpluses in supply.

The scale of hydrogen demandin the power sector depends
on the balance betweenhydrogen CCGTs and gas CCS
plants in providing low-carbon
dispatchable capacity.

83

However, the potentially greater role for hydrogen in the power sector is likely to
be in providing flexibility options to manage both deficits and surpluses in supply
from other sources:•

When demand is greater than supply and hydrogen turbines are needed toact as low-carbon dispatchable power; and•When supply is greater than demand and electrolysis can provide a
productive use for surplus electricity (e.g. to avoid curtailment of renewablegeneration).

The scale of hydrogen demand in the power sector will depend on the balance
between hydrogen CCGT and gas CCS plants in providing low-carbon
dispatchable capacity (see Chapter 2). The modelling commissioned for this reporttypically favours the use of hydrogen over gas CCS across its range of scenarios(with hydrogen-fired generation making up between 46-100% of low-carbon
dispatchable supply across scenarios in 2035). However, due to uncertainty overtheir future costs and efficiencies, the precise future balance between hydrogenand gas CCS remains unclear:•

At least until the 2040s, additional hydrogen demand at the margin mightneed to be met through blue hydrogen production (see section 2 below).
As such, the choice might well be between providing low-carbon
dispatchable capacity through hydrogen-fired capacity fuelled by bluehydrogen versus gas CCS plants.

•

Gas CCS plants have higher capital costs than hydrogen-fired plants, but
are expected to have lower operating costs (given a slight advantage inefficiency in going from fossil gas to electricity compared to use of bluehydrogen in hydrogen-fired plants). At higher load factors, the lower
operating costs of gas CCS might be sufficient to justify the higher upfront
investment, while hydrogen looks preferable at low load factors.

•

For the higher load factor role, while initially the two options might have
similar overall costs and residual emissions, there is a difference in lock-in.
Whereas a gas CCS plant continues to require methane to operate, thehydrogen plant can initially operate on blue hydrogen before switchinglater to hydrogen from a non-fossil zero-carbon source of production. So
while there may be little difference between the two options in 2035, by
2050 there is scope to switch away from blue hydrogen in the transition to
Net Zero. This would reduce the UK’s dependence on fossil fuel imports andincrease emissions savings.

Delivering a reliable decarbonised power system

While hydrogen storage and use in electricity could in principle be strongly
seasonal, in the modelling undertaken by AFRY for this report, the higher demandin winter is largely met by the greater output of offshore wind. In the modelling,rather than playing a strongly seasonal role, hydrogen storage and use forelectricity generation is largely determined by the need to back-up variable
renewable output on a multi-day / multi-week timescale (see Chapter 2).
Power sector demand for hydrogen therefore fluctuates considerably both on anhourly and a daily basis, but with little seasonal variation in 2035 (Figure 3.2).
Seasonality of demand could be expected to grow as buildings decarbonise, butmuch of the corresponding increase in electricity supply is expected to come from
offshore wind (which positively correlates with seasonal demand), so the role forhydrogen to provide seasonal storage may not be large even by 2050. Theintermittency of the demand for hydrogen in the power sector increases therequirements for storage.
•

The Central scenario finds that power demand for hydrogen – combining
both the relevant portion of inflexible CHP demand and flexible demand
from hydrogen CCGTs and Gas Turbines (GTs) – could be around 85 TWh in
2035. The flexible demand fluctuates up to around 580 GWh/day,equivalent to average daily demands of 24 GW.

•

Baseload production alone would not be able to meet the variation in the
demand for hydrogen in the power sector, and consequently storage
would be required to support the use of hydrogen in this sector. Hydrogenstorage is discussed in more detail later in this chapter.

Figure 3.2 Variation across the year in daily
average hydrogen demand (2035)
40
35
30
25
GW

Power sector demand forhydrogen fluctuatesconsiderably on an hourly anddaily basis.

20
15
10
5
0

Industry

Shipping

Power - CHP

Power - CCGT/GT

Other non-power

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility; CCC analysis.
Notes: Central scenario from AFRY modelling using annual values from CCC Balanced Pathway. Building demandfor hydrogen has not been seasonally profiled as part of this modelling, and as such ‘Other non-power’ demandpresented here for 2035 is flatter than would be expected in reality. Hydrogen use for buildings in AFRY’s Central
scenario remains limited to 1.5 TWh in 2035.

Chapter 3: Implications for hydrogen production, use and infrastructure84This scale of hydrogen use in the power sector in 2035 is not expected to comefrom hydrogen-dedicated new-build plants alone. There would likely also be
retrofits of existing fossil gas plants and hydrogen-ready plants in the mix. This would
be driven both by regulation and commercial incentives to avoid stranded asset
risk.
•

It appears technically feasible that modest retrofits to existing power plants
could be made to convert some gas plant to hydrogen.3 However, thesuitability of power plants will need to be assessed on a case-by-case basis.
Not all plants may have the required space for the widening of thepipework required for higher volumes of gas (per unit of energy) and theselective catalytic reduction technology that may be required to manage
emissions of nitrous oxides.

•

New gas plants could be designed that consider the future conversion tohydrogen such that they are built ‘hydrogen-ready’. These plants would
initially burn natural gas before switching to burn hydrogen at a future datewith the upfront design considerations helping to limit the future cost of
conversion.

•

The location of hydrogen-based power generation will be somewhat driven
by proximity to the availability of fuel, as well as access to hydrogen storagesites and transmission networks. Consequently, decisions on thedevelopment of a hydrogen network need to be made strategically (seesection 3 below).

•

In the Central scenario of the modelling undertaken for this report, about athird of hydrogen CCGT capacity in 2035 would be made up of new-build
plants and the rest would be retrofits.
– New-build CCGT capacity is expected to increase over the 2020s but
then remain flat afterwards. This is driven by the assumed 25-year
lifetime of a new-build hydrogen-fired power plant, combined with an
expected decline in demand for hydrogen-to-power generation in the2040s, as generation from renewable energy sources increases.
– The modelling does however see the capacity of hydrogen-fired
turbines suitable for a ‘peaking’ role (e.g. hydrogen open-cycle gas
turbines) continue to increase throughout the 2030s and 2040s, given
the continued system role of low-carbon peaking plants.
– CCGT retrofit capacity is expected to overtake new-build CCGT
capacity in the 2030s. Retrofitting a gas plant to hydrogen is expected
to extend an asset’s lifetime by 10 years and have lower capex costs
than a new-build CCGT (set out by AFRY as £110/kW instead of£740/kW based on published values),4 while also preventing at least
some of the current gas fleet from being stranded.

The need for hydrogen supply
and demand to grow intandem creates coordination
challenges. Hydrogen-readyturbines and hydrogen
blending could help to relax
this need for tight coordination.

The need for hydrogen supply and demand to grow in tandem creates
coordination challenges to ensure that there is both a sufficient market for the lowcarbon hydrogen production and sufficient low-carbon production to meet newhydrogen demands. There is a value in developing solutions that relax this need fortight coordination between hydrogen supply and demand.
•

85

The build of hydrogen-ready turbines enables plant to be built based on
fossil gas prior to the availability of low-carbon hydrogen supplies, and only
switch once hydrogen is available.

Delivering a reliable decarbonised power system

•Similarly, blending of hydrogen with fossil gas could provide a flexible
demand for hydrogen, whether in power plants or in the gas grid in small
proportions – current estimates are that up to 7% hydrogen by energy(equating to 20% by volume) could be blended into the gas grid withoutchanges being required to gas appliances. 5 While this flexibility is useful, it is
as a short-term measure to manage the hydrogen supply-demand balance
rather than as a long-term solution compatible with Net Zero, which will
require 100% decarbonised solutions.

Hydrogen-ready turbines and blending could therefore be used as a method ofenabling hydrogen supply chains if utilised in the 2020s, by providing a use case forhydrogen ahead of its wider scale roll-out in power and non-power sectors.
However, given its value only as a short-term interim solution, hydrogen blending
has not been modelled in the analysis presented in this report.

Chapter 3: Implications for hydrogen production, use and infrastructure86

2. Implications for hydrogen supply
Low-carbon hydrogen can beproduced in a range of ways.
The main routes for UK
production include electrolysis,
methane reformation with CCS
and biomass gasification with
CCS.

Low-carbon hydrogen can be produced in a range of ways. In this report, we
focus on three routes for UK production, outlined in Box 3.2, plus some options for its
importation.
Box 3.2
Hydrogen can be produced in a range of ways
There are several routes to produce hydrogen. The most relevant methods for UK lowcarbon production are:•

Electrolysis – producing ‘green hydrogen’ (where using renewables), or ‘pinkhydrogen’ (where using nuclear) – involves running an electric current through waterto split the molecules into hydrogen and oxygen. When this is done using zerocarbon electricity, there are no CO2 emissions associated with the operation of theelectrolyser or the energy input to it.

•

Methane reformation with CCS – producing what is known as ‘blue hydrogen’ – using
oxygen to split the carbon and hydrogen in the fossil gas, forming carbon dioxideand hydrogen. We have previously estimated that blue hydrogen can provide a
reduction in greenhouse gas emissions of 60-85% compared to unabated use of fossil
gas.

•

Biomass gasification with CCS - uses biomass as the feedstock and, with use ofsustainable biomass and carbon capture, is one form of bioenergy with CCS (BECCS)
and is considered carbon-negative. This type of hydrogen production is notexpected to comprise a major proportion of future hydrogen supply due toconstraints on sustainable biomass feedstock availability and alternative uses in otherforms of BECCS.

Source: CCC (2018) Hydrogen in a low-carbon economy.

(a) Hydrogen production capacity requirements
The Energy Security Strategy
sets a target of 2 GW and 10
GW of low-hydrogen capacity
by 2025 and 2030, respectively.
However, these targets give a
relatively poor indication of theamount of hydrogen that
could actually be produced.

87

The ESS set a target of 2 GW of low-carbon hydrogen production capacity in the
UK by 2025 and up to 10 GW by 2030, of which at least 5 GW is to be electrolytic.
However, these targets for combined GW give a relatively poor indication of theamount of hydrogen that could actually be produced:•

Blue hydrogen plants (or biomass gasification plants with CCS) could
operate essentially flat out across the year, leading to the production of up
to around 8 TWh annually of hydrogen per GW of capacity – this might
require hydrogen storage to provide the flexibility to meet demands as theyarise. Alternatively, such plants could be operated more flexibly, with alower load factor, but with less need for hydrogen storage.

•

Grid-connected electrolysis, to soak up excess decarbonised electricity
generation, will have low load factors linked to the frequency and size of
those surpluses. Based on a 25% load factor, this might lead to around 2.2
TWh annually per GW of electrolysis capacity.

•

Electrolysis based on dedicated renewables would have a higher loadfactor, linked to the output of the renewable capacity. For example, adedicated electrolyser facility linked to an offshore wind farm could have aload factor of around 50%, producing 4.5 TWh annually per GW.

Delivering a reliable decarbonised power system

The hydrogen production
targets should be set out in a
way that provides a better
indication of hydrogenproduction capacity (e.g. derated GW or TWh/year).

The current Government targets, while providing some indication of ambition forthe sector, could therefore provide production capacity equating to somewhere
between 22 and 62 TWh annually. In order to avoid this lack of clarity, in this report
we use the term ‘de-rated capacity’ to represent the level of hydrogen production
capacity if it were provided by a producer operating constantly at full capacity. It
would be valuable if the Government provided a better indication of hydrogenproduction capacity needs by 2030 (e.g. in de-rated GW or TWh/year).

The modelling for this reportsuggests that the Energy
Security Strategy targets are on
the lower end of what could
be needed to meet the 2035
decarbonisation target.

The results of the modelling for this report suggest that the ESS targets are on thelower end of what could be needed to decarbonise the power sector by 2035.
•

Across the scenarios and sensitivities which make up our provisional
indicator range (see section 5 below), between 9-14 GW of low-carbonhydrogen de-rated production capacity is deployed in GB by 2030, rising to
13-25 GW by 2035.* In both years the majority of the hydrogen production
capacity is blue (CCS-enabled), at least in part due to constraints onavailability of ‘surplus’ electricity generation, with 11-31% being electrolytic
in 2030 and 22-51% in 2035.

•

The lower bounds have potential to be further reduced where heating inbuildings is fully electrified (as in our Sixth Carbon Budget Widespread
Engagement scenario) or where there is a reduced role for hydrogen in the
power system relative to that envisaged in the modelling for this report.†•

Lower demands for hydrogen would yield lower demands for bluehydrogen production (with the volume of electrolysis largely unaffected).
However, a different balance would still see similar overall consumption offossil gas and use of CCS, with the use for gas CCS in power generation
approximately compensating for the reduction for hydrogen production.

(b) The domestic hydrogen demand-supply gap
A key aim of the ESS is to reduce the UK’s dependence on imported oil and gas, toreduce the UK’s exposure to volatile international prices. In this section we look atwhat role domestic hydrogen production could play in meeting hydrogen
demand, and the different options for importing any remaining energy required tomeet demands.‡
Domestically produced electrolytic hydrogen is one route to meeting hydrogen
demands while minimising import dependency risks. However, low-carbon
electricity has its highest value when displacing fossil generation and meeting‘core’ electricity demands – those that already exist in buildings and industry, andthose from highly efficient forms of electrification such as electric vehicles and heatpumps (Figure 3.3).

*

Underpinned by 11-17 GW and 19-33 GW of hydrogen production capacity respectively. The ranges reflect theuncertainty in the scale of future demand for hydrogen.

†

The modelling undertaken by AFRY for this report typically favours the use of hydrogen over gas CCS to provide lowcarbon dispatchable capacity (with hydrogen-fired generation making up between 46-100% of low-carbon
dispatchable supply across scenarios in 2035).

‡

We exclude blue hydrogen from the analysis in this section on the basis that it remains exposed to volatileinternational prices, and the UK is already a net importer of fossil gas and is projected to remain an importer as wetransition to Net Zero, such that blue hydrogen should be considered as effectively meeting hydrogen demands
through imported energy. This is discussed further in section 2d.

Chapter 3: Implications for hydrogen production, use and infrastructure88Figure 3.3 Emissions saved with 1 MWh ofzero-carbon electricity in different applications
1.0
0.9
0.8

tCO2e saved

0.7
0.6
0.5
0.4
0.3
0.2
0.1
0.0

Displace
coal
generation

Power
an EV

Power aDisplaceheat pumpgas
generation

Power
DACCS

Produce
Producehydrogen synthetic
to displace jet fuelfossil gas

1 MWh of zero-carbon electricity used to:
Source: CCC analysis.

Zero-carbon electricity has its
highest value when displacing
fossil generation and meeting‘core’ electricity demands.
Once these demands havebeen met, surpluses can thenbe used to produce electrolytichydrogen.

Once these core demands have been met surpluses can be used in various ways,
including exporting electricity; for electrolytic hydrogen production; and use inflexible applications such as hybrid heating systems.
•

The modelling undertaken for this report assumes a role for both electrolytichydrogen production and exports, in managing surplus electricity.
– Based on modelling of pan-European interconnected markets (andaccounting for the geographic coverage of weather systems),
interconnectors are found to play a valuable role in balancing thesystem, importing during periods of supply deficit and exporting during
periods of supply surplus.
– The activation of electrolysis is also an important means of managing
periods of surplus electricity. This produces relatively cheap electrolytichydrogen which, when combined with storage, can be used togenerate electricity later on. However, there are sizable inefficiencies
in this process, firstly in the process of electrolysis (assumed to bearound 75% efficient), and then in the use of the resulting hydrogen(with hydrogen CCGTs assumed to be around 55% efficient).
There are alternative ways to use surplus electricity in the economy beyond
those modelled for this report. For example, the deployment of hybrid heatpumps in homes in the near term (i.e. alongside existing gas boilers), could
provide a direct and highly efficient use of surplus electricity while providing
flexibility to switch to the boiler at times of insufficient electricity supply. Heatpumps can have efficiencies of 300% or more, displacing gas boiler use (atbest 87% efficient). 6 The potential emissions savings and reductions in fossil

89

Delivering a reliable decarbonised power system

gas consumption are around four times greater than if this surplus electricity
were used for electrolysis. Near-term hybrid heat pump deployment also
has potential to drive wider benefits, including around public acceptabilityof heat pumps more generally. 7
The possible gap between
overall hydrogen demand anddomestic non-fossil hydrogen
supply in 2035 could be in theregion of 7-174 TWh, with therange driven by the use ofhydrogen outside the power
sector and the low-carbon
dispatchable generation mix.

We have used the range of scenarios developed for this report, alongside our Sixth
Carbon Budget scenarios, to illustrate the possible gap between overall hydrogen
demand and the modelled domestic non-fossil hydrogen supply – from electrolysis
using surplus electricity and with a small contribution from biomass gasification withCCS – in 2035 and 2050 (Figure 3.4).
Depending on the scale of interconnector exports and the use of hydrogenoutside the power sector, we estimate the overall gap between hydrogenproduction from these modelled non-fossil sources and demand in 2035 could bein the region of 7-174 TWh.
•As set out in section 1 of this chapter, there is significant variation in nonpower hydrogen demand across our Sixth Carbon Budget scenarios. In themodelling commissioned for this report, the minimum and maximum nonpower demands were taken from our Balanced Pathway and Widespread
Innovation scenarios, but demand could be lower where there is alignment
with our Widespread Engagement scenario where there is no use ofhydrogen in the buildings sector and lower demand for energy overall.

•Power demands for hydrogen were determined in the modelling based on
the overall power demands used in our Balanced Pathway andWidespread Innovation scenario, giving a range in the power demand forhydrogen between 52-106 TWh. The demand here also depends on the
low-carbon dispatchable power mix, with hydrogen use in electricity
generation potentially lower in a mix with a greater share of gas CCS.

•

Regarding supply, there could be a role for biomass gasification, but this isunlikely to be significant due to the limits on the availability of sustainablebiomass and the relatively slow development to-date of biomass
gasification technology. Biomass gasification deployment in combination
with CCS would be worthwhile, but the biomass feedstock could instead beused for BECCS in power (see section 2 of Chapter 1).

•

Expected production of electrolytic hydrogen from surplus electricity in theCentral scenario is 36 TWh in 2035. This is limited to some degree byelectricity exports in the modelling (with GB acting as a net exporter in2035). In the event GB was able to maintain a neutral balance of importand export flows (e.g. pending EU decarbonisation progress), this could
free up a further 27 TWh of electricity for domestic hydrogen production.

While there is greater demand for hydrogen outside the power sector in 2050, thesize of the gap has potential to be lower – and even eliminated if non-power
demands align with the Widespread Engagement scenario – due to reductions indemand for hydrogen in the power sector in the 2040s. However, expansions inhydrogen demand beyond what’s in the Balanced Pathway (e.g. extensive use ofhydrogen for buildings heat) could see the gap increase, potentially considerably.
It appears unlikely that all hydrogen demand in 2035 can be met from domestic
non-fossil fuel production, particularly in light of the already ambitious levels of
renewable and nuclear build assumed in the modelling, on the basis of
Government commitments.

Chapter 3: Implications for hydrogen production, use and infrastructure90

By 2050 there is increased scope for domestic production to meet domestic
demand, but this will be heavily dependent on the Government’s strategic
decisions on the use of hydrogen for heat in buildings, expected in 2026.

Figure 3.4 The gap between annual GB domestichydrogen production and demand
450
400
350

TWh

300
250
200
150
100
50
0

Production Minimum
demandMaximum Production Minimum
demanddemand2035

Maximum
demand2050

Biomass gasification CCS

PowerElectrolysis from surplus GB
electricity
Potential additional electrolytic
production where exports reduced

Non-power
Further demand reduction possible with
Widespread Engagement alignment

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility; CCC analysis.
Notes: AFRY modelling uses demand values from CCC Sixth Carbon Budget. Hydrogen production values havebeen taken from the AFRY Central scenario, in which GB is assumed to be a net exporter of electricity in 2035. The
light orange area represents potential additional electrolytic production in the event exports are lower than AFRY’s
Central scenario assumes. Blue hydrogen production and dedicated electrolytic hydrogen projects are covered
later in the chapter, as means of closing the gap presented in this chart. The minimum and maximum demands(represented by the dark purple, purple, and light purple bars) have been taken from the range of AFRY scenarios,
reflecting the range and uncertainty in the scale of future hydrogen demand. The minimum and maximum
demands correspond to the AFRY Grid Storage and High scenarios, respectively. The High scenario uses our Sixth
Carbon Budget Widespread Innovation pathway for non-power hydrogen demands. The Grid Storage scenario
uses our Sixth Carbon Budget Balanced Pathway for non-power hydrogen demands. It remains that non-power
demands for hydrogen could be even lower than this. The light purple area represents the demand that could be
netted off, where aligning non-power hydrogen demands to the CCC’s Sixth Carbon Budget Widespread
Engagement scenario, in which greater societal shifts in behaviour are assumed and buildings are fully electrified(Figure 3.1).

(c) Dedicated zero-carbon electricity to fill the hydrogen supply
gap
One option to fill the gap is todedicate zero-carbon
electricity to the production ofelectrolytic hydrogen.

The amount of electrolytic hydrogen production in the AFRY model is estimated on
the basis of the assumption that electrolytic hydrogen will be produced using
surplus electricity (i.e. where the power available at a point in time exceeds
demand).
However, electrolysis can also be applied to zero-carbon electricity dedicated tothe purpose of producing hydrogen in the UK. This approach is not dependent on
importing energy from other countries and can consequently support greater
energy security.

91

Delivering a reliable decarbonised power system

Electrolysers operating from a dedicated zero-carbon electricity supply canachieve much higher load factors than those operating from surplus electricity,and more continued modes of operation can support higher operating
efficiencies. Higher load factors mean that the contribution of electrolyser capitalcosts to overall hydrogen production costs is lower, as the cost is spread over moreunits of output. However, much higher electricity costs would be incurred, withestimates suggesting that hydrogen produced from dedicated zero-carbon
electricity would be more expensive than hydrogen from curtailed electricity.
•

Assuming the capacity of the electricity source matches the capacity ofthe electrolyser (no overplanting), electrolysis can run at the same loadfactor as the source.

•

Hydrogen produced from dedicated zero-carbon electricity would likely
pay the levelised cost of its electricity source as the electricity price.

•

While electrolysers could be connected to a variety of zero-carbon
electricity sources, offshore wind would be the most likely due to its highload factor and low levelised cost of energy. Green hydrogen produced
from a dedicated source of offshore wind has been estimated to costaround £80/MWh in 2035 falling to around £70/MWh in 2050. In contrast,hydrogen produced from curtailed electricity is estimated to cost £4653/MWh in 2035 and £42-50/MWh in 2050. 8

Dedicated electrolytic production in the UK is likely to be preferable to importing
electrolytic hydrogen. This is due to the uncertainties surrounding the developmentof an internationally traded market for hydrogen (discussed below), as well as thelower costs and energy security benefits of domestic production compared toimports.
Zero-carbon electricity must be
prioritised to displace fossil
generation and meet coreelectricity needs (including EVs
and heat pumps). Hydrogenfrom dedicated zero-carbon
electricity should therefore only
be based on generation
sources where it is not possible
to connect to the grid.

The highly ambitious build rates
for planned zero-carbon
electricity mean that thepotential for dedicatedprojects to contribute to fillingthe 2035 gap is limited.

However, as discussed earlier in this chapter, zero-carbon electricity must first be
used to displace fossil generation, then used to meet core electricity demands(such as EVs and heat pumps) before being used to solely produce hydrogen. Thismeans that existing zero-carbon electricity capacities and commitments must not
be allocated to dedicated hydrogen production.
Hydrogen from dedicated zero-carbon electricity should therefore only be basedon extra zero-carbon electricity capacity or from zero-carbon electricity sources
where it is not possible to connect to the grid (e.g. ‘stranded’ renewable capacitythat cannot feasibly connect to the electricity system).
The highly ambitious build rates planned for zero-carbon electricity in the path to2035 imply that the potential for dedicated electrolysis projects to contribute tohydrogen supply on this timeframe is likely to be limited, with a more material rolein the longer term.

(d) Importing energy to fill the hydrogen supply gap
The modelling commissioned for this report was set up to require all hydrogen
demands to be met through GB-based hydrogen production. The model
predominantly chooses to fill the gap between demand and what can besupplied from non-fossil sources of domestic production with production from fossil
gas with CCS (‘blue hydrogen’).
However, the UK is already a net importer of fossil gas, and domestic production offossil gas is projected to continue to fall over coming decades (Figure 3.5).
Chapter 3: Implications for hydrogen production, use and infrastructure92

Although the UK’s consumption of gas will also have to fall to be on track for Net
Zero, our previous analysis indicates that these two declines will occur at similar
rates.
The UK is expected to continue
to be a net importer of fossil
gas over the coming decadeswith UK gas production unable
to meet even the fallingdemands for gas as we
decarbonise. Further gas
demands for use with CCS (toproduce electricity orhydrogen) will increase gas
imports by a corresponding
amount.

The UK is therefore likely to continue to be a net importer of fossil gas over coming
decades, with supplies of gas from UK production being insufficient to meet evenfalling demands for gas in existing uses as we decarbonise: buildings, industry –including as a chemical feedstock – and unabated use in electricity generation,
until the late 2040s (Figure 3.5).
Further gas demands on top of these uses, by building new facilities in the next two
decades using fossil gas with CCS for energy production (whether for electricity orhydrogen), will increase the amount of gas imports by a corresponding amount,and can effectively therefore be considered as using imported gas.

Figure 3.5 Projected fossil gas consumption in the
Balanced Pathway compared to UK production
900
800

Fossil gas (TWh)

700
600
500
400
300
200
100
2050

2048

2046

2044

2042

2040

2038

2036

2034

2032

2030

2028

2026

2024

0

Use with CCS in hydrogen supply

Use with CCS in electricity supply

Use with CCS in industry

Unabated use in industry

Unabated use in electricity supply

Unabated use in buildings

Unabated use in other sectors

Projected North Sea gas
production

Source: CCC analysis; NSTA (2022) August 2022 oil and gas production projections; CCC (2021) Letter: Advice to the
UK Government on compatibility of onshore petroleum with UK carbon budgets.
Notes: The wedges represent different uses of fossil gas in the CCC’s Balanced Pathway from the CCC’s advice in2020 on the Sixth Carbon Budget. The use of CCS with gas for electricity generation and hydrogen production isdifferent to that presented in this report, based on AFRY modelling, both in volumes and balance between
electricity and hydrogen. Projected consumption includes non-energy use at 2019 levels (4.5 TWh/year).

93

Delivering a reliable decarbonised power system

Imported energy could be
used to fill the gap between
domestic hydrogen production
and demand. However,hydrogen based on imported
energy would have todemonstrate that it is lowcarbon across its lifecycle.

In reality, there are various ways in which imported energy could be used to fill thedomestic hydrogen demand/supply gap. Hydrogen based on imported energy,
regardless of route, would have to demonstrate that it is low-carbon across its
lifecycle:•

The UK has developed a Low-carbon Hydrogen Standard that defines lowcarbon hydrogen up to the point of production* as having an emissions
intensity of no more than 60.8 gCO2e/kWh.9•

The Government has also announced plans to use the standard to develop
a globally recognised certification scheme for low-carbon hydrogen, with
the intention of being introduced by 2025.10 It can be expected that any
hydrogen imports would have to adhere to this standard.

In this section, we consider the challenges and benefits of blue hydrogen,imported green hydrogen and using imported electricity to make electrolytichydrogen in GB.

(i) Blue hydrogen
Fossil gas can be used to
produce blue hydrogen.
However, supplying bluehydrogen at scale requires adeveloped UK CCS
infrastructure, a reliance on
imported gas and challenges
with lifecycle emissions to be
overcome.

Blue hydrogen supply at scale comes with several challenges for compatibility withthe cost-effective delivery of Net Zero. These include ensuring it has sufficiently low
lifecycle emissions, deploying CCS in the UK at the scale required and its relianceon imported gas:•

When produced in a way that aims to minimise residual emissions, weestimate that blue hydrogen could provide lifecycle emissions savings of 6085% compared to unabated gas. Where usage is limited to sectors of theeconomy it is not feasible to electrify or reduce demand further, this level of
reduction is a valuable contribution to Net Zero (considering the alternative
is continued use of unabated fossil fuels). Nevertheless, ideally the emissions
savings would be towards the top end of this range, or even higher.
– Producing hydrogen via autothermal reformation of methane with
CCS is expected to have an efficiency of about 80%, with carbon
capture of between 90-95%. When including upstream emissions fromfossil gas supply, for which we assume a range of 15-70 gCO2e/kWhbased on our work on gas supply, this represents a reduction of around60-85% relative to use of unabated gas. †– Such calculations, and adherence with any future low-carbon
certification scheme, depend strongly on the upstream emissions fromfossil gas production and transportation. Indeed, it currently appears
plausible that the bulk of imported gas will be in the form of Liquefied
Natural Gas (LNG). This can have high supply-chain emissions if
significant quantities of the methane leak.
– Unless strong rules are developed and implemented on upstream
emissions of fossil fuel imports, this option provides little control over the
likely significant contribution of the fossil gas production process to thelifecycle emissions of blue hydrogen.

*

The point of production is specified as including all emissions from raw materials acquisition, upstream suppliers andthe operation of the hydrogen production plant†

Calculations on the lifecycle emissions of blue hydrogen do not include any contribution from fugitive hydrogen
emissions acting as an indirect greenhouse gas, which would depend on leakages rates – these are currently
uncertain and likely to depend on the application for which hydrogen is used (see Box 3.1 in the previous section).

Chapter 3: Implications for hydrogen production, use and infrastructure94•While our assessment is that carbon capture and storage (CCS) is essential
to meeting Net Zero, it has not yet been deployed at scale in the UK. With
the large-scale infrastructure development it implies, the scale to which a
CCS industry can be developed by the time the UK reaches Net Zeroremains unknown. Given this uncertainty, and the need to prioritise CCS forindustry and greenhouse gas removals ahead of energy generation fromfossil fuels, it is prudent to limit use of CCS on fossil gas where possible.

•

As set out above, the consumption of fossil gas for blue hydrogenproduction in the UK will increase imports by a corresponding amount. As
illustrated over the past year, international fossil gas prices can be highly
volatile, and security of supply is not guaranteed.

Using only blue hydrogen to fill the hydrogen supply gap in 2035 (as outlined in
Figure 3.4 above) would imply fossil gas imports for this purpose of 9-217 TWh/year. *The central value of this range is comparable to the 138 TWh/year of fossil gas
consumption (and therefore imports) from use with CCS in hydrogen production
and power generation estimated in the Balanced Pathway.
In terms of the required infrastructure, multiple domestic production plants would
likely be required, with early plants located near CO2 storage
facilities/infrastructure.
•

The optimal production profile for blue hydrogen is baseload, as it cannot
easily be ramped up or down quickly. However, having multiple production
plants allows for staged increases or decreases in output. In combination
with hydrogen storage, this can potentially create enough operational
flexibility to meet variations in required supply.

•

While all forms of hydrogen depend on the development of infrastructure
for its transportation and storage, blue hydrogen also depends on a CO2transport and storage network. Therefore, in the early days of its
development blue hydrogen is likely to be located near a CCS sink tominimise the requirements for CO2 transportation and storage.

•

While it is also conceivable that the UK could import blue hydrogen madeoverseas, in practice it appears more likely - given the existing LNG and gas
pipeline infrastructure - that the energy would be imported as fossil gas
rather than as hydrogen.

The gap between hydrogen demands and domestic non-fossil hydrogen supply
has the potential to be smaller by 2050 than in 2035, given the potential for the UK
to increase domestic zero-carbon hydrogen production to be ramped up in the
period post-2035. In this event, some blue hydrogen capacity put in place in theearly 2030s would be expected to fall into a back-up role during the 2040s.
However, this back-up role – in combination with the existing LNG importinfrastructure – would provide additional energy security (e.g. for a low-wind year)
in a decarbonised way.

*95

Assuming 80% efficiency.

Delivering a reliable decarbonised power system

(ii) Imported green hydrogen
Green hydrogen could be
imported from renewableenergy resources outside theUK, especially from countries
with abundant potential for
low-cost generation.

If the UK is going to import energy to fill the hydrogen supply gap, it is important toconsider how renewable energy resources outside the UK might be utilised,especially from countries with abundant potential for low-cost generation (e.g.
from solar in sunny regions).
Hydrogen is relatively difficult and costly to transport so while a small amount oftransportation currently occurs, the vast majority of current hydrogen use is captive
and occurs directly on the same site as its production. However, there is potential
for its international trade, especially if costs reduce:•

Producing green hydrogen is expected to have large potential for cost
reductions.
– Green hydrogen costs are driven by the cost of zero-carbon electricity
and the capital costs and efficiencies of electrolysers, alongsideassociated network costs. 11 The cost of renewable energy has
continued to fall over the past decade, while electrolyser costs can be
expected to reduce from around £705/kW to below £100/kW by 2050
as economies of scale and learning curve effects are realised. 12– In the UK, producing green hydrogen from curtailed electricity
currently costs between £65-133/MWh depending on the electrolyser
technology used. 13 This could reduce to around £50/MWh by 2050.
However, in locations with access to plentiful, low-cost renewableenergy resource, this could fall below £30/MWh in 2050. 14

Several countries haveannounced their intentions toexport green hydrogen. This
offers the UK an opportunity todiversify its energy imports.

•

In years to come it is likely that a greater number of countries will becompetitively exporting green hydrogen than there are which currently
export fossil gas or blue hydrogen. 15 This offers the UK an opportunity todiversify its energy imports across multiple countries and geographicalareas.
– Fossil fuel reserves are concentrated in a few locations with 64% of
global gas reserves located in five countries. Security of supply fromthese countries is not guaranteed and price spikes have occurred
when supplies have been disrupted. 16– Globally there is much wider access to renewable energy than fossil
energy. Countries including Chile, Norway, Australia and those in North
Africa are expected to become key exporters of green hydrogen (Box
3.3).

Hydrogen can be compressed
and imported via pipelines orconverted to a transportableform and shipped. Pipelines are
expected to be more costeffective than shipping for
distances less than 2,000 km.

Large volumes of hydrogen can be imported via pipelines or shipping, with themost cost-effective method depending on the distance from the exporter.
Shipping enables green hydrogen to be imported from countries where theconstruction of pipelines is not possible and as such green hydrogen via hydrogen
vectors would be the expected mode of transport from countries such as Chileand Australia.

Chapter 3: Implications for hydrogen production, use and infrastructure96Box 3.3
Several countries have announced plans to be net exporters of green hydrogen
Several countries with high potential for renewable energy have published hydrogenstrategies that outline their intentions to become exporters of green hydrogen.
•

Morocco published its green hydrogen roadmap in 2021, identifying green hydrogenas a key growth sector for its economy. By 2030, Morocco envisages a local
hydrogen market of 4 TWh and plans for an export market of 10 TWh, requiring theconstruction of 6 GW of new renewable energy capacity.

•

Chile announced their National Green Hydrogen Strategy in 2020. The strategy aims
to have developed the most cost-efficient green hydrogen by 2030 and to beamong the top three exporters of green hydrogen by 2040. To achieve these goals,
Chile intends to have deployed 5 GW of electrolyser capacity by 2025 and 25 GW by
2030.

•

Australia outlined its intentions to encourage the development of domestichydrogen production capabilities for domestic and export purposes in its 2019
National Hydrogen Strategy. The strategy sets a vision for commercial greenhydrogen exports by 2030 and Australia aims to be among the top three exporters ofhydrogen to Asian markets by 2030.

Source: Royaume Du Maroc Kingdom of Morocco (2021) Feuille de Route Hydrogène Vert; Gobierno de Chile(2020) National Green Hydrogen Strategy; COAG Energy Council (2019) Australia’s National Hydrogen Strategy;
IRENA (2022) Geopolitics of the Energy Transformation: The Hydrogen Factor.

Hydrogen can be shipped by converting it into a more easily transportable form
(e.g. as liquid hydrogen or hydrogen vectors such as ammonia or liquid organichydrogen carriers). Converting to these forms and then reconverting back tohydrogen incurs additional costs due to efficiency losses in the conversions and theenergy required to be input. Shipping therefore tends to be outcompeted bypipeline transport over shorter distances. Due to the cost of the conversions, it may
be advantageous to focus the use of shipping imports on sectors where thehydrogen vectors can be used directly (e.g. use of ammonia as a low-carbon fuelfor the shipping sector).
The cost of importing hydrogen via ships varies based on the hydrogen vector
used:

97

•

Ammonia is the cheapest hydrogen vector for shipping, with costs ofaround £2-6/MWh per 1,000-10,000 km travelled. However, the costs of
converting and reconverting to and from hydrogen can currently add up
to between £60-90/MWh. 17•

Liquifying hydrogen and shipping is expected to be more expensive, withcosts around £30-45/MWh per 1,000-10,000 km travelled, and a further£60/MWh for the conversion processes. Technology to ship liquid hydrogenis also at an earlier stage of development relative to shipping ammonia
and is unlikely to be an economically feasible transport option in the near
future. 18•

The conversion and reconversion costs can be expected to reduce withtechnological innovations. However it remains likely that the costs of
converting hydrogen into a transportable form and back again will be far
greater than the costs of shipping, adding significantly to the cost ofimports.

Delivering a reliable decarbonised power system

Despite ammonia already being transported globally, all these energy vectors
need to resolve safety issues around flammability, toxicity and safe storage in order
to be viable options for transporting and storing hydrogen at scale.
For short distances, importing compressed hydrogen over pipelines is expected tobe more economical than converting the hydrogen into a transportable form andshipping.

While unlikely to be costcompetitive in the near-term,green hydrogen imports are
expected to be costcompetitive with domestic
green hydrogen production by
2050.

The UK’s ability to import greenhydrogen by 2035 will dependon how much green hydrogenis globally available for export
and the competing demandsof other countries.

•

Pipeline transportation of hydrogen is considered to be cheaper thanshipping for distances of up to 2,000 km with this increasing to over 3,000 km
if large volumes (greater than 14 TWh/year) can be transported.19
Transporting hydrogen via pipelines would be the expected mode forgreen hydrogen imports from Europe and North Africa. BEIS hascommissioned research on using pipelines to import compressed hydrogenfrom Norway and Spain.20•

The UK currently has gas pipelines with Norway, the Netherlands, Belgium
and Ireland. There is the possibility that these could be repurposed forhydrogen. Retrofitting existing high-capacity gas pipelines for hydrogentransportation could cost 40-65% of new pipeline construction.21 However, it
is unclear whether embrittlement issues could mean conversions are notpossible.

•

It is currently not possible to quantify hydrogen leakage and there areuncertainties around the extent of leakage that could occur during its
transportation.22

While long-term projections are uncertain, green hydrogen imports are estimatedto be cost-competitive with domestic green hydrogen production from curtailed
wind by 2050. (Figure 3.6).
•

It is unlikely that importing green hydrogen will be cost-competitive withdomestic green hydrogen production from curtailed electricity in the nearterm. However, published projections suggest that imports will exhibit
significant cost reductions over the next few decades that are likely toincrease its competitiveness.

•

AFRY modelled the cost of domestic blue hydrogen production to be£50/MWh in 2035 and around £45/MWh in 2050. Based on these costprojections, green hydrogen imports could be expected to also becompetitive with blue hydrogen by 2050.

The UK’s ability to import green hydrogen by 2035 will depend in large part on how
much green hydrogen is globally available for export, and the competing
demands of other countries.
•

The level of global interest in low-carbon hydrogen suggests that a globalhydrogen market is likely emerge over the next few decades. However,there are a wide range of estimates for the potential scale of global greenhydrogen production, and the quantity which could be available forexport. 23,24•

2035 is not far away. Given that an international hydrogen market has notbeen established yet, the viability of imported green hydrogen for any rolein the UK by 2035 remains highly uncertain.

Chapter 3: Implications for hydrogen production, use and infrastructure98

•The European Union has also set a target to import 390 TWh of greenhydrogen by 2030, further increasing the challenge of meeting the 2035
shortfall with green hydrogen imports. 25

Figure 3.6 Projected costs for domestic greenhydrogen compared to imported greenhydrogen (£2020)
0

20

40

60

80

100

120

0

20

40

60

80

100

120

Domestic green hydrogenproduction from curtailed
electricity

Green hydrogen imports(via 3,000 km pipeline)

£/MWh
2030

2040

2050

Source: BEIS (2021) Hydrogen production costs; IEA (2022) Global Hydrogen Review; European Hydrogen Backbone(2021) Analysing future demand, supply, and transport of hydrogen; Energy Transitions Commission (2021) Making
the Hydrogen Economy Possible; PwC (2022) The green hydrogen economy; Hydrogen Council (2022) Global
Hydrogen Flows; CCC analysis.
Notes: Domestic green hydrogen production costs based on the curtailed electricity cost estimates in BEIS (2021)
Hydrogen production costs. This assumes an electrolyser load factor of 25%. The costs for alkaline and PEM
technology have been used to inform the range. Green hydrogen import costs have been determined by
combining published literature estimates for green hydrogen costs in favourable locations with literature estimates
for the cost of transportation via pipeline. High volume pipeline estimates have been used with a pipeline distanceof 3,000 km (the point at which high volume pipelines are estimated to be cheaper than shipping). The range
reflects the variation in literature values and differences in pipeline capacities. Depending on the end destination
for hydrogen, some additional storage costs are likely to be required.

(iii) Imported electricity for domestic hydrogen production
Electricity could be imported
via interconnectors fromcountries with abundant, lowcost renewable electricity to
produce green hydrogendomestically.

A third option to fill the gap between domestic production and demand is toimport electricity directly from countries with abundant, low-cost renewableelectricity via interconnectors and produce green hydrogen domestically.
Interconnectors already play an important role in supporting the UK’s security ofelectricity supply. The number of interconnectors between the UK andneighbouring countries is expected to increase in future with a number ofinterconnection projects under development.
•

99

The Government has committed to deliver at least 18 GW ofinterconnection capacity by 2030 and appears on track to achieve thistarget. 26

Delivering a reliable decarbonised power system

•The UK currently has 7.4 GW of existing interconnector capacity withFrance, the Netherlands, Norway, the Republic of Ireland and Belgium. In
2021, the UK was a net importer of electricity and imported 24.6 TWh via
these interconnectors with 53% of the imported electricity from France and
24% from Belgium. 27•

A further 8.5 GW of capacity has received regulatory approval. This
includes connections with Demark and Germany. Other interconnectors
are also planned. 28

Transporting electricity via High Voltage Direct Current (HVDC) cables for the
production of electrolytic hydrogen domestically, has advantages overtransporting hydrogen via pipelines or shipping:

Although the UK could import
additional electricity via
interconnectors with mainland
Europe, until the European
system is decarbonised, this risks
increasing overall emissions.
Dedicated cables with green
sources could provide earlier
decarbonised supply.

•

Interconnector costs exhibit greater unit-cost reduction over longer
distances than hydrogen pipelines, which require compressor stations to beinstalled at regular intervals. Consequently, interconnectors can be used
cost-effectively between the UK and a larger number of countries.

•

It may be possible to realise hydrogen pipeline cost savings by converting
existing gas pipelines for hydrogen transportation. However, the overall
opportunities for cost reduction are expected to be more limited because
pipelines are considered to be a more mature technology than HVDC
interconnectors with more limited opportunities for cost reduction overall.

•

Literature estimates indicate that interconnectors could be used to importelectricity for hydrogen production at a cost of £29-40/MWh by 2050, *making interconnectors highly cost-competitive with hydrogen imports. 29•

Hydrogen leakage rates could mean far greater transport efficiencies for
HVDC interconnectors over gas pipelines. Leakage reduction potential isalso of particular importance given recent higher estimates of the indirect
warming effects of fugitive hydrogen (see Box 3.1).

The carbon-intensity of hydrogen produced from imported electricity depends onemissions at the other end of the cable. Although the UK could import additional
electricity via the existing and planned interconnectors with mainland Europe to
produce green hydrogen, until the European system is decarbonised this risks
increasing overall emissions. Dedicated cables for imported electricity from green
sources (e.g. from solar in Southern Europe or North Africa), could be one route todeliver earlier decarbonised supply.

(e) Delivery risks
It is unlikely that contributions tohydrogen supply fromdedicated zero-carbon
electricity sources, green
imports or electricity imports
would remove the need forblue hydrogen in 2035.

It is unlikely that any contributions from green hydrogen imports, or electricity
imports for domestic green hydrogen, would remove the need for blue hydrogenon a 2035 timescale. The build rates required for the Government’s existing
ambitions for zero-carbon electricity (included in the modelling undertaken for thisreport) mean that further zero-carbon capacity for dedicated hydrogenproduction is not expected to be available at significant scale by 2035.
Blue hydrogen will therefore have an important part to play in filling the gap
between domestic production and demand.

*

A distance of 3,000 km is applied.

Chapter 3: Implications for hydrogen production, use and infrastructure100However, a portfolio of blue hydrogen and energy imports for hydrogen –imported as green hydrogen and/or electricity – would provide greater diversity ofsupply and lower lifecycle emissions.
Further progress in funding
mechanisms is required if theEnergy Security Strategy’scommitment of 10 GW of lowcarbon hydrogen production
by 2030 is to be met.

In order to meet the commitment made in the ESS of up to 10 GW of low-carbonhydrogen production capacity by 2030, Government will need to make further
progress in finalising funding mechanisms. We note that the scale of deployment ofhydrogen in the power sector in the AFRY modelling (which tends to preferhydrogen over gas CCS) would require hydrogen production capacity that goesbeyond existing commitments. While it might be necessary to go further, there isalso a question of what is feasible by 2030. A balanced approach to provision of
low-carbon back-up capacity is likely to be needed to limit hydrogen requirements
to manageable levels.
The Government has work in train on the Net Zero Hydrogen Fund and theHydrogen Production Business model, with Government responses to consultations
having been published in 2022, in addition to terms and conditions for theHydrogen Production Business Model contract. The overall framework has yet to be
finalised with allocation rounds due this year.

Recommendation

Owner (timing)

Finalise funding mechanisms and allocate funding to support the development of 10 GW of lowcarbon hydrogen production by 2030, ensuring these are designed to limit residual and upstream
emissions, but also reflect hydrogen costs in a way that does not bias towards hydrogen where
electrification is competitive.

DESNZ (2023)

CCS is a critical enabler fordelivery and Government plans
to deliver it have faced
repeated cancellations anddelays. It is crucial that
Government plans areprogressed urgently.

CCS also remains a critical enabler for delivery, applied both to biomass and to
fossil gas, across hydrogen production and electricity generation. In our 2022
Progress report to Parliament we noted that Government ambitions to deliver it
have faced repeated cancellations and delays. The ten-point plan established acommitment to deploy CCUS in a minimum of two industrial clusters by the mid2020s, and four by 2030 at the latest. While Track 1 projects have beenannounced, and a project shortlist has been developed for phase 2 of the cluster
sequencing; Track 2 has not yet been launched and no further update has been
published on the CCUS Transport and Storage Regulatory Investment model(previously planned for 2022). 30 These must be progressed urgently.

Recommendation

Owner (timing)

Finalise and deliver the CCUS Transport and Storage Regulatory Investment business model,
consistent with the Government's ambition to establish at least two CCS transport and storage
clusters in the mid-2020s. This will require promptly beginning the process of awarding permits andconstruction of the necessary infrastructure, to ensure that it is ready in time for deployment.

DESNZ (Q1 2023)

De-risk the future Carbon Capture and Storage project pipeline by launching the next cluster
selection process as soon as possible, consistent with the Government's ambition to enable final
investment decisions on Track 2 projects from 2024.

DESNZ (Q1 2023)

Publish a plan for CO2 transport from dispersed sites.

DESNZ (2023)

101

Delivering a reliable decarbonised power system

3. Hydrogen infrastructure
Hydrogen transportation andstorage infrastructure isnecessary to connect supply
and demand.

The infrastructure for the transportation and storage of hydrogen is necessary toconnect supply and demand in space and time, both for known needs, and as acatalyst for growth of the hydrogen economy.

(a) Hydrogen storage(i) Hydrogen’s role in long-term energy storage
The UK’s energy demands are higher in the winter than the summer and willcontinue to be so in the future (see Chapter 1). It is therefore necessary to haveinfrastructure and energy supply that can flex to meet this pattern of demand,
through some combination of increased energy generation in the winter and longterm storage.
A changing climate, increased
use of demand-side response
and use of offshore windmeans the future energy
system may need less seasonal
storage than today.

The future energy system will likely require less seasonal flexibility from a gaseous
energy vector (e.g. hydrogen, replacing the role of fossil gas) in the future than it is
the case today:•

As winters get milder and summers hotter, less energy will be required forheating in winter and more required for cooling in summer. This will lead tosome reduction in the current seasonal differences.

•

Further reduction in the winter peak is achievable with energy efficiency(including use of more efficient technology such as heat pumps), anddemand-side response.

•

Generation from offshore wind is greater in the winter. This correlation withdemand is helpful to the energy system as a whole and reduces the needfor seasonal energy storage.

Section 1 of this chapter illustrates the weak seasonality expected in hydrogen
demand in 2035 under the Central scenario (Figure 3.2). The seasonality ofdemand could be expected to grow as buildings decarbonise, but much of thecorresponding increase in electricity supply is expected to come from offshore
wind (which positively correlates with seasonal demand), so the role for hydrogento provide seasonal storage may not be large even by 2050.
Long-term storage will beneeded to act as back-up forextended periods of low wind
generation. Hydrogen storage
can play an important role
here.

Despite reductions in seasonality, there will still be demand for long-term storage.
This is energy storage that can be maintained for a long period of time until it isneeded. Hydrogen storage has potential to play an important role here.
•

Rather than being used primarily to meet seasonal swings in energy
demand, this long-term storage acts as back-up for extended periods of
low wind generation.

•

In addition to providing a balance between demand and supply forenergy over the year, hydrogen storage also has a valuable role inaddressing profile mismatches in hydrogen supply and non-power
demands, as well as outages.

Chapter 3: Implications for hydrogen production, use and infrastructure

102

The modelling commissioned
for this report envisages astrong role for hydrogenstorage, with hydrogen use in
the power sector likely to be astrong determinant on thescale required.

The modelling commissioned for this report envisages a strong role for hydrogenstorage in meeting the needs of the energy system.
•

Across the range of scenarios used for our indicators, 2.1-2.8 TWh ofhydrogen storage is deployed by 2030, with 3.3-5.2 TWh by 2035, and 7.111.6 TWh by 2050.

•

Our 2030 range remains in the middle to higher end of projections recently
published as part of research undertaken for Government. 31 The lower
bounds of our ranges have potential to be further reduced where there isan even greater reduction in the role of hydrogen in the power system thanenvisaged in the modelling for this report (with hydrogen-fired generation
making up between 46-100% of low-carbon dispatchable supply acrossscenarios in 2035). However, a more limited use in the power system would
require a stronger role for gas CCS and the associated infrastructure.

•

The use of hydrogen in the power sector is likely to be a strong determinantof the scale of hydrogen storage required, with stable sources of hydrogen
demand (e.g. in industry) likely to need much less storage than intermittent
hydrogen demand.

(ii) Different forms of hydrogen storage
While there are a range ofhydrogen storage options, salt
caverns are the main solution
being explored in the UK.

Salt caverns are the main underground storage solution being explored in the UK.
Studies by the British Geological Survey suggest the UK has the potential forthousands of TWh of salt cavern storage. 32 Although other options for storinghydrogen exist – including depleted gas fields, aquifers, and lined hard rockcaverns (Box 3.4) – these are not being considered by the Government, and so are
not discussed in detail in this report.
To some extent, the Government has a choice about precisely how muchhydrogen storage capacity is developed in the UK to support time-varying
production and use. For example, instead of blue hydrogen capacity operating
consistently at full capacity, with storage providing a buffer for variation indemands, an alternative would be greater variation in the level of blue hydrogenproduction to better match the demand profile. This may entail a greater
requirement for fossil gas storage. This is not discussed further here but remains an
option for the proportion of supply met by blue hydrogen.
Box 3.4
Alternatives to salt caverns for underground hydrogen storage
Aside from in salt caverns, hydrogen can be stored underground via several different
methods, with each having their own advantages and challenges.

103•

Depleted gas fields account for 76% of current natural gas storage capacity
worldwide and tend to have a larger capacity and be more geographicallywidespread than salt caverns. They can only operate on a few cycles a year, so are
better for seasonal storage than providing short-term flexibility. They could also be
used for carbon capture and storage.

•

Aquifers represent 11% of existing gas storage and operate similarly to depleted gas
fields except they contain water instead of natural gas. This means that they must be
overlaid with an impermeable cap rock to keep the gas underground. They may not
be tight on all sides, so extensive surveys are needed. Like depleted gas fields,
aquifers require more cushioned gas than salt caverns and allow less flexibility.

Delivering a reliable decarbonised power system

Lined hard rock caverns tend to store natural gas liquids rather than gases. They
could be used to store compressed or liquified hydrogen, but require the largest
amount of investment, and have the smallest capacity of all options. However, thesecaverns only require 10-20% cushioned gas – the lowest of all hydrogen storage
options – and can have multiple cycles, providing more flexibility to the system.

•

There are currently no projects in the UK that are looking into storing hydrogen indepleted gas fields, aquifers, or lined hard rock caverns.
Source: IEA (2022) Global Hydrogen Review 2022.

Salt caverns are already usedin the UK to store hydrogen andother gases. The caverns havethe lowest levelised cost of allhydrogen storage options andcan be operated flexibly tosupport power sector flexibility.

Salt caverns are created by drilling into existing salt beds deposits and injecting
water to dissolve the salt, leaving a cavern from which hydrogen can be piped inand out. Existing salt caverns in the UK already store hydrogen and other gases(e.g. in Teesside since 1972) and three projects are looking into hydrogen storage
further: Humber Hydrogen Storage, HyNet / HyKeuper, and HySecure. It may bepossible for salt caverns holding other gases to be repurposed for hydrogen.
Salt caverns can be operated flexibly with multiple cycles a year, making themmore suitable to support power sector flexibility and electrolysis than other forms ofunderground storage. They have the lowest levelised costs of all hydrogen storage
options and require less cushion gas than some other options (meaning morecapacity can be used). However, salt caverns typically have a smaller storage
capacity than some other options, and the geographical availability may belimited. 33,34
The modelling commissioned for this report assumes that salt caverns are the only
type of underground hydrogen storage in GB, * with four locations modelled:
Cheshire Basin, East Irish Sea, East Yorkshire and Wessex. The following technoeconomic and deployment assumptions are used in the modelling:•

Capex is assumed to be between £100-150/kW, with opex assumed to be£3.8-6.8/kW/year. Costs vary between the sites but are not expected toreduce over time.

•

Capacity is only assumed to become available in 2030. Each site has alifetime of 40 years and a build time of four years.

•

Efficiency is assumed to be 95%. This means that for every 100 MWh ofhydrogen that goes into storage, 95 MWh of hydrogen can be extracted
again, with the losses factoring in the energy required for the hydrogencompression.

There are two other potential types of hydrogen storage that could also play
important roles in managing hydrogen supply: 35•*

Above-ground storage in medium-pressure storage tanks for a storage
duration of up to six hours. Storage tanks would be able to have several
cycles a day and could fill up directly from, and empty into, thetransmission network for morning and evening peaks.

They are accompanied by medium-pressure storage tanks, but these account for a tiny fraction of storage
capacity – 8 GWh compared to 5,220 GWh of salt cavern storage in 2035 in the AFRY Central scenario.

Chapter 3: Implications for hydrogen production, use and infrastructure

104

•

Linepack storage, as in the gas networks today, where hydrogen iseffectively stored in transmission pipelines by dropping the outlet pressure.
There would likely be reduced opportunity for hydrogen linepackcompared to natural gas today, given the lower energy density ofhydrogen.

(b) Hydrogen networks
A hydrogen network is requiredfor hydrogen use to expand
outside of planned clusters.

A hydrogen network is required for hydrogen use to expand outside of the plannedclusters. The factors which will determine the appropriate levels of network build will
include: the range of hydrogen end-uses (including any role in home heating); thegeographical location of end-uses, a function both of policy decisions andeconomics; the nature and location of hydrogen supply and associatedinfrastructure; and security of supply and competition considerations. Insufficientbuild has potential to drive inefficiencies (e.g. in the location of assets, or in thevolume of production and storage infrastructure required) and, in turn, systemcosts.
There are a number of ways to transport hydrogen domestically:

Pipelines are the only transportmode suited to transporting
significant volumes ofhydrogen. It may be possible torepurpose some gas pipelines
to hydrogen.

•Hydrogen could in theory be transported by pipeline, rail, road, and sea.
However, pipelines are the only mode suited to transporting significant
volumes of hydrogen. The Government’s Hydrogen Strategy indicates thatroad transport will only be used in the early to mid-2020s, and this will be
replaced by pipelines as distances and scale increase. 36•

In some cases, gas pipelines can be repurposed to hydrogen. This can
reduce costs and prevent stranded assets.
– Repurposing is more likely to be possible where there are underused
parallel pipelines which would allow one line to be temporarily closed
and repurposed, allowing the other to satisfy existing natural gas
demand needs. This scenario is likely to rely on there being a minimumhydrogen uptake by relatively large consumers that are co-locatedwith the repurposed timelines.
– Repurposing a pipeline may involve regularly monitoring pipeline
integrity, adding a hydrogen barrier coating, or reducing pressure(and its swings) so safety thresholds can be met. Repurposing cansave 50-80% of the costs of building new pipelines. 37– However, if repurposing is technically infeasible or the natural gas
demand is too strong, then new pipelines would need to be built.

•

Projections for pipeline needs vary, with uncertainties around the role ofhydrogen in power, and in buildings demand for hydrogen.
– National Grid is exploring options to develop a UK hydrogen
backbone (Project Union). This aims to join industrial clusters together
to connect major sites of hydrogen production with its end-uses(industry, transport, power, and possibly heat) via up to 2,000 km of
network. 38

105

Delivering a reliable decarbonised power system

– Research undertaken for Government suggests between 100 km and1,000 km of pipeline could be needed by 2030 (with the range driven
by uncertainty in the role of hydrogen in power), with 700-26,000 km
needed by 2035 (with the range largely driven by uncertainty arounddemand for hydrogen for buildings). 39
The modelling undertaken forthis report projects that GB
would require 20-27 GW oftransmission pipeline capacity
by 2035. In the Central
scenario, this capacity isequivalent to around 3,800 kmof pipeline.

The modelling undertaken for this report examined the scale of hydrogen pipelinetransmission capacity that could be required to meet the levels of demand
included in the modelled scenarios. It did so by considering GB as 11 hydrogenzones with industrial clusters dispersed across GB and broadly aligned with those
identified in Project Union.
The modelling projects that GB would need 20-27 GW of pipeline capacity by 2035
(Table 3.2).
•

The modelling deploys hydrogen pipeline capacity at a rate of 1.2-2.4 GW
a year between 2030 and 2035, with deployment constrained before 2030.

•

The pipeline build projected in the Central scenario is equivalent to around2,800 km of pipeline by 2030 and around 3,800 km of pipeline by 2035.

•

The growth of pipeline capacity is limited in some areas (such as between
the Midlands and South Wales) but is significant in others (such as between
the Midlands and the North).
– Capacity was assigned based on the location of production and salt
caverns. The largest deployment of new pipelines occurs between the
Midlands and the North of England and Scotland. This links a supply ofhydrogen from the North to salt cavern storage in the Midlands.
– Hydrogen flows are partially population weighted (replicating nonpower demands) and pipeline capacity is deployed between London
and the Midlands and South.

Late network delivery has thepotential to inhibit thedevelopment of the storage
and production infrastructureneeded.

The scale of hydrogen network required is highly dependent on the decisions yet
to be taken in high demand sectors (e.g. the 2026 hydrogen for heat decision).
However, late hydrogen network delivery has potential to act as a blocker tostorage and production infrastructure needed to support the 2035 power system
decarbonisation target. This must be a key consideration in strategic decisions
around infrastructure build.

Chapter 3: Implications for hydrogen production, use and infrastructure106

Table 3.2
GB hydrogen transmission pipeline capacity in the Central scenario

Industrial cluster
Salt cavern

Boundary

2028

2030

2035

SHETL North – SHETL South

0.0

0.6

0.7

SHETL South – SPT

0.0

3.1

3.7

Upper North - SPT

0.0

2.5

3.0

North – Upper North

0.0

0.2

0.4

Midlands – North

0.0

6.0

7.3

East – Midlands

0.0

0.0

0.0

London – Midlands

0.0

0.2

0.5

London – South

0.0

1.0

3.0

Midlands – South

0.0

0.4

1.3

London – Thames

0.0

1.7

2.6

Midlands – South Wales

0.0

1.3

2.8

Total

0.0

16.9

25.1

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility.

(c) Delivery risksLong lead-times for hydrogen
infrastructure build suggest that
Government’s development
timelines may not be ambitious
enough to deliver the levels of
infrastructure outlined in thisreport.

107

The Government has committed to develop new business models for the transportand storage of hydrogen by 2025. 40 However, the long lead-times associated with
infrastructure build suggest that Government’s timeframes for development may
not be sufficiently ambitious to achieve the levels of infrastructure outlined in thisreport.
•

The modelling undertaken for this report implies a need for between 2.3-2.8
TWh of hydrogen storage by 2030. The lead-times required for new salt
cavern storage are around 7-8 years (both planning and construction).
Alongside this, 20-27 GW of pipeline capacity is estimated to be necessary
by 2035.

•

There is potential for the lower bounds of hydrogen use to be reduced
further relative to those set out in this report (where heating is fully electrified
or low-carbon dispatchable power is planned to be heavily gas CCS
dominant), in turn implying lower requirements for storage and transport
infrastructure. However, this will require additional build of alternative
infrastructure in its place, (e.g. increased levels of gas CCS and other formsof storage).

Delivering a reliable decarbonised power system•There is also a risk of stranded assets where there is a mismatch between
the proportion of gas plants being future proofed for hydrogen relative to
gas CCS, and strategic decisions around infrastructure build which
determine the deliverable balance of hydrogen and gas CCS in the future
power system.

The Government needs to fast
track its development ofbusiness models for hydrogentransport and storage to keep
options open on the scale ofhydrogen use by 2035.
Strategic decisions will also beneeded.

These factors imply that the Government needs to fast track its development of
new business models for hydrogen transport and storage. This will keep options
open on the scale of hydrogen usage by 2030 and 2035. The Government should
also set out strategic decisions as part of a comprehensive long-term strategy forthe delivery of a decarbonised power system by 2035 (as recommended earlier inthis report) alongside a plan on the distribution and storage of hydrogen outside ofclusters.

It is not sensible to delay all
decisions on hydrogen
infrastructure until after
decisions on the use ofhydrogen for heating.
Development of hydrogen
infrastructure must be initiatedsooner, pursuing investments
considered low-regret given
the need for hydrogen in theelectricity system, and inindustry.

While the decisions in 2026 on the respective roles of hydrogen and electrification
for buildings heating will affect the precise shape of future electricity andhydrogen infrastructure, it is not sensible to delay all decisions on hydrogen
infrastructure for three years. Development of hydrogen infrastructure must be
initiated sooner, pursuing a set of ambitious investments that are considered lowregret given the need for hydrogen infrastructure to manage the electricity system
and in industry.

Recommendation

Owner (timing)

Fast track the development of new business models for hydrogen transportation and storage
infrastructure, with a view to keeping options open for larger scale hydrogen use by 2030. Legislate
in the Energy Bill to create enabling powers for the hydrogen storage business model and finalise
the business model by the end of 2023. Fast track the hydrogen transportation business model
alongside this, clarifying the respective responsibilities of Government, Ofgem and the FSO in
funding and delivery.

DESNZ (2023)

Publish a site-specific plan for distribution and storage of hydrogen and other low-carbon
infrastructure outside of clusters.

DESNZ (Q1, 2023)

Chapter 3: Implications for hydrogen production, use and infrastructure108

4. Implications for fossil fuel consumption
A key aim of the Energy
Security Strategy is to reduce
the UK’s dependence on
imported fossil fuels.

A key aim of the ESS is to reduce the UK’s dependence on imported oil and gas,
thereby reducing exposure to volatile international prices. The Government has set
a target for the UK to be a net energy exporter by 2040. 41
The UK is currently a net importer of oil and gas, with net imports of fossil gas (485
TWh) and crude oil (420 TWh) both significant in 2021, prior to Russia’s invasion of
Ukraine and the turmoil this caused in international fossil fuel markets. 42

Gas demands in end-use
sectors are projected todecrease steadily on the path
to Net Zero.

The UK currently produces around 440 TWh of domestic gas and imports
around 500 TWh of natural gas, with 88% of these coming from just four
countries (62% Norway, 15% Qatar, 6% USA and 5% Russia). *•The UK can also act as a ‘land bridge’, importing gas (e.g. as LNG) andthen re-exporting it. This effect was small in comparison to the volumes ofimported gas up to 2021, with net exports of around 75 TWh, mainly to
Ireland.

•This ‘land bridge’ phenomenon has been seen more strongly in the last 12
months, as the UK’s LNG import infrastructure has effectively enabled it toimport fossil gas as LNG on behalf of mainland European countries,
exporting it via existing interconnector pipelines (as well as exporting gasfired generation via electricity interconnectors). We will review these
dynamics in our annual Progress Report later in 2023, once more complete
energy data for 2022 are available.

Gas demands in end-use sectors (i.e. outside electricity generation and hydrogenproduction) are expected to reduce steadily over the period to 2050 (Figure 3.7).

*

109

•

These figures are for the years 2018-2020. There was a 17.2% drop in production in 2021 due to an extensive
maintenance schedule, which required a spike in imports.

Delivering a reliable decarbonised power system

Figure 3.7 Overall UK gas demand in non-power
sectors in our Balanced Pathway (TWh)700

Gas demand (TWh)

600
500
400
300
200
100

Unabated use in buildings

Unabated use in industry

Use with CCS in industry

Projected North Sea gas
production

2050

2048

2046

2044

2042

2040

2038

2036

2034

2032

2030

2028

2026

2024

0

Source: CCC (2020) Sixth Carbon Budget Balanced Pathway; NSTA (2022) August 2022 oil and gas production
projections.
Notes: Demand for gas from other non-power sectors not shown on figure. These account for around 0.2% of gas
demands each year.

There will still be a significant
requirement for gas with CCS
for energy generation in 2035.
However, increases inrenewable energy andelectrolyser capacity will
enable a significant reduction
in gas demand for energy
generation by 2050.

Regarding gas demands for energy generation (across power and hydrogen),there will still be a significant requirement for gas in 2035 for use with carbon
capture and storage (CCS), across some combination of post-combustion gas
power plants and blue hydrogen production.
However, fossil gas consumption can be expected to reduce from 2040 to 2050 asincreases in renewable energy capacity decrease the demand for low-carbon
dispatchable generation, and increases in electrolyser capacity ramp up the
production of domestic electrolytic hydrogen (Figure 3.8):•

The power demands for gas will be impacted to some degree by thebalance between gas CCS and hydrogen in delivering low-carbon
dispatchable power. However, a move towards a greater gas CCS mix will
make only a small difference to overall gas demand (power from bluehydrogen requires around 14% extra gas per MWh generated than powerfrom gas CCS).

•

Instead, the demand for gas is driven by size of the hydrogen supply gap,
between consumption and what can be met through non-fossil supply, withblue hydrogen production expected to play an important role in filling thisgap by 2035 but then falling into a back-up role as zero-carbon forms ofhydrogen grow to dominate.

•

Across the range of scenarios developed for this report there is 135-379 TWhof GB gas demand for power and hydrogen in 2035 and 30-281 TWh in
2050.

Chapter 3: Implications for hydrogen production, use and infrastructure110When combined with the non-power demands for gas in our Sixth Carbon
Budget scenarios, this equates to total gas demands of 439-845 TWh in 2035
and 66-611 TWh in 2050.
Reducing the UK’s reliance on
gas imports depends onbuilding large amounts of zerocarbon generation capacity,
as well as energy efficiency
and efficient electrification
across end-use sectors.

Reducing our reliance on gas imports and becoming an overall net exporter ofenergy depends on building out a large amount of zero-carbon generation
capacity, as well as pursuit of energy efficiency and efficient electrification acrossthe buildings, industry and transport sectors. Using hydrogen in place of efficientelectrification (e.g. instead of heat pumps for buildings) would be a much lessefficient use of domestic energy resources, leading to greater need for imported
energy to supplement them.

Figure 3.8 Annual GB gas usage in the Central
scenario and our Balanced Pathway (TWh)800
700

Gas demand (TWh)

600
500
400
300
200
100
0
Hydrogen

2025
Power

2030
Industry

2035
Buildings

2040

2050

Projected North Sea Gas Production

Source: AFRY Central Scenario, CCC (2020) Sixth Carbon Budget Balanced Pathway; NSTA (2022) August 2022 oiland gas production projections.
Notes: Gas demands in buildings and industry taken from the CCC’s Balanced Pathway; those for power andhydrogen are taken from AFRY’s Central scenario modelled for this report.

While reducing the demand on
fossil fuel imports, the shift
towards a decarbonised
energy system will increase thedemand for critical minerals
with several low-carbon energy
sources dependent on certain
minerals.

111

While the deployment of renewable energy and electrolyser capacity will reducedemands on fossil fuel imports, the shift towards a decarbonised energy system will
increase the demand for critical minerals. Several low-carbon energy sources andstorage options are reliant on certain critical minerals whose supply is dominatedby only a few countries.
•

Wind turbines use magnets that require rare earth elements including
neodymium, dysprosium and praseodymium while solar panels use gallium.
The current market-leading form of battery storage requires the use oflithium, cobalt and granite. Ongoing research aims to find alternative
materials that give similar performance. 43•

The production of these critical minerals in centred in only a few countries.
For example, China is the main producer of rare earth metals, accounting
for an estimated 70% of global production in 2022. 44

Delivering a reliable decarbonised power system

The Government published a Critical Minerals Strategy in 2022 that aims to improve
the resilience of critical supply chains and combat the risk of increasing
dependence on critical mineral imports. The strategy focuses on maximising the
UK’s domestic capabilities, diversifying its supply across further countries andenhancing the ability and transparency of international markets. 45

Chapter 3: Implications for hydrogen production, use and infrastructure112

5. Indicators for monitoring progress
We have developed aprovisional set of indicators
against which we plan tomonitor progress on hydrogenproduction and storage
towards 2035, with ranges toreflect uncertainty.

In addition to the indicators on electricity system flexibility set out in Chapter 2, wehave also set out a provisional set of indicators against which we plan to monitor
progress on hydrogen production and storage towards 2035 (Table 3.3).

We will be keeping the set ofindicators under review,
including considering any otherareas where future indicators
may be needed.

We will be keeping these indicators under review, including considering how best
to monitor progress in the context of the indicator ranges, and considering anyother areas where future indicators may be needed (e.g. in relation to
infrastructure development).

As explained in Chapter 2, the range in these indicators reflects a subset of the
scenarios and sensitivities modelled for the purposes of this report, selected with aview to reflecting the range of outcomes which might be achieved pending
uncertainty.

We also note that the lower bounds of our hydrogen indicator ranges havepotential to be further reduced where heating is fully electrified (as in our Sixth
Carbon Budget Widespread Engagement scenario) or where there is a lesser rolefor hydrogen in managing the power system than envisaged in the modelling forthis report (with hydrogen-fired generation making up between 46-100% of lowcarbon dispatchable supply across scenarios in 2035). We intend to keep theseunder consideration pending future work. The most up-to-date list of indicators willremain visible in our published monitoring framework. 46

113

Delivering a reliable decarbonised power system

Table 3.3
Indicators for hydrogen production and storage to 2035
Indicator

Unit

2025

2028

2030

2035

Low-carbon hydrogen production

TWh/year033 - 55

76 - 121

115 - 216

Low-carbon hydrogen production derated capacity
In operation

GW

0

4-6

9 - 1413 - 25

Under construction

GW

4-7

6-9

3-7

3-8

In development

GW

8 - 12

4-8

3-6

5 - 15In operation

TWh

0

0

2-3

3-5

Under construction

TWh

1-2

2-4

1-2

1-2

In development

TWh

2-4

1-2

2-3

2-3

Mt/year1

8 - 1624 - 37

46 - 69

Hydrogen storage capacity

Carbon capture and storage
CO2 captured

Source: AFRY (2023) Net Zero Power and Hydrogen: Capacity Requirements for Flexibility; CCC analysis.
Notes: The in-operation values for low-carbon hydrogen production de-rated capacity have been calculated from the installed production capacity andthe respective load factors for the different technologies determined by the modelling (in 2035, the load factors are 95-96% for biomass gasification CCS,
79-92% for ATR CCS and 39-48% for electrolysis).

Chapter 3: Implications for hydrogen production, use and infrastructure114

Endnotes
1 CCC (2018) Hydrogen in a low-carbon economy,

https://www.theccc.org.uk/publication/hydrogen-in-a-low-carbon-economy.

2 BEIS (2021) Heat and Buildings Strategy, https://www.gov.uk/government/publications/heat-and-buildings-strategy.

3 GE (2022) Hydrogen for power generation: Experience, requirements, and implications for use ingas turbines, https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gas-turbines

4 Element Energy (2018) Opportunities for hydrogen and CCS in the UK power mix,

https://www.element-energy.co.uk/wordpress/wp-content/uploads/2019/11/Element-EnergyHy-Impact-Series-Study-3-Hydrogen-for-Power-Generation.pdf.

5 CCC (2018) Hydrogen in a low-carbon economy,

https://www.theccc.org.uk/publication/hydrogen-in-a-low-carbon-economy/.

6 CCC (2020) The Sixth Carbon Budget Methodology Report, https://www.theccc.org.uk/wp-

content/uploads/2020/12/The-Sixth-Carbon-Budget-Methodology-Report.pdf.

7 For further discussion see CCC (2020) Policies for the Sixth Carbon Budget and Net Zero, box 3.1,

https://www.theccc.org.uk/wp-content/uploads/2020/12/Policies-for-the-Sixth-Carbon-Budgetand-Net-Zero.pdf.

8 BEIS (2021) Hydrogen production costs 2021,

https://www.gov.uk/government/publications/hydrogen-production-costs-2021.

9 BEIS (2022) UK Low-carbon Hydrogen Standard: emissions reporting and sustainability criteria,

https://www.gov.uk/government/publications/uk-low-carbon-hydrogen-standard-emissionsreporting-and-sustainability-criteria.

10 DESNZ (2023) New UK certification scheme to boost British hydrogen sector,

https://www.gov.uk/government/news/new-uk-certification-to-boost-british-hydrogen-sector.

11 Material Economics (2020) Mainstreaming Green Hydrogen in Europe,

https://materialeconomics.com/publications/mainstreaming-green-hydrogen-in-europe.

12 Energy Transitions Commission (2021) Making the Hydrogen Economy Possible,

https://www.energy-transitions.org/publications/making-clean-hydrogen-possible/.

13 BEIS (2021) Hydrogen production costs 2021,

https://www.gov.uk/government/publications/hydrogen-production-costs-2021.

14 PwC (2021) The green hydrogen economy, https://www.pwc.com/gx/en/industries/energy-

utilities-resources/future-energy/green-hydrogen-cost.html.

15 RMI (2022) Strategic Advantages of Green Hydrogen Imports for the EU,

https://rmi.org/insight/strategic-advantages-of-green-hydrogen-imports-for-the-eu/.

16 IRENA (2022) Global Hydrogen Trade to Meet the 1.5°C Goal: Green Hydrogen Cost andPotential, https://www.irena.org/publications/2022/May/Global-hydrogen-trade-Cost.

17 RMI (2021) Fueling the Transition: Accelerating Cost-Competitive Green Hydrogen,https://rmi.org/insight/fueling-the-transition-accelerating-cost-competitive-green-hydrogen/.

18 RMI (2021) Fueling the Transition: Accelerating Cost-Competitive Green Hydrogen,https://rmi.org/insight/fueling-the-transition-accelerating-cost-competitive-green-hydrogen/.

19 IEA (2022) Global Hydrogen Review 2022, https://www.iea.org/reports/global-hydrogen-review-

2022.

115

Delivering a reliable decarbonised power system

20 E4tech (2022) Expansion of hydrogen production pathways analysis – import chains,https://www.gov.uk/government/publications/expansion-of-hydrogen-production-pathwaysanalysis-import-chains.

21 Guidehouse (2020) European Hydrogen Backbone,https://guidehouse.com/insights/energy/2022/european-hydrogen-backbone-energyindependence.

22 BEIS (2022) Atmospheric implications of increased hydrogen use,

https://www.gov.uk/government/publications/atmospheric-implications-of-increasedhydrogen-use.

23 Energy Transitions Commission (2021) Making the Hydrogen Economy Possible,

https://www.energy-transitions.org/publications/making-clean-hydrogen-possible/.

24 World Energy Council (2021) Hydrogen on the Horizon: Ready, Almost Set, Go?

https://www.worldenergy.org/news-views/entry/press-release-insights-brief-hydrogen-readyalmost-set-go.

25 European Union (2022) REPowerEU Plan, https://energy.ec.europa.eu/topics/energy-systems-

integration/hydrogen_en.

26 HM Government (2020) Energy White Paper: Powering our Net Zero Future,https://www.gov.uk/government/publications/energy-white-paper-powering-our-net-zerofuture.

27 BEIS (2022) Digest of UK Energy Statistics: Annual Data for UK, 2021,

https://www.gov.uk/government/statistics/digest-of-uk-energy-statistics-dukes-2022.

28 Ofgem (2022) Interconnector, https://www.ofgem.gov.uk/energy-policy-and-regulation/policy-

and-regulatory-programmes/interconnectors.

29 Energy Transitions Commission (2021) Making the Hydrogen Economy Possible,

https://www.energy-transitions.org/publications/making-clean-hydrogen-possible/.

30 BEIS (2022) CCUS Investor Roadmap,

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1118383/ccus-roadmap.pdf.

31 Frazer-Nash and Cornwall Insight for BEIS (2022) Hydrogen transportation and storage

infrastructure – Assessment of requirements up to 2035,
https://www.gov.uk/government/publications/hydrogen-infrastructure-requirements-up-to-2035.

32 HM Government (2021) UK hydrogen strategy,

https://www.gov.uk/government/publications/uk-hydrogen-strategy.

33 IEA (2022) Global Hydrogen Review 2022, https://www.iea.org/reports/global-hydrogen-review-2022.

34 Beutel, T., Black, St. (2005) Salt deposits and gas cavern storage in the UK with a case study ofsalt exploration from Cheshire. Erdoel Erdgas Kohle, 121 (3), 31-35.

35 Element Energy (2018) Hydrogen supply chain: evidence base,https://www.gov.uk/government/publications/hydrogen-supply-chain-evidence-base.

36 HM Government (2021) UK hydrogen strategy,

https://www.gov.uk/government/publications/uk-hydrogen-strategy.

37 IEA (2022) Global Hydrogen Review 2022, https://www.iea.org/reports/global-hydrogen-review-2022.

38 National Grid (2021) Making plans for a hydrogen ‘backbone’ across Britain,

https://www.nationalgrid.com/stories/journey-to-net-zero-stories/making-plans-hydrogenbackbone-across-britain.

Chapter 3: Implications for hydrogen production, use and infrastructure116

39 Frazer-Nash and Cornwall Insight for BEIS (2022) Hydrogen transportation and storage

infrastructure – Assessment of requirements up to 2035,
https://www.gov.uk/government/publications/hydrogen-infrastructure-requirements-up-to-2035.

40 BEIS (2022) Proposals for hydrogen transport and storage business models,

https://www.gov.uk/government/consultations/proposals-for-hydrogen-transport-and-storagebusiness-models.

41 BEIS (2022) UK government takes next steps to boost domestic energy production,

https://www.gov.uk/government/news/uk-government-takes-next-steps-to-boost-domesticenergy-production.

42 BEIS (2022) Digest of UK Energy Statistics: Annual Data for UK, 2021,

https://www.gov.uk/government/statistics/digest-of-uk-energy-statistics-dukes-2022.

43 POST (2019) POSTnote 609: Access to Critical Minerals, https://post.parliament.uk/research-briefings/post-pn-0609.

44 USGS (2023) Rare Earth Statistics and Information, https://www.usgs.gov/centers/national-

minerals-information-center/rare-earths-statistics-and-information.

45 BEIS (2022) UK Critical Minerals Strategy, https://www.gov.uk/government/publications/uk-

critical-mineral-strategy.

46 CCC (2022) Monitoring Framework. https://www.theccc.org.uk/publication/ccc-monitoring-framework/.

117

Delivering a reliable decarbonised power system

Chapter 4

The need for climate resilience
1. Climate and weather risks to a decarbonised energy system121

2. Delivering a climate-resilient decarbonised energy system

125

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Introduction
The changing climate is expected to lead both to changes in the ‘business as
usual’ weather patterns that impact supply and demand profiles, and changes inextreme events which have potential to drive weather-related system faults.
Previous chapters have dealt with the first of these, and here we focus on thesecond.
Climate risks to the powersystem were among some of
the most urgent risks facing the
UK in the latest UK Climate
Change Risk Assessment(CCRA3).

Climate risks to the power system were among some of the most urgent risks facing
the UK in the latest UK Climate Change Risk Assessment (CCRA3). 1 The CCC
identified risks to people and the economy from climate-related failure of thepower system as one of eight priority areas for further action by Government, given
the potentially far-reaching consequences of a power failure across society, andthe growing importance of electricity in the transition to a Net Zero economy.
Given the growing interdependencies between key societal functions and theenergy system, together with the move towards a system more dominated byvariable renewables, it is essential for policymakers to consider changing climate
hazards as part of system planning. A resilient energy system will deliver a reliablesupply of decarbonised energy, despite climate change.
This chapter covers the resilience of today’s energy system, the potential impactsof extreme weather events on the future decarbonised system, and what isneeded to ensure resilience to those hazards.
This chapter is set out in two sections:
1. Climate and weather risks to a decarbonised energy system
2. Delivering a climate-resilient decarbonised energy system

Chapter 4: The need for climate resilience120

1. Climate and weather risks to a decarbonised energy system(a) Current weather-related disruption
It is currently not possible toadequately assess the extent towhich the energy system isresilient to today’s weather
climate.

Recent storms have highlighted that the energy system is insufficiently resilient totoday’s weather and climate. Disruptions to the energy system can havesubstantial impacts on society and the economy. The financial impact of weatherrelated outages has also not been comprehensively assessed.
Despite the critical economic role of a functioning electricity system, reporting andmonitoring standards for weather-related electricity outages are currently limited.
Data on outages to electricity supply are currently not reported at a national
scale, and weather-related faults on the distribution network, transmission networkor generation facilities are not recorded consistently:•

Distribution network failures: Distribution Network Operators report ‘customer
interruptions’ and ‘customer minutes lost’ to Ofgem each year. However,data on the weather-related cause, as well as the impact on other key
systems, are not available.

•

Transmission network failures: Available data suggest that half of alltransmission network faults are weather-related, with transmission overheadline fault rates about a thousand times higher in storms than in ‘normal’
weather. 2,3•

Generator failures: Data on outages to generating capacity are also poorly
reported. Reports produced under the Government’s Adaptation
Reporting Power do provide some insights on some events, although this is
not consistently collated or reported at a national level.

As energy storage becomes an increasingly important part of the electricity systemover coming years, good reporting practices on weather-related disruption shouldbe implemented.
Specific instances of weatherrelated power failures overrecent years highlight thepotential for significant
impacts.

Specific instances of weather-related power failures over recent years highlight thepotential for significant impacts (Box 4.1).
Box 4.1
Recent weather-related disruption to the electricity system

121•

In 2019, a lightning strike initiated a cascade of events that, via a number ofincorrect automatic responses by generators, led to interruption of power supply to
one million people in the South-East of England and caused significant knock-on
effects on the rail sector, leaving passengers stranded on trains for many hours.

•

Storm Arwen, in 2021, caused extensive damage to the local grids across Northern
England and Scotland, initially leaving over one million customers without power. The
North-East of Scotland experienced the equivalent of almost two years’ worth ofoverhead line faults in a 12-hour period. Much of the damage was caused by wind
gusts of about 100 mph, with over 1,000 points of damage recorded in the North-Eastof Scotland. Thousands of customers remained without power for days.

•

Storm Barra, also in 2021, brought gusts of around 80 mph along with blizzards andheavy rain, causing a loss of power to around 30,000 homes in Northern Ireland.
Wales and parts of England were also affected.

Delivering a reliable decarbonised power system•In 2022, extreme temperatures during the July heatwave caused power cuts due to
conductors sagging and transformers overheating, with temperatures exceeding
40ºC in some places. During the heatwave grid operators were forecasting a 70%
chance that demand would outstrip supply, an outcome that would have caused
blackouts across the network.

Source: Ofgem (2022) Final report on the review into the networks’ response to Storm Arwen; MacIver, C., Bell, K., &Nedd, M. (2021) An analysis of the August 9th 2019 GB transmission system frequency incident. Electric Power
Systems Research, 199; various media reports.

(b) Changing risks of weather-related failures
Over the decades to 2050 andbeyond, global climatechange will drive changes to
UK weather and climate,altering the types of weather
hazards the energy system will
face.

Over the decades to 2050 and beyond, global climate change will drive changes
to UK weather and climate. This will alter the types of weather hazards the energy
system will face (Table 4.1). Climate change elsewhere will also create risks to the
UK through direct routes (e.g. disrupting the supply of electricity flowing throughinterconnectors) and indirect ones (e.g. disrupting international key component
supply chains). The expected changes in UK and global climate through to 2050
will occur largely independently of how rapidly global greenhouse gas emissions
are reduced, although further change beyond 2050 is strongly dependent onwhether global efforts to reduce emissions are effective. Changes will emerge
continuously, but weather and climate fluctuations will still strongly influence what
hazards are experienced in any one year. The design of the decarbonised system
we build by 2035 must consider the range of possible future climate conditions that
it will be required to operate under over its lifetime.
By 2050, some weather hazards that can impact on the functioning of theelectricity system will become more common and intense and will have potentiallylarger effects on the system than today. Some hazards will become less likely but
will still occur occasionally in the future. Changes in some potentially important
weather hazards remain uncertain (Chapter 1).

Table 4.1
Potential impacts on the energy system due to climate trends & extreme weather events in the UK
Climate hazard

Expected change by 2050

Potential impacts on the energy system
Generation and storage

Transmission and distribution
networks

Heatwaves~50% chance of 2018
summer each year*

Efficiency loss at thermal
generation plants; efficiency
loss of solar PV generation;higher electricity demand forcooling; maximum operating
temperatures for components
exceeded.

Efficiency loss on transmission
lines; restrictions of thermal
ratings of assets; risk of faults
increased if power flows not
reduced; potentially
dangerous sagging of powerlines.

Flooding (river,surface and coastal)~5% wetter winters on
average**

Loss of generation capacity or
storage due to inundation.

Loss of transmission &distribution capacity due toflood damage.

~10% increased intensity ofheavy rainfall
10 – 30 cm increase inaverage sea levels***

Chapter 4: The need for climate resilience122Drought~10% drier summers on
average****Loss of generation capacity
due to lack of water supply forcooling and production ofhydrogen.

Wind strength andwind regimes

Highly uncertain

Potential large-scale andcoordinated loss of wind
generation during winddroughts; or high wind speed
shutdown of turbines.

Loss of network capacity due
to damage in high winds.

Storminess andoccurrence of storm
eventsHighly uncertain

Loss of generation capacity
due to damage during storm
events; potential large-scaleand coordinated loss of wind
generation during high windspeed shutdown of turbines.

Loss of network capacity due
to damage in storm events.

Snow and ice

Decreasing but still possible

Potential during periods of very
low temperatures for failure ofgas supply or electricity
generation equipment.

Loss of network capacity due
to icing of power lines.

Source: UKCP18 Projections; summarised in CCC (2021) Independent Assessment of UK Climate Risk.
Notes: * around 10-25% today; ** compared to 1981-2000 ***above 1981-2000 levels; **** than over 1981 – 2000.

(c) Cascading failures
The cascading impacts ofelectricity failure are alreadysignificant. These will continue
to grow in an increasingly
electrified economy facing
more common and severe
extreme weather events.

Extreme weather events can create cascading risks that spread across the
economy, with impacts an order of magnitude higher than impacts that occur
within a single sector. The cascading impacts of electricity failure are alreadysignificant. These will continue to grow as the economy becomes increasingly
electrified and as extreme weather events become more common and severe. As
well as an increasing reliance on electricity among other critical national
infrastructure (CNI) sectors, energy and other infrastructure operators increasingly
use mobile or internet-based means to communicate with their staff, thus they are
increasingly exposed to telecoms outages. Energy, water and IT infrastructure areoften co-located, meaning that weather-related power cuts can affect multiple
sectors simultaneously. Transport routes can become unpassable, delaying therestoration of power after an outage.
CCRA3 concluded that more action is needed to understand the scale ofinterdependency risk between the energy system and other key infrastructure. The
available evidence suggests that Governments and industry may be significantly
underestimating the vulnerability of interconnected systems. 4 Evidence obtained
during a recent parliamentary inquiry into critical national infrastructure andclimate adaptation found numerous recent examples of cascade events and nearmisses, including:123•

During Storm Arwen in 2021, BT’s ongoing transition to digital phone lines(which are reliant on electricity) meant that some customers were left
without access to communication, even for calls to the emergency
services.

•

A power station had to reduce operations for two to three weeks when thecanal water level fell below the required level for abstraction in 2021.

Delivering a reliable decarbonised power system

•Gaps in understanding of theserisks remain and need to beaddressed.

An energy company reported that engineers had trouble visiting sites todeal with technical faults during the ‘Beast from the East’ storm in 2018 due
to major travel disruption. 5

Gaps in understanding of these risks remain and need to be addressed tounderstand the full scale of climate risks facing the future electricity system. These
include:•Improved understanding of how climate change will alter key weather
hazards (such as wind and lightning extremes).

•

The full range of potential storm impacts, including future risks of damage
from storm-felled trees falling on power lines.

•

A more systematic assessment of risks posed from cascading impacts
across multiple sectors due to failures of the electricity system.

The next UK Climate Change Risk Assessment (CCRA4) presents an opportunity to
improve the evidence base in these areas.
Recommendation

Owner (timing)

Commission further research to improve understanding of how climate change is altering key
weather hazards that will impact the energy system, including developing plausible high-impact
low-likelihood scenarios to stress test the system against.

DESNZ, UKRI,
Defra (ongoing)

Coordinate a systematic assessment of risks posed from cascading impacts across multiple sectors
due to failures of the decarbonised energy system as part of the next round of the Adaptation
Reporting Power. This coordination role should include: producing a template or guidance forassessing interdependency risks, including transition risks; further building the evidence base oninterdependency risks; supporting sector forums to enable collaboration; working with regulators to
support cross-sector working; and leading a stress-testing exercise on core infrastructure systems toidentify key weaknesses and points of failure under plausible extreme events from future climate
conditions.

Defra (2025)

Require all energy system organisations to report under the Adaptation Reporting Power, to link theiradaptation actions to climate risks, with clear ownership and timescales, and to provide more
information on the effectiveness of adaptation actions in reducing risk within their ARP reports.

Defra (2023)

Chapter 4: The need for climate resilience124

2. Delivering a climate-resilient decarbonised energy system
A decarbonised energy system will not be reliable if it is not climate-resilient. If
future climate risks are not considered and reflected in energy system planningand operation, there is a significant risk that new infrastructure and system design
may not be well adapted to the climate and weather hazards expected over its
lifetime, creating additional costs to retrofit later and/or locking in increased
climate vulnerability. In addition to climate risks, other critical risks to the functioningof the system, for example space weather incidents, also need to be considered inplanning for the energy system to be resilient overall.
A decarbonised energy system
will not be reliable if it is notclimate-resilient. We must not
lock-in increased climate
vulnerability or additional cost.

Energy UK reports that the majority of existing generation assets will reach the endof their life by 2039. 6 In addition to replacement of existing assets, significant
additional generation capacity will be required by 2050 to deliver Net Zero (driven
by growing use of variable renewables and meeting demand arising from theelectrification of road transportation and household heating).
As the UK upgrades its energy system for 2035 and beyond, we should be doing a
range of things to manage these risks:•

Reduce the vulnerability of network and generation assets to climate
hazards.

•

Increase system-level security of supply.

•

Identify and manage interdependencies.

The rest of this chapter sets out actions needed to build a climate-resilient,
decarbonised energy system.

(a) Reduced vulnerability of assets
To reduce vulnerability ofgeneration and network assets,climate impacts such as floodrisk, extreme heat andreduced water availability
must be considered in site
selection and design,
maintenance and life
extension.

To reduce the vulnerability of generation and network assets, climate impacts suchas flood risk, extreme heat and reduced water availability must be considered insite selection and design. These should also factor into the maintenance and lifeextension of existing assets. This is crucial to maximise system outputs under futureclimate conditions and minimise risks of damage and disruption. For example,
enhancing flood defences or burying assets, which reduces exposure to somehazards, or designing assets to higher maximum operating temperatures.
The National Policy Statement for new energy infrastructure, and provisions under
the Planning Act, require applications for new energy infrastructure to account forthe potential impacts of climate change. These include using the latest UK Climate
Projections available at the time and with adaptation measures that are based on
the latest UK Climate Change Risk Assessment (CCRA). The extent to which thesetests are being applied is not known.
For projects in the Government’s Major Projects Portfolio (GMPP), the Infrastructure
and Projects Authority (IPA) has recently published tests for climate resilience to be
applied in assurance reviews of all GMPP projects. However, a monitoring regime is
not yet in place. Such a regime would improve transparency around climate
resilience considerations in major energy infrastructure projects and produce datathat could be published on Government registers of major projects.

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Standards and guidance for network operators cover resilience against someclimate hazards – primarily flooding. Technical guidance (ETR138) 7 requires
significant substations (i.e. those with more than 10,000 connections) to be resilient
for a 1-in-1,000-year flood event. Other standards for vegetation management
around overhead lines, act to reduce damage caused by trees felled in severe
weather. International standards for heat that apply to component parts of theelectricity network and transformers, state that equipment should function atambient air temperatures of between -25ºC and 40ºC.
There is a need for minimum
resilience standards, covering
all relevant parties and all
relevant climate hazards.

The UK is already experiencing regular heat-related outages and heatwaves areprojected to become more common and extreme in the decades to 2050 andbeyond. 8 As such the current maximum operating threshold requirements forgeneration and network assets are unlikely to be sufficient in some parts of the UK.
The UK Government has committed to new standards for resilience by 2030 under
the new UK Resilience Framework. 9 This presents an opportunity to ensure that the
future energy system is resilient to the full range of climate conditions under which it
will operate.

Recommendation

Owner (timing)

Develop a pathway to setting appropriate minimum resilience standards (both at asset and systemlevel) to relevant climate hazards identified in the UK Climate Change Risk Assessment (CCRA),
covering all relevant parties. These need to be established with a mechanism to regularly review
and revise as understanding of these risks improves.

DESNZ, Cabinet
Office (by 2028 at
latest)Energy generators, electricity transmission and distribution grid companies, and gas
transportation companies are invited to report their climate risk assessments andadaptation plans to Defra every five years, under the Adaptation Reporting Power(ARP).* However, participation is voluntary and as a result there are gaps inreporting across the sector. The CCC assessed all third round ARP reports andfound good coverage of adaptation plans for electricity transmission anddistribution, but a lack of detailed adaptation plans from generators, and Ofgem
declined to report. 10 Reporting under the ARP should be mandatory and therequirements for reporting by generators and regulators should be reviewed toensure sufficient coverage across the sector.

(b) System-level security of supply
A reliable and resilient decarbonised energy system will have sufficient generation
capacity, flexibility, and redundancy to respond to variations in the weather onwhich it is reliant, and to climate and weather-related changes in demand.
•*

Capacity. Sufficient capacity is needed to be able to account for seasonal
and weather-related changes in demand. These are associated withgreater electricity demands in the winter and summertime peaks
associated with increased cooling demands, and may occur at times whengeneration from weather-dependent renewable sources are low. Therealso needs to be sufficient capacity to allow for maintenance and outagesof key electricity system assets.

Covers GB electricity transmission and distribution companies, GB energy generators generating over 10 TWh andtransportation companies serving over 50 000 customers.

Chapter 4: The need for climate resilience

126

•

Flexibility. There must be sufficient flexibility options that allow demand forand supply of electricity to be balanced on the grid for various timescales.
Chapter 2 discusses the generation mixes and levels of firm unabated gas
capacity that can ensure sufficient flexibility, even under more extreme but
plausible low wind scenarios.

•

Redundancy. Adequate redundancy is required in network design toreduce the likelihood of loss of supply to locations, and in downstream
services e.g. local generation, increased storage, and diversity ofgeneration.

(c) Interdependencies identified and managed
Interdependency risks are notbeing consistently incorporated
into climate change risk
assessments and adaptation
action plans of energy networkand system operators.

ARP reports submitted in 2021 show that network and system operators are startingto actively consider their interdependencies with other infrastructure systems.
However, interdependency risks are not being consistently incorporated into
climate change risk assessments and adaptation action plans. We maderecommendations to Defra in 2022, aimed at improving understanding ofinterdependency risks at operator level and the steps being taken to managethem.

(d) Facilitating delivery(i) Governance
Current governancearrangements for resilience inthe energy system arecomplex.

Current governance arrangements for resilience in the energy system are complex.
A wide range of Government bodies, public sector agencies and privateorganisations play a role in design of the energy system and maintaining resiliencein its operation (Box 4.2). Effective co-ordination on resilience between thesebodies will be vital.
Box 4.2
Governance of climate resilience in the energy sector
Governance of resilience in the energy sector is complex, responsibilities are often
overlapping and not always clear.
•

Central Government.
– DESNZ: energy policy and meeting statutory decarbonisation targets.
– Defra: national adaptation planning.
– Cabinet Office: co-ordination and emergency response.
– Treasury: sets the direction of the UK’s economic policy and influences every policy
across Government.

•

Regulators. Ofgem regulates the electricity and gas market; its powers and duties do
not currently explicitly reference Net Zero or climate resilience.

•

System operators.
– National Grid ESO operates the electricity transmission system, and takes steps toensure that it operates in a stable manner. It is also responsible for thedevelopment of transmission network reinforcement strategy and for maintenanceof a number of key industry standards and codes that have a major influence on
resilience of electricity supply.
– The new Future System Operator (FSO) will oversee the UK energy system and willplay a key role in ensuring resilience (expected to be established in 2024).

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Delivering a reliable decarbonised power system

– National Grid Gas operates the gas transmission system and may manage any
future large-scale hydrogen network infrastructure.
•

Infrastructure owners.
– Electricity generation companies are responsible for the resilience of individual
generation facilities.
– Transmission network owners are responsible for the design, construction andmaintenance of the high voltage network.
– Distribution Network Operators (DNOs) provide the infrastructure which takes theelectricity from the transmission network and from smaller scale ‘distributed
generation’ and delivers it to homes and businesses. DNOs also have a
responsibility for identifying vulnerable consumers and developing priority service
registers, and face incentives from Ofgem related to vulnerable consumers.

•

Trade Bodies. The Energy Networks Association (ENA), representing energy network
owners and operators, leads the maintenance of a large suite of ‘engineering
recommendations’ and guidance documents on behalf of the sector. Energy UK
also has an influential role, with members representing around 80% of the UK’s power
generation and over 95% of the energy supply.

•

Planning authorities are responsible for ensuring that applications for planning
consents submitted by developers of electricity system assets are well-adapted tothe changing climate.

The Government has not yet defined its vision for what a well-adapted, climateresilient energy system will look like. This should be a priority in the next National
Adaptation Programme in 2023 (NAP3).
Recommendation

Owner (timing)

Set out, in NAP3, the Government’s vision for what a well-adapted and climate-resilient energy
system will look like. This vision should be supported by clear outcomes, actions and ownership.

Defra (2023)

Conduct a review of governance arrangements for resilience to climate hazards in the energy
system, to ensure they are fit for the new expanded and more diverse low-carbon system given
increasing societal reliance on electricity.

DESNZ, Ofgem(2024)

Designate Ofgem and parties responsible now and in the future (including the new Future System
Operator) for the maintenance of energy sector codes and standards, with a clear mandate toensure climate and weather resilience.

DESNZ, Ofgem(2024)(ii) Research and data
We have already set out a need for the evidence base on climate risks to be
improved, and for research to be undertaken to deliver this.
To understand future risks, there must be improved data collection on thechallenges faced today. This will also support the development of indicators which
can be used to measure progress.
Work is underway in the sector, via Ofgem, DESNZ and others, to identify
adaptation indicators for the energy system. Current reporting requirements on
DNOs do not require outages to be categorised by weather cause.

Chapter 4: The need for climate resilience128

Consistent reporting and collation of this data, covering the full extent of the UK,
would provide a meaningful indicator of how climate-related impacts on theenergy system are changing. This should be combined with improvements inreporting on climate risks and adaptation plans by network and system operators,
as recommended to Defra in our evaluation of ARP3 in 2022.
Recommendation

Owner (timing)

Extend requirements for reporting on outages to include the cause, duration and magnitude of all
outages (with weather-related outages specifically identified), and collate this as a national
indicator.

Ofgem, DESNZ(2024)(iii) Investment
Investment in the UK’s energy sector is currently largely delivered by the private
sector - over 80% of energy projects and almost 100% of utilities projects in the
Treasury’s Infrastructure and Construction Pipeline are privately funded. 11 It is thisprivate investment that must deliver electricity system resilience to weather
hazards. Government’s role is to work with industry, regulators, sector bodies, andother stakeholders to ensure that the investment in the electricity system is resilientand secure against the impacts of climate change, and to provide policy andregulatory oversight to ensure predictable and attractive long-term investment
opportunities, together with ensuring the system is well-managed to mitigate risk
from weather related impacts.
Our recent Adaptation Investment report 12 explores barriers to investing in climate
resilience and identifies funding streams that could enable adaptation projects tosecure investment. The UK Infrastructure Bank (UKIB) was launched in 2021, tasked
with accelerating investment into ambitious infrastructure projects, cutting
emissions and levelling-up the UK. Investment is likely to be heavily weighted
towards energy projects, presenting an opportunity to ensure that the Net Zeroelectricity system is resilient to the future climate conditions which will poseincreasing risks to energy supply. However, to date the UKIB has focussed onemissions reduction in financing projects and is yet to demonstrate a strategy toaddressing Net Zero and adaptation together.

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Endnotes
1 CCC (2021) Independent Assessment of UK Climate Risk.
2 Murray, Kirsty and Bell, Keith (2014) Wind related faults on the GB transmission network. In: 2014

International Conference on Probabilistic Methods Applied to Power Systems, PMAPS 2014, 201407-07 - 2014-07-10

3 Morris, E.A. and Bell, K. and Elders, I. (2016) Spatial and temporal clustering of fault events on the

GB transmission network. In: 2016 International Conference on Probabilistic Methods Applied toPower Systems, 2016-10-16 - 2016-10-20, Beijing Friendship Hotel. (In Press)

4 Jaroszweski, D., Wood, R., and Chapman, L. (2021) Infrastructure. In: The Third UK Climate

Change Risk Assessment Technical Report. [Betts, R.A., Haward, A.B., Pearson, K.V. (eds)]
Prepared for the Climate Change Committee, London, https://www.ukclimaterisk.org/wpcontent/uploads/2021/06/CCRA3-Chapter-4-FINAL.pdf.

5 Joint Committee on the National Security Strategy (2022) Readiness for storms ahead? Criticalnational infrastructure in an age of climate change,
https://committees.parliament.uk/publications/30507/documents/175976/default/.

6 Energy UK (2021) A Sector Overview 2021: Climate Change Risks and Adaptation Responses for

UK Electricity Generation, https://www.energyuk.org.uk/publication.html?task=file.download&id=7951.

7 Energy Networks Association (2018), Engineering Technical Report 138: Resilience to Flooding ofGrid and Primary Substations, https://www.ena-eng.org/enadocs/D0C3XTRACT/ENA_ET_138_Extract_180902050400.pdf.

8 Met Office (2022) UK Climate Projections: Headline Findings,

https://www.metoffice.gov.uk/binaries/content/assets/metofficegovuk/pdf/research/ukcp/ukc
p18_headline_findings_v4_aug22.pdf.

9 HM Government (2022) The UK Government Resilience Framework,https://www.gov.uk/government/publications/the-uk-government-resilience-framework.

10 CCC (2022) Understanding climate risks to UK infrastructure, Evaluation of the third round of the

Adaptation Reporting Power, https://www.theccc.org.uk/publication/understanding-climaterisks-to-uk-infrastructure-evaluation-of-the-third-round-of-the-adaptation-reporting-power/.

11 IPA (2021) Analysis of the National Infrastructure and Construction Pipeline 2021,

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/1016759/Analysis_of_the_National_Infrastructure_and_Construction_Pipeline_2021.pdf.

12 CCC (2023) Investment for a well-adapted UK,

https://www.theccc.org.uk/publication/investment-for-a-well-adapted-uk/.

Chapter 4: The need for climate resilience130Delivering a reliable decarbonised power system
March 2023
Climate Change Committee
1 Victoria St
Westminster
SW1H 0ET
www.theccc.org.uk@theCCCuk