Volume 17, Issue 13 p. 3240-3266
Open Access

Offshore versus onshore: The underestimated impact of onshore wind and solar photovoltaics for the energy transition of the British Isles

Philipp Diesing

Corresponding Author

Philipp Diesing

School of Energy Systems, LUT University, Lappeenranta, Finland

Chair Electric Power Networks and Renewable Energy, OVGU Magdeburg, Magdeburg, Germany

Reiner Lemoine Foundation, Berlin, Germany


Philipp Diesing, Reiner Lemoine Institute, Rudower Chaussee 12, 12489 Berlin, Germany.

Email: [email protected]

Contribution: Conceptualization, Data curation, Formal analysis, Methodology, Visualization, Writing - original draft

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Dmitrii Bogdanov

Dmitrii Bogdanov

School of Energy Systems, LUT University, Lappeenranta, Finland

Contribution: Data curation, Methodology, Software, Writing - review & editing

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Rasul Satymov

Rasul Satymov

School of Energy Systems, LUT University, Lappeenranta, Finland

Contribution: ​Investigation, Visualization

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Michael Child

Michael Child

School of Energy Systems, LUT University, Lappeenranta, Finland

Contribution: Data curation, Writing - review & editing

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Ines Hauer

Ines Hauer

Chair Electric Power Networks and Renewable Energy, OVGU Magdeburg, Magdeburg, Germany

Institute of Electrical Power Engineering and Energy Systems, TU Clausthal, Clausthal, Germany

Contribution: Writing - review & editing

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Christian Breyer

Christian Breyer

School of Energy Systems, LUT University, Lappeenranta, Finland

Contribution: Conceptualization, ​Investigation, Resources, Validation, Writing - review & editing

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First published: 03 September 2023


The British Isles, consisting of the United Kingdom and the Republic of Ireland, were investigated for a sustainable energy system transition towards 100% renewable energy in 2050. Under given framework conditions, three pathways comprising the entire energy system were investigated in 5-year time steps and hourly resolution applying an advanced energy system modelling tool and identifying the lowest cost solutions. The British Isles were structured into 10 sub-national regions. Special attention was paid to the high offshore wind potential of the British Isles, as well as the limited societal acceptance for onshore wind in the United Kingdom. The results indicate that a transition to 100% renewable energy is economically more attractive than the governmental strategy that involves nuclear power and fossil carbon capture and storage. The total annualised system costs can decrease to 63 b€ and a levelised cost of electricity of 40 €/MWh if onshore wind and solar photovoltaics are allowed to be built to a higher extend. High levels of electrification and sector coupling are the main reasons for decreasing primary energy demand. The multiple risks of nuclear technology can be avoided if dedicated action towards 100% renewable energy is taken.


The climate emergency became a broadly discussed topic in recent years, due to visible and more frequently occurring extreme weather events like droughts, floods, and intense rainfalls [1]. Scientific observations continue to confirm dangerous trends like the melting of ice sheets at the poles and rising sea levels as a consequence [2]. In comparison to the previous three decades, instances of unprecedented weather events are projected to increase by a factor of two to seven between 2021 and 2050, and potentially increase to a factor of 21 under high-emission scenarios beyond 2050 [3].

With the Paris Agreement [4] and the United Nations Sustainable Development Goals (SGDs) [5], a clear future vision was shaped for urgent climate actions in particular but also for sustainability issues in general, which included more social and environmental dimensions. One example is health-damaging air pollution, mainly caused by fossil fuel but also biomass combustion [6]. In terms of climate actions, the clear goal is to limit global warming by 1.5° compared to pre-industrial levels. However, the latest intergovernmental panel on climate change (IPCC) synthesis report indicates that humankind is currently not at all on track to reach this goal or avoid the severe consequences of this development [7].

The British Isles, consisting of the United Kingdom of Great Britain and Northern Ireland (henceforth: UK) and the Republic of Ireland (henceforth: Ireland), represent highly developed countries that need to mitigate their greenhouse gas emissions (GHG) emissions drastically to be compliant with the Paris Agreement. Initiating a transition towards a clean and sustainable energy system, based on 100% renewable energy (RE), can be the most promising solution. As of today, a large number of studies, summarised in [8-10], indicate that a 100% RE system can be achieved globally at low cost. Hundreds of studies show the benefit of 100% RE systems [10, 11], which is confirmed for the UK and Ireland by Meschede et al. [12].

Natural gas and fossil oil are essential parts of the current energy system of both countries. In the UK, natural gas and fossil oil accounted for 42% and 31% of domestic energy use, respectively [13]. Since 1990 the use of coal has decreased significantly and remains a rather small part of the energy system of both countries. Coal has been substituted by natural gas for heating and electricity recently. There has also been an introduction of mainly onshore and offshore wind power for electricity generation and increasing use of biomass and waste-to-energy resources. Between 30% and 40% of primary energy supply in recent years was supplied by imported fossil fuels and indicates a lack of domestic resources [13]. The energy flows of the current energy system are illustrated in Figure 1. All energy sectors are independent from one other and electricity is used directly to satisfy the electricity demand. Natural gas is mainly used for heating and oil for transportation.

Details are in the caption following the image
Energy flows in the British Isles in 2020. Values are in TWh. TWh, terawatt hour.

The UK has witnessed a continuous decline in GHG emissions, nearly cutting them in half since 1990, going from 809 to 414 million metric tons of CO2 equivalent. This achievement can be attributed to the growing utilisation of low-carbon energy sources, which have steadily increased from 9.4% in 2000 to 21.5% (including 6.6% nuclear) of the primary energy supply by 2020. Additionally, the transition from coal to natural gas has played a significant role in this reduction, due to the lower emission intensity of natural gas [13]. Further contributions to this originate from efficiency enhancements in the residential sector, which have experienced a 23% decrease in energy intensity per household [14]. For Ireland, the emissions remain roughly on the level of 1990 (around 30 Mt CO2eq). However, emissions increased until 2006 to 44 Mt CO2eq, most likely connected to the growing gross domestic product (GDP), and decreased afterwards, as the expansion of wind power accelerated [15, 16].

The development of accelerating RE expansion might not only be driven by the willingness of policy makers to fight the climate emergency but also by declining costs of RE and storage technologies [10, 1721]. The UK governmental pathway towards net zero emissions indicates that fossil-nuclear technologies are considered to be a major cornerstone of the future energy system [22]. Ireland's Climate Action Plan indicates a different path that focusses on large-scale wind power without nuclear power [23].

The scientific literature continues to identify a variety of drawbacks for fossil carbon capture and storage (CCS) and nuclear power. For instance, the emissions of blue hydrogen (grey hydrogen with CCS) can be underestimated if full value chain emissions are not respected [24], which also applies to nuclear power in part [25]. The latter shows further drawbacks in terms of the nuclear technology decline [26] and other constraints such as its lack of fast availability [27], problems with waste disposal [27, 28], and risk of accidents with a high damage potential [29].

In contrast to this, studies showed that nuclear-free energy systems are technically and economically desirable for the case of Sweden and Finland [30, 31], but also for Japan [32, 33], which has been subject to a more intense debate about nuclear power due to the disaster of Fukushima. Further, in [34, 35] it could be demonstrated that new nuclear power technologies show unfavourable economic conditions and can be effected by construction delays and cost overruns, as it is currently happening with the Hinkley Point C plant in Somerset, England [36]. Recent events that took place in France in 2022 point to a correlation between nuclear power and reliability concerns, originating from deteriorating power plants [37], as well as the increasing impact of climate change leading to a shortage of cooling water. In a fully developed RE system, such challenges can be entirely overcome [38].

From a renewable resource perspective, the reliance on fossil-nuclear technologies is not required. The UK and Ireland benefit from noteworthy wind resources [39], which were already noticed in the late 1970s and had been translated to implications for policy makers at that time [40]. Ongoing development in wind power technology (both onshore and offshore) has led to a growing amount of installed wind power capacity. In recent years, offshore wind power has expanded significantly, especially in the UK, leading to the highest offshore wind power capacity by country in 2021 with more than 10 GW [41] and the UK being considered to be the world leader for offshore wind [42]. Governmental plans indicate that further offshore wind power expansion is considered as a key strategy for emission reductions [13]. Onshore wind power expansion is discussed more controversially as caveats against this technology exist and it faces social and political resistance [43], but also contrary developments can be observed [44]. The resource potentials for solar energy are smaller and depend on available land, while the economics have reached competitiveness [17]. The UK benefits from the most abundant offshore wind energy potential in Europe, while Ireland comes in second place, offering a combined technical potential of 8000 TWh annually [45].

While the potential of wind energy for the power sector is acknowledged by both countries, uncertainty remains regarding the future development of the entire energy systems and its various elements in the upcoming decades. Previous studies investigated the energy transition towards 100% RE for Ireland [46, 47], for Scotland [48] or for the British Isles as a region of Europe [49-51]. It is mentioned that the UK and Ireland can work as exporters in an interconnected European energy system [51, 52]. Other studies focused on the UK's power sector, finding that hydrogen storage is the cheapest balancing solution [53] and that excess electricity can be used for heat and transportation [54]. Williams et al. [55] investigate the generation and storage requirements for the energy system of the UK based on 95% of renewables, using biomethane and green hydrogen as balancing options for variable renewable generation. What most of these studies have in common is that they consider offshore wind power to be the main supplier of electricity (most likely due to its resource availability), and with one exception that finds onshore wind power and solar photovoltaic (PV) to be preferable [56]. As of today, no study has yet investigated the full energy system transition of the British Isles with a focus on full cost optimisation and sector coupling in high temporal and spatial resolution.

This study addresses the research gap of a transition investigation of an interconnected, sector-coupled energy system of the British Isles towards 100% renewable energy in 2050. A cost-optimisation model is applied to investigate different pathways towards this goal and to identify the least cost solution. It further addresses the research gap of the impact of solar PV and onshore wind power and its performance against (1) the commonly chosen offshore wind power dominated approach and (2) the governmental strategy that aims for nuclear power and fossil CCS. Key novelties of the study are the cost compositions of the energy system with different constraints, its technological components and their interactions, leading to a novel understanding of industrial regions with high availabilities of wind resources and moderate availability of solar resources.


2.1 Model description and modelling approach

With the LUT Energy System Transition Model (LUT-ESTM), the transition to a desired system within a specific region is simulated in intervals of 5 years, aiming for cost minimisation. A comprehensive explanation of the model, along with its equations and data flows, is described by Bogdanov et al. [54] for the power sector and in [17, 55] for all sectors including power, heat, transport, industry, and desalination. This study utilised the version of the model outlined in [56], to include the latest model improvements. The model conducts linear cost optimisation in hourly resolution for each year, following 5-year time-steps from 2020 to 2050. The input data is organised in a way to describe the energy system as of today, encompassing power, heat, and transport sectors. Additionally, it includes regional renewable resources, load profiles for power and heat and hourly resolution, demand projections, and cost and lifetime estimations until 2050.

The model aims to optimise for least cost solutions while matching all constraints. For the case of respective economic conditions, the model expands (installs) RE technologies, while phasing out fossil-nuclear technologies, according to their technical lifetime, if this leads to lower cost solutions. RE technologies that are installed in a specific year remain in the system throughout their technical lifetime. Afterwards, they will be either refurbished or replaced by new RE technologies with lower cost. The model restricts the installation of newly added renewable capacity based on the upper technical potential of a specific technology, taking into account its available resources. The installation of new RE capacity is further limited to a growth in capacity share of 4% (percentage points) per year to avoid an unrealistically fast ramp-up. The model prefers the technology mix with the lowest total costs over technology combinations with higher costs until the resource is not available anymore. This is done while hourly demand profiles, and therefore seasonal variation, are respected. Typically, this leads to a balance of solar and wind technologies due to resource complementarity [51].

The first target function of the model is to minimise the sum of total annualised system costs, which is shown in Equation (1). The following abbreviations are used: subnational region (r), all subnational regions (reg), technologies for electricity and heat generation and storage (tech, t), capital expenditures for a specific technology t (CAPEXt), capital recovery factor for technology t (crft), fixed operational expenditures such as day-to-day (OPEXfix,t), installed generation capacity by region and technology (instCapt,r), variable operational expenditures such as fuel costs for technology t (OPEXvar,t), total amount of energy generation by region and technology for 1 year (Egen,t,r), ramping costs by technology (rampCostt) and annual totals for ramping by region and technology (totRampt,r).
min r = 1 r e g t = 1 t e c h C A P E X t · c r f t + O P E X f i x t · i n s t C a p t , r + O P E X v a r t · E ge n t , r + r a m p C o s t t · t o t R a m p t , r $$\begin{equation} \min \left( { \def\eqcellsep{&}\begin{array}{@{}*{1}{c}@{}} {\mathop \sum \limits_{r\ = \ 1}^{reg} \mathop \sum \limits_{t\ = \ 1}^{tech} \left. {\left( {CAPE{X_t} \cdot cr{f_t}} \right. + OPEXfi{x_t}} \right) \cdot instCa{p_{t,r}} + }\\[9pt] {OPEXva{r_{\ t}} \cdot {E_{{\mathrm{ge}}{{\mathrm{n}}_{t,r}}}} + rampCos{t_t} \cdot totRam{p_{t,r}}} \end{array} } \right)\end{equation}$$ (1)
The second key function is shown in Equation (2) and describes the main constraint that must be met at every hour of the year: matching power supply and demand. The following abbreviations are used: technology (t), hours of the year (h), all power generation technologies (tech), technologies for electricity generation (Egen,t), subnational region (r), all subnational regions (reg), imported electricity by subregion r (Eimp,r), technologies for storing electricity (stor), discharged electricity from storage (Estor,disch), electricity demand in the power sector (Edemand), electricity exported by region r (Eexp,r), electricity for storage charge (Estor,ch), curtailed electricity (Ecurt), and electricity, that is used by other sectors, for example for heat pumps or battery electric vehicles (BEV) (Eother). Similar boundary conditions define the hourly supply and demand balances for heat, fuels, and CO2 flows and are fully described in [18].
h ε 1 , 8760 t t e c h E g e n t + r r e g E i m p r + t s t o r E s t o r , d i s c h t = E demand + r r e g E e x p r + t s t o r E s t o r , c h t + E c u r t + E other $$\begin{eqnarray} && \forall h\ \varepsilon \ \left[ {1,8760} \right]\ \mathop \sum \limits_t^{tech} {E_{ge{n_t}}} + \ \mathop \sum \limits_r^{reg} {E_{im{p_r}}} + \ \mathop \sum \limits_t^{stor} {E_{stor,disc{h_t}}}\nonumber\\ && = \ {E_{{\mathrm{demand}}}} + \mathop \sum \limits_r^{reg} {E_{ex{p_r}}} + \mathop \sum \limits_t^{stor} {E_{stor,c{h_t}}} + {E_{curt}} + {E_{{\mathrm{other}}}}\end{eqnarray}$$ (2)

The component structure of the model is illustrated in Figure 2 for all sectors, visualising sector coupling through electricity, heat, fuel, and CO2 flows. The energy system's core component is the alternating current (AC) grid, which serves as the central connection for all regions, generation (renewable and conventional), electricity storage, and sectors though electricity transmission. The AC grid fully satisfies the electricity demand of all electricity consumers, with the exception of prosumers, that can partly supply their own electricity demand. Power-to-heat (PtH) technologies enable sector coupling between the power and the heat sector. Heat demand is satisfied in a centralised manner through heat plants (also combined heat and power) or decentralised, with heat pumps, boilers or direct electric heating technologies. Thermal energy storage (TES) is divided into district heat storage and high temperature heat storage (realised through sensible heat storage). Power-to-X technologies enable sector coupling between the transport and the power sector via Power-to-Liquids, where CO2 from biomass burning or Direct Air Carbon Capture and Utilisation or Storage (DACCU, DACCS) is used. Sector coupling is further ensured via direct electrification of different modes of transport (road, rail, marine, and aviation) that are connected to the AC grid.

Details are in the caption following the image
LUT Energy System Transition Model (LUT-ESTM) scheme for all sectors, system components and electricity, heat, fuel, and CO2 flows [17, 55].
The model considers residential, commercial, and industrial prosumers in a separate submodel with a slightly adjusted target function. Prosumers are considered to have PV systems, including batteries and individual heat supply. These prosumers have the ability to generate and store their own electricity. They also have the option to sell any surplus electricity to the grid, receiving a predetermined remuneration, or alternatively, to purchase electricity from the grid based on the projected market price. The target function is shown in Equation (3). The same abbreviations as in the previous equations are applied, adding the retail price for electricity (elCost), the feed-in price for electricity (elFeedIn), and the electricity feed into the grid (Ecurt).
min t = 1 tech CAPE X t · cr f t + OPEX fi x t · inst Ca p t + OPE X var · E Gen + elCo st · E grid + elFe edIn · E curt $$\begin{equation} \min \left(\sum _{t\ =\ 1}^{\textit{tech}} \def\eqcellsep{&}\begin{array}{c}\left(\textit{CAPE}{X}_{t}\cdot \textit{cr}{f}_{t}+\textit{OPEX}\textit{fi}{x}_{t}\right)\cdot \textit{inst}\textit{Ca}{p}_{t}+\\ \textit{OPE}{X}_{\textit{var}}\cdot {E}_{\textit{Gen}}+\textit{elCo}\textit{st}\cdot {E}_{\textit{grid}}+\textit{elFe}\textit{edIn}\cdot \ {E}_{\textit{curt}}\end{array} \right) \end{equation}$$ (3)

The applied model is able to simulate energy-intensive industries (EIIs) such as iron and steel, cement, basic chemicals, aluminium, and pulp and paper [57], seawater desalination based on renewable electricity for countries with limited fresh water supply [58, 59], and carbon dioxide removal as a part of the overall energy system [57, 60]. This study simulates the industry sector as a part of the power and heat sector, where industrial heat is assigned to different temperature levels of the heat sector and industrial power demand is assigned to the overall power demand.

In Prina et al. [61] the LUT-ESTM was classified as a bottom-up, long-term modelling tool. It received a high rating for temporal and spatial resolution and the ability to integrate sector coupling, while it was rated medium in techno-economic detail and transparency. Compared to other energy system models, it received a high overall rating. LUT-ESTM was identified as the second most applied tool for investigations of energy system with high shares of renewables, only surpassed by EnergyPLAN [11].

2.2 Assumptions and input data

To examine the interactions within the future energy system of the UK and Ireland but also due to geographical similarities, the British Isles were simulated as one electricity market. Utilising a multi-node approach, the UK and Ireland were subdivided into 10 distinct subregions, each presented in Table 1 with the respective administrative regions.

TABLE 1. Abbreviations of the 10 subregions and their composition by administrative regions.
Abbr. Administrative regions
British Isles E – S England: Southwest, Southeast
E – M England: East Midlands, West Midlands
E – NW England: Northwest
E – NE England: Northeast, Yorkshire and The Humber
E – L England: Greater London
E – E England: East
SC Scotland
W Wales
NIR Northern Ireland
IR Republic of Ireland

The structure of the subregions was determined based on factors such as final electricity consumption, geographical proximity, and administrative limitations, ensuring that administrative regions are not split. The subregions are interconnected through a combination of high voltage alternating current (HVAC) and high voltage direct current (HVDC) transmission lines and cables. The transmission infrastructure interconnects the consumption hubs, represented by cities with the highest population, as depicted in Figure 3. It should be noted that in reality the transmission grid of the British Isles is more complex. The actual network includes several voltage levels (300–400 kV in the UK and 220 kV in Ireland), as well as connections from offshore wind farms to the main land. There is also a HVDC interconnector within Scotland, which is not represented here [62].

Details are in the caption following the image
Simplified transmission grid based on ENTSO-E data [62]. Consumption hubs are shown as red dots. Black lines represent HVAC, green lines represent HVDC (sea cables).
The following data were collected for model input and can be found in the supplementary material of this study (Supporting Information):
  • Availability of renewable energy: solar irradiation, rivers flow rates, and wind speed distribution for nodal capacity factors and full load hours (FLH) for a reference year (2005);
  • Installation history for all technologies, beginning in 1960, in 5-year time intervals;
  • Amount of annual sewage sludge, animal excrements, and biowaste, to determine technical biogas potential;
  • Technical potential of geothermal energy;
  • Power and heat demand (industrial, space heat, and domestic hot water) in hourly resolution;
  • Annual power and heat demand in 5-year time intervals from 2020 to 2050;
  • Annual passenger transport demand in passenger kilometres (p-km) and freight transport demand in tonne kilometres (t-km) for road, rail, aviation, and marine from 2020 to 2050;
  • Efficiencies by technology to account for energy losses through energy conversion;
  • Financial assumptions (capital expenditures (CAPEX), fixed and variable operational expenditures (OPEXfix, Opexvar) for all technologies in 5-year time steps from

    2020 to 2050;

  • The current and projected lifetime of all technologies;
  • Lower limit and upper technical potential for solar and wind energy resources;
  • Lower limit: installed capacity at each time-step;
  • Upper technical potential: highest possible installable capacity based on land area;
  • Transmission grid and energy consumptions hubs (equal to cities with highest population of each subregion.

Population projection data were taken from [63] for England, from [64] for Scotland, from [65] for Northern Ireland, from [66] for Wales, and from [67] for Ireland. To allocate only nationally available values to the nine subregions of the UK and address cases where regional data was unavailable, population projections were applied as an additional parameter. This allowed for the necessary division of data. For Ireland, separate data sources were predominantly accessible, enabling a more distinct analysis.

In the main scenario (Best Policy Scenario (BPS), see Section 4), solar PV is limited to 1% of total land area demand with a power installation density that is growing from 91 MW/km2 for fixed-tilted PV in 2020 to 137 MW/km2 due to projected efficiency improvements for solar modules (that are expected to increase from the present-day efficiency of around 20% to 30% in 2050 [68]), and based on a ground cover ratio of 45% for fixed-tilted solar PV and 31% for single-axis tracking, according to [69]. This leads to an upper limit for fixed-tilted solar PV of 859 and 589 GW for single-axis tracking. Onshore wind is considered to be limited to 2% of the total land area with a significantly lower power installation density of 8.4 MW/km2 [70]. This leads to an upper limit for onshore wind of 53 GW.

For the UK and Ireland, the annual economic potential for offshore wind was found to be 2700 and 600 TWh, respectively, and thus available to a great extent [45]. The annual technical potential is larger by a factor of 2 to 3, reaching 8000 TWh for both countries combined. For this study, the input data for wind and solar resources are derived from NASA data for the reference year 2005 [71]. This data was reprocessed by the German Aerospace Centre [72] in 0.45 × 0.45° nodal resolution and applied for this study in this format. The regional FLH, as well as the hourly profiles for the sample year 2005, which are used for this study for wind onshore, wind offshore, and solar PV (fixed-tilted), are illustrated in Figures 4, 5 to 6. The highest wind power potential can be found for Scotland and Ireland, the lowest in Southern England. The coastal regions have higher wind onshore potentials than the inland. FLH for solar PV are lower by a factor of 4 to 5, compared to onshore and offshore wind, and higher in the south. In terms of hourly profiles, a seasonal complementary can be observed between wind and solar resources, with wind resources being superior in winter and solar resources in summer.

Details are in the caption following the image
Full load hours (left) and hourly profile (right) for wind onshore.
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Full load hours (left) and hourly profile (right) for wind offshore.
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Full load hours (left) and hourly profile (right) for solar PV (fixed-tilted). PV, photovoltaic.

As described in the previous sub-section, the energy supply and demand must match for every hour of the year, which is a key constraint of the modelling approach. Thus, the variable characters of RE resources (wind, solar, and precipitation) are fully taken into account and several options exist to account for variable RE yields: (1) increasing or decreasing the energy generation from dispatchable renewables (hydropower, bioenergy, geothermal), (2) charging or discharging of various storage options, and (3) the transfer of electricity through transmission grids from one region to another. Ultimately, a combination of options is applied to select the cost optimal way of balancing variabilities, which is ensured due to the cost-optimisation function, explained in the previous sub-section. Furthermore, the estimation of potentials for additional renewable energy resources was done separately. To ensure sustainability, the focus on biomass resources was limited to waste biomass (including municipal solid waste) from which biogas and subsequently biomethane can be produced. Discussions with local initiatives in the UK revealed concerns about air pollution, leading to the assumption that biomass utilisation beyond biogas cannot be considered in this study. As a result, the available biomass potential was narrowed down to biowaste, animal excrements, and sewage sludge, amounting to a cumulative potential of 11.5 TWhth.

Geothermal potentials were estimated by Aghahosseini and Breyer [73] for all countries globally and the obtained data was used for this study. A relatively novel energy resource that has gained attention is ocean energy, especially wave power, which has recently been integrated into LUT-ESTM. The applied wave power potential was assumed to be 27 GW in 2050 for the UK (and 21 GW for Ireland) [74]. The values for the UK were split according to the length of the coastline to determine the potential of each subregion. Tidal stream energy has not yet been integrated in the current version of LUT-ESTM.

Electricity demand (excl. electricity demand for heat and transport) was obtained in hourly resolution from Toktarova et al. [75]. For cross-verification, this was adjusted by using demand projections published by the government of the UK and also applied to Ireland for simplification. A mean compound annual growth rate (CAGR) of 0.9% was calculated, indicating a growing electricity demand [76]. The electricity demand for both countries combined is projected to increase from 280 to 363 TWh per year from 2020 to 2050.

Annual heat demand from 2020 to 2050 and hourly heating profiles for space heating, domestic hot water, and industrial heat demand were sourced from Keiner et al. [77] and illustrated in Figure 7. It indicates a roughly stable heat demand across the transition. In LUT-ESTM a division between centralised and individual heat is conducted: centralised heat demand includes district heating as well as industrial heat across low (< 100°C) and medium temperature (100–1000°C) industrial heat. Residential and commercial heating systems, along with high-temperature industrial heat, contribute to individual heat demand. Low- and medium-temperature heat demand accounts for 62.0% of the industrial sector's heat requirements. District heating is not used in the UK and Ireland. In the UK, only 1.2% of the overall space heating and domestic hot water demand is supplied through district heating [78]. For the purpose of this study, it is assumed that heat networks are not significantly expanded for the 100% RE scenarios.

Details are in the caption following the image
Annual heat demand until 2050 for temperature levels (left) and end-use (right). HT, high temperature; LT, low temperature; MT, medium temperature.

The demand for transportation is categorised into two components: passenger transportation demand, measured in p-km , and freight transportation demand, measured in t-km. These categories are further divided into different modes of transportation, including road, rail, marine, and aviation. To determine the subregional demands, national values for the UK were split according to the proportion of the population for road (p-km and t-km), rail (p-km and t-km), and marine (p-km) transportation. For aviation, the passenger and freight demand were allocated based on the percentage of total passengers and unloaded cargo, respectively, at various airports, considering that a significant portion of aviation traffic is centred around the London airports. The allocation of marine t-km was based on unloaded cargo at different ports. Data for transport demand projections were taken from governmental sources: road (passenger and freight) [79], aviation (passenger) [80], and marine (freight) [81]. In the absence of specific data for aviation freight and marine passenger transport, it was assumed that the development of freight and passenger transport follows a similar pattern for both aviation and marine. The projections for transportation demand are depicted in Figure 8.

Details are in the caption following the image
Final annual transport demand until 2050 for passenger (left) and freight (right).

The transmission grid was simplified for the model to capture the structure of the high-voltage (HV) transmission grid found in the existing power system. The direct modelling of medium- and low-voltage distribution grids is not part of the model. To streamline the representation, each subregion is assigned a central load centre, which is interconnected with the load centre of neighbouring subregions. Transmission losses in the interregional transmission grids are taken into consideration by accounting for the distance between load hubs and the specific type of transmission line or cable utilised. Losses from regional distribution grid were obtained from [82]. It is assumed that 70% of all power transmission occurs via underground cables, while the remaining 30% is conducted through overhead power lines.

2.3 Scenario definitions

This study carries out simulations for three scenarios to show how certain constraints can impact the technology mix and costs of the energy system. Two scenarios focus on achieving 100% RE by 2050. The third scenario follows the UK government's net-zero strategy by 2050 through the utilisation of nuclear power and fossil CCS technologies, but also expansion of renewables, such as offshore wind power. BPS aims to achieve a transition to 100% RE without delayed policies or counterproductive actions, with the exception of land area limitations for onshore technologies, which are here assumed to be societal and political consensus. Additionally, the BPS plus scenario explores the impact of fewer area constraints for solar PV and onshore wind power. It also considers a reduced reliance on offshore wind and higher levels of imported e-fuels. In Table 2, the scenarios are summarised.

TABLE 2. Scenario description.
Scenario Description
Best Policy Scenario (BPS) 100% renewable energy and zero emissions as the key target in 2050. Phase-out of nuclear and fossil power plants is initiated immediately. Offshore wind serves as the primary source for electricity with 2 GW/y of offshore wind installations until 2026, and 3 GW/y beyond. Onshore wind power and solar PV are limited to 2%a for all subregions and 1% of available land area, respectively. Biomass is limited to biogas. Imports of e-fuel are allowed, but limited to e-LNG.
Best Policy Scenario– fewer restrictions (BPSplus) 100% RE in 2050 with more land area for onshore wind power (3%a) and solar PV (2%). Higher shares of e-fuel imports are allowed, including e-liquids, e-LNG, e-ammonia, and e-methanol. Offshore wind power installations must be at least 1 GW/y from 2030 onwards. Installations can be higher, if economically viable.
Current Policy Scenario (CPS) Represents the strategy described in Energy White Paper released by the government of the UK [22]. Expansion of nuclear power to one-fifth of total electricity generation share and fossil CCS applications are simulated.
  • CCS, carbon capture and storage; LNG, liquified natural gas; PV, photovoltaic; RE, renewable energy.
  • a For Scotland, the land area availability was chosen to be 2.5% in the BPS and 4% in the BPSplus to represent higher perceived social acceptance for this technology.


This section provides a detailed discussion of the BPS. The BPS will be examined thoroughly, followed by a comparison of the other scenarios. The comparison will focus on key outcomes related to primary energy demand (PED), electricity generation as well as costs, and CO2 emissions.

3.1 Best policy scenario

The BPS exemplifies a complete shift towards a 100% RE in 2050. This transition is primarily driven by offshore wind power as the main RE source, supported by onshore wind power, solar PV, wave power, and smaller contributions from biogas, geothermal energy, and hydropower. The energy transition for each sector from 2020 to 2050 is depicted in Figures 9, 10 to 11. During this transition, electricity generation experiences significant growth, expanding by a factor of 4. This growth is mainly attributed to the electrification of heat through the use of electric heating systems and heat pumps, the adoption of BEVs for transportation, and the utilisation of e-fuels like e-kerosene for aviation, based on renewable electricity.

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Electricity generation (left) and installed electrical capacity (right) by technology.
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Heat generation (left) and installed heat capacity (right) by technology.
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Electricity demand (left) and final energy demand (right) for transport by technology.

By 2050, offshore wind power emerges as the primary energy source, making a substantial contribution of 38.1% to electricity generation. Although the installed solar PV capacity is highest, its electricity output is limited due to less FLH. In terms of heat generation, there is a transition from relying on natural gas boilers to utilising heat pumps with exceptional efficiency for low-temperature heat requirements. Additionally, e-fuels and direct electric heating play significant roles in meeting medium- and high-temperature industrial heat demands. e-Fuels are only used for high-temperature process heat in industrial applications due to the low technology readiness level (TRL) of electric furnaces. Furthermore, there is a strong surge in electricity demand in the transport sector, reaching 618 TWh in 2050. Most energy savings in the transport sector can be achieved through direct electrification of road transport, due to much higher efficiency of BEVs compared to conventional internal combustion engines (ICEs), which explains the decreasing final energy demand, illustrated in Figure 11 (right). The strongly growing electricity demand is related to less efficient e-hydrogen and e-fuel production and use, which are necessary for a variety of applications such as international aviation and global commodity trade via marine shipping.

As the energy transition progresses and RE technologies become more prevalent, the demand for energy storage solutions increases. Figures 12-14 illustrate the range of applied storage technologies along with their growth patterns throughout the transition period. These figures also depict the hourly utilisation profiles of these technologies in 2050. Most storage output originates from electricity storage, followed by gas storage and heat storage, which accounts for a smaller amount.

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Electricity storage output until 2050 (left) and hourly battery storage state-of-charge in 2050 (right).

In terms of short-term electricity storage, various types of batteries in different use-cases emerge as the main storage technologies. Residential prosumer and utility-scale battery storage systems take the lead, supported by Vehicle-to-Grid and pumped hydro energy storage. These solutions play a crucial role in addressing the variable nature of renewable energy sources and ensuring a stable supply of electricity.

The solar PV generation and the battery use profile (Figure 12, right) complement each other from early winter to late autumn. During winter, wind and batteries interact more, as solar resources are very low, due to seasonality. Heat storage for high temperature (HT) industrial heat and district heat (equivalent to medium- and low-temperature industrial heat, as there is no district heat network in the British Isles) is charged in the evening hours from spring to autumn (Figure 13). Hydrogen storage (Figure 14) operates as a mid-term buffer storage with 12 full charge cycles over the year to balance energy supply and demand, when wind is not vastly available. The results indicate that methane storage (not visualised here) with five full charge cycles serves more for seasonal balancing than hydrogen. The extensive utilisation of these storage technologies ensures a harmonious alignment between supply and demand for every hour of the year .

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Thermal energy storage output until 2050 (left) and hourly heat storage state-of-charge in 2050 (right).
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Gas storage output until 2050 (left) and hourly hydrogen storage state-of-charge in 2050 (right).

Illustrated in Figure 15 is the regional electricity generation mix for each region, showing that Scotland, Ireland, and Southern England become energy supply hubs. Wales, England (except London), and Northern Ireland are offshore wind centres. Scotland and Ireland use higher shares of onshore wind and wave power. London acts as a demand hub and a supply sink and can produce electricity almost only through prosumerism (rooftop PV), indicating its dependency on imports from neighbouring regions. Where available, geothermal energy contributes a small share.

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Regional electricity generation in 2050.

The regions of the British Isles are interconnected, leading to a total transmission capacity of 92 GW in 2050, where some regions become net importing regions and others become exporters, as illustrated in Figure 16. The integrated approach of regional interconnection, combined with sector coupling and energy storage, leads to low shares of curtailment of renewable electricity generation. In 2050, the total electricity trade amounts to 293 TWh with a curtailment of only 4 TWh.

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Transmission capacity (left) and exchanged electricity for all regions (right) in 2050 indicating net exporting and importing regions.

The regional storage distribution is illustrated in Figure 17. It can be seen that battery prosumers are predominantly located in Southern England, London, and the Midlands and hydrogen/gas storage is located in the regions with lower population density and respectively lower demand. Pumped hydro energy storage (PHES) and adiabatic compressed air energy storage (A-CAES) are located in regions, where geographical availability is given. A-CAES plays a minor role with a total storage output of only 69 GWh.

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Regional annual generation from electricity storage (left) and heat storage (right).

The flow of energy for all sectors in 2050 is presented in Figure 18. RE sources, including environmental heat, serve as the sole origin of all energy, with a small portion being imported in the form of sustainable e-LNG. Different sectors are strongly interlinked with each other via storage, and various Power-to-X applications, which can be identified as one of the key differences to the current energy system and substantiates the term ‘Power-to-X economy’ [83]. Grid use and conversion losses can further be seen. Green e-hydrogen produced from water electrolysis (blue in the centre of the diagram) holds a central role in the energy system; it primarily functions as an intermediate energy carrier for the production of e-fuels rather than being directly utilised for final energy demand [83]. Figure 18 further provides insights in the most important sector coupling technologies: heat pumps (PtH), BEVs (power-to-mobility), and electrolysis as a basis for further Power-to-X conversion steps, which account for significant energy flows.

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Energy flows in 2050 for the British Isles. All values are displayed in TWh. TWh, terawatt hour.

Figure 19 visually represents the electricity exchange among different regions of the UK and Ireland. Notably, there is a strong exchange of electricity between Wales and Southern England, and further with London, which indicates that London is partly supplied by offshore wind from Wales. Additionally, the East of England supplies electricity to London. Wales engages in electricity exchange with the Midlands and Ireland, while Scotland exports electricity to the North of England. There is almost no electricity exchange between Ireland and Northern Ireland as a result of cost optimisation, which may look different in reality.

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Electricity exchange within the UK and Ireland in 2050.

Figure 20 presents the evolution of levelised costs (left) and total costs (right) throughout the transition period. The levelised cost of electricity (LCOE) experiences a substantial reduction, decreasing from 80.2 to 42.8 €/MWh from 2020 to 2050, with capital expenditures comprising the largest proportion. The total annualised system costs remain relatively stable during the transition, starting at 85.8 b€ in 2020, peaking at 90.9 b€ in 2030, and subsequently declining to 78.6 b€ in 2050. Capital expenditures account for the majority of these costs, followed by fixed operational costs.

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LCOE (left) and total annualised system costs (right) until 2050. LCOE, levellised cost of electricity.

During the energy transition, CO2 emissions witness a decline across all sectors, ultimately reaching zero in 2050, as depicted in in Figure 21. Due to the roll-out of wind power and heat pumps at early transition steps, the power and heat sectors experience an early and substantial emission reduction. Low-carbon alternatives for high-temperature industrial process heat, aviation, and marine transportation rely on the availability of e-fuels, which become more abundant in the later stages of the transition. Thus, these parts of the energy system are defossilised later. As illustrated in Figure 21 (bottom right), the highest share of emissions originates from heat and transport sectors at any given time of the transition. The transport sector is mainly influenced by passenger transport via road and aviation. The main characteristics of decreasing emissions are the switch to BEVs for road transportation and the switch from fossil kerosene to e-kerosene jet fuel for aviation. In a 100% RE system, the latter is fully carbon neutral, since the required CO2 for fuel production is sourced via direct air capture [84]. By initiating the energy transition without delays, the emission of CO2 can be diminished by 36% in the next years, with the potential to avoid over half of today's emissions by 2035.

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CO2 emissions for the power sector (top left), heat sector (top right), transport sector (bottom left), and all sectors (bottom right). CO2, carbon dioxide.

3.2 Scenario comparison

The key distinction among the three scenarios lies in the composition of the electricity generation mix, which significantly impacts the costs and the energy system structure. The CPS shows highest overall PED, followed by the BPS and BPSplus as depicted in Figure 22. The CPS reaches 1984 TWh and the BPS plus 1659 TWh in 2050. The figure further indicates that the key difference between the CPS and BPS/BPS plus, the utilisation of large amounts of nuclear power and fossil fuels even in 2050. It is assumed that the remaining emission is reduced by DACCS, which was introduced to LUT-ESTM .

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Primary energy demand for all scenarios until 2050.

The composition of the electricity generation mix, as depicted in Figure 23, shows the distinctive characteristics of each scenario. Offshore wind power emerges as the primary renewable energy source in all scenarios, except for the BPSplus, where solar PV attains the highest share, accounting for 37% of the total generation. In the BPS scenario, offshore wind power represents 38% of the generation, equivalent to 537 TWh. In the BPSplus scenario, due to less restrictive land area limitations, onshore wind power and solar PV gain greater significance.

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Electricity generation mix for all scenarios until 2050.

A strong feature of the CPS scenario is the use and expansion of nuclear power, which reaches 22% of the generation in the target year, as indicated by the governmental strategy. Wave power is a key feature only in the BPS with a marginal small contribution in the CPS and no contribution in the BPSplus. Significantly different levels of electricity generation are also evident among the scenarios. In the CPS scenario the least amount of electricity is generated, attributed to lower levels of electrification in the heat and transport sectors. In the BPSplus scenario, more imports of e-fuels result in lower domestic electricity generation, contributing to a reduced PED and avoiding losses in e-fuels production in the UK and Ireland.

All the scenarios share the common objective of achieving net-zero CO2 emissions by 2050. Figure 24 (left) provides an overview of cumulative emissions throughout the entire system transformation, revealing that the CPS emits more emissions compared to the other scenarios. Among the 100% RE scenarios, there is not a significant difference, although the BPSplus demonstrates the lowest cumulative CO2 emissions. Additionally, Figure 24 (right) demonstrates that emissions from the power sector can be eliminated early in all scenarios, while the defossilisation of the heat and transport sectors occurs later. By 2030, the 100% RE scenarios achieve an almost full reduction of power sector emissions and nearly 50% reduction of all emissions.

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Cumulative (left) and sectoral CO2 emissions (right) in GtCO2 for all scenarios during the transition.

Finally, each scenario shows different cost characteristics and is illustrated in Figure 25, where the levelised costs of electricity (left) and the total annualised costs for all sectors (right) are illustrated. The capital expenditures are the main driver for the LCOE for all scenarios. The BPSplus benefits from the lowest LCOE as well as lowest total annualised system costs in 2050 with 40 €/MWh and 63 b€, respectively. In contrast, the CPS has the highest levelised costs with LCOE of 70 €/MWh and total annualised costs of 93 b€. In terms of total annualised system costs, the BPS is between BPSplus and CPS with 79 b€ in 2050. More detailed comparisons in terms of costs for all sectors can be found in the supplementary material.

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LCOE (left) and total annualised system costs (right) for all scenarios until 2050. LCOE, levelised cost of electricity.


4.1 General implications for the energy transition

The findings of this research describe the technical implications for implementing various cost-optimised energy transitions, moving away from the current non-sustainable energy system towards a low-carbon energy system in the UK and Ireland. These transitions are carried out within specified framework conditions and constraints. A large amount of insights can be derived from this.

First, the electrification of all sectors is a prerequisite for an effective transition. Electrification leads to significant PED reduction due to efficient technologies such as heat pumps and BEVs [85]. Incremental energy efficiency improvements such as improved building insulation or increased efficiency of electrical appliances are helpful to further reduce energy demand and are already tackled by the UK government [86]. However, the impact of electrification is considered to be the measure with more impact [8] and will most likely be one of the key characteristics of future energy systems [87]. Second, a technology mix of different RE technologies is necessary that must be balanced by a set of storage technologies, flexible use of system components, electricity exchange between neighbouring regions and several sector coupling elements. This integrated system planning approach leads to a low share of curtailment and high integration rates of RE generation. The implementation of large-scale storage systems must be subject to intelligent and holistic system design: sufficient grid infrastructure and proximity to renewable electricity generation must be ensured. Gas storage as well as PHES and A-CAES are limited in terms of geographically suitable storage sites, which must be considered an additional constraint. Third, 100% RE scenarios (BPS, BPSplus) can be economically competitive or even significantly cheaper than the governmental strategy (CPS). Fourth, by the year 2030, significant progress can be made in transforming the power sector. However, achieving the transformation of the heat and transport sectors necessitates the widespread implementation of e-fuel production methods [88, 89]. These e-fuels include e-hydrogen, e-methane, e-methanol, e-ammonia, and Fischer-Tropsch fuels. Solid carbon pricing mechanisms as one of the key financing approaches combined with the decreasing costs of renewable electricity generation and balancing technologies lead to economically attractive transition scenarios.

The findings further indicate that the expansion of clean and affordable renewable electricity generation technologies, such as onshore wind power and solar PV, can significantly reduce the overall costs of the energy system (BPSplus). This stands in contrast to a scenario with limited land availability (BPS). The main scenario of this study, the BPS, which is considered to be the socially desired path within the possible options for 100% RE, relies on a diverse range of energy sources for electricity generation. Offshore wind power is the most important, which could be exceptional for the case of the British Isles, since most countries in the world are expected to transition towards solar PV in the sunbelt [90] and a wind-solar-mix in countries with stronger seasonality [91]. For the British Isles, offshore wind power will be supported by solar PV, onshore wind power, hydropower, wave power, geothermal energy, and the utilisation of biogas from organic residues.

The heat sector, which is almost fully electrified, relies on heat pumps for domestic hot water and space heating that can be supplied by decentralised rooftop PV for prosumers. It is important to note that the rapid scale-up of heat pumps in the study is a result of the cost optimisation approach used in the model, and the actual deployment in reality may occur at a slower pace. Additionally, all new technologies across all sectors must interact via sector coupling. Smart and resilient distribution grids are necessary to supply the large number of heat pumps and BEVs with sufficient renewable electricity. Measures to improve the integration of those technologies into future distribution grids include smart charging for BEVs [92] and V2G approaches (mobility-to-power) [93] or the flexible and price-driven operation of heat pumps [94]. Another measure is demand side management (DSM), which has already been investigated for the case of the UK in the 2000s [95] and could further assist in integrating sector coupling technologies, while lowering the costs for storage and transmission infrastructure.

EIIs such as the production of steel and cement need temperatures of more than 1000°C, which is beyond the abilities of heat pumps. Different approaches such as electric kilns and boilers are required, but suffer from low technological maturity [96, 97]. However, other studies conclude that avoiding e-hydrogen and e-fuels leads to higher system efficiency and lower costs and should thus be avoided in favour of direct electrification of heat [98, 99]. Green e-hydrogen is further expected to become unavoidable as a feedstock for steel production [100, 101] and the production of green e-chemicals [102]. Historically, electricity prices in the UK have been higher compared to other European countries [103]. To defossilise EIIs, the electrification of heat [104] and processes is required, which is a complex topic and is dependent on massive upscaling of renewable electricity supply, green e-hydrogen production, and the commercialisation of direct and indirect electrification technologies [105]. In this study, the full electrification of low- and medium-temperature industrial process heat is assumed, while high temperature process heat is indirectly electrified through e-fuel use. From all sectors, the defossilisation of EIIs is technically most demanding, yet possible, as studies conclude [106, 107]. As costs of renewable electricity are expected to decrease, the long-term competitiveness of EIIs can be considered to be likely. However, the near-to-midterm investments in new production plants with high capital costs [108] must be flanked by governmental measures, such as carbon contracts for difference [109] or supported industrial electricity prices to avoid the migration of large industries to other countries, leading to carbon leakage [110]. For the UK, current measures include the Industrial Energy Transformation Fund (IETF) [111] and the Clean Steel Fund (CSF) [112], while support schemes for the Irish industry are discussed [23].

From an efficiency point of view, electrification of transport is superior compared to the use of e-fuels, as long as it is technically feasible. In order to represent a possible market diversity, additional technologies for powertrains with less shares in the overall vehicle mix were considered in this study (e.g. fuel cell electric vehicles). However, other studies evaluate maximum efficiency potentials if only BEVs are considered to be used for road passenger transport [113]. Due to the limited energy density of batteries, combustible fuels that are produced from sustainably captured CO2 and green e-hydrogen, will most likely become important for aviation and marine transportation [114]. E-ammonia and e-methanol are proposed as fuels for marine transportation and are likely to be competitive in the future [115]. The study results indicate that in ambitious scenarios, no demand adjustments are necessary as sufficient technological options exist to fully decarbonise the current transportation demand. However, other studies conclude that measures such as avoid, shift, and improve can have positive impacts on citizens’ well-being [116]. Beyond powertrain transitions, broader discussions on mobility transitions in general that include behavioural changes can have positive impacts on early emission reduction [117]. Developments within the British Isles, such as car-free inner cities, have been discussed for various cities including Dublin [118] but also Edinburgh, Birmingham, and London [119].

The results for the UK and for Ireland show several similarities. The heat and the transport sectors as well as energy storage roughly rely on the same technologies in all scenarios: battery storage for short-term storage, heat pumps for individual heating, and BEVs for passenger transportation. Differences can be found mostly for the electricity generation mix, as Ireland's main source of electricity is wave power in the BPS (UK: mostly offshore wind power), onshore wind power in the BPSplus (UK: solar PV or offshore wind power), and offshore wind power in the CPS (UK: nuclear power). From all subregions in the UK, Scotland is the one with a structure very close to Ireland, most likely due to similar resource availabilities, land area, and comparable energy service demands. Nuclear power is not part of governmental plans in Ireland and therefore not imposed in the CPS.

The overall findings of this study in terms of electrification and RE expansion are consistent with studies for sector coupling and smart energy systems [120, 121] as well as for the energy transition of other countries [57, 122]. Green hydrogen becomes a key component in a fully renewable energy system, but not necessarily for final energy use. Instead, green hydrogen may work as an intermediate product for the conversion to a variety of e-fuels. Therefore, it should be considered as important but not as the most characteristic element of a future Power-to-X economy [83] that also comprises electricity-based mobility and heat as well as the substitution of fuels for primary energy supply. The downstream applications for green hydrogen derivatives are vast, such as e-ammonia (as a fuel or for fertilizers) [123], e-methanol (as a fuel or as a basic chemical for the chemical industry) [124], or Fischer-Tropsch fuels [125] as they all necessarily rely on hydrogen. While some direct uses for hydrogen are realistic (e.g. for green steel), it may not serve as a silver bullet for all end-use applications. Upscaling green e-hydrogen production can be initiated through decentralised electrolysis [126], while competitiveness must be ensured.

4.2 Onshore versus offshore energy supply

Due to high wind speeds in the UK and Ireland, the potential of onshore wind power is undisputed [127, 128]. It benefits from high technological maturity and low costs, which has been known for more than a decade [129]. However, it is subject to social and political opposition, especially in the UK. It was found to be the technology with the lowest approval rating of only 44% between 1991 and 2017. Offshore wind instead shows an approval rating of 89% [43]. While earlier research focussed solely on offshore wind as the main renewable resource [52, 54], the findings of the present study clearly indicate that onshore wind can lower the costs of electricity. This study further suggests that solar PV should not be underestimated for the British Isles, since its decreasing costs can compensate for the lower FLH. These findings are in line with the projections for other countries, indicating that solar PV will be the most important energy resource in future energy systems [130, 131]. From an acceptance perspective in the UK, solar PV seems to be subject to less opposition than onshore wind according to Harper et al. [43] and might offer a low-cost technology with high acceptance. However, it remains unknown how acceptance of technologies will develop in the future.

The topic of economic competitiveness of different RE technologies is scientifically debated for the case of UK. A recent study by Mandys et al. [132] highlights the cost competitiveness of solar PV in the UK. The authors suggest that especially utility-scale systems should be considered seriously from 2035 onwards as a major technology for the energy transition. Klöckl et al. [133] argue against by highlighting that wind power shows higher FLH and superior demand correlations and suggest that power system models should examine which technology performs better in a system context. Mandys et al. [134] emphasise in their response that solar PV shows the clear advantage of a projected steep cost decline, which is not expected to the same extent for wind power. The results of this study confirm that onshore wind power performs economically better than solar PV in the first 5 to 10 years of the transition, as shown in Figure 9, due to higher FLH, despite higher capital expenditures. However, the wind onshore expansion decreases, as soon as land area limitations are reached, which opens a window of opportunities for solar PV. In the BPS, the upper limit of onshore wind power is reached earlier than in the BPSplus. In a system context, both onshore technologies are economically more attractive than offshore wind power, which materialises in the scenarios only due to predefined ramping. Finally, it is not either wind power or solar PV, the least cost system solution requires both least cost onshore electricity supply options.

The trade-off between land area availability and system costs can be evaluated in detail when the central BPS is compared with the BPSplus scenario. Higher shares of onshore wind power and solar PV can reduce the costs significantly. For this reason, a strong support of energy community projects that aim for onshore technology deployment (and thus increase the socially tolerated land area dedicated to onshore wind and solar PV) can be an economically powerful measure. Energy community projects raise social acceptance and inclusion, while supporting economic interests of marginalised communities [135]. Apart from this, as demonstrated in the BPSplus scenario, the total system costs would be decreased significantly. The BPSplus can be seen as a ‘testing-the-limits-scenario’ in which also energy independence is softened, by allowing higher imports of e-fuels (leading to 155 TWh for BPSplus in 2050, compared to 29 TWh in the BPS), which again lowers the costs. The imported e-fuels in the BPS are solely e-methane, while in the BPSplus, 83% of the imported fuels are Fischer-Tropsch fuels (mainly e-kerosene jet fuel) and 17% e-methane. The import dependency in the BPS is very low with only 2% of total PED compared to 12% in the BPSplus.

Wave power (along with other forms of ocean energy) is a source of energy that has the potential to become important for future energy systems [136]. Although it is not yet cost-competitive to other RE sources and the technology suffered from technical backlashes in the past [137], it has the ability to contribute in the long term, when the technology becomes more mature and costs decrease [138, 139]. According to Satymov et al. [139] wave power can become a competitor to offshore wind power, since wave power has the advantage of higher installation density and is perceived with smaller visual impact. In the results of the BPS, wave power becomes an important part of the energy system from 2040 onwards, in accordance with economic projections applied in this study [140]. If economic conditions are favourable for wave power, the case of the British Isles presents one example of how wave power can impact and contribute to energy transitions. Wave power could share the stage with offshore wind power if land area is geographically limited. This could be the case also for islands and archipelagos like the Maldives, where the impact of wave power on the energy transition was recently examined [140]. In addition, energy supply diversity is increasingly noticed as a means for overall energy system resilience and needs to be considered in the societal discourse [28].

4.3 Transdisciplinary implications and opportunities of a 100% renewable energy system for the British Isles

The transition to a 100% RE system across all sectors implies a set of transdisciplinary implications that include challenges but also several opportunities that benefit from further discussion.

A prominently discussed topic is district heating, which gained lots of attention in the past decade and fourth-generation district heating is increasingly discussed as an element of 100% RE systems [141]. In this study, no expansion of district heating was assumed due to the fact that, historically, almost no heat networks were built in the UK and Ireland until today [142, 143], only small expansions are planned [22] and the trend of ongoing decentralisation in energy systems implies a tendency towards individualised heating. However, previous studies highlight potential benefits of district heating, such as the efficient utilisation of waste heat sources [141, 144], the reduction of biomass consumption [145], and lower system costs [141]. A previous 100% RE study on Ireland concluded that the implementation of district heating can be the first step of any energy transition for straightforward cost and fuel savings [46], while another study concluded that the initial costs for a UK heat network would be initially more expensive than in other European countries [144]. It can be concluded that the use of district heating can improve the energy transition of the British Isles, while its widespread application is uncertain and the choice between individual or centralised heat technologies must be carefully made to respect local circumstances of municipalities [146].

Prosumerism and decentralised trends will change the role of consumers in future energy systems [122]. An often proposed measure to adjust the energy system in accordance with variable renewable electricity generation is DSM and adjusted consumption profiles of households and industry [147]. Benefits of DSM include increased flexibility, reduced generation capacities, and potential cost reduction due to reduced energy storage and transmission requirements [148], which was confirmed for the case of Ireland [149]. However, the results of this study demonstrate that the current demand profiles can be fully met without demand adjustments, if variable RE generation is properly balanced through energy storage, sector coupling, and interconnections but future research might investigate DSM options for the British Isles energy transition in a holistic approach.

Another aspect of the energy transition is energy security, which became a broadly discussed topic, recently. The British government reacted to the Russian invasion in Ukraine with a new energy security strategy, which takes RE expansion into account, but also nuclear power upscaling and shale gas exploitation [86]. Instead, a country whose energy system is based on 100% domestic RE supply can significantly increase its energy sovereignty due to strong reduction of fossil fuel and uranium imports and thus vulnerability to geopolitical distortions. The current import dependency can be reduced significantly, although dependency remains in terms of wind turbine and PV module import, which can be reduced by supporting British or Irish manufacturers. Energy security must further be ensured by inter-annual balancing technologies in years with lower wind yield, which can include the overdimensioning of RE capacity but also the excess production of storable gases and fuels such as e-hydrogen or e-methane in high wind yield years, which can be stored and reconverted in years with low wind yields.

From a societal point of view, the energy transition towards 100% RE has impacts on the job market. Due to higher labour intensity of RE supply chains, the energy transition has the potential to create new jobs in different fields [150]. Based on the employment factor method [151], a previous study estimated that the number of total jobs in the energy system increases to more than one million in the late 2020s and finally to 2 million by mid-century in the British Isles [150]. While it is acknowledged that jobs in the fossil industries will disappear, new technological fields and their vast potentials such as water electrolysis, FT synthesis, and direct air capture have the possibility to overcompensate lost jobs in the fossil industries considerably. Under considerations of a just transition and considering the fact that some regions are more vulnerable than others (e.g. Midlands, Yorkshire, and the Humber) [152] an integrated approach is necessary that includes job-transfer, support mechanisms, and structural region-dependent aspects [153], while key factors such as effectiveness, fairness, and political transformation potential must be considered [154].

Although largely discussed for developing countries [153], the COVID-19 pandemic and rising energy prices increased the rates of energy poverty also in the UK and Ireland. In 2022, 13.4% of households in the UK [155] and 29% in Ireland [156] were subject to fuel or energy poverty. Energy poverty is further connected to low incomes and inefficient buildings [157]. The shift towards an entirely RE system can have positive impacts on energy poverty reduction, since the dependence on fossil energy carriers and thus the vulnerability to global market sensitivities is reduced. Apart from this, the results of this study indicate that LCOE but also total system costs can decrease, which will lower overall electricity prices. As mentioned earlier, the support of energy communities can further reduce costs for communities. Further, the effect of indoor air pollution should be mentioned and is often connected to energy poverty in developing countries but can also be an issue in parts of the EU [157]. With a shift to 100% RE with low shares of biomass use positive impacts on outdoor air pollution reduction can be expected [6].

4.4 Entirely renewable versus fossil-nuclear-renewable energy supply

Nuclear and fossil energy remain cornerstones of the UK's energy transition plan. The governmental strategy towards climate neutrality that has been updated with the British energy security strategy puts additional focus on domestic fossil resource exploitation, to become independent from Russian imports. For instance, shale gas is again considered a potential option [86]. This current strategy can be considered the key political barrier for a future 100% RE system, as fossil-nuclear-based energy systems differ fundamentally from 100% RE systems, where the former are designed in a centralised and the latter typically in a decentralised manner. The current strategy of the UK can lead to lock-ins, block investments, and innovations in much needed RE infrastructure [27] and block flexible wind farm operation [158]. Further, it can lead to higher costs and risks, CO2 emissions, and construction delays [159]. Research from the University of Sussex indicates that a correlation between shifts in energy policy towards nuclear power and activities in the UK's military nuclear capacities could be observed in the last decades, while countries without military nuclear programmes are moving away from this technology [160].

The Irish government does not mention nuclear power in its recent Climate Action Plan and CCS is rather mentioned in terms of hard-to-abate industrial emission [161], where it can be considered essential for some industries [107]. The strategies of both countries fundamentally differ in terms of this important viewpoint. Although the discussion on soft (entirely renewable) and hard (nuclear power) energy transition pathways originates from the 1970s [162], it is still subject to current debates, as some countries in Europe focus on nuclear power (UK, France, Finland) while others do not (Germany, Ireland, Denmark) [163]. The results of this study indicate that both pathways towards entirely RE supply can save a significant amount of total costs under the applied constraints. Ultimately, decisions towards or against a certain technology are made in a societal discourse and executed by policy makers, while transparency in terms of these decisions is crucial [160]. However, the possibility of clean and affordable electricity generation through abundant RE potentials in the case of the British Isles might steer this discussion away from fossil and nuclear energy supply (especially in the UK) and more towards offshore and onshore wind power and solar PV, which will finally be complemented by storage, flexibility, and sector coupling components.

4.5 Study limitations

The study is subject to some limitations that could impact the generalisability of the obtained findings. Since LUT-ESTM is a cost-optimisation model, especially cost assumptions but also demand projections are critical for the study results and can be subject to a certain bias. While all of the collected data are referenced in the supplementary material, the model requires a set of specific data, for example, to describe the capital expenditures of a certain technology at each time step of the transition. To increase accuracy and to minimise bias, all input data would need to be validated through multiple data samples for each input to create a normal distribution and subsequently derive the most probable data. However, this was beyond the scope of this study. Instead, attention was paid to ensure the validity of the collected data, by collecting the most up-to-date data, and relying on peer-reviewed journal articles and official, governmental statistical sources.

Additionally, modelling energy transitions up to 2050 requires assumptions for future developments, which are inherently subject to uncertainty. The phenomenon of unpredictability and uncertainty intensifies as one extends their gaze into the distant realms of the future. The approach of this study was to observe and represent a given energy system and base future projections on current market trends and developments, which are considered as most likely according to the knowledge of today. However, geopolitical events, like violent conflicts, can have a strong influence on market developments, as has just recently happened to the natural gas market. Energy system models do not properly include social factors, such as justice and acceptance, which are already recognised in the scientific debate [164]. One attempt was made in this study by considering the limited social acceptance of onshore wind power, being aware of the fact that more detailed research should be done. Other aspects of future uncertainty exist in terms of material criticality, for example, for lithium [165], which can further affect the transition although studies indicate that most limited materials can be potentially substituted [10]. However, material criticalities would most likely influence the costs of certain technologies and thus have an impact on the results of this study.

The study is further subject to limitations regarding the abilities of the applied model. Although the modelling has been done in high temporal resolution on an hourly scale, the modelling results do not approach energy system characteristics that occur below this time resolution, for example, on a second or minute-scale, but these are assumed to be balanced with battery storage with smart inverters. Adequate capacity of short-term storage is installed in all scenarios. N−1 constraints are not modelled in detail, as well as frequency and voltage stability requirements. To conduct this, mere power sector models or stochastic optimisation methods [166] are better suited. However, these lack the ability to properly demonstrate an energy transition across all sectors.

Further, this study has not addressed the interconnection between the British Isles and Europe, as this has already been done in [51, 52]. More research is needed to further understand the interconnections between subregions of the British Isles and other European countries. Due to the characteristic of a wind power dominated energy system in the British Isles, the effects of inter-annual wind variations have not yet been investigated but should be subject to follow-up research. Especially, for countries such as the UK and Ireland with high expected shares of wind power in a 100% RE system, studies show that annual wind yield varies significantly [167], which was not considered in this study. The national transmission grid is also represented in a simplified way in this study and factors like grid expansion bottlenecks, potential grid congestions, and their impact on the energy transition are not examined.

The regional implementation of RE technologies is not considered beneath the level of subnational regions. However, PV systems, heat pumps, battery systems, and electric vehicles in particular are connected to low- and medium-voltage grids. These must be designed accordingly and extended with communication technology to implement vehicle-to-grid and demand-side management concepts. Distribution grids have not been modelled in this study. While electricity can be transported efficiently over long distances, as shown, heat must be provided more locally. Different regional conditions lead to different supply concepts (district heating if industrial waste heat is available, central heat pumps, or individual heat pumps). Other tools need to be developed for such local investigations for instance, power system simulation in a higher detail or multi-energy system models for distribution grids [168].


Three scenarios for the energy transition towards zero emissions in 2050 of the United Kingdom and Ireland were examined, by applying a mature energy system model. Under given constraints, it could be demonstrated that 100% renewable energy can be achieved by (1) relying on offshore wind power as the dominant source of energy or by (2) increasing the share of onshore wind power and solar PV. A scenario based on the approach of the governments of the United Kingdom and Ireland, involving fossil carbon capture and storage and nuclear power in the United Kingdom, resulted in the highest costs. The least costs could be achieved for the scenario with higher shares of onshore wind and solar PV, reaching 63 billion Euro in 2050, which is 20% below the scenario with offshore wind focus. The results of this study may serve as a reopener the debate on whether onshore wind and solar PV should gain more attention in the energy transition, especially for the United Kingdom, where resistance towards onshore wind can be perceived. For the two possibilities of reaching 100% renewable energy, a trade-off between land-area use and total costs must be found. To reach the ambitious goal of 100% renewable energy in all sectors, a set of technologies for storage, sector-coupling, and flexibility must be applied. If this is actively targeted, a fossil-nuclear approach that leads to lower levels of sustainability and higher costs can be avoided.


  • 2 W/3 W
  • two and three wheelers
  • AC
  • alternating current
  • A-CAES
  • adiabatic compressed air energy storage
  • b€
  • billion euros
  • BEV
  • battery electric vehicles
  • BPS
  • best policy scenario
  • C&I
  • commercial and industrial
  • CAGR
  • compound annual growth rate
  • capital expenditures
  • CCGT
  • combined cycle gas turbine
  • CCS
  • carbon capture and storage
  • CHP
  • combined heat and power
  • CPS
  • current policy scenario
  • CSP
  • concentrating solar power
  • direct air carbon capture and storage
  • DC
  • direct current
  • DH
  • district heating
  • e-fuel
  • electricity-based fuel
  • FCEV
  • fuel cell electric vehicle
  • FLH
  • full load hours
  • GDP
  • gross domestic product
  • GHG
  • greenhouse gas emissions
  • GW
  • gigawatt
  • HDV
  • heavy duty vehicle
  • HT
  • high temperature
  • HV
  • high voltage
  • HVAC
  • high voltage alternating current
  • HVDC
  • high voltage direct current
  • IH
  • individual heating
  • IPCC
  • intergovernmental panel on climate change
  • LCOC
  • levellised cost of curtailment
  • LCOE
  • levellised cost of electricity
  • LCOH
  • levellised cost of heat
  • LCOT
  • levellised cost of transmission
  • LDV
  • light duty vehicle
  • LNG
  • liquified natural gas
  • LT
  • low temperature
  • MDV
  • medium duty vehicle
  • MT
  • medium temperature
  • MWh
  • megawatt hour
  • OCGT
  • open cycle gas turbine
  • OPEX
  • operational expenditures
  • PED
  • primary energy demand
  • PHES
  • pumped hydro energy storage
  • PHEV
  • plug-in hybrid electric vehicle
  • p-km
  • passenger kilometres
  • PP
  • power plant
  • PtH
  • power-to-heat
  • PtX
  • power-to-X
  • PV
  • photovoltaic
  • RE
  • renewable energy
  • RES
  • residential
  • ROR
  • run-of-river
  • SDGs
  • sustainable development goals
  • SoC
  • state of charge
  • ST
  • steam turbine
  • TES
  • thermal energy storage
  • t-km
  • tonne kilometre
  • TWh
  • terawatt hour
  • UK
  • United Kingdom

    Philipp Diesing: Conceptualization; Data curation; Formal analysis; Methodology; Visualization; Writing—original draft. Dmitrii Bogdanov: Data curation; Methodology; Software; Writing—review & editing. Rasul Satymov: Investigation; Visualization. Michael Child: Data curation; Writing—review & editing. Ines Hauer: Writing—review & editing. Christian Breyer: Conceptualization; Investigation; Resources; Validation; Writing—review & editing.


    The authors thank David Toke from University of Aberdeen for valuable discussion on the energy transition options of the UK and LUT University for general support.


      The authors declare no conflict of interest.


      The first author would like to thank Reiner Lemoine Foundation for the valuable scholarship.


      The supplementary material can be found:


      The data that support the findings of this study are available from the corresponding author upon reasonable request.