Potential for Below Baseline REGOs

Two silhouetted figures stand on a platform at sea, observing a vast offshore wind farm against a dramatic sunset sky.

LGCs are now in an interesting position. With the REGO scheme all but fully legislated to start in 2025, there may be opportunity to meet voluntary requirements from this secondary market before it becomes the likely primary market at the end of 2030 until 2050.

The REGO scheme looks likely to exist in parallel to the LGC scheme until the expiry of the RET, with generators able to decide which products they would like to produce in any given period.

However, the REGO scheme will open previously un-tapped generation, such as below baseline generation, generation from outside of the Australian economic waters area and exported generation i.e. Sun Cable, which the LGC cannot. Further (although unlikely before 2030), STCs can be pooled to create 1 MWh, i.e. 1 REGO certificate at the point the 1MWh limit is reached.

This market is currently untapped, but with a REGO holding the same credentials as an LGC, the voluntary surrender optionality (RET Liability must still be met with LGCs until 2030) can be achieved through the REGO scheme.

With voluntary surrenders increasing, the CER estimated in 2022 a total of 7.4million LGCs were surrendered voluntarily. This increased the demand for LGCs by 1.6million in comparison to 2021 and created a demand 23% above the legislated requirements for LGCs (33m).

Prior to a REGO scheme, the increasing demand for these LGCs has come from growing corporate targets either directly into the LGC market or through its secondary market, such as GreenPower schemes.

Without increasing the availability of alternative generation sources, this growth could lead to a tightening of the supply-demand balance of the LGC and an increase in price. As such the introduction of a REGO from 2025 could be the pressure release valve the industry requires.

The growing non-RET requirements are significant, and therefore, the introduction of secondary sources of power through the REGO scheme is the only way the market will be able to meet the increasing demand.

The ACCC investigation into Momentum in 2016, where Momentum was handed a $54,000 fine for falsely advertising their green credentials, as they are backed by Hydro Tas whose generation was below baseline, has brought to the fore the requirement for accreditation of these below baseline assets (outside of the i-REC scheme).

Below baseline is renewable generation assets created before 1997 – mainly hydro assets. The baseline is set on production between 1994 – 1996, and therefore, generators coming on from 1997 have a baseline of zero and can produce LGCs, unlike those online prior to 1997. Indications are these facilities generate 12-13TWh of electricity each, that is, 12-13 million REGOs, which could come into the Australian voluntary market (pre-2030 RET end). However, the below baseline generation is eligible for an i-REC certification and many assets pursued this option prior to the REGO /GO scheme announcements. As such, this 12-13 million may be as low as 2 million in the initial years, given existing PPAs and voluntary i-REC surrender deals in place.

It is worth noting, if Hydro Tas had created the REGO and these were surrendered against the Momentum portfolio, the renewable claim would have been upheld, and the REGO would have never hit the market. This example shows that even if produced, companies may utilise the additional certification without giving others the opportunity to trade them in the open market.

A concern does sit around the inclusion of small-scale renewable REGOs, although unlikely to be in large quantities prior to 2030, the concern holds that the measurement of the “hour” the REGO is produced, when the cumulative units have reached 1MWh of generation, is currently untested and there are a significantly larger number of these units than there are utility scale solar. The cost and oversight required could add cost to the certificate, which we currently have no view of as to the uptake or requirements.

AEMO’s Draft 2024 Integrated System Plan

Electricity substation at sunrise, representing the transition in Australia's National Electricity Market as per AEMO's 2024 ISP.

AEMO recently released its Draft 2024 Integrated System Plan (ISP), which serves as a roadmap for the energy transition in the National Electricity Market (NEM) over the next 20-plus years in line with government policies aimed at achieving net zero by the year 2050.

The plan outlines a cost-effective strategy for essential energy infrastructure to meet consumer needs, ensure reliability and affordability, and achieve net zero. AEMO highlights the urgency for action as the NEM shifts from coal-fired generation dependency. With the closure of coal-fired power stations, the draft proposes using renewable energy supported by storage and gas as the most economical solution for Australia’s energy transition.

The policy set by the Federal Government aims for a 43% reduction in emissions compared to 2005 levels by the year 2030. Additionally, the policy targets 82% of electricity supplied in the NEM to come from renewable sources.

Previous ISPs established ambitious trajectories for investment, and it is imperative that projects are now executed according to the plans. AEMO’s most probable future scenario predicts about 90% of NEM’s coal fleet will retire before 2025, and the entire fleet will retire before 2040.

The energy transition is already well underway, with coal retiring faster than initially announced. The ISP continues to stress the need for urgent investments in generation, firming, and transmission to maintain a secure, reliable, and affordable electricity supply. The retirement of coal-fired generators necessitates a transition to low-cost renewable energy, supported by firming technologies like storage and gas-powered generation.

AEMO has stated that the NEM must almost triple its capacity to supply energy by 2050 to replace retiring coal capacity and meet increasing electricity demand. Every government within the NEM is actively endorsing the transition. The Federal Government has broadened the Capacity Investment Scheme, while various states have their initiatives supporting the transition to net zero.

The 2024 ISP outlined three future scenarios for 2050, which included Step Change, Progressive Change, and Green Energy Exports. All these scenarios involve the retirement of coal, aligning with government net-zero commitments. AEMO has assigned likelihoods of 43% for Step Change, 42% for Progressive Change, and 15% for Green Energy Exports.

Under AEMO’s optimal development path (ODP) for the Step Change scenario, there is a call for investment that would triple grid-scale variable renewable energy by 2030 and increase it sevenfold by 2050. The plan emphasises grid-scale generation within Renewable Energy Zones, quadrupling firming capacity, supporting a four-fold increase in rooftop solar capacity, and leveraging system security services to ensure reliability.

In terms of transmission, nearly 10,000 km of transmission is needed by 2050 for the Step Change and Progressive Change scenarios, with over twice that to support the Green Energy Exports scenario. The annualised capital cost for all infrastructure in the ODP until 2050 is $121 billion, with transmission projects constituting 13.5% of the annualised cost.

The NEM faces several risks in transitioning from coal to renewable energy. Key challenges that AEMO has identified include uncertainty in infrastructure investment, early coal retirements, markets and power system operations that are not yet ready for 100% renewables. Additionally, consumer energy resources are not adequately integrated into grid operations, the social license for the energy transition is not being earned, and critical energy assets and skilled workforces are not being secured.

In summary, AEMO’s Draft 2024 Integrated System Plan charts a crucial path for Australia’s energy transition, aligning with net-zero goals. With an urgent focus on retiring coal-fired stations, the plan advocates a swift move to renewables backed by storage and gas solutions. The plan also outlines the significant challenges faced by the industry that are required to be overcome in order to reach net zero by 2050 while ensuring a reliable and affordable energy supply.

Queensland’s SuperGrid Infrastructure Blueprint: A Bold Vision or a Tall Order?

Engineers in safety vests and helmets discussing renewable energy solutions on a laptop at a wind turbine electricity plant during twilight

In September 2022, the Queensland government unveiled its SuperGrid Infrastructure Blueprint, a comprehensive plan aimed at transforming the state’s energy landscape. With ambitious targets of achieving 70% renewable energy by 2032 and 80% by 2035, the blueprint sets out to revolutionise the state’s historically coal-dependent energy sector. But, as the initial excitement subsides, concerns regarding feasibility and practicality have begun to surface.

At the heart of the blueprint are six Renewable Energy Zones (REZs), designed to harness the state’s abundant wind and solar resources. These zones have been hailed as the cornerstone of Queensland’s renewable energy future, yet the involvement of various stakeholders, including First Nations people and local farmers, introduces complexities that may impede progress.

One of the primary concerns surrounding the blueprint is the intermittency of renewable energy sources. To address this issue, the plan proposes a significant investment in long-duration storage, complemented by an additional 3 GW of grid-scale storage. However, questions linger regarding the sufficiency of these measures to ensure a stable power supply during periods of high demand. With further delays to Snowy 2.0, the optimism of pumped hydro projects being completed on time has plummeted.

Furthermore, while the blueprint mentions low to zero emission gas-fired generation, the vagueness surrounding the term “low to zero” raises doubts about the commitment to truly reducing emissions. This ambiguity could undermine public trust in the project and create uncertainty for investors.

Another point of contention is Queensland’s continued reliance on its connection with New South Wales. Although this relationship provides a safety net, it also suggests a possible lack of confidence in the state’s independent capability to meet its energy needs.

Powerlink, the entity responsible for facilitating community engagement, faces the daunting task of balancing diverse interests and opinions. While the blueprint’s emphasis on collaboration is laudable, experienced observers may view this approach as a potential hindrance to timely decision-making.

Despite reservations, the SuperGrid Infrastructure Blueprint offers numerous opportunities for innovation and growth, particularly for those familiar with navigating regulatory frameworks. Nevertheless, the magnitude of the challenges ahead cannot be ignored. Bureaucratic obstacles, coupled with the weight of expectation placed upon Renewable Energy Zones, leaves room for doubt regarding Queensland’s ability to deliver on its promises.

In conclusion, the SuperGrid Infrastructure Blueprint represents a bold vision for Queensland’s energy future, but its success hangs in the balance. Either the state will emerge as a leader in the global transition to renewables, or it will serve as a cautionary tale of overambition. Only time will tell if Queensland has taken a confident step forward or a tentative shuffle into the unknown.

Renewable energy storage road map released

Edge 2020 Brisbane City

The CSIRO released its Renewable Energy Storage Roadmap at the end of March 2023.

Their modelling suggested that while Australia leads the world in solar generation, and we have reduced emissions significantly, there is still a big task ahead of the country if we are to meet net zero emission targets and maintain affordable and reliable energy to end users. The CSIRO Renewable Energy Storage Roadmap report showed Australia will need significant amounts of storage to meet the transition to renewables.

Storage is the key to integrating renewable energy into the grid and reducing the dependency on coal and gas fired generation. Currently the electricity produced from renewable sources such as wind and solar is intermittent and is not easily dispatched into the grid when it is most needed. Storage allows the renewable energy to be generated when the natural resources are high and dispatching it into the grid when the electricity is needed.

Dispatchable storage is currently available in the grid in the form of pump storage hydro, such as Wivenhoe power station in Queensland and Tumut 3 in NSW. There are also various battery installations located across the NEM.

The dispatch of renewable energy may require different storage technologies to best suit an evolving NEM. Storage comes in various forms from electrochemical storage such as batteries, mechanical storage such as hydro, chemical storage and thermal storage. Each technology has its pros and cons, but a combination of technologies is likely to be required to meet the real time storage volumes and timings of the NEM.

For many years pumped hydro has been seen by governments as the solution to Australia’s energy storage needs, but timing is the limiting factor in this solution.

To enable the transition from coal and gas fired generation to renewables, storage is required now. On a typical day we have excess solar generation resulting in negative spot prices, however over the evening peak as demand increases the supply of renewable drops of coal and gas provide the generation to meet demand. Thermal generation is normally dispatched at prices higher than the cost of renewables resulting in higher spot prices. If storage could be used efficiently the solar energy produced during daylight hours could be used over the evening peak and into the evening resulting in lower electricity prices.

As coal fired generation retires between 2023 and 2035, new dispatchable generation needs to be brought online, the CSIRO report states, development timelines need to be accelerated to bring more projects online by 2030.

Pump storage hydro typically has a lead time of 10 years so either development timelines need to be accelerated or different storage technologies need to be employed in the meantime.

CSIRO chief executive said “there was a need for a “massive increase” in storage capacity to achieve the transition to net zero, with estimates of 11 to 14 gigawatts of additional storage capacity by 2030 alone.

2030 is not far away, to meet the transition targets should industry be focusing on storage rather than generation? Is storage an opportunity to utilise existing infrastructure like old mine pits for pump storage hydro or repurpose retiring thermal power station sites as storage hubs?

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.

Energy Market Update – East Coast

Energy market prices

Edge 2020 round up of the last week

Week ending Friday 17th March


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


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


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


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

Coal and gas moves to renewables and storage

Renewable generators with battery storage

With Enel X announcing the installation of battery storage systems in shopping centres in Melbourne and on the NSW central coast, this year may see a shift in the energy market as we transition from coal and gas to renewables and storage.

Recently AEMO’s CEO Daniel Westerman said, ‘even after factoring the cost of new transmission lines, wind and solar remain by far the cheapest forms of new power generation’.

Key federal policies have underpinned the need to progress an increase in renewable energy. Growth in renewable energy is dependent on the growth of storage to be fully utilised and the need for greater transmission infrastructure is required to link the projects to the end users.

The announcement of the Net-zero emissions target of 43% of 2005 levels by 2030 have pushed other mechanisms to also ramp up across the country. The key federal mechanism is the Safeguard Mechanism, which targets the emissions reduction for Australia’s largest emitting facilities. In line with the Safeguard mechanism the 82% renewables energy target in the National Electricity Market (NEM) by 2030 is also incentivising renewable generation. As both these drivers will require more renewable energy to be rolled out to offset the thermal generation, more storage will be required to compensate for the intermittency of renewable generation and an increase in transmission lines will be required to connect the renewable energy projects with storage and end users.

AEMO has for many years been looking at a fundamental shift in generation, transmission and energy usage. AEMO is now focusing on firming, Electric vehicles and the regulatory framework to enable these changes to occur.

In recent years we have regularly seen that the NEM has the potential to operate with very high levels of renewables, but the limiting factor still remains that thermal generation provides reliability and system security when the wind is not blowing or the sun is not shining. At the end of December, South Australia produced 104% of its demand with renewable energy and exported the extra electricity to neighbouring regions.

With most states striving for high renewable energy targets, Victoria is hoping to reach 95% renewables by 2035 and Queensland has increased its target to 80% renewables by 2035.

With the recent volatility in the overseas energy markets, in which Australia is a pivotal player in due to the large quantities of coal and gas we export, there is now a greater incentive to shift away from thermal generation due to the volatility and high prices.

AEMO reports show there is currently 21GW of new projects undergoing connection assessment and they expect 5GW of new capacity to be added during FY2023, in addition to the 4GW currently operating.

To assist this influx in renewable generation ARENA granted $176m in December 2022 to fast track 8 new battery projects to bring in 2.0GW/4.2GWh of storage. The plan is to triple the battery storage across the NEM by 2025.

Over the next year we will also see more transmission lines connecting the nation as more renewable energy zones are connected to the load centres under the Rewiring the Nation policy.

The first transmission projects to receive Rewiring the Nation funding were announced following the October 2022 Federal budget. Recently funded projects include the VNI NSW-Victoria interconnect, Marinus Link and various NSW transmission projects connecting the renewable energy zones. This funding will assist in building the transmission lines over the next 10 years.

If your business is interested in wholesale or retail renewable PPAs we’d love to help you. Contact us on: 1800 334 336 or email: info@edge2020.com.au

Slow growth in renewable energy

The Clean Energy Council (CEC) recently released to its members their quarterly renewable projects report, which showed only one renewable project, Stubbo solar farm, reached financial close in Q3-2022. The 400MW Stubbo solar farm situated in NSW demonstrates the slowing of the renewable industry. Renewable project growth has slowed by almost 30% compared to Q2 -2022 and over 60% slower than Q3 -2021.

While politicians are talking up the prospects of a renewable energy driven industry to reduce the impact of climate change, the reality reaching the 44GW target outlined by the federal government may be hard to achieve at the current rate of growth. To meet the 44GW target by 2030, a significant number of new wind, solar and storage projects need to come online. If these projects do not happen, the retiring coal generators cannot be replaced and may be forced to remain online.

The CEC says investment in renewable is at an all-time low. Quarterly investment has dropped almost 60% to $418M.

As well as the federal announcements, QLD and VIC have also announced ambitious renewable targets linked to the transition from coal fired generation.

Recently the Federal Minster for Climate Change and Energy estimated Australia must install 22,000 500-watt solar panels every day for eight years, along with 40 seven-megawatt wind turbines every month, backed by at least 10,000 kilometres of additional transmission lines to meet its commitment to reduce emissions by 43 per cent by 2030. This is what is required for us to reach a target of 82% renewables by 2030.

While only one project reached financial close last quarter, three projects started construction during Q3-2022 with an increase of installed capacity of 902MW. As well as another two projects that completed commissioning during Q3-2022.

The Stubbo solar farm project also included a storage device, being the only storage device to reach financial close.

Currently, there are 247 financially committed renewable projects in Australia, with 221 under construction and 169 undergoing commissioning.

The CEC notes that the desire to build new solar, wind, pumped hydro, and transmission lines are meeting opposition from local communities. For example, projects like the Chalumbin wind farm, situated next to World Heritage-listed rainforests in North Queensland are reducing the number of wind turbines they are installing by half due to the concerns from the local community. Another example being part of the Queensland government’s renewable plan which included the construction of the largest pump storage hydro station near Mackay. Mackay locals later found out one of their towns has the potential to be flooded as part of the mega project.

With ambitious renewable targets being spruced by politicians and businesses actively seeking renewable energy to aid in the decarbonisation of their operations, the question of where and when these projects will be delivered needs to be asked. The majority of people support the transition to renewables but obviously not in their backyard.


The South Australian island and running on renewables

On November 12th a series of storms passed through South Australia that had the potential to black out the whole state, as had previously happened in 2016. Whilst parts of South Australia did lose power, it was far less dramatic than the last weather event due to a significant amount of work that has been undertaken by AEMO to build a more secure grid since the 2016 blackouts.

In 2017 AEMO released a review of the events that had blacked out the state; the main cause was of course the extreme weather that had knocked over transmission lines as well as some wind farms not meeting protection standards. Similar to 2016, it was destructive storms that passed through South Australia and damaged the network on the 12th November. At 4:59 PM, the market was notified of a significant power system event due to the tripping of multiple transmission lines. Both elements on the Tailem Bend – Southeast 275kV transmission line had tripped. Some transmission towers were damaged and had fallen over, resulting in the South Australian grid being disconnected from the NEM. On Saturday at 6:03 PM, AEMO notified the market that South Australia had been reconnected to the NEM after the 275kV transmission line at Tailem Bend was returned to service.

During events like this AEMO invokes its power to manage system security; however, this time, it went a step further and constrained off-rooftop PV to maintain a secure level of Distributed PV (DPV) generation. AEMO switched off as many rooftop PV installations as possible during the middle of the day, a rare occurrence known as “islanding” of the state grid to maintain stability, designed to keep the DPV below the secure threshold. PV generation is not as easily controlled as other sources. At times South Australia can meet all domestic demand for power via rooftop solar and sends surplus to Victoria but this cannot be managed in an islanded state, therefore requiring the curtailment of the rooftop PV allowing AEMO to manage scheduled and semi-scheduled generation assets to maintain system security.

Smart metering is required to enable the shutting down of rooftop PV systems, however not all South Australian PV systems can be controlled remotely as they have older inverters. This resulted in only 50% of systems being curtailed. Over time as more rooftop PV systems are installed using smart inverters, there will be more control of their output. Currently, AEMO can control 100MW of PV generation, but during the recent event, it also used voltage control to trip off a further 300MW of rooftop PV out of approximately 1,000MW of installed capacity.

The South Australian network has now been re-synchronised to the NEM, and electricity is flowing between South Australia and the other states of the NEM as before. While South Australia was isolated from the NEM for a week, South Australia was powered by wind and solar for up to two-thirds of its electricity demand, with gas providing the difference. System stability is a delicate balance between the supply of electricity, the types of generators providing the electricity and the electricity demand from end users. This time, part of the solution was to encourage end users to consume more electricity, enabling a higher generation level. Before the curtailment, South Australia was supplied by over two-thirds of its demand via renewable generation.

While high levels of renewable generation are good for keeping electricity costs down, the savings can be eroded by high-frequency control costs and the need for a more expensive gas-fired generation to fill the gap when the sun is not shining, and the wind is not blowing.

Edge2020 have an eye on the energy market, enabling us to support customer supply and demand agreements. Our clients rely on our experts to ensure they are informed, equipped, and ideally positioned to make the right decisions at the right time. If you could benefit from an expert eye on your energy portfolio, we’d love to meet you. Contact us on: 1800 334 336 or email: info@edge2020.com.au

Coal state leading the way to renewables

Last week in Queensland the weather was perfect. It was perfect for those at the beach during school holidays but also perfect for renewable energy.

As everyone in the NEM knows, Queensland is better known for its dominant coal generation, at times pumping out 80% of Queensland’s power supply. With the clear skies and just enough wind, Queensland became the renewable state.

Last week, Queensland’s demand was supplied by over 66% renewable energy. Solar was the largest contributor of renewable energy with wind coming in second.

Previously we have seen the state powered by 50% renewables but the 66% hurdle is a positive message for end users impacted by the reliability and behaviour of the thermal generators.

The Palaszczuk government announced their 10-year-energy plan which involved introducing two new pumped hydro mega-projects in regional Queensland and a green conversion of its coal-fired power generators. The Palaszczuk government also has recently announced upping the target of 50% renewable energy by 2030 to 70% by 2032.

Despite this increase in target, until recent years coal has remained dominant in Queensland. The government has all but ruled out the early retirement of any of the state-owned coal-fired power stations, following pressure from unions. Some could say the slow uptake in renewables is due to supply chain issues, registration, connection and construction delays while other may say it results from the government owning a significant portion of the existing thermal and non-thermal generation that is reaping high returns due to the spot and forward energy prices.

AEMO’s recent Integrated System Plan (ISP) shows the NEM will contain over 80% capacity coming from renewables by 2030. While the renewable industry in Queensland has been slow to grow recently more federal funding is being used to rewire the nation by connecting renewable energy zones (REZ) to end users. With the rewiring in place developers are less restricted in building and financing renewable projects and producing renewable energy.

Industry is also looking for renewable energy to meet their sustainability targets which leads to a market for new renewable projects. AEMO indicated there are thousands of MWs of renewable projects waiting to be built.

If Queensland followed the latest ISP, the state would require an additional 30GW of energy from renewable sources and the storage required to make it useful for end users when the sun does not shine, or the wind does not blow.

Today’s announcement by the premier outlined the $62B plan for Queensland energy and jobs. The plan includes:

  • 70% of Queensland’s energy supply from renewables by 2032
  • 80% of Queensland’s energy supply from renewables by 2035
  • Two new pumped hydros at Pioneer/Burdekin and Borumba Dam by 2035
  • A new Queensland SuperGrid connecting solar, wind, battery and hydrogen generators across the State
  • Unlocking 22GW of new renewable capacity – giving Queensland 8 times the current level of renewables
  • Publicly owned coal fired-power stations to convert to clean energy hubs to transition to, for example, hydrogen power, with jobs guarantees for workers
  • Queensland’s publicly-owned coal-fired power stations to stop reliance on burning coal by 2035
  • 100,000 new jobs by 2040, most in regional Queensland
  • 11.5GW of rooftop solar and 6GW of embedded batteries
  • 95% of investment in regional Queensland
  • Building Queensland’s first hydrogen ready gas turbine

With this announcement by the Premier, Edge look forward to more renewable generation entering the market resulting in savings for end users and the planet.

If procuring renewable energy is one of your company goals, Edge2020 can help you build a PPA to support your sustainability strategies. Contact us on 1800 334 336 or info@edge2020.com.au