Retailers, Retailers Everywhere, and not a Lesson Learned

In August, AEMO received five registrations for new customer status customers to come into the market as a Market Customer, the latest and most publicised of these being Tesla Energy Ventures Australia Pty Ltd. Now, this wouldn’t be their first foray into the energy markets, they already have their energy arm out of the US and are expanding rapidly within the Australian space.

But Tesla is not alone; the AER has seen 22 new electricity retail licence applications since 2020, including the newly formed Ampol Energy, Smartest, and Telstra.

Now whilst competition is great for any market, I am absolutely not a monopolist, I do view this market penetration with slight concern.

With the UK seeing over 27 Energy Suppliers going under since January 2021, unregulated and “low cost”, usually spot exposed participants, with little to no risk profiling, can cause burden and costs to our market, never mind eroding the confidence of consumers. The UK offers a valuable lesson in this space and is one I fear has not been headed by our regulators.

With the cost of Retailer of Last Resort passed through to consumers who have had no dealings with those companies, but the market operator forced to share the burden, where does the responsibility for the failure sit? I would note the AEMC have released improvements papers to try and address some of these questions, but with the increasing number of these retailers entering the energy markets is it going to be too little too late.

With this summer promising some significant volatility, between RRO in SA, the ESOO stating the risk of shortages in both Victoria and South Australia now exceeds the strictest benchmark this coming summer, an all but certain El Niño bringing heat and reduced wind generation, and AEMO searching for Reserve Energy Markets across the NEM, including TAS for the first time, the volatility could expose some of these participants to more credit calls than their cash flow can handle.

Only time will tell, and luckily most of these retailers do not have a significant market share at this time, but this summer could be the spotlight the regulators need to tighten the requirements for new retailers. Or maybe not.

Electricity Grid Faces Challenges Amid El Niño’s Return, Warns AEMO

Australia’s electricity grid is bracing for potential disruptions this summer, particularly in Victoria and South Australia. The Australian Energy Market Operator (AEMO) has expressed concerns about the imminent El Niño, which is anticipated to bring about a season of extreme heat and wind-less days.

This latest warning from AEMO (2023 ESOO) presents a very concerning picture. The slow pace of transitioning from old coal plants to cleaner energy sources, coupled with potential coal and gas shortages, has heightened the risk of blackouts. AEMO’s annual 10-year outlook emphasizes the urgency of investments. With nearly two-thirds of Australia’s coal power fleet expected to shut down by 2033, the need for swift action to ensure uninterrupted power supply is paramount.

The challenges of transitioning to a greener economy are becoming more evident. The scenario in NSW, following the proposed 2025 closure of the massive Eraring coal generator, is particularly urgent. AEMO strongly recommends postponing such retirements to avoid blackouts. Contrasting their optimistic report from February, the upcoming summer may see Victoria and South Australia facing with power shortages. These shortages can be attributed to a mix of factors, including periods of low wind, recurring generator breakdowns, and the gas plant shutdown.

The latest AEMO report indicates that roughly 3.4GW of new generation and storage capacity is projected by this summer. Furthermore, initiatives like Snowy 2.0 in NSW and the Borumba pumped hydro project in Queensland are aimed to bolster capacity by 2032-33. However, there are concerns as projects like Snowy 2.0 confront delays and rising costs.

With the re-emergence of the El Niño pattern, the electricity grid is anticipated to be under significant stress, especially following three comparatively milder summers due to La Niña. The growing popularity of electric vehicles and electric heating, notably in states like Victoria, will add to the strain on the grid.

Sarah McNamara, the CEO of the Australian Energy Council, perceives this both as a challenge and an opportunity. She is optimistic that the market can overcome these obstacles with the appropriate price signals to stimulate investment.

In conclusion, while the journey to a low-emission economy might be lined with challenges, with the right strategies and investment, Australia can ensure a reliable and sustainable power supply for its citizens.

And the Best Horror Story of 2023 Goes to…

No need for Stephen King, the ESOO (Electricity Statement of Opportunities) is this year’s horror bestseller, and it comes out this week.

In WA this week we have seen the power of the AEMO reports. With the WA WEM ESOO showing the government’s ambition to phase out coal by 2030 would result in shortfalls. This week the WA government scrambled to cover the shortfall and quickly announced the Muja 6 plant was given an extension until at least April 2025 under ‘reserve outage mode’ conditions. With WA planning to remove 1,366MW from the system by 2030, the transition was showing shortfalls of just below 1GW by FY26 and a terrifying 4GW by FY33. The noises coming from the state are therefore all about how to “manage the transition” and no longer how to meet the targets.

Over in the NEM (National Electricity Market), even before the release of the ESOO this week, this was the week in which we saw announcements in Victoria and an expected announcement from NSW looming. The question is no longer will Australia meet its Net-Zero target, but by how far we will miss it and what impact will closures have before renewable uptake comes onto the grid?

The Victoria government has pre-empted its requirements and moved forward to strike the “structural transition deal” with AGL to continue the operations at Loy Yang until 2035. Despite the pressure from certain board members, even they have to concede that the uptake in renewables is not at pace to orderly transition the market away from coal.

Energy Australia followed this announcement with the news that through its “Climate Transition Action Plan” the Yallourn power station will close in 2028, with the Point Piper remaining available until 2040.

This has been flanked by the NSW government strategically leaking, no doubt to soften the announcement, that the Eraring plant will remain online. The question now is in what form and at what cost.

With Australian renewable uptake at one of its lowest levels in years, hindered by the huge subsidies in the US and massive European demand. Increasingly vocal opposition to transmission upgrades, especially from rural communities, and no certainty on policy post the RET expiry in 2030, there is no doubt this week’s ESOO will make scary reading.

With the COP28 looming at the end of November, I think the hot potato in Canberra is going to be who goes, as there is no doubt when the ESOO is published we will be back in the naughty chair.

The question, therefore, is not will we miss our energy transition and therefore climate targets, but rather by how much?”

Australian Manufacturing: Is it time to bring it home?

Australian Manufacturing - Wind Turbine

The English love their football (soccer) and no more so than Baddiel and Skinner who sang “It’s coming home” for the 1996 Euro’s. But with another wind project either being delayed or scrapped is it really time to consider if the Chief Operating Officer of AGL, Markus Brokhof is right “The manufacturing industry has to come back to Australia.”

The latest announcement from CleanCo last week which stated the company is pulling the pin in their investment in the Karara Wind Farm in the Southern Downs in Queensland, citing delays, not in connections or transmission but in turbine parts and rising costs, only acts to further strengthen Brokhof’s argument. This investment was part of the wider MacIntyre precinct and would or may still be, the largest wind precinct in Australia. However, this could be a blow to Queensland’s target of owning 50% of new renewable generation within the state.

This is just the latest in a string of windfarms to hit delays, the Clarke Creek wind farm has been hit with numerous delays between change in ownership from Goldwind to Andrew Forest’s Squadron energy, through to shutdowns for worker safety as well as project management changes causing equipment to be removed from site. With the offtake from the first stage of the project mostly going to another Government Owned Corporation, Stanwell could this be a further blow to the state’s advanced renewable targets, 80 per cent by 2035, and the existing 50% by 2030.

Another one of Andrew Forests wide array of companies is Windlab, whose own windfarm the Upper Burdekin project has not only lost its inaugural customer Apple, but has had to significantly downsize the output of the site from the proposed 193 Wind turbines to a reduced 136 and is now likely to only have 80 following significant opposition from wildlife conservationists who stated that the project was threatening already endangered species.

To further stoke the flames, AEMO has now come into the forefront of media, stating that not only do we not have enough investment in renewable electricity to compensate for the expected closure dates of coal generation, but the firming technology to support this renewable grid has not been fully funded or addressed, this year’s ESOO will certainly paint a bleak picture for the medium term in Australia. This sentiment is only exacerbated by the Australian former chief scientist and first Victoria State Electricity Commission CEO, Andrew Finkel, who last week quit his role at the SEC stating; not only was the capital investment not in place but investment has dried up and the “country is unlikely to reach its emission reduction targets.” I’m sure not a sentiment which was welcome news for the Andrew’s government whose election campaign was built on the premise the SEC would be both decarbonising the Victorian grid whilst reducing the cost for Victorians.

With the COP 28 due in November and Australia looking like it will miss it’s, late to the party but thanks for coming, 2030 targets, increasing international pressure will be placed upon Australia to ask how we will try and achieve some meaningful reductions? Rik De Buyserie, Engie Australia’s CEO implied to even get close to the 2030 climate targets Australia would need 10,000km of new transmission, 44GW of new renewables and 15GW of firming capacity. With components scarce, increasing costs and logistical issues of port slots to physically ship the parts to Australia, maybe it is time to turn our attention inwards and start upskilling and creating our own industry to de-carbonise ourselves?

AEMO adds to the spooking of the Energy Market post Liddell Shutdown

Energy Market - AEMO _ Liddell Shutdown

On Thursday (25th May 2023) AEMO released their Scheduling Error notification (incident number 54) confirming they had incorrectly scheduled three of the Liddell units into one of their systems, post the Liddell shutdown, which caused price spikes across the NEM and forwards market on the morning of 1st May 2023.

As has been widely documented the last three Liddell units came offline on the 24th of April (Unit 4), 26th April (unit 2) and finally unit 1 on the 28th of April. This should have flowed through to the systems within the AEMO dispatch engines, however due to an error this was not the case, and the market was affected by the error between midnight and midday on the 1st of May 2023.

The error was cause by a mismatch of data used within the systems which feed the NEMDE (NEM Dispatch Engine) used by AEMO, whereby one part of the system removed the units from 00:01 on the 1st May. However, a separate part of the NEMDE’s data feed system, which controls the constraints still included the Liddell units at their “initial values” i.e. 500MW, not their real value of zero.

When the equations within the constraint tried to equalise, there was a “drop” of 1500MW on one side of the equation from the first interval on the 1st May 2023.

To rectify this AEMO reduced flow coming from Victoria into NSW and around 173MW of generation was dispatched down.

Prices reacted as expected with 6 periods between midnight and 6am having prices between $2,771.58/MWh and $2,964.04/MWh and increasing the daily average price by around 30% to an average of $288.86.

With a marketplace reacting to every cough of a power station, especially in the days following the Liddell closure the added constraint was enough to also strengthen the forwards market with the Q323 close price rising $5.50/MWh on the day in comparison to the day before across QLD, Vic and NSW and even SA was affected with an $8/MWh increase on the previous days close.

This strength continued into the next few weeks as outages came into the mix, a tube leak delaying the return to service of Bayswater 2 to the 3rd May, Kogan Creek, Eraring 2 and Tarong taking outages, the return of Callide being delayed and an unexpected interest rate hikes putting additional pressure on the market. Speculators were quick to act trading the spread between states thus increasing prices across the NEM.

This reactionary sentiment is one we feel will remain for a while, with the spot market quickly correcting however the futures continue to hold value down the curve.

News from Rewiring The Nation

Australian Power Lines

Over the last week Chris Bowen has been selling from everyone to industry to landowners on the government’s $20 billion “Rewiring the Nation” project. He has stated that “securing social license to build the transmission lines is the single most pressing issue for the Australian energy transition.

The proposal involves the development and construction of 10,000km of lines before 2030 and the key to achieving this will be community and stakeholder relationships, which are now being built into the regulatory investment test (RIT-T) process. To facilitate this the NSW and VIC government are offering $200,000 per km for the land crossed by these new infrastructure projects.

Ian Learmonth, the head of the Clean Energy Finance Corporation, said that Australia will need an estimated 29GW of large-scale renewables to meet our ambitious goals, which breaks down to around 3.6GW a year.

This compares to last year’s large-scale wind and solar where Australia only installed 2.3GW. The 29GW required to be installed is challenged by the slow progress in developing essential new transmission lines and therefore Australia’s targets are at risk.

Daniel Westerman, the Chief Executive of AEMO, has stated that “From our control room we can see that increasing amounts of solar and wind generation are being curtailed because there’s not enough transmission capacity to transport it.”

Despite this, the share of renewables in the grid is hitting new highs, averaging 37% in Q1, and peaking at 66% for a half-hour dispatch period. As a result, greenhouse gas emissions from the grid were at their lowest recorded ever in Q123.

Additionally, there is concern from AEMO that there is 14GW of coal powered generation capacity retiring by 2030, which exceeds the 8GW of renewables announced so far. The effect of this could be starkest in the short term. With Eraring (2,880MW) due to come off in late 2025, there are concerns of a significant short term firming capacity gap for first few summers in NSW.

However, with a new Capacity scheme expected to be announced in the next few months, and the next ESOO due in October expected to show the shortfall for NSW, the possibility of extension is one being seriously discussed.

With the VIC – NSW West Interconnector final drafts expected soon and Humelink approval expected early next year, the move to new transmission is starting. However, questions remain as to whether it is too late for the government to meet its targets.

Next test in NSW for the transition to renewables

Hand turning off light switch

For over eight years, there has been talk of AGL shutting down Liddell power station. Finally, this will become reality today, with the next Liddell unit being shut down.

Liddell Unit 4 will be shut down today, followed by Units 1 and 4 over the next 10 days. The retirement of Liddell power station will make 10% of NSW’s availability being bid unavailable.

It would be expected that the permanent closure of 10% of NSW’s electricity generation would put the grid at risk and lead to higher electricity prices.

AEMO has alleviated market concerns by saying, “Supply is not at risk”. However, Edge2020 is not ruling out an upward pressure on prices due to a shock to the market, despite the market knowing the Liddell units would be shut down for many years.

The retirement of Liddell power station is the next big step for NSW as the state transitions from scheduled coal-fired generation to intermittent renewable energy and storage.

While the market has known about the retirement of the Liddell power station for years, Edge2020 expects the market to be firm on the reality of the closures. Spot electricity and forward prices in NSW and Queensland may increase in the short term; however, they will settle over time.

Following the retirement of the Liddell units, availability will still be relatively high in NSW. The capacity factors of the remaining coal-fired units will increase, and gas will fill the remaining gaps. As a result of this and generation from neighbouring regions, it is unlikely that the NSW region will incur a significant drop in availability resulting in a Lack of Reserve (LOR) notice from AEMO.

AEMO confirmed in February that the closure of the Liddell units would not breach the reliability standard; however, AEMO’s latest reliability report has raised concerns that reliability risks remain in NSW. AEMO’s biggest reliability concern has been the delayed delivery of Snowy Hydro’s Kurri Kurri gas-fired generator. The Kurri Kurri gas-fired generator has been delayed by 12 months. AGL has confirmed AEMO has not approached them regarding reliability levels following the closure.

Further to alleviate the availability and reliability concerns of the market as we approach to summer is the news that Energy Australia will have the 300MW Tallawarra B gas-fired generator online in December. Additionally, NSW imports additional electricity from Queensland and Victoria via the interconnectors.

AGL has plans to repurpose the Liddell site into a clean energy hub which will include a 250MW battery with room for expansion that could be linked to a nearby pumped hydro project.

After the closure of Liddell 4 on April 19th, followed by Unit 2 six days later, and then finally Unit 1 on April 29th, AGL will start demolition in early 2024.

The next few weeks will be an interesting time in the industry, particularly for NSW politics and the wider NEM. Edge2020 will monitor the market and provide updates over the next few weeks as the final unit retires.

Solar and wind are the big losers in latest AEMO MLF forecasts

woman on a windy day

As the electricity market evolves the Australian Energy Market Operator (AEMO) makes assessments of the changing landscape from a transmission and security of supply perspective.

Recently AEMO released its final assessment of Marginal Loss Factors (MLFs). MLF determine how much energy is lost between the generator and the region reference node in each state.

In this next round of MLFs many of the big losers are the intermittent generators. Changes to the grid and the closure of thermal generators have had a detrimental impact on wind and solar farms. Lower MLF’s impact the amount of revenue generators can make.

The final MLF numbers are not as bad as what was published in AEMO draft report providing some positive news for wind and solar developers. Since the draft report new modelling has included the delayed return to service of the Callide C units.

The primary driver for changes in the new MLF forecasts has been changes in availability due to the closure of Liddell, revised return to service dates for Callide C, revised demand forecasts and the increased penetration of solar and wind generation into the grid.

Recent transmission line work has resulted in an increased capacity between Queensland and NSW which means increased flows from Queensland which results in wind and solar projects located in the north of NSW being constrained.

MLF generally gets worse for generators at the end of a long transmission lines, this has resulted in generation in northern NSW being the big loser this year. Some solar farms in the New England region have dropped by over 3%.

While a 3% fall sounds bad, it is not as bad as the MLF for Moree, a 57MW solar farm in western NSW which loses over 20% of its generation by the time it gets to the regional reference node. Previously Moree solar farm had an MLF of 0.8275, this year it is 0.7977.

The return to service of Callide C significantly impacted solar farms in central Queensland, however the delayed return to service has lessened the impact. Daydream, Collinsville, Kidston, and Moura are some of the solar farms most impacted by the new MLFs.

So what does the mean to end users? While we are seeing a rapid increase in renewable generation, the location of this generation is important to the success of a project. If we use the example of Moree where over 20% of the renewable generation does not reach the market then the question has to be, was it built in the correct part of the grid. Many people focus on the size of the project while the volume of electricity produced needs to be of greater importance. Unfavourable MLF will impact the success of the project, will reduce the renewable energy available to the market and potential can leave end users with less renewable energy than what they had signed up for.

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


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:

Future investment in the grid not the cheapest option

At the end of February, Energy Ministers agreed to go down the path of a voluntary congestion relief market with priority access. Most developers and advocates of renewable energy have supported the energy minister’s decision to proceed with planning for a congestion relief market, but Australian Energy Market Operator (AEMO) have released initial costings showed it could cost more than $300M.

Previously the Energy Security Board (ESB) proposed a connection fee model, the voluntary congestion relief model has been estimated to cost up to 30 times more than the connection fee model.

The new ESB boss and current chair of the rule maker, the Australian Energy Market Commission (AEMC), recently said “the more expensive voluntary model chosen to help fix transmission congestion on the grid from the influx of renewables will ultimately deliver more benefits for consumers and result in fewer carbon emissions”.

The NEM is controlled by the National Electricity Market’s dispatch engine (NEMDE), this computer system dispatches all the scheduled units across the NEM and optimises across all inputs including bid prices, constraints, supply, and demand. This is an aging system and would require replacement to operate the ESB’s proposed connection fee model.

The Australian Financial Review revealed the congestion model would cost $76M, much higher than the $19M congestion model initially preferred by the ESB, however there are cost savings in not replacing NEMDE.

The ESB’s cost-benefit analysis of the capacity relief market would result in a net benefit of between $2.1B and $5.9B over 20 years. Apart from the economic benefits the model would reduce emissions by 23Mt over the 20 years.

Transmission congestion has increased over the last 5 to 10 years as more renewable and storage projects connect to the existing network. The market operator AEMO has been highlighting the need for new network capacity to accommodate the 127GW of renewable energy expected to enter the grid by 2050 in various planning publications. While renewable energy will displace the majority of coal and gas generation an extra 63GW of transmission capacity are still needed to facilitate the 127GW of renewables and storage likely to connect to the grid.

Under the current market rules generation from new projects can curtail the output of existing power station resulting in existing projects exporting less power. While this model works well for system security it does not work well for developing an industry and providing certainty for developers.

The ESB’s preferred option of voluntary congestion would allow developers to trade congestion relief with priority given to existing projects over new projects when accessing the grid during times congestion.

The final model will be delivered to the energy ministers by mid-2023 and is likely to be in place in 2027.

Despite being the best solution over the long-term existing energy users will pay the cost in the short term.

 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: