Possible extension to the gas caps

Image of Gas Stove

It is likely today that the Climate change and Energy Minister Chris Bowen will announce an extension to the $12/GJ cap on wholesale gas. Currently the gas caps will expire at the end of the year. Following the release of the draft mandatory code of conduct the market will have several weeks of consultation.

Energy producers are likely to be concerned over an extension or possibly permanent changes to the wholesale gas. Energy producers will also be concerned that changes will impact the pricing of long-term deals as it is likely a reasonable pricing clause will be included.

Under the reasonable price provision, gas companies could only charge a price based on the cost of production plus a reasonable margin. The reasonable price does not consider the capital invested during exploration and development of projects. Gas buyers will be able to challenge the price of contracts via a formal dispute process. The dispute process is designed to determine what the ‘reasonable’ price should be.

While the extension to the cap mechanism will provide certainty for energy users, energy producers remain in a holding pattern.

Gas producers are not finalising new gas supply contracts for 2024 until the government confirms what the impact of the code will have on pricing.

The federal government have also set the expectation that the federal budget will include a Petroleum Rent Tax. The Australian Petroleum Production & Exploration Association (APPEA) have shared with its members concerns that changes to the taxing of gas producers will add $100B of tax receipts to the government.

To appease the gas production sector, it is expected the new code will allow for exemptions. New projects that add supply for domestic use may qualify for exemptions from any specific pricing provision.

APPEA said the code “must recognise the importance of gas in a cleaner energy future, and the need to ensure settings which enable investment in new supply to avoid forecast shortfalls and put downward pressure on prices”.

Gas industry developers continues to warn the broader industry that deterring investment in new gas supply will harm the supply to manufacturers and reduce the secure of supplies of electricity across the NEM.

Beach Energy’s chief executive has said that getting the terms of the code wrong could imperil Australia’s transition to low-carbon energy given the role gas plays to support renewable energy.

At the end of the day changes to the industry need to benefit producers, end users and ensure gas and electricity security is achieved. While international cost pressures are impacting the gas and electricity industry. The continued development of gas resources are required to provide gas the opportunity to be the transitional fuel as Australia strives to its Net zero emission targets.

Dispute over forecasted supply “gap” in East Coast gas market

Gas

AEMO last week released a report which forecasted a supply “gap” on the east coast gas market of up to 33 petajoules on assumptions that the three Queensland LGN ventures exported all their uncontracted gas this year. The report warned of a risk of a gas shortfall in the southern states this winter unless the LNG exporters in Gladstone diverted shipments from export to domestic customers.

Santos’ GLNG joint venture has spoken out against the winter gas shortfall forecasted by AEMO saying that Queensland’s three LNG ventures have committed to make available all the domestic gas expected to be needed this year. AEMO’s forecast did not account for the ventures move to supply an additional 100 terajoules a day of gas this winter.

The joint venture said it had sold more than 15 petajoules of gas to wholesalers, retailers and power generators which will deliver gas between May and September “to alleviate critical peak winter demand in east coast gas and electricity markets”.

GLNG also said AEMO’s data was based on forecasts and the other two Queensland LGN ventures had offered more than 20 petajoules of domestic gas for sale, and there has been no spot LNG export from Gladstone in 2023.

The GLNG chief executive Stephen Harty commented taking all those factors in consideration, “it looks like any potential shortfall has already been fully mitigated.”

On April 1st the Federal Resources Minister is due to start deciding whether to curb LGN exports from Gladstone on a quarterly basis if required to avoid shortfalls in the domestic market.

The reform of the Australian Domestic Gas Security Mechanism (ADGSM) has Queensland LNG exporters and their customers in Asia concerned due to the volumes of gas that Asian nations rely on.

AEMO’s report again has called upon the Albanese government to match support, it has voiced for the role of gas through the energy transition with policy measures. Which would encourage investment in the development of gas resources.

Despite this, the cap implemented on wholesale gas prices and proposed ongoing regulation through “reasonable pricing” provisions on the east coast market has caused gas producers to put several investments in proposed projects on hold. The rules are to be included within the mandatory code of conduct which is expected to be released within the coming weeks.

Industry gas executives are currently arguing for some relaxation of the rules to allow new projects that are needed to meet demand to go ahead, and that barriers to new gas supply investment are removed on the east coast as more gas supply is needed over the coming years. Victoria and NSW state governments are also under pressure to relax restrictions on onshore gas development.

 Edge2020 have an eye on the energy market, enabling us to support price  benefits as well as 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

Energy Market Update – East Coast

Energy market prices

Edge 2020 round up of the last week

Week ending Friday 17th March

QLD

  • QLD prices ranged between -$315.80/MWh and $15,500/MWh for the week ending 17th March 2023, averaging $191.36/MWh.
  • Hot humid weather at the back end of the week resulted in demand increasing and spot prices spiking. Over the evening peak on Thursday spot prices hit the $15,500/MWh market cap while on Friday’s evening peak the price reached $14,500/MWh. Outside these spikes the maximum daily price remained below $400/MWh.
  • Solar output increased across the week as cloud cover reduced. Solar output peaked on Friday at 2,002MW, however there was limited solar available over the evening peaks on Thursday and Friday to suppress spot prices.
  • Wind generation was low during the high spot price events. High spot prices on Thursday and Friday occurred just prior to the evening ramp up of wind. Part of the week saw no wind generation across the state, however output peaked in the early hours of Saturday morning at 443MW. Typical of load swings on intermittent generation by 14:15 the same day wind generation had dropped to less than 2MW.
  • Gas fired generators continue to increase their output. Darling downs hava moved from an intermittent profile to a baseload / peaking hybrid by ramping up generation over the evening peak. Swanbank E continues to operate after midday through until the following morning as seen in previous weeks. Yarwun operated around the clock. During the high price events on Thursday and Friday, Townsville was joined by Roma and Oakey to cover the price spikes.
  • While Wivenhoe continues to operate every evening, the duration is reducing as spot prices decline. Kareeya has joined Barron Gorge in operating throughout the week at 86MW and 66MW respectively. Output from Barron gorge was reduced to zero prior to the evening peak on Thursday due to river safety but had returned to full load by the time the high prices occurred.
  • Coal fired availability remains high despite some reliability issues. During the high price events some generator reduced output, but most remained unchanged. The reason for the sustained high prices on Thursday was a chain conveyor issue at Kogan Creek that took 250MW out of the market. Tarong North was taken out of service during the week and the until returned to service over the weekend.

NSW

  • NSW prices ranged between -$47.00/MWh and $14,506/MWh for the week ending 17th March 2023, increasing the average to $169.43/MWh thanks to several price spikes on Thursday and Friday.
  • Solar output continues to drop again this week, peaking slightly lower than last week at 2,357MW. Similarly, to Queensland there was minimal solar output during the spot price spike on Thursday and Friday.
  • Wind generation was also low across NSW during the high spot price events. High spot prices on Thursday and Friday occurred just after wind output dropped by ~800MW. Output peaked in the early hours of Monday morning at 1,492MW. Prior to the high prices on Thursday output was also high reaching 1,440MW only hours before the spot price spikes.
  • Tallawarra returned to base load operation this week with Colongra, Smithfield and Uranquinity providing the occasional evening peak generation. All gas units ran over the evening peaks on Thursday and Friday when the high spot prices occurred.
  • Coal fired availability remains high this week with no unplanned unit outages. All coal fired units are now cycling their units across the day to reduce exposure to negative prices but are increasing output over the evening peak and into the night when spot prices are higher. The price spike was partially caused by Vales Point 5 being out of service.

SA

  • SA prices ranged between -$982.42/MWh and $1,004.70/MWh for the week ending 17th March 2023, averaging $67.97/MWh.
  • Solar generation was heavily constrained again this week due to negatives prices and system security concerns, solar peaked at 414MW with output ranging between 360MW and 410MW for the back end of the week.
  • High levels of wind generation during solar hours resulted in solar being constrained. Wind output peaked at the end of the working week at 1,173MW significantly lower than previous weeks. Wind output also dropped below 20MW for part of the week, but this was when solar output was high. High spot prices continue to occur when wind generation is low.
  • Torrens Island B and Pelican point continued to share the synchronous generation across the week. Dry creek, Quarantine and Osbourne also ran over the higher priced intervals throughout the week.

VIC

  • VIC prices ranged between -$995.78/MWh and $357.49/MWh for the week ending 17th March 2023, averaging $57.54/MWh.
  • Solar generation was heavily constrained due to negative spot prices but still managed to peak at 803MW and ranged between 700MW and 760MW across most of the week apart from over the weekend when output was constrained to 450MW.
  • Wind generation in Victoria was sporadic peaking at 2,763MW but dropping to less than 5MW at some parts of the week. Similar to South Australia, higher spot prices continue to occur when wind generation is low.
  • Hydro generation remained unchanged to last week with across the week with Murray, Eildon and Dartmouth only operating during the higher priced parts of the day.
  • Availability of coal fired generation in Victoria remains unchanged with no outages.

Energy users wait for lower price after intervention bill

Following the passing of the energy reform bill in Canberra last Thursday, end users are waiting to see when the price of gas and electricity starts to match the caps imposed in the wholesale market.

Prior to the passing of the intervention bill, end users were looking at gas deals above $30/GJ. Now a cap of $12/GJ has been imposed, what will be the offer price to gas consumers? AGL have been quoted,

“as soon as the legislation is passed, they will try to get some better offers”

The legalisation covers uncontracted wholesale gas and capping this portion of the market at $12/GJ may not see the benefits flow through to end users.

Large end users of gas have the option to procure gas from the spot market, this segment of the market is not covered by the $12/GJ cap so prices in the gas spot market are likely to be higher than $12/GJ. So, with coal prices peaking again above $300/t is there the potential for gas to now be the transitional fuel to renewables?

The war in Ukraine has influenced the transition to renewables and potentially speed the process up worldwide. European countries are now less likely to take significant volumes of gas from Russia, so they will be looking at alternative fuel sources. As a result of the gas supply issues out of Russia, some European countries are reviving their coal fired generation fleet while they transition to renewables.

While international gas prices remain high, Australian gas producers have been very vocal in leaving the domestic gas market alone and let it work as intended. They argue the gas market will fix itself, higher prices will signal the investment in new supply, resulting in lower long term energy prices.

The gas market is currently proving to be very profitable for producers at the expense of end users. A recent report from the regulators exposed that the majority of offers for 2023 gas were over $30/GJ and a report out of AEMO shows the cost of production is $9.50/GJ or below. With a potential continuation of the $20/GJ profit for gas producers they will be pushing to make gas the transitional fuel and push out the coal industry.oc

While the intervention bill is designed to be in place for 12 months, the ACCC has flagged an extension to the reasonable pricing framework saying they,

“would be expected to be required until domestic gas prices are reflective of the underlying costs of production and that there is sufficient supply at these prices”.

At Edge2020 we will continue to monitor both the gas and electricity markets to understand the impacts these market caps will have on the prices offered to end users.

Edge2020 have an eye on the energy market, enabling us to support price  benefits as well as 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

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

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.

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.

Is this happening to your business? If you feel you need more control of your company’s energy spend, please reach out to discuss joining our Edge Utilities Power Portfolio (EUPP) where we use the power of bulk purchasing to help Australian businesses of all sizes save on their energy bills. Read more: https://edgeutilities.com.au/edge-utilities-power-portfolio/ or call us on: 1800 334 336 to discuss. 

 

AEMO Suspends the Market

Below is the media release from AEMO after it suspended the National Electricity market at 14:05 today.

AEMO today announced that it has suspended the spot market in all regions of the National Electricity Market (NEM) from 14:05 AEST, under the National Electricity Rules (NER).

AEMO has taken this step because it has become impossible to continue operating the spot market while ensuring a secure and reliable supply of electricity for consumers in accordance with the NER.

The market operator will apply a pre-determined suspension pricing schedule for each NEM region. A compensation regime applies for eligible generators who bid into the market during suspension price periods.

In making the announcement AEMO CEO, Daniel Westerman, said the market operator was forced to direct five gigawatts of generation through direct interventions yesterday, and it was no longer possible to reliably operate the spot market or the power system this way.

“In the current situation suspending the market is the best way to ensure a reliable supply of electricity for Australian homes and businesses,” he said.

“The situation in recent days has posed challenges to the entire energy industry, and suspending the market would simplify operations during the significant outages across the energy supply chain.”

Edge wish to reiterate, this is not a physical supply issue. AEMO directed 5GWhs of physical generation into the market. If generators can operate when under direction, they do not have a physical reason to not generate (such as maintenance, overhaul etc), so the reduced availability we are seeing has to be a commercial trading decision to either price volume into higher price bands or to remove availability in the maximum availability bands of their bids. The availability is there, the generators are just not offering it via the spot market.

The market suspension is temporary, and will be reviewed daily for each NEM region. When conditions change, and AEMO is able to resume operating the market under normal rules, it will do so as soon as practical.

Mr Westerman said price caps coupled with significant unplanned outages and supply chain challenges for coal and gas, were leading to generators removing capacity from the market.

He said this was understandable, but with the high number of units that were out of service and the early onset of winter, the reliance on directions has made it impossible to continue normal operation.

The current energy challenge in eastern Australia is the result of several factors – across the interconnected gas and electricity markets. In recent weeks in the electricity market, we have seen:

  • A large number of generation units out of action for planned maintenance – a typical situation in the shoulder seasons.
  • Planned transmission outages.
  • Periods of low wind and solar output.
  • Around 3000 MW of coal fired generation out of action through unplanned events.
  • An early onset of winter – increasing demand for both electricity and gas.

“We are confident today’s actions will deliver the best outcomes for Australian consumers, and as we return to normal conditions, the market based system will once again deliver value to homes and businesses,” he said.

What does it mean for generators and end users.

  • Bidding and dispatch will continue as usual under the market rules.
  • Dispatch instructions will be issued electronically via the automatic generation control system as usual
  • If required AEMO may issue dispatch instructions in any other form that is practical in the circumstances.
  • Spot prices and FCAS prices in a suspended region continue to be set in accordance with NEM rules or under the Market Suspension Pricing Schedule.

The Market Suspension Pricing Schedule is published weekly by AEMO and contains prices 14 days ahead.

The market will continue to operate under the Market Suspension Pricing Schedule until the Market operator determines the market is able to return to normal conditions and the suspension is revoked.

Article by Alex Driscoll, Senior Manager – Markets, Trading, and Advisory

Drivers behind potential load shedding

In the energy market, probably not unlike most complex markets / industries, we never let the truth stand in the way of a good mainstream news story. So much so, at Edge we struggle to watch mainstream news!

Yesterday Edge highlighted that a tight supply balance was not the key driver for the unprecedented high prices occurring in the spot and contract markets.

As previously outlined, generators bidding behaviour is playing a pivotal role, lifting the average price in the spot market as their spot traders shift volume into higher price bands. This pushed spot prices so high that on Sunday the market reached the cumulative price threshold (CPT). This means that the sum of spot prices in a seven-day period hit a level which caused AEMO to intervene and cap prices until the market returns below this threshold.

As has been widely discussed on Sunday evening, AEMO stepped in and controlled the spot price once the sum of the previous 2,016 (7 days) trading intervals equalled the cumulative total of $1,359,000. The cumulative CPT is equivalent to an average price of $674.16/MWh for the seven-day period.

During market intervention, spot prices in the relevant region are capped at $300/MWh.  This commenced at 6.55pm on Sunday night in Queensland and will continue until the 7-day average drops below the CPT. Once this is achieved the CPT remains on foot until at least 04:00 the next trading day.

Since Queensland hit the cap on Sunday, we have now seen every mainland region in the National Electricity Market (NEM) also hit the CPT. As at publication, intervention pricing is currently enacted in all of these regions (QLD, NSW, VIC, and SA). Tasmania is currently under threat also.

During market intervention the maximum spot price can only reach $300/MWh (there is also a floor of -$300/MWh). $300/MWh is currently lower than the short run marginal cost (SRMC) of many gas generators when priced against the current gas price, which is also currently capped by AEMO (at $40/GJ).

A consequence of capping these markets is higher priced generation withdraws from the electricity market, as an example gas generator have a Short Run Marginal Cost (SRMC) of generation of roughly $400/MWh based on a fuel cost of $40/GJ, but with a cap of $300/MWh on the electricity generated it results in generators removing their availability from the market which in turn results in regional availability dropping. Hence subsequent threats of power outages and the potential requirement for load shedding.  It’s a case of the market being more under threat from commercial drivers than physical drivers.

The commercial dynamics of the current market create a perceived lack of availability in the market and leads to generators looking to other (non-capped) revenue streams for their generation stack. This is precisely what occurred over Monday with 607MW of availability being removed from QLD available generation, and 930MW removed from NSW. The drop in dispatchable generation resulted in AEMO publishing a Lack of Reserve (LOR) forecast and requests by AEMO for a market response. Rather than this call being answered, generators held firm and did not place generation back into the traditional bid stacks.  Across Monday the LOR dropped further as more generation disappeared into the ancillary market and as we approached the evening peak AEMO called an LOR3, which resulted in AEMO also calling on Reliability and Emergency Reserve Trader (RERT) providers to fill the availability gap.

Overnight AEMO’s action on calling RERT prevented load shedding, however this may not be the case in NSW tonight where 590MW of load is forecast to be interrupted at 19:00. If there is insufficient support under RERT to compensate for this supply shortage, we could see load shedding.

With all mainland NEM regions currently operating under the CPT we expect to see more market intervention, and those generators exposed to a capped gas price removing volume out of the market as electricity prices are capped at levels below their SRMC. This is likely to see AEMO needing to intervene in other regions, invoking RERT to source additional availability, or failing that load shedding.

Article by Alex Driscoll and Stacey Vacher.