Grids with high shares of renewable energy add usable capacity fastest when transmission investment, demand response, battery storage and regulation move together. This paper compares Britain, Abu Dhabi and Australia and finds that new lines are arriving slowly and at rising cost, so flexible demand, batteries and reformed grid connection queues are now doing much of the work.
All three regions are building new links and substations to move renewable power from where it is generated to where it is used, but on very different timetables.
Britain's Eastern Green Links each carry up to 2 GW from Scotland to England. According to National Grid, Links 1 and 2 are due in 2029, Links 3 and 4 from 2033, and Link 5 in 2035.
Financing is following. The National Wealth Fund lent ScottishPower £600m for seven priority network projects in May 2025, and a further £600m for Eastern Green Link 4 in March 2026.
Abu Dhabi is reinforcing its 400 kV network. TAQA Transmission awarded the ICAD-4 substation to Linxon in February 2025, for commissioning in 2028, and will connect the new round-the-clock solar and storage project.
Australia faces the steepest cost pressure. The Victoria to New South Wales Interconnector West (VNI West) should unlock about 3.4 GW of new renewables, but its Victorian section has moved to November 2030, and the Australian Energy Market Operator (AEMO) put the rise in real cost estimates for new overhead lines at 25% to 55% in its May 2025 draft, before its final report of August 2025 dropped the split between lines and substations and said estimates run up to around 100% higher in some cases (Table 1 and Figure 1).
Table 1: Grid upgrades in Great Britain, Abu Dhabi and Australia, status at September 2026
AEMO's own summary of the cost update is blunt:
Figure 1: How AEMO's transmission cost estimates changed between its draft and final 2025 reports
Increase in real cost estimates against the 2024 Integrated System Plan. The May 2025 draft gave separate ranges for overhead lines and substations. The final report of August 2025 no longer splits them and publishes only an upper figure, so its bar has no lower bound.
Demand response, which pays customers to use less power at peak times, now works at scale in all three regions, from British households to Abu Dhabi industry and Western Australia's contracted reserves.
In Britain, according to the system operator's review, 1.6 million households and businesses took part in the Demand Flexibility Service in winter 2022/23, cutting demand by about 3,300 MWh over 22 events (Table 2).
In 2023/24, third-party apps paid participants between about £2.40 and £3.00 per kWh saved (Table 3).
Table 2: Great Britain's Demand Flexibility Service, winter 2022/23
Table 3: Rewards offered by third-party apps under the Demand Flexibility Service, winter 2023/24
In Abu Dhabi, the second phase of the Department of Energy's demand response pilot started in May 2025. It targets more than 250 MW from over 30 industrial and commercial organisations, with Energy Pool as aggregator, and supports a policy target of 200 MW under contract by 2030.
Western Australia shows how quickly peaks are rising. Its demand record, unchanged since 2016, has been broken repeatedly since late 2023, beginning with 4,233 MW in February 2024, and the six highest peaks all fell within twelve months (Figure 2).
Figure 2: Western Australia's six highest operational demand peaks, February 2024 to January 2025
Megawatts, highest 5-minute interval, South West Interconnected System. Numbers below each marker give its rank. Filled markers match figures AEMO has published. Hollow markers are values from AEMO's record demand slide, reproduced in the original paper; published data on a different basis differs from them by 8 MW or less.
AEMO activated 126 MW of demand reductions when operational demand reached a record 4,486 MW on 20 January 2025 (Figure 3). Its planning report also flags a gap in how the market's standing demand programmes are contracted:
Figure 3: Demand reductions activated at Western Australia's record peak on 20 January 2025, against the forecast capacity surplus for summer 2025-26
Megawatts. AEMO activated 126 MW of demand reductions at the record 4,486 MW peak; without them, it estimates peak demand would have reached 4,594 MW. The surplus is capacity above AEMO's requirement, which already includes a reserve margin.
These programmes flatten peaks, free transformer headroom and give operators rapid, software-based "virtual lines". The rules that support them include:
They stabilise the grid most when demand response is bought as a fast, clearly defined service, rather than paid only for energy delivered at scarce moments.
In Australia, 12 registered demand response providers supplied 19% of contingency raise frequency reserves in Q1 2025, an average of 330 MW.
In the same quarter, the wholesale demand response mechanism dispatched only 4 MWh, down from 87 MWh a year earlier (Figure 4).
Abu Dhabi and Britain rely on events called at peak times, paid through an aggregator or through suppliers and apps (Table 4).
Table 4: How demand response is procured and what it delivers
AEMO says the dispatch figure understates what is out there:
Figure 4: Wholesale demand response dispatched in Australia's National Electricity Market, by quarter
Three battery projects stand out, each doing a different job: stabilising the grid in Scotland, supplying solar power around the clock in Abu Dhabi, and letting existing lines carry more power in New South Wales.
Britain's system operator ties the project to its zero-carbon operation target:
Masdar presents its project as an answer to the oldest limitation of renewables:
Table 5: Four projects behind the paper's storage milestones
Storage soaks up surplus solar, defers line upgrades and supplies fast frequency response, which makes it central to 100% renewable ambitions.
Machine learning is making solar forecasts more accurate and reserve levels leaner, which lowers balancing costs without new infrastructure.
Britain's system operator, now the National Energy System Operator (NESO), made its day-ahead solar forecasts 33% more accurate in 2019, working with the Alan Turing Institute.
Its Dynamic Reserve Setting tool, built with the Smith Institute, sets reserve levels a day ahead. NESO reports that the tool has cut how much reserve it needs to buy:
National Grid Electricity Distribution's 2024 scenarios were the first by a distribution system operator to model maritime, aviation, rail and agriculture demand.
In Australia, AEMO published its final 2025 inputs and scenarios in July 2025, reviewed by the Australian Energy Regulator in August, and its 2026 Integrated System Plan in June 2026 (Figure 5).
Table 6: Forecasting and planning tools for variable solar
Figure 5: Australia's 2026 Integrated System Plan cycle, December 2024 to June 2026
They are redesigning grid connection queues and planning processes, so that network companies, operators and governments stop duplicating each other's work.
NESO explained why the queue had to pause:
The New South Wales review set out a similar aim for planning:
They need to plan for both ends of the day: record-low midday demand as rooftop solar grows, and evening peaks increasingly met by storage.
In Britain, NESO warned in April 2025 that national demand could fall below its 13.4 GW record:
A new record of 12.8 GW has since been set, and NESO's 2026 Summer Outlook puts the chance of a lower figure this summer at about 75%.
In Dubai, the 250 MW / 1,500 MWh Hatta pumped-storage plant provides six hours of storage at full output.
In Australia's National Electricity Market, average battery output rose from 98 MW in Q1 2025 to 359 MW in Q1 2026, after 4,445 MW of new battery capacity connected (Figure 6).
Table 7: Planning signals for 2030 and beyond
Figure 6: Average battery discharge in Australia's National Electricity Market, first quarters of 2024 to 2026
In Abu Dhabi it has mostly helped, because transmission and distribution sit in separate companies under one owner.
TAQA Transmission owns the high-voltage grid, including the 400 kV backbone, while TAQA Distribution supplies customers at lower voltages. As subsidiaries of the same group, they can share data and align investment more easily, avoiding the split incentives seen in some liberalised markets.
Abu Dhabi is doing best so far, because its largest new solar project is designed with storage from the outset.
Britain is building the Eastern Green Links to carry Scottish wind power south, but the links arrive between 2029 and 2035 (Table 1).
Australia built renewables ahead of transmission and is now retrofitting, for example with the Waratah battery, while VNI West's timetable slips. Transgrid's latest position on the New South Wales section is:
That is what lagged sequencing costs: retrofits such as Waratah, and new lines that arrive years after the generation they serve.
Not yet: each region is reforming its rules, but none has finished.
In Britain, connection reform and the distribution system operation incentive in Ofgem's current distribution price control (RIIO-ED2), which rewards companies for using flexibility instead of reinforcement, show progress. But developers still wait years to connect: when Ofgem approved the reforms in April 2025, it found waiting times too long, with some new connection offers dated in the 2040s.
Ofgem now also funds grid expansion, partly to cut constraint costs:
Abu Dhabi has moved from a pilot to a policy target of 200 MW of contracted demand response by 2030.
Australia's rule changes on wholesale demand response (2020) and integrating energy storage (2021) opened the market to flexible load and storage, but the wholesale mechanism remains little used (Figure 4) and local planning hurdles remain.
They can plan on shared scenarios and fund infrastructure jointly.
Joint scenario planning, such as the distribution scenarios built with NESO and AEMO's inputs and scenarios report, gives everyone the same evidence base.
Co-funded programmes, such as NESO's Stability Pathfinder and the AED 36 billion programme agreed by EWEC, TAQA and Masdar in April 2025, a quarter of it for grid, show how costs and risks can be shared.
Building social licence into planning, as AEMO now does, earns public trust and speeds up delivery.
Not yet: in MCC's assessment, about 90% renewables looks feasible, but the last 10% is still difficult and expensive.
Large-scale solar with multi-hour batteries, such as the Masdar and EWEC project, covers daily balancing. Dubai's pumped-storage plant at Hatta, targeted for completion in 2025, brings a technology new to the region:
Gas turbines able to co-fire green hydrogen remain the seasonal back-up.
The remaining gaps are inertia services and storage lasting more than 12 hours. The large Saudi battery awards so far are four- to five-hour systems, such as the 2.5 GW / 12.5 GWh the Saudi Electricity Company awarded in January 2025.
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