Boardroom Energy
Bulletin

This week:

  • How slow can the NEM bike go?

  • High EU carbon prices: where ambition exceeds capacity

  • Waiting for a wave of offshore wind

  • Chart of the week: Renewables correlation

In Brief

The oddly named Electricity Statement of Opportunities (ESOO) is a thick, technical document. It’s put out every year at the end of August by the market operator (AEMO). The ESOO is designed to flag potential future reliability risks to signal investors to fix them.

The ESOO is framed by the rules of credible contingencies – things AEMO can credibly plan for. The reality is most blackouts in recent years have occurred because of non-credible contingencies, things that are possible but aren’t inside AEMO’s official planning remit. AEMO has a tough job. It has to plan for things it can’t see or can only partly see. Good luck with that.

The ESOO used to be a technical document for energy nerds. Now it’s fussed over and tweeted about like the publishing of exam results. It is spun in many directions. The big concern AEMO has at the moment is not with running out of electricity, but having too much, specifically too much rooftop solar PV. We take a deeper look at that.

The Energy Security Board continued to promote its plan to introduce capacity payments, as the energy-only market alternative would be a maximum price of $60,000 per MWh. That is the price that would be needed to create enough commercial risk to push up derivative cap prices high enough that these payments could keep infrequently used peakers or storage facilities alive.

Offshore wind projects could soon be legal in Australia following the introduction of legislation in the Federal Parliament. But will any get built? We take a closer look.

OPEC has returned to its core business strategy of trying to control global oil markets by agreeing to only slowly increase supply, despite accelerating oil demand as northern hemisphere economies spring back from COVID-19 recessions and head into winter. Oil is back to around $70 a barrel, with the flow on effects meaning higher gas prices and higher electricity prices in the NEM.

The carbon price in Europe has passed 60 EUR which is just loose change short of AUD $100 a tonne, and some analysts think it has a long way still to run this year. Is it a case of political ambition running ahead of technical capacity to deliver?

Back home in Australia, it seems that lockdowns have been the major contributor to emissions reduction in recent times, with transport emissions in particular, expected to bounce back as we return to normal, and potentially overtake electricity as the major emissions source by 2030.

Korea might have committed to net zero by 2050, but its state banks are still funding around $127 billion in fossil fuel projects. There are plenty of these types of opportunities for private (or government-backed) capital as major commercial banks and investors vacate the space.

Speaking of greenwash, Santos is facing a landmark greenwashing case against it making claims that it produced clean energy and was on track to meet net zero emissions targets, sending a warning to other big talking businesses that they need to actually back their rhetoric with deliverable actions.

Speaking of Andrew “Twiggy” Forrest, he’s been busy calling for a net zero by 2050 target and recycling claims that he will produce 15 million tonnes of green hydrogen by 2030.

How slow can the NEM bike go?

AEMO’S annual electricity statement of opportunities (ESOO) is eagerly awaited each year by energy nerds and others. It is one of those documents that each person can take their own message from, depending on their perspective. On the surface, things are looking pretty good. It’s underneath the waterline where the anxieties emerge. Not with running out of electricity, but having too much at times, specifically too much rooftop solar PV.

The main role of the ESOO is to flag potential reliability issues over a ten year forward horizon. In an improvement from last year, none of the NEM regions are forecast to breach either of the reliability standards in the next five years.

Last year NSW was forecast to breach the tighter of the two reliability standards (the interim reliability measure or IRM dreamed up by pollies worried about the electoral impacts of blackouts. This year NSW is forecast to come in below the IRM until 2029 when the closure of the Vales Point power station would breach the reliability standard.

The change appears largely due to Snowy’s Kurri Kurri gas plant being expected to come online in 2023/24. It’s also helped by marginally lower demand forecasts and additional renewables. It’s curious that so many people who criticised the Kurri Kurri project now cheer the reliability it will help deliver.

The rest of the NEM is not forecast to breach the IRM or the Reliability standard, until Victoria in 2028 when Yallourn closes. In both cases, this is only if no further new dispatchable capacity arrives in the next few years. There are already several plausible sources for extra capacity including a transmission upgrade to make full use of Snowy 2.0, Energy Australia’s Tallawarra B and several big battery projects.

Figure 1: Expected unserved energy, 2021-2030, Central scenario

Source: AEMO

The increase in unserved energy (AEMO code for blackouts) as Yallourn and Vales Point close highlights the risks to reliability from sudden outages of a large power station. Planned closure can be planned for, because there is several years’ notice. Unplanned closure can’t. The threat to Yallourn’s operations from mine flooding is the kind of risk AEMO has their eye on. But the net unexpected outage will likely be somewhere else, somewhere unexpected. If Callide B and C had been anywhere other than Queensland, or if the fire had happened during a hot summer, there would have been blackouts as a result.

How to meet maximum demand is no longer AEMO’s top concern though. A bigger issue is minimum demand. This initially sounds like a nice problem to have. The issue is not supply adequacy, of course, it is system security – the stability of the grid. Low demand will arise in the middle of a sunny (but not hot day) when most electricity comes from rooftop PV, a source notoriously hard to monitor or control. The rest from large scale solar.

At some point, this would mean there would be little or no synchronous generation online – the big spinning machines that drive coal, gas and hydro power would have switched off because rooftop solar doesnt even bid in the grid and large scale renewables generate at zero marginal cost.

This is a problem, because it is millions of micro-variations in these spinning machines that keep a large-scale power grid stable, in much the same way as kids keep their bikes on a straight line by tweaking the handlebars left and right. Taking them out of the equation and relying on the electronic inverters that govern PV large and small (and wind farms, batteries) is like taking the handlebars off your kid’s bike, giving them a PlayStation controller and saying, “it’s OK, I’ve rigged this up so this makes the wheels go left/right instead”. They’ll learn how to control the bike that way eventually – they just need enough time.

Do we have enough time? AEMO says it is aiming to be ready for this state of affairs by 2025. That is only four years away. The second part of the headache is that in this scenario, all the coal plants in the NEM will be turned off. They will probably need to be up and running again within a few hours as the solar ramps down. This will also be a race against time.

The other option is to find new demand. AEMO is modelling scenarios in which there is greater electrification of transport and new demand sources from hydrogen manufacture. It anticipates both will be a flexible source of demand, able to ramp up to help manage minimum demand (when prices will be rock-bottom) and to turn off to avoid exacerbating maximum demand. But this requires a big shift in mindset from consumers, who typically see electricity supply as just there when they want it. The scale of the challenge is illustrated by the fact that a whole new set of rules have been implemented to make it easy for large users to provide this flexibility – the wholesale demand response mechanism. AEMO’s forecast for the amount of new demand response this will deliver: 56MW. This is a drop in the ocean of what will be required.

As Energy Consumers Australia Lynne Gallagher recently pointed out, the electricity system needs to become a whole lot more consumer-centric if large scale demand response (including aggregating the actions of millions of small consumers) is to play the crucial role envisaged in helping balance the grid.

So, it turns out that we, the consumers are the training wheels. Are we ready for this role?

High EU carbon prices: where ambition exceeds capacity

The carbon price in Europe is soaring, currently approaching AUD$100 a tonne. That’s while the European economy is forging out of its COVID-19 recession with the EU’s economy predicted to grow by around 4.8 per cent in 2021 and more of the same in 2022. Pricing emissions doesn’t appear to be holding the European economy back.

Figure 2: EU carbon price (EUAs) 2021

Source: Amber

That’s the good news. The bad news is that sustained increases in carbon prices reflect growing scarcity for permits. This scarcity is being pushed by a rage of short-term market factors, but there may be a deeper, underlying problem. The EU’s political ambitions on climate are moving faster than technology can solve them.

Currently the carbon price is hovering above 60 EUR, double its value from a year ago.  This year’s surge has been driven by a range of factors: economic recovery and increased demand for energy and certificates. Very tight European gas supplies and higher gas and oil prices meant coal would be used more for electricity, and coal needs around twice the certificates of gas.

But it may not stop there. Some analysts predict the carbon certificate price (EUAs) could reach 110 EUR by the end of 2021. That’s nearly AUD$180 a tonne. The EU carbon price is still relatively contained to the electricity market. Big emitters like gas and coal power stations have to buy and surrender certificate for each tonne of greenhouse gas they emit. When they don’t have any viable lower emissions options, they are forced to pay whatever it takes to supply electricity, and these prices are passed on to consumers.

The price confidence may also be driven by increasingly ambitious political targets being proposed by European governments. Their headline act is the “Fit for 55” package designed to deliver emissions reductions at 55 per cent by 2030.

The closest thing Australia has in way of a carbon price is the artificially low price of ACCU’s, produced under the emissions reduction fund. It is trading around AUD $18 a tonne. It is more a political prop than genuine price signal of the scarcity value of greenhouse emissions.

The strength of the EU carbon price suggests more long term than short term drivers at play, as investors look to increasingly tight carbon markets and pricing in the future. This is being fuelled by populist ambition out of Brussels and some national governments. In turn, the higher the cost of carbon gets, the more pressure there will be on EU lawmakers to enforce carbon border tariffs in imports flagged at the end of 2019.

There is a small problem. The carbon border tariffs proposed by the EU may breach WTO rules, and countries disadvantaged by them, like China, may challenge and win. That’s why the EU is trying to enlist support from the US and other key economies, so that the case for applying carbon border tariffs is more widely supported.

So far it has struggled in its campaign to broaden support for a carbon price. The EU took 5 years to design its scheme and has been bedding it down since 2005. The Biden Administration will not move on carbon pricing this term at the very least. It cannot afford to risk backlash in key marginal industrial and rust belt states.

High carbon prices increase demand for lower abatement alternatives. Right now, it doesn’t look like there are enough of these around, at any price. This explains the growing frenzy of European companies to explore lower carbon technology options. But research takes time too.

Waiting for a wave of offshore wind

A long-awaited bill has been introduced to lay the regulatory groundwork for allowing offshore wind farms to be built in Australian waters. Will this spark a tsunami of projects?

Offshore wind is more expensive to build and maintain, but more efficient than “conventional”  onshore wind. While the size of onshore wind turbines average around 3MW, offshore turbines are huge, averaging around 7.5MW per turbine. The largest offshore turbine available today, the 12MW Haliade-X has three carbon fibre turbine blades each 107m long, making them larger than the wing of a jumbo jet. The blades (which rotate at over 300km/h at the tips), generator and associated equipment weigh over 900 tonnes. They are enormous renewable beasts.

There are, self-evidently,  several challenges with installing giant wind turbines in the sea. In shallow waters, the logistics of anchoring the turbines are possible, but more challenging than onshore. A platform is required to hold the pylon and turbine in place, and special ships are required for construction and maintenance. The transmission connection needs to be laid underwater.

As the sea gets deeper (where the best winds often are), construction has to flip to a floating platform, and the supply chains from port get longer, the further out the wind farm is. For this reason, floating wind farms are only just moving past the pilot project stage. Oil rigs float and are anchored in deep seas, so it is technically possible. But the energy produced by an oil rig is much greater than the energy produced by each floating wind turbine.

The flip side is that with access to stronger winds and the larger turbines, offshore wind farms have higher capacity factors – up to 60 per cent in the best situations. This slightly offsets the increased costs on a levelized cost basis, but there’s still a big gap. IRENA estimates the average LCOE of onshore wind at US$39/MWh versus offshore at US$84/MWh.

So why would anyone build offshore wind if it’s twice as expensive as onshore? To answer this question, look at the places that are building offshore wind: UK, western Europe, northeast USA, Japan, Taiwan. They all have high population densities. So, there is not enough land to power their economics purely on land-based renewables. They have no option but to look offshore. The UK in particular has plans for around half its power to come from offshore wind by 2050.

Australia does have options. We have lots of land. We also have better solar resources to complement wind power than the countries listed above. There are grandiose plans for 30-50GW projects based around onshore wind, solar and battery storage. It’s true that there are some excellent offshore wind resources that could deliver much better capacity factors than anything on land. But these prime resources are off the coast of Southern Tasmania, which is not very near any major loads. It seems unlikely that locals would welcome the industrialisation of that part of the world, either.

Where offshore wind is a central part of a country’s plans for decarbonising its power system there has been a key focus on ways to drive down costs. Economies of scale from large and multiple projects are critical, allowing for shared construction equipment (such as the “jack-up” ships that can anchor themselves to the seabed while craning parts up to the top of the pylon) and maintenance facilities and supporting local manufacturing. In other words, there’s not much point in building one offshore wind farm, you need to build a dozen – in roughly the same area. Extensive R&D has also played a key role.

But if Australia doesn’t really need one wind farm, we definitely don’t need a dozen. Some optimists think that’s what we’ll get though, with 18 prospective wind farms for a total of 29GW apparently under consideration. Look a little closer and it turns out they are almost all in the “pre-feasibility” stage. Some of the proponents are struggling to build a functioning website, let alone a wind farm.

It may be that Commonwealth government foot-dragging on implementing the regulatory framework for developing offshore wind is a key reason these projects are all in their infancy. But outside of a benevolent government, it’s not clear who would pay the inevitable premium to underwrite any of them. It’s a classic chicken and egg situation – offshore wind is too expensive right now, but to make it more competitive we’d need to build a lot of it – but there’s no sign it’s one we need to resolve to decarbonise Australia.

Chart of the week: Renewables correlation

Winter runs from the first of June until the end of August. Winter is the most supply challenged season for large scale renewables. How well do wind and solar complement each other? In the winter of 2021 Australian NEM states observed lower solar correlations, even though the sun rises and sets at much the same time. That’s because of increased cloud cover and different weather patterns in different regions. We observed some slight negative correlation between wind and solar in each state, ranging from minus 0.06 to minus 0.34. Not un-useful, but not enough to impact capacity requirements for firming generators.

Finally we would observe wind is slightly positively correlated with other interstate wind generation. The wind isn’t always blowing somewhere.

Table 1: Renewables correlation, winter 2021

 

Winter 2021NSW WindNSW SolarQLD SolarQLD WindSA SolarSA WindVIC SolarVIC Wind
NSW Wind1
NSW Solar-0.151
QLD Solar-0.060.841
QLD Wind0.28-0.34-0.301
SA Solar-0.160.820.76-0.341
SA Wind0.37-0.15-0.110.06-0.221
VIC Solar-0.140.920.79-0.320.83-0.181
VIC Wind0.39-0.03-0.030.10-0.100.60-0.061