Quote from Graeme Weston on 16 February 2026, 11:11 am

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Domestic Portfolio Strategy - Option

Dry-Year Risk: Domestic Portfolio vs LNG Infrastructure

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

This option outlines a domestic portfolio alternative and recommends integrated modelling before any irreversible LNG commitment. A severe dry year creates a 1.5–2.0 TWh seasonal energy shortfall, typically concentrated in winter, coinciding with peak demand.

Portfolio Option

1. Hydro operated as seasonal storage (governance reform, not new build).
2. 2–3 TWh renewable overbuild (wind-led, winter-aligned).
3. 40% rooftop solar penetration over time (reduces hydro drawdown earlier in the year).
4. 1M EVs with managed charging and partial V2G capability.
5. Flexible ammonia export load (interruptible within minutes, absorbs excess renewables, profits to sovereign wealth fund - SWF).
6. Moderate grid-scale battery deployment (2–4 GW / 8–16 GWh).

Engineering logic

• Renewable overbuild reduces annual hydro depletion by ~2 TWh.
• Rooftop solar reduces daytime and shoulder-season hydro usage.
• V2G reduces evening peak draw, preserving lake levels.
• Ammonia plants shed up to 500 MW instantly during tight supply.
• Hydro retains 4–5 TWh seasonal storage capacity.

Under expected-value modelling, the combined effect offsets the modeled 1.5–2 TWh dry-year deficit. LNG becomes tail-risk only for multi-year inflow failure combined with low wind.

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2. Capacity Adequacy: What About Peak Risk?

LNG addresses seasonal energy. It does not materially improve peak flexibility without gas-fired generation capacity.

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.

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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.

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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 after non-network solutions exhausted.
• Market design reform.
• Possibly catalytic funding for export ammonia. ??

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

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5. Transmission Implications

Overbuild requires:

• Targeted transmission upgrades (particularly SI wind to NI load).
• HVDC optimisation.

However:

• Rooftop solar reduces distribution loading.
• V2G reduces peak flows.
• Flexible ammonia reduces curtailment.
• Emergence of microgrid routers and power electronics ??

Net transmission impact is neutral to moderately positive compared to LNG-driven thermal reliance.

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6. Geothermal Constraint

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

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7. Hydrogen/Ammonia Risk

Industry concerns:

• Export market volatility.
• Capital intensity.
• Technology risk.

Mitigation:

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

If ammonia margins fall, overbuild still reduces hydro depletion and fuel imports.

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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.

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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.

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10. Stress Case: Simultaneous Low Hydro + Low Wind

This is the most serious challenge.

Mitigation layers:

1. Ammonia plant shutdown.
2. EV charging curtailed.
3. Industrial demand response.
4. Hydro preserved earlier in year.
5. Sovereign fund supports temporary imports if required. ??

Probability-weighted expected LNG utilisation becomes very low.

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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.

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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.

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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.

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Appendix A - Core Finding

A coordinated domestic portfolio can offset the expected dry-year deficit while reducing fuel import exposure and building national capital.

The portfolio includes:

1. Hydro optimisation as seasonal storage
2. 2–3 TWh renewable overbuild
3. Accelerated electrification (EV + heat)
4. Flexible export ammonia load (interruptible)
5. Moderate grid-scale battery deployment

Under expected-value modelling, this combination materially reduces the need for LNG. LNG becomes residual tail-risk insurance only.

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Financial Comparison (Indicative)

Option	Annual Fixed Cost	Fuel Exposure	Wealth Creation	Stranded Asset Risk
LNG	~$200M	High	None	High
Domestic Portfolio	Capital investment	None	Yes	Low

Ammonia export margin (~$100M/year) could be directed into a sovereign resilience fund, building ~$3–4B over 20 years.

Electrification reduces fuel imports by ~$6–7B/year long term, dwarfing LNG insurance cost.

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Risk Perspective

LNG addresses seasonal risk but increases geopolitical exposure and long-term fossil dependency.

The domestic portfolio reduces the seasonal deficit structurally while increasing system flexibility and optionality.

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Recommendation

Before committing to LNG infrastructure:

Commission integrated probabilistic modelling comparing:

1. LNG-only scenario
2. Domestic portfolio scenario

Metrics should include:

• Expected system cost (20-year horizon)
• Security-of-supply probability
• Wholesale price volatility
• Geopolitical exposure
• Stranded asset risk

Decision should be based on probability-weighted cost and long-term capital efficiency.

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Appendix B - Technical Annex

Numerical Assumptions and System Modelling Inputs

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A. System Baseline

Annual electricity demand: ~43 TWh
Peak demand: ~7 GW
Effective hydro seasonal storage: ~4–5 TWh
Modeled severe dry-year deficit: 1.5–2.0 TWh

Discount rate (real): 6%
Time horizon: 20 years

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B. LNG Infrastructure Assumptions

Infrastructure capex / contracted cost: ~$1B
Annual fixed cost: ~$180–220M
Delivered LNG electricity cost: ~$200–250/MWh
Effective dry-year marginal cost: ~$330–380/MWh

Utilisation: low probability except severe drought

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C. Renewable Overbuild Assumptions

Additional generation target: 2–3 TWh/year

Indicative mix:

• 600 MW wind (CF 42%)
• 400 MW solar (CF 18%)
• 100 MW geothermal (CF 90%)

Capex estimate: ~$2.5–3.5B
Blended LCOE: ~$85–100/MWh

Winter-adjusted contribution to dry-year deficit: ~1.5–1.8 TWh effective.

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D. Rooftop Solar Assumptions (40% Penetration Scenario)

500,000 homes
10 kWp each
Annual output: ~7.9 TWh

Winter contribution: ~3–4 TWh
Primary effect: reduces hydro drawdown earlier in year.

Private capital funded.

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E. Electrification Assumptions

1M EVs by 2040

Embedded storage:
~30 kWh usable per vehicle
~30 GWh aggregate
~6 GWh reliably available

Peak flexibility: ~1–1.5 GW

Fuel import reduction (long-term): ~$6–7B/year.

Electricity demand increase: ~12–14 TWh.

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F. Grid Battery Assumptions

8–16 GWh total system capacity
Capex: ~$1,000/kWh
Total capital: ~$8–16B (staged deployment)

Role: peak shaving and wind smoothing.
Does not independently solve seasonal deficit.

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G. Flexible Ammonia Export Assumptions

Electrolyser capacity: 500 MW
Annual electricity input: ~3 TWh
Conversion efficiency: ~63%

Output: ~365,000 tonnes ammonia/year

Export price assumption: $700/tonne
Gross revenue: ~$255M/year
Electricity cost (@$40/MWh): ~$120M
Net margin before O&M: ~$135M
Net after O&M: ~$100–110M/year

Operation: fully interruptible during scarcity.

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H. Sovereign Resilience Fund

Annual contribution: ~$100M
Real return: 5%

Projected value:
10 years: ~$1.4B
20 years: ~$3.6B

Equivalent to 15–20 years of LNG fixed cost.

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I. Combined Seasonal Balance (Indicative)

Dry-year deficit: 1.8 TWh

Mitigation layers:

• Renewable overbuild (winter-adjusted): ~1.6 TWh
• Preserved hydro due to rooftop + V2G: ~0.5–0.8 TWh
• Peak shaving reduces depletion rate

Combined expected mitigation: ~2.1–2.4 TWh

Residual extreme multi-year drought remains low-probability event.

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J. Sensitivity Variables

• Hydro inflow volatility
• Wind drought correlation
• EV uptake rate
• Ammonia export price
• Battery cost decline
• Electrification pace
• Transmission reinforcement timing

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K. Required Modelling Work

1. Monte Carlo seasonal inflow modelling
2. Correlated wind-hydro stress test
3. Electrification growth scenarios
4. Price-duration curve impact
5. Probability-weighted LNG utilisation

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Final Technical Statement

Under expected-value modelling with moderate renewable overbuild and accelerated electrification, the domestic portfolio materially reduces the seasonal deficit and peak risk. LNG becomes a high-cost tail hedge rather than a structural necessity. Further modelling is warranted before permanent LNG commitment.

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Appendix C

How Accelerated EV Adoption Multiplies the Domestic Energy Portfolio

Accelerated EV adoption is not simply transport policy. It acts as a system multiplier across reliability, economics, and sovereignty.

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1. Direct Economic Multiplier

Current petrol and diesel imports cost New Zealand approximately $6–7 billion per year (price-dependent).

As EV penetration rises:

• Imported fuel spending falls.
• Electricity demand rises domestically.
• Capital remains in the New Zealand economy.

Even partial electrification produces savings many times larger than the annual cost of LNG insurance (~$200 million/year).

Order of magnitude effect:
Fuel displacement savings are roughly 30× larger than LNG fixed cost.

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2. System Reliability Multiplier

EVs provide:

• Flexible charging load
• Embedded storage (V2G capability)
• Peak demand reduction

At 1 million EVs:

• ~1–1.5 GW peak elasticity
• ~20–30 GWh distributed storage
• Reduced hydro drawdown during evening peaks

This directly strengthens dry-year resilience and reduces the probability that LNG would be required.

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3. Renewable Investment Multiplier

Accelerated EV uptake:

• Absorbs renewable overbuild
• Reduces curtailment risk
• Improves economics of wind and solar
• Supports flexible export load (e.g. ammonia)

It increases utilisation of domestic generation assets.

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4. Geopolitical Risk Multiplier

Oil imports represent a larger geopolitical exposure than dry-year gas risk.

Electrification:

• Reduces exposure to global oil markets
• Increases energy sovereignty
• Improves balance of payments stability

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5. Net Portfolio Effect

When electrification is accelerated:

• Renewable overbuild becomes more viable.
• Hydro seasonal storage becomes more effective.
• Flexible export becomes more economic.
• LNG utilisation probability declines.

Electrification amplifies each pillar of the domestic portfolio.

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Conclusion

Accelerated EV adoption acts as a structural multiplier on the domestic energy strategy:

• Financial multiplier (multi-billion fuel savings)
• Reliability multiplier (peak elasticity + storage)
• Investment multiplier (renewable utilisation)
• Sovereignty multiplier (reduced import dependence)
• Capital cost to EV owners

Without accelerated electrification, the domestic portfolio is weaker. With accelerated electrification, LNG becomes materially less necessary.

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