New Zealand's big energy companies have commissioned a report into the possible importation of LNG to bolster dwindling domestic gas supplies. Photo / Getty Images
Importing liquefied natural gas to offset New Zealand’s dwindling gas reserves is feasible but challenging, potentially requiring capital investment of up to $1 billion, a report commissioned by the big energy companies says.
Clarus (formerly First Gas), Contact Energy, Genesis Energy, Meridian Energy, and Mercury commissioned two studies, looking at both conventional-scale solutions as used across the globe, as well as smaller scale options.
Data out last month showed New Zealand’s domestic gas supply is reducing faster and sooner than previously forecast.
Revised forecasts have annual gas production falling below 100 petajoules (PJ) by 2026 instead of the previously forecast 2029.
Last winter, constrained gas supply for electricity generation was a key element in driving wholesale power prices up to $820 per megawatt hour (MWh).
Clarus chief executive Paul Goodeve said the report aimed to provide New Zealand with a robust and “clear-eyed” evaluation of LNG (liquefied natural gas) import feasibility.
Studies were carried out between September 2024 and May 2025 by international LNG experts, Gas Strategies (UK), with engineering consultancy Wood Beca (NZ).
The reports showed that a gas import option may be technically feasible, though more challenging than anticipated.
The study partners said LNG is just one of several options being explored to support energy resilience.
Investment in renewables, demand-side management and electrification remain central to the country’s low-carbon energy transition, they said.
“Ultimately, our energy future will be shaped by a mix of energy options and this work ensures the option of LNG is properly understood,” Goodeve said.
The report said conventional-scale LNG options provided high levels of flexibility – but at a cost.
LNG is equivalent to domestic natural gas, once it is regasified, and can be transported using existing gas networks and used in existing gas appliances.
The report noted the global LNG industry had grown considerably over recent years, with around 50 countries now relying on LNG imports to meet their domestic energy needs.
The global LNG trade has standardised around large vessels (carrying around 170,000–180,000cu m, or 4.5PJ of gas), with much of the storage and regasification equipment located on permanently moored ships known as Floating Storage and Regasification Units or FSRUs.
The benefit of these conventional-scale LNG solutions was to improve security of energy supply, providing access to energy when required, the report said.
In New Zealand’s case, this may be in a dry year when hydro inflows are low, or if domestic gas supply continues to decline.
The study found that a conventional solution would allow New Zealand to access additional gas at around $18 per gigajoule (GJ) on a landed cost basis.
The landed price is at the entry point to the import terminal and includes shipping.
The total cost to end users would also need to account for the capital and operational costs required to deliver that gas into the system through port upgrades, regasification systems and storage, estimated at an additional $170-$210 million a year.
These would also contribute to the effective delivered cost to more accurately reflect the total cost to end users.
Therefore, the final delivered cost per GJ would depend on the annual throughput of the terminal.
The large size of the ships involved in conventional-scale LNG imports would necessitate significant infrastructure investment, including port or pipeline upgrades.
“Depending on the location and technology used, capital cost estimates range from $190 million to $1 billion which is a significant investment given the uncertainty around how often LNG imports would be needed.”
Smaller-scale options would cost less but would offer less flexibility.
In an effort to seek out lower capital cost solutions, the research work also explored smaller-scale developments that would use existing port infrastructure without major modifications.
These solutions would involve much smaller vessels of around 15,000 cubic metres in size (0.4 PJ).
Roughly one-tenth the size of conventional LNG carriers, they could shuttle between Australian LNG export projects and a New Zealand port, such as Port Taranaki.
This model could provide an additional 7–10PJ of energy per year to the New Zealand system, equivalent to around one month of current gas supply.
Smaller ships meant limited site works would be required, enabling faster and more flexible development.
On a landed cost basis, small-scale LNG would cost about 25% more than large-scale, at $20–$21/GJ.
The additional capital costs of smaller-scale LNG infrastructure are estimated between $140m and $295m, depending on how much onshore storage is built.
“So, while the gas costs are more expensive than conventional scale, the infrastructure costs are lower, the gas itself is expected to be more expensive.”
The final delivered costs per GJ would need to take into account both the landed cost and capital cost.
The study also highlighted several issues that would need to be addressed in moving forward with smaller-scale solutions.
These included securing interest from existing sellers to supply a relatively small volume of gas and ensuring sufficient storage of LNG when it arrives in New Zealand.
The report said six locations for LNG imports have been identified across the North Island.
It said no single location had the existing combination of sufficient water depth, benign weather and ocean conditions and existing gas pipeline capacity to meet demand scenarios.
All locations would therefore require financial investment to address one or more of these issues.
LNG imports were unlikely to be achieved in less than four years, unless the existing permitting and consenting process was fast-tracked.
The report said LNG represented an insurance policy for New Zealand to ensure the availability of gas resources into the future.
Over a 15-year duration, the annualised cost of the infrastructure to provide this certainty was $170–$210 million, excluding the cost of the LNG.
“However LNG demand is uncertain and it is recognised that in some years demand could be zero.
“In this case, fixed infrastructure costs will still need to be recovered.”
The cost of the LNG, based on an average price over the last 12 months, would be $83m per LNG cargo.
The report said LNG prices have been particularly volatile in recent years.
The number of cargoes required each year could vary between zero and three up to 2030, and perhaps up to seven cargoes per year, post 2030.
Following on from last year’s shortage, thermal generators Contact and Genesis have secured more gas from Methanex, a methanol producer and exporter.
In addition, Contact announced today that it had a seven-year gas supply agreement with Greymouth Gas New Zealand.
The agreement to supply up to 7PJ of gas per annum will take effect from October 1, 2025, with an option to extend for a further three years from October 2032.
In a normal hydrology year, Contact expects to generate 200GWh to 300GWh of electricity from its gas peaking units at Stratford, supporting its Clutha hydro scheme.
Jamie Gray is an Auckland-based journalist, covering the financial markets, ghe primary sector and energy. He joined the Herald in 2011.