Federal and State Government agree to power bill

On Friday National cabinet met and agreed on the states introducing a cap on wholesale gas and coal. The temporary cap will be set at $12/GJ for gas and $125/t on coal. The caps will not enforce on export contracts therefore not limiting the opportunities on high international prices.

During the meeting it was agreed that the states would sort out the coal cap and the federal government would change laws to legislate the $12/GJ cap on domestic gas. As the caps are focused on the domestic market, they will only have a small impact on the profitability of producers. It is anticipated that only 4% of gas and 10% of coal will be affected by the cap, the remaining volumes will be exposed to international markets.

As the states have been tasked with implementing the cap it is likely they will go down different routes in achieving the same outcomes. The simplest state to implement the changes will be Queensland as the government still owns and control 80% of the coal fired generation fleet. Queensland will likely use its directive powers and instruct its government owned corporations (GOCs) to dispatch the coal assets below specific prices. NSW will likely use changes in law to cap the price for the state.

In line with the price caps, national cabinet also discussed an assistance package to lower the impact on families and business as a result of high inflation and high commodity prices.

The cap mechanism will be used for uncontracted gas and coal, this may have limited impacts on generators as the majority of coal and gas has already been produced under longer term contracts with strike price below the proposed caps.

At this stage it is unlikely that the mechanism will be in place until February despite federal politicians being recalled to Canberra on Thursday to discuss the issue. While the bill will get the support of the House of representatives it is expected the Greens will put pressure on the Government in the Senate to limit any compensation for the coal producers.

When the futures market opened on Monday morning it was evident the traders expect the caps to flow into the market. Both QLD and NSW futures dropped by $20/MWh for later dated quarters and over $30/MWh for Q123.

Edge2020 have an eye on the energy market, enabling us to support customer supply and demand agreements. Our clients rely on our experts to ensure they are informed, equipped, and ideally positioned to make the right decisions at the right time. If you could benefit from an expert eye on your energy portfolio, we’d love to meet you. Contact us on: 1800 334 336 or email: info@edge2020.com.au

The South Australian island and running on renewables

On November 12th a series of storms passed through South Australia that had the potential to black out the whole state, as had previously happened in 2016. Whilst parts of South Australia did lose power, it was far less dramatic than the last weather event due to a significant amount of work that has been undertaken by AEMO to build a more secure grid since the 2016 blackouts.

In 2017 AEMO released a review of the events that had blacked out the state; the main cause was of course the extreme weather that had knocked over transmission lines as well as some wind farms not meeting protection standards. Similar to 2016, it was destructive storms that passed through South Australia and damaged the network on the 12th November. At 4:59 PM, the market was notified of a significant power system event due to the tripping of multiple transmission lines. Both elements on the Tailem Bend – Southeast 275kV transmission line had tripped. Some transmission towers were damaged and had fallen over, resulting in the South Australian grid being disconnected from the NEM. On Saturday at 6:03 PM, AEMO notified the market that South Australia had been reconnected to the NEM after the 275kV transmission line at Tailem Bend was returned to service.

During events like this AEMO invokes its power to manage system security; however, this time, it went a step further and constrained off-rooftop PV to maintain a secure level of Distributed PV (DPV) generation. AEMO switched off as many rooftop PV installations as possible during the middle of the day, a rare occurrence known as “islanding” of the state grid to maintain stability, designed to keep the DPV below the secure threshold. PV generation is not as easily controlled as other sources. At times South Australia can meet all domestic demand for power via rooftop solar and sends surplus to Victoria but this cannot be managed in an islanded state, therefore requiring the curtailment of the rooftop PV allowing AEMO to manage scheduled and semi-scheduled generation assets to maintain system security.

Smart metering is required to enable the shutting down of rooftop PV systems, however not all South Australian PV systems can be controlled remotely as they have older inverters. This resulted in only 50% of systems being curtailed. Over time as more rooftop PV systems are installed using smart inverters, there will be more control of their output. Currently, AEMO can control 100MW of PV generation, but during the recent event, it also used voltage control to trip off a further 300MW of rooftop PV out of approximately 1,000MW of installed capacity.

The South Australian network has now been re-synchronised to the NEM, and electricity is flowing between South Australia and the other states of the NEM as before. While South Australia was isolated from the NEM for a week, South Australia was powered by wind and solar for up to two-thirds of its electricity demand, with gas providing the difference. System stability is a delicate balance between the supply of electricity, the types of generators providing the electricity and the electricity demand from end users. This time, part of the solution was to encourage end users to consume more electricity, enabling a higher generation level. Before the curtailment, South Australia was supplied by over two-thirds of its demand via renewable generation.

While high levels of renewable generation are good for keeping electricity costs down, the savings can be eroded by high-frequency control costs and the need for a more expensive gas-fired generation to fill the gap when the sun is not shining, and the wind is not blowing.

Edge2020 have an eye on the energy market, enabling us to support customer supply and demand agreements. Our clients rely on our experts to ensure they are informed, equipped, and ideally positioned to make the right decisions at the right time. If you could benefit from an expert eye on your energy portfolio, we’d love to meet you. Contact us on: 1800 334 336 or email: info@edge2020.com.au

Market Report – Quarter 3 2022

Overview of National Electricity Market (NEM) Quarter 3 2022

International drivers continue to increase gas and electricity prices across the NEM. The main reason for this increase has been and continues to be the tight supply / demand balance resulting from Gas flow restriction in Europe, associated with the war in Ukraine. The reduced flow of gas in Europe has resulted in a greater demand for Australian gas that in turn has put cost pressures on Australian gas market. Higher priced gas then links into to Australian electricity market, leading to higher spot and futures electricity prices.

For Q322 electricity spot prices averaged $216/MWh across the (NEM). The Q322 average spot price of electricity was close to matching the all time record of $264/MWh that occurred in Q222. Interestingly, the average price of electricity for Q322 was more than three times higher than the same quarter the previous year. In Q321the average price of electricity was $58/MWh.

NEM operational demand increased by 2.6% or 559MW to 22,414 MW compared with the same quarter last year. We also saw demand increase for the first time in Q3 since 2015. Households and businesses used more electricity from the grid as a result of their underlying electricity consumption increasing and the output from their rooftop Photovoltaic systems (PV) not generating as much as normal due to cloudy conditions.

High spot prices occurred at the start of Q322 on the back of record high spot prices seen across Q222. The July NEM monthly average of $360/MWh was $23/MWh higher than the June 2022 average of $337/MWh. Later on in the quarter spot prices fell with August Electricity prices averaging $145/MWh across the NEM. Until this year QLD, NSW, VIC and TAS have not recorded a Q3 average electricity price of over $100/MWh. South Australia reached this milestone in Q316 at $119/MWh.

Historically Q3 is not a volatile quarter, but this year it is different, Q322 saw 24% of the dispatch intervals with a price over $300/MWh. This is on the back of the previous quarter, in July prices exceeded $300/MWh 61% of the time, the highest monthly proportion since  the start of NEM. Many intervals saw prices in the $300-$500/MWh range resulting in spot prices moving above the historical price cap threshold of $300/MWh.

Below are the drivers that elevated spot prices and volatility in Q322.

  • A reliance on thermal generation (coal and gas fired) with higher fuel cost due to the increased demand for these resources internationally.
  • Hydro generation setting prices at elevated levels due to limited water supply and bids adjusted to meet revised trading strategies.
  • An increase in demand as consumption increased and rooftop PV generation reduced due to cloudy skies.
  • Price volatility significantly increased the average spot price of electricity with large jumps in spot price due to the distribution of generation offers within the bid stack. The market operator stacks all offers from lowest to highest to build the bid stack. The spot price for a trading interval is the offer price of the marginal unit at the required generation level to meet demand. The bid stack ranges from -$1,000 to $15,500/MWh. During August the spot price reached over $1,000/MWh as generators withdrew generation for technical and economic reasons.
  • With higher average electricity prices we also saw less negative electricity prices across the NEM. In the previous year we experienced negative prices 17% of the time but for Q3 we have only experienced negative prices 9% of the time.

Weather

A La Niña event was declared across the NEM increasing the likelihood of above average winter-spring rainfall across much of northern and eastern Australia, while a negative Indian Ocean Dipole (IOD) event increased the likelihood of rainfall across southern and eastern Australia. Q322 was very wet, with many sites recording their wettest July on record. Wet weather continued across Q3 with September’s rainfall being the fifth highest on record across Australia. Temperatures at the beginning of the quarter were below average in many parts of Victoria and Tasmania and above average minimum temperatures occurred across south-east Australia.

La Niña resulted in wet and cloudy conditions impacting solar generation and the supply of coal to power stations, in additon to the export market resulting in higher prices.

Electricity Demand

As outlined above the NEM demand has changed since the same time last year, the below chart shows this graphically.

 

 

 

 

The chart below shows how the demand in Q3 has increased in recent years.

 

 

 

 

 

 

 

The charts below also show the slow down in the growth on rooftop PV and change in operational demand.

 

 

 

 

 

 

 

NEM Spot Prices

NEM spot prices have increased significantly and have reached unprecedented levels.

The cost of the underlying fuels for generators has led to these increases. Coal and gas prices are at all time highs due to international demands leading to a high cost of generation. The chart shows the correlation between East coast gas price and the price of electricity. Coal also corelated closely to the cost of generation and a resulting electricity spot price.

Prices have also increased as renewables generation (solar, wind and hydro) is lower due to cloud cover reducing solar, low storage levels reducing hydro generation and hence it bids in at higher prices. There have also been large swings in the output from wind which results in spot market volatility.

 

Generation and Offer Prices

Gas contributed the most to supply in Q322 and as result of the high cost of gas this has influenced the average spot price.The lower volume of generation from coal was a result of bidding behaviour withdrawing thermal capacity and intermittent generation like solar and wind taking a larger market share.

A lower capacity factor for coal generation has resulted in coal fired availability moving higher up the bid stack resulting in coal fired generation needing to dispatch at higher spot prices to meet their long run average costs.

 

 

 

 

 

 

 

 

 

 

 

Emissions

NEM emissions intensities declined this quarter slightly to 0.6 tCO2-e/MWh. Total emissions were 0.2% lower than Q321.

Australian Stock Exchange (ASX)

The futures market was influenced by a higher spot market, gas prices and the delays experienced with large scale renewables, a slowing in the rooftop PV market and climate conditions likely to reduce the output from solar generation.

The future price of electricity traded on the ASX for Calendar 2023 (Cal 23) continued to increase in price across the quarter in the four NEM mainland regions. Cal 23 New South Wales futures finished the quarter at $232/MWh, with Queensland at $224/MWh, South Australia at $193/MWh and Victoria at $157/MWh.


Credits: All charts in this report are sourced from AEMO

 

Edge 2020 offer market leading services for business energy users who require a resource they can trust. We help you navigate the ever-changing energy landscape and ensure the proactive and accurate delivery of advisory, account, and portfolio management services and associated outcomes. Reach out, we would love to assist you: info@edge2020.com.au or call on:1800 334 336

 

Green hydrogen

Green hydrogen

In the brightest day and the blackest night, no opportunity shall escape my sight.

Ok, bar the bad Green Lantern pun, Green Hydrogen is the superpower on everyone’s lips at the moment. From the USA releasing its draft National Clean Hydrogen Strategy and Roadmap a few weeks ago, to the announced changes in the Hydrogen regulation in Europe, even Queensland has jumped on the press release bandwagon, announcing it as a cornerstone within its new Jobs and Energy Plan.

But what is this superpower? How can it help and what does it really do?

Well let’s start at the beginning, what is Green Hydrogen, why is it different to Grey or Blue Hydrogen and why is that important?

Green Hydrogen is produced by electrolysis, by splitting water into its base elements of Hydrogen and Oxygen. The reason it is Green is this process is done using renewable energy. The most preferred approach is to have this PPA (green energy) onsite and therefore Behind the Meter, however it is equally classified, at the moment, from other sources, with both the PPA and electrolyser being grid connected. Noting that there are additional costs if this is not co-located BTM generation as Network costs come into play.

The differential between this and Grey and Blue Hydrogen isn’t the process, but the fuel used to power the electrolysis. Grey Hydrogen comes from Natural Gas and Blue is from Gas but that is coupled with Carbon Capture and Storage (a technology which has been the silver bullet since I was at Uni and despite millions being pumped into the technology remains uneconomic and therefore unused).

Why is this important – well to truly move towards a clean energy future, and for Hydrogen to play a large part in that, the technology used to create the hydrogen must be green, otherwise the end product (the hydrogen) is just an energy transition of the non-renewable source which was used to create it. This is why the Europeans (CertifHy) amongst others, will only allow Green Hydrogen certification from real PPA sources, not greenwashed with carbon credits, and certainly not from any other forms of electricity.

So how can the green hydrogen transform our supply? Well ignoring other uses of the fuel and export at the moment, transportation being a key area which could benefit as their fuel is hard to abate without a viable alternative as well as Ammonia and Methanol production. There is the obvious use if the fuel can be used for power supply.

This is moving closer with the planned Tallawarra B 200MW dual fuel power station (natural gas and green Hydrogen) due online in the summer of 2023/ 24. If this technology can be proven, this will be a huge source of clean energy which can be used for grid stability and baseload generation, it could also remove any bumps from the transition away from coal.

To give a sense of scale though 1KG of hydrogen is equivalent to about 33.3KWh of electricity. Last year the NEM supplied around 204TWh of electricity, so we would require around 6.2million tonnes (or 6.2billion KG) of Hydrogen to power the NEM.

Now the part to blow your noodle, to produce that 1Kg of Hydrogen we need to put into the electrolyser around 50KWh of electricity (taking a 67% efficiency rate for an Alkaline or PEM electrolyser, noting Solid Oxide electrolysers can have higher efficiencies.) Using this 67% efficiency rate we need to put in 310TWh of electricity to be able to produce the 240TWh required for the NEM. This is without factoring that Hydrogen which can be used for transportation and that which will be exported (with Japan underpinning many domestic projects how much will be available in Australia initially? But I said I wouldn’t be diverted to this today!).

This means the Hydrogen power industry alone has the capability to more than double the capacity requirements of the NEM. However, this requirement and thirst for power could be its real secret superpower.

Network constraints are the words every solar and wind operator hates, the renewable energy is being produced but either cannot be transported to the load centres or cannot be used in the local distribution zone and as such is wasted. Although the Hydrogen industry may not be able to use all this excess volume, especially in the near term, it certainly can absorb a large amount of it. Thus, reducing curtailment and increasing the renewable penetration to the grid.

But that isn’t its only superpower to assist with the balance of the grid, cast your mind back to this winter with curtailment being requested from every corner of the NEM. Rather than being the off-taker, the electrolysers can provide demand side management. They will naturally be programmed to react to the price and renewable energy generation signals anyway to be efficient. Therefore, turning up and down at these strained periods without needing market intervention will be a benefit we have not previously been able to tap into.

Hydrogen certainly looks to be the silver bullet this industry has been craving, and no one wants to be left behind when this train leaves the station. However, with so much in theory and nothing as yet proven to scale, we all hope that it doesn’t turn out to be the Aquaman of the superhero world.

Edge2020 provides energy management and advisory services to buyers and sellers of physical and financial energy products. We specialise in electricity, gas, renewable, environmental, and carbon products. Edge2020 can help ensure you achieve your business sustainability goals by supporting you with strategies that focus on minimising consumption and responsible purchasing of renewable energy. Reach out to our passionate team for support to improve your sustainability outcomes – email: info@edge2020.com.au 

 

International oil price fluctuations and the electricity market reacts

Organization of the Petroleum Exporting Countries (OPEC+), the intergovernmental organisation of 23 oil exporting nations mainly in the Middle East and Africa (with the original core 13 holding most power) is the body which is responsible for around 40% of the world’s oil production. In early October this group agreed to slash the output of crude oil by 2 million barrels a day. To put this in perspective Saudi Arabia produces on average 10 million barrels per day of the current, already reduced, 42 million barrels coming from the OPEC+ nations and this 2-million-barrel reduction translates to about 2% of the global oil supply. It is also worth noting in 2016 when OPEC became OPEC+ Russia joined the organisation and has held a strong voice ever since.

This reduction in production, shows a sign of deepening rifts between the Middle East and the US, and the cynic in me says may be more than slightly linked to the upcoming US mid-term elections where the democrats are already looking weaker than their GOP counterparts – not that those countries have ever influenced an American election in the past *Cough Trump Cough*.  But regardless of motives these new production limits will come into place in November and the impending reduction in production has repercussions which flowed through the broader Australian and global energy markets including oil, coal and gas.

Australian electricity prices are strongly correlated with the international crude oil price, particularly in QLD and NSW, the impact of Brent crude futures hitting a high of $US93.39 on Monday caused a rally on the Australian electricity market, with the Q123 QLD price rising 20%, as the effect of this increase translated to the domestic electricity market. Brent Crude being the international oil benchmark price.

However, OPEC+ are not the only drivers of the oil price, especially WTI and Brent prices. The US dollar, on the back of a fear of a global recession has been strengthening which has dampened the demand for their oil on the international stage. (Consider the FX implications of a strong dollar, if you are buying from Europe the same amount of crude oil now costs more as the number of Euros to achieve the same dollar amount has increased). So, a reduction in demand of America Oil due to FX and reduction in export from OPEC+ can only move the needle up in price regardless of source.

We also cannot ignore the ongoing COVID implications in Asia, especially China. Their glut of demand has not returned to anywhere near the pre-pandemic levels and as such that demand is not translating into a price war to ensure delivery of the commodity. Conversely to above this is actually holding prices lower and reducing the impact of the OPEC+ reduction.

But there is no ignoring the elephant in the room, the impact of Russia’s invasion of the Ukraine, which has led to global increases in commodity costs, has also acted as a buffer to the oil price despite the recession fears. As many countries imposed their own moral code and refused to buy Russian oil, other sources could benefit from the increase in demand. By the end of September this year Russian oil was trading at $20/barrel cheaper than its Brent counterpart. Some less scrupulous countries such as India and China, sought to benefit from this price differential and ignored the sanctions coming from the West and are now taking at least half of Russia’s oil exports. Further, Russia has now overtaken Saudi Arabia to be the biggest exporter of oil into China. Therefore, could the cut in reduction be as simple as the rest of OPEC+ looking to balance the loss in demand from the East by passing inflated prices to the West?

But back to Australia, we are obviously a commodity rich nation, however with our internal thirst for electricity and therefore generation linked heavily to the export price of that commodity, we are subject to these international fluctuations also. As the price of the oil increases, the global demand from that commodity shifts to other sources. Our gas and coal price domestically are therefore linked heavily to the price that exporters can achieve if they send our home-grown coal and gas abroad. So as the demand shifts from oil, to gas or coal so does the price. Hence the correlation described above with Brent rising and that coming into our domestic market.

Then for fun lets add in our own pressures, we are expecting another La Nina this year, last year’s summer La Nina brought low solar output coupled with flooding, wet coal stockpiles and just-in-time delivery delays due to the tracks being flooded and trains not able to deliver.

We also have an economy which is having increasing inflationary pressures. These inflation increases will flow onto the interest rates (including the interbank rates) and therefore commodity prices. How? Well, a retail return is based on 2 main drivers, network and wholesale costs, the latter we have covered above. But in isolation network costs will also increase, due to the inflation increasing the nominal value of the asset and therefore the increasing value of the debt as the interest rates increase also.

Further any investment required to transition our market to greener fuels will also be increased, as the levelized cost of electricity for these new assets is also increased due to cost of capital and higher interest rates feeding through. As such the ‘Energy transition’ will now cost more.

There is also a regulatory driver, with an impending price cap increase being fast tracked, this will allow system stability to flow through, as gas won’t withdraw at the $300/MWh cap as this looks likely to be increased to $500/MWh. Therefore, does that become the new ceiling of our market?

There is an old idiom that when China sneezes Asia catches a cold, I unfortunately think this now needs to be broadened to when any imbalance occurs the ripples will be felt globally.

The balance is so tight that without some easing of any fundamentals the shocks will continue. AEMO are acknowledging this, but despite acknowledging the issues they are desperately clinging to the hope a capacity market will be the silver bullet to system stability, backed by large synchronous generators, not that they have any benefit from that mechanism. However, I cannot agree, point in fact I point you to the black outs in the UK on August 9th 2019, a market which has had a capacity mechanism for many years yet in a moment of system instability these ‘capacity assets’ could do nothing and they experienced a blackout for 45 minutes and over 1 million people were affected.

What this means for us is without regulation around bidding behaviour based on cost of generation from hedges not advantageous forward prices, we are looking at another summer with uncertainty and volatility based on international fundamentals pulling the Australian market along for the ride.

Winter is coming

Now I am a major Game of Thrones fan, but I never thought moving to Australia that I would turn into Ned Stark and constantly worry about a Northern Hemisphere Winter. But, as we are hurtling towards those cooler months in t’north and following the tumultuous Q2 and start of Q3 in the NEM, I am preaching that the Northern ‘Winter is Coming’ and even down here in Australia we must be ready.

As background Northern Europe, UK, France, Belgium, Germany etc., rely on feeds of Gas from Norway and Russia. Gas is significant in Europe as a 1-degree shift in temperature can result in around 5% of domestic demand increase, or decrease, due to most homes being heated via Gas-Central heating. With a third La Niña about to be called in the Southern hemisphere and La Niña, correlated with colder winters in Europe, with increased snowfall, as it shifts the jet stream north to the pole and increases storms across Northern Europe, this can only mean an increase this heating demand.

This confluence of events would usually increase my concern for a tight supply in the European market, but this year is different. Ignoring for now the Russian flows, we will circle back to that later, Norway’s Energy Minister has already raised the possibility that they may restrict electricity exports with possible restrictions to Gas flows as well. With much of their electricity coming from hydro, and after an un-seasonably warm summer period, Norway has stated the priority will be to refill the reservoirs over winter, rather than secure the energy supply of their European neighbours. With this flow being restricted into Northern Europe, coupled with a diminishing fleet of coal and nuclear options, gas will be the favoured source of domestic supply for Northern Europe. Although there are other interconnectors, it is anticipated these will either be significantly under utilised or such a price differential within a domestic market will occur to ensure flows to a single market will ensue. This could be facilitated by pushing those areas (countries) price up to exorbitant amounts to ensure flow across the interconnector and shore up domestic supply. With flows of course favouring higher priced regions.

Now let’s put Russia into the mix. Russia announced this week that the Nord-Stream 1 pipeline, a crucial pipeline for gas flow into Europe, required maintenance from the 31st August. This happens to coincide with European markets trying to firm up winter supply by filling storage and Russia increasing aggression to the Ukraine, but I am sure that was a coincidence.

The 3-day maintenance will have a return to service for the 2nd September. But how likely is this to return? Well, if the last outage is anything to go by, where only 40% of the required flow reached Europe and the delivery of the required turbine was strangely delayed, the price increase was significant and totally in Russian control. Now with this latest outage and flows expected to be around 5% of the obligations agreed with the EU, the cynic in me wondered if Putin is trying to offset the sanctions place on Russia by pushing the cost of Gas to exorbitant amounts. If he can sell his 5% for the same as the revenue from the already inflated 40% and free the remaining gas for sale to more amiable neighbours, he is in a win-win situation.

The real fear is that this flow remains low for the whole of Europe’s winter, which would not only put massive strain on the cost of generation but also lead to many retailers simply not able to meet their obligations and go under. There is also a risk of lack of supply and therefore blackouts as well as increasing costs on an already strained economic environment.

To mitigate this, European generators are throwing out their climate targets with the baby and the bath water in favour of supply and are scrambling to shore up gas supply and return coal-fired power stations from cold storage. The Mehrun Coal-Fired Power plant in Saxony Germany came back online at the start of August, Uniper have just announced they are re-commissioning the Heyden plant in North Rhine-Westphalia and in the UK, the government has made moves to re-open the rough gas storage facility, 25% of it initially, ignoring the safety concerns which led to its original closure. But this will not be enough, and this is where Australia needs to brace itself for a secondary wave of impacts.

LNG and coal exports into Europe will increase, as the price differential will be significant. The ensuing impact through the JKM on the domestic gas market, and coal export price will affect the replenishment of the longer-term running costs of our own generators.

Although significant volume should be pre-hedged, these prices will start feeding through, nothing is stopping the trading opportunity cost being passed through by generators. They will argue the replenishment of the stockpile will need to factor these spot and forwards prices, interesting that doesn’t flow through in a bear’s market though.  What does that mean for our summer, well it means the high prices aren’t going anywhere fast. The shortage of supply in the NEM may be diminished, with most, if not all units now returned from overhaul, yet the price is continuing to take advantage of, and reflect the international fundamentals rather than the real long run average cost of the asset.

With the Capacity Mechanism being put on ice and strengthening Safeguard Mechanisms already announced by the Labor Government, coupled with favourable international fundamental conditions providing political cover for generators, could this be the last hurrah for coal and gas generators to eek the last value from these assets?

Either way be under no illusions, with the Northern winter hurtling towards us, European prices already building in shortfalls in supply and no end to the Ukraine conflict in sight, the Vega sensitivity is going off the chart and is not going to be subsiding anytime soon. As such Australia, and especially its energy markets need to brace, for the fallout.

To circle back to Game of Thrones, Ramsay Bolton stated, “If you think this has a happy ending, you haven’t been paying attention” for ‘winter is coming’ and we must be prepared.

The Safeguard Mechanism – not so safe anymore

Once again, the Labor government has shown its teeth when it comes to climate. Last week rebuffing the Energy Security Board’s action for a Capacity Mechanism, which would inevitably only benefit large coal and gas generators, and today bringing out a consultation paper to reform the Safeguard Mechanism.

This hasn’t come as a surprise as it was a cornerstone of their election campaign, but to have done it so quickly may surprise some, and to have a start date for these reforms at the start of the next financial year, 1st July 2023, will surprise many.

To re-cap, the Safeguard Mechanism is the legislation which came in in 2016, it was designed to reduce the emissions of the industrial sectors within Australia with targets or baselines capping the amount of emissions each facility can emit. The flaw was that the large industries could continue to re-set these baselines so as to ensure that as production increased, so did the baseline and as such the emissions would also be increased without penalty. In the Financial year 2020 – 2021, these large emitters made up 28% of Australia’s Carbon Footprint

What is currently being proposed is a type of basic cap and trade model with stricter reduction targets, to help the government achieve their net 43% reductions by 2030 and net zero by 2050. This equates to reductions for these large emitters of an initial 3-6% and increasing post 2030.

The consultations also ask for feedback on whether the concept of using industry average benchmarks should be used to set all baselines. This will be strongly argued against by industry, especially since the published default values are significantly lower than most emitting facilities. However, it may enforce the desired reductions, this I am sure will be a major discussion topic in the weeks ahead.

Other parts of the paper discuss increasing the transparency of the Australian Carbon Credit Units (ACCU) market and the Carbon Offsets used to abate the excess Scope 1 emissions. This would support the tender sent out late last year to establish a trading platform for the Carbon Credits, which would de-mystify the pricing and availability of this currently opaque market. This is a measure, I am sure, will be welcomed across the industry, especially by those projects with excess certificates.

However, what will not be welcomed from the green flank in government, and their supporters, is the possible future inclusion of international Carbon Offsetting certificates. With many of these trading at significant discounts to the Australian government accredited ACCUs, the value of these domestic projects could be significantly eroded if international credits can be applied to excess emissions.

The drafts of the responses will be being formed by C&I regulation teams over the coming weeks, with the aim to try and protect their position and emissions as much as possible. I am sure they will be arguing for facility specific, production adjusted targets with the cheapest offsets possible for over emissions. However, how successful their lobbying will be is yet to be seen. This new government is not afraid to turn the status quo on its head and with ambitious climate targets, and with international eyes watching, I am not sure that industry will receive the desired outcome from this reform. With the consultation closing at the end of September this will certainly be one to watch before the end of the year.

Market Update – Q3 2022 to date

As we move out of Q2 2022, a quarter that we have never seen behave in this way before, it is interesting to see how things have changed in Q3 to date.

Why was Q2 2022 so controversial? Well, we saw record spot prices, record forward prices, caps put on the gas market, caps put in place in the electricity market, market direction, the activation of Reliability and Emergency Reserve Trader (RERT) and eventually suspension of the National Electricity Market (NEM). As we moved through Q3 has the situation changed?

To make this decision we must first review Q2, to assist us in understanding if things are going to change. What caused all the market intervention in Q2 and the eventual market suspension?

Q2 is normally a quiet time in the NEM, demand is low, and generators take the opportunity to take units offline for routine planned overhauls. The drop in availability that results from the units on overhaul are normally soaked up by the remaining units online. This Q2 we saw a lower than normal number of units online across the NEM to take up this slack, namely Callide C4 that was offline due to the catastrophic failure in May 2021, Swanbank E and thermal generators dispatching less volume due to flooding across NSW and QLD reducing coal supplies.

Q2 2022 saw average spot prices more than double compared with recent years and peaked at the end of the quarter. The average for Q2 2022 reached $332/MWh in Qld, $302/MWh in NSW, SA at $257/MWh and VIC the lowest, at $224/MWh.

Interestingly the quarterly average price for NSW and QLD was above where the Administered Price Cap (APC). The APC is triggered when the sum of the previous 7 days trading intervals equals $1,359,100. The price is then capped at $300/MWh and remains in place at least until the end of the trading day.

Q2 2022 was a quarter of extreme price, low availability, and market interventions. In Queensland for example we saw 42 hours of spot prices below $0/MWh but also 32 hours above $1,000/MWh. While we did not see a significant number of prices reaching the market cap of $15,100/MWh we did see solid prices that increased the average to levels not normally seen in Q2.

During Q2, exacerbating the issue, we saw significant volume bid in below $0/MWh so units would remain online, however with little between this price and higher prices meant there was a visible gap in the bid stack until prices were over $300/MWh. This distribution was a result of higher fuel cost such as spot gas at $40/GJ which converts to a generation price of over $400/MWh. However, we also saw the emergence of strategic bidding that introduced volatility and higher average prices into the market. The result of the strategic bidding was spot prices for the majority of the time across the NEM were above $100/MWh and often above $300/MWh.

As coal supplies became limited due to flooding, the gas price also jumped due to the global supply issues caused by the war in Ukraine. These fundamentals led to the spot prices increasing and eventually forcing the market operator to cap the market when the Administered Price Cap was reached. APC put a cap of $300/MWh on the electricity spot market.

As a result of the APC, generators removed capacity out of the market rather than operating at a loss due to their higher spot fuel cost. This resulted in the removal of over 3,000MW of generation in which forced AEMO to intervene in the market and direct units online as well as being forced to activate RERT to maintain system security.

Over a few days operating under the APC the market became impractical to operate using directions and AEMO eventually suspended the market on 15 June 2022.

During market suspension AEMO took over the control of the dispatch of market participants units.

Simultaneously during the market suspension, availability returned to the market as units returned from overhauls, coal and gas supply restriction improved and trading strategies were reviewed by the market participants.

On 24 June 2022 AEMO lifted the suspension of the market and the NEM returned to normal operation.

Since the lifting of the market suspension and the commencement of Q3 we have seen a change in some behavior, however spot prices remain high. In the first week of Q3 market participants took advantage of market conditions of low intermittent generation ensuring they benefitted from the ability to increase volatility. In the first week spot price hit the new maximum price cap of $15,500/MWh on several occasions.

While these price spike has lifted the quarterly average for the first 21 days of Q3 to $466/MWh in QLD and $418/MWh in NSW we are seeing this average drop each day.

The main driver for the lower spot prices is, as mentioned before, the improved availability across the NEM. Availability in QLD is regularly reaching 9,000MW compared to in June when it dropped 6,600MW. The short-term outlook for generation continues to improve daily with the majority of planned outages now completed.

A secondary driver that has pushed down average prices is the return of the sun. Solar generation is now regularly pushing the spot price below $100/MWh and on some occasions back into negative territory.

Less volatility in the spot market has been reflected in the forward market with Q422 QLD dropping from over $270/MWh in June to $260/MWh and the Q123 product dropping below $250/MWh.

Without delving into the gas supply concerns in Victoria, all other states have removed the price cap on gas allowing the market to operate more efficiently. This has not resulted in the gas market trading at significantly high prices as feared, Qld is $42.75/GJ, NSW is $51.51/GJ and SA at $45.51, translating into a sub $500/MWh peaking gas plant cost of generation.

As the weather warms up and the daylight hours increase, we expect to see a drop in demand, with heating loads reducing coupled with an increase in the generation provided by solar.

All of this, as well as increased thermal generator availability and stability in the gas markets, should see spot and forward prices continue to fall across the quarter.

Is UFE the UIG of Australia?

Anyone who knew me in my past life in the UK knows that I harped on about Unidentified Gas (UIG) A LOT!

The idea behind UIG is simple, allocate the gas which couldn’t be attributed to a meter in an area across all end users in that area, in which it was used (off-taken). Seems simple right. But when was the last time you actually gave a meter reading? Possibly six months to a year ago? Well that means your off-take (unless you are on a smart meter) is estimated and you will be either over or under on allocated unidentified gas.

Although this seems sensible with everyone eventually giving a meter read and therefore it will all work out in the wash, what exacerbates the issue, especially at the moment, is the extreme increase in the gas price at which these charges are now passed through to retailers and then in turn our bills.

Now what does understating this UK gas usage or allocation have to do with Australia? Well, quite a lot. The system is similar, but not the same.

Following Global Settlements being introduced by AEMO we have started seeing Australia’s version of these charges coming into our bills. We allocate the unidentified – called Unaccounted for Energy (UFE) within each region by the off-takers in that area.

What we are not doing yet, which in the UK’s defense they do there (through XOServe), is take into account those meters which are half hourly ready (smart(er) meters) and therefore their usage should be known. Currently in Australia the offtake in a region will be directly linked to your proportion of an energy being allocated to you and you literally have no say in these charges, despite having updated metering capability.

The sore point of it all is that this is occurring at a time when our electricity market is extremely high and therefore there is a possibility of the combination of large UFEs  being passed through to end users at high prices, with companies having no control over the volume or price it is passed through at. This is leading to significant shocks to companies’ outgoings, as there is little to no visibility on the charge on any given month, and no way to forecast them to budget.

I fear that UFE will become my new soap box issue, and I can guarantee this isn’t the last anyone will hear on this. I am pretty sure I won’t be the only one who will be making noise.

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Labor pushes ahead with a controversial capacity market

What is the goal of a capacity electricity market?

You may be forgiven for not sitting through the full press conference last Thursday, where the Albanese government stated Australia would be strengthening their 2030 targets to 43% under the Paris Agreement. However, if you had, around 30 minutes in you would have heard Chris Bowen, the newly appointed Minister for Climate Change and Energy state, “in relation to the short term, State and Territory Ministers agreed with me last week, that we should proceed at haste, at pace, with the capacity mechanism. I asked, on behalf of all Energy Ministers, the Energy Security Board to proceed with that work, at speed, and they are doing that. I am very confident I will be able to get agreement of State and Territory Ministers for a comprehensive capacity mechanism and I’ll have more to say when that work is ready.”

Well that work dropped this morning (20th June) at 7am. They have given those who wish to respond until (25th July) to submit their views on this paper so at pace it shall be. However; given the response following the ESB Post 2025 paper I am not sure that any amount of noise and lobbying from the industry is going to stop this juggernaut from achieving its goal, especially since it is being backed by those generators who have the most to gain from this market. Not only that, but unless there is a big bump in the road, a first look Capacity Mechanism will be in place by 1st July 2025.

What is the goal of this market? – Well in my opinion there is only one reason that this would be encouraged and that is to subsidise coal-fired power stations which have had their financial viability severely questioned by the growing penetration of lower cost renewables within the system. Don’t get me wrong, the longer-term markets have the potential to encourage other faster starting generators onto the market, but this hasn’t really been the case in other capacity markets i.e. Great Britain (GB).

This argument is only further strengthened when looking at how the GB Market ended up achieving their stability, in their high renewable penetrated market, which is from nuclear power which has been guaranteed a strike price of £92.50/MWH or ~$163/MWh. Thus, making any capacity market payment minuscule in comparison to the underpinning of the generation at that rate.

The ESB are arguing, and convincing themselves and the government in the process, that this mechanism is the answer to AEMO’s ISP step change scenario, in which demand increases and coal exits the system. If that is indeed their argument, then they are ultimately stating they cannot efficiently run a system in which coal is not part of the generation mix and unless this is financially managed there will be a ‘disorderly transition.’

The question therefore isn’t will there be a capacity mechanism from July 25, but how centralised or decentralised will the final design be? Will it sit as a Physical Retailer Reliability Obligation – PRRO design, one in which the market determines for itself the level of the required capacity, or do we go wholly down the regulated route with AEMO determining in long term auctions (similar to the GB model which has several T-year auctions) and they forecast demand and supply to determine the required level of capacity and sell these capacity certificates to retailers to meet their requirements.

There is no grey area for the ESB, they have stated openly in the paper they wish for the forecasting and determination of the capacity requirements to be centralised and for AEMO to manage these purchases on behalf of market participants. In essence they would moderate the capacity of these generators, for a cost, at certain times of day or periods of high system stress to allow them to ensure capacity is available to the market operator when needed. End users would then pay for that management of the system and their portion of that capacity.

The other point to note, keenly hidden within the paper is the four yearly review of the Reliability Standard and Settings Review (RSSR) that is about to be undertaken, with significant interest been taken in the Market Cap, especially given the gas price cap is equating to a marginal cost of generation higher than the electricity price cap (Presuming a normal heat rate of 8-12). If the caps are risen for both the caps $300/MWh and spot $15,100/MWh markets as expected, could the requirement of ‘capacity’ in the market become a moot point? Surely the exacerbation of the current situation could be avoided if the gas generators were certain of meeting the cost of generation and you cannot truly believe that a market cannot efficiently run with enough capacity if they are achieving $15,100/MWh or possibly more?

The real key argument which has not been addressed by the paper however, is the idea that aging coal plants are unlikely to be able to ramp in time to fill the gaps between this growing renewable penetration. Therefore, the question really needs to be asked is this the right investment if you really want to transition this grid or should this be put into different technology rather than prolonging the life of unsuitable assets?

Ultimately however the bottom line remains ‘user pays.’ As such any one of the options being floated will be passed through to end users through retailer or network tariffs.

I will let the retailers and generators pick apart the nuances of the paper, but needless to say the government will be pushing ahead with this in some form, the only question will be how much say we will have in the centralisation of the market or not, and therefore how much control retailers will have on the costs of this capacity.

Written by Kate Turner, Senior Manager – Markets, Analytics, and Sustainability