Andrew Horwood looks at what happened in the Netherlands when its electricity transmission and distribution infrastructure couldn’t keep up with the demand generated by its ambitious decarbonisation plans. Andrew covers recent New Zealand developments to see whether we’re better placed to avoid the same pitfalls.
As countries around the world race to decarbonise their energy systems, the Netherlands offers a cautionary tale. The Dutch electricity system, once a model of efficiency and interconnectivity but now facing the pressures of rapid electrification, is grappling with serious grid congestion and infrastructure bottlenecks.
The challenge in the Netherlands is moving electricity from where it’s generated to where businesses and communities want to consume it. The Dutch experience underscores the importance of proactive planning, regulatory reform, and strategic investment.
Demand for electricity has outstripped grid capacity in the Netherlands
A triple whammy has increased the push for electrification in the Netherlands.
First, the Dutch Senate voted last year to permanently halt natural gas production from the Groningen field by October 2024. Groningen has provided energy for decades, but its extraction operations were causing earthquakes and damaging thousands of buildings in the area.
Second, while the Netherlands still imports gas from Norway and other countries, it has drastically reduced fossil fuel imports from Russia following the invasion of Ukraine. The uncertainty caused by the war and the reduction in Russian supply led to sharp increases in gas prices across Europe, the Netherlands included. The price volatility and supply shock has led the Dutch to look to electricity as an alternative energy source.
Third, the Netherlands is committed to achieving net-zero carbon emissions by 2050, and has committed to major investments in offshore wind and solar generation, as well as hydrogen infrastructure. Already, over 2.6 million Dutch houses have solar panels.
That convergence of factors means a lot more pressure on the country’s electricity transmission and distribution infrastructure – that is, the lines and installations that move electricity from where it’s generated to where it’s needed.
Grid congestion has become a big problem, with new connections for housing developments, industrial projects, and renewable energy installations now delayed until the mid-2030s.
To provide the grid capacity the country needs, the Dutch government estimates that around €200 billion in investment in cables and substations will be needed by 2040. The need for that huge financial outlay is a threat to the country’s decarbonisation and economic goals.
The challenges facing the Netherlands with its transmission grid serve as a warning for transmission and distribution infrastructure elsewhere in the world.
In New Zealand we’ve got some similar worries – but we’re responding
Some of these factors at play in the Netherlands are present in Aotearoa too. For example, our gas reserves may be falling faster than expected previously. MBIE announced recently that as of 1 January 2025 natural gas reserves were down 27% on the previous year, with the reduced numbers mainly due to gas field operators refining their estimates of reserves, rather than gas use over 2024.
The reduced gas supply is one reason demand for electricity is expected to increase by between 35% and 82% by 2050, according to MBIE. More generally, the driver is the expected widespread electrification of transport, heating, and industrial processes over the next two-plus decades as we transition to a low-emissions economy.
The Dutch experience shows that transmission and distribution challenges need to be tackled in coordination with increasing generation from renewable sources and encouraging electrification across industries and consumers. Without the solid middleware between generation and end use, the system can break down, with long delays.
In New Zealand we’ve been seeing a variety of shifts to help our transmission grid and distribution networks cope with the future we’re aspiring to. Regulatory changes and technological advances are relieving the pressure on this infrastructure and also making it easier for Transpower and distributors to invest and upgrade.
New rules are making it easier for end users to connect to our distribution networks
When it comes to moving electricity to where it’s needed, our distribution networks – the 29 lines companies – have been likened to our local roads. The transmission network run by Transpower – the national grid – is like our motorways and major highways, because it moves electricity at high voltages over long distances. Our distributors then connect up with that main “highway” to take the power to local users, covering the final, shorter distances and at lower, more useable voltages.
Our Electricity Authority has introduced some new rules to make it easier and faster for the end users of electricity to connect to the local distribution networks – particularly larger-scale electrification projects like EV charging stations and solar farms, as well as manufacturing facilities. In our roading metaphor, think of these individual connections as like your driveway.
The new rules standardise application processes across our 29 lines companies, with the aim of eliminating inefficiencies in some of the processes. They also require more consistency in pricing methods for new and upgraded connections – which will especially make life easier for businesses operating in several regions.
These changes are designed to reduce delays and reduce costs. That’s great for those wanting to connect to networks, but it creates some cost for some distributors.
New DER technology is connecting generation directly to distribution, and regulators are smoothing the way
New Zealand’s electricity system is shifting to incorporate more distributed energy resources – or “DERs”. DERs are small-scale units of energy generation or storage that are connected directly to a distribution network (rather than to Transpower’s transmission grid like our big generation assets).
DERs include rooftop solar, household and community batteries, and community energy projects. This decentralisation offers benefits in affordability as well as empowering our communities to be more resilient – but it also introduces more balls for a distributor to juggle.
Distributed solar generation is likely to get a boost following a flurry of announced initiatives from both government and business to support solar. In particular, the Government announced in June that it was widening the permitted voltage range on electricity networks, which allows households to export more solar-generated electricity back to the system.
Otago distributor Aurora Energy has embraced this, so from August 2025 solar panel owners can export up to 10 kW of solar-generated electricity back to Aurora Energy’s network, up from the previous limit of 5 kW. Network constraints could limit how much power is actually exported, but Aurora has signalled it is generally willing to manage more electrons.
Key to managing all this complexity is “digitalisation” – using digital technologies to improve business processes and operations. Smart meters, real-time data, and automated control systems enable better coordination between supply and demand.
Integrating those new technologies requires regulatory support, consumer trust, and a lot of investment. Recognising its importance, the Electricity Authority consulted on its digitalisation programme earlier this year.
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Regulators are easing restrictions on distributors investing in generation
Meanwhile, in February the Government announced that it plans to ease restrictions on electricity lines companies investing in generation, to help strengthen the energy network.
Currently, distributors have been limited to owning no more than 250 MW of generation connected to Transpower’s national grid, or no more than 50 MW of generation connected to their own networks, unless they operate that generation in a separate company or get an exemption from the Electricity Authority.
Changes to remove or reduce those restrictions are expected to be made through a new Energy and Electricity Security Bill to be introduced this year.
Transpower and our distributors can now collect more revenue
Transpower and our electricity distributors are natural monopolies, and so are regulated by the Commerce Commission under the Commerce Act to ensure consumers and businesses get a fair deal in the absence of competition.
Since 1 April 2025, the Commission has allowed Transpower and local lines companies to collect more revenue, so they can invest and ensure their infrastructure continues to be safe and reliable. For the average household, this is expected to add up to $10 a month in the first year and $5 a month for the four years after that.
Distribution and transmission charges account for around 25% and 8% of an average household power bill, respectively. The distribution charges fund the maintenance and upgrade of the 150,000 km of power lines that connect homes and businesses to the national grid. The transmission charges fund Transpower’s infrastructure asset base, currently including 25,000 transmission towers, 11,000 kilometres of lines, and 174 substations.
Investment drivers include standard stuff like replacing aging infrastructure and expanding capacity to accommodate new connections. However, this is the 21st century and investment to keep pace with technological developments and the growth of electrification is vital.
Regulators are encouraging smart time-of-use initiatives to reduce strain on our networks
As well as that regulatory step to ensure distributors have sufficient revenue to make necessary investments, other new regulatory initiatives are aimed at reducing the need to invest. The Electricity Authority has now required major electricity retailers to offer off-peak or time-of-use pricing plans by 1 July 2026. The goal is to encourage off-peak charging, improve the efficiency of the grid, and reduce the costs of upgrading infrastructure.
Recognising the impact of EV charging on peak demand, MBIE began consulting in July this year on regulating smart EV chargers, which know to charge at the best times, like when electricity is cheaper (reflecting lower demand on a network). MBIE is considering requiring all chargers to be smart, among other options.
Modelling suggests that widespread adoption of smart chargers could save New Zealand up to $4 billion by 2050, by avoiding costly upgrades and reducing reliance on fossil-fuelled generation.
Ensuring our networks can handle the electric future we want depends on a proactive, coordinated approach
The experience in the Netherlands is a reminder that as we electrify our economy and embrace renewable energy, we need to ensure our transmission grid and distribution networks are ready to operate on a significantly larger scale.
That takes proactive planning and a coordinated approach, based on sufficient revenue, smart use of smart technology, and the right regulatory settings.
