New Zealand Faces Growing Gas Supply Risk

The power sector’s gas demand is about to shift in 2026 with the retirement of the Taranaki Combined Cycle (TCC) gas-fired power plant in late 2025. TCC’s capacity is 385 MW, around 5% of national peak demand, and it has historically been one of the country’s major gas-fired generators. Its closure is expected to reduce national gas generation capacity from 1,385 MW to 1,000 MW. No new fossil-fuel plant substitution is planned. While the retirement removes a steady baseload gas customer, it does not eliminate the system’s dependence on dispatchable capacity during dry periods. It instead increases the sensitivity of the market to hydro outcomes and the availability of the remaining fossil fuel power stations.

However, in New Zealand gas is not just a power-sector fuel: its strategic importance is driven by industry, with the chemical sector accounting for more than 40% of country’s total gas demand (in contrast with its 30% in the energy mix). Within that segment, consumption is highly concentrated. About 90% of the chemical sector’s gas demand is attributed to Methanex’s two methanol facilities in Taranaki, making the Canadian company the single largest component of New Zealand’s national gas demand. Nearly all methanol production is exported, mainly to Asia-Pacific markets including China, Australia, and South Korea. As supply tightened, methanol exports fell from 1.7 million tonnes in 2019 to 0.5 million tonnes in 2025. Methanex even fully shut its plants twice to redirect gas toward power generation needs – from mid-August to October 2024 and from mid-May to July 2025.

The current government shows signs of understanding of the situation and has moved to restart gas upstream investment. New Zealand’s Parliament repealed the 2018 offshore exploration ban in July 2025, reopening permitting beyond Taranaki from around September and introducing both tendered and open-market processes. Two applications have been notified since 25 September 2025 (offshore Taranaki and Waikato) with decisions due in January and March 2026, while Todd Energy’s Karewa discovery secured a mining permit in June 2025 and EnZed Energy has applied for offshore acreage in Taranaki. The budget also committed up to NZ$200 million (US$116.5 million) over four years, aiming for 10–15% government stakes in new projects.

However, two constraints limit the ability of this policy pivot to stabilise the market in the near term. The first is reserve confidence. Recent reclassifications have shifted multiple reserves from commercially recoverable (2P) to potentially recoverable (2C), raising uncertainty over their deliverability and economics. The second concern is timing. Offshore discoveries typically require long lead times – optimistically 4–5 years and (in more technically complicated cases) 8–10 years – before first production. As experts predict that the expected tightening point between gas demand and supply in the country will be in 2027, the first incremental supply from new discoveries is about to come too late to save the situation. Political risk also remains a factor with the 2026 election capable of reopening the policy debate around fossil fuels sector.

That gap makes LNG imports a credible option—but not a quick one. Coal power stations were the only remedy New Zealand could use immediately during the 2024 shortage: coal imports surged to 900 kt in 2024 from 260 kt in 2023, according to Kpler. This trend became even more notable in 2025, with total coal imports reaching around 1.36 million tonnes, a further 50% increase year-on-year. Gas is different. LNG would require dedicated import infrastructure, most plausibly a floating storage and regasification unit (FSRU), yet global availability is tight, and many units have been locked into Europe since the 2022 energy crisis. That could push New Zealand’s LNG import timeline into 2028–2029. Distance adds another penalty: as a remote and relatively small market, New Zealand would likely face higher shipping and logistics costs, translating into a premium on delivered LNG. Until import capacity exists, shortfalls will continue to be managed through price spikes, rationing, and industrial demand curtailment.

If imported LNG becomes the marginal supply source, the implications for the industrial sector in the country are clear. Methanex is likely to face the earliest pressure: producing export methanol is economically coherent when the production is based on competitively priced domestic gas, but the advantage weakens if domestic gas is substituted by imported LNG carrying a large premium. Residential and commercial demand – around 10% of current gas consumption – should be more resilient. By contrast, the largest industrial users and the chemical sector will face stronger incentives to optimize consumption or leave the country altogether. Meanwhile, New Zealand’s gas market will remain highly sensitive to weather: until new domestic supply arrives or import capacity is built, dry winters will continue to translate quickly into higher prices and industrial curtailment.

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