The UAE Net-Zero Strategy—Aspirations, Achievements and Lessons for the MENA Region

Abstract

The Middle East and North Africa region has not played a major role in climate action so far, and several countries depend economically on fossil fuel exports. However, this is a region with vast solar energy resources, which can be exploited affordably for power generation and hydrogen production at scale to eventually reach carbon neutrality. In this paper, we elaborate on the case of the United Arab Emirates and explore the aspirations and feasibility of its net-zero by 2050 target. While we affirm the concept per se, we also highlight the technological complexity and economic dimensions that accompany such transformation. We expect the UAE’s electricity demand to triple between today and 2050, and the annual green hydrogen production is expected to reach 3.5 Mt, accounting for over 40% of the electricity consumption. Green hydrogen will provide power-to-fuel solutions for aviation, maritime transport and hard-to-abate industries. At the same time, electrification will intensify—most importantly in road transport and low-temperature heat demands. The UAE can meet its future electricity demands primarily with solar power, followed by natural gas power plants with carbon capture, utilization and storage, while the role of nuclear power in the long term is unclear at this stage.

1. Introduction

Global warming, driven by human activities, is causing climate change, with aggravating impacts on the weather, ecosystems, living habitats, human health, food and water security, etc. Atmospheric CO₂ levels—and, consequently, the Earth’s average surface temperature—continue to rise [1]. Reducing greenhouse gas (GHG) emissions is a global responsibility. The Middle East and North Africa (MENA) region is a climate change hotspot [2]. Heatwaves are becoming more frequent and harsher, leading to growing heat-related mortality rates. Climate change is also increasing droughts and aggravating the already severe water stress problem, raising also food security concerns [3]. Furthermore, close to 100 million people in the MENA region live in coastal areas and will eventually be affected by the rise in sea levels. Hence, a path to net-zero emissions is vital for this region.

The potential of the MENA region to become a solar power and green hydrogen hub is well recognized [4,5,6]. However, a question remains as to how rapidly such a transition could take place. This paper focuses on the United Arab Emirates (UAE), its net-zero strategy and the nation’s alignment with it through performed actions, set projections and realistically achievable goals. The UAE is an important player in the MENA region with regard to the energy sector transition. In particular, as the country has a strong financing base, it could play a vital role in the technology transformation and trigger cost reductions over time based on the learning curve.

The carbon footprint of the UAE is estimated at 260 Mt CO₂ eq., which is mostly attributed to the energy sector and industry [7]. Under a business-as-usual scenario, i.e., if no or minor carbon abatement measures are taken, these emissions will double by 2050. This will be accompanied by troubling resource scarcities, increasing energy costs, major environmental impacts, detachment from global innovation, etc. On the other hand, with the appropriate measures, projections and policies [8], the UAE will be able to drastically reduce its emissions in the coming decades to eventually reach carbon neutrality. The country has committed itself to a net-zero roadmap: the UAE Energy Strategy 2050 provides a framework for environmental obligations while creating an environment conducive to economic growth [9].

This work focuses on the UAE’s power sector decarbonization as the cornerstone of the broader energy sector transition, which includes intensifying electrification and technological migration towards power-to-fuel (P2F) solutions, especially green hydrogen. In the long run, the power system will become the backbone of the energy sector; hence, the decarbonization of power generation is the main element in reaching carbon neutrality. Such a transition is ambitious, especially considering that, in 2019, around 97% of all power generation in the UAE originated from fossil fuels—mostly natural gas [10]. However, considering recent achievements and short-term projections, the UAE is advancing relatively rapidly in the decarbonization of its power sector, and this trend will eventually lead to carbon neutrality, as will be detailed in this paper.

This article emphasizes the criticality of global warming and climate change and the urgent need for action to drastically reduce GHG emissions (Section 2). It also discusses the ongoing electricity sector transformation, especially the growing role of variable renewable energy (VRE) and its technological implications (Section 3). Furthermore, we detail how the UAE is pursuing these transitions and implementing emerging technologies to achieve its carbon neutrality projections and commitments (Section 4). Finally, we summarize the conclusions of this work (Section 5).

2. Climate Change and Climate Action

Global warming and climate change have become some of the most pressing issues for modern society. The annual global anthropogenic GHG emissions reached 53 Gt CO₂ eq. in 2023, exhibiting an incremental trend. About half of all human-emitted CO₂ is absorbed by the oceans and land ecosystems, and the rest accumulates in the atmosphere. Even if emissions start declining soon, we are far from reaching carbon neutrality. Meanwhile, atmospheric CO₂ levels have reached 429 ppm [1]. This increase is causing global warming and climate change. Global warming is defined as the rise in the Earth’s average surface temperature relative to the 1850–1900 period, which provides a preindustrial reference. The Earth’s average surface temperature has already increased by around 1.3 °C compared to the preindustrial level [11]. At the Paris Climate Conference in December of 2015, the global community reached an agreement to control GHG emissions and confront the impacts of climate change [12]. The key target is to constrain the temperature increase below 2 °C compared to preindustrial levels and to undertake efforts to maintain it below 1.5 °C.

Table 1. Top ten countries in GHG emissions in 2023, their CAGRs and their targeted net-zero years [13].

Country/Region	Total [Gt]	Share in Global [%]	Per Capita Emissions [t]	CAGR (1990–2023) [%]	Net-Zero Target
China	15.94	30.1	11.3	4.4	2060
United States	5.96	11.3	17.8	−0.1	2050
India	4.13	7.8	2.9	3.4	2070
European Union	3.22	6.1	7.2	−1.2	2050
Russia	2.67	5.0	18.5	−0.4	2060
Brazil	1.30	2.5	6.2	2.0	2050
Indonesia	1.20	2.3	4.3	3.4	2060
Japan	1.04	2.0	8.3	−0.7	2050
Iran	1.0	1.9	11.0	3.4	NA 1
Saudi Arabia	0.81	1.5	24.5	3.8	2060
World	52.96	100	6.6	1.5	2050

CAGR: combined annual growth rate. ¹ Iran is not yet a signatory of the Paris Agreement.

lists the top ten countries with the largest carbon footprints and highlights their GHG emission trends and net-zero targets.

The consequences of global warming have been widely discussed by the Intergovernmental Panel on Climate Change [14,15]. A major consequence is the rise in the sea level caused by the melting of glaciers and ice sheets. This leads to seawater flooding in low-lying coastal areas, causing the loss of land, including entire islands. Coastal ecosystems, such as river deltas, will increasingly suffer from saltwater intrusion, leading to habitat contraction, loss of biodiversity and loss of freshwater resources. Global warming also affects precipitation, as it intensifies the Earth’s water cycle by increasing the atmosphere’s capacity to hold vapor. Thereby, storm-affected areas experience an increase in precipitation and in the risk of flooding, while areas located far away from storm tracks experience less precipitation and increased risks of drought. This intensifies major climate events, such as heatwaves, wildfires and hurricanes. Other severe climate change effects include ocean acidification, erosion, landslides, etc. All these factors mean that climate change will have severe consequences for water and food security and impose new risks for human health and safety [16,17,18]. The effects of climate change vary around the globe, as does the capacity of different countries to adapt to these. Severely affected regions with limited resources will become sources of climate refugees [19]. Hence, urgent and strong actions are needed at the levels of both mitigation, i.e., reducing GHG emissions, and adaptation, i.e., improving resilience to climate change.

This global challenge originates from the fact that modern human civilization has heavily relied on fossil fuels, culminating in the current industrial society, with an energy-intensive GDP. Moreover, the reliance on fossil fuels has become severe in recent decades. For example, the current global fossil fuel consumption is about seven times that of 1950. The global primary energy consumption reached 172 PWh in 2024, with around 80% being covered by fossil fuels [20].

Table 2. Breakdown of global GHG emissions by sector [7].

Sector	Emissions [%]	Cause
Energy Systems	37	Processing of fossil fuels and their use in power and heat generation
Industry	24	Hard-to-abate industries such as steel, cement, chemical, etc. (excluding energy supplied by utilities)
Agriculture	20	Land use change (e.g., deforestation), methane from livestock and crops, etc.
Transport	14	Road transport, rail, aviation and shipping
Building	5	LPG for cooking, space and water heating with gas, etc.

provides a breakdown of the global GHG emissions by sector: 80% of emissions are related to energy consumption, while the other 20% are caused by agriculture. This emphasizes the importance of decarbonizing the energy system to achieve net-zero emissions.

Reducing GHG emissions is a global imperative that demands collaborative action from every nation. However, the strides made by major players such as China, the United States, India and the European Union have disproportionate impacts. The EU, in particular, is performing very well. Its 2020 target called for a 20% reduction in emissions relative to 1990 levels, but the bloc exceeded this goal by far, with a 31% reduction [21,22]. Despite this overall success, it is worth noting that France did not meet its individual target. Looking forward, the EU’s trajectory is promising. Projections indicate that, by 2030, emissions will decrease by 55% compared to 1990 levels—a target that is well within reach given the current trends. Even more ambitiously, the EU aims for a 90% reduction by 2040, laying the groundwork for the legally binding net-zero target set for 2050 under the EU Green Deal.

As highlighted in Table 1, China is currently responsible for 30% of global GHG emissions. Most of China’s emissions originate from its energy system (49%) and industrial sector (35%). While China’s decarbonization is of global relevance, it is also fundamental for the country, as its population and infrastructure are heavily exposed to climate risks. This is especially true for China’s densely populated and economically thriving coastal cities. Furthermore, as a manufacturing powerhouse, China needs to adapt to the ongoing technological transition towards a global low-carbon economy. The country has set the goal of carbon neutrality for 2060. However, it is expected to reach its peak carbon emissions by 2030, before its carbon footprint starts shrinking [23].

The International Energy Agency has proposed a roadmap to reach net-zero emissions globally by 2050 [8]. The strategy calls for power sector decarbonization by massively scaling up PV and wind energy while transitioning to P2F solutions and intensifying electrification. In line with this, electricity would dominate energy consumption by 2050, with close to 90% of power generation coming from renewables. Furthermore, the roadmap proposes ending the sales of new petrol cars by 2035 to shift the focus to electric vehicles (EVs) and hydrogen fuel cell vehicles (HFCVs). At the same time, P2F alternatives should become essential in energy-intensive industries and as fuel sources in aviation and maritime transport. The roadmap also proposes banning new fossil fuel boilers in buildings starting from 2025 to drive up sales of heat pumps.

A net-zero roadmap has been also created by the International Renewable Energy Agency, with renewable energy and energy efficiency being the pillars for decarbonization [24]. In this scenario, renewable energy should supply two-thirds of the global energy demand by 2050. This target can be achieved by accelerating PV and wind power growth, while intensifying electrification and P2F use in industry and transport. More specifically, the share of renewables in power generation would need to increase from around 30% today to around 60% by 2030 and 85% by 2050. A cost–benefit analysis shows favorable results for the renewable energy roadmap, especially when accounting for externalities. Among others, many benefits can be attributed to reduced health impacts from fossil fuels, as has been shown also in other studies, including Markandya et al. [25] and Vandyck et al. [26].

Roadmaps for the transition to renewables have multiplied in recent years, particularly through studies of national and regional scenarios, e.g., for Europe [27,28,29], China [30], India [31], Pakistan [32], Turkey [33], Nepal [34], Canada [35], etc. Generally, such studies assess renewable energy targets in terms of resource availability, technical feasibility, cost effectiveness, contributions to climate goals, etc. This provides support for decision-makers to shape renewable energy objectives and strategies. As an example, Zubi et al. have proposed a power mix for Spain that complements wind energy and PV with dispatchable power plants—specifically, hydropower, concentrating solar thermal power (CSTP) with thermal storage, solid biomass, biogas from waste and energy crops and geothermal energy [36,37]. Such a mix could have a fossil fuel backup to guarantee firm capacity. This can be achieved within the existing renewable energy infrastructure, e.g., in hybrid CSTP plants, dual-fuel gas turbines, Rankine cycle with co-combustion units, etc. Such a power mix would provide the basis for increased electrification and P2F solutions to decarbonize the energy sector and meet the target of net-zero emissions.

The decarbonization of the power sector provides the basis for carbon neutrality, as it can be complemented with electrification and P2F solutions. The feasibility of a low-carbon electricity mix is, to some extent, proven today. There are already many countries with a fossil fuel share of less than 5% in electricity production, including Switzerland, Norway, Sweden, Iceland, Paraguay and Costa Rica. Moreover, some major economies have been able to achieve an electricity mix with a minor fossil fuel dependence, including France with 9.5%, Brazil with 13.6% and Canada with 16.6%. These successes, however, are based on dispatchable power plants—specifically, hydropower, nuclear power, biomass and geothermal energy. Global carbon neutrality, on the other hand, will require a feasible electricity mix based on VRE—most importantly, PV and wind power. This is fundamental in reducing and overcoming resource constraints [38] in an economically sustainable way [39], especially in countries that do not have significant hydropower, biomass or geothermal resources and do not wish to opt for nuclear power. However, the transition to a VRE-based mix will depend on enabling technologies, i.e., on advanced batteries, demand-side management (DSM), sector coupling, prosumer platforms, smart grids, digital technologies, etc., as will be detailed in the next section. While this technological shift is demanding, it also creates valuable opportunities—not only for climate action but also for energy security [40], energy poverty mitigation [41], energy justice [42], environmental justice [43], energy democracy [44], etc.

3. Modern Power System Landscape

A common global development in the electricity sector is the growing demand, which has emerged despite continuous energy efficiency measures. This is especially true for the emerging economies of China [45] and India [46]. Many developing countries have still not reached the UN’s Sustainable Development Goal 7, i.e., ensuring access to affordable, reliable, sustainable and modern energy for all. Overcoming energy poverty, especially in Sub-Saharan Africa and South Asia, is a global challenge that needs to be confronted within the focus on climate action [47,48,49,50]. While economic growth, especially in the Global South, remains a driver of the increase in the electricity demand, technological shifts will also have a major impact in the coming decades. One important aspect in this regard is the growing electrification, especially that of road transport.

The carbon emissions from road transport can be reduced drastically through EV adoption, provided that the power mix has low specific emissions [51]. Policies are being set around the globe to advance EV readiness [52]. The major car manufacturers have adjusted their market projections accordingly. The reduced costs and improved durability of lithium-ion (Li-ion) batteries have improved EV competitiveness at the total cost of ownership (TCO) level [53]. Nevertheless, the electrification of road transport brings major challenges to the power system in terms of energy and power demands. In particular, the need for fast charging points results in supply bottlenecks, and this requires grid upgrades in terms of power generation, transmission and distribution.

A still more demanding challenge for the power system will be the development of the hydrogen economy [54]. Currently, the hydrogen supply infrastructure is in its initial rollout stage, providing relatively small capacities [55]. Nevertheless, these aspects will change in the coming decades, with the global hydrogen market accelerating and its production becoming increasingly linked to renewable energy [56]. Hydrogen production is expected to become the primary electricity-consuming sector in many countries by 2050, despite having a negligible power demand share today. Many countries in the MENA region have set ambitious roadmaps for hydrogen production, usage and export [57,58]. The hydrogen economy will be a major contributor to the global transition to net-zero emissions [59]. Hydrogen has the potential for large-scale implementation across hard-to-abate sectors—most importantly, transport (aviation and maritime) and industry (steel, cement, etc.) [60].

Hydrogen can be obtained from fossil fuels, biomass or water. Accordingly, there are several processes for hydrogen production, including steam methane reforming [61], methane pyrolysis [62], coal gasification [63], biomass gasification [64], biomass pyrolysis [65], biomass fermentation [66], water electrolysis [67], thermochemical water splitting [68], etc. Today, most hydrogen is produced from natural gas via steam methane reforming without carbon capture utilization and storage (CCUS), which is referred to as “gray hydrogen” [69]. When this process is implemented with CCUS, the product is called “blue hydrogen” [70]. Hydrogen production through methane pyrolysis gives “turquoise hydrogen” [71]. This is a high-temperature process that uses a catalyst (metal, metal oxide or carbon) to split methane into hydrogen and solid carbon. While hydrogen originating from fossil fuels plays the key role in the short and medium term, a global, sustainable hydrogen economy needs to rely on water as the hydrogen raw material [72]. The patent landscape of hydrogen production confirms this trend [73]. Using renewables as the power source for water electrolysis results in “green hydrogen” [74], while using nuclear power results in “pink hydrogen” [75]. For more details regarding the hydrogen “colors”, refer to [76,77]. A study on the hydrogen production costs incurred via different routes is available in Farhana et al. [78]. Although the market share of green hydrogen is negligible today, it is expected to ultimately dominate the hydrogen economy, becoming a key component of climate action [79].

Green hydrogen can be compressed or liquified and used directly as a fuel. However, it must also be understood within the P2F context, which includes different fuel paths. For instance, green hydrogen can be combined with captured carbon dioxide to produce synthetic methane, which can be stored, transported and distributed in existing natural gas networks. Hydrogen and captured carbon dioxide can also be combined to produce synthetic kerosene, which is a potential sustainable aviation fuel [80]. Ammonia, a promising maritime fuel, can be produced from hydrogen using the Haber process [81,82].

The development of the hydrogen economy is expected to increase the global electricity demand. However, if we extrapolate recent trends (2.8% average annual growth), the electricity demand can be expected to double by 2050. Covering such demand under net-zero emissions is undoubtedly a major global challenge. Three technology clusters can help to achieve this goal: renewable energy, nuclear power and fossil fuels with CCUS. Thereby, renewable energy will dominate the landscape, and, within this, solar and wind power will be the primary resources at a global scale.

The growing share of PV and wind energy in the electricity mix imposes new challenges for the power system. These are non-dispatchable sources that require forecasting and proactive management. PV and wind generators peak and rest frequently, i.e., they operate with a relatively low annual capacity factor and leave a significant firm capacity gap. For instance, PV causes grid integration challenges related to the duck curve. This aspect has been assessed, among others, by Zubi et al. using an electricity dispatch model [83]. The PV midday peak drastically reduces the operation gap in dispatchable power plants; on the other hand, these must cope alone with the evening demand peak. The duck curve results in significant fuel penalties in dispatchable power plants due to the frequent pausing, prolonged operation at partial loads and higher reliance on peak units. Furthermore, PV curtailment becomes substantial. The effects of VRE on the grid can be partly counterbalanced through the flexibilization of dispatchable power plants [84,85]. However, the share of these sources will drop with the growing PV and wind shares in the power mix; hence, broader measures are needed, including the addition of energy storage capacities, DSM, etc.

As the installation sites for PV and wind generators depend on the resource quality and proximity to consumers, significant changes in the grid topology are taking place, with congestion and curtailment challenges emerging [86]. Accordingly, the role of distributed generation is growing, with the inclusion of new system architectures, including mini-grids and aggregators [87].

While the installed capacity of centralized PV and wind farms will continue to grow, distributed systems are also expected to form a significant component in the transition to a VRE-based power mix. Germany was an early adopter of rooftop PV funding schemes, with the 1000 Roofs Program introduced in 1990 and accomplished in 1992, with just a few MW connected to the grid. Today, the global installed rooftop PV capacity exceeds 300 GW, but this is still a small fraction of the global potential of around 20 TW. Joshi et al. have calculated that 0.2 million km² of rooftops globally can be used to install PV systems [88]. Their study presents the quantification of the rooftop PV potential considering the levelized cost of electricity (LCoE), with a high spatiotemporal resolution. They have concluded that 10 PWh of electricity can be generated annually at costs of between 4 and 10 cUSD/kWh, with an additional 17 PWh for a cost of between 10 and 28 cUSD/kWh. Additionally, it is noted that PV is becoming ubiquitous, as illustrated in Figure 1.

Recent trends show also a growing interest in urban wind turbines, with new concepts emerging, including those of Flower Turbines, IBIS Power, O-Innovations and Aeromine Technologies, as illustrated in Figure 2. For instance, Flower Turbines is commercializing vertical-axis rooftop wind turbines with a height of one to a few meters and a tulip-like shape. Urban wind turbines do not necessarily compete with PV panels for roof space [89]. For instance, a layout that accommodates both is the POWERNest by IBIS Power, where vertical turbines are placed underneath solar panels, allowing for the maximum power generation per m². As the technology matures and incentives are provided, urban wind turbines will become increasingly common in distributed generation, enhancing the technological diversity in prosumer platforms.

A grid typology that has become associated with renewable energy is the microgrid/mini-grid. Modern microgrids date back to the 1990s, when financial support programs for rooftop PV began in Germany, Japan and California, initiating and accelerating the distributed PV market. This trend was later followed in many other countries. Initially, due to their minor role, it was tolerated that such systems fed variable, non-dispatchable power into the grid, independently of the local demand. Nevertheless, it soon became clear that a major transition was taking place, with ever more power consumers becoming prosumers [90]. In the late 1990s, researchers began exploring how to confront this growing prosumer role and plan and manage distributed energy resources in an integrative way that exploits the local energy potential for reliability, resilience and profitability [91]. This led to an architecture that matched demand and generation locally in a subsection of the grid, allowing for energy autonomy [92]. This development eventually led to the grid-connected microgrid of today, which was soon exploited as a key technology for rural electrification in developing countries as well. Microgrids and mini-grids are extensively discussed in the literature, with a focus on technological and technical aspects [93,94], system optimization [95,96,97,98,99], market design [100,101,102,103], etc.

The growing reliance on variable renewable energy, especially PV and wind power, is accompanied by a growing number of batteries in the power system [104]. These can have a variety of roles, including variable renewable energy balancing, peak load shifting, the supply of ancillary services, etc. [105]. A wide range of battery chemistries are being implemented in power systems, including lead–acid, lithium-ion, sodium sulfur, flow batteries, etc. [106], while the research and development of new chemistries is intensifying [107]. Other energy storage technologies, such as fly wheels [108] and supercapacitors [109], are also emerging, particularly within the context of high-power-density applications, such as fast EV charging. While power system batteries will be mostly stationary, by 2035, there will be also a large number of EVs in circulation, with a global battery capacity averaging roughly 5 kWh per capita. Exploiting this huge power storage potential of EVs for the benefit of the power system brings major challenges due to the fragmented capacity and mobility [110]. Several smart EV charging schemes are currently under demonstration: unidirectional smart charging (V1G) [111], vehicle-to-grid (V2G) [112], vehicle-to-home (V2H) [113], etc. These ongoing developments increasingly couple power supply and mobility together, setting new requirements for the electricity grid, while also providing new opportunities in power system optimization.

Currently, Li-ion batteries are being used as stationary units in power systems, while their V2G potential remains untapped. This aspect, however, is likely to change in the future with the growing digitalization. There are different Li-ion battery chemistries depending on the composition of the cathode material [114]. In terms of market share, the most relevant chemistries are lithium–nickel–manganese–cobalt (NMC) and lithium iron phosphate (LFP). LFP, as a cobalt-free chemistry, has been gaining relevance with accelerating market growth. Furthermore, these batteries have outstanding durability, lasting roughly 4000 cycles or more. LFP batteries have high roundtrip efficiency of around 92% and a low self-discharge rate of roughly 5% per month. Other advantages include a sub-second response time and a relatively high power-to-energy ratio. State-of-the-art LFP battery cells have a satisfactory specific energy density of around 200 Wh/kg, while they are adaptable to compact battery pack designs thanks to their inherent safety. All these factors together favor their use in EVs, with all the advantages of economies of scale. Accordingly, LFP battery costs have been falling rapidly, which, together with the long cycle life and low maintenance requirements, makes them very market-competitive [115,116].

If the Li-ion battery market continues to grow at the current pace, without implementing effective collection and recycling schemes, lithium will become a critical material. This has increased the interest in sodium-ion (Na-ion) batteries. Sodium is the sixth most abundant element in the Earth’s crust and can be produced cheaply from seawater [117], which contributes to the promising low-cost potential of Na-ion batteries [118] and indicates benefits in terms of the circular economy and environmental performance [119]. There are several cathode material alternatives for Na-ion batteries, including transition metal oxides, polyanionic compounds and Prussian blue analogs [120,121]. Metal oxide alternatives include compounds based on low-cost abundant materials such as iron and manganese. Hard carbon works well as an anode material for Na-ion batteries and can be pasted onto an aluminum foil that acts as a current collector and anode terminal. This provides another material advantage over Li-ion batteries, which require a graphite anode pasted onto a copper foil. Na-ion battery cells with energy densities of around 160 Wh/kg are the state of the art, while projections of 200 Wh/kg in a few years have been noted. This will place Na-ion batteries in direct competition with LFP, especially if similar durability is achieved [122]. Na-ion batteries are currently finding initial use in EVs, mainly in entry-level cars with a relatively small battery pack (e.g., the Yiwei EV, a brand under China’s JAC backed by the VW Group).

Modern power systems are expected to increasingly exploit demand control to facilitate VRE integration [123,124]. Thereby, significant DSM potential can be unlocked in association with EV charging [125,126,127], power-to-heat applications [128,129,130], water desalination [131,132], etc. DSM can create win–win situations for power producers and consumers. While the management of VRE becomes more cost-effective for the producer, the consumer can profit from dynamic time-of-use tariffs. For instance, the growing use of heat pumps provides an opportunity in this regard. Heat pumps are adapted to low and medium temperature needs—typically under 160 °C—and stand out for their energy efficiency. This is within the temperature requirements in buildings, as well as many industries, such as the food industry. Hence, thermal storage systems can be used to absorb PV and wind power peaks at a favorable electricity tariff.

The growing VRE share in the power mix is also impacting ancillary services [83]. Traditionally, these have been mostly provided by dispatchable power plants. As an example, primary reserves are often covered by spinning turbines that are purposely operated at a partial load to maintain ramp-up potential. With the shrinking market share of traditional dispatchable power plants, the system operator must be open to new market participants, such as battery banks, aggregators, etc. Furthermore, a key development in the power system is the growing digitalization, which will shape the smart grid of the future. Digitalization is based on several pillars: advanced metering infrastructure (AMI) [133], Internet of Things (IoT) [134], artificial intelligence (AI) [135,136] and blockchain [137,138,139,140,141]. These developments will also allow the refinement of the time and space granularities of the electricity market. Refining the space granularity implies dividing the common market into several bidding zones or nodes. This does not limit electricity trade but accounts for transmission losses through a price differential that prioritizes local and nearby producers, reducing supply–demand distances, minimizing grid losses and avoiding congestion. On the other hand, the time granularity is refined by later gate closure, faster scheduling and shorter dispatch intervals. Such a close-to-real-time electricity trading will allow for more accurate VRE forecasting. PV and wind farms can then be operated under ahead-planned feed-in commitments with relatively tight margins.

The main insight from this section is that the global electricity demand will at least double between today and 2050 due to economic growth, increasing electrification and the transition to the hydrogen economy. Such demand must be met under climate action—more specifically, a net-zero strategy—and will require a shift to a VRE-intensive power mix. This development aligns with the diversity of technologies and measures that have been briefly highlighted: battery storage, DSM, distributed generation, prosumer platforms, mini-grids, aggregators, smart grids, digitalization, modern ancillary services, etc. While these developments underline a general global trend, each country represents its own specific case and technological priorities within this diversity. The next section details the specific case of the UAE.

4. The UAE’s Net-Zero Perspectives

The electricity demand of the UAE has been growing at an annual average of 3.5% during the last decade. This trend is likely to continue in the coming years; hence, the annual demand will increase from 155 TWh in 2025 to around 184 TWh in 2030. The growing electrification and green hydrogen production will cause acceleration between 2030 and 2050. The electricity demand is expected to grow at an annual average of 4.5% within this period, reaching 285 TWh in 2040 and 444 TWh in 2050. This trend is highlighted in Figure 3. The chart also illustrates a breakdown of the expected power mix.

PV will reach a share of 25% (46 TWh) in annual power generation in 2030, while, in 2050, it will dominate the mix, with a share of 50% (222 TWh). Within this period, natural gas combined-cycle (NGCC) power plants will grow in terms of annual power output, from 79 TWh in 2030 to 138 TWh in 2050, yet their market share will drop from 43% to 31% in the same period due to the accelerating demand. A qualitative change in NGCC plants will be the inclusion of CCUS solutions over the years. As shown in Figure 3, it is assumed that the UAE will not build new nuclear reactors; hence, the annual nuclear power generation will remain at around 44 TWh. This will result in a shrinking market share, from 24% in 2030 to 16% in 2040 and just 10% in 2050. As is clear here, the UAE’s power system decarbonization strategy relies on three components: PV, natural gas with CCUS and nuclear power, with PV clearly dominating in the long term. One can also expect a small market share for other renewables, at roughly 3–4%, predominantly consisting of CSTP and wind farms. Although CSTP has the advantage of being dispatchable, its limited cost potential means that it cannot compete with PV due to its much lower learning rate, while its water footprint is significantly larger, and its performance drops notably in dusty environments.

The growing role of PV in the UAE will bring a major energy cost advantage. As highlighted in Figure 4, the average LCoE will decrease notably from 6.6 cUSD/kWh today to 4.8 cUSD/kWh in 2050. The average LCoE is calculated from the LCoE of the single technologies with consideration of their market shares.

As highlighted in Figure 5, the UAE’s power mix development will enable a reduction in the specific carbon footprint from 280 gCO₂/kWh today to 100 gCO₂/kWh by 2050, considering lifecycle emissions. This, however, will not result in a reduction in the power sector’s footprint due to the multiplying demand. Accordingly, the lifecycle emissions will remain around 45 Mt between today and mid-century. It is important to highlight that, while most of the power sector emissions today are direct, originating from NGCC power plants, most of the lifecycle emissions in 2050 will be indirect, originating from the manufacture of PV panels, batteries, etc. These emissions are the responsibility of the manufacturing country, yet, independently of this, carbon costs are generated and are eventually passed to the consumer. Therefore, in this paper, all emissions are calculated on a lifecycle basis and penalized at 60 USD/t CO₂. This will allow us to enhance cleantech’s competitiveness while also securing a budget for the purchase of carbon credits to achieve a net-zero power mix. Such a power mix is the necessary basis for electrification and P2F solutions, allowing the decarbonization of transportation and industry as well.

As highlighted in Figure 3—and noted by other authors, e.g., Eveloy et al. [10]—PV will form the backbone of the UAE’s future power system.

Table 3. Major PV farms in the UAE.

Solar Farm (Location)	Owners	Capacity [MW]	Area [km2]	Panels/Structure	Completion	PPA [cUSD/kWh]
Mohammed bin Rashid Al Maktoum Solar Park (Saih Al-Dahal)	DEWA	3960 1	77	Crystalline Si and CdTe Single-axis tracking	2030	1.7 (Phase 5) 1.63 (Phase 6)
Al Dhafra Solar Project	TAQA Masdar EDF Renewables Jinko Power	2000	22	Bifacial crystalline Si Single-axis tracking	2023	1.34 2
Al Ajban PV Solar Farm	EWEC EDF Renewables KOWEPO	1500	20	Bifacial crystalline Si Single-axis tracking	2026	1.42
Al Khazna Solar Project	EWEC EDF Renewables KOWEPO	1500	20	Crystalline Si Single-axis tracking	2027	1.46
Noor Abu Dhabi Solar Power Plant (Sweihan)	TAQA Marubeni Jinko Solar	1177	8	Crystalline Si Fixed structure	2019	2.42

¹ This project includes an additional 700 MW capacity for CSTP. ² As of 2025, Al Dhafra project holds the world record for the lowest PPA.

lists major solar farm projects in the UAE, emphasizing the fast development of this sector. The UAE has very high solar irradiation and large amounts of available land for PV farms [142]. This is accompanied by strong institutional support and well-developed infrastructure [143], as well as a competitive market and financing environment [144]. Table 3 lists projects with a total installed capacity of 11 GW, while there are also projected PV farms with 7 GW from Masdar, TAQA, Helion, Engie and Brooge, which will be dedicated to the production of green hydrogen and ammonia. Rooftop PV systems are also gaining importance—most notably within Shams Dubai and the Abu Dhabi Solar Rooftop Program [145]. The installed PV capacity is predicted to reach 23 GW in 2030, contributing with a share of 25% in annual power generation.

As can be observed from Table 3, the power purchase agreements (PPAs) exhibit record-low values for large PV farms in the UAE. For instance, the Al Dhafra project dispatches all its electricity to the grid at a price of just 1.34 cUSD/kWh. Equation (1) can be used to calculate the LCoE of a PV system without considering battery storage. In the UAE, such costs can be expected to remain in the 1–2 cUSD/kWh range for large installations, which results from system costs of roughly 400 USD/kW. This includes PV panel pricing in the 100–150 USD/kW range and inverter pricing at around 50 USD/kW. Most PV farms in Table 3 use single-axis tracking. While single-axis trackers are more costly than a fixed structure, such farms reach a notably higher capacity factor under the UAE’s solar conditions, i.e., close to 25%, as compared to just 19% with a fixed structure. Large PV projects in the UAE are securing financing at interest rates in the 4–6% range, while the power plant lifetime is 25 to 35 years.

Equation (1): PV levelized cost of electricity

$$C=100 \left({\displaystyle \frac{k}{t}}{\displaystyle \frac{i}{1-{\left(1+i\right)}^{-n}}}+{\displaystyle \frac{m}{t}}\right)$$

(1)

C [cUSD/kWh]: LCoE;

k [USD/kW]: Specific capital requirement to be written off by start of operation;

t [h/yr]: Capacity factor;

i [0]: Interest rate;

n [yr]: Power plant lifetime;

m [USD/yr]: Annual O&M costs.

Adding battery storage is required to render PV semi-dispatchable, which is especially needed in a PV-intensive mix, as will eventually be the case in the UAE. Li-ion batteries with LFP chemistry are good candidates for this purpose, while Na-ion batteries are also expected to emerge as a competitive alternative with improved circular economy adherence and potentially a cost advantage [146,147]. As an example, EWEC anticipates the addition of battery storage to the Al Ajban project. After completing the installation of 1.5 GW PV capacity in 2026, EWEC will commence with the inclusion of batteries, with the first banks to be connected by 2028.

The power storage cost depends on the battery cost and its cycle life, together with other factors, as detailed in Equation (2).

Table 4. Energy storage cost in cUSD/kWh for Li-ion battery under different battery cost and cycle life assumptions.

	Battery Cost [USD/kWh]
Cycle Life	200	150	100
2000	15.4	11.6	7.8
3000	11.6	8.8	5.9
4000	9.8	7.4	5.0
5000	8.7	6.6	4.4
	Hardly competitive (today)	Fairly competitive (short term)	Widely competitive (long term)

Assumptions: Average battery usage of one cycle per day, maximum depth of discharge of 90%, annual O&M costs equivalent to 3% of battery cost, PV power cost of 1.5 cUSD/kWh (representative for UAE solar farms), roundtrip efficiency of 88% (power conversion included) and interest rate of 6%.

provides a summary of these costs with assumptions that match Li-ion batteries. The large-scale implementation of battery banks in PV farms is expected to accelerate once the storage costs decrease to around 10 cUSD/kWh, which is likely by 2030. In the longer term, battery storage costs of around 5 cUSD/kWh can be expected, as the manufacturing costs continue declining and the cycle life improves.

Equation (2): Battery storage cost

$$C={\displaystyle \frac{k}{3.65fd}}\left({\displaystyle \frac{i}{1-{\left(1+i\right)}^{-\frac{l}{365f}}}}+m\right)+e{\displaystyle \frac{1-r}{r}}$$

(2)

C [cUSD/kWh]: Cost of energy storage;

k [USD/kWh]: Battery-specific cost;

f [c/d]: Use frequency in full cycles per day;

d [0]: Permitted depth of discharge as per datasheet;

l [c]: Battery cycle life;

i [0]: Interest rate;

m [0]: Annual O&M cost expressed as ratio of battery-specific cost;

e [cUSD/kWh]: Cost of electricity;

r [0]: Battery roundtrip efficiency.

Ensuring that PV is semi-dispatchable in the UAE requires that roughly 40% of the electricity generated during the day can be shifted to the nighttime hours. As illustrated in Figure 6, the cost of semi-dispatchable PV in the UAE will be 6 cUSD/kWh in the short term and will decline to 3.5 cUSD/kWh in the long run. In 2030, the cost breakdown will be as follows: around 1.6 cUSD/kWh for the PV generator output, 4 cUSD/kWh for the battery storage (considering 40% power shift) and 0.4 cUSD/kWh carbon penalties (with 70 g CO₂/kWh specific lifecycle emissions, at 60 USD/t CO₂ tariff).

The production of hydrogen at scale in association with PV farms is foreseeable in the UAE, with several projects announced by major stakeholders, including Masdar, TAQA, Helion, Engie and Brooge. This is forming a trend in the energy system, where green hydrogen is produced from solar power. Figure 7 shows, for instance, how liquid green hydrogen can be produced as aviation fuel in a grid-connected mini-grid typology. PV farms with battery storage can be built as solar mini-grids and additionally have the backup of the main grid. This system can then provide the needed electricity onsite for water electrolysis and hydrogen liquefaction. The hydrogen is then stored in cryogenic tanks and transported to the airport for use as aviation fuel. An advantage of solar mini-grids, especially in the case of the UAE, is the relatively flexible selection of locations. It is possible to place such plants in the vicinity of aviation hubs and thus minimize the costs related to power transmission and hydrogen transportation. Further information about hydrogen as an aviation fuel can be found in references [148,149,150,151].

Grid-connected solar mini-grids for green hydrogen production can be optimized to achieve a high degree of autonomy from the main grid. This is especially true for the UAE, where the irradiation values are high and the seasonal differences in PV output are minor. Hence, a PV farm in which the annual net power production equals the annual demand would guarantee minimal reliance on the main grid. Thereby, the sizing of the battery bank should extend operation to the nighttime hours while providing sufficient maintenance time. For instance, a realistic annual capacity factor of 78% for a green hydrogen production plant would require a battery bank with 8 h of autonomy at nominal power. Considering Dubai as a reference location, such a mini-grid would be able to rely on direct solar power generation at a proportion of 94% in the annual balance. The other 6% would be imported from the main grid during the winter and exported back during the summer. This guarantees a very high solar fraction in green hydrogen production: 94% without further consideration and 100% should the exchange with the main grid count as net metering. Further information about mini-grid operation is available in Shahgholian [152]. An overview of the mini-grid optimization techniques can be found in references [153,154,155].

As highlighted in Figure 3, natural gas power plants will remain the backbone of the UAE’s power system in the short and medium term. The largest power station is the Jebel Ali Power and Desalination Plant in Dubai. This complex is owned and operated by DEWA and currently possesses 8.6 GW of power generation capacity. With the focus in desalination shifting to reverse osmosis (RO), power generation at Jebel Ali will be achieved mainly with NGCC. Assuming 6000 operation hours annually, the power generation would amount to 51.6 TWh, i.e., 28% of the national electricity demand, in 2030. DEWA also operates the Hassyan Power Plant, a 2.4 GW complex consisting of four state-of-the-art steam cycle units for power generation and an RO desalination plant. It was originally intended as a coal power plant but was then converted to natural gas and constructed as carbon-capture-ready.

The LCoE of NGCC in the UAE is typically around 4.3 cUSD/kWh today. This considers an initial investment of 600 USD/kW, 2 years of power plant construction time, a 20-year lifetime, a 65% capacity factor, a 1.7 cUSD/kWh fuel cost, 58% average efficiency, 25 USD/kW O&M costs and a 5% interest rate. With 420 g CO₂/kWh specific emissions and 60 USD/t carbon penalties, an additional cost of 2.5 cUSD/kWh results, bringing the LCoE to 6.8 cUSD/kWh. Future NGCC power plants will include CCUS, which will be competitive against carbon penalties of 60 USD/t. Carbon capture and storage costs are between 15 and 130 USD/t at major emissions sites, while afforestation is within the range of 50–250 USD/t [156,157,158]. In the long term, the production of synthetic fuels, building materials and chemicals using captured CO₂ will create lower-cost alternatives for power plants [159,160,161]. Considering these factors, the average LCoE of NGCC with CCUS will remain at around 5.4 cUSD/kWh in the coming decades.

Regarding nuclear power, the UAE has built four nuclear reactors at the Barakah plant in the Al Dhafra region, which together provide nominal power of 5.6 GW and generate 44 TWh annually. This covers around 30% of the electricity demand today but will satisfy only 10% of the demand in 2050. Barakah is owned by the Emirates Nuclear Energy Corporation (ENEC) and operated by the Nawah Energy Company, a subsidiary of ENEC and the Korea Electric Power Corporation (KEPCO). The LCoE of Barakah is 6 cUSD/kWh. This considers 4.5 billion USD/GW in construction costs, an average of 8 years of reactor construction time, 8000 operation hours annually, a 35-year lifetime, a 5% interest rate, 120 USD/kW in fixed O&M costs and 0.1 cUSD/kWh in variable O&M costs.

While nuclear power diversifies the power generation technologies in the UAE, it has a relatively high LCoE, especially when compared with PV. At this stage, it is still unclear whether nuclear energy will play the role of a bridging technology, serving the net-zero by 2050 goal, or will remain as a pillar in the UAE’s electricity supply beyond the lifetimes of existing reactors. Whether additional nuclear reactors are built in the future is still to be seen. This paper assumes that no new nuclear reactors will be placed on-grid before 2050.

As indicated in Figure 3, the electricity demand in the UAE will reach 444 TWh in 2050. The breakdown of electricity consumption is expected to be as follows: 42% for green hydrogen production; 14% for EVs; 12% for the aluminum industry; 8% for water desalination, transportation and distribution; and 24% for all other applications. Green hydrogen is produced via water electrolysis and compressed or liquified for direct use in transport and industry. It also can be converted into green ammonia for local use and export. Green ammonia is considered a promising alternative maritime fuel to replace heavy fuel oil. So far, ammonia has been shipped in liquid petroleum gas (LPG) tankers as a chemical commodity, mostly for fertilizer production. Hence, it benefits from well-developed storage and transportation infrastructure and a worldwide terminal network. Nevertheless, some engineering challenges are still to be overcome, including ammonia toxicity and NO_x emissions, before it is used as a maritime fuel.

Road transport in the UAE currently accounts for roughly 40 Mt of CO₂ emissions annually. The electrification of road transport will reduce its carbon footprint drastically. Compared to HFCV, EVs have better energy efficiency, smaller carbon footprints, lower TCO, etc., and hence are expected to eventually dominate the market. With the current specific power sector emissions of 280 gCO₂/kWh, an average EV in the UAE causes the emission of 55 gCO₂/km, as compared to an internal combustion engine vehicle (ICEV), with an average of 190 gCO₂/km. In 2050, the lifecycle emissions of an EV will be roughly 10 times smaller than those of an equivalent ICEV. We expect the electricity consumption in road transport to be around 60 TWh in 2050.

Currently, the largest electricity consumer in the UAE is Emirates Global Aluminum (EGA) with an annual demand of around 44 TWh, i.e., around 30% of the total power generation. Today, the UAE ranks fifth globally in aluminum production, with an output of 2.7 Mt, and exports to over 70 countries worldwide. EGA has secured raw material supplies from its subsidiary, the Guinea Alumina Corporation. In the production process, bauxite (aluminum hydroxide-rich ore) is processed to alumina (Al₂O₃) using the Bayer process and then to aluminum using the Hall–Heroult process. The latter is an energy-intensive electrolytic reduction process in which alumina reacts with carbon to produce aluminum and carbon dioxide. This process generates direct emissions of around 1.2 t CO₂ per ton of aluminum. The electricity demand for the production of aluminum is around 17 MWh/t. Hence, the carbon footprint of aluminum production depends mostly on the source of electricity. It can range from under 3 t CO₂ per ton aluminum for a low-carbon power supply to over 15 t for electricity originating from a coal power plant [162]. EGA projects that it will be placed at the lower end of this range by purchasing clean energy certificates from solar farms.

The UAE has an iron and steel industry with current annual production of 3.2 Mt. In iron production, iron ores—mainly hematite (Fe₂O₃) and magnetite (Fe₃O₄)—are reacted with coal to produce iron and emit CO₂. Moreover, natural gas can be used in this process to produce iron, carbon dioxide and water. The coal-based process emits 1.9 t CO₂ per produced ton of iron, while, with natural gas, the emissions are 1.2 t CO₂. Emirates Steel purchases iron ores mainly from Bahrain, Oman and Sweden and produces iron using natural gas. Green hydrogen can replace natural gas in this process to eliminate the direct emissions from iron and steel manufacturing in the UAE [163]. The current iron production costs are around 450 USD/t. Replacing methane with hydrogen, assuming a hydrogen cost of 3 USD/kg, would increase the production cost to 520 USD/t. A carbon penalty of 60 USD/t CO₂ would place green hydrogen and natural gas at cost parity. To maintain the current annual production of 3.2 Mt while switching to hydrogen, the UAE would need to produce 0.16 Mt of green hydrogen for this industry.

The water supply in the UAE relies heavily on seawater desalination [164]. There is also a significant dependence on groundwater, including saline aquafers. While the country has long relied on thermal desalination, used in combination with thermal power plants, today, the focus has clearly shifted to RO [165]. The UAE’s annual freshwater consumption is currently around 9 billion m³. The electricity consumption for water supply (desalination, transportation, distribution, etc.) is around 25 TWh. The demand for fresh water in the UAE will increase substantially in the coming decades, but this will be accompanied by improved water utilization and energy efficiency. Hence, the electricity consumption in the water sector is expected to grow to around 36 TWh in 2050. The shift from thermal desalination to RO, together with the decarbonization of the power mix, will drastically reduce the carbon footprint of the water sector in the UAE.

Based on the overview provided in this section, it can be concluded that the UAE’s potential to reach its net-zero target by 2050 is strong. The country is on a promising path in decarbonizing its power sector and transitioning to a hydrogen economy, while reducing the dependence on fossil fuels in favor of electrification and P2F alternatives. This allows for carbon abatement to be applied in all major GHG-emitting sectors: power generation, road transport, aviation, maritime transport, hard-to-abate industries (aluminum, steel, etc.), seawater desalination, etc.

Much of the electricity generated in the UAE in 2050 will be used for green hydrogen production. This will amount to hydrogen production from natural gas—mostly blue and potentially turquoise hydrogen. We estimate that 3.5 Mt of green hydrogen will be produced in 2050, demanding around 185 TWh of electricity, i.e., 42% of the total power generation. Most of this hydrogen will be used in aviation, shipping and energy-intensive industries.

5. Conclusions

The current level of global GHG emissions is alarming and is accelerating global warming and climate change. It is important to take urgent climate action, with a strong focus on decarbonizing energy consumption. A feasible strategy in this regard is to decarbonize the power sector while intensifying electrification and transitioning to P2F alternatives. Three technology clusters have a role in reducing the carbon footprint in electricity generation: renewable energy, nuclear power and fossil fuels with CCUS. Thereby, renewables are expected to play the primary role at the global level. Solar and wind energy are the most abundant resources. Due to their variability, their exploitation at a large scale necessitates other key technologies, including advanced batteries, smart grids, digital technologies, DSM, etc. The possibility to exploit solar and wind energy in distributed systems as well provides an opportunity for new topologies, such as micro- and mini-grids, virtual power plants, etc.

The decarbonization of the power sector provides the basis for electrification, with the major environmental and sustainability benefits that accompany it. Thereby, the transition from ICEVs to EVs is highly relevant. An EV charged from renewable energy has zero direct emissions and a small fraction of the lifecycle emissions of an ICEV. Banning fossil fuel boilers in favor of heat pumps is another key measure to leverage electrification within the context of climate action. Among others, industrial heat pumps can be widely used in food processing. Water desalination with RO consumes much less energy than thermal desalination and has a much smaller carbon footprint, especially with a low-carbon power supply.

While electrification is an effective solution for road transport, low-temperature heat, etc., it has its limitations in covering the energy demand in other key sectors, such as aviation, shipping and hard-to-abate industries, including steel and cement. P2F alternatives can provide effective solutions in this regard. For instance, liquid green hydrogen could become the primary aviation fuel in the future, green ammonia could play a major role as a maritime fuel, and green hydrogen could replace coal and natural gas in the iron and steel industry.

The MENA countries still rely heavily on fossil fuels in their energy supplies, and several economies depend on oil and gas exports. This region has vast solar energy resources and a record-low LCoE from PV farms. This provides a unique opportunity for power sector decarbonization, which can be accompanied by electrification and P2F solutions. The MENA region has strong potential to develop into a global solar energy and green hydrogen hub, allowing it to take climate action while reducing the cost of energy and enhancing energy security.

The UAE can play an important role in this transition and has already set its net-zero target for 2050. Thereby, the UAE’s power system will evolve to form the backbone of its energy sector. The country will rely mostly on three technologies in the decarbonization of its power sector: PV, natural gas with CCUS and nuclear power. PV can be expected to dominate the power mix in the long term, with a share of 50% by 2050. Thereby, the electricity demand will almost triple in comparison with today. This development represents the cornerstone of a broader energy sector transition that includes intensifying electrification and technological migration towards P2F solutions. Much of the generated power will be used for green hydrogen production (42%), followed by road transport (14%), the aluminum industry (12%) and the water supply (8%). Thereby, grid-connected solar mini-grids could emerge as a common layout in which electricity is generated locally for water electrolysis and hydrogen compression/liquefaction, as well as the production of other P2F alternatives, such as green ammonia. This will allow P2F hubs to be built, which can be located close to demand points. The growing PV share in the power mix will help the UAE to reduce its average LCoE in power generation substantially while meeting its climate goals.

A key conclusion from this work is that the UAE’s net-zero by 2050 goal is realistic and it is on a promising path, especially considering the achievements throughout the last decade and the projections already within reach. Nevertheless, much will eventually depend on the long-term upscaling of the installed PV capacity and associated battery storage, the transformation of natural gas power plants to include CCUS, the electrification of road transport and other energy-intensive sectors and massive investments in water electrolysis and other P2F alternatives, as well as hydrogen compression and liquefaction. To put this into perspective, the UAE’s PV sector will have to reach annual generation of 222 TWh by 2050, which requires an installed capacity of around 115 GW and demands around 1.4% of the UAE’s national territory for solar farms. Nonetheless, land use can be notably reduced if PV is exploited within the context of ubiquitous technology, as illustrated in Figure 1. When it comes to power storage, an installed battery capacity of around 270 GWh will be needed to render PV semi-dispatchable and facilitate its integration into the power system. Furthermore, electrolysis for annual hydrogen production of 3.5 Mt must be put in place, together with the needed compression and liquefaction units.

Sensitive policies and practices are required to materialize the transition to net-zero in the UAE and, more generally, in the MENA region. The energy sector should be bound to carbon accounting and trade to enhance the competition around carbon abatement and the circular economy. The scaling up of PV farms requires land use and supportive infrastructure, as well as attracting investors with simplified regulatory procedures and guaranteed power purchase. Resource studies to identify the best solar farm locations, together with environmental impact assessments, should provide a basis for land licensing. Furthermore, it is fundamental to create a framework for the collection and recycling of consumed PV panels and batteries that engages stakeholders and ensures circularity. The roll-out of green hydrogen production requires securing the supply of electrolyzers at scale. Accelerating the electrification of road transport is dependent on improving EV readiness by enhancing the power distribution network and building up the public charging infrastructure. The EV market’s development can be supported with incentives that favor e-mobility at the TCO level. The electrification of the heat demand could be supported with regulatory measures such as banning new fossil fuel boilers in buildings and key industries. The measures suggested here should be evolutionary and adapted to the market dynamics.