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Abu Dhabi has so far favoured large, centralised solar parks. By 2020, rooftop solar on government buildings had reached 2.94 megawatts, less than one per cent of the 1,177 megawatts installed at the Noor Abu Dhabi plant alone, according to Ramachandran, Mourad and Hamed (2022) and Alhammami and An (2021). Worldwide, the picture is different: the International Energy Agency’s solar PV tracking shows an installed base split roughly 50:50 between centralised and decentralised systems (Figure 1).
Solar energy is the heat and electricity produced by capturing and converting sunlight. The electricity-producing systems this paper covers use two methods, photovoltaics and concentrated solar power, as the United States Office of Energy Efficiency and Renewable Energy explains. Installed capacity is divided between centralised systems, also called utility scale, and decentralised systems, also called distributed generation.
Centralised solar plants are large installations that generate electricity in bulk, displacing carbon-intensive fossil fuel plants. They benefit from economies of scale, which lowers their cost and makes solar competitive with conventional generation. Decentralised systems put panels at distributed locations, usually close to the final consumer. Generating on site reduces the need for grid power, which may come from fossil fuels or other low-carbon sources such as nuclear, and which loses energy in transmission along the way.
Table 1: How centralised and decentralised solar differ
Figure 1: Historical uptake of global solar energy capacity in gigawatts by type of generation system, with the 2030 target for net zero.
That contrast prompted the questions this paper sets out to answer. Why is there, in the words of Hamdi (2024), “a preference for large-scale projects” over distributed generation? Why does Dubai’s rooftop scheme appear more successful than Abu Dhabi’s? Is decentralised solar still uneconomic given low electricity tariffs, as Griffiths and Mills (2016) once found? Is centralised solar so cheap that decentralised solar is not worthwhile, the question Thapar (2022) asked for India? Is the net metering policy unattractive or useless? And are there technical, behavioural or societal issues holding distributed solar back, of the kind Seetharaman and colleagues (2019) describe?
The International Energy Agency’s Renewables 2023 report forecasts that solar capacity additions between 2023 and 2028 will be about three times the additions of 2017 to 2022. Centralised additions rise from 502 to 1,525 gigawatts and decentralised additions from 366 to 1,140 gigawatts, as Figure 2 shows.
Figure 2: Forecast for global solar energy installed capacity additions in gigawatts, by period and type of system.
The UAE aims for net zero in its energy and water sectors by 2050, a commitment set out in the UAE Energy Strategy 2050. The resource is there: global horizontal irradiance, the standard measure of solar radiation, is about 6.045 kilowatt-hours per square metre per day according to the Global Solar Atlas.
That net zero commitment underpins the measures the government is taking to spread decentralised renewable generation, such as rooftop panels and solar water heating. The Ministry of Climate Change and Environment lists solar as a priority in its National Climate Change Plan, among the plan’s long-term actions for 2030 to 2050.
The International Energy Agency’s Electricity 2024 report expects the carbon intensity of UAE electricity to fall below 400 grams of carbon dioxide per kilowatt-hour by 2026. The government’s own target is 270 grams by 2030. In 2023 the national strategy gained an interim goal of 30 per cent renewables in the energy mix by 2031, according to the UAE Embassy in Washington, on the way to the original aim of 44 per cent by 2050 (Figure 3). Enerdata puts the renewable share of electricity production at 5.3 per cent in 2023.
Figure 3: UAE share of renewable energy in total electricity production, with the UAE Energy Strategy goals for 2031 and 2050.
Abu Dhabi has targets of its own. The Emirates Water and Electricity Company aims to raise the emirate’s solar capacity to 7 gigawatts by 2030. The Noor Abu Dhabi plant at Sweihan began commercial operation in April 2019: 8 square kilometres, 3.2 million panels and about 1 gigawatt of alternating-current output. Across the border, Dubai’s Mohammed bin Rashid Al Maktoum Solar Park is the largest single-site solar park in the world, built on the independent power producer model with a planned 5,000 megawatts by 2030.
Very cheap by any historical standard. The levelised cost of energy, the average net present cost of a generating system’s electricity over its lifetime, is the metric researchers and the industry use to compare projects (Alhammami and An, 2021). Figure 4 shows the levelised cost in US cents per kilowatt-hour for some of the main centralised projects in the Gulf Cooperation Council, compiled by Alashqar and colleagues (2022). Each successive project has come in cheaper, from 5.61 cents at the second phase of the Mohammed bin Rashid park to 1.32 cents at Al Dhafra.
Figure 4: Levelised cost of energy in US cents per kilowatt-hour for centralised solar projects in the Gulf Cooperation Council region.
Policy studies point the same way for the small end of the market. Alsalman, Ahmed, Bahroun and Saboor (2023) find that a unified renewable energy policy across all of the UAE’s electricity authorities, combining a feed-in tariff with net metering, could substantially lift the uptake of decentralised solar. Ueckerdt and colleagues (2013) add that incentives for rooftop installations on homes and commercial buildings would contribute to the energy mix while letting communities and individuals take part in the transition.
On a levelised cost basis, decentralised solar can be four times as expensive as centralised solar. But that comparison measures the cost at the point of production, not the landed cost of electricity delivered to the customer, which is what customers and policy makers actually pay for. You and Hargreaves (2024) set out why a single production metric cannot settle energy policy choices.
Levelised costs for centralised solar generally leave out grid transportation, balancing, intermittency, losses and peak-power costs, as Kabeyi and Olanrewaju (2023) show. To improve comparability, Ueckerdt, Hirth, Luderer and Edenhofer (2013) proposed a system-wide metric, the levelised full system cost of electricity. Idel (2022) applied it to Germany and found that the full system cost of centralised solar, at 1,548 dollars per megawatt-hour, is 43 times its levelised cost of 36 dollars. On that basis the true landed cost of solar may be higher for centralised systems than for decentralised ones, the conclusion Thapar (2022) reached for India.
Distributed systems generate where the electricity is used. That reduces the need for grid power, which may have been produced from fossil fuels or from other low-carbon sources such as nuclear, and it avoids the transmission and distribution costs and losses that a remote solar park incurs on the way to the customer.
The two system types face different physical limits. Rooftop systems are constrained by roof size and shading, which cap their output. Centralised plants need large land areas and face longer construction timelines and grid integration issues. Both are intermittent, and both have a place in decarbonisation, so the paper compares them on a common footing using the widely accepted levelised cost method described by Alhammami and An (2021):
Here t is the year of operation, from 1 to n, the operating life in years. Initial capex is the upfront cost of building the plant, including construction and assembly. Grid connection costs are the distance-based costs of spur lines over land and construction-period transit costs. Operation and maintenance covers the annual cost of running and maintaining the equipment. The weighted average cost of capital is the financing rate for the assets over their life, following the economic evaluation manual of Short, Packey and Holt. The capacity factor is the ratio of actual annual output to output at rated capacity for a full year; the paper adopts 32 per cent, the figure TAQA uses in its own base case. The number 8,760 is the hours in a year.
The National Renewable Energy Laboratory’s 2024 Annual Technology Baseline calculates the levelised cost in dollars per kilowatt-hour year by year over the project life using equation (2):
Table 2: Terms in the National Renewable Energy Laboratory equation.
MCC follows that approach with a simplified form, equation (3), which allows the two system types to be compared year by year across the forecast period, with the capital recovery factor from equation (4):
Alongside the levelised cost, the paper calculates the net present value of each plant’s cashflows, equation (5), to measure the net benefit of the investment, with the net cashflow in each period defined in equation (6):
Abu Dhabi subsidises electricity indirectly. The government pays the energy companies, which lets them hold the customer tariff well below the economic cost, meaning the full cost of generating, transmitting and distributing each unit. MCC used the Department of Energy’s RC2 price control final decision and TAQA’s 2023 financial statements to estimate what that subsidy does to sector costs and to each customer group.
With the subsidy in view, the paper then tests whether each customer group would find it worthwhile to install its own solar, assuming the customer pays the set-up cost. The test uses two standard financial measures, the internal rate of return and the payback period, treating the initial investment and operation and maintenance as outgo and the avoided electricity cost as income. The internal rate of return r is the discount rate at which the net present value is zero, following Focacci (2009), and the payback period y, after Kessler (2017), is the number of years until the avoided electricity cost equals the money spent:
Solar cells come in three main types, monocrystalline, multicrystalline and thin film, in decreasing order of efficiency and cost (Raman and colleagues, 2012). The system specifications used in the calculations, in Table 1, follow the National Renewable Energy Laboratory’s Q1 2023 cost benchmarks.
Table 3: Specifications for the systems considered in the centralised and decentralised energy plants.
The Abu Dhabi Distribution Company charges different base tariffs to different customer groups. The paper uses the 2024 tariffs in Table 2 to estimate each group’s savings, payback and return from a distributed solar system.
Table 4: Abu Dhabi Distribution Company 2024 customer tariffs in dirhams per kilowatt-hour.
TAQA’s 2023 annual accounts consolidate its subsidiaries, including the Abu Dhabi Distribution Company, Al Ain Distribution Company and the Abu Dhabi Transmission and Despatch Company. From the notes to the accounts, MCC estimates that power, meaning generation plus transmission and distribution, is 65 per cent of total power and water revenue, with the remaining 35 per cent from water and allied services.
TAQA also reports ‘other operating revenue’, the difference between the maximum allowed revenue set in the RC2 final decision and the revenue actually collected from customers. The paper treats that amount as the total subsidy borne by the Abu Dhabi government, takes 65 per cent of it as the power share, and splits that 0.75 to 0.25 between generation and transmission and distribution.
TAQA’s report states that its generation of 58,731 gigawatt-hours (58.7 terawatt-hours) meets 71 per cent of Abu Dhabi’s electricity requirement, which implies a total requirement of 82.7 terawatt-hours. That matches the Department of Energy’s RC2 assumption for Transco of 82,628 gigawatt-hours for 2023. Dividing the generation revenue and the transmission and distribution revenue by those volumes gives the implied economic cost of electricity to the government, 36 to 41 fils per kilowatt-hour.
Capital and operating costs for building and running each type of plant are set out in Table 3. Rooftop and ground-mounted capital costs come from Falcon Energy, an installer in the UAE. For the centralised plant, the paper takes the published levelised cost of 1.6215 US cents per kilowatt-hour for the sixth phase of the Mohammed bin Rashid Al Maktoum Solar Park and derives an indicative capital cost of 1,221 dirhams per kilowatt. The split of capital and operating cost into sub-costs follows the National Renewable Energy Laboratory’s cost breakdown for utility-scale solar.
Table 5: Cost categories and inputs in the comparative analysis and levelised cost calculation, in 2023 dirhams.
The decentralised systems are sized for the residential and commercial and industrial customers described in TAQA’s financial statements, as Table 6 shows.
Table 6: Decentralised solar generation systems, size and capital cost.
Table 7: UAE electricity consumption by customer group, 2022.
Yes, by a wide margin, once the grid’s full cost is counted. MCC’s analysis of the Department of Energy’s RC2 final decision and TAQA’s 2023 financial statements puts the average economic cost of electricity at 36 to 41 fils per kilowatt-hour (0.36 to 0.41 dirhams). Rooftop solar produces at about 12 fils. Until recently that was not the case: Griffiths and Mills (2016) found rooftop solar unviable in Abu Dhabi because the costs were too high. Since 2016 costs have fallen materially, below both the economic cost and most tariff levels.
The effect of grid stability is a caveat. The impact of either system type on grid stability depends on grid size, solar penetration and the presence of other renewables such as wind and hydro, and any deployment strategy needs to weigh those factors.
Figure 5: MCC analysis of the levelised cost of solar projects compared with the economic cost of electricity and retail tariffs, in dirhams per kilowatt-hour.
Rooftop solar at 12 fils per kilowatt-hour is well below the 39 fils economic cost and the 27 fils expatriate tariff. It is not cheap enough, though, to undercut the heavily subsidised 7 fils tariff for UAE nationals or the 5 fils agricultural tariff. Ground-mounted solar at 22 fils is less attractive to customers on the expatriate tariff of 27 fils or the commercial tariff, but it is still well worthwhile for the government, because it is far cheaper than the 39 fils economic cost.
Table 8: The key numbers in one place.
Three to six years for every group except UAE nationals. For each customer group the paper estimates the costs and savings of a rooftop or ground-mounted system, then the internal rate of return and payback period. Table 6 sets out the results.
Table 9: MCC analysis of distributed solar generation by customer group: tariff, system size, costs, payback period and internal rate of return.
On current cost data, rooftop and ground-mounted systems deliver electricity at 11 fils per kilowatt-hour (residential rooftop) to 22 fils (industrial ground-mounted). The spread in returns and payback between groups is almost entirely a subsidy effect: from the customer’s side, payback and return bear little relation to the levelised cost, and none at all in the case of UAE nationals.
Without the subsidy the overall benefits would be larger. Because UAE nationals earn a return of only 0.2 to 1.4 per cent, they have little reason to install solar, yet each unit they did generate would remove 0.32 dirhams of subsidy, the largest saving of any group. The same large saving applies to agricultural customers.
About 112 million dirhams a year for every one per cent of demand it supplies. The paper models three adoption scenarios for distributed solar starting in 2025, supplying 0.5, 1.0 and 1.5 per cent of Abu Dhabi’s electricity requirement. In the base case, supplying one per cent needs 292 megawatts, costs 1,342 million dirhams to install and generates about 826 gigawatt-hours a year. The annual subsidy borne by the government falls by an estimated 112.1 million dirhams, a result that benefits the government, customers and the environment at the same time. Figure 6 summarises the set-up cost, electricity generated and carbon avoided under each scenario.
Figure 6: MCC analysis for three adoption scenarios, distributed solar size,set-up cost and CO2 emissions avoided
Subsidy reform is itself one of the steps to net zero in the National Climate Change Plan, which asks the water and electricity authorities across the country to revise tariff structures, cut subsidies to customers and raise prices gradually. The current tariffs, above all for UAE citizens, discourage distributed solar, a point Griffiths (2013) made for the wider region. Even so, the economics work for every customer group except those on the local citizen tariff. Figure 7 breaks down the implied annual subsidy reduction in the base case by customer group.
Figure 7: Abu Dhabi tariff vs implied subsidy reduction in Base case fordistributed solar (by customer group)
Up to 5 million tonnes of carbon dioxide a year by 2030 in the fastest scenario, alongside a subsidy saving of 1.47 billion dirhams a year. Abu Dhabi illustrates how subsidies can get in the way of net zero targets. By covering everyone’s electricity cost the government is generous, but in some circumstances that generosity works against the climate goal.
The base case installs 292 megawatts of distributed solar in 2025 to supply one per cent of demand. From there the paper models three growth paths, scenarios A, B and C, in which the yearly capacity increment grows at 10, 21 and 30 per cent. In scenario C, distributed solar generates 10.8 terawatt-hours a year by 2030, around 10 per cent of estimated demand, which the authors judge a reasonable ceiling. Table 7 sets the three scenarios beside the centralised programme.
Table 10: MCC analysis of distributed solar adoption scenarios compared with the centralised solar approach.
The centralised programme is modelled to reach 10.3 gigawatts by 2030, based on available data, TAQA’s planned projects and MCC’s forecast assumptions. Figure 8 plots historical and forecast capacity for both routes from 2018 to 2030, marking the Noor Abu Dhabi, Al Dhafra and Al Ajban steps in the centralised line.
Figure 8: Historical and forecast solar capacity in gigawatts, centralised solar against the three distributed solar scenarios, 2018 to 2030.
Distributed solar is cheap enough to benefit the UAE government and the economy in every scenario and every customer group, and the net metering scheme is not an economic or technical barrier. What holds it back is that the customers who receive the largest subsidies, UAE nationals and agricultural users, have no financial reason to install it. For everyone else the economics are strong, with an average payback of about five years.
Distributed generation also offers a route for local private sector involvement in the emirate’s clean energy build-out. It widens Abu Dhabi’s strategic energy options, supports the local economy and gives visible form to its sustainability commitment.
The authors list nine likely reasons, which future research should test.
Table 11: Potential reasons for the slow uptake of decentralised solar in Abu Dhabi, as listed in the paper’s conclusions.
The legal point refers to the Department of Energy’s electricity generation licensing guide for self-supply.
The optimal level of distributed generation for Abu Dhabi, weighing grid stability, demand and cost efficiency, remains open. Policymakers, above all in the Department of Energy Abu Dhabi, should look at tailored options to encourage solar on buildings while protecting grid reliability and long-term sustainability. The effect of battery storage on the efficiency and reliability of distributed solar also needs work, as Mas’ud and colleagues (2018) note for the Gulf, particularly as the technology advances and its indirect costs change. The sale of carbon credits from distributed solar, demand response planning, net metering policy and electric vehicle storage are further openings for research.
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