Electricity Authority Market Commentary

The path of the HVDC running from Benmore in the South Island to Haywards in the North Island

The high-voltage direct current cables (HVDC) electrically link the North and South Islands of New Zealand and are a vital piece of national infrastructure. These cables allow electricity produced in either island to flow to the other. Since the North Island is more populated, and therefore consumes more electricity, the HVDC typically transfers electricity northward during the day and southwards overnight. This pattern can differ, for example when South Island lake levels are low and or when North Island wind generation is high.

These cables also provide ‘security of electricity supply’¹ in both islands, especially in winter when electricity demand is high. Electricity in the South Island can become constrained when the hydro lakes are low, and importing electricity from the North is needed to meet demand. Alternatively, if North Island wind generation is low, or other generation unexpectedly trips, more South Island hydroelectricity is brought North.

The first set of cables were known as pole 1 and was commissioned in 1965 to transfer 600 MW. Pole 1 stretched over 600 km, beginning at Benmore dam in Canterbury and ending at Haywards in Wellington. Most of the link consisted of overland transmission and then submarine cables along the Cook Strait. A second link, pole 2, was added in 1992. In 2012 pole 1 was retired and replaced with pole 3 in 2013. Together, pole 2 and pole 3 can transfer a maximum of 1050 MW northwards and 750 MW southwards.

Every year, pole 2 and 3 must undergo maintenance to ensure their continued reliability. Since 2019, maintenance occurs in February² as demand for electricity is lower in summer and it is less likely to be disruptive to the electricity grid. This year, the outage spanned from 23 February to 6 March³, with at least one pole out during that time. During the weekend of 25-26 February, both poles went on outage, which electrically disconnected the islands. This caused price separation⁴ to occur. Prices were around $1/MWh in the South Island, as there was abundant hydro generation and less demand. At the same time, prices were around $150/MWh in the North Island, as thermal generation was needed to meet demand. Price separation is a legitimate market phenomenon, which reflects the underlying electricity market conditions in each island.

Some South Island hydro generators also schedule maintenance outages to coincide with the HVDC outage in February, as requirements for their electricity is low when it can’t be transported north. In comparison, the North Island hydro generators conserve water before the HVDC outage, as they need to meet North Island demand.

The Electricity Authority monitors the amount of electricity flowing between each island, and how this impacts electricity spot prices and market dynamics. Read our weekly trading conduct reports. More information and real-time HVDC flows can be found on our EMI website  and on Transpower’s website.

_{1. What is security of supply?}

_{2. Previously this occurred in November.}

_{3. A second pole 2 outage is also occurring between March 21-30 March}

_{4. New Zealand's geography and price separation}

Waikato River

Over 50% of New Zealand’s electricity is produced by hydro power. New Zealand’s largest hydro schemes, the Waitaki and Manapōuri, are in the South Island. While there are hydro dams in the North Island, these schemes have a smaller capacity. Since the North Island has higher electricity demand, the South Island generated electricity is often transported north via the HVDC inter-island cable.

In January 2023, the oceanic and atmospheric phenomenon known as La Niña, contributed to dry weather in the South Island, and wet conditions across the upper half of the North Island. Lakes Manapōuri and Te Anau experienced their lowest January inflows since 1953, while Lake Taupō recorded its fourth highest January inflow. This ‘wet dry divide’ impacted hydro storage and generation across the country.

Until early February this year, low rainfall in the South saw hydro storage in lakes Manapōuri and Te Anau drop below their low-operating ranges. Meridian, who operate Manapōuri power station, then had strict limits on how quickly the lake levels could drop further. This reduced their ability to generate electricity.

In contrast, heavy rain in the North Island saw Lake Taupō’s storage reach its maximum agreed limit. Mercury had to spill water downstream into the Waikato River, in line with resource consent requirements with Waikato Regional Council. This was controlled, due to heavy rain and to prevent further flooding downstream. During the heavy rain, Karāpiro dam outflows were above 500 cubic metres per second, resulting in some minor flooding in Hamilton.

Mercury has nine hydro generation dams on the Waikato River, with additional streams also supplying more water at various points in the chain. Each dam has a different amount of water that can be stored directly above it (see Figure 1). It takes about 24 hours before water released from Lake Taupō reaches the final dam at Karāpiro. No one event may be the same in terms of how much water is flowing in from which streams.

Mercury must carefully manage these many complexities when deciding how much water to release from Lake Taupō, how much and when to generate from each dam, and how much they might need to spill at Karāpiro - all while complying with various resource consents.

With plenty of water in the North Island, and restrictions on water usage in the South, there were high transfers of electricity southwards across the HVDC cable. Mercury generated a total of 414 GWh in January from its Waikato hydro stations – the highest over the previous nine years (during January) was 332 GWh. Southwards flows over the HVDC reached above 400 MW at some points (see Figure 2).  

In the previous nine years, only one other had southward HVDC flows which reached higher than those seen in January 2023. This occurred in 2018, when there were extreme weather events in the North Island in January and low hydro storage in the South Island.   

NIWA forecasts that La Niña conditions¹ will continue over the next few months. New Zealand’s extreme conditions may therefore persist, which will impact hydro storage and generation. Climate change may also mean these extreme events become more common in the future.

The Electricity Authority regularly monitors New Zealand’s hydro generation and storage. View our EMI website.

Figure 1: Waikato hydro system and relative storage

Figure 2: HVDC flows between 1 January – 5 February 2023

^{1. Seasonal climate outlook} 

^{2. Note gaps in the figure are a feature of the plotting – not zero MW HVDC flows.}

^{1. Read our explainer: The forward electricity market explained}

^{2. Future prices came down slightly between 25 January – 8 February 2023, however, the overall trend is still increasing.}

^{[3] This is generation which has been ‘committed’ ie, the unconditional final investment decision has been made. However, there are other projects which are being actively pursued, but are less likely to be online by the end of 2026. For more information, read this generation investment survey.}

^{[4] The Electricity Authority is investigating ways to promote consumer interests during periods of peak demand in winter 2023, see our consultation paper: Driving efficient solutions to promote consumer interests through winter 2023.}

^{[5] A large gas fired power station.}

December 2022 was the end of an immense year in the electricity sector. A dry summer and autumn, which saw hydro lakes levels plummet over several months, was juxtaposed by a wet and windy winter and spring (see Figure 2). Rain and snow melt kept New Zealand’s hydro lakes high, with total controlled storage at 97% full on 1 December 2022. This, alongside high wind and geothermal generation, allowed the electricity system to operate at near 100% renewables during times in November and December. This renewable electricity kept spot prices low – with the average December 2022 price being $17/MWh across all nodes.

In December 2019 hydro storage reached even higher levels than in December 2022, but prices remained high (see Figure 3). Large rainfall events in November and December 2019 resulted in South Island reservoirs reaching maximum capacity and hydro generators spilling water. Spot prices were expected to fall to very low levels to avoid unnecessary spilling of water. However, spot prices rose as high as $618/MWh, while the average price for the month (at the time) was $54/MWh across all nodes (see Figure 4).

The increase of spot prices led to multiple industry participants alleging that an “undesirable trading situation” (UTS) had occurred, and that generators had breached the rules of the Electricity Industry Participation Code 2010 (Code). After further analysis and consultations, the Electricity Authority decided that the situation did indeed constitute a UTS, which spanned from 3-27 December 2019.

A UTS is a situation outside the normal operation of the electricity market that threatens, or may threaten, confidence in, or the integrity of, the wholesale market. The UTS provisions of the Code oblige the Authority to attempt to correct such situations and restore the normal operation of the market.

To rectify the situation, the Authority imposed a price cap of $13.70/MWh on the offers made in the South Island by nine different stations between 3-27 December 2022. The Authority then worked with the system operator (Transpower) and others to resettle the market, with some generators required to repay the excesses they had made during the UTS period.

Under the Code at the time, the allegation of a breach of the trading conduct rules by generators in respect of the events that led to the UTS was not upheld. This was because the safe harbour provisions in clause 13.5B of the Code applied. 

In June 2021, the Authority amended the rules in the Code under which such a breach would be considered. These changes strengthen the requirements for generator offers to be “consistent with those made where no generator could exercise significant market power”, (for more on this read here) including by revoking the safe harbour provisions. The Authority also began weekly monitoring of generator offers under this rule, with reports published here.

The Authority also completed a post implementation review of the new trading conduct provisions in June 2022. Whilst nothing definitive could be proclaimed, the indicators examined found that the new provisions appear to be having the desired impact on generator offer behaviour.

New Zealand is a long and thin country, filled with mountains, lakes, volcanoes, cities, and vast plains. This geography impacts New Zealand’s electricity sector.

Electricity in New Zealand is transported, using the national grid, from power stations to households, businesses, and large industrial users. The largest hydro power stations are in the South Island, while the bulk of New Zealand’s electricity demand is in the North Island. The North Island also contains all of New Zealand’s thermal and geothermal power stations, and the majority of New Zealand’s wind farms.

The High Voltage Direct Current (HVDC) lines electrically link the North and South islands. These large cables mostly transport electricity produced in the South Island up to cities in the North Island.

New Zealand’s wholesale electricity market uses locational marginal pricing, where the price at each location (or node) reflects the cost of transporting electricity to that location. This means that the price at each location is different. (For a good introduction to locational marginal pricing, see Transpower’s Market 101 - Part 2 Locational Marginal Pricing.)

Locational marginal pricing occurs because of losses or transmission constraints. As electricity is transported between locations, losses occur due to heat losses on the lines. The cost of this lost electricity is included in the price at each location.

Transmission constraints occur when the electricity transported over a line reaches the maximum capacity of that line. This can be exacerbated by outages of other lines to the same location – either planned or unplanned. This congestion on the grid also results in costs of transporting electricity to a location, which are included in the locational prices.

New Zealand’s unique geography sometimes means that wholesale electricity spot prices between the islands can be quite different. This is called price separation and is the result of transmission constraints (rather than losses). If price separation occurs, there are usually lower prices in the South and higher prices in the North. This type of price separation occurred in November 2022, as seen in Figure 1. 

Figure 1: Half hourly spot prices for the North and South Islands, 21-23 November 2022

Price separation arose because of transmission constraints brought about by a number of contributing factors. Firstly, heavy rain in early November 2022 refilled many South Island hydro lakes. This allowed them to generate at high outputs with a low offer price[1]. It’s therefore been economic to generate a lot of electricity in the South and transport it North. This means the HVDC has been running hard – often up to the limit of what it can transfer (especially when wind has been low in the North Island).

Once this limit is reached, extra electricity for North Island demand is met using North Island generation, meaning the locational prices in the North Island will be set by more expensive North Island generation, while the lower priced South Island generation will still set the price at the South Island nodes.

The system must also carry reserves (generation on stand-by) to cover the sudden unexpected loss of the largest part of the system that could fail.[2]

Electricity and reserves are produced by the same generation stations ie, a power station can offer in both electricity and reserves for the same time period. The market then selects the optimal allocation for each power station between what it should generate and how much it should keep in reserve. This means that the need for increased North Island reserves reduces the amount of North Island generation capacity to supply electricity, which generally increases both North Island spot electricity prices and North Island reserve prices.

The HVDC can transfer reserves between the islands as well as electricity eg, it often uses cheap South Island reserves to help cover North Island generator risks. In that case it is the combination of electricity and reserve transfer that is constrained by the HVDC limit. This means that inter-island electricity and reserve transfer compete for capacity in a similar way to generator electricity and reserves, causing electricity and reserve price separation to occur simultaneously.

Another way high HVDC transfer levels can cause price separation is when the HVDC becomes the ‘risk setter’ ie, it is the largest part of the system that could fail. So, to cover the risk the HVDC poses, the North Island must have enough reserves available to cover an unexpected HVDC failure. Thus, the effective cost of using cheap South Island electricity to meet North Island demand is increased by the cost of North Island reserve.[3]

Other contributing factors to price separation during November have been North Island thermal and geothermal power station outages[4]. Geothermal power stations contribute cheap electricity, and their loss must be covered by more expensive thermal or hydro power. Also, the largest and most efficient Huntly thermal unit, Huntly 5 (see header image), was on outage with its generation being covered by more expensive thermal units. Since Huntly 5 is very large, its outage also contributed to the HVDC being the risk setter more often.

This complex spot price behaviour indicates that spot prices have reacted to changing underlying conditions. The Authority monitors spot prices, and instances of price separation, in our weekly trading conduct reports.

Image: Huntly Power Station Unit 5 uses natural gas as its fuel source and is able to generate up to 403MW of electricity.

[1] See our explainer: Spot prices fall as hydro storage increases.

[2] New Zealand’s electricity system is designed to cover the unexpected loss of the largest risk (called the ‘risk setter’), usually the biggest generator in each island or the HVDC. This is achieved by having reserves, or extra “just in case” generation, available in each island. See our explainer: Keeping the lights on with reserves. 

[3] Actually, it is usually the difference between North and South Island reserve prices, not just the North Island reserve price, because increasing North Island reserve means that less South Island reserve is required to cover North Island generator risks.

[4] Read our explainer: Why do power station outages occur?

Why do we need electricity reserves?

Electricity is a unique product because electricity generation and consumption must match moment to moment. The System Operator sends instructions (based on an optimisation algorithm that minimises total system cost) to generators to ensure this balance is maintained, but there are always risks of unforeseen events. For example, a sudden change in electricity consumption, a transmission line getting damaged, or a generation unit failing. In order to ensure the lights stay on, there needs to be enough reserve ie, “just in case” generation capacity, to respond to an unexpected and sudden event.

The New Zealand power system runs on a frequency of 50 Hz. If electricity generation and consumption (including losses[1]) remain in balance, the frequency stays at 50 Hz. If consumption is higher than generation, the frequency will drop below 50 Hz and vice versa. The equipment on New Zealand’s grid is designed to operate in a relatively narrow band around 50 Hz and could be damaged or operate less efficiently if the frequency moves outside this band. Large thermal generating units are particularly sensitive and will disconnect from the grid to protect themselves from damage if they detect frequency outside the allowable band.

In the worst-case scenario, a drop in frequency could cause a generation unit to disconnect which could drop the frequency further, leading to a cascade of disconnections resulting in a black out. Frequency keeping reserve (FKR) and instantaneous reserve (IR) are designed to prevent such scenarios by responding to changes in frequency.

What is frequency keeping reserve?

To keep the frequency at 50 Hz, every half hour the System Operator selects one or more generators to be frequency keepers in each island. The frequency keepers monitor for small changes in frequency and adjust their generation output to keep the frequency within a small band around 50 Hz.[2] The HVDC also has controls to help balance the frequency between the islands, allowing the frequency keeping duty to be shared between generators in both islands. Frequency keeping is mainly intended to respond to small changes[3] in electricity consumption or generation (such as sudden changes in wind generation), but is not enough to respond to a large change (such as a large generation unit suddenly failing), so instantaneous reserve is also needed.

What is instantaneous reserve?

Instantaneous reserve[4] is spare capacity which can quickly respond in the event of an unexpected event which causes a large drop in frequency. This ensures the continued supply of electricity to consumers. The amount of instantaneous reserve needed is determined by the largest part of the system that could fail. This is usually either the largest generation unit that is running or the transfer across the HVDC.

Some instantaneous reserve is provided by interruptible load, for example hot water heating and some industrial processes. Interruptible load providers are paid the reserve price in exchange for allowing their load to be interrupted. However, the majority of reserves are provided by electricity generators. This is provided either by a unit generating below its full capacity[5] or a unit ready to start generating within a few seconds[6]. Instantaneous reserve can be shared between the islands if the HVDC is not the largest risk and is not running at full capacity.

How does the reserve market impact the electricity market?

Electricity and reserves are produced by the same generation stations ie, a power station can offer in both electricity and reserves for the same time period[7]. However, any capacity used as electricity cannot be used as reserve and vice versa. The market selects the optimal allocation for each power station between what it should generate for electricity and what it should keep in reserve, to keep total system costs as low as possible.

Most of the time the cost of providing spare capacity as reserve is low. However, sometimes generators need to run units inefficiently to provide reserves, so this reserve is offered at a higher price. Other times generators would miss out on high electricity prices to provide reserve, so the reserve price is increased[8] to make up the difference. Also, some units can only be used for reserves when they are generating already. This means that occasionally high-cost generation is brought on so that it can provide reserve[9] as well. Again, the reserve price increases to account for this higher electricity cost. All these mechanisms can result in spikes in the reserve price, with a recent example shown in Figure 1. Most reserve prices were below $2/MWh during the week shown, with occasional spikes up to $250/MWh in the North Island.

Figure 1: Sustained instantaneous reserve prices in the North and South Island, w/c 20 November 2022

The amount of reserve needed in each island is determined by the largest part of the system that could fail. This means that when reserve prices are high, reducing the size of this risk setter could reduce overall costs. For example, if the largest generator is 500 MW and running at full capacity, 500 MW of instantaneous reserve (IR) is needed to cover the risk. However, if the largest generator’s output is reduced to 490 MW, only 490 MW of IR is needed.

If the cost of an additional 10 MW of electricity from another generator is less than the cost of an extra 10 MW of IR, the largest generator will be asked to generate only 490 MW. This can also occur when the HVDC is the risk setter, constraining the amount of generation that can be transferred and contributing to price separation between the islands, discussed in ‘New Zealand’s geography and price separation’.

The Authority monitors both the spot energy market and reserve market in our weekly trading conduct report.

The future of reserves

Battery technology offers new solutions to both frequency keeping and reserve, as well as other ancillary services like voltage support. Meridian Energy has recently received resource consent for its 100 MW battery storage project.

SolarZero, which offers solar panel and battery services, has started offering interruptible load into the reserve market, taking advantage of installed batteries. It is likely that battery technology will become an integral part of the reserve market (and the electricity market) and could reduce reserve prices.

[1] For a description of losses, see our explainer: New Zealand’s geography and price separation.

[2] The “normal” band is 49.8 to 50.2 Hz but often a tighter tolerance is achieved.

[3] Up to around +/-30 MW.

[4] There are two types of instantaneous reserve dispatched each trading period, fast instantaneous reserve (FIR), which must be able to react within 6 seconds and be sustained for 60 seconds, and sustained instantaneous reserve (SIR), which must be available within 60 seconds and be sustained for 15 minutes.

[5] This is referred to as partly loaded spinning reserve (PLSR). Offers for PLSR take into account ramp up rate as well as total capacity. Most thermal and hydro generation units can offer PLSR, dependent on how quickly they can ramp up.

[6] This is referred to as tail water depressed reserve (TWDR) and is offered by some hydro generation units. It involves running the unit like a motor without water flowing through the turbine. The control gates can be quickly opened to allow water to pass through the turbine and generate electricity if needed.

[7] Interruptible load providers offer only into the reserve market.

[8] The market clearing engine automatically increases the reserve clearing price to account for this lost opportunity (ie, opportunity cost) of generating electricity.

[9] Partially loaded spinning reserve.

Figure 1: Genesis's Rankine Unit 4 at Huntly Power Station being prepared for outage (26 October 2022)

Electricity in New Zealand is generated by hydro dams, geothermal and thermal power stations, and wind farms. Some of these power stations were built recently, like the Waipipi wind farm in Taranaki which was completed in 2021. Others are over 60 years old, like the Roxburgh dam in Central Otago. Maintaining each power station is critical - power stations cost millions to build and generate the electricity that facilitates modern life across Aotearoa.

Power stations have regular outages for planned maintenance or to be recertified. Power stations also have unexpected outages when equipment fails. Most planned outages occur during summer when demand is low and less electricity generation is needed. During winter, minimal planned outages occur, as high demand requires more electricity generation.

Many South Island hydro outages are planned to align with New Zealand’s annual inter-island transmission cable outage in February. This cable outage reduces electricity transfer between the North and South Islands for about one week.

Figure 2 shows New Zealand’s average daily generation outages from 2013 to 2022. In 2020 the inter-island transmission cable outage moved from November to February and so outage volumes moved respectively.

Figure 2: Average daily generation outages (MW/day) by month, from 2013-2022 (scheduled in Transpower’s POCP customer portal)

Outages in 2022 differed slightly from previous years - outages through to June 2022 were high, but then fell below historic levels from July. This likely arose from the following factors:

• The Clutha Upper Waitaki Lines Project (CUWLP) upgraded transmission lines between the Clutha and Upper Waitaki, which enabled more generation from the Manapōuri, Clyde and Roxburgh dams to be transferred northwards. Some South Island hydro generators coordinated their outages with nearby transmission outages related to CUWLP.
• COVID-19 delays may have shifted scheduled outages from 2020/2021 into early 2022.

Next year, the inter-island transmission cable outage will occur between 23 February and 6 March 2023. So, parts of the Manapōuri, Benmore, Aviemore and Takapō hydropower stations have scheduled maintenance outages at this time.

The electricity sector coordinates outages through Transpower’s POCP portal. Generators log outage start and end dates and the amount of unavailable generation. Transpower uses POCP data for the New Zealand Generation Balance (NZGB) which predicts situations where simultaneous outages could pose a risk to the supply of electricity, especially if demand is forecast to be high.

Transpower’s calculations on NZGB, based on the current schedule of outages, show a good buffer of electricity supply compared to forecast demand for the rest of this year and first half of next year. Transpower regularly update these calculations as more information becomes available.

The Electricity Authority actively monitors trading conduct as part of the new trading conduct provision which came into effect on 30 June 2021. This includes monitoring generation outages to ensure participants comply with trading conduct rules.

In New Zealand, between 80-95% of electricity is generated by renewable sources, with the majority produced by hydro dams. Most dams are in the South Island and their electricity is ferried to the North Island via large cables (called the High-Voltage Direct Current or HVDC).

The additional water used in dams (hydro storage) is refilled by both rain and snow, with snow having a particularly strong seasonal impact on storage. Hydro lake levels typically drop during autumn and winter, as hydro generation runs hard and rain falls as snow on the slopes of the Southern Alps. Then snowmelt flows into the hydro lakes in spring and summer. This snowmelt contributes to between 20-70% of spring and summer water inflows[1] in the South Island’s hydro lakes.

There are three main water catchments in the Southern Alps, the:

• Waitaki river, which feeds hydro dams like Benmore and Aviemore;
• Clutha river, which runs through the Clyde and Roxburgh dams; and
• Waiau river, which flows through the Manapōuri Power Station.

Snow typically accumulates at elevations above 1,000 metres, so the first two catchments experience more snowmelt as their mountains are higher.

New Zealand experienced its wettest winter on record in 2022. In late October 2022, national hydro storage was 23% percent above the historic mean ie, the lakes were high, when typically, they would be low. Hence, snowmelt - combined with already high lake levels - could see high hydro storage persist at lakes Pūkaki, Hawea and Takapō throughout the remainder of the year.

Figure 1: Estimated seasonal snow storage in the Waitaki catchment, 1 April - 22 October 2022

Figure 1 shows an estimate of snow storage in the Waitaki catchment up to 22 October 2022, produced by Meridian Energy. Meridian estimate that the Waitaki catchment has ~1,500 GWh of snowmelt in the catchment on 22 October 2022, which is above the 75^th percentile. Lakes with less snowmelt, however, like Manapōuri and Te Anau, could remain with low hydro storage, especially as NIWA are forecasting normal or below normal rainfall[2].

Figure 2 below shows storage at New Zealand’s main hydro storage lakes in 2022, alongside the historic mean and 10^th and 90^th percentiles of lake levels.

Snowmelt is vital to New Zealand’s electricity generation. Ongoing work seeks to improve our understanding. This online tool visualises where precipitation anywhere in the world will flow. For example, see this example of a raindrop (or snow flake) falling in the Southern Alps, and how this snow fall eventually runs out along the Clutha river through the Clyde and Roxburgh power generation dams. The NIWA website also displays snow depth across different mountains in New Zealand.

The Electricity Authority monitors hydro storage and how it changes throughout the year. Current and past national hydro storage levels can be found at Electricity Authority - EMI (market statistics and tools) (ea.govt.nz).

Figure 2: Hydro storage at major South Island hydro lakes in 2022, alongside the historic mean and 10th and 90th percentiles between 1926 and 2021

[1] Nottage-et-al.-2010.-CC-Adaptation-In-NZ.pdf (climateandnature.org.nz)

[2] Seasonal climate outlook September - November 2022 | NIWA

Electricity in New Zealand is generated from hydro dams, wind farms, geothermal power stations and thermal power stations, which run on coal, gas or diesel. A small percentage of electricity is also generated from solar farms and co-generation[1].

The majority of New Zealand’s electricity (60-70%) comes from hydro dams - with the largest dams located in the South Island. Many dams have storage, which save water for future use. This allows hydro dams to ramp up and down generation to match electricity demand. Geothermal generates another 15-20% of Aotearoa’s electricity. It produces electricity at a near constant rate and cannot adjust its output.

Wind farms generate between 5-10% of New Zealand’s electricity. Wind generation has no flexibility[2] and is dependent on how the wind is blowing, meaning the electricity market must react to its fluctuating output. Other sources of electricity, like hydro and thermal, must either make way or make up for wind.

There is currently 1.04GW of wind generation installed in New Zealand, which is about 10% of New Zealand’s total capacity. The largest wind farms are in South Taranaki and the Tararua ranges, with others in Otago, Southland and Wellington.

Wind generation is as tricky to forecast as wind itself, and sometimes an accurate prediction only materialises a few hours in advance. Currently, wind and thermal generation are inversely related. If wind generation is high, thermal generation is generally low and vice versa.

The influence of wind on electricity spot prices and thermal generation can be seen in Figure 1, which shows the spot price between 3-4 October 2022, alongside wind and thermal generation.  On 3 October alone, wind fluctuated from roughly 50MW in the morning to over 700MW by the evening. The nationally averaged spot price rose close to $250/MWh when wind was low and thermal generation was high. Prices then dropped to roughly $5/MWh when wind was high and thermal generation was lower.

Figure 1: Wind and thermal electricity generation and the half hourly spot price between 3-4 October 2022

As more wind farms are built, ever improving wind prediction will allow the flexible system surrounding wind generation to react to its fluctuating power output. In a 100% renewable future, hydro generation, and potentially demand response, grid scale batteries and thermal generation - fuelled using biomass - will support wind, instead of fossil fuelled thermal generation.

The Electricity Authority recently released a paper discussing how around 400-500MW of investment in new supply or demand response will be needed every year until 2050 to help meet New Zealand’s renewable electricity goals.

The Electricity Authority monitors wind generation, see our weekly Trading Conduct Reports and Quarterly Reports.

Figure 1: Short-dated forward prices, 4 October 2021 – 3 October 2022

Why do we have a forward electricity market?

Electricity in New Zealand is sold from generators to buyers[1] every 30 minutes via auctions. These buyers must pay the electricity spot price, explained in Eye on Electricity #2, which changes every auction to reflect underlying market conditions.

The forward electricity market (or electricity futures), however, allows electricity buyers to purchase a forward contract. This contract protects buyers against volatile spot prices by fixing their electricity price for a specified period. This creates more certainty in the market, as electricity buyers (sellers) will have more stable costs (earnings).

How are forward prices determined?

Forward prices reflect expectations of future electricity demand and generation costs. These prices are determined by market buyers and sellers and therefore represent the consensus view of future prices.

Forward price contracts for New Zealand electricity can span a period of months or quarters. This reflects the extent the contract covers. Contracts ending within a year are dubbed ‘short-dated’ contracts, while those extending over a year are called ‘long-dated’ contracts.

What influences forward prices?

Current and projected market conditions impact forward electricity prices. Hydro storage, as explained in Eye on Electricity #1, tends to heavily impact short-dated future prices, making them potentially more volatile than long-dated future prices. High hydro storage depresses spot prices as abundant hydroelectricity can be offered cheaply into the market. So the cost of short-dated forward prices tends to fall as hydro storage increases.

Figure 1 shows short-dated forward electricity prices as of 3 October 2022. The December 2022 contract price began declining in early July 2022, as hydro storage began increasing (see vertical blue line). This indicates that high hydro storage is likely to keep spot prices depressed through to December 2022. The March 2023 contract price dipped slightly as hydro storage increased, however it has since increased again. The cost of the June and September 2023 quarter contracts did not react to increasing storage, as these were unlikely to be impacted by high hydro storage.

Other factors which can impact forward prices are seasonal climate expectations, namely the possibility of either an El Niño or its sister La Niña. The El Niño-Southern Oscillation can affect the electricity industry at both ends of the spectrum, by changing expected demand patterns and weather systems, which impacts both hydro and wind generation.

Industry participants can also impact forward electricity prices with corporate announcements. For example, in July 2020 when Rio Tinto announced that the Tiwai Point aluminum smelter (which is New Zealand’s largest electricity consumer[2]) would cease operating, forward prices declined sharply. This reflected an expectation that more electricity would be available in the market after its closure. However, when in January 2021 it was announced that Tiwai Point would remain open, forward prices bounced back up.

In late August 2022, Genesis[3] launched their Market Security Option. This indicated an expectation of rising thermal fired electricity generation costs, and subsequently forward prices increased, as seen in Figure 1 (see vertical red line for the announcement date).

The Electricity Authority monitors the forward electricity market and publishes commentary in each quarterly report, which can be found here.  Readers can find interactive plots showing how forward electricity prices are changing at: Electricity Authority - EMI (market statistics and tools) (ea.govt.nz).

[1] Both retailers, who buy electricity on the behalf of consumers, and large industrial electricity users.
[2] Consuming roughly 12% of New Zealand’s electricity.
[3] A company which operates many New Zealand power stations.

The heavy rain that has lashed the country in recent times may have caused flooding and numerous slips in parts of the country but there has been one upside – storage in New Zealand’s hydro schemes has risen rapidly.

As of August 25, hydro storage was sitting at 77 per cent of the theoretical maximum storage – at 3400GWh up 28 per cent on the same time last year.

As the lakes levels have risen, prices on the spot market have fallen because of the abundance of available hydro generation as seen in Figure 1.

Fig. 1: Weekly average spot price Otahuhu relative to Hydro Storage April-August 2022

The decline in spot prices relative to the abundance of hydro storage contrasts with the events of December 2019 when spot prices remained elevated despite hydro storage increasing, as seen in Figure 2.

Fig. 2: Weekly average spot price Otahuhu relative to Hydro Storage October-December 2019.

Following a year-long investigation after a claim made by seven claimants, the Authority decided there was an undesirable trading situation for the period between  3-27 December 2019 and reset prices for the period of the UTS to a level that was more consistent with the abundance of water available for generation.

The Authority introduced new trading conduct rules in June 2021 and is actively monitoring trading conduct behaviour.

The recent high inflows into hydro lakes as also impacted on the futures market with Forward Electricity Market prices falling for the remainder of 2022 as seen in Figure 3.

Fig. 3: Forward Electricity Market prices 26 May-17 August 2022