Government Boosts Firming Power Generation: Blueprint or Cautionary Tale?

Edge2020_Power Generation

In a bold stride towards energy security and sustainability, the Australian Federal Government, led by Chris Bowen, unveiled plans on Thursday to augment its support for an additional 550 megawatts (MW) of firming power generation in New South Wales (NSW). This amplification propels the existing plan of the state to nearly a gigawatt of firming capacity, a robust move geared to maintain grid reliability and security.

The comprehensive scheme, anchored in sustainability, is anticipated to attract nearly AUD 10 billion in investment and stimulate the power generation of an impressive 6 gigawatts (GW) to support the national grid’s dependability.

To date, proposals exceeding 3.3GW have been tendered, these initiatives target the void left by the looming shutdown of fossil fuel generators across the National Electricity Market (NEM). The government’s ambitious plan aims to offset the forecasted power deficits in the CAL28/29 periods following the discontinuation of Eraring and Vales Point power stations, operated by Origin and Delta respectively.

Chris Bowen hailed the announcement as a substantial enhancement to energy security, attributing this positive shift to the deployment of large-scale batteries and other zero-emission technologies. These avant-garde technologies promise to swiftly dispatch cleaner, more affordable renewable energy on-demand, such as during intervals of calm weather and diminished sunlight.

However, the ambitious plan is not devoid of challenges. It remains uncertain whether the proposed measures will adequately address the power shortage anticipated from the phasing out of fossil fuel generators. The firming capacity earmarked for support is predominantly anchored in large-scale battery and pumped hydro storage.

Recent delays to the Snowy 2.0 project have sparked fresh apprehensions about the NEM’s ability to maintain a stable electricity supply and avert a surge in power prices. Furthermore, while storage options such as pumped hydro and batteries seemingly complement renewable sources, uncertainties linger about the reliability of renewable energy during periods of calm weather and low sunshine. These concerns will be crucial in determining whether the shutdown of existing coal generation is postponed or accelerated.

The Federal Government’s bid to enhance firming generation capacity in NSW, although ambitious, is riddled with uncertainties. Striking a fine balance between maintaining grid reliability, mitigating price surges, and ensuring project completions will be a delicate act.

As Australia stands on the precipice of a renewable energy revolution, it begs the question: will this be the blueprint for the future, or will it serve as a cautionary tale? The success or failure of this grand scheme will undeniably cast a long shadow over the future of renewable energy not only in Australia but globally.

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.

NSW South West Renewable Energy Zone

Street lights at night

Last Friday, the NSW government released their draft declaration for the South West Renewable Energy Zone (SW REZ) access scheme to the public. This is one of five REZs which have been identified within NSW as part of the NSW governments Electricity Infrastructure Roadmap. The schemes are overseeing the volume of projects which will be granted to the transmission within these zones and co-ordinate the network and generation investments into the areas.

The SW zone is based towards the Victorian border and the proposed connection point would be in the Dinawan Substation. The access standards are very similar to those already proposed in April for the states Central-West Orana (CWO) region.

With the CWO attracting more than $35billion worth of proposed projects the SW REZ is hoping to attract significant investment for its 2.5GW transfer capacity, noting the location will not allow for offshore wind and as much Hydrogen investment as that seen in the CWO.

The NSW government has stated that the aim of the declaration is that “An access scheme provides an opportunity to control the connection of projects to the REZ. In the case of the South West, the proposed access scheme triggers the application of modifications to the National Electricity Rules (NER) open access arrangements as they apply to the access right network.”

The access granted projects will benefit from significant network upgrades including potential upgrades to the Project Energy Connect (PEC) interconnector which is being developed at the moment and is to run between SA (Robertstown) and NSW (Wagga Wagga), upgrades to the HumeLink which would connect that Wagga Wagga substation with Snowy Hydro and its increasing capacity and further strengthen the investment case for the proposed Victoria-NSW interconnector (VNI West). The latter is currently within the RIT-T (Regulatory Investment Test for Transmission) process.

These proposals will surely give investors’ confidence in providing the required project certification to be granted the access to that zone. They must not only show feasibility and prepare to sign onto the standards set out in this proposition, but must ensure they can manage voltage, frequency especially which there are potential disruptions within the system. However, the rewards of participating in a well-funded, transmission rich environment which has certainty of curtailment risk for the access rights holders, are surely going to outweigh the paper-work process of being accepted and given the over subscription of the CWO, you can imagine a similar uptake in this round.

The consultation for the South West Renewable Energy Zone (SW REZ) access scheme is closing on the 15th May 2023.

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.

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.

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

AEMO Suspends the Market

Below is the media release from AEMO after it suspended the National Electricity market at 14:05 today.

AEMO today announced that it has suspended the spot market in all regions of the National Electricity Market (NEM) from 14:05 AEST, under the National Electricity Rules (NER).

AEMO has taken this step because it has become impossible to continue operating the spot market while ensuring a secure and reliable supply of electricity for consumers in accordance with the NER.

The market operator will apply a pre-determined suspension pricing schedule for each NEM region. A compensation regime applies for eligible generators who bid into the market during suspension price periods.

In making the announcement AEMO CEO, Daniel Westerman, said the market operator was forced to direct five gigawatts of generation through direct interventions yesterday, and it was no longer possible to reliably operate the spot market or the power system this way.

“In the current situation suspending the market is the best way to ensure a reliable supply of electricity for Australian homes and businesses,” he said.

“The situation in recent days has posed challenges to the entire energy industry, and suspending the market would simplify operations during the significant outages across the energy supply chain.”

Edge wish to reiterate, this is not a physical supply issue. AEMO directed 5GWhs of physical generation into the market. If generators can operate when under direction, they do not have a physical reason to not generate (such as maintenance, overhaul etc), so the reduced availability we are seeing has to be a commercial trading decision to either price volume into higher price bands or to remove availability in the maximum availability bands of their bids. The availability is there, the generators are just not offering it via the spot market.

The market suspension is temporary, and will be reviewed daily for each NEM region. When conditions change, and AEMO is able to resume operating the market under normal rules, it will do so as soon as practical.

Mr Westerman said price caps coupled with significant unplanned outages and supply chain challenges for coal and gas, were leading to generators removing capacity from the market.

He said this was understandable, but with the high number of units that were out of service and the early onset of winter, the reliance on directions has made it impossible to continue normal operation.

The current energy challenge in eastern Australia is the result of several factors – across the interconnected gas and electricity markets. In recent weeks in the electricity market, we have seen:

  • A large number of generation units out of action for planned maintenance – a typical situation in the shoulder seasons.
  • Planned transmission outages.
  • Periods of low wind and solar output.
  • Around 3000 MW of coal fired generation out of action through unplanned events.
  • An early onset of winter – increasing demand for both electricity and gas.

“We are confident today’s actions will deliver the best outcomes for Australian consumers, and as we return to normal conditions, the market based system will once again deliver value to homes and businesses,” he said.

What does it mean for generators and end users.

  • Bidding and dispatch will continue as usual under the market rules.
  • Dispatch instructions will be issued electronically via the automatic generation control system as usual
  • If required AEMO may issue dispatch instructions in any other form that is practical in the circumstances.
  • Spot prices and FCAS prices in a suspended region continue to be set in accordance with NEM rules or under the Market Suspension Pricing Schedule.

The Market Suspension Pricing Schedule is published weekly by AEMO and contains prices 14 days ahead.

The market will continue to operate under the Market Suspension Pricing Schedule until the Market operator determines the market is able to return to normal conditions and the suspension is revoked.

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

LGC prices slide

Yesterday we considered the possibility of large-scale generation certificate (LGCs) prices reducing due to the federal review. Prices have slid $4/certificate this week.

In recent news reports, ERM founder, Trevor St Baker said the government would need to adjust the renewable energy target (RET) to 20,000 gigawatt hours to fall in line with infrastructure expectations.

“There is no way we are going to make the 33,000 target. It’s impossible to get there.” Mr St Baker said.

We concur, and have for quite some time.  Fundamentally, in a politically stable environment, we can only see LGC prices trending to and sitting at the full tax adjusted penalty of around $93/LGC. There aren’t enough certificates in the market to fulfil obligations without a sharp increase in the number of new renewable generation projects coming online over the next two years. We still forecast an LGC deficit during 2018.

However, we do not live in a politically stable environment. Abbott and Turnbull went head to head last week over the future of the RET. This combined with 2016 liabilities being squared away, has seen $4/certificate shaved off spot LGC prices this week. This is a reduction of approximately 5 percent. The movement shows how quickly environmental markets can change when politicians weigh-in.

After almost guaranteed price increases following the bipartisan agreement in 2015, trade for 2017 just got interesting.

LGC prices since 2016

References: http://www.afr.com/news/politics/renewables-target-will-not-be-met-says-erm-founder-20170126-gtyyvo

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