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New Zealand: 5 energy policy briefs

The energy policies moving New Zealand’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Dry-year security response · emergency reserve scheme decided 13 January 2026, live by the last quarter of 2026

New Zealand · Electricity Authority Te Mana Hiko and Transpower (System Operator) · decision · 2026

Where it stands: Emergency reserve scheme Code amendment decided 13 January 2026; Transpower building the service for the last quarter of 2026

The August 2024 gas shortage and historically low hydro storage forced industrial shutdowns and a policy reset. The Electricity Authority's answer is an emergency reserve scheme, decided on 13 January 2026: a new ancillary service run by Transpower that pays industrial users to reduce demand or add generation when supply is especially tight, worth an estimated $33 million in net benefits and due in place by the last quarter of 2026.

The problem

New Zealand runs a hydro system with only a few weeks of storage and no large interseasonal reserve, so a dry autumn in the South Island has always had to be covered by thermal generation. That backstop is eroding: domestic gas production has declined faster than expected, the Maui and Pohokura fields are past peak, and the thermal fleet that used to absorb a dry year is ageing and increasingly expensive to fuel. In August 2024 a fuel shortage and low inflows produced sustained high wholesale prices, industrial curtailment and a political crisis, and it exposed the fact that the market had no formal mechanism to buy emergency demand reduction before the system operator reached the blunt instruments of an official conservation campaign and rolling outages. The last time those were needed, on 9 August 2021, about 34,000 consumers were disconnected for up to two hours. Transpower's 2026 Security of Supply Assessment now shows the New Zealand Winter Energy Margin falling below the lower security standard by 2031 in its Reference Case, and, under an Expected Future Case with lower domestic gas supply and LNG imports from 2029, dry-year energy risk emerging as early as 2028.

What it does

The Electricity Authority consulted on establishing an emergency reserve scheme from 31 July to 28 August 2025 and on the Code amendment proposal from 17 October to 14 November 2025, and announced its decision on 13 January 2026. The scheme is implemented as a new ancillary service, operated by Transpower as system operator, under which industrial organisations opt in and are paid to reduce electricity demand briefly, or provide additional generation, for short periods when supply is especially tight and it makes commercial sense for them to do so. The Authority's research estimates net economic benefits of $33 million, and it judged the scheme significantly cheaper than investing in additional emergency generation; Transpower is working with providers to develop and implement it, with the scheme due in place by the last quarter of 2026. The Authority explicitly benchmarked the design against comparable mechanisms in Texas, Great Britain and Australia. This sits inside a wider security programme: Transpower consulted in late 2025 on amendments to the Security of Supply Forecasting and Information Policy covering improved forecasting tools, enhanced risk communication, updated contingent storage buffer settings and expanded system risk considerations, to be implemented before winter 2026; the Authority made frequency and voltage common quality Code amendments on 10 March 2026 and finalised the Connected Asset Commissioning, Testing and Information Standard on 31 March 2026 with the Code amendment decision published 18 May 2026; and from 19 May to 30 June 2026 it consulted on common quality and wholesale market arrangements for battery energy storage systems and hybrid stations and released a discussion paper on moving New Zealand to five-minute settlement. Transpower continues to publish electricity risk curves and simulated storage trajectories monthly and a quarterly security of supply outlook.

Market effect

An emergency reserve scheme puts a floor under the value of large industrial flexibility and a ceiling on the tail of the spot price distribution. For industrial consumers with interruptible processes it creates a second revenue line that was previously available only through bilateral arrangements with a gentailer, and it makes demand-side response a registered, dispatchable product rather than an informal favour to the system operator. For generators the effect is to reduce the frequency of the extreme scarcity events that reward peaking plant, which slightly weakens the merchant case for new thermal capacity at exactly the time the security assessment says more firm capacity is needed. The more important market signal is the gas trajectory: with the Winter Energy Margin projected below the lower standard by 2031 in the Reference Case and dry-year risk potentially emerging by 2028 if domestic gas falls faster and LNG imports do not arrive until 2029, the forward curve for winter cover in the late 2020s carries a structural premium that neither the reserve scheme nor the Code amendments remove. The battery energy storage and five-minute settlement workstreams matter for the same reason: New Zealand is building the market arrangements that let batteries and flexible load substitute for the thermal firming the system is losing, and the timing of those Code changes will determine how much of the 2028 to 2031 gap can be met without new gas-fired plant.

Key numbers

Estimated net economic benefit of the scheme
$33 million
Implementation deadline
In place by the last quarter of 2026, operated by Transpower
Most recent emergency disconnection event
9 August 2021, about 34,000 consumers off supply for up to two hours
Security of supply outlook
New Zealand Winter Energy Margin falls below the lower standard by 2031 in the Reference Case, and dry-year risk could emerge by 2028 in the Expected Future Case

Who gains and who pays

  • Large industrial electricity users (gains): Can opt in to be paid for short-notice demand reduction or additional generation under the new ancillary service.
  • Households and small businesses (gains): An extra layer of protection against the unplanned disconnections last seen on 9 August 2021.
  • Transpower as system operator (obligation): Must develop, procure and operate the scheme with providers by the last quarter of 2026.
  • Peaking and thermal generators (costs): Fewer extreme scarcity events reduce the merchant value of emergency generation capacity.
  • Battery storage developers (mixed): Gain from the firming gap but await the outcome of the 2026 BESS and five-minute settlement Code work.

Implementation

The scheme is a Code amendment creating an ancillary service, so Transpower must write the procurement and dispatch procedures, register providers and integrate the product into its security of supply toolkit before the last quarter of 2026; the Authority monitors compliance through its Compliance Committee and the Rulings Panel. It operates upstream of the existing emergency machinery, the Emergency Management Policy, official conservation campaigns and the Rolling Outage Plan, and alongside the amended Security of Supply Forecasting and Information Policy that took effect before winter 2026. The system operator continues to publish the annual Security of Supply Assessment, the monthly Energy Security Outlook with electricity risk curves and simulated storage trajectories, the quarterly Security of Supply Outlook and the New Zealand Generation Balance. The remaining structural questions, the future of the Huntly thermal station and its firming arrangements, the contractual position of the Tiwai Point aluminium smelter as the country's largest single load, and the government's gas supply interventions, sit outside the Code and are being handled through commercial agreements and government policy rather than regulation; those arrangements should be confirmed against MBIE and company disclosures before being relied on.

Concerns

  • Declining domestic gas supply with LNG import capability not expected before 2029
  • The Winter Energy Margin falling below the lower security standard by 2031 on current projections
  • Reliance on voluntary industrial opt-in for a scheme that must work in the tightest hours
  • Timely delivery of committed generation and battery projects, on which the near-term adequacy finding depends
  • Emergency reserve payments and scheme costs being recovered from all consumers
  • Market arrangements for batteries and five-minute settlement still only at discussion stage in 2026

Dates to watch

  • 2026-12: Emergency reserve scheme due to be in place and operated by Transpower
  • 2027: Authority decisions on battery energy storage market arrangements and the five-minute settlement discussion paper
  • 2028: Earliest emergence of dry-year energy risk under Transpower's Expected Future Case
  • 2031: Year the New Zealand Winter Energy Margin falls below the lower security standard in the Reference Case

Sources

Checked against sources on .

Level playing field Code amendments · non-discrimination obligations on the four gentailers from 1 July 2026

New Zealand · Electricity Authority Te Mana Hiko and the Commerce Commission (Energy Competition Task Force) · regulation · 2026

Where it stands: Non-discrimination, hedge disclosure and market making Code amendments made in May 2026 and in force from 1 July 2026

After the August 2024 fuel shortage and sustained high wholesale prices, the Electricity Authority and Commerce Commission created a joint Energy Competition Task Force. Its first tranche landed in 2026: Code amendments made on 8, 13 and 15 May 2026 impose non-discrimination obligations on Contact, Genesis, Mercury and Meridian in hedge trading, tighten hedge disclosure and market making, and require time-of-use and peak export pricing from 1 July 2026.

The problem

New Zealand's wholesale market is dominated by four vertically integrated gentailers that own most of the flexible hydro and thermal capacity and most of the retail book. An independent retailer or a new generator has no hydro storage of its own, so it must buy risk management contracts from the same firms it competes with, and in August 2024 a gas supply shortage and low hydro inflows produced sustained high spot prices that squeezed independents, shut down industrial load and pushed several retailers to the wall. The Electricity Authority's mandate had been widened in 2022, but the underlying structural asymmetry was untouched: the Authority could see the wholesale price but not whether the hedge offers made to an independent were on the same terms as those made to a gentailer's own retail arm. An independent review of market performance by Frontier Economics, published on 1 October 2025, put the competition question squarely on the table.

What it does

The Electricity Authority and the Commerce Commission jointly established the Energy Competition Task Force in response to the August 2024 shortage, with MBIE participating as an observer, and ran an eight-initiative work programme aimed at enabling new generators and independent retailers to enter and compete. The Authority amends the Electricity Industry Participation Code 2010 under the Electricity Industry Act 2010, whose section 15 was amended by the Electricity Industry Amendment Act 2022 (2022 No 46, assented 31 August 2022) to add an additional objective of protecting the interests of domestic and small business consumers, and section 16(1)(ia) a matching function. The first tranche is now made. On 26 May 2026 the Authority published its non-discrimination obligations decision paper, following a Code amendment made on 15 May 2026: the four large gentailers, Contact Energy, Genesis Energy, Mercury NZ and Meridian Energy, must supply risk management contracts on an even-handed basis to all buyers and cannot favour their own retail arms on price or non-price terms. Gentailers must submit implementation plans and certify compliance annually, and file six-monthly Retail Price Consistency Assessments demonstrating that retail price offers are justifiable against their expected cost of supply and that an equally efficient retailer could compete on price. The obligations came into force on 1 July 2026, with implementation plans and the first assessments due on 3 September 2026. Alongside them the Authority made Code amendments on market making arrangements (8 May 2026), hedge disclosure obligations and the definition of a materially large contract (13 May 2026), and earlier decisions of 16 July 2025 requiring retailers with 5 per cent or more market share to offer a time-of-use plan giving small consumers cheaper off-peak rates and requiring distributors to pay a rebate to consumers who export at peak times, both expected to be available by 1 July 2026. In April 2026 the Task Force announced three new collaboration priorities, updated its Terms of Reference in May 2026 with a joint regulatory model, and in July 2026 published a Code change decision on targeted intervention for connection pricing with a balance point principle.

Market effect

The non-discrimination obligations attack the single biggest barrier to entry in New Zealand electricity: the price at which an independent can buy firm cover. If they work, independents and new generators can hedge on the same terms as a gentailer's internal retail desk, which narrows the retail margin gentailers can sustain and makes an independent retail book financeable without owning generation. The six-monthly Retail Price Consistency Assessment is the enforcement teeth, because it forces each gentailer to show that its own retail prices are justifiable against its expected cost of supply, an equally-efficient-competitor test that has no precedent in the New Zealand market. The market making and hedge disclosure amendments do the same job from the transparency side: better disclosure of over-the-counter positions and firmer market making obligations tighten the visible forward curve that everyone else prices off, and the Task Force has flagged a standardised super-peak hedge contract to address the periods where cover is scarcest. On the demand side, mandatory time-of-use plans from large retailers and peak export rebates from distributors give households and small businesses a price signal for shifting load and for exporting battery and rooftop solar output at peak, building the consumer-side flexibility that reduces the dry-year peak. The risk for incumbents is compliance cost and, more materially, margin compression; the risk for the reform is that even-handed offers are still made at a price no independent can afford if wholesale scarcity persists.

Key numbers

Firms subject to non-discrimination obligations
The four large gentailers: Contact Energy, Genesis Energy, Mercury NZ and Meridian Energy
Non-discrimination obligations in force
1 July 2026, with implementation plans and first assessments due 3 September 2026
Retail Price Consistency Assessment frequency
Six-monthly, with annual compliance certification
Time-of-use pricing threshold
Retailers with 5 per cent or more market share, available by 1 July 2026
Task Force initial work programme
Eight initiatives, launched after the August 2024 fuel shortage

Who gains and who pays

  • Independent retailers and new generators (gains): Entitled to hedge offers on an even-handed basis and to greater forward-market transparency.
  • Contact, Genesis, Mercury and Meridian (obligation): Non-discrimination obligations, annual certification, implementation plans and six-monthly Retail Price Consistency Assessments.
  • Households and small businesses (gains): Large retailers must offer time-of-use pricing and distributors must pay peak export rebates from 1 July 2026.
  • Distribution businesses (costs): Must fund peak export rebates and comply with the July 2026 connection pricing decision.
  • Owners of rooftop solar and home batteries (gains): Paid fair rates for power exported to the network at peak times.

Implementation

Code amendments are made by the Authority Board after consultation with a regulatory statement under section 39 of the Electricity Industry Act, published on ea.govt.nz and gazetted, with effective dates set to allow system change. Guidance documents accompany the obligations: non-discrimination guidance and retail price consistency assessment guidance were published with the 26 May 2026 decision, and further guidance on long run marginal cost based distribution rebates and business consumer eligibility followed on 17 August 2026. Monitoring and compliance work is already under way and is the third of the Task Force's 2026-27 collaboration priorities, covering a monitoring and compliance guideline, analysis of the assessments and a review of gentailers' non-discrimination implementation plans. The other two priorities are a Commerce Commission review of the efficiency of grid exit point upgrades, with an issues paper planned for August 2026, and connection pricing and competition for connection works, where formal work on competition in connection delivery is expected to begin in 2027 and the connection pricing timeline assumes revenue allowance changes are in place by 1 April 2028 ahead of the next distribution default price-quality path in March 2030.

Concerns

  • Even-handed offers may still be priced beyond what independents can absorb in a scarcity-driven market
  • Compliance and monitoring burden on both the Authority and the four gentailers
  • No structural separation, so vertical integration and its information advantages remain
  • Retail Price Consistency Assessments rely on cost information that only the gentailers hold
  • Peak export rebates and time-of-use plans shift cost between consumer groups
  • Reform momentum depends on a joint Task Force whose priorities were reset in April 2026

Dates to watch

  • 2027-03: Second round of six-monthly Retail Price Consistency Assessments from the four gentailers
  • 2027: Commerce Commission and Authority work on competition in connection delivery markets begins
  • 1 April 2028: Target date for connection pricing revenue allowance changes ahead of the next distribution price path

Sources

Checked against sources on .

DPP4 and RCP4 · $11.5 billion for distributors and $5.9 billion for Transpower, 1 April 2025 to 31 March 2030

New Zealand · Commerce Commission New Zealand · decision · 2024

Where it stands: Both determinations operating from 1 April 2025 to 31 March 2030, consolidated as amendments are made

On 20 November 2024 the Commerce Commission made joint final decisions resetting the electricity distribution default price-quality path and Transpower's individual path for 1 April 2025 to 31 March 2030. Distributors were allowed $11.5 billion of revenue, up $3.5 billion, and Transpower $5.9 billion, up $1.8 billion, with a WACC of 7.1 per cent against 4.6 per cent previously and about $10 a month added to the average household bill.

The problem

New Zealand's 29 electricity distribution businesses and Transpower are natural monopolies regulated under Part 4 of the Commerce Act 1986. The networks were built for a static, coal-and-hydro system with modest and predictable load growth; electrification of transport and process heat, rooftop solar and battery export, data centre load and the replacement of assets installed in the middle of the last century all arrived at once. Under the previous paths, set when the weighted average cost of capital was 4.6 per cent, allowed revenue was not enough to fund the replacement, renewal and growth programme that asset health modelling showed was needed, and Transpower in particular faced a step change in both work volume and financing cost. The Commission's problem was to fund that build without passing through every forecast in full, at a moment when consumer bills were already politically sensitive.

What it does

The Commission published its RCP4 final decision on expenditure allowances, quality standards, compliance obligations, information disclosure requirements and revenue path design on 29 August 2024, then made joint RCP4 and DPP4 final decisions on 20 November 2024 and published the final determinations the same day, with both paths beginning 1 April 2025 and running to 31 March 2030. For Transpower the total RCP4 revenue allowance is $5.9 billion, $1.8 billion above projected RCP3, comprising a capex allowance of $2.3 billion (reduced by $110 million for deliverability) and an opex allowance of $1.9 billion (reduced by $62 million), delivered as a 16 per cent annual revenue increase in years one and two and 5 per cent in years three to five, with reopeners available for deliverability and other uncertain expenditure. For the 15 distributors on the default path the total forecast net allowable revenue is $11.5 billion in nominal terms, $3.5 billion above DPP3, with a capex allowance of $5.7 billion, 37 per cent above the DPP3 allowance of $4.1 billion in 2024 constant prices, and an opex allowance of $3.6 billion, 22 per cent above $3.0 billion, delivered as an average 24 per cent revenue increase in year one and lower business-specific increases thereafter; opex step change increases were capped at 5 per cent excluding specified items such as insurance. The WACC applied is 7.1 per cent against 4.6 per cent for RCP3 and DPP3, with 6.9 per cent the average across all regulatory periods. Quality standards were largely retained with minor refinements. An innovation and non-traditional solutions allowance of up to 0.8 per cent of revenue is available, of which 0.2 per cent is reserved for collaborative projects. The Commission amended the Transpower determination on 4 December 2025 in relation to the delivery risk adjustment and published a consolidated version on 1 September 2026 reflecting a government grants income amendment; the consolidated distribution determination was updated on 26 August 2026.

Market effect

This is the largest single increase in New Zealand network charges in the Part 4 era and it moves the delivered cost of electricity for every consumer and every industrial connection. The Commission's own estimate is that the distribution component of a household bill rises on average by $10 a month, or $120 a year, in the first year for affected networks, with a regional range of roughly $10 to $25 a month; transmission charges add to that. For large users and data centres considering New Zealand, the transmission and distribution component of delivered price is now rising faster than the energy component, which changes siting decisions and strengthens the case for embedded generation and behind-the-meter storage that avoids peak network charges. For developers the same decision is an opportunity: $5.7 billion of distribution capex and $2.3 billion of Transpower capex is a five-year procurement pipeline for equipment, contractors and connection works. The 7.1 per cent WACC lifts returns on regulated assets and makes network investment attractive to infrastructure capital. The innovation and non-traditional solutions allowance, and the Energy Competition Task Force's parallel review of the efficiency of grid exit point upgrades, are the channels through which batteries and flexibility services can displace some of that spend, which matters because every deferred upgrade is a permanent reduction in the regulated asset base consumers fund.

Key numbers

Transpower RCP4 revenue allowance
$5.9 billion, up $1.8 billion on RCP3; capex $2.3 billion, opex $1.9 billion
Distribution DPP4 revenue allowance
$11.5 billion nominal, up $3.5 billion on DPP3; capex $5.7 billion, opex $3.6 billion
Revenue increase profile
Transpower 16 per cent in years one and two then 5 per cent; distributors about 24 per cent on average in year one
Weighted average cost of capital
7.1 per cent, against 4.6 per cent for RCP3 and DPP3
Household bill impact
About $10 a month, or $120 a year, on average in the first year

Who gains and who pays

  • Transpower and the 15 default-path distributors (gains): Combined $17.4 billion of allowed revenue over five years at a 7.1 per cent WACC.
  • Households and small businesses (costs): About $10 a month more on average from 1 April 2025, with a regional range of roughly $10 to $25.
  • Large industrial and data centre loads (costs): Rising transmission and distribution charges become a larger share of delivered price.
  • Network contractors and equipment suppliers (gains): A five-year pipeline of $5.7 billion distribution and $2.3 billion transmission capex.
  • Flexibility, battery and non-traditional solution providers (gains): Innovation and non-traditional solutions allowance of up to 0.8 per cent of revenue, 0.2 per cent reserved for collaboration.

Implementation

Both paths began on 1 April 2025 and run to 31 March 2030, applied through determinations that the Commission consolidates as it makes amendments; the Transpower determination was amended on 4 December 2025 for the delivery risk adjustment and consolidated on 1 September 2026 for a government grants income amendment, and the distribution determination was consolidated as at 26 August 2026. Reopeners allow expenditure to be added within the period for defined uncertain events, and the innovation and non-traditional solutions allowance is applied for separately. Aurora Energy remains on a customised price-quality path expiring 31 March 2026 before transitioning to DPP4, and Network Tasman and Nelson Electricity have operated as a single regulated entity since 1 April 2026. The Commission issued an open letter on 25 August 2025 seeking views on whether its approach to default price-quality paths is delivering for consumers, drawing 14 submissions, which will shape DPP5 from 1 April 2030. Input methodologies underpinning the paths are appealable to the High Court on the merits, and the Energy Competition Task Force's grid exit point efficiency review may prompt further regulatory change within the period.

Concerns

  • Affordability: a 24 per cent first-year distribution revenue increase lands with consumers already facing high energy prices
  • Deliverability, since the Commission cut $110 million of Transpower capex and $62 million of opex on that ground
  • Whether the 7.1 per cent WACC over-rewards regulated networks relative to risk
  • Reopeners and amendments adding to allowed revenue during the period
  • Whether non-traditional solutions actually displace network build or simply supplement it
  • Regional inequity in bill impacts, from about $10 to about $25 a month depending on network

Dates to watch

  • 1 April 2027: Third-year revenue step, when Transpower moves to the 5 per cent annual increase profile
  • 31 March 2030: End of the DPP4 and RCP4 regulatory period
  • 1 April 2030: DPP5 and the next Transpower path take effect

Sources

Checked against sources on .

Fast-track Approvals Act 2024 · 149 listed projects, one-stop expert panels, in force 24 December 2024

New Zealand · Parliament of New Zealand (Fast-track Approvals Act 2024, 2024 No 56) · statute · 2024

Where it stands: In force since 24 December 2024, amended 17 December 2025; referral and panel process operating on 149 listed projects

The Fast-track Approvals Act 2024 replaced the Resource Management Act consenting path for nominated infrastructure and development projects with a ministerial referral and an expert panel that grants all approvals at once. Schedule 2 names 149 listed projects, including a large slate of wind, solar and hydro schemes, and the Act was extended and amended by the Fast-track Approvals Amendment Act 2025 in December 2025.

The problem

New Zealand's Resource Management Act 1991 consenting regime had become the binding constraint on energy build. A single wind farm could face council consents, Department of Conservation concessions, wildlife authorities, archaeological authorities and Environment Court appeals, each with its own timetable and its own appeal path, and a project that reached financial viability on paper could lose three to six years and several million dollars in process. Transmission upgrades, geothermal development and grid-scale solar faced the same problem in different sequences, and no agency was responsible for the total elapsed time. With a dry-year security gap opening later in the decade and the National Policy Statement for Renewable Electricity Generation unable to override the procedural burden, the incoming government treated consenting speed, not capital, as the first-order obstacle.

What it does

The Fast-track Approvals Act 2024 received Royal assent on 23 December 2024 and came into force the day after. Its stated purpose in section 3 is to facilitate the delivery of infrastructure and development projects with significant regional or national benefits. It creates a two-step route: a referral application to the responsible Minister, with consultation and notification requirements, reports on Treaty settlement obligations and on the use of public conservation land, and a ministerial decision against the criteria in section 22; then a substantive application to an expert panel convened under Schedule 3, which applies this Act's process instead of the process under each specified Act and can grant resource consents, notices of requirement, concessions, wildlife and archaeological authorities, access arrangements and land exchanges together. Schedule 2 lists 149 projects that may proceed directly to the panel stage without a referral decision, and the list spans wind farms, solar farms, hydro storage, quarrying, mining, housing and transport. Schedule 4 identifies land on which non-mining activities are ineligible, and section 5 defines ineligible activities. Sections 117A and 118 let the Governor-General amend the Schedule 2 description of a listed project and amend Schedule 4 by Order in Council. The Act binds the Crown, carries an explicit obligation relating to Treaty settlements and recognised customary rights, and preserves Te Ture Whaimana, the Vision and Strategy for the Waikato River. The Fast-track Approvals Amendment Act 2025 (2025 No 78) came into force on 17 December 2025, amending the Schedule 2 heading and the referral and panel machinery, adding a Government policy statement power in section 10A, and refining how competing applications and existing resource consents for the same activity are handled. Administration moved to the Ministry for Cities, Environment, Regions, and Transport.

Market effect

For developers the Act converts consenting from an open-ended risk into a bounded one, which is worth more than any subsidy in a market where the cost of capital is the main determinant of a project's levelised cost. Being named in Schedule 2 is itself a valuable asset: it removes the referral decision, shortens the path by months and materially raises the probability of consent, so listed wind, solar and hydro projects trade at a premium and unlisted competitors must either secure a ministerial referral or accept the slower route. The one-stop panel also changes how projects are packaged, since generation, transmission connection and access arrangements can be approved in the same decision rather than sequentially. The market consequence is a step change in the consented pipeline available to bid into power purchase agreements and into the security-of-supply gap that Transpower's 2026 Security of Supply Assessment identifies from 2028 to 2031, and it lowers the risk premium lenders apply to New Zealand renewable development. The counterweight is legal and political risk: panels decide with constrained appeal rights, so contested projects concentrate their challenges into judicial review, and a future government could amend Schedule 2 or the Act's criteria, which is why the December 2025 amendment and the new Government policy statement power matter to anyone underwriting a project on the strength of a listing.

Key numbers

Listed projects in Schedule 2
149 projects able to go directly to an expert panel
Royal assent and commencement
Assented 23 December 2024; in force the day after assent
Amending Act
Fast-track Approvals Amendment Act 2025 (2025 No 78), in force 17 December 2025
Approvals consolidated in one panel decision
Resource consents, notices of requirement, concessions, wildlife and archaeological authorities, access arrangements and land exchanges

Who gains and who pays

  • Developers of listed renewable and infrastructure projects (gains): 149 Schedule 2 projects can go straight to an expert panel for all approvals at once.
  • Lenders and equity investors in New Zealand generation (gains): Bounded consenting timelines cut development risk and the cost of capital.
  • Councils and the Environment Court (costs): Lose jurisdiction over listed and referred projects; appeal rights are narrowed.
  • Iwi, hapu and Treaty settlement entities (mixed): The Act carries explicit Treaty settlement and customary rights obligations but compresses participation timeframes.
  • Unlisted competing developers (costs): Must obtain a ministerial referral or accept the slower standard consenting path.

Implementation

The Environmental Protection Authority receives substantive applications, checks completeness and scope, and passes them to a panel convener who appoints an expert panel under Schedule 3; the Minister decides referral applications and, following the 2025 amendment, decides whether there are competing applications or existing resource consents for the same activity. Listed projects proceed in stages where necessary and the Minister may determine that a project is a priority. The Governor-General can amend Schedule 2 descriptions and Schedule 4 land by Order in Council, so the project list is a living instrument rather than a fixed schedule; secondary legislation has already been made under the Act. Panel decisions are subject to limited appeal, with judicial review the main residual challenge route, and separate consequential amendments touch the Resource Management (Natural and Built Environment and Spatial Planning Repeal) legislation and the Waikato-Tainui Raupatu Claims (Waikato River) Settlement Act 2010. The Act now sits alongside the Planning Bill and Natural Environment Bill, the wider resource management replacement package that was before the Environment Committee in August 2026, so its long-term role depends on how those bills land.

Concerns

  • Narrow appeal rights concentrating challenge into judicial review and creating timing uncertainty anyway
  • Political durability of a project list that can be amended by Order in Council or by a future Parliament
  • Environmental and conservation outcomes where panels weigh national benefit against local effects
  • Adequacy of iwi and hapu participation within compressed timeframes
  • Panel capacity and convener throughput as the pipeline of substantive applications grows
  • Interaction with the Planning Bill and Natural Environment Bill replacing the resource management system

Dates to watch

  • 2027: Panel decisions on the main tranche of listed renewable generation projects
  • 2027: Passage of the Planning Bill and Natural Environment Bill and their interaction with the fast-track regime
  • 2028: Earliest point at which fast-tracked generation can materially close the dry-year energy margin Transpower forecasts

Sources

Checked against sources on .

Zero Carbon framework and NZ ETS settings · auction floor $71 in 2026 falling volumes to 2030

New Zealand · Parliament of New Zealand and the Governor-General in Council (Climate Change Response Act 2002) · statute · 2019

Where it stands: Zero Carbon framework in force since 14 November 2019; ETS unit settings for 2026 to 2030 made 22 September 2025 and operating

The Climate Change Response (Zero Carbon) Amendment Act 2019 gave New Zealand a legislated 2050 target, emissions budgets and a Climate Change Commission. The binding price signal comes from the ETS unit settings: the September 2025 amendment regulations set auction volumes falling from 11.7 million units in 2026 to 5.6 million in 2030, with an auction floor rising from $71 to $87. In 2025 Parliament also weakened the 2050 methane target and repealed the offshore petroleum exploration ban.

The problem

New Zealand's electricity system is already about 85 to 90 per cent renewable, so the country's emissions problem is transport, agriculture and process heat rather than power, and its climate policy had cycled with each government since 2008. The 2019 reform was designed to take the target out of annual politics by legislating it and by creating an independent Commission to advise on carbon budgets. The New Zealand Emissions Trading Scheme is the only broad economy-wide carbon price in the country and, unlike the European system, it covers liquid fuels, industrial process heat, waste and forestry, with electricity generators liable for the emissions of the thermal plant they run. The scheme's weakness was supply: unit volumes and price controls are set by regulation, and getting them wrong either floods the market and collapses the price or starves it and spikes it, which directly moves the short-run marginal cost of Huntly, Stratford, McKee and every other gas or coal unit that sets the wholesale price in a dry year.

What it does

Part 1B of the Climate Change Response Act 2002, inserted on 14 November 2019 by section 8 of the Climate Change Response (Zero Carbon) Amendment Act 2019 (2019 No 61), sets a 2050 target of net zero for all greenhouse gases other than biogenic methane, with biogenic methane 10 per cent below 2017 levels by 2030; the 2050 methane band was amended on 17 December 2025 by section 4 of the Climate Change Response (2050 Target and Other Matters) Amendment Act 2025 (2025 No 80) from 24 to 47 per cent down to 14 to 24 per cent below 2017 levels. The Act obliges the Minister to set successive emissions budgets, requires an emissions reduction plan for each, and establishes the Climate Change Commission with statutory advisory duties. Unit supply is set separately: the Climate Change (Auctions, Limits, and Price Controls for Units) Amendment Regulations 2025 (SL 2025/209), made by Order in Council on 22 September 2025 and notified in the Gazette on 25 September 2025, replaced Schedule 3 of the 2020 principal regulations with settings for 2026 to 2030. New Zealand units available by auction fall from 11.7 million in 2026 to 10.2 million (2027), 8.6 million (2028), 7.1 million (2029) and 5.6 million (2030), with overall unit limits of 16.3, 14.6, 12.7, 11.1 and 9.6 million and no approved overseas units. The auction floor, below which units must not be sold, rises from $71 in 2026 to $75, $78, $82 and $87 by 2030. Two cost containment reserve tranches sit above: in 2026 trigger prices of $203 and $254 release 2.3 million and 4.2 million units, tightening to $248 and $309 for 1.4 million and 2.5 million units in 2030. The same instrument cut bid collateral from five to three working days before an auction and replaced the process for determining auction results. Separately, the Crown Minerals Amendment Act 2025 (2025 No 40, assented 5 August 2025) repealed sections 23A(2), 24(5A) and 25(2A) of the Crown Minerals Act 1991, removing the 2018 restriction that confined new petroleum exploration permits to onshore Taranaki, and added a Government Policy Statement power over minerals.

Market effect

The auction floor is the practical carbon price floor for New Zealand thermal generation, and at $71 a tonne in 2026 it adds roughly $28 to $30 per MWh to a combined-cycle gas plant at about 0.4 tonnes per MWh and around $60 per MWh to Huntly's coal-fired Rankine units at roughly 0.85 tonnes per MWh. Because thermal plant sets the wholesale price in dry and peak periods, the escalating floor feeds straight into the forward curve that generators, retailers and large industrial buyers trade, and the rising path to $87 by 2030 steepens that effect just as declining domestic gas supply raises fuel cost. Falling auction volumes, from 11.7 million to 5.6 million units over five years, tighten the scheme's supply side and shift the marginal unit toward forestry removals and surrendered stockpile, which is why forestry conversion economics now compete directly with pastoral land use. The cost containment reserve at $203 in 2026 caps the plausible near-term upside for hedgers. The 17 December 2025 weakening of the 2050 methane target and the August 2025 repeal of the exploration ban both point in the opposite direction, signalling to gas explorers and to emitters that the policy path is again contestable, which widens the risk premium on long-dated carbon and gas positions rather than narrowing it.

Key numbers

Auction volumes 2026 to 2030
11.7, 10.2, 8.6, 7.1 and 5.6 million New Zealand units
Auction floor price
$71 in 2026 rising to $87 in 2030
Cost containment reserve triggers in 2026
$203 releasing 2.3 million units and $254 releasing a further 4.2 million
Overall unit limits 2026 to 2030
16.3, 14.6, 12.7, 11.1 and 9.6 million units, with no approved overseas units
2050 targets
Net zero for gases other than biogenic methane; methane 14 to 24 per cent below 2017 (amended 17 December 2025)

Who gains and who pays

  • Thermal generators (gas and coal-fired plant) (obligation): Surrender units for combustion emissions; the auction floor sets a hard carbon cost per MWh.
  • Renewable generators and storage (gains): A rising thermal marginal cost lifts the wholesale price they receive without a corresponding carbon liability.
  • Forestry and carbon removal project owners (gains): Falling auction volumes make forestry removals the marginal source of units.
  • Industrial process heat and liquid fuel users (costs): Pay the unit price through fuel and energy contracts across the whole economy.
  • Petroleum explorers (gains): The 2025 repeal of the onshore-Taranaki restriction reopens offshore exploration permitting.

Implementation

The Environmental Protection Authority runs the quarterly auctions and the unit register; the Ministry for the Environment produces the regulatory impact statement behind each annual settings update, in this case dated 5 August 2025, and the Minister makes the amendment regulations by Order in Council, normally in September for the following five years. That annual cycle is the single most important recurring date in the New Zealand carbon market, because each update rolls the five-year window forward and can change both volumes and price controls. Emissions budgets and emissions reduction plans run on a separate five-yearly cycle under sections 5X to 5ZH of the Act, with the Climate Change Commission advising and the Minister responding. Section 5QA requires the Minister and the Minister of Agriculture to initiate a review of the biogenic methane target, and the December 2025 amendment has reset the band that a future review will test. The Crown Minerals changes require new minerals programme and permitting work by the Ministry of Business, Innovation and Employment before block offers can resume offshore.

Concerns

  • Policy reversibility: the 2050 methane band was weakened in December 2025 and the exploration ban repealed in August 2025
  • A large privately held unit stockpile can mute the effect of falling auction volumes
  • Forestry-dominated supply concentrates scheme integrity risk in one sector
  • Carbon cost passes into electricity prices in exactly the dry periods when thermal plant is most needed
  • Annual settings changes make long-dated carbon and electricity hedging expensive
  • Uncertainty over whether renewed offshore exploration will deliver gas before the late 2020s supply gap

Dates to watch

  • 2026-12: Final NZ ETS auction of 2026 under the new volume and price control settings
  • 2027-09: Expected annual amendment regulations updating unit limits and price controls through 2031
  • 2030: Auction volume falls to 5.6 million units and the auction floor reaches $87

Sources

Checked against sources on .