Save money on business energy bills

Power Portfolio

Edge Utilities launch the Edge Utilities Power Portfolio to help businesses save on energy costs

With energy prices at an all-time high, the team at Edge Utilities are using the power of bulk purchasing to help Australian businesses of all sizes save on energy bills. We’ve developed the Edge Utilities Power Portfolio (EUPP) to give every Australian business access to the SAME savings as large energy users and shield them from rising energy prices.

Shield your business from rising energy costs:

By taking multiple energy users to market as one larger group, we can access bulk purchasing prices, saving on what you are currently paying for your energy. Joining the Edge Utilities Power Portfolio (EUPP) means you can access these savings AND have your energy portfolio managed by one of Australia’s leading energy management teams.

We do the hard work for you.

Through the EUPP you are joining a large power portfolios to which we apply portfolio optimisation analytics. You will be taking advantage of procurement strategies usually only available to really large users. We negotiate terms that you could never achieve on your own. With the right portfolio, we can even support your transition to renewable energy with minimal impact on your energy rates.

Who is Edge Utilities?

Under our parent company, Edge 2020, we have provided energy broker services for over 14 years, working with Australia’s largest energy users, including BHP, Glencore and SBS.

From the moment you join the EUPP, our energy team works for you. The sooner we start, the sooner you save. 

As a launch special, Edge Utilities is waiving the sign-up fee to join the EUPP. Even more savings for you.
For more information on the Edge Utilities Power Portfolio, visit: 

Let’s talk Energy Markets


In the past 2 years, the market has dropped from highs of over $75/MWh in August 2019 then following the events outlined on the chart below the market price dropped to historic lows of around $36/MWh. Following some volatility at the start of 2021 driven by a hot summer, the market firmed and increased further because of the catastrophic failure of Callide C4 and the tripping of many other power stations.

The chart below shows that the underlying spot price (light blue line) has continued to spike and trend up resulting in increases in the contract prices. Another interesting aspect of price curves is how market announcements such as the cost of coal and gas can impact the curve. In months, the curve softened but spiked due to conflicts in Ukraine causing coal and gas, a key input to thermal generation, to increase in price.

The spot price of these commodities is not directly linked to the fuel price used by generators in the next quarter, so the market has now softened.

Future years are also becoming cheaper year on year as renewable energy takes a larger share of the market and renewable energy is expected to continue to fall in price.

Having recently undertaken a few requests for proposals (RFP) for our clients, we are aware there is good value for companies willing to take up longer term renewable PPAs. More and more projects are becoming available post 2023/24.

Undertaking a renewable PPA will go towards meeting many companies’ sustainability targets through the procurement of renewable energy and environmental certificates.

Below are the contact details for Alex. He would be happy to discuss your company’s sustainability targets and how we can help the business reach them.

Alex Driscoll

Senior Manager Markets, Trading & Advisory

M: 0437 966 409

P: (07) 3905 9226

T: 1800 334 336



The Australian Energy Market Commission (AEMC) has released its annual residential electricity price trends report. The report provides governments and consumers with an understanding of the cost components across the electricity supply chain and provides transparency into the final price by consumers. It also provides a forecast of the costs for the next 3 years.

In the 12th version of the report, the AEMC found there is a general trend of residential bill reductions. Queensland is expected to see the largest drops, with a projected drop of 10% while the only region to increase is the ACT with an increase of 4%.

The 10% savings for Queenslanders are expected to translate on average to a savings of $126 which will see electricity bills the lowest since 2010/11.

The key drivers in an electricity bill are the wholesale, environmental and network costs. Wholesale costs are likely to fall by $36 over the 3 years, environmental costs will also drop by around $35 due to the increased reliance on renewable generation however the network costs are likely to increase by 3.4% or $21 over the 3 years due to the increased investment in the transmission and distribution networks.

AEMC Chair Anna Collyer said, “the report shows that, based on current trends, prices per kilowatt hour are likely to be under 26c p/kWh by June 2024, the first time since 2016/17”.

The report gives enough visibility into the future that claims that the cost of power delivered to consumers will drop and continue to trend down despite the closure of large thermal power stations.

Even though wholesale and environmental costs are trending down the cost of network investments will transfer into higher network costs as investments are made into the network to strengthen the grid and allow for the two way connection of distributed generation.

An interesting comment from the AEMC is that environmental costs are expected to drop by $16 out to FY23/24 due to a decrease in large-scale renewable energy costs. We are seeing a trend in the short term of environmental costs increasing due to delays in the construction and commissioning of new generators. We are also seeing an increase in the cost of LGC’s as more companies choose to buy extra certificates for voluntary surrender.

The head of the AEMC also said “While we have just under 2,500MW of generation expected to exit the grid over the next three years, there are almost 5,500MW of committed new large-scale generation and storage projects coming online over the same time period,”

With the addition of a further 4,130 MW of new rooftop PV capacity, this is likely to push prices down however until the network is reinforced it may have the opposite effect.

Edge has reported over the last couple of years that the cause of some of the market volatility has been because of the unconstrained rooftop PV lowering the operational consumption and disporting the scheduling of generation throughout the NEM.

The next 3 years may be the most crucial in the transition of the NEM from thermal generation to renewables and the investments in getting the network in place will be passed on to end users.

The question is, do consumers want the cheapest power in the short term or is a grid designed to provide the cheapest energy for the long term, the answer?

Article written by

Alex Driscoll

Senior Manager Markets, Trading & Advisory


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

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

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

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

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

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

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

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

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

Written by Alex Driscoll Senior Manager Markets, Trading & Advisory

Hydrogen Guarantee of Origin Scheme

Everyone wants a piece of the Hydrogen pie, and the Australian government is no exception. With the predicted demand forecasted to be 50 million tons by 2025 for industry and transport alone, and a conservative growth of 3.5% per year expected following this it isn’t surprising everyone wants to be first out to the Hydrogen blocks.

No sooner had the Department of Industry, Science, Energy and Resources (DISER) released its discussion paper and questionnaire to set up a Renewable Guarantee of Origin (GO) scheme for the Hydrogen industry (and post RET electricity sector) than the Queensland Minister for Energy, Renewables and Hydrogen, Mick de Brenni, went to the Smart Energy Summit and announced the Queensland Government was partnering with the Smart Energy Council to create a zero-carbon certification scheme to create certificates for renewable hydrogen, ammonia and metals produced in the state.

But the big question which needs to be looked at is “are all GO certificate’s equal?” This is going to be key to the salability and international credentials which will be imperative to the confidence given to our hydrogen on the international stage.

The most defined scheme by far is the European CertifHy scheme which has set some stringent definitions that Australia seems to be trying to find some wiggle room within! The CertifHy scheme was founded in 2014 and sets strong guidelines (backed by the European Union Renewable Energy Directives (RED I and RED II) policies, setting out minimum thresholds of the emissions intensity of hydrogen that can be certified under the scheme.

Australia will need to match these emission intensity thresholds or down the track when our “green” hydrogen isn’t accepted worldwide we will suffer the consequence. Within both proposals (DISER and the Smart Energy Council) they are supportive of using the scheme using the governments Climate Active certification. This seems sensible until you investigate their requirements for “net-zero emissions.” The issue arises in that the status can be reached by emissions can be offset by purchasing carbon credits, these don’t have to be Australian (Australian Carbon Credit Unit’s ACCU’s), but the status can be achieved with international private certification schemes which may not hold up to the stringent regulation of state-run schemes.

CertifHy has only 2 definitions of Green Hydrogen. Green Hydrogen is Hydrogen generated by renewable energy with carbon emissions 60% below the benchmark emissions intensity threshold set by Natural Gas. The second is Low Carbon Hydrogen which is created by energy, not from a renewable energy source but still means the same emissions benchmark of 60% below GHG emissions of natural gas. All other forms are known as Grey Hydrogen.

If this is seen to be the international standard Australia cannot deviate from this. With major stakeholders in the design of the CertifHy scheme from Japan, the USA, Canada, and South Korea the creation of a harmonized GO across Europe and beyond the market for certified GO Hydrogen will have its base standard set. Being accepted on a national scheme will not be an issue if it corresponds with the international standard, but this is one corner the Australian Government must be careful not to cut in its green ambition.


Since the release of the latest Electricity Statement of Opportunities (ESOO), Edge has updated its energy price forecast and the energy landscape is looking difficult for the remaining baseload coal generators. Most of the coal-fired generators remain in vertically integrated portfolios which used to use the cheap coal generation to subsidise the more expensive gas and renewable generation. With the increased penetration of renewables, the cost for these assets has reduced and become a burden on the portfolio. With the cost to maintain the thermal units to meet reliability standards and generating less, the cost per MWh is increasing.

The change in the market is reducing the value of what non-renewable generation has on portfolios. Companies with large coal exposures have written down their coal assets and needed to change their business model to survive.

Renewables are pushing out coal-fired power stations and putting increased pressure on the gas-fired generators. Over the last decade, renewable energy has been gaining market share and with reducing installation costs, the share of the market has increased over the last 5 years. In the last 2 years, renewables have generated more electricity than brown coal following the closure of Northern Power Station in South Australia and Hazelwood in Victoria.

Black Coal Power Stations are next to be impacted by renewables. Although until recently the biggest threat has been for Solar during daylight hours, which still allows the thermal generators to make their required returns outside solar hours. This equation is changing with the increased penetration of batteries that will increasingly allow solar generation to be time-shifted into non-daylight hours and hence reducing the number of hours thermal generation can control spot prices.

With Solar, we are seeing a marginal cost of generation of $0/MWh so these power stations bid into the market at $0/MWh which pushes more expensive generation further up the bid stack. When negative spot prices occur, increasingly we are seeing large scale solar generation curtailing their generation to reduce their exposure to negative prices. Due to the nature of Solar generation which can increase or decrease their generation very quickly, this practice is causing issues for the market operator.

The energy market is cyclic, we have seen high prices which lead to investment in generation followed by low prices as demand grows to meet the extra generation. Between 2017 and 2020 we had record-high prices across the NEM following the closure of Hazelwood. We are now experiencing record low prices because of the influx of cheap renewable generation. These low prices are putting pressure on the financial modelling of future renewables, which has the potential to impact the supply and demand balance in the future once the aging coal-fired fleet retires.

Capacity factor, the ratio of actual electricity output to the maximum electricity production from that specific asset, is falling for all coal-fired generators. The next coal-fired power station to close has dropped in capacity to 42% and other aging power stations have also dropped well below 70%.

The first state to have no coal-fired generation is South Australia and this state has been working through the challenges of a market filled with intermittent generation. The market operator has worked to resolve the technical issues arising from high penetration of intermittent generation, these solutions are starting to be used across the NEM.

South Australia at this moment in time is where we will see the other states in future years. System stability is becoming the issue and finding solutions to provide inertia which is key to system stability.

Another issue for the market is when the intermittent generation does not generate the demand that needs to be met for more expensive dispatchable generation such as fast responding gas turbines.

The problem for the market is not the increased penetration of renewable energy or system security, it is who and what fill the supply gap once intermittent generation is taken out of the equation. At times this residual amount can be very high.

The reserve can be filled by coal or gas, but the baseload units are not designed to only operate on the part of the days when they are required. Currently, these units stay online 24hrs per day. The only option they have is to reduce their output to minimum load to reduce output and potential losses resulting from very low prices.

As the coal plants become older and less reliable the service, they provide becomes less dependable, so more reliable solutions such as gas-fired generation or batteries once they become commercially viable are the solution. This leaves coal-fired generators in a market that they can’t sustain their required returns and can’t provide the service with the market needs due to their lack of flexibility.

As the growth in renewable increases, coal will be pushed out as the financial pressure on the generators and retailers increases. Retailers will renew their fleet of assets to meet the future need of their business and reducing maintenance costs and reducing emission liabilities will be the key driver to retiring the coal fleet. Coal-fired power stations are struggling to make the required returns now with most stations unable to remain viable after 2030 if the current price trend continues.

The government may have thrown the coal-fired generators a lifeline with the Energy Security Board (ESB) capacity market post-2025, where generators will be paid to remain available to provide inertia and other system security services. The issue with the lifeline is in the future. There will be other technologies that will be able to provide these services at low prices, making coal-fired generators obsolete.


We all agree having a safe, reliable, and secure National Electricity Market (NEM) is the key deliverable for AEMO. AEMO have flagged that there is a shortfall in the participants able to provide key services to keep the grid stable as the generation mix changes and they are running out of tools to keep the grid stable.

The biggest issue for AEMO and market participants is as synchronous generators such as thermal power stations reduce availability and eventually retire the much-needed system security services such as inertia and voltage control that they provide, drops.

As a result of AEMOs concerns, the Australian Energy Market Commission (AEMC) has developed ways of valuing the much-needed services.

The AEMC has just released a directions paper outlining mechanisms that could provide the system security services to the NEM. The AEMC has also highlighted support for innovative technologies to provide these services.

At this moment in time, AEMO has limited tools to improve system security at times of scarcity apart from using its intervention powers to direct generators online to provide the services. The problem with using its direction powers is that additional costs associated with the directions are passed onto end users and as a result this does not meet the requirement of the National Electricity Objective (NEO) of providing the lowest cost solution and it also distorts the market.

AEMC’s directions paper covers two rule changes proposed by Delta Electricity and Hydro Tasmania. The Delta proposal is to introduce a capacity commitment mechanism to provide system security and reliability services. In Hydro Tasmania’s request they propose to create a market for inertia, voltage control and system strength products.

Both these rule changes will form part of the Energy Security Boards (ESB) ‘post 2025’ market design. AEMO is also working with participants to develop the engineering to meet these challenges. These challenges include a changing market due to an increased reliance on weather dependent generation such as solar and wind and new technologies such as batteries.

The options in the directions paper are about providing a transitional approach as we move to a different generation mix while keeping the cost of the solutions to a minimum over the long-term. Solutions may include a similar process to direction but increasing the transparency of what assets should be online to maintain system security while keeping the costs down. Some of the options available to AEMO could be scheduling assets to provide specific services like voltage control while other would be scheduled for inertia. These arrangements would likely transform into stand-alone services similar to the current FCAS services.

The market is changing at a rapid pace and these extra tools in AEMO’s toolbox should allow the NEM to operate safely and securely for many years into the future.


With the release of the latest Electricity Statement of Opportunities (ESOO) some of the assumptions used in it have raised concerns of the viability of Snowy 2.0 and the impact it will have on security of supply for the market. Snowy 2.0 had been given the green light under AEMO assumptions even though the project would not have hit the hurdle rate AEMO uses for all other projects.  The second concerning point is when you build one of the largest generation assets in the country it is crucial that it is linked to the market via appropriate transmission lines. Information from transmission line providers suggests the full capacity of the powerlines will not be in place when Snowy 2.0 comes online. Our third concern is the cost of the new transmission line projects are rapidly rising. These costs will go directly to the end user.

Transmission provider TransGrid outlines information on HumeLink, the transmission line earmarked to connect Snowy 2.0 to the NEM. TransGrid estimates HumeLink costs have increased from $1.3B in the draft assessment to $3.3B. The more worrying statement is TransGrid saying the final cost could be up 50% or more.

Apart from HumeLink, to be full unconstrained, Snowy 2.0 will need the Victoria to NSW interconnector West (VNI West) transmission to be built. HumeLink is labelled the largest transmission project in history, VNI will be a similar size and most likely a similar price however costing have not been released.

The cost of these two transmission lines will eventually be passed down to end users via increases in transmission tariffs. Modelling has indicated that the $3.3B for HumeLink will add 40% to NSW costs. While these costs are met by all end users, large users will be impacted the most as these fees are paid for on a proportional basis.

Latest costing suggests HumeLink, VNI West and Snowy 2.0 has the potential to cost $12 billion. This will make Snowy 2.0 the most expensive generation and transmission project in history.

The question is, with far cheaper renewable projects that do not require 2 huge transmission lines to make them effective for system security, are there better options the federal government and the consumers of NSW could be spending their money on.


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

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

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

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

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

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


On Thursday last week, Australia’s largest energy company released its annual report. The 192-page document contains a lot of information but not a lot of good news for investors. One of the sections is titled “a year of continued evolution”, first there was the planned demerger, then the exit of its CEO following the demerger announcement, now to cap it off the news of on-going challenging market and operating conditions due to declining wholesale electricity prices.

The FY21 financial results demonstrate the huge reliance AGL has on the wholesale electricity market with profits dropping 33.5% to $537M. These results have not been favourable for investors with dividends also down to $0.75 per share.

Revenue from consumer customers increased 1.1% thanks to an increase in customer numbers but large business customers revenue fell by 12.4% because of COVID related consumption drops and finally there was a drop of 4.6% for wholesale customer revenue driven by lower volumes and lower prices.

With the restructure of the business, AGL is looking to lead into a new future. Part of the new future is the decarbonising of the business and the move towards renewables.

AGL Energy CEO has called for a national plan to phase out coal fired generation to protect consumers and jobs if the energy transition falls into chaos.

The concern for the industry is that events like the Callide C4 turbine failure or the flooding of the Yallourn mine could trigger price shocks and blackouts. Other concerns include the increased penetration of cheap renewable energy and batteries that will make coal fired generation uneconomic, leading to early retirement.

AGLs idea has been endorsed by the majority of companies with coal fired generation assets. The Energy Security Board (ESB) has also flagged a scheme may be required to enable the orderly retirement of assets while keeping the grid stable.

AGLs CEO said “a plan is needed that goes beyond the reforms proposed for the National Electricity Market to give certainty to industry, investors, consumers and others about the pathway towards the eventual shutdown of plants”. This is something that would work in Queensland that has historically been reluctant to announce the early retirement of power station following the impact on regional jobs.

Alinta’s CEO has supported the AGL idea. Alinta operates Loy Yang power station which supplies a large quantity of baseload electricity in Victoria.

Origin’s CEO also supports the plan, saying they want to avoid a messy transition to low carbon energy.

We all agree a transition plan to reach renewable energy and emission targets is useful for owners and operators of coal fired generation to manage the life of their plant, but we must remember the owners of these assets are ultimately responsible for the utilisation of their assets. If they are under financial pressure and the units are becoming uneconomic, they can notify the market and retire the units or simply mothball the units.

Apart from sudden shocks to the market like what occurred following the Callide failure, other units in the generation mix pick up the difference very quickly. If the market is working correctly, the lowest cost solution is always found.

The Energy Security Board is working on plan to transition to a low carbon market to alleviate the concerns of generators with other enhancements including a two-way market to benefit consumers.

It is understood the ESB is developing a strategic reserve mechanism for generators to ensure adequate supply and certainty of available capacity. This mechanism will include capacity payments for dispatchable generation to supply the much need system security service they provide rather than just the electricity they generate.

With increased pressure on the federal government to reduce emissions to meet net zero by 2050, coal will need to make room for renewable energy. The question is, should coal generation be pushed out based on economics or should the industry and ultimately end users’ subsidies the coal generators to keep the lights.