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

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


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 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.


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.


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.


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.


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.

South Australia separated from the NEM!

The South Australian (SA) region has been separated from the remainder of the NEM regions due to the destruction of the main alternating-current (AC) interconnector between SA and Victoria (VIC).

What occurred:

  • On the 31st of January 2020 during wild storms that lashed eastern SA, western VIC, the 500kV main (AC) interconnection cable running through southwestern VIC was disconnected due to transmissions towers east of Heywood (Victoria) and west of Geelong (Victoria) collapsing in damaging storms and extremely strong winds.
  • When this occurred,
    • Interconnection flows quickly swung from exporting MW’s into VIC, to importing MW’s into SA.
    • Alcoa’s Portland aluminium smelter tripped which only exacerbated the problem,
    • A handful of wind farms were cut off from the market including McCarthur Wind Farm (420 MW) in Victoria, and the three Lake Bonney Projects in South Australian (~278.5 MW)

What does this mean:

  • Basically SA has been left to fend for itself, cut-off from the rest of the NEM
  • All MW’s (majority of all, with the small Murraylink direct-current interconnector still available) and frequency control services must be sourced from SA, locally.
  • Currently all SA generators are running hard and optimising portfolio’s for frequency control services (FCAS) prices rather than regional reference prices (spot price)
  • Additionally, a vast majority of gas-fired generation units including, Osbourne GT, Pelican Point, Torrens Island A and B units have and continue to receive market intervention notices from AEMO requiring them to be online
    • This is adding to the oversupply in the region with wind generation quite strong for this time of the year,
    • Not to mention, the wind generation, being a variable generation type, is not helping from a forecast perspective for AEMO, adding to the FCAS costs and requirements in the SA region.


  • AEMO have indicatively provided a two week return time off the back of AusNet’s (interconnector owner) initial assessment and action plan to fix the interconnector.
  • AusNet’s solution is to construct temporary interconnection with power poles and lines to have arrived on site yesterday (03/02/2020).

Current weather forecast and impact on spot price:

  • Currently temperatures are set to be relatively mild for an SA summer at this stage.
  • However, temperatures are expected to reach the late 20’s and early 30’s towards the end of the week, historically, temperatures at these levels have encouraged higher demand and the need for imports from VIC, which will not be possible with the largest interconnector between the two regions out of action.
  • Although we are seeing some extreme lows in spot price, there is the possibility we could see some extreme highs. It is dependent on:
    • AEMO’s intervention in the market with AEMO issuing FCAS targets to participants in the realm of $300/MWh for raise and lower services (due to the inability to source FCAS from outside of SA), and
    • Generators potentially looking to spike spot prices or increase the spot price with no doubt, gas generator running costs no doubt increasing every MWh the interconnector is out of action.

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

Water – a top priority for Tarong Power Station

Current weather conditions are placing an increased reliance on the diminishing water catchments across Australia. These water catchments store water for use by various parts of the local community including drinking water for residents, irrigation and Electricity generation.

Stanwell recently announced water sustainability is a top priority for its Tarong Power stations located within the South Burnett region.

Water is an essential necessity for thermal power stations to make electricity. The water is used for steam production and cooling.

Tarong power station consisting of 4 X 350MW thermal units and a 443MW supercritical unit. These units obtain their water from two sources, the primary source is Lake Boondooma and secondary from a pipeline using water from Lake Wivenhoe or recycled water produced under the Western Corridor Recycled Water Scheme.

Stanwell corporation is focusing on mitigating the impact on the South Burnett community by reducing the usage of water from Lake Boondooma to ensure the South Burnett community have access to drinking water. Initial initiatives used at the power station to reduce the reliance on Lake Boondooma water include the use of recycled water from the ash dam and stormwater.

Tarong Power Station have access to water from Lake Wivenhoe if Lake Boondooma drops below 34%, currently the Lake Boondooma’s level is 22.95% as of the (Source: SEQWater 2020). Lake Wivenhoe water also comes at an added cost. Water is currently the highest operating cost for Tarong Power Station.

An alternative to using Lake Wivenhoe water is the use of purified recycled water from the Western Corridor Recycled Water Scheme. The scheme is not currently in operation, however when operating and supplying water to Tarong Power Station it will add significantly to the costs of generation.

Tarong Power Station first used purified recycled water from the Western Corridor Recycled Water Scheme in June 2008 following a similar water supply limitation brought on by the 2008 drought.

As a result, the increasing marginal cost to generation caused by the higher water cost, Tarong Power Station may change its operation and reduce generation or dispatch its units at higher prices. Under either scenario this may increase the cost of wholesale energy in Queensland.

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

Retailer Reliability Obligation triggered in South Australia

The SA Government (South Australian Minister for Energy and Mining) has the power (under South Australian Legislation) to trigger a Retailer Reliability Obligation (RRO) upon informant from AEMO of a one-in-two year peak demand forecast shortfall event as published in the South Australian Gazette 17 December 2019, with the AER confirming and publishing the notice 9 January 2020. For the avoidance of doubt this means that unlike all other regions which require the Electricity Statement of Opportunity (ESOO) to predict an unserved energy event, SA can act independently without approval as such from the AER.

The RRO was trigged for South Australia on the 9 January 2020 for the following periods:

  • First Quarter (Q1) for Calendar Year 2022
  • First Quarter (Q1) for Calendar Year 2023.

The periods of concern according to AEMO’s forecasting includes:

  • each weekday from 10 January 2022 – 18 March 2022 for the trading periods between 3pm and 9pm EST;
    • **(Peak demand expected to be 3,030 MW)
  • each weekday from 9 January 2023 – 17 March 2023 for the trading periods between 3pm and 9pm EST
    • **(Peak demand expected to be 3,046 MW)

A T-3 Instrument has been created and the Market Liquidity Obligation (MLO) of the SA region’s largest generation businesses, Origin, AGL and Engie have been called upon and are to begin trading exchange-listed (ASX approved products) for Q12022 and Q12023 from 7 February 2020.

With the triggering of the RRO, the South Australian Minister has made a T-3 instrument (under NEL Part 7A 19B (1)):

  • Q1 2022: This T-3 Reliability Instrument applies to the South Australian region of the National Electricity Market for the trading intervals between 3pm and 9pm Eastern Standard Time each weekday during the period 10 January 2022 to 18 March 2022 inclusive. The Australian Energy Market Operator’s one-in-two year peak demand forecast for this period is 3,030 Megawatts.
  • Q1 2023: This T-3 Reliability Instrument applies to the South Australian region of the National Electricity Market for the trading intervals between 3pm and 9pm Eastern Standard Time each weekday during the period 9 January 2023 to 17 March 2023 inclusive. The Australian Energy Market Operator’s one-in-two year peak demand forecast for this period is 3,046 Megawatts.

With the T-3 instrument created by the SA Energy Minister, this has triggered the MLO, effectively a market making obligation on the parties identified above to reasonably offer liquid exchange-listed products for the identified shortfall periods.

Obligated MLO participants such as Origin, AGL and Engie will from 7 February 2020 begin offering exchanged-listed products for both Q12022 and Q12023.

The triggering of the RRO means retailers and large load consumers can start procuring volume for their forecast demand for Q12022 from as early as 7 February 2020, and no later than 31 December 2020, the T-1 instrument implementation date (13 months prior to the shortfall period identified). 

If you would like to know more, please contact Edge on 07 3905 9220.