Mapping out the future of New Zealand’s electricity system
What should New Zealand’s electricity system look like if we are to meet our decarbonisation goals?
A recent report prepared for the Commissioner for the Environment sets out different future pathways for New Zealand’s electricity system and their economic and electricity price implications.
The June 2023 report, “The economics of four future electricity system pathways for New Zealand” (Report), uses Energy Link’s market modelling to assess four potential pathways for New Zealand’s electricity system. The different pathways highlight major energy market factors currently being discussed in relation to meeting New Zealand’s decarbonisation goals, as these factors have significant impacts on long-term electricity supply and demand.
The Report aims to “kickstart an open debate to ensure key investment decisions are for the long-term benefit of consumers”, rather than to draw any definitive conclusions about the best pathway forward.
Energy Modelling and Analysis
Energy Link used a range of models to analyse the four selected pathways up to 2050 and assess electricity system characteristics, including:
- Future CO2 emissions;
- Wholesale market price volatility;
- Energy security;
- Wholesale and final electricity prices for different consumers; and
- Economic costs and benefits of each pathway.
Each pathway was sensitivity tested to assess the impact of various assumptions (such as weighted cost of capital and discount rates) on the Report’s economic and financial conclusions.
Four Future Electricity System Pathways
The pathways and their assessments are:
Pathway 0: Pathway 0 represents “business as usual”, under which the Tiwai Point aluminium smelter (which uses around 13% of New Zealand’s total electricity) remains operational, and prevailing economic conditions and market demand continue without major changes. This pathway was used as a benchmark to compare market effects across the other three pathways.
Assessment: The modelling demonstrated that under a business as usual scenario, total electricity system generation capacity would almost double in 2050, largely as a result of wind and solar generation. By 2030, renewables would supply 95% of total electricity demand, increasing to 96.5% by 2050.
Pathway 1: Under Pathway 1, the Tiwai Point aluminium smelter shuts down and the Manapōuri hydro-electricity dam (which currently powers the smelter) funnels electricity into the national grid. This pathway is otherwise the same as Pathway 0, requiring less renewable development to meet demand, and making it the lowest cost option.
Assessment: Closure of the Tiwai Point aluminium smelter provides the most immediate impacts on residential electricity prices (with electricity bill savings of up to $197.50 per year under certain conditions) and emissions – but the emissions soon level out by approximately 2025 and then stay fairly stable over the course of the modelling period. The emissions reduction is a result of the additional electricity dispatched to the grid, which reduces reliance on carbon intensive fossil fuel generation. By 2030 renewables supply 95.3% of total electricity generated, and 96.5% by 2050.
Benefits outweigh costs in this pathway, and it has the highest positive Net Present Value (NPV) of all the pathways.
Pathway 2: Pathway 2 models large-scale green hydrogen production by the Southern Green Hydrogen project located in Southland, an Australasian joint venture between Woodside, Meridian and Contact Energy (SGH). For this pathway, the Tiwai Point aluminium smelter remains active. All hydrogen is exported overseas due to the domestic market being undeveloped, which means additional renewable electricity generation plants must also be constructed to meet the increased demand.
Pathway 2 contemplates two different sub-pathways. In pathway 2a (fixed supply), SGH operates continuously, without any shut downs or reductions. Pathway 2b (variable supply) is more flexible; an option fee is paid to SGH to curtail production and provide flexible demand to the grid and, if required, to allow it to shut down in a “dry year”. The type of option fee would be based on the difference in operational costs between the two sub-pathways, and is assumed to be passed on to consumers through higher electricity prices.
Assessment: Significantly more wind generation is required under Pathway 2 as a result of increased demand for new renewables, with both SGH and Tiwai Point operating in the South Island. Under Pathway 2a, South Island electricity demand is so significant that it raises doubt as to whether SGH and Tiwai Point are both sustainable, given generation capacity constraints and pressure on the transmission grid, and it is anticipated that the electricity infrastructure will be pushed to its limits. The modelling assumes that the South Island grid is upgraded to increase supply capacity constraints.
The generation capacity in Pathway 2a (20.3GW) is slightly higher than in Pathway 2b (19.6GW), while Pathway 2b has lower average emissions.
However, while Pathway 2b performs better than Pathway 2a overall, both hydrogen options perform poorly in comparison to other pathways as assessed against the various indicators - residential electricity prices remain the highest (the average annual electricity bill increasing by $172.40 in some cases), and this is the least effective option for ensuring energy security. The two sub-pathways both demonstrated negative NPV, regardless of different cost of capital assumptions and discount rates used.
These findings suggest that allowing Tiwai Point to remain operational within a low carbon, intermittent electricity system would result in high system-wide costs.
By 2030 renewables reach 95.1% of total electricity generation under Pathway 2a, and 95.5% under Pathway 2b, and by 2050 renewables are 96.3% and 97.1% respectively.
Pathway 3: Under Pathway 3, Tiwai Point remains operational and a pumped hydro-electricity storage scheme at Lake Onslow is commissioned. It is anticipated that the Lake Onslow project would be operational from 2031, but would not be completely full (and operating normally) for another two to three years, depending on whether New Zealand faces wet or dry years during the relevant period. The Lake Onslow project is intended to support the grid by pumping during periods when prices are low (ie when hydro-lakes are full), and generating when prices are higher. This helps stabilise electricity prices and leads to long-term reductions in wholesale prices. All of the Lake Onslow project’s construction, maintenance and operation costs are passed onto consumers via their electricity bills. (None of New Zealand’s current hydro-electric generation is pumped.)
Assessment: Lake Onslow pumped hydro-electricity storage stood out in the modelling as the only pathway to effectively suppress seasonal market volatility. This resulted in a reduction in wholesale electricity prices and increased predictability of market electricity prices.
Even after factoring in the construction costs of the Lake Onslow project, this pathway leads to lower residential electricity prices compared to Pathway 0. The pathway also resulted in a positive NPV for all scenarios analysed except those with the highest weighted average cost of capital and discount rates. For example, when the time horizon of the cost benefit analysis is extended to 100 years (from 50), the Lake Onslow project becomes more economic, which demonstrates how an extended time period for analysis can improve the financial performance of long-lived infrastructure projects. Further, when applying hyperbolic discount rates, which place more weight on the costs and benefits of long-lived assets to more appropriately value these for future generations, there is a positive NPV across all discount rates.
Pathway 3 also demonstrates direct economic benefit to consumers, as under certain conditions it could lower average annual electricity bills by up to $150 by the year 2050, along with other benefits such as security of supply.
Installed generation capacity also doubles by 2050, with over 85% of new generation attributable to wind and solar. Because the Lake Onslow project is itself a large and flexible generation resource, it avoids the need for the construction of additional flexible generators and allows existing flexible thermal generators to be decommissioned sooner. This leads to the largest reduction in emissions across all pathways. (Simpson Grierson notes that fast-acting generation will likely be required as a reserve, which would be thermal generation, unless there is very significant battery storage development elsewhere in New Zealand.)
By 2030, renewables account for 94.9% of total electricity generation, increasing to 97.7% by 2050.
While the Report does not make any recommendations, we expect the pathways analysis will be carefully considered by the Government during its current energy strategy development phase. The Government expects to release its energy roadmap in early 2024, and is currently considering its energy strategy. In that context, the Report may give some valuable foresight into what investors in electricity generation may expect from Government policy in this area.
Given the huge level of investment required for New Zealand’s transition to net zero emissions, it will be important for energy market participants to stay up to date on policy positions, and to actively contribute to shaping the future electricity system.
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