Market Update – Q3 2022 to date

As we move out of Q2 2022, a quarter that we have never seen behave in this way before, it is interesting to see how things have changed in Q3 to date.

Why was Q2 2022 so controversial? Well, we saw record spot prices, record forward prices, caps put on the gas market, caps put in place in the electricity market, market direction, the activation of Reliability and Emergency Reserve Trader (RERT) and eventually suspension of the National Electricity Market (NEM). As we moved through Q3 has the situation changed?

To make this decision we must first review Q2, to assist us in understanding if things are going to change. What caused all the market intervention in Q2 and the eventual market suspension?

Q2 is normally a quiet time in the NEM, demand is low, and generators take the opportunity to take units offline for routine planned overhauls. The drop in availability that results from the units on overhaul are normally soaked up by the remaining units online. This Q2 we saw a lower than normal number of units online across the NEM to take up this slack, namely Callide C4 that was offline due to the catastrophic failure in May 2021, Swanbank E and thermal generators dispatching less volume due to flooding across NSW and QLD reducing coal supplies.

Q2 2022 saw average spot prices more than double compared with recent years and peaked at the end of the quarter. The average for Q2 2022 reached $332/MWh in Qld, $302/MWh in NSW, SA at $257/MWh and VIC the lowest, at $224/MWh.

Interestingly the quarterly average price for NSW and QLD was above where the Administered Price Cap (APC). The APC is triggered when the sum of the previous 7 days trading intervals equals $1,359,100. The price is then capped at $300/MWh and remains in place at least until the end of the trading day.

Q2 2022 was a quarter of extreme price, low availability, and market interventions. In Queensland for example we saw 42 hours of spot prices below $0/MWh but also 32 hours above $1,000/MWh. While we did not see a significant number of prices reaching the market cap of $15,100/MWh we did see solid prices that increased the average to levels not normally seen in Q2.

During Q2, exacerbating the issue, we saw significant volume bid in below $0/MWh so units would remain online, however with little between this price and higher prices meant there was a visible gap in the bid stack until prices were over $300/MWh. This distribution was a result of higher fuel cost such as spot gas at $40/GJ which converts to a generation price of over $400/MWh. However, we also saw the emergence of strategic bidding that introduced volatility and higher average prices into the market. The result of the strategic bidding was spot prices for the majority of the time across the NEM were above $100/MWh and often above $300/MWh.

As coal supplies became limited due to flooding, the gas price also jumped due to the global supply issues caused by the war in Ukraine. These fundamentals led to the spot prices increasing and eventually forcing the market operator to cap the market when the Administered Price Cap was reached. APC put a cap of $300/MWh on the electricity spot market.

As a result of the APC, generators removed capacity out of the market rather than operating at a loss due to their higher spot fuel cost. This resulted in the removal of over 3,000MW of generation in which forced AEMO to intervene in the market and direct units online as well as being forced to activate RERT to maintain system security.

Over a few days operating under the APC the market became impractical to operate using directions and AEMO eventually suspended the market on 15 June 2022.

During market suspension AEMO took over the control of the dispatch of market participants units.

Simultaneously during the market suspension, availability returned to the market as units returned from overhauls, coal and gas supply restriction improved and trading strategies were reviewed by the market participants.

On 24 June 2022 AEMO lifted the suspension of the market and the NEM returned to normal operation.

Since the lifting of the market suspension and the commencement of Q3 we have seen a change in some behavior, however spot prices remain high. In the first week of Q3 market participants took advantage of market conditions of low intermittent generation ensuring they benefitted from the ability to increase volatility. In the first week spot price hit the new maximum price cap of $15,500/MWh on several occasions.

While these price spike has lifted the quarterly average for the first 21 days of Q3 to $466/MWh in QLD and $418/MWh in NSW we are seeing this average drop each day.

The main driver for the lower spot prices is, as mentioned before, the improved availability across the NEM. Availability in QLD is regularly reaching 9,000MW compared to in June when it dropped 6,600MW. The short-term outlook for generation continues to improve daily with the majority of planned outages now completed.

A secondary driver that has pushed down average prices is the return of the sun. Solar generation is now regularly pushing the spot price below $100/MWh and on some occasions back into negative territory.

Less volatility in the spot market has been reflected in the forward market with Q422 QLD dropping from over $270/MWh in June to $260/MWh and the Q123 product dropping below $250/MWh.

Without delving into the gas supply concerns in Victoria, all other states have removed the price cap on gas allowing the market to operate more efficiently. This has not resulted in the gas market trading at significantly high prices as feared, Qld is $42.75/GJ, NSW is $51.51/GJ and SA at $45.51, translating into a sub $500/MWh peaking gas plant cost of generation.

As the weather warms up and the daylight hours increase, we expect to see a drop in demand, with heating loads reducing coupled with an increase in the generation provided by solar.

All of this, as well as increased thermal generator availability and stability in the gas markets, should see spot and forward prices continue to fall across the quarter.

Accessing the STTM: Alternative gas supply

Stacey Vacher, Managing Director
Nick Clark, Energy Analyst

For a growing number of large energy consumers, consideration is turning to whether entering standard vanilla retail gas agreements deliver the most effective outcome. For consumers who are located within the bounds of the Sydney, Brisbane or Adelaide Short Term Trading Market (STTM) markets, many may not be aware that there is an alternative way to purchase gas. Below, we consider how the STTM works and what the benefits are of exploring this option.


What is the STTM

The STTM is essentially a market for the trading of natural gas at a wholesale level at defined hubs between pipelines and distribution systems. The STTM is a day-ahead gas market operated by the Australian Energy Market Operator (AEMO) with hubs located in Sydney, Adelaide and Brisbane. This means that gas is traded a day ahead of the actual gas day. The market settles daily with “shippers” delivering gas and “users” consuming gas. An organisation may sell gas as a shipper and purchase gas as a user through the same STTM, however, it would do so at the daily market price.

Source: “Overview of the STTM for Natural Gas”, AEMO, page 1

Market participants are incentivised to ship and consume volumes of gas nominated through a pricing mechanism, which aims to keep the gas supply system balanced. Organisations are able to sell excess gas to its requirements on the open market the next day, as well as bid to purchase extra gas as and when required. This system allows participants more flexibility and choice in purchasing gas supplies. Furthermore, the STTM’s price transparency ensures that the price set by the market daily truly reflects the current supply and demand situation.

Each of the STTM hub settles independently of the other, however each hub operates under the same rules outlined by AEMO.

For further operational details of the STTM, AEMO has provided an “Overview of the STTM for Natural Gas” (Link:

Benefits of participating in the STTM

There are a range of drivers for some large gas consumers transitioning to purchasing and selling gas in the STTM. The main reasons are:

  • The STTM is an historically lower commodity cost;
  • Consumers can manage or avoid penalties under daily, monthly, and / or annual take or pay positions;
  • There is increased flexibility for both sellers and consumers; and
  • There are no long-term commitments.

These benefits can materially lower the cost of consuming gas. Depending on the nature of the organisation, there are a range of structures to access an STTM. Each structure requires varying levels of engagement from the consumer.

Engagement with Edge

To assist in transitioning your organisation to accessing the STTM, Edge are able to offer the following services:

  • Daily nominations and trading;
  • Monthly reconciliation;
  • Facilitation of short and long-term Gas Supply Agreements; and
  • Managing the STTM application.

Entering the STTM market is strategic decision for most organisations and can take anywhere between 3-12 months to transition. If you would like to know more, please contact us to understand if accessing the STTM market is the right decision for your organisation.

We note that there are also alternatives for consumers who are not within the STTM limits, however these options are not discussed for the purposes of this article. If you would like further information on your options, please contact your Manager Wholesale Clients or Edge on (07) 3905 9220.

The future is bright for Edge

By Stacey Vacher, Edge Managing Director

After celebrating ten years in business last year, 2018 has been a year of reflection. As founder and Managing Director, I especially have been reflecting heavily on why the business started, how it has become what it is today and, perhaps most importantly, where the business is headed.

One thing I’m very proud of is that the ethos of Edge has been unwavering since inception. Edge was established to deliver value.  At the core of every decision we make and everything we do is ensuring large energy users are equipped to achieve superior energy outcomes.  Put simply, we do everything possible to provide the tools and means to buy better.

They say you are only as good as your team. If I reflect on that, Edge’s performance is a reflection on the evolution of the team over the past ten years.  Attracting and retaining suitable staff is so important in any business.  In the energy industry, it is critical.  Knowledge, experience and industry-based networks add immense value to the capabilities of our team, and ultimately the outcomes for energy users that entrust us with their portfolios. As a relatively small player in an elite league, we punch above our weight to attract the talent that do justice to our ethos and the portfolios we manage. We do this through a client base that exceeds any other in the market, and by having established a reputation for the core values we adhere.  Integrity, honesty, trust, loyalty and respect are so much more than words in a policy document.  They are at the heart of everything we do.

The reason for this business is still as relevant as the day it was established.  We deliver value, and more than ever we love doing it. We’ve been successful in building a portfolio of top tier clients and establishing ourselves as a respected counterparty amongst the largest of players in our industry.  We work closely with the largest retailers, generators, and law firms across the market.  And we work directly for some of the largest and most trusted consulting names in the world.  Despite all of this, there is no denying that many consumers don’t even know our name. And we want this to change.

Edge’s services have reached under fifty of the largest names in our market, with approximately 7.5TWh currently under management and over 10TWh contracted in 2018.  Our gas portfolio is small in comparison. Looking forward, first and foremost we want to enhance the way we manage this portfolio.  Restructuring the team has been a major focus, with a move to offer each client an even deeper pool of skills and experience dedicated to their portfolio.  Portfolio Managers who were once tasked with delivering many aspects of a client’s requirements have recently been phased out of the business.  Replaced with more senior dedicated managers of wholesale clients for strategic management and dedicated account managers for more transactional services. Each Manager Wholesale Clients will ultimately ensure that their portfolio is being optimised.  They’ll be heavily supported by their dedicated Account Manager, our Markets and Advisory team, and our IT team through The Edge Energy Management System (TEEMS) and our customer facing portal (Edge LIVE).

We want to reach more portfolios, and exponentially increase the clients we represent.  We want all business energy users in Australia, not just the top tier, to know our name and the immense value our team will bring to their portfolio.  Commencing in early 2019 we will invest in dedicated sales personnel to market our services throughout the market.  A dedicated BDM will target consumers more suitable for Edge Energy Services’ portfolio, whilst a Channel Manager will be positioned to focus on stand-alone Edge LIVE (BI platform) and Edge Utilities (SME brokerage) services.

Briefly and in closing, our service offering has exploded in recent years, with the development of in-house spot forecasting models, brokerage services on environmental and renewable transactions, and specialist advisory services around FCAS, embedded generation, and generation revenue optimisation strategies. We look forward to outlining these further in the next edition of Edge Insights.

In the meantime, we warmly welcome all feedback on the recent changes to the team and ultimately the management of your portfolio.  This feedback is essential to us ensuring you are getting the value we constantly strive for.

Renewable Generation Off-Takers On The Rise

By Stacey Vacher, Edge Managing Director

We are seeing a significant increase in large users exploring renewable generation off-take opportunities. This includes behind the meter build-own-operate or power purchase agreements (PPAs), and offsite commercial arrangements otherwise referred to as corporate PPAs, synthetic PPAs, or simply contracts for difference (CFDs). The reasons are mixed. Some are looking to meet future corporate emissions targets.  Others are aiming to achieve lower energy costs. Some are looking to further diversify procurement strategies. All are fearful of missing out on the next big opportunity.

Edge are actively involved in taking large electricity users through the process of assessing, and where feasible, entering into arrangements with renewable generation. We provide a range of services covering everything from practical energy market expertise and advice through to strategy development and implementation and even transaction support. This is particularly helpful where the renewable generation forms part of a new or existing electricity sales agreement as negotiating terms can otherwise be difficult. Large mining, transport, agricultural and manufacturing clients are amongst those leading the way. Elsewhere in the market, we have all seen the announcements from users such as Sunmetals, Telstra, Onesteel, Sunshine Coast Council, Universities and smaller aggregated buying groups (to name a few).  The list is growing rapidly.

Looking beyond the consulting jargon, the diverging spectrum of price forecasting curves, and the race for the next Renew Economy or AFR headline, are these deals really the right thing for your business? Absolutely, they can be. But they may also not be. It is critical that you understand the current electricity market including renewable generation, and the potential financial benefits and costs these opportunities can bring to your business.  Edge can work with you to identify and understand these critical components to ensure you take the right direction when considering renewable generation in your portfolio. It is important to consider how adding renewable generation will affect your current position including your electricity contract.

You’re shown the aggregate market price of electricity and LGCs today and a comparable renewable generation blended off-take price.  Depending on the region and generation project, you’re looking at $130 to $150/MWh on the market against $60 to $70/MWh for renewable generation. The savings appear staggering. But some things may be too good to be true and the devil certainly is in the detail.


These opportunities are long term propositions, typically seven to twelve years though can be as long as twenty years or as short as three years. A lot can happen in this time and only one thing is for certain, things will change.  Supply and demand profiles will change. Project and market pricing will change.  Governments and their priorities and policies will change.  Depending on your corporation’s view on being quarantined (for better or worse) from these changes, you may lean towards all longer term, a blend of longer and shorter term, or no longer term contracting.

Project Risk

Renewable project developers are everywhere. Long haul business class cabins are filled with them. Virtual office spaces have never had it so good.  But not all have the experience in developing projects in Australia, therefore lacking experience with NEM based network service providers (NSPs), Australian government and council bodies, EPC contractors, and the like. Go to any NSP public forum and you’ll see first-hand the challenges that face NSPs around renewable project connections. Be it sheer volumes of enquiries, network or timing constraints, project risk is rife. An off-take start date can quite literally make the difference between a business case supporting the opportunity or not.  Partnering with a credible counterparty and / or managing project risk is critical.

Price Forecasting

The harsh reality is, we spent 2017 being privy to too much price forecasting that existed simply to suit the narrative. You can make generation opportunity in or out of the money with a suitable forecast curve.   Price forecasting plays a significant role in assessing the optimal renewable generation project and the potential value and risk that sits within in it.  Projecting future spot prices is a quantitative minefield. There are a few well known modelling tools utilised by equally well-known consultants to generate spot price forecasts in the NEM.  Edge also generates in house spot price forecasting. Whomever you utilise to produce future price curves, challenge the inputs and demand shape on the outputs. With significant volumes of renewable generation set to enter the NEM and aging fossil fuel plant preparing to exit, we are moving into a new dynamic in the NEM.  The characteristics of the supply curve are changing considerably. As storage technology advances, the behaviour of intermittent generation too will advance.  As users are forced to explore demand side management (DSM) opportunities, the demand profile will also change.  Five-minute trading intervals will change supply and demand behaviour. To adequately assess any renewable generation or off-take opportunity it’s about the expected spot outcome and the sensitivity around this result, measured in each trading interval. Having a high and low case based around randomly selected forced outages doesn’t even begin to address the uncertainty in the electricity market. Even if a project is priced firm to a flat mega-watt (MW) profile, understanding the potential impact to the shape the merits of the firm pricing against other procurement strategies.

Regulatory Risk

Either we are getting older and more in tune with the volatile nature of politics, or politics has taken regulatory racket ball to the whole next level. Investment in new generation in the NEM has previously stalled due to policy uncertainty.  The more recent run of high electricity prices is testament to this. Just when the market does what markets are supposed to do and responds to price drivers with new entrants and technological advancements, our policy makers inject more uncertainty in the form of a National Energy Guarantee (NEG). The end game of the NEG is noble. To promote that we meet our international emissions commitments, whilst ensuring our electricity is reliable, secure, and of course affordable.  Achieving this whilst not forcing any politician to back down from previously stated principals. The practical application of the proposed design however is a very long way from readiness, and in its current form is alarmingly at risk of causing segregation and market power that can only result in higher energy prices.  Meanwhile the Government has cast a dark cloud over the application of the Renewable Energy Act, and specifically the ability for renewable energy projects to receive certificates if they are commissioned after the target date of 2020.  It’s a risk that not even all the developers are aware of.  As an off-taker you must make it your priority to be across it and manage it.

Shape Risk and Firming

Renewable generation is intermittent.  The question remains; what happens when the sun isn’t shining, or the wind isn’t blowing?  Storage solutions are on the rise, but the dispatch limitations and costs still make it very challenging to get the business case across the line.  Clients who are looking to integrate renewable generation in their portfolio must be aware of the risks associated with shape risk.  This includes managing their shape with the overall shape of their hedge portfolio (tenure, type, etc.) and spot risk.  How can one best introduce intermittent generation (or intermittent offtake) into a portfolio, and what is the most efficient and effective means to manage this risk.  Firming products are one of the most sought-after products in the NEM today. Physical solutions have their role in mitigating some shape risk and include DSM, onsite generation, and storage solutions. Financial solutions also stand to play a significant role, including both traditional electricity derivatives and weather derivatives.  Securing firming products is undeniably challenging.  Hydro and gas generators have five-minute settlement to consider.  Furthermore, gas generators need to clear long-term fuel supply hurdles.  Coal generators may not be so eager to firm a product that will ultimately stand as the perfect competitor to their own offtake. Edge work closely with clients to understand shape risk and firming solutions.  We actively engage with the wholesale market to seek and deliver solutions that work best for each individual client.


Settlement of third party PPAs need not be complicated.  In fact, it need not be independent of your electricity invoices.  Edge has negotiated PPAs that settle directly between the project and off-taker. We have also negotiated settlement services with retailers to ensure consumers benefit from longer term renewable generation whilst still only receiving monthly invoices form their retailers.  Understanding the cash flow implications and adequately addressing credit counterparty risk is all critical but certainly manageable.


There are accounting implications as to how these arrangements are structured.  Whilst we are across these due to our involvement in large offtake deals, we are not an accounting firm.  We would strongly recommend that any consumer exploring these opportunities ensures their accounting advisors are across implications such as implied lease agreements, impacts to the balance sheet, and / or derivative accounting.

Whatever stage your organisation is at in considering Renewable Energy as a part of your electricity portfolio, Edge can help. If you would like to learn more about Edge, please visit or alternatively you can call one of our team directly on 07 3905 9220 or on 1800 EDGE ENERGY.

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


If you need to buy or sell LGCs and need advice on timing to market, please contact us here or on 07 3232 1115.