Is unaccounted for energy (UFE) allocation affecting my company’s bottom line?

Energy meter costs

I find myself asking, is UFE the UIG of Australia? Anyone who knew me in my past life in the UK knows that I harped on about Unidentified Gas (UIG) A LOT!

The idea behind the UK’s UIG is simple, it is to allocate the gas which couldn’t be attributed to a meter in an area, across all end users in that area in which it was used (known as “off-taken”). Seems simple right. But when was the last time you actually gave a meter reading? Possibly six months to a year ago, right? Well that means your off-take (unless you are on a smart meter) is estimated and you will be either over or under on allocated unidentified gas.

Now although this seems sensible with everyone eventually giving a meter read and therefore it will all work out in the wash,  the issue is currently exacerbated by the extreme increase in the gas price. These high prices are now passed through to retailers and then in turn our bills.

Now what does understating this UK gas usage or allocation have to do with Australia? Well, quite a lot. The system is similar, but not the same.

Following Global Settlements being introduced by AEMO we have started seeing Australia’s version of these charges coming into our bills. We allocate the unidentified – called Unaccounted for Energy (UFE) within each region by the off-takers in that area.

What we are not doing yet, which in the UK’s defense they do there (through XOServe), is take into account those meters which are half hourly ready (smart(er) meters) and therefore their usage should be known. Currently in Australia, the offtake in a region will be directly linked to your proportion of energy being allocated to you and you literally have no say in these charges, despite having updated metering capability.

The sore point of it all is, that this is occurring at a time where our electricity market is extremely high and therefore there is a possibility of the combination of large UFEs at high prices being passed through to end users, whilst having no control over the volume or price it is passed through at. This is leading to significant shocks to companies’ outgoings, as there is little to no visibility on the charge on any given month, and no way to forecast them for a company’s budget.

I fear that UFE will become my new soap box issue, but I can guarantee this isn’t the last anyone will hear on this. I am pretty sure I won’t be the only one who will be making noise.

Is this happening to you? If you feel you need more control of your company’s energy spend, please reach out to discuss joining our Edge Utilities Power Portfolio (EUPP) where we use the power of bulk purchasing to help Australian businesses of all sizes save on their energy bills. Read more: or call us on: 1800 334 336 to discuss.  


Andrew Forrest is one step closer to building a hydrogen fuelled power plant in NSW with the project being declared as a critical state significant infrastructure (CSSI) project. The CSSI status granted by the NSW Department of Planning, Industry and Environment show the $1.3B project has government support.

The duel fuelled 635MW power station is also hoping for support through the federal government’s Underwriting New Generation Investments scheme but at this stage no funding has been released to any project. The power plant forms just one part of Andrew Forrest’s plans for Port Kembla with his company Squadron Energy also developing the LNG import terminal.

The duel fuelled power station is designed to run on 50% green hydrogen but is likely to utilise the LNG available close by.

The Port Kembla power station is aiming for financial close by August 2022 and operational by Q125.

NSW Deputy Premier John Barilaro said the move to grant the project “critical state significant infrastructure” was driven by its “game changer” status in terms of supporting new renewable energy in NSW as coal power plants close.

The timing of this announcement is also good news for renewable energy project developers who have recently been invited to an expression of interest for the New England Renewable Energy Zone (REZ). The synchronous power station will not only provide an opportunity to burn clean green hydrogen but also provide much needed system strength services such as inertia.

The government has received 34GW of renewable energy interest which is 4 times the proposed capacity of the REZ. This has raised concerns from communities that fear over development of the area.

Matt Macarthur Onslow, from the Responsible Energy Development for New England, said the major expansion envisaged lacked “social licence”, and major divisions within local communities regarding renewables and concerns that they feel are being overlooked.


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More bad news for electricity retailers with Origin Energy announcing an impairment of $1.6B after further writing down the value of its generation assets and reducing the value of its renewable energy contracts.

In a statement, Origin said the write downs were a result of falling wholesale prices, mostly driven by the influx of new wind and solar projects. High gas prices also reduced the returns from their fleet of gas-powered generation.

Origin owns the largest coal fired generation unit in the NEM, so the market pressures weighed heavily on the balance sheet. Origins large exposure to the non-renewable segment of the market through its Eraring coal fired power station which resulted in a $583M post-tax impairment. This comes because of Origin’s assumption of a lower outlook for wholesale electricity prices driven by new supply expected to come online, including both renewable and dispatchable capacity, impacting the valuation of the generation fleet, particularly Eraring Power Station.

Eraring is expected to be the cause of much of the impairment, but the gas-powered generation (GPG) units did not fair much better. The GPG were affected due to the increased cost of gas and the decrease in the spot and contract electricity market price.

Strategically Origin has chosen to source renewable energy through PPA rather than build physical generation so are not exposed to the physical renewable market. Origin was an early mover in the renewable PPA space so the PPA’s on their books are very expensive compared to what the market offers are today. This has resulted in Origin writing down some of the value of these existing PPAs.

Origin says it will write down $995M in value of goodwill for these renewable PPA’s and the gas contracts that are out of the money. Origin expects the spot market price to be up to $20/MWh below where they previously anticipated the price to be.

Origin expect their FY2022 profits to be lower than expected at $450- 600M which will again be largely supported by the LNG export part of the business.

On a positive front, Origin expects the market to recover in FY2023 where earnings are expected to increase by $150-250M on the back of a material rebound in energy market earnings.


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

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

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

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

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

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

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

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

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

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

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

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


In this issue we look at the following;

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

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


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

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

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

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

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

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

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

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


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

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

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

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

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

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


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

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

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

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

commence construction in 2024.

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

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

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

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

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

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


A constraint designed to maintain power flow in the Gladstone region, primarily to maintain the continuous current rating on the 132kV feeder bushing at Boyne Smelter, is constraining off hundreds of MWs in Queensland.

Constraints on the interconnectors out of Queensland are also limiting QLD generation. A constraint to avoid voltage instability on the Sapphire to Armidale 330kV transmission line is reducing NSW generation.

Constrained gas supply is also impacting spot prices. BHP’s Gippsland Basin joint venture with Exxon in Victoria, is not operating at full capacity due to a processing train at the Longford plant out of service since 28th June. This was due to an unplanned maintenance issue.

The unplanned issue at Longford has also reduced the output from the Bass strait gas fields that feeds the plant. The Iona gas storage facility operated by Lochard Energy is also running low.

The reduced level of generation from coal fired generation, resulting from the loss of Callide power station, the delayed return of Callide C3, and the reduced output of Yallourn in Victoria due to flooding have all added to the extra requirement for gas powered generation in QLD and VIC.

The requirement for extra gas-powered generation has led to higher prices in the gas market, which in turn leads to higher dispatch prices of the gas-powered generation. Higher dispatch prices lead to higher spot prices.

Domestic pressures on gas prices on the Australian wholesale market have been impacted by the overseas gas market demand and prices. As the Australian gas market is export dominated, any changes to overseas prices are reflected domestically. The benchmark Japan Korea Marker (JKM) is linked to the LNG netback price.

The JKM is also used as a floor for gas contracts in Australia and with the JKM lifting to $19/GJ this reflects in Australia. Today the Declared Wholesale Gas Market (DWGM) prices in Victoria is $58.44/GJ with a demand of 1,100TJ.

The futures market has responded to this week’s higher spot prices, along with the announcement that Callide C4’s return to service would be delayed until the end of 2022. The unit was planned to be in service by the end of 2021 and capable of supplying power over the 2021 summer however, the delay has pushed up the Q122 quarter prices as well as most of the quarters until 2023.