Boardroom Energy
Bulletin

This week

In case you needed confirmation of how messed up energy markets are today, public companies are being pressured to sell coal and gas assets while demand for these resources (and their prices) are skyrocketing. The Wall Street Journal notes demand and prices for thermal coal are rebounding strongly in post-COVID Europe, China and the US, with coal prices reaching $130 per tonne, the highest they’ve been in  a decade. Surging gas demand in Asia is pushing LNG exports to new highs prompting Chevron, Exxon and Shell to pump another $6 billion into the Gorgon gas project. The International Energy Agency warns that this resurgent demand will blow any chance of making next zero emissions targets by mid-century, but are sheepish on how we convert hydrogen media releases into utility scale zero emission alternatives.

This moral hand wringing is just transferring highly profitable carbon intense assets from public to private equity ownership. Meanwhile foreign investors are threatening to blacklist investment in Australian publicly listed companies because the national government won’t commit to net zero by 2050. So that just made private equity ownership a bit more lucrative.

The wrecked unit at Queensland’s Callide B power station wont be back on line until next year, with other generators trying to suggest the prolonged outage of this single unit alone is responsible for sharp increases in wholesale prices.

In Victoria Yallourn is back online but the cracking of the levees holding back the Morwell river from flooding the open cut brown coal mine remain worryingly large. EnergyAustralia think it will cost tens of million to repair. Who will pay for it? Maybe the Andrews Government, as we discuss in more detail in this week’s bl0g.

Three of the gang of four wind farms being blamed for the system black in South Australia in 2016 have been found guilty of not having the correct ride through settings, and have been fined in the Federal Court. AGL is the last remaining wind farm operator to face the music in August. It is adamant it followed the rules.

Speaking of AGL, only a month after the EnergyConnect transmission line was approved, they announced they will close a unit of Torrens Island B power station in Adelaide . Expect more to follow.

Transgrid’s commercial wing Lumea is making promises they probably can’t keep, claiming they can build a 300MW battery in Victoria without Government assistance. Go on then. Stop talking about it and do it. We dare you.

Twiggy watch: this week Andrew “Twiggy” Forrest announced he would donate $66 million to Bill Gates’ climate venture capital fund.

 

Has EnergyConnect claimed its first victim?

The new transmission line between South Australia and NSW may have claimed its first victim, with AGL announcing one of the four gas fired units at its Torrens Island B power station will be mothballed.

Five weeks after the $2.3 billion transmission line was approved, the impact on the viability of South Australian generators has already begun. AGL hasn’t set a date on when the unit will go offline which suggests it’s unlikely to be this year. They may wait until they can see when the transmission line becomes operational.

The promises of large energy bill savings to customers in SA and NSW was predicated on all existing generators remaining in the market. Which was courageous.

The reality is that once the interconnector is built, it will enable lower cost generation from NSW to sell into South Australia’s volatile high renewables market. This is great for reliability, but will cut the margins and viability of South Australian gas generators who rely on these intermittent periods of high prices to remain in business.

The AGL decision may be a portent of more closures to come. This risk of extensive SA-based gas fired generator closures was first identified in February 2019, in the independent external review of the modelling run by SA transmission business ElectraNet by economists Oakley Greenwood.

Oakley Greenwood observed in its review that discussion of the fate of SA generators was beyond the scope of its technical review. But should it have been? Oakley Greenwood suggested reliability analysis should include “if all major gas plant withdraws to be replaced by new large interconnectors”.

AEMO’s 2018 Integrated System Plan’s central scenario forecast that all major SA gas plant would close after the interconnector was commissioned, but would be replaced by pumped hydro in SA. The pumped hydro projects have instead been abandoned.

Torrens Island B is expected to close permanently in 2026, so it will only be a few years ahead of schedule. Under ElectraNet’s modelling for the transmission line the other two gas generators at Pelican Point and Osborne have to be subsidised to remain in service to 2033.

That’s a whole lot of reliability uncertainty and generator exit which wasn’t mentioned in the media releases or the regulator’s assessments. It would consign South Australia to being no longer energy independent, but reliant on importing most of its firm generation from Victoria and NSW. This assumes these states have spare capacity at the times when they are needed.

If this does end up becoming a generator car crash, state and federal governments will be forced to just continue their ongoing program of interventions and financial aid. Propping up old generators while sheepishly reporting energy transformation.

A battery without government backing? tell em they’re dreaming

Transmission company TransGrid has a commercial, non-regulated subsidiary called Lumea that thinks it can build a giant 300MW battery in Victoria without any government assistance. As Darryl Kerrigan would say, “tell them they’re dreaming”.

A growing part of the problem is chronic government intervention in the grid. As governments suppress wholesale electricity prices and do everything they can to reduce volatility and uncertainty, they make it harder for batteries to earn a living. Which results in governments then having to underwrite the batteries as well.

The big loser here is taxpayers, who pay for the cost of the government interventions and then pay again for the subsidies for the new technologies. These costs are not visible in the electricity price, they just get added to the government credit card bill which grows larger every day.

There is currently a queue of around 41 large scale batteries proposed in Australia, all waiting for government funding to reach commercial closure. The scale of ambition over delivery suggests there is a fundamental problem in trying to get a large number of large-scale batteries to make money. Or, in more simple terms, the cost of the battery is higher than the value of the electricity.

Batteries can make money from two basic sources: they can sell ancillary services to the grid like regulating frequency, which has been their bread and butter to date, earning 83 per cent of their total revenue in the first quarter of 2021.

Selling FCAS has been a crucial earner for the first utility batteries like the heavily subsidised Hornsdale Power Reserve. Batteries are ideally suited for this role, they respond quickly and are generally able to inject power into the system as soon as it is needed. They can also make millions from it under critical conditions, like when South Australia was islanded for 18 days at the start of 2020.

The problem battery investors face is that they are making less revenue, not more. The FCAS market is finite and the spread on offer from arbitraging electricity – buying low and selling high – is falling as electricity prices are falling. The more governments subsidise over capacity and low wholesale prices, the harder they make it for battery investors.

We can see this from the simple maths put on the table by Lumea. They are proposing to build a 300MW/580MWh battery located in Victoria at an up front cost of around $300 million.

The number of cycles a battery can run depends on the depth of discharge – the more power you load and unload each time, the fewer cycles you can get out of it. As a rough guide a utility scale battery can cycle around 3000 times over a decade if it’s not pushed too far.

Holding aside cost of land and capital, connection fees and operational costs and assuming 100 per cent efficiency, how much average “spread” do you need just to recover the $300 million capex spend on a 300MW/580MWh battery?

If we assume a dispatch depth of 50 per cent, then the maths is:

$300 million (cost of the battery) divided by [580 (number of MWh in the battery) x 0.5 (50 per cent dispatch depth) x 3000 (number of discharges)]

This equals a $344 per MWh spread that is needed. So that means you need to buy each electron around $350 cheaper than the price you sell it. Or you need to find another valuable revenue stream from somewhere.

Looking at the month of June, the spreads were higher at the start of the month because of the knock-on price effect of the closure of the Callide C power station in Queensland. Daily price spreads of around $200 per MWh were possible then, if the battery could charge and discharge with the benefit of perfect hindsight, which is doubtful.

Later in the month even after the scare around the Yallourn Power station, prices calmed down with spreads of around $100 per MWh available, assuming optimal battery operation. And June was a good month: higher demand (cold weather) and tighter supply (generator outages) meant prices were significantly higher in June in Victoria: $87.92 per MWh compared to $72.84 in May, $49.47 in April and only $30.36 in March.

To be commercially viable as pure energy storage plays batteries need to increase the number of cycles they can run and the depth of these cycles, reduce capex costs, or sell into higher volatility. On its own, it’s hard to see how Lumea gets close at the moment, just like the other utility battery 41 proposals.

The Odd Couple

The price of Australian Carbon Credit Units has “surged” to record highs just north of $20, up from around the mid-teens where the auctions have sat since the scheme started in 2014.

It’s a triumph of political double speak: the clayton’s carbon price. The carbon price you have when you don’t have a price on carbon. And its accelerating success is due in at least some part to escalating corporate activism in Australia.

The growth in demand for ACCUs is the result of two factors: speculation that the certificates will be worth more in the future and are being bought up by speculators and the rise of corporate offsetting of emissions to manage reputation.

The conservative Morrison Government has evolved a silent partnership with activists who are herding blue-chip companies into the scheme “voluntarily” under the threat of being targeted and their brands and reputations damaged.

It’s a different kind of regulation to the more structured government agencies that most are used to – the Australian Tax Office, the Australian Competition and Consumer Commission.

In the voluntary climate world the new regulators are slightly more mysterious – the Australian Centre for Corporate Responsibility or Market Forces. They cruise the business world threatening to attack superannuation funds, banks, insurers and target investors in ASX-200 companies if they are breaching the rules on climate set by, um, the Australian Centre for Corporate Responsibility and Market Forces. It’s a virtuous circle of compliance imposed and policed by self-appointed moral agents.

In 2020 the Federal Government announced changes to the voluntary carbon market it had created in 2014, widening its scope and beefing up participation in activities like tree planting and industrial facilities cutting emissions.

The King Review was all voluntary, of course. You didn’t have to reduce emissions or buy offsets. The Federal Government’s politically comfortable fall line was to provide the market and let the attack dogs of corporate activism do the dirty work.

Analysts Reputex opined that the rising demand  for offsets is driven by forward contract speculation from investors who think the seemingly inevitable “net zero by 2050” commitment by Australia will be backed by legal constraints on emissions. This is reflected in a sharp increase in ACCU prices, which they think will ultimately converge towards the European carbon price, currently AUS$85.

Actual offsetting of Australian corporate emissions still remains predominantly the domain of cheap and possibly worthless certified emissions reduction units (CERs) from overseas, which can be bought from a couple of dollars a tonne and upwards, depending on the quality of the story you would like to go with it.

Chart of the week – Q3 2021 caps

The caps market is a good proxy for the level of risk and volatility in the wholesale electricity market. The caps market for Q3 2021 has picked up where Q2 left off, with caps prices rising in NSW and Queensland amid ongoing uncertainty about generators and claims that generators are using this to short supply and push prices back to survivable levels.