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QLD smashes electricity demand record during heatwave but narrowly avoids high pricing

Midway through February 2018, Queenslanders sweltered through a severe heatwave, which saw statewide average temperatures exceed 40°C for several days. These extreme conditions resulted in electricity demand in QLD exceeding the 9,400 MW threshold for the first time ever. Not just once, but four days in a row starting from Monday the 12^th of February (see Figure 1).

The previous record for the highest ever electricity demand was 9,369 MW and was set on 12 February 2017. This figure was eclipsed during the 5pm trading interval on 14 February 2018 when total demand reached 9,840 MW. During this time, the Australian Energy Market Operator (AEMO) had also declared an actual lack of reserve (LOR 1) event for QLD. Despite these record breaking levels of demand, the 30 minute spot price remained at relatively modest levels below $350/MWh over the four days (see Figure 2).

Some might look at this modest pricing and conclude that QLD was a long way away from reaching $10,000/MWh. However, this could not be further from the truth. In order to understand just how close the market was to a price spike, we need to examine the generator bidstack.

Generator bidding data shows QLD narrowly escaped extreme pricing

The dispatch process is complicated but to put it in very simple terms: generators submit bids to AEMO for each five minute dispatch interval, signalling how much electricity they are willing to provide and at what price. AEMO’s central dispatch process then orders these bids from least to most expensive. The least cost generators (taking into account constraints) are dispatched to serve the demand in the market. The marginal bid (i.e. the last/highest cost generator that is selected) sets the price for everyone in that dispatch interval. The bidstack changes every five minutes depending on market conditions and generator bidding behaviour.

The data sets that contain the bidding information for the National Electricity Market (NEM) are notoriously difficult to access and work with. For this purpose, we use a very nifty software package from Creative Analytics (part of the Energy One group) called NemSight. NemSight allows us to extract relevant bidding data with ease and in an intuitive, easy to understand format.

For our exercise, we have extracted the bidding data for two days: 11 October 2017 and 14 February 2018. These two days were very similar in terms of price outcomes. The 30 minute spot price peaked at $259/MWh on 11 October 2017 compared with $338/MWh on 14 February 2018. Furthermore, both days had a similar average daily price ($115/MWh on 11 October compared with $105/MWh on 14 February). Despite these similarities, the bidding data tells a very different story in terms of how close each of these days came to a price spike.

Figure 3 shows a comparison of the generator bidstack for each day. We have shown the dispatch interval where pricing was the closest to spiking on each respective day. The regional bidstacks (in teal) have been adjusted to account for constraints and imports via the interconnectors. In red, we have the corresponding electricity demand for that particular dispatch interval. The data shows that 11 October 2017 was more than 600 MW away from reaching price levels greater than $10,000/MWh. In contrast, 14 February 2018 was a knife’s edge away from very high pricing with very little room for things to go wrong in the market. QLD energy consumers were very lucky to walk away from the heatwave relatively unscathed.

Coal and gas generators were less available when needed the most

In addition to the static snapshot in Figure 3, we also examined how the bidding behaviour of QLD generators evolved on 14 February 2018. The video below is an animation from NemSight. It shows how the volume offered, and the price at which it was offered, changed throughout the day. The interesting thing to note is the dropping availability in the afternoon, which pushes prices closer to the brown zone (>$10,000/MWh).

This reduction in availability was predominately due to Gladstone (black coal), Millmerran (black coal), and Braemar 1 (gas) as shown in Figure 4. These fossil fuel generators lost availability when needed the most in the late afternoon. This raises several questions for policy makers. In particular, what portion of fossil fuel capacity can reliably meet peak demand?

If there is one thing that our analysis here has shown, it is that when it comes to the energy market, there is almost always more than meets the eye. This highlights the need to understand underlying market dynamics rather than relying on conventional wisdom or incomplete data to make decisions. This is more important now than ever as we enter an unprecedented transformation of the electricity sector.

Author: Marija Petkovic, Founder & Managing Director of Energy Synapse
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Victoria sets new record for electricity prices

Victoria has traditionally been considered the “boring state” when it comes to volatility in wholesale electricity prices. But that all changed last month when the average spot price for Victoria hit $133.48/MWh, setting a new record for January prices for the state. January 2018 narrowly missed out being the highest flat average for any month, only being surpassed by June 2007 ($143.28/MWh).

This increase in volatility comes on the back of 2017, which saw several factors come together to create an unprecedented energy crisis in the National Electricity Market (NEM). Some of these key factors include a decade of policy uncertainty, exit of ageing generation, high gas prices, outdated market rules, and a lack of competition. The energy crisis during 2017 produced the highest annual average spot price for Victoria ($66.58/MWh) since the commencement of the NEM in the late 90s. Despite energy becoming one of the hottest issues in government and the media over the last 18 months, high pricing has continued into 2018 as seen in Figure 1.

January 2018 has been unusually hot for Victoria. According to long term climatic data from the Bureau of Meteorology, Melbourne has an average of 0.7 days with temperatures ≥ 40°C during January. January 2018 had three days that exceeded 40°C. In contrast, January 2017 had none, and January 2016, only one. Furthermore, this is the first summer without Hazelwood, a 1600 MW brown coal fired power station that closed at the end of March 2017.

Victoria had four days in January where spot prices exceeded $2,000/MWh, compared with zero in the whole of 2017, and only two during 2016. The highest pricing came on Thursday the 18^th of January 2018. The spot price peaked at $12,931.04/MWh during the 5pm trading interval, setting a new record for the highest ever 30 minute spot price in Victoria. A scorching heatwave drove electricity demand up to relatively high levels. However, the 18^th was only the third highest demand day in the month. We were able to take a deeper dive into how the day unfolded by using NemSight, a software created by Creative Analytics (part of the Energy One Group).

Coal and wind generation were both less available

As can be seen in Figure 2, Loy Yang B, Victoria’s newest and most efficient brown coal-fired power station, tripped in the afternoon resulting in a sudden loss of 525 MW. Furthermore, wind power availability was about 700 MW lower than earlier in the day. Although this loss of generation was much more gradual. Nonetheless, reduced availability of coal and wind were both significant. This is because both are very cheap sources of power.

The generator bidding data in NemSight shows that all Victorian wind farms were bidding 100% of their output at prices ≤$0/MWh. Similarly, Loy Yang B was bidding all of its output at prices ≤$25/MWh. The reduced availability of this cheap electricity made Victoria more dependent on the highest priced gas and hydro generators, who were bidding in excess of $10,000/MWh, and thereby driving up prices. Figure 3 shows a summary of the bidding behaviour during the peak price period from 3 to 6pm.

Smart energy to pave the way forward

The events of the 18^th of January highlight another point. When it comes to the reliability and affordability of electricity, it is not a battle between renewable energy and fossil fuels.  Thermal generators are susceptible to failure at high temperatures. While intermittent renewables, such as wind, are dependent on prevailing weather conditions and hence are largely out of our control. Neither characteristic is effective for meeting peak demand reliably. Rather than waging a war between renewable energy and fossil fuels, we should be thinking about how we can make our energy systems more intelligent and resilient with enabling technologies such as energy storage, demand response, and predictive analytics. Smart energy is the key to a cleaner, cheaper, and more reliable electricity grid.

Author: Marija Petkovic, Founder & Managing Director of Energy Synapse
Follow Marija on LinkedIn | Twitter