Each week new records are broken across the energy market. Be it historic record low demands, reducing levels of thermal plant availability or the increased availability from renewables.

Last week saw solar reach more than 50% of Australia’s demand. This came as record generation levels came from both rooftop PV and large-scale solar sectors.

Ironically this record occurred on Sunday while the National Party room was meeting to discuss their stance on net zero emissions. As the Nationals push to lift the profile of the coal industry and power the country from coal fired power stations, solar generation reached 51.8% of the NEMs demand.

While regions like South Australia have passed the 50% solar milestone during the weekend it was the first time the NEM reached more than 50%. As expected, solar provided most of the electricity between 11:00 and 13:00, peaking at 11:55.

The 50% hurdle could have been higher as negative prices in South Australia economically constrained some large-scale solar plants. On the previous day, the record would have been broken if not for Queensland economically constraining off 1,800MW of large scale solar due to negative prices.

As mentioned above the NEM is also experiencing low operational demands and in line with the high rooftop PV generation, the demand dropped to a record low across the NEM of 12,936MW on Sunday as solar reached over 50% generation. As rooftop PV is not economically constrained, it accounted for 38% of the underlying demand.

As solar generation increased, it displaced coal fired generation with black coal generation throughout Queensland and NSW reaching historic lows of 6,105MW.

These statistics were surely discussed in the Nationals party room over the weekend and along with AEMOs forecasts showing the NEM can reach 100% renewables by 2025 as their base case scenario in modelling such as the ISP and the ESOO, the question about the role of renewable and coal in the market must have been discussed.

During the Spring months, skies are clearer and air temperatures are conducive to low air conditioning and heating loads, we could realistically see a situation where rooftop PV could cover demand. Of course, this will cause issues for AEMO who are required to keep various synchronous units online for system security however recent changes have allowed AEMO to employ systems to switch off solar in the event of a grid event to maintain grid security.

Written by Alex Driscoll Senior Manager Markets, Trading & Advisory


Recent data shows there is a slowdown in the rooftop solar industry, and this is likely to continue as prices rise. Installations in August dropped, most likely due to the current lockdowns in NSW and Queensland. NSW installations have been the heaviest impacted followed by Victoria then the largely COVID free Queensland.

The early growth in the roof top PV market has gradually reduced with 2021 largely being flat across Queensland and Victoria. Early adopter states like South Australia are gradually declining due to early adopters reaching capacity. The growth in the early adopter segment is now replacement of existing systems with larger systems.

It is likely that the continued growth in states like Queensland are a result of COVID related home improvement plans funded by government financial stimulus.

Recent talk of a ‘sun tax’ has prompted people to install roof top PV before the changes occur while residents in SA would be concerned about installing a system that can be switched off when system conditions occur potentially leaving them exposed to high electricity cost. The other driver slowing the uptake of roof top PV is the lower feed in tariffs offered by retailers. The lower feed in tariffs do not make the installation of roof top PV as attractive and large-scale renewable energy should also bring down the retail cost of electricity.

With recent changes to the exchange rate the cost of imported panels will increase and as a result roof top installation will become more expensive. Higher installation costs and lower feed in tariff reduces the incentive for households to install solar.

As the number of installations drops, operational demand is less impacted during solar hours as consumption increases over time. Under the small-scale renewable energy scheme, liable entities are required to surrender the number of small-scale technology certificates (STCs) equal to that produced each year so as the number of certificates created each year increases the number of certificates they need to procure also increase. Any slowdown in the installation market may even reduce the percentage of certificates the liable entities need to surrender. STCs are likely to stay in their narrow trading range even if the number of certificates created each year fluctuates.


In a sign that not only coal fired generators are impacted by changes in energy industry, last Friday more bad news came out the Australian Stock Exchange with Genex Power announcing a $16.5M write down on the value of its recently completed Jemalong solar farm due to dropping power prices.

In its FY21 results presentation, Genex Power outlined its revenue was underpinned by long term contracts for its operating assets and its projects in construct.

The Jemalong solar farm was completed on time and on budget so any losses could not be directed at this. The project located in western NSW was bought from solar developer Vast Solar.

The Jemalong assets were commissioned in July and are operating ahead of expectations however its recognition of the merchant revenue from the project in a falling market has caused value to be written down.

Despite the forecast for falling electricity prices, Genex is powering ahead with other developments including the Kidston Pumped Storage Hydro plant that will sit alongside the existing 50MW Kidston Solar farm that is planned to expand by a further 270MW in the future.

Genex is banking on the 250MW Kidston pumped hydro storage facility providing an arbitrage opportunity for the company as it can charge its storage by filling the upper reservoir during low day time prices and generate up to 250MW over the higher price parts of the day most likely the morning and evening peaks. If all modelling goes to plan Genex may also add up to 150MW of wind at the Kidston energy hub by 2025.

The company is also looking to diversify its portfolio geographically by installing a 50MW/100MWh battery at  Bouldercombe, in Queensland. The battery is likely to be operational by 2023 with the 250MW Kidston pumped hydro storage facility likely to generate by 2024.


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On Wednesday last week the Energy Security Board (ESB) released a statement outlining that they had finalised advice on the redesign of the national electricity market (NEM) and handed the report to the Energy National Cabinet Reform Committee. This advice comes from a 2019 request to redesign the market to support the orderly transition to a modern energy system that allowed a rapid increase in the growth of large and small scale renewable energy.

Details of the advice is not publicly available but wording in the media release indicates that coal fired generation will play a key role in the transition. The statement outlines that there must be a coordination of the exit of aging coal fueled generation to maximise the opportunities and minimise risks associated with the transition to deliver affordable, smart, and clean energy.

The ESB consulted widely with industry stakeholders, conChanges to the generation mixsumer bodies, academics, government bodies and interested parties over the last two years. An options paper was released in April and the final advice is expected to closely reflect the options discussed.

Key areas we expect to be tackled in the final redesign advice is preparing for the older coal fired generation retirement, backing up power system security, unlocking benefits and opening the grid to cheaper large-scale renewables.

In preparing for the retirement of the older coal fired generation, the ESB want to give an incentive for the right mix of resources including renewables and non-renewable generation. This was to restore confidence in consumers that energy will be available when required and the mix will include intermittent generation like wind and solar as well as firm dispatchable generation like gas.

To tackle the need for a more secure power system, the ESB will require different ancillary services like inertia, voltage, and frequency control. A market for these services will be required to ensure the procurement and dispatch of these services save money while keeping the network electrically secure.

Further work will also include unlocking the benefits for all energy consumers to gain the advantages of rooftop solar PV, batteries, and smart appliances. Improvement in these areas may also include how consumers source their energy.

As generation is only part of the equation the need to reform the way electricity is transported is also a key redesign topic. Upgrading the network with the construction of transmission lines will reduce congestion and allow cheaper generation to be built in regional areas and improve the diversification of the grid by opening up more geographic locations.

The question most end users are asking is who is paying for all these improvements. As usual the end user will pay. The ESB is understood to be recommending capacity payments for electricity generators to remain online. These generators are likely to be the older coal fleet so consumers will be paying to keep higher carbon intensive technologies online rather than supporting renewables.

This situation will pay generators an available payment to generate when required. In reality, these units will not generate unless the market is at the point of load shedding.

Capacity payments are used in the Western Australian electricity market, under their current arrangements, generators receive capacity credits in line with their units generating capacity.

In the NEM if capacity payments are introduced, they will essentially offset the Reliability and Emergency Reserve Trader (RERT) costs currently used to provide a similar service.


In this issue we look at the following;

  • We recently contracted 3 of Brisbane’s Largest Towers. How do we do it?
  • What is causing the increase in the spot &futures market prices?
  • What is aggregated electricity procurement and should you do it?

National NAIDOC week was celebrated during July and Edge acknowledge the Turral and Yuggera peoples as the traditional owners of the land on which our offices sit. We pay respect to elders past, present and future.


Last Tuesday saw a new record set for wind powered generation with NEM wide production reaching 5,899MW late in the afternoon. Wind made up 20% of the total generation at the time and on occasion peaked to 26% of NEM wide generation. As seen from my market commentary in recent weeks we have seen large fluctuations in available generation from intermittent sources such as wind and solar. In the past 6 months although peak wind production reached 26% it has also reached a low of just 2%. As more wind farms come online and are built across different regions, we will see more diversification of output. Currently Victoria leads the pack with the most wind generation followed by NSW and SA with TAS and QLD only contributing small amounts of wind generation.

In line with the increase in renewable generation, last year operational demand increased by 350MW primarily driven by cooler Q2 conditions and the opening up of the economy following the Covid lockdowns the previous year. LNG export prices have also increased as the world economy improved, this led to an increase demand in QLD for electricity in the gas production value chain. Overall wind and solar generation have reached record highs peaking at 57% market share in April.

Although the average operational demand has grown, the increased penetration of roof top PV reduced demand by 298MW between 10:00 and 14:30. Generation from intermittent sources such as wind and solar reached a record 7,368MW in the second quarter, 457MW more than the same quarter a year ago.

Coal fired generation dropped for a few reasons over the quarter, initially coal generation was being offset by renewable generation then interruptions in coal supply and unit failure lowered production.

The largest contributors to these reductions where Victoria’s Yallourn power station where flooding in the neighbouring mine reduced the output and a catastrophic failure at Queensland’s Callide C4. Following the failure of Callide C4, network protection took out a significant amount of coal units over the next couple of hours while the network was reinstated to isolate Callide power station. As a precaution the undamaged coal fired units at Callide remained offline for the following weeks while the cause of the initial failure was investigated.

With low and sometimes negative prices during the day due to high levels of rooftop PV, large scale solar and wind, the remaining generators tried to extract value from the morning and evening peaks. Historically this would have been taken up by coal fired generation but in Q2 gas powered generation (GPG) operated more due to the scarcity of coal fired units.

A record amount of 57% renewable generation occurred at 11:30 on 11th April, this was made be solar, roof top PV, hydro, and biomass, and was 1% more than the previous record seen in October 2020.

Although renewable generation has been high, restrictions on the network are limiting further output. Curtailment occurred for about 4% of semi-scheduled intermittent generation which was higher than Q1 primarily due to higher negative prices. Intermittent generation now their output at times of negative pricing to limit their exposure to the market. We also see an increase in the amount of curtailment resulting from network congestion and network constraints. In regions with very high levels of renewable penetration such as South Australia saw intermittent generation curtailed to manage AEMOs System strength concerns.


Scott Morrison and his Minister for Energy and Emissions Reduction continue to appoint mining executives to the Australian Renewable Energy Agency (ARENA). The next to be appointed is Stephen McIntosh from Rio Tinto. Fellow board member John Hirjee is also a former Rio Tinto executive.

As Rio Tinto is one of Australia’s largest coal producers, opponents to the appointments find it hard to understand how these executives can add value to the ARENA board.

However, Minister Angus Taylor said “that the addition of McIntosh would bring to the ARENA board experience in the production of the materials used in clean energy technologies like electric vehicles and battery storage”.

Taylor went on to say “Mr McIntosh is a former Rio Tinto Group Executive with experience in green metals, wind, solar and batteries. He has also worked across hydrogen and carbon capture technologies during his time with the company.”

Darren Miller, the CEO of ARENA, has had his contract extended for another three-year term and will work with other senior staff and board members to provide funding into the development of new clean energy technologies.

Questions have been raised about if ARENA is distributing its funding fairly with Rio Tinto awarded funding for a feasibility study into the use of Hydrogen at its Yarwun alumina refinery and the funding of the Kidston pumped Hydro project where renewable projects in the region were rejected.


Spark Infrastructure, the partial owner of SA Power Networks, Transgrid, Powercor, CitiPower and the Bomen Solar farms is looking at developing a 2.5GW renewable energy hub in the middle of the South West Renewable Energy Zone (REZ) in NSW.

The Dinawan Energy Hub is strategically situated along the route of the planned interconnector between South Australia and NSW. The EnergyConnect project will be a 330KV interconnector running between Wagga Wagga and Robertstown in South Australia and will open up more than $20B of new renewables projects.

The Dinawan Energy Hub will be located halfway between Coleambally and Jerilderie and due to its location will support the existing network and the Humelink and Karanglink interconnectors.

The hub is expected to be completed by 2025 and is expected to include 1GW of wind, solar and battery storage. The $1.5B project will be undertaken in stages with the first stage expected to

commence construction in 2024.

Spark Infrastructure have completed the project identification stage of the development and now will undertake engineering studies and community consultation. The final investment decision is expected in 2024.

In some ways the Dinawan Energy Hub will compete with the NSW government’s plans to develop the REZ however Spark infrastructure believe the REZ and the energy hub can be developed together.

Spark Infrastructure is also in the news with a potential takeover bid for the multi-billion-dollar business.

Leading global investors including Kohlberg Kravis Roberts (KKR) and Ontario Teachers’ Pension fund have showed interest in investing in renewable energy and infrastructure projects in Australia.

It is understood these investors are looking at investing $5B to take over Spark Infrastructure.

If the takeover goes to plan, KKR and Ontario Teachers’ Pension Plan may add the Australian market to their target markets having recently bought a stake in Finland’s largest electricity distributor. KKR is also in the process of buying John Laing, a developer with interest in renewables assets in Australia.


Back in 2017 following the black out of South Australia, the Tesla big battery was announced as the largest lithium-ion battery in the world. Weighing in at 100MW/150MWh the unit was big and provided enough storage to get regions through short duration period of high price of low availability. At the time, most people in Australia thought of batteries as a small segment of the industry and did not predict batteries to make any meaningful impact on the market for the next 10 to 20 years.

The Tesla big battery has now grown to 150MW/194MWh with the addition of extra batteries but has lost its title as the world’s largest and is likely to lose the title as Australia’s largest battery with Neon installing a 300MW/450MWh big battery near Geelong.

Now even Australia’s newest largest battery is about to be pushed off the top step as large scale wind and solar projects are installing larger, high-capacity batteries.

Most large-scale batteries in Australia have not been operating as storage devices, instead offering a service to “time shift” generation out of intermittent generation such as solar or wind to the time where the energy is required and returns better prices. The big batteries have predominantly been operating in the frequency market where they deliver network services such as frequency control ancillary services and synthetic inertia. To provide the network service the batteries operate for short sharp periods and as a result do not require large amounts of storage duration. As the competition in the network services segment of the industry increases the price for these services has reduced. Battery developers are now focusing on “time shifting” to provide better return for their projects rather than being exposed to low solar hour prices.

As coal fired generators retire the “duck curve” will deepen opening more opportunities for batteries to time shift the wind and solar generation into the evening peaks.  Developers are now looking for large duration storage to optimise their returns over the evening peaks. It now appears a 4-hour storage duration is the norm.

In recent weeks we have seen the large market players with significant thermal generation installed entering the battery developer market. Energy Australia is planning a 350MW big battery with four-hour storage at Yallourn.  AGL is constructing a 250MW big battery with four-hour storage at its Torrens Island site in South Australia which has announced the mothballing of its gas units. AGL also plans to replicate the 250MW battery at its Loy Yang coal site in Victoria. At Eraring, Origin is planning to install a big battery to offset generation when the coal fired power station closes.

The question is, if “time shifting” occurs, the times when the battery charges will likely raise spot prices as demand increases and the evening peak prices should drop. To make money battery operators will need to arbitrage the charging cost with the price they receive when they discharge. With the increased penetration of wind and solar generation into the generation mix the spot prices during the solar hours are likely to fall further however with many large-scale battery developers still heavily reliant on coal fired generation the optimisation of their exist portfolio will be interesting to see.