Boardroom Energy

This week:

  • You can’t call it coalkeeper when there’s no coal to keep

  • Can you be made redundant before you start work?

  • Report card season

  • Chart of the week: Crisis – what crisis?

In Brief

The Coalition appears to have nearly completed its last minute pit-lane climate repairs and will get its net zero by 2050 commitment to the starting line just in time for the Glasgow climate conference starting next weekend. It’s already clear that COP26 won’t be a milestone event in global climate negotiations. China’s President Xi isn’t going, nor is Russia’s Vladimir Putin. US President Biden is struggling to get the Senate to back his ambitious Clean Energy Performance Plan, and may have to take a weaker compromise deal to Glasgow, if anything at all. While West Virginia Democrat Senator Joe Manchin is demonised as a coal state hold-out in these negotiations, any climate package without the broad backing of both major parties faces oblivion the moment control of the Senate tips back to the GOP.

Perhaps more decisive will be the preceding G-20 meeting in Rome, which is arguably more important for Morrison politically and optically. His real intent in taking net zero to Glasgow will be to neutralise climate and energy ahead of next year’s election. The Coalition will campaign hard on Australia avoiding the energy crisis and skyrocketing power prices that are wrecking UK energy retailers and industry, and hitting Europe, China and some Asian economies hard. LNG exports and prices are increasing as Europe and Asia try to outbid each other to get more gas. It is a salient reminder of the demand inelasticity of energy.

In a comparison not unlike Aesop’s grasshopper and the ant, the UK’s is exposed to the very worst of global gas shortages after it closed key gas storages. Japan, meanwhile, may be spared the worst of the crisis as its LNG stocks are at five-year highs. Sometimes it pays to focus on energy security.

In a sign of the times Rio Tinto will push to halve its emissions by 2030 while BHP has cut a deal with Iberdrola to supply half of the power for its Olympic Dam mine in South Australia with renewables. We take a look at what that means for the volatile, big renewables SA grid.

The developers of the heavily publicised SunCable project to sell renewables to Singapore via a giant power cable have announced they are getting some experts to help them with the project. Which makes you wonder what they have been doing until now.

Australia has been labelled one of the least attractive places to attract green investment by a new report, which seems odd given Australia has been setting a blistering, world record place on per capita renewables investment. Speaking of which, the world’s biggest energy utility Enel is joining a long list of global energy companies kicking the tyres on Meridian Energy’s $1bn Australian business. We take a closer look.

For subscribers we have two new Background Papers this week: one looking at offshore wind in Australia and a form guide to the Glasgow COP26 summit.

You can’t call it coalkeeper when there’s no coal to keep

A new renewables deal to help power the biggest mine in South Australia may end up being a case study for why fast starting dispatchable generators need capacity payments in big renewables grids.

Global mining giant BHP has signed a deal with global renewables developer Iberdrola to buy the renewable electricity from its new Port Augusta hybrid renewable project to help power its giant Olympic Dam mine.

The deal has been announced with the usual win-win media releases: BHP gets a single contract to lock in prices and materially reduce its emissions at the iconic metals mine. It will contract renewables backed by electricity from Iberdrola’s existing portfolio, which includes a 120MW gas peaker in Adelaide and a 25MW battery in the state’s mid north.

It’s a big win for Iberdrola too. They got approval for the 317MW hybrid wind and solar renewables project at Port Augusta in 2019. A year later they bought out Infigen Energy where they picked up 278MW of wind generation at Lake Bonney in the state’s mid-north.

Adding Lake Bonney to Port Augusta meant that Iberdrola was long on renewables in a state that is already long on renewables, at least from a market perspective.

The South Australian wholesale price is the most volatile in Australia by some margin, and the spot prices paid at times of high wind and solar generation regularly head into negative price territory.

For Iberdrola the deal brings not only the cachet of supplying a big miner but secures an offtake contract for the Port Augusta generation when the 210MW of wind and 107MW of solar comes online in the middle of 2022.

But the loser is anyone else selling large scale solar exposed to spot prices and the remaining intermediate gas generators in South Australia: Pelican Point, Quarantine and Osborne. These generators are commercially marginalised by more renewable generation, but are still critical for reliable supply at times when there is high demand and low renewable generation.

These “tail risk” events can be less frequent with increased supply of intermittent generation, but more acute when they occur. The energy crisis in the UK and Europe is a real-world example of how critical these events can become, even if they only occur infrequently.

In the future the hope is that technologies like hydrogen and low-cost batteries in concert with renewables will be able to completely replace gas peakers. In the short term the Energy Security Board has proposed the introduction of capacity payments for these types of firming technologies. To keep them in business, and to bridge a pathway to these new technologies until we are sure we don’t need the old gas peakers any more. This idea – which has yet to be fully developed has been dubbed “coalkeeper” by some of its critics who apparently think it’s all a sneaky plot to keep old coal plants going.

The future for these critical local generators looks even grimmer once the EnergyConnect transmission line between SA and NSW comes on line after 2023, as cheaper coal fired electricity from NSW undercuts them even further. That throws up a whole suite of emissions-based  and technical challenges: the life of higher emissions NSW coal generators may be extended by putting SA gas out of business. South Australia could become almost completely dependent on firming generation from NSW and Victoria, at a time when those big generators are rapidly closing.

There’s no coal to keep in South Australia. Yet it increasingly looks like the state that needs capacity payments the most.

Can you be made redundant before you start work?

The problem with a rapidly changing electricity system, is sometimes it changes so fast that by the time you have installed a technical solution, it is already redundant. That may be the case with $180 million worth of large spinning machines which are just about to come on line in the live experiment that is the South Australian electricity grid.

System strength is a timely, if very “inside baseball” topic for Australia’s grids. It’s one of the four horsemen of the electricity system power quality apocalypse, along with frequency control, inertia and voltage control. These are the invisible but critical technical factors that must be managed along with having enough electricity as we move to electricity systems with increased renewable generation.

At a regulatory level, the AEMC has just passed a final rule change to set a long-term framework for system strength. In the real world of the South Australian (SA) grid, local transmission company ElectraNet and system operator AEMO are carrying out final tests on four large spinning machines – synchronous condensers – designed to help keep the SA grid stable by providing system strength in key locations of the grid. These are similar to the turbines that generators use, but don’t actually produce any energy, hence they don’t have the fuel costs

AEMO sees system strength as “the ability of the power system to maintain and control the voltage waveform at any given location in the power system, both during steady state operation and following a disturbance”. The traditional way to do this is with large spinning machines, such as coal, gas or hydro generators that are synchronous with the grid they are connected to. Traditional grids had enough sufficient strength inherently provided by these machines that there was nothing to manage or pay for.

This all changed in SA a few years back as the balance of generators shifted from the traditional synchronous machines to newer renewables plant that use inverters to connect to the grid. Inverter connections mean wind and solar generators are not naturally synchronous).

In periods of high renewables, AEMO would direct some gas generators to switch on to provide this rotating mass and keep the system secure, even though the wholesale electricity price was too low to be commercially viable for them. This cost consumers twice: the gas generators are entitled to compensation for being directed on, while some of the renewables had to be displaced to make way for them. Last year the cost of paying gas generators to be directed on was $50m.

Given these costs, $180m for four synchronous condensers (syncons) that are expected to run for decades seemed like a bargain. While it’s likely that they will work out cheaper than the current arrangements, technology is moving fast in this space. Although it’s only two years since the decision to install them was taken, alternative solutions that are much cheaper have been successfully trialled in Queensland and Victoria.

These approaches involve careful choice of large scale inverters and “tuning” the inverters appropriately. While there may be a slight premium involved in selecting the right inverters, the rest is essentially software. The Queensland project cost less than $1m, according to ARENA who co-funded it.

The Queensland trials on inverter based system strength suggests this technology may be location-specific – it may not work in all parts of the grid at all times. It seems likely that as this approach is refined, however, it will become more widely applicable and more straightforward to implement.

Meanwhile, AEMO has made it clear that it is not yet ready to rely entirely on the synchronous condensers. Even once testing is complete it will still require two synchronous generating units to be online at all times. This should cut directions and their associated cost, by perhaps two-thirds, but it is clear that the syncons are not a complete solution. AEMO appears unlikely to review this (despite the promising results in other regions from inverter management) until EnergyConnect is complete in around three years’ time.

There’s no obvious villain here. ElectraNet was obliged by new rules to take responsibility for ensuring there were assets in the SA network that could provide system strength. It went out to tender for generators to promise to turn on when required, and based on the prices it got back, reckoned it was much cheaper on an annualised basis to buy the synchronous condensers. ElectraNet could only make choices based on the technologies available to it, and at the time, EnergyConnect had not been confirmed, while the use of inverter-based resources to support system strength was yet to be explored. Even so it was still a case of comparing apples with oranges.

It was comparing a contract payment that could be renegotiated after a few years when either the requirements or the potential supply options could have materially changed with a regulated cost to consumers that will endure for forty years. The bids may also have been impacted by an expectation that all three tendering parties would need to participate in the contracting option. It’s not clear why a hybrid option of – say – two synchronous condensers and a lower contribution from generators wasn’t considered.

It also seems that AEMO is somewhat conservative in its use of directions. But it’s their job to keep the lights on, and an insecure power system could result in a black system event, such as SA experienced in 2016. Nonetheless there is a potential disconnect in asking TNSPs to procure whatever is necessary to provide system strength over a horizon of several years and then asking AEMO to decide whether it has the resources it needs on a day-by-day basis. This split of responsibilities has been confirmed by the new rules.

Does this matter? In the end, the annualised cost of the SA synchronous condensers is around $15-16m. The potential cost of paying two generating units to be directed on as necessary was estimated by ElectraNet at $12m, though this could fluctuate from year to year. SA consumes about 12TWh of gird electricity each year, so they can expect to pay around $2 or so extra per MWh for system strength. That’s not huge, even if it does turn out that the same results could be achieved more cheaply with the right inverters set up the right way. But all the breathless talk about Australia becoming a “renewable superpower” is predicated on the assumption that we will be able to produce electricity cheaper than other countries in a carbon-constrained world. If this is going to happen, we’ll need a laser-like focus on driving costs down and solving technical challenges in the most efficient way. That’s not happening in SA right now.

Report card season

The Investor Group on Climate Change (IGCC) released a report this week arguing that Australia is among the least attractive countries for green investment, alongside Argentina, India, Indonesia, Mexico, Russia and Saudi Arabia. Ranking countries is in vogue in the run-up to the Glasgow COP meeting, as evidenced by the Climate Council and KPMG also releasing their own league tables.

By the standards of such report cards, the IGCC analysis is pretty high-level. It takes results from three other comparison exercises: Climate action tracker, Oxford’s Smith School analysis of covid recovery spending and Bloomberg’s climate risk disclosures and combines them into a set of traffic lights across five metrics (three are from Climate action tracker). By contrast the KPMG net zero readiness index is more thorough, combining 103 indicators. While that makes it seem especially robust it also makes it so complex that governments trying to do better would need some help working out what they should do. From a global consultancy firm, perhaps?

The key question is how relevant these metrics are? If Australia had more ambitious targets it would be a signal for green investment, but only if the policies to deploy it were in place. Under President Biden, the US has re-joined the UNFCCC process and upped its targets, but Congress is yet to pass the infrastructure bill that will unleash the funding.

The COVID recovery spending is a curious metric. For most countries, COVID recovery spending was about keeping the economy afloat through transfer payments, such as Australia’s Jobkeeper. Of course, this expenditure has nothing to do with green investment. As Australia spent a greater share of its GDP on COVID recovery than many other countries, it’s unsurprising that green investment forms a low share. It would be fairer to judge countries on the portion of their recovery plans relating to future investment and how much of that is green oriented. Admittedly, the federal government’s preference for a gas-led recovery means it would likely score poorly on that metric too.

Also, government expenditure on green investment isn’t necessarily a plus for the private sector. It can simply crowd out private sector investment.

The disclosure metric is also of limited relevance. It is largely based on mandatory adoption of the Taskforce on Climate-related Financial Disclosures (TCFD). So far only the UK has implemented this in full. However, TCFD or similar disclosures are increasingly being adopted voluntarily, including by many Australian companies. ASIC encourages use of TCFD. It’s also unclear how much it affects project investment as opposed to investment in company shares. Presumably, projects are judged on their own merits, not just on whether their owners comply with TCFD. Implausibly, Australia is ranked at the same level as China for these environmental performance disclosures.

A key gap in this analysis is the general attractiveness of a country for  investment full stop. Australia should score well here, with clear rules and laws around property rights, insolvency processes and corporate probity. Certainly, it is preferable on that basis than the other “laggards” the IGCC groups it with.

It’s also useful to do a reality check on what’s happening to Australian corporates in the green space. Smith School include transmission in its green investment, and Australian electricity networks are in hot demand. Ausnet is subject to a tug-of-war between APA and Brookfield while Spark has just been bought out by KKR and OTPB. In both cases, the network businesses have been valued at a 50 per cent premium to their underlying regulated asset base. Australian renewables companies like Infigen, Meridian/Powershop and Tilt renewables have also been enthusiastically sought after by local and international buyers. Meanwhile, the energy transition will require large increases in supply of lithium, rare earths and other resources, which is starting to translate into the share prices for junior mining stocks that specialise in them. None of this looks like a lack of enthusiasm for Australian assets with a green tinge.

Finally, the report suffers from the same mistake made my many assessments of Australia’s climate performance in recent years – to only look at policies and goals at the national level. Unlike the 50 states of the US where the signal can get lost in the noise, Australia’s six states and two territories are sending clear positive signals to green investors. All have net zero targets and most have near-term policy goals such as 2030 renewables targets and green hydrogen strategies. Admittedly, the corollary of this is that the federal government’s foot-dragging on a national net zero target or increased 2030 targets looks increasingly dogmatic – even if it did no more than let the states get on with it, it could increase the 2030 target to 30-38 per cent reduction on 2005 levels.

Boardroom Energy’s assessment of the IGCC report: C-, could do better.

Chart of the week: Crisis – what crisis?

Wholesale electricity prices have skyrocketed in Europe, and particularly the UK as a result of a gas shortage triggered by strong northern hemisphere summer demand and sustained low wind generation in 2021. UK forward contract prices for 2022 are trading north of 200GBP per MWh, that’s more than AUD$350/MWh for baseload contracts. The gas crunch has also created shortages and higher prices in some other big gas importing economies like China and Singapore. The impact is more muted in economies like Japan because of its long-term gas supply contracts and risk averse levels of storage capacity. Wholesale electricity prices are increasing there too, driven more by higher coal prices. The short gas market has nearly doubled US gas prices, albeit from a much lower base than Europe or Asia.

UK 2022 forward summer baseload electricity price (GBP/MWh)

Source: ICE

The Australian electricity market appears so far relatively unaffected by these global trends. Baseload futures for 2022 reported by the ASX have remained stable following a rally in wholesale electricity prices in the first half of 2021 as gas prices recovered from their pandemic lows.

Western Australia is partly protected by long term contracts and their capacity mechanism (which allows them to cap spot prices at a much lower level). The east coast is more exposed to global price tends with the opening of LNG exports in Queensland. Gas has historically set the marginal price for electricity as gas peaking generators price into electricity markets to recover the spot price paid for their gas.

Australia 2022  forward baseload electricity price ($/MWh)

Source: Boardroom Energy from NEM Review