Dry-Year Risk – Ohope Community

Domestic Portfolio vs LNG Infrastructure

New Zealand faces a seasonal energy deficit in a severe dry year, creates a 1.5–2.0 TWh seasonal energy shortfall, typically concentrated in winter, coinciding with peak demand. The current policy proposal is to address this via permanent LNG import infrastructure (~$200M/year fixed cost plus fuel).

The MBIE paper to Cabinet discussed alternatives. MBIE’s modelled fossil fuels and largely preserved:

Energy-only wholesale market.
Hydro commercial dispatch incentives.
Marginal scarcity pricing structure.
Limited flexibility monetisation.

Under that structure, LNG is a logical insurance response. MBIE modelling limited renewables to the existing energy-only market design, without structural changes such as:

Large-scale deliberate overbuild.
Flexible export loads (e.g. ammonia sponge).
DLMP introduction.
Hydro governance reform.
Benchmark price bands.

In other words, renewables were assessed but in isolation as incremental additions, not as part of a redesigned system architecture.

This discussion explores a combination of non-fossil fuel options in more detail. It outlines a domestic “portfolio” of alternatives and recommends integrated modelling before any irreversible LNG commitment.

Portfolio Option

Hydro Dams operated as seasonal storage (governance reform, not new build). Manage the hydro dams currently owned by several Gentailers as a “NZ Big Battery”, retains 4–5 TWh seasonal storage capacity. Treats Hydro Coordination explicitly as seasonal storage rather than purely commercial generation. Transparent water-value frameworks and reserve thresholds moderate extreme depletion behaviour. Hydro becomes the backbone of resilience, not a scarcity amplifier.
Renewable overbuild (wind-led, winter-aligned), reduces annual hydro depletion by 2–3 TWh. Renewable overbuild adds more cheap wind and solar than average demand strictly requires. In normal and wet years this surplus generation reduces hydro lake drawdown, meaning more water is stored heading into winter. The effect is probabilistic: by preserving hydro in ordinary years, the likelihood of entering a critical dry-year depletion state falls. Overbuild shifts the risk distribution left rather than covering the tail with imported fuel. This will generate excess energy in wet years which will disrupt the market.
Flexible ammonia plants built next to overbuilt solar/wind generation, designed to sponge excess in wet years and export load (interruptible within minutes, absorbs excess renewables, profits to sovereign wealth fund – SWF). Isolated from energy market, designed to shed up to 500 MW instantly during tight supply. In a renewable overbuild scenario, surplus electricity will exist in wet or windy periods. If that surplus is not absorbed, wholesale prices collapse and renewable investment becomes unstable. A large electrolysis + ammonia facility can act as a “sponge load.” Other industry load shedding in extreme year (last resort, purchased by SWF).
Target 40% rooftop solar penetration over time (reduces hydro drawdown earlier in the year), reduces daytime and shoulder-season hydro usage.
Target 1M EVs with managed charging and partial V2G capability, reduces evening peak draw, preserving lake levels. V2G integration turns the EV fleet into distributed storage. Bidirectional charging allows aggregated vehicles to discharge during evening peaks and absorb surplus midday solar. This reduces peak hydro ramping and shortens scarcity events. Even partial participation materially increases system flexibility and reduces pressure on thermal backup.
Current pricing of delivery (poles and wires) is inefficient and unfair. DLMP (Dynamic Locational Marginal Pricing) extends price signals to reflect delivery constraints. Local generation and flexible loads are rewarded for relieving congestion. This improves siting decisions, reduces unnecessary transmission expansion, and monetises delivery flexibility that the current energy-only wholesale market undervalues.
Moderate grid-scale battery deployment (2–4 GW / 8–16 GWh). Flexibility markets allow demand response, batteries, and smart loads to compete alongside generation. Scarcity is addressed through elastic demand and storage rather than fossil fuel.

The structural reform pathway works by reducing the probability and severity of dry-year shortages through system redesign rather than fuel import insurance.

Together, these 7 elements prevent hydro depletion, introduce a greater range of tools, reduce volatility frequency and amplitude, absorb surplus without price collapse, and align investment with a two-way, electrified system. The pathway lowers structural risk while building domestic, revenue-generating assets rather than underwriting long-term LNG infrastructure. Not funded by government.

Under expected-value modelling, the combined effect offsets the modeled 1.5–2 TWh dry-year deficit.

2. Capacity Adequacy: What About Peak Risk?

LNG addresses seasonal energy. It does not materially improve peak flexibility without gas-fired generation capacity. Available Portfolio peak management tools:

V2G: up to 1.5 GW peak elasticity at 1M EV penetration.
Residential batteries: distributed short-duration discharge.
Grid batteries: firm 2–4 hour peak cover.
Flexible industrial load shedding (ammonia, more purchased from SWF).

Peak adequacy is therefore strengthened relative to LNG-only insurance.

3. Market Signals: Does Overbuild Crash Prices?

Industry concern: excess renewables suppress wholesale prices and deter investment. Response:

Flexible ammonia creates a price floor by absorbing surplus.
Electrification increases controllable demand.
Hydro seasonal optimisation reduces scarcity premiums.
Sovereign fund reduces need for scarcity rents to fund reliability.

The portfolio reduces volatility, not necessarily long-run average cost below sustainable LCOE. Curtailment risk is mitigated through export load design.

4. Capital Allocation: Who Pays?

LNG:

~$200M/year fixed system cost via levy.
Fuel cost during drought.

Portfolio:

Renewables funded privately.
Rooftop systems privately funded.
EV fleet privately funded.
Ammonia, self funded as export industry.
Hydro reform largely governance change.
Grid batteries market-funded where economic.

Public capital requirement primarily:

Grid reinforcement only after non-network solutions exhausted.
Market design reform.
Possibly catalytic funding for export ammonia. The Government may provide limited, early-stage financial support to enable the first flexible ammonia plants to be built — not to permanently subsidise them.

Net effect: capital shifts from fossil insurance to productive assets.

5. Transmission Implications

2-way energy flows require new thinking taking advantage of mesh architecture for more resilience. Rooftop solar reduces distribution loading, V2G reduces peak flows, flexible ammonia reduces curtailment and emergence of microgrid routers (power electronics) means net transmission impact is neutral to moderately positive compared to LNG-driven thermal reliance.

6. Geothermal Constraint

Geothermal remains dispatchable but resource-limited. Portfolio assumes modest expansion only. Seasonal solution is not geothermal-dependent.

7. Hydrogen/Ammonia Risk

Industry concerns:

Export market volatility.
Capital intensity.
Technology risk.

Mitigation:

Plants built modularly.
Fully interruptible operation.
Export-only mandate (profit to SWF) avoids domestic electricity price distortion.
Conservative capacity sizing (e.g., 500 MW initial).

If ammonia margins fall, overbuild still reduces hydro depletion and fuel imports. Not limited to ammonia, forestry value adding plants could serve the same purpose where appropriate.

8. LNG Risk Comparison

LNG exposes NZ to:

Global gas price volatility.
Shipping route disruption.
Currency risk.
Stranded asset risk if electrification accelerates.

Portfolio relies on:

Domestic wind, hydro, solar.
Domestic electrification.
Export markets where NZ has renewable advantage.

Geopolitical exposure declines.

9. Sovereign Wealth Fund Buffer

Ammonia export margin (~$100M/year) placed into ring-fenced fund:

Builds $3–4B buffer over 20 years.
Provides drought financial hedge.
Replaces fixed LNG levy.

Insurance becomes capital accumulation, not expense.

10. Stress Case: Simultaneous Low Hydro + Low Wind

This is the most serious challenge. Mitigation layers:

Ammonia plant shutdown.
EV charging curtailed.
Industrial demand response.
Hydro preserved earlier in year.
Sovereign fund a capital reserve for domestic response.

Probability-weighted expected LNG utilisation becomes very low.

11. Stranded Asset Risk

Electrification trajectory reduces long-run gas demand. An LNG terminal risks under utilisation by the 2035–2045 timeframe. Portfolio investments remain productive regardless of gas market evolution.

12. Investment Logic

LNG = fixed insurance premium. Portfolio = capital redeployment into:

Productive renewable generation.
Export industry.
Transport electrification.
Distributed storage.

Expected-value analysis favours portfolio if:

Dry-year probability remains low.
Electrification accelerates.
Renewable LCOE remains competitive.

Conclusion

The domestic portfolio is technically capable of covering expected dry-year risk. It:

Reduces volatility.
Builds domestic capital.
Avoids fossil lock-in.
Improves peak adequacy.
Reduces geopolitical exposure.

LNG remains a high-cost tail-risk hedge. The policy decision is not reliability vs ideology. It is Import fuel insurance vs domestic energy investment.

Fiscal Comparison – LNG Infrastructure vs Structural Reform Pathway

This note summarises the fiscal implications of two alternative approaches to managing dry-year electricity risk: construction of LNG import infrastructure, and a structural reform pathway centred on renewable overbuild, V2G integration, DLMP, hydro coordination and flexibility markets.

The LNG option represents a long-term, fixed financial commitment. Based on publicly released assumptions, annual exposure is likely in the order of $150–300 million per year over 15–20 years. That equates to a total nominal exposure of approximately $3–6 billion. Even if levy-funded, this remains a long-duration commitment that carries balance-sheet and political risk. The infrastructure must be paid for whether or not it is heavily utilised. Global LNG price exposure and underutilisation risk remain with the system. LNG does not create a revenue-generating asset; it functions as insurance against low-probability seasonal shortfall.

The structural reform pathway primarily involves regulatory reform rather than capital underwriting. Introducing DLMP, enabling V2G participation, reforming hydro coordination, and facilitating renewable overbuild would require market redesign, settlement upgrades and administrative oversight. Estimated fiscal costs are modest by comparison—likely in the tens of millions for implementation and low ongoing regulatory costs thereafter. The majority of capital deployment—renewables, EV batteries, distributed storage—would be funded privately. If sovereign participation were chosen for export load or renewable development, those would be productive, revenue-generating assets rather than insurance expenses.

The key fiscal difference is this: LNG represents concentrated, long-term Crown exposure tied to imported fuel. Structural reform represents limited regulatory expenditure that unlocks private capital and domestic asset formation.

LNG’s value proposition depends on reducing forward price risk premiums. That benefit is sensitive to utilisation rates and global fuel prices. If dry years are infrequent or electrification reduces thermal dependence, LNG may be underutilised while fixed costs remain. In that scenario, consumers continue paying the insurance premium without proportional benefit.

Structural reform distributes risk across technologies and participants. It reduces exposure to imported fuel, builds domestic infrastructure aligned with electrification trends, and maintains reversibility. If assumptions change, reform elements can be adjusted incrementally. LNG infrastructure, once contracted, is not easily unwound.

From a fiscal risk perspective, LNG increases long-term fixed obligations. Structural reform increases regulatory complexity but minimises balance-sheet exposure.

The decision is therefore not solely about reliability; it is about the nature of the Crown’s long-term financial commitment. LNG commits the Crown to decades of fixed insurance payments. Structural reform commits the Crown primarily to market modernisation.

That is the fiscal distinction for Cabinet consideration.

Fiscal Comparison, Assumptions Used

Electricity demand ~40–45 TWh/year
LNG levy range $2–4/MWh
LNG fixed commitment $150–300m/year
20-year evaluation horizon
Structural reform assumes primarily regulatory change with private capital mobilisation.

1. Direct Crown Fiscal Exposure

Category	LNG Infrastructure	Structural Reform (DLMP + V2G + Overbuild + Hydro Coordination)
Upfront capital commitment	$0.5–1.0B equivalent contractual value	<$100m regulatory/system upgrades
Annual fixed fiscal exposure	$150–300m	<$20m ongoing regulatory oversight
20-year nominal exposure	$3–6B	<$300m
Balance-sheet impact	Likely contingent liability	Minimal
Levy required	Yes (electricity levy)	No (unless incentives introduced)
Fuel procurement risk	Yes	None

2. Contingent Risk Exposure

Risk Type	LNG	Structural Reform
Underutilisation risk	High	None
Global price exposure	High	None
Stranded asset risk	Moderate–High	Low
Political reversal risk	Moderate	Moderate
Technology obsolescence risk	Moderate	Low
International supply chain disruption	High	Low

3. Revenue or Asset Creation

Category	LNG	Structural Reform
Revenue-generating asset	No	Yes (renewables, export loads)
Import substitution value	Limited	High (fuel import reduction)
Sovereign fund accumulation potential	No	Possible (export margins)
Asset life aligned with 2050 decarbonisation	Weak	Strong

4. Net Fiscal Characteristics

Characteristic	LNG	Structural Reform
Fiscal profile	Fixed insurance payment	Low regulatory cost
Capital productivity	Low (used rarely)	High (daily utilisation)
Exposure asymmetry	Downside skewed	Distributed
Crown underwriting required	Likely	Not structurally required
Reversibility	Low	High

5. Risk-Adjusted Fiscal Outlook (Qualitative)

Outcome Scenario	LNG Fiscal Impact	Reform Fiscal Impact
Moderate dry years	Full fixed cost paid, limited utilisation	No additional fiscal cost
Severe drought	LNG runs, cost justified	Portfolio absorbs via preserved hydro + flexibility
Rapid electrification	LNG underused, cost remains	Reform benefits increase
Global LNG price spike	Fiscal stress risk	No exposure
Renewable cost decline	LNG stranded risk increases	Reform strengthens

Cabinet-Level Interpretation

LNG represents a multi-billion-dollar long-term fiscal commitment with limited productive return outside dry events.
Structural reform primarily involves regulatory cost and system redesign, with capital largely funded by private investment.
LNG fiscal exposure is concentrated and long-lived.
Reform fiscal exposure is low and adaptive.

Summary Statement for Cabinet

If the objective is to minimise long-term Crown fiscal exposure while maintaining reliability margins, structural reform presents materially lower balance-sheet risk than LNG infrastructure.

LNG functions as a fixed insurance premium.
Structural reform functions as system modernisation with limited direct fiscal commitment.

References

MBIE Cabinet Paper – Dry Year Risk https://www.mbie.govt.nz/dmsdocument/31754-government-investment-in-dry-year-risk-cover-consideration-of-an-lng-import-facility

LNG fact sheet https://www.beehive.govt.nz/sites/default/files/2025-10/Fact%20sheet%20-%20LNG%20Procurement.pdf

Letter from Commissioner for Environment https://pce.parliament.nz/media/3bunxnn1/letter-to-minister-watts-re-lng-import_nov-2025.pdf

Rewiring Aotearoa Response to LNG https://www.rewiring.nz/news/rewiring-aotearoas-response-to-next-phase-of-lng-terminal-you-cannot-create-cheap-electricity-with-expensive-fuel

SEANZ Analysis of LNG Case https://www.seanz.org.nz/the-lng-story

Smart Energy NZ – briefings https://smarterenergy.nz/#briefings

Consumer NZ review https://www.consumer.org.nz/articles/could-lng-push-your-power-bill-even-higher