David Haugh
OECD Economic Surveys: New Zealand 2026
Abstract
New Zealand’s electricity system is highly renewable but increasingly exposed to security and affordability pressures as domestic gas supply declines and hydro variability intensifies. With electricity demand set to rise sharply from transport and industrial electrification and data‑centre growth, the central challenge is ensuring sufficient seasonal (dry-year) firming rather than expanding renewables alone. Subject to a normalisation of international markets, gas and LNG can help manage short‑term security risks. However, they are not a long-term affordability solution and risk locking in fossil‑fuel dependence and would further exacerbate New Zealand’s already high vulnerability to liquid fuel import stoppages and price volatility. Breaking the gas–electricity price link requires rapidly scaling non‑gas seasonal (dry-year) firming, such as biomass, pumped hydro and geothermal. This could be supported by Crown minority co‑investment to overcome structurally weak investment incentives. Competition remains constrained by gentailer dominance and limited access to seasonal firming for independents; a Firming and Flexibility Market (FFM) and strengthened conduct rules would reduce barriers to entry and lower risk premia. Planning and gentailer governance reforms are essential to accelerate investment and ensure a secure, affordable, and sustainable electricity system.
New Zealand’s electricity system has long been highly renewable and dominated by hydro and increasingly geothermal generation (Figure 2.1). Its current trials, while unique in some respects, reflect the pressures that arise when very high renewable shares are reached while flexible thermal capacity, notably gas, declines. Supply shortages and high prices are hurting households and accelerating deindustrialisation. Generation capacity is low and unbalanced. Compounding these challenges, after a long period of stagnation, demand is set to grow strongly due to the electrification of transport and industry and the growing use of AI. Demand is expected to grow by 60% by 2040, if innovation permits rapid electrification of transport and process heat (MBIE, 2024a). As electrification accelerates, the central challenge is securing seasonal (dry‑year) firming—dispatchable supply available for weeks or months—along with sufficient short-duration flexibility to replace the declining role of gas, rather than simply adding renewables or focusing on peak‑shaving as in most other OECD countries.
Source: OECD, Green Growth database.
Rapidly dwindling gas supplies have markedly weakened the system’s long-standing seasonal firming generation solution that provides reliable backup energy during “dry years” when hydro generation is constrained. A lack of reliable seasonal firming generation at a reasonable price is a major vulnerability, driving up electricity futures prices and undermining industrial competitiveness (Frontier Economics, 2025; MBIE, 2023; OECD, 2024). A May 2025 survey found that 25% of businesses reduced production and a similar share reported job losses due to high electricity costs (MEUG, 2025).
To boost investment in seasonal firming, the government is co-investing in increasing domestic gas production availability and proceeding with an LNG import terminal. While these steps may ease short-term security of supply pressures, they are not likely to materially improve electricity affordability and risk locking in fossil fuel dependence, weakening investment signals for competing seasonal (dry-year) firming technologies such as biomass (wood), or pumped hydro. Demand response is usually for peak shaving but a limited number of industrial sites such as the aluminium smelter can also offer extended, multi‑week demand reductions during low‑hydro periods. This chapter therefore argues for a careful recalibration of gas‑use policy to manage short-term security risks without undermining long‑term decarbonisation and affordability goals. It then outlines how to build on current reforms to ensure sufficient non-gas seasonal firming and short-duration flexibility during extended hydro shortages. Limited access to seasonal firming and demand flexibility for independents is a major entry barrier. The chapter proposes replacing vertically integrated generator-retailer (gentailer) controlled bilateral deals with a public firming and flexibility market, strengthening EA powers, and reforming market rules. It also recommends adapting gentailer financial strategies, especially payout ratios, to support investment in a high-electricity-demand future.
New Zealand’s electricity system was largely developed by the state between the 1950s and 1980s on a foundation of hydroelectric generation. Today, renewables account for about 75% of installed generation capacity and supply around 85% of electricity consumed, one of the highest shares in the OECD (Table 2.1). As a result, New Zealand’s electricity generation has very low greenhouse gas (GHG) emissions, around 94 gCO₂/kWh, making it one of the most carbon-efficient electricity systems in the OECD (Box 2.1).
Share of generation, per cent, 2024
Note: The table shows the generation normally produced rather than the share of installed capacity.
Source: Energy in New Zealand – Countries and Regions IEA, and IEA Monthly Electricity Statistics.
Increasing renewables electricity to electrify industry and transport is key to New Zealand’s strategy to achieve net zero emissions of all greenhouse gases except biogenic methane by 2050 and this transition will proceed more rapidly if electricity prices remain affordable. Meeting the net zero goal requires a major expansion of renewable electricity generation to enable electrification of transport and industrial heat, which currently rely heavily on fossil fuels. The government’s July 2024 climate strategy aims to double renewables by 2050 and install 10 000 EV chargers (Ministry for the Environment, 2024) by 2030. However progress is slow with EV chargers expanding from 1024 at the end of 2023 to only 1466 at the end of 2025. While official estimates are lacking, rough calculations suggest wind and solar potential is several times the current annual generation. For instance, converting 2.5% of farmland (circa 3 000 km²) to a 50/50 mix of wind and solar could yield 100 TWh—2.5 times current output. Super-critical geothermal could add another 40 TWh. However, achieving this requires resolving current electricity system issues.
Electrification is also critical for supporting low-carbon economic growth because emissions reductions in hard-to-abate sectors like agriculture will be limited under current policy settings, so deeper cuts in energy-related emissions are essential to compensate. Agriculture remains the largest emitter (over 50%), mainly methane. In October 2025, the government revised the 2050 biogenic methane target to 14–24% below 2017 levels (down from 24–47%) and chose not to price agricultural emissions, relying solely on technology (Climate Change Commission, 2025). This risks undermining future emissions budgets and shifting the burden to other sectors. A stronger institutional framework is needed to better align climate goals with land use, infrastructure, and agricultural policy (PCE, 2024). Agricultural methane remains disproportionately high, and voluntary tech-based approaches may fall short of international commitments (OECD, 2024).
New Zealand’s electricity system is increasingly vulnerable to extreme weather, as seen during Cyclone Gabrielle, which left 240,000 customers without power and exposed weaknesses in overhead lines and substations (Electricity Networks Aotearoa, 2023). While Transpower’s Climate Adaptation Plan and the Government’s National Adaptation Plan mandate risk assessments and upgrades (Transpower, 2024; MfE, 2022), incremental measures are insufficient. New Zealand must adopt system-wide resilience planning, including mandatory climate risk assessments, stronger design standards, and market incentives for resilience investments and not just renewable generation (IEA, 2023a). Greater use of distributed energy resources, microgrids, and storage is also needed to reduce single points of failure and enhance flexibility (IEA, 2022a).
The highly renewable and hydro-based system meant that for a long time, New Zealand’s electricity prices were cost-competitive, supporting, alongside cheap and plentiful domestic natural gas, the development of energy intensive industries, including aluminium smelting, steel production and food and wood products processing. Despite these advantages, the electricity system has some important geographical challenges. First, distance from other countries implies no connection to another country’s electricity network. There is also no LNG terminal to import gas. Therefore, self-sufficiency in electricity and gas is required. Second, around 75% of installed hydro capacity, the baseload of the system, is concentrated in the south of the South Island, whereas around one third of electricity demand is in Auckland, the largest city and around 1 000 kilometres from the major hydro power stations.
These locational features create systemic exposure of electricity generation to rainfall conditions. Indeed, the most important security of electricity supply issue is the so-called “dry-year” problem, where hydro storage and generation falls due to insufficient rainfall. The electricity system is particularly vulnerable to rainfall patterns in the South Island, especially during “dry years”—typically 3–4 months of low rainfall affecting hydro catchments. This core security of supply issue stems from limited hydro storage: just 4 TWh (10% of annual generation), compared to 70–80% of generation in Norway. Despite high dam walls and steep, mountainous terrain, geography (fewer wide deep valleys and high-altitude glacial lakes than Norway) and public opposition to land flooding have led to a mainly run of river design constraining storage capacity. This forces generators to reduce output during dry spells. Over the past 25 years, dry years, defined as hydro storage falling 50 billion cubic metres below the long-run average, have occurred every 3 to 5 years, including in 2001, 2005, 2008, 2012, 2017, 2021, and 2024 (Figure 2.2).
Note: Four quarters moving average.
Source: New Zealand Electricity Authority and Ministry of Business, Innovation and Employment.
Since the introduction of new exploration techniques by Shell and the discovery of the Maui gas field in 1969, gas-fired generation has become the main firming solution, as in many OECD countries. Gas offers fast ramp-up, lower emissions than coal, and was historically affordable due to steady exploration and stable reserves. This ensured both electricity security and affordability, as gas-fired plants, often the marginal generators during low hydro periods, set electricity market prices based on spot gas prices, tightly linking the two (Figure 2.3).
Source: New Zealand Electricity Authority and emsTradepoint.
New Zealand’s delicate gas–electricity market balance has been disrupted by a sharp decline in domestic gas production since 2018. This came to a head in the 2024 dry year. As reserves dwindled, wholesale gas prices surged, reaching NZD 30–40/GJ. With hydro storage critically low, hydro generators - the marginal producer - raised the offer price significantly, with a ceiling effectively set by the next alternative, gas generation, which also raised offer prices sharply due to a shortage of fuel and high gas prices. This dynamic drove wholesale electricity prices sharply higher, with daily averages peaking at over NZD 800 per MWh in early August, up from typical winter levels of around NZD 180 per MWh. For several days, spot prices exceeded NZD 300 per MWh before falling back as emergency measures, including Methanex releasing gas and increased rainfall, eased supply constraints.
Even more concerning is that falling gas production and reserves and uncertainty about their future trajectory has contributed, along with significant uncertainty about government policy, to pushing up longer-term contract electricity prices, forcing temporary and permanent industrial shutdowns, and markedly raising the risk of rapid deindustrialisation (Box 2.2). As a result, wholesale spot and forward contract prices, which were previously low, have risen sharply. They are now uncomfortably high in international comparison. Indeed, they are now far higher than in the Nordic countries with similarly renewables dominated systems (Figure 2.4).
New Zealand’s energy crisis threatens key export sectors—agriculture, forestry, horticulture, and manufacturing—due to their reliance on gas-fired and electricity-intensive processes. With gas supplies dwindling and firming capacity insufficient, industrial demand curtailment has been widely used to maintain grid stability, though at high economic cost. Methanex temporarily shut its Taranaki methanol plants, redirecting gas to generators (Methanex, 2024), while Ballance Agri-Nutrients warned of possible shutdowns over long-term gas contract issues. A survey found nearly half of large industrial gas users had already cut operations, raised prices, or reduced staff, with 30% expecting to follow within a year (BusinessNZ Energy Council, 2025). In 2024, several wood processors, including Winstone Pulp, Oji Fibre Solutions, and Pan Pac, closed or suspended operations due to unsustainable electricity prices, with Winstone’s closures alone costing 230 jobs in Ruapehu. Oji shut paper mills at Penrose and Kinleith mills.
1. Excluding the period between July 2021 and February 2023 for the European countries when electricity prices in Europe reflected a temporary boost due to the large increase in gas prices arising from Russia’s illegal war of aggression against Ukraine.
2. Wholesale electricity long-dated futures price.
Source: New Zealand Electricity Authority and Ember Energy.
In a fully functioning market with access to large natural resources to build new electricity generation, high prices should be at least partially reversed as generation investment increases in response to higher potential profits. The upward trend in spot and especially forward contract prices electricity prices since 2018 provides a strong signal to build new generation. Encouragingly, after very little investment in generation for more than a decade, there is a solid investment pipeline of intermittent wind and especially solar projects (Figure 2.5). Wind and solar installed generation increased by 577 and 421 MW, respectively, from 2020 to 2024. Installed capacity is projected to increase even more rapidly by around 1 450 MW for wind and 1 370 MW solar from 2025 to 2032.
Installed capacity
Note: Projected installations from 2025-2032 including commissioned, committed and actively pursued projects.
Source: OECD Calculation using MBIE and Electricity Authority data.
An insufficient increase in installed generation through to 2025, especially an unbalanced mix with a stagnation in seasonal firming generation, has left a risk of a breach of security standards in 2026, especially if there are delays in the building of new generation building (Transpower, 2025; Transpower, 2026). If supply was responding properly to high electricity prices, then arbitrage should roughly equalise wholesale forward contract price of electricity and the marginal cost of building new generation. However, contract prices remain well above this level, even allowing for increasing construction costs. This margin reflects an elevated risk premium and the marginal cost of the plants that provide multi-week seasonal firming during dry years.
Over the past decade, investment in new generation assets has been plagued by uncertainty coming from three main sources (Table 2.2). Two of these around the level of total demand and supply of the system have been resolved, opening the door to renewables investment. The remaining barrier concerns the viability of seasonal firming options, which has multiple dimensions. Uncertainty about future gas availability constrains investment in new thermal plant. But investment in other long‑duration firming technologies, such as pumped hydro and biomass, faces different challenges, including long consenting processes, high upfront capital requirements, and uncertain long‑duration revenue streams. These factors collectively raise the cost of firming and contribute to persistent forward‑market premia.
Source: OECD Secretariat.
Gas plays a large role in the electricity system providing both a peaking and seasonal firming role and is the marginal and therefore market price setter around 70-90% of the time (BCG, 2025). Even in ordinary years, gas typically supplies around 300 MW of generation outside dry-year conditions. Improving electricity security, and industrial resilience requires managing near-term gas tightness without deepening long-run dependence. The IEA has highlighted New Zealand’s need for more peaking and seasonal firming capacity and better demand management to support its high renewable shares (IEA, 2023a). Gas supply could be increased through domestic production and the Government’s decision to contract for an LNG import facility intended to backstop dry‑year risk. However, a prudent strategy under high uncertainty is to reduce electricity’s structural dependence on gas by progressively replacing gas peaking with batteries and expanding non‑gas seasonal firming generation (e.g. pumped hydro), supported by greater demand‑side flexibility.
The decline in domestic gas production (Figure 2.6) stems from a combination of mature fields underperforming expectations, downward reserve revisions, and reduced development success, policy uncertainty and the 2018 exploration ban. New Zealand has seen over NZD 1 billion in development investment since 2020, but results have been disappointing, with low gas finds (MBIE, 2025a). Production fell 21% year on year in 2024 several fields performing well below prior forecasts; MBIE now expects annual production to drop below 100 PJ by 2026, earlier than previously projected. These production shortfalls, rather than demand alone, pushed wholesale gas prices higher and tightened gas availability for electricity generation in 2024 and 2025. Mitigating this trend requires restoring investor confidence through clearer policy signals and support for exploration.
Source: Ministry of Business, Innovation and Employment.
With foreign majors exiting or downsizing, New Zealand faces gaps in capital, rigs and specialist capability for large offshore projects. Even if modest new supply were secured, it would not materially change the long-term structural decline in domestic gas availability. Industry testimony confirms that new large-scale development would require bringing an offshore rig to New Zealand. This is a high fixed-cost investment that demands multiple exploration projects over 2-3 years to be viable. Given limited opportunities in Taranaki and high-risk prospects elsewhere, the likelihood of major new discoveries is low. Experience in New Zealand and OECD countries shows that large developments rely on foreign joint ventures, which are unlikely to return without compelling prospects.
Even with exploration success, supply may still fall short of household, industrial, and electricity generation needs. Residential demand is modest and could be met with alternatives, like biogas from waste treatment. However, current electricity generation requires around 30 PJ of gas, about 30% of domestic 2025 supply, and no recent field discovery exceeds this. Without foreign expertise and capital, the chance of developing large new fields remains low. Incentives to explore have also been reduced by the impending closure of the largest gas user, Methanex, removing a stable source of long-term demand. While Methanex’s exit would ease average gas demand-supply pressures, it would also remove the system’s main source of demand-side flexibility in dry years. This underscores why gas cannot remain the backbone of seasonal electricity firming.
Given the difficulty of boosting domestic supply, the government has opted for LNG imports. LNG can, in principle, provide insurance against dry‑year shortages and may reduce the dry-risk premium in forward markets. By compressing the dry‑year risk premium MBIE’s analysis indicates LNG availability could reduce forward electricity prices by at least NZD 10 per MW but this will be partially offset by a levy on electricity to pay for the terminal. Public studies for industry and the Gas Industry Company (GIC) show LNG is technically feasible but costly, with options ranging from small‑scale shuttle concepts (higher landed gas cost, lower capex) to conventional‑scale terminal (lower unit gas cost, higher capex). Both likely require strong government facilitation (e.g., consenting) to deliver on schedule (Gas Industry Company – EY, 2024; Chapman Tripp, 2024; Enerlytica, 2023).
The Government has announced it intends to contract an import facility at conventional scale at a cost of at least NZD 1 billion and use it to supply seasonal firming generation. In the absence of LNG, the most likely counterfactual is not stable, low-priced domestic gas, but increasing scarcity as domestic supply declines, leading to curtailment of non-electricity users. The introduction of LNG would alleviate quantity shortages but would fundamentally change gas price formation. Once LNG is in place, the international LNG price would set the New Zealand gas price, leaving both gas-fired generation and electricity prices in dry years or whenever LNG gas fired generation is the marginal producer exposed to global gas price volatility (Figure 2.7). Without adequate non‑gas seasonal firming, gas prices will continue to set marginal electricity prices both during dry and indeed most of the time, keeping wholesale and forward prices elevated.
Source: The World Bank; Ember Energy Research; emsTradepoint; and OECD calculations.
For many internationally‑exposed industries, LNG‑linked energy prices would likely be too high to sustain competitiveness, risking further rapid deindustrialisation. Experience shows the market will resolve a gas shortage by allocating gas to the highest bidder, electricity generation, forcing industry, a major gas user with no short-term practical substitutes to gas for heat processes and feedstock (fertiliser), to close. Electricity generators can pay more not because this is a higher value-added activity, and therefore this would be an efficient allocation, but because they have market power that industry does not. Unlike industry, electricity generators in New Zealand do not face foreign competition and have strong market pricing power to pass on these costs to electricity users, notably industry, which ends up with no or very high-priced gas and high-priced electricity.
Public sponsorship of LNG risks locking‑in fossil dependence and weakening incentives for alternatives such as biomass, pumped hydro and demand response. The conflict in the Middle East underlines that introducing reliance on LNG would exacerbate New Zealand’s already high vulnerability to imported liquid fuels shortages. In addition, it would create a single-point-of-failure risk because there is only one viable port of entry in Taranaki.
These considerations call for using LNG, if used at all, as a short-term transition tool to meet dry-year seasonal firming needs only. This implies keeping up-front capital expenditure on gas, port and electricity plant to a minimum, even if this results in temporarily higher unit gas costs, and relying on coal where necessary, while accelerating sustainable solutions such as electrifying industry and transport and scaling non-gas seasonal firming generation (Table 2.3). As part of the transition package, limited investment in gas storage could be considered, including the potential use of the depleted Tariki field, subject to further work confirming technical and commercial feasibility. If viable, gas storage would allow existing domestic gas supply to be shifted across time rather than increasing total gas use, directly addressing the fuel‑availability constraint that drove extreme price spikes in winter 2024. However, even if feasibility were confirmed, gas storage would not resolve the long‑run decline in domestic gas supply and therefore cannot substitute for sustained investment in non‑gas seasonal firming.
Note: Pumped hydro is a storage technology and therefore costs are expressed per MWh of storage capacity rather than per MWh generated. Cpital costs for wind and Solar Overbuild are very high because they include the capital required to replace gas‑based seasonal firming using intermittent renewables plus long‑duration storage, which is pumped hydro. Cost estimates for biomass CHP are based on EPA and IEA benchmarks for modern high‑pressure CHP plants, with lower running costs reflecting mature Nordic‑style wood‑chip supply chains (EPA, 2007; Hansen, 2022; OECD, 2025). Higher estimates used in MBIE modelling reflect pellet‑based systems and immature domestic supply chains. LCOE: Levelised Cost of Electricity.
Source: IRENA, MBIE (2024b), Interactive Levelized Cost of Electricity Tool; IEA (2023) Renewable Energy Market Update; PwC (2024), National impacts report: New Zealand offshore wind industry; EA (2024) The levelised cost of electricity; National Renewable Energy Laboratory (2024), Offshore wind: 2024 annual technology baseline; Hansen, M. (2022) IEA Bioenergy Task 32: Biomass combustion—Final task report 2019–2021; U.S. Environmental Protection Agency (2007), Biomass combined heat and power catalog of technologies; OECD (2025), OECD Economic Survey of Finland.
Many medium‑sized industrial users can technically switch to electric boilers and heat pumps, but face up‑front investment and network‑upgrade hurdles. Targeted support, such as concessional loans or accelerated depreciation, may be justified where electrification has a viable business case. Sudden industry closures can create path dependencies, reducing the capacity to move to new industries and grow new exports. The pulp and paper industry, for example, is a key developer and source of know-how for the green industrial transition in Finland, including advanced materials and power-to-X technologies (OECD, 2025a).
Battery investments are taking place to help replace gas peaking generation. However, despite high prices, no significant seasonal firming generation has been built. Back-of-the-envelope estimates suggest that covering an average dry-year hydro shortfall of around 1.6 TWh over six months would require roughly 400 MW of seasonal firming. In addition, to fully break the link between gas and electricity prices, the around 300 MW of gas generation used in ordinary years must be replaced.
Genesis Energy maintains up to 750 MW of coal-fired capacity at Huntly and is building a 600 000-tonne coal stockpile to increase coal use during dry years. However, this is only a temporary measure and cannot fully replace gas seasonal firming, as the coal units cannot operate at full output for extended periods without significant maintenance and fuel constraints. Running Huntly at 700 MW for six months would require more than 1.2 million tonnes of coal, over twice the size of the planned stockpile, highlighting the limits of this approach. Replacing gas for seasonal firming needs in the medium-term would require replacing at least 700 MW of gas generation (around 300 MW used in ordinary years plus 400 MW extra in a dry year) with low-emissions firming capacity to phase out coal, reduce emissions, and permanently break the gas–electricity price link. Moreover, hydro shortfalls can spike well above 400 MW for several weeks if inflows are very low. For security of supply in the longer run to completely replace gas generation, actual investment may need to exceed 1 000 MW, supplemented by seasonal storage to manage prolonged dry spells.
Seasonal firming has not been built in New Zealand because the investment case is structurally weak: revenues arrive only in infrequent dry years, making cashflows lumpy and uncertain, undermining bankability for investors who must commit large upfront capital for assets used intermittently. At the same time, renewables projects such as pumped hydro have faced long consenting times although these are now diminishing due to planning reforms including fast tracking. Biomass firming faces fuel‑supply coordination problems, geothermal exploration risk, and high capital intensity, and gas generation faces fuel shortages. The absence of a market instrument that pays for multi‑week or multi‑month flexibility means developers cannot monetise firming value in advance, and without revenue certainty, neither gentailers nor new entrants can finance long‑duration firming projects.
Significant business case uncertainties mean a market-led, Crown supported solution could be needed, alongside changes in market design discussed below. Crown involvement in the form of minority co-investments in non-gas seasonal firming generation to demonstrate solid backing for moving away from gas entirely may be needed for over-coming reluctance to building new non-gas seasonal firming generation and crowding in private sector investments.
Viable alternatives to gas seasonal firming include biomass, pumped hydro, and geothermal. Each option involves trade-offs in cost, emissions, and flexibility, making centralised planning alone unlikely to deliver an efficient outcome. Biomass (wood) offers a potential balance of fuel availability, moderate emissions, and lower price volatility compared with gas (Box 2.3). Large-scale biomass generation is proven in countries such as Finland and Sweden and could enhance competition if developed by existing wood processors with boiler expertise. Coal-fired generation remains low-cost and quick to deploy but carries very high emissions and exposure to global fuel price swings. Geothermal provides reliable, low-emissions baseload capacity, making it suitable for seasonal firming but capital costs are high. Wind and solar overbuild combined with seasonal storage solutions such as pumped hydro can deliver scalable, zero-emissions firming, but may require very high upfront investment.
Wood (biomass) electricity generation is an underutilised but promising part of New Zealand’s renewable energy mix. It offers firming capacity to complement intermittent renewables and help address dry-year risks. Sustainably sourced biomass, especially in combined heat and power (CHP) systems, can provide dispatchable renewable energy and enhance regional resilience (IEA, 2023b). Although biomass makes up about 7% of New Zealand’s primary energy supply, it is mostly used for industrial process heat rather than electricity (MBIE, 2025b). In contrast, countries like Finland and Sweden, have successfully integrated wood biomass into their electricity and heat systems. Finland generates over 13% of its electricity from biomass, mainly via CHP plants at pulp and paper mills (IEA Bioenergy, 2023).
New Zealand has significant potential from fast-growing plantation forests. Forestry and processing residues could sustainably supply 4 million tonnes of biomass annually (Scion, 2024). This is enough to generate around 7 TWh or 16% of total electricity demand. Much of this biomass, including in-forest residues and sawmill by-products, remains underutilised. The 2025 Wood Energy Strategy prioritises biomass for process heat decarbonisation and includes modest funding for supply chain development. However, it lacks a clear roadmap for scaling up electricity generation. Genesis Energy’s plan to co-fire up to 300 000 tonnes of biomass annually at Huntly by 2028 is a promising step (Genesis Energy, 2025), but broader government support may be needed for non-gentailer projects to boost competition in seasonal firming generation.
A practical next step would be targeted capital support for CHP expansion projects in high-potential regions, like Kinleith, Kawerau and Whirinaki, which already have CHP related infrastructure, biomass feedstock and industrial heat demand. Additional opportunities exist in Southland and Northland, where surplus biomass and industrial users could support regional CHP systems and improve energy resilience. A firming and flexibility electricity market (see below) could incentivise private investment, and clarifying ETS treatment of biomass would support investor confidence. Importantly, the Wood Energy Strategy envisions mobilising not just waste but also uneconomic-to-export material, like slash, thinnings, and storm-damaged wood. Scaling up would require harvesting low-grade logs and residues, chipping them on-site, and transporting them to regional hubs. This would need investment in mobile chippers, transport, and drying infrastructure to ensure year-round supply and consistent fuel quality.
With the right regulatory and planning framework, the private sector can partially address these trade-offs. However, investment in seasonal firming generation is unlikely without overcoming the barriers described above. Indeed, recent investor presentations confirm that three of the four gentailers plan no long-term firming projects for dry-year cover, while Genesis is focused on securing coal for Huntly. Genesis has signalled interest in burning biomass (wood waste) instead of coal and has signed a term sheet with Foresta to supply torrefied biomass, targeting 300,000 tonnes annually by 2028. However, this ambition is highly contingent on developing a domestic supply chain and likely requires Crown co-investment, given the scale, cost, and technical challenges involved.
The Crown has signalled and started to invest in the gentailers to support investment in new generation. To catalyse supply and competition, Crown minority equity could prioritise independent‑led non-gas seasonal firming projects, alongside market design changes that provide long‑duration revenue certainty. This would strengthen competition, diversify ownership, and avoid reinforcing vertical concentration. Diversifying across multiple projects would spread financial and natural disaster risk. The minority nature of the investments would leave the market as the main determinant of prices and output Further guardrails to mitigate market mitigation risks are using open, competitive tenders, time-bound declining support and no guaranteed offtake.
A publicly announced government strategy to break the dependence of the electricity market on gas could bring immediate gas and electricity price relief to households and industry, if backed by minority stake Crown co-investments in non-gas firming. This is because, if backed by material funding and therefore credible, the market would immediately price in the increased probability of a better balance between future demand and supply in gas and electricity markets. This would be especially the case if this new seasonal firming is available to new entrant renewables generators and independent retailers, as extremely limited access to firming and flexibility options is the principal barrier to entry. Leaving industrial users as the main consumers of gas could also encourage greater gas exploration that requires long-term steady gas purchase contracts, which industry is more likely to be willing to enter than electricity generators looking for firming and peaking supplies only.
Increasing competition and ensuring regulation is competition-friendly are essential levers to lower prices and improve electricity system and economy-wide productivity (Box 2.4).
A policy of increasing competition is key to lifting sectoral performance and New Zealand’s low aggregate productivity as it provides a powerful incentive to firms to innovate and reduce costs (OECD, 2024a). As highlighted in the OECD New Zealand Economic Survey of 2024, productivity growth is severely impeded by New Zealand’s highly concentrated markets, particularly in banking, construction and building materials, energy and groceries. Exclusive supply agreements are used to limit access to essential inputs at a reasonable price. Vertically integrated Incumbents often exploit their power to tie up access to essential inputs from energy, land or wholesale groceries for their retail arms. Despite few convictions due to excessively tight criteria and inadequate powers assigned to the Commerce Commission, predatory pricing has been pervasive in many industries for decades. These problems have been compounded by out-of-date regulations in areas such as in digital markets (OECD, 2025b).
The government has introduced significant framework reforms to modernise competition regulation and raise competition across the economy including crucially reinforcing the powers of the Commerce Commission (Table 2.4).
These welcome steps are in line with past OECD recommendations and paying off. Armed with new powers and a mandate to act by the government, the Commerce Commission has issued specific behaviour guidelines and stepped up its enforcement actions, filing criminal charges against the grocery incumbents and fining a major retail chain for predatory pricing. It has also filed proceedings against the dominant building materials firm for anti-competitive behaviour. In a welcome move the maximum fine for breaches of the Fair-Trading Act has been increased from NZD 600 000 to NZD 5 million. However, this is still far below the Australian maximum fine of around NZD 60 million and should be increased further if it proves insufficiently dissuasive of anti-competitive behaviour by large incumbents.
Regulatory modernisation should be accompanied by greater efforts to tackle entry barriers created by market structure or incumbent behaviour. While sector-specific measures have been taken such as open banking and fast-track approvals for grocery entrants, marked entry barriers remain, and incumbent market shares are not falling. Mutual standards recognition, such as the reform to allow the use of overseas-certified building products, can quickly increase the range of high-quality inputs to generate more competition in a market where essential inputs such as plasterboard are a virtual monopoly.
Mutual recognition can be complemented by creating essential input markets domestically (e.g., wholesale groceries or firming electricity), applying non-discriminatory supply rules, and linking compliance to supplying in those markets. The technical and market specific nature of these types of rules call for granting the Commerce Commission code writing powers. Several OECD jurisdictions grant competition authorities flexible powers to develop and enforce industry codes as a complement to traditional enforcement. The Australian Competition and Consumer Commission, for example, administers mandatory codes approved by Cabinet across sectors such as franchising and energy. The UK’s Competition and Markets Authority now has similar rule-making powers under the Digital Markets, Competition and Consumers Act 2024, and Nordic authorities are considering market investigation tools modelled on this approach. By contrast, the Commerce Commission lacks such authority and relies on court-based remedies, limiting its ability to address structural competition issues promptly. Granting the Commission code-making powers akin to the ACCC would align New Zealand with OECD best practice and the international trend toward ex ante regulatory instruments to complement traditional enforcement in concentrated and digitally disrupted markets (OECD, 2021).
New Zealand’s electricity market design is “textbook best practice” in many respects, including locational near real time marginal pricing (Table 2.5). However, market structure, notably dominance by vertically integrated generator-retailers (gentailers), and an even higher concentration of firming assets is limiting competition in both the spot and price hedging markets. A lack of access to sufficient firming generation contributes to a lack of competition, is a barrier to entry for independent and generators, and is the cause of unaffordable electricity for industry.
Source: OECD Secretariat; New Zealand Electricity Authority; PJM Interconnection; United States Intercontinental Exchange; Nord Pool (Europe); Electric Reliability Council of Texas (ERCOT); United Kingdom National Grid ESO; Australian Energy Market Operator; Australian Energy Regulator; California Public Utilities Commission; Commission de Regulation de L’Énergie; Ontario Energy Board; Ofgem United Kingdom; and Nordic Energy Regulators.
Electricity generation and retailing is dominated by four vertically integrated gentailers, Genesis, Meridian, Mercury, and Contact, who produce around 90% of total generation (Table 2.6). Contact is fully privately owned, while the others operate under a mixed ownership model, with 51% Crown ownership and 49% listed on the NZX. Despite partial state ownership, these firms are managed commercially at arm’s length. Vertical integration has pros and cons. It offers financial discipline and efficiency benefits, such as avoiding double marginalisation and improving coordination between generation and retail. This can help shield consumers from wholesale price shocks and support financial stability (Meade, 2021). However, it also limits competition and is not best international practice (Castle and Varriale, 2026). Gentailers can use internal transfer pricing to supply their retail arms at generation cost, while maintaining high wholesale prices for independent retailers. Since 2018, wholesale prices have risen faster than retail prices, and over twenty small retailers have exited the market, citing unaffordable hedges and squeezed margins.
These competition problems are exacerbated by an even more concentrated distribution of firming assets. Market power can be episodic, with hydro dominant portfolios exerting more influence in wet years (controlled in the South Island by Meridian and North Island by Mercury), and thermal-dominant portfolios in dry years (controlled by Genesis and Contact), creating two dominant players in both conditions. Gentailers can use this control to restrict shaped hedge supply, further disadvantaging independents (Commerce Commission, 2025a).
When lakes are full or near full, hydro generators should offer electricity at low prices to avoid spilling water and wasting generation potential. However, Meridian and Mercury can strategically manage their offer curves, withholding low-priced volume and offering higher-priced blocks to shape market prices, especially during peak periods. Indeed, hydro offer prices do not always reflect low marginal costs during wet years, suggesting strategic behaviour (EA, 2025). This contributes to high wholesale prices, limiting the ability of independent retailers to compete, especially if they lack access to shaped hedges or flexible generation. The market power of Meridian and Mercury is also enhanced by their dominance of hydro generation in their respective islands and constrained transmission capacity between the islands.
Conversely, during dry years, asset distribution gives Genesis Energy and Contact Energy a strategic advantage due to their diversified portfolios combining thermal and renewable generation. With hydro inflows constrained, Mercury and Meridian, become price takers, unable to meet contracted retail and wholesale obligations without purchasing electricity at elevated spot prices. In contrast, Genesis and Contact can outbid other gas users, secure fuel, and dispatch thermal generation at high wholesale prices. The EA’s 2024 energy margin analysis confirms that thermal generators captured significant margins between July and September 2024, when hydro storage was low and spot prices surged.
Rising electricity demand and rapid deployment of intermittent renewables are intensifying market structure issues in the wholesale market. While initiatives by the Electricity Authority (EA) and the government are introducing important measures, including mandatory non-discrimination rules, regulated hedge market access, enhanced retail competition frameworks, and new standardised flexibility products, are important steps forward, they primarily address transparency and fairness within the existing energy-only spot market.
These new initiatives do not fully resolve the structural concentration of flexible generation assets or incentivise investment in new firming capacity (Energy Link, 2025). Hence, further reforms to amplify the existing initiatives, including the introduction of a formal firming and flexibility market (FFM) and adapting electricity market rules to be suited to intermittent renewable technologies, are needed. For example, as the share of wind and solar rises, existing market rules may need updating to clarify performance obligations during scarcity periods, such as defining how generators participating in firming or flexibility products must respond to dispatch instructions or deliver contracted availability. These nontechnology‑specific requirements would ensure that all participants, including intermittent generators, contribute clearly and predictably to system reliability once an FFM is in place. Further improvements, as planned by Transpower, in transmission capacity between the North and South Islands would complement the FFM by reducing regional price separation and limiting the ability of dominant hydro generators to exploit transmission constraints. Further planning reforms would also help accelerate the development of the FFM.
2.4.1. Creating a firming and flexibility market to incentivise firming investment and lower barriers to entry
Market design should encourage flexibility, capacity, and retail innovation, and maximise the value of low-carbon technologies (IEA, 2022b). To phase out fossil thermal capacity, the system increasingly needs different types of balancing resources to replace gas: seasonal (dry‑year) firming (multi‑week to multi‑month dispatchable supply) and short‑duration firming and flexibility - resources that operate for minutes to hours to manage peak periods, reserves, and fast variations from wind and solar. Most batteries and demand response provide this shorter‑duration flexibility, although very rare industrial arrangements, most notably the NZAS–Meridian contract, can deliver multi‑week demand reductions and thus partially mimic seasonal firming. Because these resources differ fundamentally in duration, scarcity conditions, and operational characteristics, a credible market instrument must be capable of procuring both types of services transparently.
A dedicated firming and flexibility platform that enables consumer-side participation through smart tariffs and demand response. Indeed, there is a strong need to provide clear market signals to support investment in firming and flexibility resources, especially as renewable penetration increases and traditional thermal capacity declines (IEA, 2020).
A shadow firming market already exists through swaptions (option to enter a price hedging contract) and bilateral deals between gentailers and large industrial users (Energy Link, 2025). In 2025, Genesis offered exclusively to the other three gentailers access rights for ten years to 50 MW of coal and gas fired firming generation each at Genesis’s, Huntly power station, the main dry year firming generation available in the country. These arrangements are piecemeal, opaque and limit access to firming for independent generators and retailers. The Commerce Commission acknowledged the competition limiting effects but authorised the contracts on the grounds that public benefits (security of supply and lower wholesale prices) outweighed competition limiting effects. Genesis noted it has 135MW of firming still available and would offer this in hedging contracts to independents. The Commission said it would monitor progress on this commitment but did not make it a formal requirement for authorisation (Commerce Commission, 2025b). A formal FFM would complement existing reforms by replacing the current ad hoc approach with a transparent, tradable platform for both firming and flexibility services. It would introduce forward-looking price signals, enabling better hedging and investment planning, and help smooth price volatility.
While the ongoing initiatives will improve access to hedging products and reduce discriminatory pricing, the FFM would expand the pool of tradable flexibility services, enable dynamic procurement of firming capacity, and support investment in seasonal flexibility that is critical for dry-year resilience. On the demand side, the FFM would enable participation from a broader range of industrial loads. Most demand response (DR) would provide short‑run flexibility, but the platform could also accommodate long‑duration industrial arrangements similar to the NZAS contract, allowing these rare resources to be procured transparently and rewarded for multi‑week reductions during dry‑year scarcity events. This would ensure that DR complements, rather than substitutes for, the dedicated seasonal firming needed to address hydro‑scarcity risk. On the supply side, the FFM would also support price discovery for firming services, especially during dry years or peak demand periods, and unlock investment in underprovided resources, such as grid-scale storage, peaking generation, and seasonal firming (e.g. wood fired generation). It would also complement transmission upgrades and progressive scarcity pricing reforms by ensuring that flexible resources are available and compensated (Energy Link, 2025).
New Zealand already relies on the ASX‑listed electricity futures and options market for forward hedging, including baseload and peak contracts traded at Benmore and Otahuhu nodes. In 2025, the Electricity Authority (EA) introduced a new standardised super‑peak flexibility hedge product to improve price discovery and risk management during high‑demand, high‑volatility periods. This filled a gap not covered by existing ASX products. While these instruments help market participants hedge short‑run exposure to peak‑time volatility, they remain focused on hourly to daily price risk and do not address New Zealand’s long‑duration hydro‑scarcity risk.
Beyond the new hedge products, the EA has launched broader initiatives, including market‑making arrangements for the new hedge product and a roadmap to improve industrial demand flexibility. These measures improve short‑term market functioning and price stability during high-demand periods. However, they also do not tackle deeper structural issues in the electricity system, such as the concentration of seasonal firming generation assets or the absence of mechanisms to price multi-week or multi-month scarcity.
The FFM would fill these gaps. Participation in an FFM would also offer a practical mechanism for gentailers to demonstrate compliance with non‑discrimination rules, by making access to firming products standardised, transparent, and equally available. While reinforced EA monitoring and expanded regulated hedge access remain important, a mandatory FFM is the most effective tool to materially reduce vertical‑integration advantages and ensure a truly level playing field. The FFM can be implemented within the Government’s dry‑year work programme (Action 2.5) as the market instrument that procures long‑duration flexibility (supply‑ and demand‑side) on option‑based, performance‑contingent terms.
The proposed FFM would therefore complement, not replace, current ASX and EA flexibility products. It would trade short‑term flexibility hedges, consistent with Europe’s short‑run flexibility platforms or ERCOT’s real‑time ancillary service markets, and long‑duration hedging options that insure specifically against multi‑week or multi‑month scarcity caused by low inflows and constrained hydro storage. Unlike European capacity markets, which remunerate the availability of capacity, FFM instruments are option‑based and performance‑contingent. The option premium compensates sellers for granting the right to call on flexibility, but payments for delivered energy or demand reduction occur only when defined scarcity triggers materialise (Box 2.5). This adds a long‑duration, scarcity‑responsive layer to the hedging ecosystem, reinforcing, rather than bypassing, real‑time price signals.
The unique part of the FFM compared to hedging markets elsewhere is the trading of long-dated hedging instruments designed to address New Zealand’s seasonal (dry-year) problem. Two illustrative examples of these instruments are presented.
Seasonal generation firming option (independent retailer as buyer): An independent retailer signs a 10‑year call option on 50–100 MW of seasonal firming generation from a geothermal or CHP wood boiler plant. The annual option premium compensates the generator for granting the right to call, not for mere availability like in a capacity market. Exercise is permitted only when system‑wide scarcity conditions are met (e.g. lake storage falling below a defined percentile). When exercised, the generator must supply output at an agreed strike price, with penalties for non‑performance. This structure provides the retailer with insurance against dry‑year price spikes, while giving the generator a bankable, scarcity-linked revenue stream rather than passive capacity payments.
Seasonal demand‑response option (renewables generator as buyer): A new wind or solar developer contracts a 15‑year demand‑response (DR) option with a large industrial user for 30–150 MW of curtailable load. The developer pays an annual option premium, a payment for the right to call the reduction, not for mere availability. A portion of this premium could depend on the industrial site maintaining telemetry readiness, meaning it has the real‑time meters, data feeds and control systems required for Transpower to reliably see, verify and confirm demand reductions as they happen. When scarcity triggers occur, typically linked to multi-week hydro dry-year shortages or reserve constraints, the DR provider must reduce consumption relative to an agreed baseline and receives a strike‑linked settlement for verified delivery. Non‑delivery triggers penalties. For the renewables project, the DR option provides long‑duration insurance against dry‑year price spikes; for the industrial user, it monetises flexible demand in a manner analogous to the long‑term NZAS demand‑response arrangements.
A FFM would also directly address the market power the gentailers derive from their vertical integration and control of firming assets. It would do so by enabling more participants on both the demand management and firming supply side of the market, reducing reliance on the gentailers. An FFM would help break the structural advantage of the gentailers have over independents by improving access to firming capacity, reducing reliance on bilateral arrangements and improving price transparency. It would also reduce the power of gentailers with thermal assets to withhold shaped hedges during dry years to drive up prices. By increasing the access to a greater supply of firming, the FFM would also lower wholesale price risk premiums and address the financial vulnerability of hydro-dominated generators and industry in dry years.
The FFM would also support decarbonisation by incentivising investment in clean firming technologies, such as pumped hydro, wood, and smart load control, helping to ensure reliability as fossil thermal generation is phased out. For consumers, the FFM would improve affordability and choice. It would enable independent retailers to compete fairly, offer innovative tariffs, and allow households and businesses to participate through smart appliances, EV charging, and time-of-use pricing, rewarding flexibility and helping balance the grid.
2.4.2. Ensuring market conduct rules are fit for purpose in the age of net zero
While improved conduct rules are essential to strengthening hedge‑market competition, they remain difficult to enforce in a vertically integrated market. To increase hedge supply, the EA introduced a new super peak hedging product in January 2025. If trading volume is too low, the EA proposes that gentailer participation will be mandated and with minimum volumes. This will be part of the EA’s progressive enforcement framework coming into force in April 2026, that will tighten disclosure rules, impose non-discrimination rules and potentially mandate gentailers to trade hedge contracts transparently. To curb internal transfer pricing and cross-subsidisation, gentailers would be required to offer hedge contracts to independents on the same terms as their own retail arms.
These conduct rule reforms are essential steps toward fairer competition but do not fully address structural barriers and will be difficult to enforce. Their effect could be amplified by linking conduct compliance to FFM participation by establishing that participation in the market automatically satisfies non-discrimination obligations. Gentailers could still use bilateral contracts but would need to prove they meet non-discrimination standards, shifting the burden of proof and incentivising use of the FFM. This would avoid complex rule enforcement and aligns with international best practice favouring market-based mechanisms over prescriptive regulation.
Conduct rules and an FFM together can help in a complementary way to ensure fair market conduct and incentivise renewable overbuild, which many analysts consider necessary to ensure security of supply once fossil thermal generation phases out. Conduct rules ensure that new renewable developers face fair access to hedging and firming products, lowering entry barriers. The FFM then provides a scalable, market‑based pathway for renewables to secure firming appropriate to their needs- seasonal firming for dry-year risk and short-duration flexibility, reducing the risk that renewable overbuild contributes to volatility or free‑riding concerns. Together, these mechanisms help make renewable overbuild economically viable and system‑reliable, without requiring a return to centralised procurement or a regulated investment mandate.
High quality regulation adapts to technological change and market evolution (OECD, 2012). Conduct rules also need to adapt to rapid transition toward intermittent renewables, especially solar and wind. On the one hand, rules sometime discourage renewable investment and demand management. Retail pricing often fails to reflect system value of solar generation or flexible demand. Rules could be reformed to require fair pricing for the export of rooftop solar generation and batteries during peak periods. On the other hand, intermittent generators (e.g. solar, wind) can, unlike other generators, bid into the spot market without an obligation to supply. This creates a free-riding risk, where generators benefit from high prices without securing firming capacity. Dispatchable generators (e.g. hydro, thermal) bear the cost of balancing the system, undermining investment signals and reliability.
Once a liquid FFM is established, the EA could introduce a conditional supply obligation (CSO) for intermittent generators who bid into the market. The CSO would oblige the bidding generator to deliver the offered quantity or secure appropriate firming in the FFM, whether seasonal firming or short-duration flexibility for forecast errors. The obligation would internalise the cost of intermittency, encourage investment in firming options (e.g. pumped hydro). The FFM would provide a compliance pathway, allowing intermittent generators to meet obligations by purchasing seasonal or short-duration firming contracts and avoiding penalising them for forecast errors while still ensuring reliability.
Demand response (DR) can play a large part in reducing peak-to-average load, thereby reducing gentailer opportunities to supply their retail customers at a margin above cost and make large profits on the wholesale market by bidding in high-cost gas generation. Instead of returning to bilateral payments to industry as in the past, the EA could introduce a tradable industrial demand response product within the FFM, enabling broader participation and more efficient peak load management.
2.4.3. Enhancing the powers and scope of the Electricity Authority
In response to concerns about gentailer market power, the government has stated its support for stronger powers for the EA. Strengthening the EA’s mandate would not only improve competition and reliability but could also ensure the electricity market supports New Zealand’s productivity and climate goals. Effective regulators require a broad scope of action, including tariff-setting, investment oversight, and the ability to impose penalties for misconduct (Van Langen et al., 2025). Electricity becoming a core input for green and digital transitions calls for regulators be empowered to consider greenhouse gas reduction, decarbonisation, and biodiversity impacts in their decisions (OECD, 2025b). The EA plays a central role in overseeing market conduct, competition, and code compliance in the electricity sector. However, its powers are limited compared to leading regulators across the OECD. The EA lacked direct enforcement powers beyond code amendments.
In welcome move to align with international standards including in Australia, in January 2026 the government granted the EA expanded powers to enforce conduct rules with substantially increased financial penalties. Importantly the new maximum penalty is not capped and is the highest of NZD 10 million (up from NZD 2 million), three times the gain from the breach or 10 percent of the company’s turnover. This means the fine can be made commensurate with the harm and be dissuasive even for the gentailers. Beyond enforcement the EA powers should be expanded to have regard to system decarbonisation and resilience when it develops or amends code provisions on seasonal firming instruments short-duration flexibility products, or DR. To help ensure the market is as close to international best practice as possible, EA could also be given a mandate, to support innovation more through regulatory sandboxes like the United Kingdom’s regulator, Ofgem, for example in industrial demand response.
2.4.4. Reconsidering structural solutions as a last resort
Pursing market design changes should be the first line of reforms. If well implemented, market design and conduct rule changes can directly address current market power problems impeding competition and affordability. Separation of the retail and generation arms of the gentailers would be disruptive, with significant valuation implications for the listed gentailers and possibly New Zealand’s reputation with foreign investors. At the same time, the experience of several OECD countries shows that maintaining a diverse population of independent retailers is important for driving innovation in smart‑tariff design, energy‑efficiency services, and demand‑response solutions, areas where gentailers have weaker commercial incentives to innovate. Therefore, if these changes, including the FFM, combined with new non-discrimination rules and enhanced powers for the EA, do not result in a material increase in investments in firming generation, independent entry and affordability in electricity, the government should reexamine structural solutions.
The advantages of maintaining vertical integration, including avoiding significant market disruption, need to be weighed against the need for competitive transparent markets (IEA, 2022b). This is especially to ensure vertical integration is still aligned with delivering the right mix of new investment, as the system becomes almost entirely renewable (OECD, 2022). Vertical integration is present in several OECD markets, including Australia and France. However, OECD research shows that unbundled markets (e.g. United Kingdom, Germany, Nordic countries) have higher rates of new entrant participation, especially in retail and renewable generation, than those where vertical integration is allowed (Benatia and Kozluk, 2016). A review of structural options should also compare vertical separation against re-distributing firming assets. Indeed, the concentration of firming assets and lack of new firming generation appears to be weighing even more urgently on security of supply than vertical integration and even putting at financial risk some of the largest gentailers. In a system striving for net zero, the key structural question is not only organisational form but whether the market delivers sufficient renewable overbuild supported by adequate firming and a dynamic, innovative retail sector. A redistribution of firming investment may prove less costly and more effective than vertical separation and would deserve its own full investigation.
Meeting New Zealand’s decarbonisation, electrification, and energy security goals will require massive and well-designed investments in new electricity generation. However, outdated gentailer governance arrangements and financial strategies, and a cumbersome planning system threaten to hamper this process despite New Zealand’s large potential to increase renewable electricity generation.
2.5.1. Aligning gentailer governance and financial strategy with growing investment requirements
Gentailers are central to delivering new generation investment. When the mixed ownership model (MOM) gentailers were created in 2013, electricity demand was flat, and investment needs modest, making high dividend payouts relatively benign. Today, surging demand from transport electrification, industrial decarbonisation, and AI-driven data centres requires firming and seasonal capacity, demanding a shift in gentailer governance and financial strategy.
Despite strong governance features, including partial public ownership, board independence, and commercial discipline, MOM gentailers’ financial strategies are misaligned with system-wide investment needs and broader government goals for secure, sustainable, and affordable electricity (OECD and World Bank, 2024; Frontier Economics, 2025). Compared with OECD best practice and leading international utilities, New Zealand’s gentailers face several challenges: absence of a published ownership policy, high dividend payout ratios, and inadequate technical expertise on boards, especially for assessing investment projects.
Gentailers have consistently paid out 90–240% of net income in dividends (Figure 2.8), totalling NZD 11.8 billion over the decade to 2025, exceeding net profits by NZD 4.5 billion. In 2023, gentailers paid NZD 1.2 billion in dividends off just NZD 530 million in net profit. The high dividend ratios have constrained investment, with only NZD 1 invested in renewables for every NZD 2.41 paid out in dividends (NZCTU, FIRST Union, and 350 Aotearoa, 2023). The government’s offer to participate in equity raises for “strategic and commercially rational investments” is ad hoc and administratively burdensome and lacks scale. Internationally, utilities like Enel (Italy), Iberdrola (Spain), and EDF, adopt flexible dividend policies, often suspending payouts during major investment phases, while Nordic electricity SOEs retain earnings to fund renewables and grid upgrades (OECD and World Bank, 2024). Financial analysts would normally consider payout ratios of above 80% as too high, endangering the financial health of companies with significant investment needs (Perez and Poston, 2025).
Note: Payout ratios are calculated as dividends paid per share over earnings per share.
Source: Contact, Genesis, Meridian Energy and Mercury.
The three gentailers are not SOEs but MOM listed companies and as such the Crown does not set dividend policy. The Board determines payouts within listing rules and governance obligations. However, OECD guidelines recommend that governments publish a formal ownership policy for companies that it has a controlling stake, clarifying their strategic objectives, dividend expectations, and performance metrics. New Zealand lacks such a policy for its MOM gentailers, creating ambiguity around whether these firms should prioritise shareholder returns or system investment (OECD and World Bank, 2024). In contrast, utilities like EDF (France) and Statkraft (Norway) operate under clear ownership mandates that align the firm’s behaviour with national energy goals. New Zealand should follow suit, explicitly tasking MOM gentailers with supporting secure, sustainable, and affordable electricity, and requiring that their financial strategies reflect this mandate (OECD & World Bank, 2024). The government should include in a Crown Ownership Expectations Statement for MOM gentailers an indicative payout‑range (e.g., 60–70%) and re‑investment thresholds, and signals temporary dividend restraint during major capex cycle, while leaving Boards responsible for dividend decisions (OECD and World Bank, 2024).
MOM gentailer boards vary in their expertise but overall lack directors with deep expertise in energy systems, engineering, and market design. While governance and financial skills are well covered, technical capacity to assess seasonal firming, flexibility, and dry-year resilience is limited. International utilities, like Statkraft and EDF, appoint directors with engineering and decarbonisation planning experience (OECD and World Bank, 2024). In 2025, two MOM gentailers without sufficient seasonal firming assets saw significant profit declines, exposing both firms and the Crown to financial risk. Unlike State‑Owned Enterprises, which follow a dedicated SOE appointment process, MOM gentailers are listed companies, and their director appointments follow public‑company governance procedures, with the Crown participating as a majority shareholder alongside other investors. The government should also include in the ownership expectations statement a desired board‑skills profile—covering technical and engineering expertise in generation, flexibility and grid operations, and strategic experience in infrastructure finance and climate transition planning. Board evaluations and nominations could then reference this skills matrix without altering the underlying appointment processes (OECD and World Bank, 2024; Frontier Economics, 2025).
2.5.2. Removing land planning roadblocks
New Zealand’s land planning system has been a major obstacle to electricity investment, compromising reaching climate targets and dragging on economic performance. Multiple generation projects by small and large generators alike, including hydro and wind generation, have suffered costly delays due to New Zealand’s main planning legislation, the Resource Management Act (RMA) becoming cumbersome due to constant amendments and shifting national direction. After serial amendments it is over 900 pages long, making it difficult for councils to understand and use. These problems are compounded by overlapping consenting requirements from district, regional and national plans. It has been estimated that consenting will need to be 50% faster for New Zealand to meet its GHG emissions targets (Moore et al., 2023). The RMA today confers excessive appeal rights (e.g., appeals over developments anticipated in district plans) in comparison with other OECD countries, slowing planning decisions (OECD, 2024). Appeal rights are granted to any person who made on a submission on a development regardless of where they live, encouraging serial objectors and gaming of the system (Infrastructure Commission, 2024). Most projects require multiple planning consents (land use, subdivision, pollutant discharge) even when zoning decisions has signalled what is acceptable. There are also over 1100 types of land zone as each council designed its own zoning framework.
The government has taken important steps including fast tracking for planning approvals and imposing a 12-month limit on local government consenting for renewable energy projects. These are welcome short-term measures. Comprehensive reform is essential to support sustained investment in generation, transmission, and emerging clean‑energy technologies. The broader planning framework is currently in transition as the government moves to replace the RMA with two new bills. The Planning Bill and the Natural Environment Bill passed First Reading in December 2025, and Government has signalled changes to National Direction (new NPS‑Infrastructure; amended NPS‑Renewable Energy Generation; amended NPS‑Electricity Networks). The extent to which these bills effectively resolve long‑standing challenges, such as duplicated consents, inconsistent zoning, unclear national direction and wide appeal rights, will depend on their final design, resourcing and implementation. This requires careful assessment and design of the accompanying detailed regulations and national planning guidance, and ensuring local authorities have the capacity to implement them effectively.
International experience shows that planning regimes depend on the availability of high‑quality environmental information, which requires investment in data collection, monitoring and spatial mapping to enable evidence‑based, integrated spatial planning (Pierce and Alexander, 2024). As part of the comprehensive overhaul, the number of land zones should be reduced to around 10 to 15, similar to Japan’s 13. It is important to recycle as much as feasible RMA terminology to avoid jamming the legal system with litigation interpreting the meaning of new terms.
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