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

High electricity prices – What’s really driving them?

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

In recent weeks we have seen a rapid increase in the cost of electricity both in Queensland (“QLD”) and New South Wales (“NSW”).

The chart shows how spot prices (light blue line) and forward prices in QLD have increased considerably since mid-2021. Most notably, we’ve seen frightening increases since mid May 2022.

The question is, what is really driving these unprecedented high prices?

Underlying fuel costs are playing their role, as we’ve seen significant increases in the cost of gas and coal resulting from the Ukraine crisis. Recent weather conditions on the east coast of Australia have also adversely impacted coal deliveries.

Analysis of the supply / demand balance and the bidding behaviour of participants is also in focus. Whilst underlying fuel prices have had a part to play, trading behaviour appears to be playing a leading role in the most recent electricity price increases. At a high level, the structure of the bid stack is a key driver to volatility occurring in QLD and NSW over the past few weeks.

Having analysed the market Edge2020 have found that small changes in the supply / demand balance coupled with strategic bidding behaviour has had a significant impact on spot prices.  Edge2020’s analysis shows that as solar generation diminishes the market power and influence on the spot price shifts from intermittent generation such as solar, to thermal generators such as gas-fired and coal fired generation.  With surplus availability of generation across the states, high demand or scarcity of supply are not the key drivers for the higher prices.

Both QLD and NSW bid stacks reflect the recent strategic bidding of generators in these regions. The bid stacks show how peaking plant are dispatching units at elevated prices, well above levels supported by inflated gas prices. Bid stacks also indicate that coal fired generation is not operating at full capacity. In the absence of news to the contrary, we can assume that output has been restricted for commercial reasons rather than technical limitations. Noting that no re-bids with technical limitations were published during the period analysed.

As spot market volatility has increased, as to have prices across the forward market, with uncertainty and risk having been priced in significantly. Views on future fundamentals remain broad, resulting in differing strategies between forward traders. Whilst spot traders successfully maintain unprecedented volatility in spot prices however, it’s difficult for forward traders to sell into this market. Once the opportunity presents to do so, we could see significant spreads and chunky declines in forward pricing.

 

 

Yesterday was a BIG day in the market

You may have heard it has been hot in Queensland over the last couple of days. Yesterday this all came to a head with the market showing some cracks.  

 At a high level, the spot price averaged $1,607/MWh for the day. Prices were less than $300/MW for most of the day when solar generation was high but as we moved to the evening the spot price spiked to between $10,000/MWh to $15,100/MWh for a few hours as coal, gas fired generation and pumped hydro set price.  

Yesterday and again today the market is under pressure on both the supply and demand sides. For the last couple of days, the hot weather has been influencing consumption. The second part of the equation is the supply side. At the start of yesterday Queensland’s largest generator, Kogan Creek was offline as well as Callide B2. All other “baseload” units were online.  

High temperatures and particularly high humidity impact the output from coal and gas fired generation. Coal units generally vacuum unload over the evening peak if they have not been proactively managed by the operators, which AEMO is fully aware of and is built into the contingency. Another issue with Kogan Creek being offline is that it reduces the flow across the QLD to NSW Interconnector (QNI), the result flows from NSW and is generally capped at ~600MW.  

The final issue is the bidding behaviour of participants. The previous days’ bid stack indicated prices would stay below $300/MWh during the daylight hours then jumped to $900/MWh where CleanCos cap price with its Wivenhoe Hydro generator, but once through that price band the spot price jumped to $10,000/MWh then again to $15,100/MWh.  

Adding to the already tight supply balance, the Tarong Power Station Unit 2 tripped at 15:15, returning to service at 18:50. Tarong 2 was ramping up at the time of the trip and from the trip profile, it does not look like a tube leak. From 18:50 the unit ramped up over the next couple of hours and is now running normally. Shell also had plant issues at the 78MW Condamine Power Station, taking the unit offline. Tarong, Millmerian, Stanwell and Gladstone Power Stations also had one or more issues over the evening peak.  

An Intervention Event was triggered as a result of Reliability and Emergency Reserve Trader (RERT) being implemented in Qld. This took effect from 17:00 01/02/22 until 21:30. Intervention pricing took effect from 17:00.  

A Lack of Reserve (LOR3) is still active for today as RERT has not been extended to manage today’s evening peak. If RERT is extended or reinstated today the LOR3 will be cancelled.  

As part of RERT, Powerlink was asking for industry to reduce consumption if safe. Large mines in Queensland have historic agreements with Ergon to reduce consumption and on this occasion, they reduced load as requested.  

In the build-up to the evening peak, the Minister for Energy, Renewables and Hydrogen and Minister for Public Works and Procurement, the Honourable Mick de Brenni made the statement “It is possible that Queensland’s previous record demand of 10,044MW will be exceeded on either today or tomorrow.”  

Queensland’s demand peaked at 16:40 as a result of the demand side management.  

At 21:30 AEMO published a market notice letting the market know that the intervention event had ended and as a result, RERT and Intervention pricing was not continuing.  

So what is ahead for us today?  

  • Demand forecast is looking to peak close to 10,000MW today, this is forecast to occur at 17:00.  
  • Pre dispatch spot pricing is again forecast to be at $15,100/MWh between 14:00 and 23:00.  
  • RERT may be needed again today and AEMO will currently be exploring their options. 

Written by Alex Driscoll Senior Manager Markets, Trading & Advisory

Federal Government King Review

Recently the Australian Government released findings of the King Review, accepting 21 of 26 recommendations to incentivise greenhouse gas (GHG) emissions abatement from industry.

The focus of the Expert Panel review was the development of rules to credit emissions reductions below Safeguard Mechanism baselines. Credits created under the proposed mechanism could be used to meet compliance obligations under the Safeguard Mechanism.

The panel recommended producing new credits generated under the scheme, known as Safeguard Mechanism Credits (SMCs). The SMCs would be different to the Australian Carbon Credit Unit (ACCU) offsets. SMCs would be for transformative abatement projects based on changes in emissions intensity rather than absolute emissions.

The proposed crediting mechanism would be similar to a baseline and credit framework scheme employed under current legislation however the baseline component of the framework does not account for absolute emission increases. The proposed mechanism will separate an emissions intensity crediting baseline that is focused on ‘transformative’ projects. The new credits will have lower environmental integrity due to the lower threshold for creation of credits for potential abatement projects. The creation of these credits will result in a two speed carbon price.

The Review observations that SMCs could be purchased at a price set by the market or at a fixed price. The price may also be linked to the existing ACCU price. As a result, lower quality SMCs would be expected to trade at a discount to ACCUs.

The Review saw the potential for LGCs to increasingly be considered for use in carbon markets due to their implicit carbon abatement value. It is not proposed to link LGCs in the new scheme.

Future of Contract Markets and the Baseload Swap

It is no surprise, when I say the National Electricity Market (NEM) is going through a vast transition and transformation, with an ever-increasing penetration of renewable generation, in the form of both utility scale renewable generation and household installations.

The world as we know is also battling the global pandemic that is Coronavirus. This has had a significant impact on people and their livelihoods and health.  along with a significant impact on energy markets around the globe. To top it all off, energy markets have had to endure a supply price war recently, between OPEC’s unelected leader, Saudi Arabia and non-OPEC oil producer, Russia.

With a rapidly evolving and ever-changing energy landscape, what should our contract markets look like? Are the current products fit for purpose or offer value in an energy landscape like the NEM? As a generator, the days of capturing value and running flat out all hours of the day, are indeed starting to dwindle, with quick, nimble, and easily dispatchable fast-start generation likely to excel in the near to longer-term landscape. Take South Australia (SA) as a good example, as to the success of fast-start plant. On the 04/04/2020 at 12:00pm, the 5 minute spot price was down at -$1,000/MWh, which is where it stayed the majority of the morning, due to low demand and strong generation, trying to send megawatts into Victoria (VIC), maxing out the interconnector. Shortly after that, at 12:20pm, prices spiked to above $300/MWh for the next 30 to 40 minutes or so, with fast-start gas generation swooping in and capturing this short-term high price period.

If this type of generation is the key to success in this new look NEM that we operate in, where fast-start, short burst generation is taking its place to complement the intermittent renewable generation in wind and solar, utility or household, that continues to penetrate the market, why are our contract markets continuing to predominantly offer baseload swaps?

A baseload swap is a contract for energy, say 5 MW for $70/MWh, for a defined period, for a month, a quarter, a calendar, or financial year. The way a swap works is the $60/MWh becomes the strike price in which the seller of the swap pays the floating price (the price of the underlying wholesale product which is electricity in this instance) and the buyer pays the fixed $70/MWh.

Say you have contracted a baseload swap for 5 MW for the entire calendar year of 2020, this would mean that for every half hour (with electricity settling every half hour as per the underlying wholesale market settlement regime in the NEM), of the entire 2020 calendar year, the buyer will pay the seller $70/MWh, and the seller will pay the buyer the underlying wholesale or spot price. For example, say this morning the wholesale or spot price for electricity for the half hour ending period of 9:30am was $40/MWh; this would result in the buyer paying the seller $70/MWh for 5 MW, whilst the seller would pay the buyer $40/MWh for 5 MW, resulting in a $30/MWh contract for difference (CFD) payment going from the buyer to the seller.

However, think about this, the baseload swap is exactly that, baseload. So, a contract for calendar year 2020 means you are locked into that same position (unless you sell out of the position) 24 hrs, 365 days.

So, do baseload contracts offer appropriate value anymore, in a market which are short-lived upward volatility and recently longer periods of downward volatility?

Mid last month, Snowy Hydro struck a contract defined as a ‘super-peak’ swap, which will cover what has been defined as the “super peak” periods of the day, generally morning and evening peak usage when solar is ramping up or down. The trade was brokered through an over-the-counter (OTC) trading hub operated by Renewable Energy Hub, and it is believed, similar deals will be a gateway to funding and bringing into the market technology such as batteries and demand-response into the energy markets.

Snowy Hydro has been procuring renewable PPA’s for a while, through wind and solar generation, including the 90 MW it procured from the Sebastopol Solar Farm in NSW. They are looking to use the renewable generation and back it with their significant hydro fleet, to sell a new range of products to its customers.

With wholesale energy prices reducing significantly since September 2019, and the overabundance of generation in states such as QLD and SA, and with the rapid introduction of new technology, it is likely a significant number of customers will choose to take more wholesale/spot price exposure, rather than contracting ahead of time.,

This fuels the argument for the need to have more flexible and robust products, ones that are for particular trading intervals, perhaps in the day, day-ahead products, week-ahead products, or perhaps more products like Snowy’s ‘super peak’ product?

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.

What’s Oil got to do with it?

There is no doubt that energy markets and the energy industry itself are rapidly evolving and moving away from fossil fuels. The evolution of energy seems to be coming, and only coming faster given this tumultuous time the people and countries across the world have endured. Lets start with oil; Australian’s across the nation are very aware of the recent global oil price crash to new historic levels, particularly when it is reported in the news headlines that Australian’s are seeing almost 15-year lows at the petrol bowser. The impact of the recent oil price crash however does not stop at the bowser, it has and will continue to have significant impacts on energy markets across the globe including in Australia.

Oil prices have been hit recently due to two major events; one being the global epidemic of COVID-19, resulting in a significant reduction in demand for oil across the globe. The International Energy Agency’s (IEA) April 2020 reports an expected drop in demand of global oil of 9.3 million barrels(mb)/day year on year for 2020, with April 2020 demand estimated to be lower than 2019’s demand by 29 mb/day. The second impact to oil markets has been the oil price and supply war between OPEC’s pseudo leader Saudia Arabia and non-OPEC nation, Russia, two of the largest global oil exporters. Saudi Arabia and Russia could not agree levels of supply, leading to Saudia Arabia flooding the market with oil and prices, both spot and futures, reaching new lows. The quarrel between the two global oil market power-houses and the impacts of the COVID-19 on demand for oil has led to the historical event where the West Texas Intermediate (WTI) oil price index fell into negative price territory, with May 2020 future prices settling at -USD$37.63/barrel on the 20/04/2020, after reaching a low of -USD$40.32/barrel earlier that day.

The major oil index, WTI, saw futures prices for June 2020 contracts settling at around USD$17/barrel on the 29/04/2020, whilst Brent Crude, another major oil index also felt the pain of slowing demand, with prices dropping below USD$20/barrel on the 27/04/2020. But the impact of tumbling oil prices reaches far and wide, particularly here in Australia. Australia has a booming natural gas industry and was the largest exporter of liquified natural gas (LNG) as of January 2020. A significant number of gas sales agreements are linked to the crude oil indices, with Australian gas companies feeling the hurt given the tumble in oil prices. Brent Crude oil futures for June 2020 contracts settled at around USD$24/barrel on the 29/04/2020. At these prices, the likes of Santos and Oil Search will be hurting given both flagged a cashflow breakeven oil price of ~USD$25-29/barrel, and USD$32-33/barrel, respectively. Demand for natural gas in international markets has also tumbled, and due to the linkage between oil prices and gas contracts, spot contract prices have shifted down, with June 2020 contracts settling at AUD$2.87/GJ (~USD$1.88/GJ) as of the 30/04/2020, again a far reach from prices seen in November 2019 of ~AUD$7.30/GJ (~USD$5/GJ).

Further impacts of the oil market crash on gas markets has been cheaper domestic gas prices for consumers. Queensland, the largest gas extractor and exporter on the east coast has seen prices in its short-term trading market (STTM) in Brisbane reach as low as AUD$2.31/GJ in March 2020, a significant drop from AUD$9-11/GJ we witnessed the same in 2019. Other energy commodities have also seen a decline off the back of the oil price tumble, including thermal coal. As stated above, with gas prices domestically and internationally falling away, thermal coal prices have come off due to energy users opting for cheaper fuel sources such as oil and gas. Spot thermal coal contracts for the May 2020 settled at USD$52.35/metric ton(mt) on 30/04/2020, far softer than spot prices a year ago at ~USD$90/mt.

This brings us to the all-important energy market and commodity, electricity, which with all the above combined has seen electricity prices fall off a cliff. The National Electricity Market (NEM) in the last few years has been on a renewable power growth spurt. Queensland for instance has the highest penetration of large scale solar generation of approximately ~2,400 MW and a significant penetration of rooftop solar reaching ~2,100 MW, combine them together and on a mild April day in 2020, you have almost 2 thirds of maximum demand. With renewable energy displacing thermal/fossil fuels, off the back of reducing pricing for the technology and subsidies in the form of renewable energy certificates (RECs), combined with both far cheaper gas prices allowing gas plant to bid in and capture price spikes due to their fast-start and intermittent operating capabilities, and reduced demand for electricity due to the impact of COVID-19 with business and industry operating skeletally, electricity prices continue to sit at prices not witnessed since 2016.

All the above has been caused by two events, both significant to the global economy, and the energy industry in their own rights. One thing is for sure, the events have helped push the electricity market on the East Coast of Australia into a new direction far quicker than it may have if the two COVID-19 and the oil price crash did not occur. We are seeing new market design concepts (ie. capacity markets, two-sided markets) and new contract market products (ie. super-peak swap) coming to light, that give way to new technologies and greater competition. The abundance of natural gas in Australia is affordable for households for heating and is finally being utilised as the ‘transition’ or bridging fuel it was always pegged as, to renewable energy in the wholesale market. One thing is for certain, change is afoot, and it definitely has me excited.

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.

History making Oil price – what it means for Energy in Australia

Overnight the major oil price index, the West Texas Intermediate (WTI) Crude Oil Index fell from trading at USD$20.97/barrel to enter negative price territory for the first time in history, with May 2020 future prices settling at -USD$37.63/barrel on the 20/04/2020, after reaching a low of -USD$40.32/barrel. The event was sparked off the back of increasing storage concerns given excess supply build-up brought on by suppressed demand as a result of COVID-19. The recent announcement by OPEC + to cut demand by 9.7 million barrels a day in May and June months, and the additional 5 million barrels per day to be cut by other nations outside of OPEC and Russia, including the US, Canada and Brazil has done little to quash concerns of an oil supply glut with consultancy firm Rystad Energy estimating demand will be cut by 27 million barrels a day in April and 20 million into May as a result of COVID-19’s impact on global usage.

The market for WTI Crude Oil entered con-tango yesterday (20/04) with spot prices significantly lower than future prices for the commodity, however today (21/04) it has bounced back breaching positive price territory sitting above USD$1.00/barrel at 3:30pm (EST). Brent Crude Oil prices however remained relatively static on the 20/04, ending the day in the mid $USD20/barrel range at USD$26.04/barrel, despite the traditional correlation of trading between WTI and Brent Crude oil prices. So why is the oil price so important to Australia, well as Edge has previously pointed out in the past, a significant number of long-term gas deals are linked to an oil price index, likely Brent but also WTI. This has huge ramifications for Australia who became the largest exporter of liquefied natural gas (LNG) as of January 2020 this year, a commodity and industry which also contributes massively to the Australian economy.

With LNG sales effectively hitched to oil prices, I can only imagine what the contract price for some of the underpinning investment and long-term contracts of domestic and international gas looks like! We have witnessed that domestic gas prices across the NEM and international LNG Spot market prices have both taken a dive off the back of the recent oil price and supply war and the impacts to demand from COVID-19. Currently the ACCC has calculated LNG netback contract prices of gas to the Wallumbilla Hub (domestic gas hub connecting gas from QLD to southern states) at prices of AUD$3.73/GJ and AUD$3.60/GJ for April and May 2020, the cheapest price the commodity has been in the last 4 years, with future prices looking likely to hit $3/GJ. Currently the JKM (Japan Korea Marker) spot LNG market index for Asia – which is a significant demand hub for Australian spot LNG cargoes – is depicting prices of AUD$3.39/GJ for future contracts for June 2020 as of 20/04/202, however given the recent negative price event in international oil prices it is likely these future contract prices could fall further.

With LNG markers like the JKM heavily correlated to movement of oil prices it is likely we will not see a return to the AUD $8/GJ JKM Swap price for some time. The oil price slump is also expected to impact investment decisions, as once again the gas industry and heavily correlated to global oil prices. Majority of the domestic gas players including Oil Search and Senex Energy are gearing up for extended periods of reduced returns and cheaper gas prices due to a significant number of gas sales contracts linked to the Brent Crude oil index. Oil Search indicated to the market its break-even oil price range of USD$32-33/barrel, without funding growth projects, well above the current future oil contract prices; whist Senex Energy’s Chief, Ian Davies stated that “Demand has fallen off a cliff,” and that they were “planning for fairly soft prices for a while.” Even the likes of Santos flagged they are aiming for a free-cash flow break-even oil price of USD$25/barrel in 2020, however needs a price of USD$60/barrel to fund new growth projects, which could see the Narrabri project in jeopardy.

What is incredible to see is investment decisions like Arrow Energy’s Surat Gas Project still going ahead even when energy markets are entering unchartered territory. Arrow Energy’s joint owners, Shell and PetroChina have finally given the go ahead to the $10 billion development of Arrow’s vast gas resources located southern Queensland’s Surat basin, sanctioning the commencement of phase 1 of the Surat Gas Project on 17 April 2020. Arrow’s joint owners have decided to push forward with the expansion despite the recent downturn in oil and gas prices felt across the globe due in part to the COVID-19 outbreak and the recent oil price war. The Surat Gas Project is expected to bring on 90 billion cubic feet (~95 PJ) of gas a year, with 600 phase one wells set for construction this year with first gas expected in 2021, according to Arrow’s announcement.

The Surat Gas Project also comprises some big steps for the industry, with the deal underpinned by significant infrastructure collaborations and gas sales agreements which will see Arrow gas compressed and sent to market via Shell’s existing QGC infrastructure (including existing gas and water processing, treatment and transportation infrastructure). Good news for these gas volumes is that part will be allocated for sale into the domestic wholesale gas markets on Australia’s east coast, and part will be allocated to be converted to LNG via QCLNG’s liquified natural gas infrastructure located on Curtis Island, near Gladstone port. This is welcomed news with manufacturing firms across the east coast screaming for further domestic gas reserves to be developed in order to keep domestic gas prices at reasonable levels and increasingly de-linked from international LNG prices and indexes, such as the Japan Korea Marker (JKM).

In addition, it was also announced the Andrew “Twiggy” Forrest-backed LNG import terminal located at Port Kembla in NSW has been given the tick of approval by the NSW State Government. The Australian Industrial Energy venture which is co-backed by the Japanese firm Marubeni and global trading shop JERA in continuing forward with plans to build and operate the Port Kembla import terminal with a likely final investment decision expected later this year and first gas imports in 2022, with customers and the Australian Energy Market Operator (AEMO) reporting expected shortfalls of the commodity in regions such as Victoria and New South Wales could come as early as 2023, with shortfalls especially apparent into and beyond 2024.  

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.

Infigen want an Operating Reserve Market

Infigen have submitted a letter to the Australian Energy Market Commission’s Chairman requesting the introduction of an Operating Reserves and Fast Frequency Response rule change. Infigen state in their letter that this market proposal they have put forward would “relatively simple to implement and would provide added confidence that sufficient resources to respond to unexpected changes in supply or demand would be available”, as stated in their letter.

Most importantly, Infigen have stated a rule change such as this would remove the reliance on and provide an alternative to the RERT (Reliability and Emergency Response Trader) procurement and contracts of which cost consumers $34.5 million, and avoid further intervention in the market by the market operator. Infigen believe that a “free-rider” problem may occur under tight capacity scenarios in the market increased risks of random government interventions to avoid adverse market and operational outcomes.

As such, they believe “marginal value of incremental capacity is by definition very high and delivers considerable benefits to the entire market’” calling out that raising the market price cap does not solve the issue with systemic risk to portfolios/participants caught short due to plant outages or network failures. Instead, Infigen have called for the introduction of a Operating Reserves market for near term to avoid increasing the market price cap and increase the reliability and security of supply to consumers.

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.

5 Minute Settlement could slide 12 Months

On the 26 March 2020, the energy market bodies including the Australian Energy Market Commission (AEMC), Australian Energy Market Operator (AEMO) and the Australian Energy Regulator (AER) wrote a letter to the Australian Federal Government’s Energy Minister, Angus Taylor which advised and sought  for the consideration to consider a longer implementation time-frame for the market’s transition to the 5 minute settlement regime which was pegged to begin on 1 July 2021.

The Market bodies have stipulated the reasoning for this is due to the vast impacts to industry and the workforce that have occurred due to the COVID-19 outbreak. The letter to Mr Taylor proposes delaying the start date of 5 minute settlement by 12 months so industry can defer further/remaining expenses associated with preparing for 5 minute settlement.

It also states that AEMO will still work to the same deadline, albeit 12 months would provide AEMO with extra time to ensure 5 minute scheduling and dispatching engines are sound at least in a development environment. As yet we do not know if the 5 minute settlement will get the go ahead to be delayed, with market bodies still reaching out to market participants to advise as to whether this will be advantageous or not.

The impact of a 5 minute settlement delay to the market will be impact all participants and investment decisions, there are some calling out this only extends coal-fired generation’s life-span, but if you have been watching the futures prices and spot prices of late, coal-fired generation is already in a world of hurt with no doubt a lot of questions being raised about the remaining lifespan of some coal plant in both QLD and NSW. Should 5 minute settlement be delayed by 12 months, there is the likelihood we see the slide of investment in some fast start plant, such as new batteries and hydro.

Gas-fired generators who have not re-tuned/upgraded their synchronising and start time to less than 5 minutes will still have the 30 minute settlement price to fall back on at least for another 12 months and be able to capture any value the 30 minute average settlement price may represent. The flip side of 5 minute settlement is that it would be very good for renewable generation as it would make the thermal plat operators reassess their operating philosophies with gas likely more removed from the market, and propping up the price.

The 2021/2022 financial year was likely to be a more costly financial year given the introduction of 5 minute settlement, which would effectively mean a vast majority of gas plant would not be able to curb price spikes as effectively under the new settlement regime, resulting in a change to their operating philosophy, however both the impacts of COVID-19 an the recent oil price collapse has significantly changed this stance.

Unfortunately, there is no real way to know how much of an impact globally it will have, and how long the impacts of COVID-19 will last. Similarly, with Saudi-Arabia and Russia both engaged in a price/supply war over Oil (two of the largest producers of oil) it is all hard to depict how long the extremely cheap domestic gas prices will last, particularly with investment decisions in new domestic gas likely put on hold.

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.

COVID-19 / NEM Impact Statement

COVID-19 has impacted us all in recent weeks. At Edge we have put plans in place that have allowed us to provide all services our clients require without disruption.

We are working diligently to understand the impacts COVID-19 could have on the energy markets in the short and longer term. As more information comes to light, we will provide further updates on the impacts to the market and our clients.

As we are only a few weeks into this pandemic we will try and provide an understanding of the impact COVID-19 could have on the market.

Oxford economics, a team of 250 economists, has recently published a paper providing a high-level update on the impact of the pandemic on the world economy. Their initial work predicts a short, sharp recession to the global economy with major national economies going into deep recession during the first half of 2020. It is modelled that over the full year global growth will drop to zero.

Oxford economics are predicting, based on historic experience, a strong bounce back in activity once social distancing measures are relaxed. It is forecast that businesses that can get through the first half of 2020 should be prepared for a strong second half of 2020, with global growth forecast above 4%.

Overseas experience

As China was the first country to close-down as a result of COVID-19 we can learn from their recent energy experience and translate it into the Australian market.

In January and February energy production dropped significantly with thermal power dropping 8.9%, hydro dropping 11.9% and nuclear and wind dropping to a lesser extent at 2.2% and 0.2% respectively. On the flip side Solar generation increase by 12%.

Early indications are that thermal and hydro station dropped production the most due to reduced staffing level causing lower operational hours. Renewables were impacted the least due to their non-dispatchability.

It is estimated that during the height of the Chinese lockdown period over the 27 days, demand decreased by 16%.

At Home in Australia

Generation

Large generation portfolio’s including the likes of Stanwell and AGL have publicly acknowledged they have put plans in place to ensure generation meets demand, this includes stockpiling coal to ensure security of fuel supply. Smaller generators on the other hand may not have the staff to guarantee operation of their units over the long term due to illness.

Energy Price Impacts

With the additional impact of lower energy demand in Asian countries such as China, Australia’s liquefied natural gas demand significantly reduced, resulting in excess domestic gas supply particularly on the east coast of Australia. Although majority of the LNG facilities on the east coast reside in QLD, we have seen an increase in gas generation and a decrease in bid prices in regions more dependent on and abundant with gas-fired generation, such as South Australia. We are seeing approximately 600 MW more of gas-fired generation in March 2020, compared to March 2019, bid in at prices below $50/MWh. Assisting this is the collapse in natural gas prices in the Adelaide Short-term Trading Market, which has traded at the mid to high $5/GJ range for March 2020, compared to the significantly higher price range of $10 – $11/GJ we witnessed back in March 2019. Both of these variables are introducing cheaper supply in the energy markets both for heating (in homes) and electricity generation. With interconnection remaining relatively unconstrained this is resulting in lower prices across all NEM regions.

AEMO

AEMO has put in place its pandemic response plan so the market operator can continue to operate the NEM and WEM efficiently and safely. Key actions in the pandemic plan include limiting contact with key staff such as control room and other business critical staff.

Demand

Following the initial breakout of COVID-19 in Australia and the early shutdown of some businesses, demand fell by about 600MW in NSW or about 8% of average demand. This was reflective of all states. Over the recent week the steep reductions in demand experienced at the start of COVID-19 have flattened out as a result of two possible reasons. In some regions such as Victoria, demand has increased. The first reason for this change in demand is consumption has moved from businesses to individual homes. Across Australia average demand is currently only 7% below last month’s average. The demand change is also attributed to seasonal change which has resulted in a reduction in load associated with cooling.

Change in demand – daily profile

The chart below illustrates the change in demand across the day and compares a summer profile and a transition to an autumn profile. The top line is early February with the bottom-line showing demand from Monday the 23rd March.

Source: AEMO 2020

The chart shows morning peak has reduced slightly however the demand over the evening peak has dropped significantly.

Impact of large users

It is expected that large users would be impacted significantly by the virus however this does not appear to be the case. With parts of the world such as South Africa shutting down mines and industry following government direction the supply / demand balance is falling in the favour of Australia. Add to this the favourable exchange rates, the export potential of commodities from Australia remains strong. The Australian mining industry is also designated as an ‘Essential Service’ so at this stage they are sheltered from future lock downs. This positive news for the mining sector which will benefit mining rich states with demand expected to reduce to a lesser extent than other states.

Renewables

If the trends overseas are reflected in Australia the current installed capacity of renewable generation will continue to operate at strong levels providing staffing is available to operate and control the assets.

There will be a likely slowdown in the development of renewable projects as a result of the restrictions on travel, meetings and specialist staff available for construction, connection, commissioning and final approvals.

This slowdown will impact the future mix of generation assets across Australia, the current trend in carbon emission reductions and the supply and price of environmental products.

LGCs

Edge has modelled the impact of a 10% reduction in demand with a business as usual generation profile for large scale renewable generators to understand the impact this downturn may have on LGC supply and price.

The 10% reduction in demand could reduce the RPP percentage by 0.32%. The likely effect of a reduced percentage and business as usual renewable production will be surplus LGCs in the short term and reduced prices for LGCs.

STCs

With the downturn of the economy it is expected that less roof top solar will be installed resulting in a reduction in the current surplus of certificates carried forward since 2017. The reduction is expected to reduce the STP below 20%.

If you have any questions regarding this article or the electricity market in general, call Edge on 07 3905 9220 or 1800 334 336.