Seeking out emissions to reduce
Offshore wind – fewer reports, more turbines please
One market participant category to rule them all
Chart of the week: Gas prices and electricity prices
Can you hear the drums, ScoMo? At the start of the year the Federal Government looked cherry ripe to go to an early election in the spring of 2021. Australians felt the worst of the COVID-19 pandemic was behind them, and the political risk around climate change had been diffused by falling electricity prices. Now COVID-19 vaccine mismanagement has become a subject of national shame and wholesale electricity prices are heading back up.
The causes are partly seasonal. A cold winter has pushed up demand for heating, while solar generation is at its lowest for the year. When there is 15GW of solar PV, that matters. The Callide C power station is still off line after an explosion in late May, but the main culprit is rising gas prices. Gas continues to set the marginal price of electricity because gas peakers buy a lot of gas at spot prices and bid into the market to recover these. As peakers tend to set the wholesale price, especially at times of higher demand, so prices are going up. High gas prices are in turn a combination of factors – low Victorian storage levels, cold winters, high demand and technical problems at the Longford gas plant in Victoria tightening supply. We look at the enduring relationship between spot electricity and gas prices in our chart of the week.
As the EU ramps up its rhetoric on the threat of possibly WTO illegal carbon import tariffs, Japan has responded by upping its rhetoric on cutting coal and gas use by 2030. Sounds impressive, but what will they replace them with? Japan is exploring offshore wind generation and more solar, but doesn’t have the room to run big renewables like Australia.
The NSW government will ban onshore gas in large tracts of the state in a political move to appease the Nationals, while gas developers warn of higher prices from continued gas scarcity and more reliance on imports. Speaking of which, where is the gas-led recovery from COVID we were promised last year?
Chevron promised to capture and re-store 80 per cent of the carbon dioxide coming from its giant Gorgon LNG project. It has dismally failed its first five year target set by the WA EPA and now faces paying a big penalty for the breach. The failure also casts doubt on gas industry claims they can use CCS to reduce wellhead emissions. And if they cant make it work there, then that doesn’t bode well for CCS anywhere else.
Seeking out emissions to reduce
Making investment decisions in the light of climate change and decarbonisation is hard. Specialist funds with strong environmental social and governance (ESG) investment mandates are finding it harder to find the right investments. In the EU, tighter disclosure rules have shrunk the amount of sustainable assets by US$2trn, while here in Australia a local fund is claiming it needs to invest more overseas because the federal government’s lacklustre climate policy means there are few local options.
This may be a sign of a shift in investor mindset from simply excluding businesses and assets that aren’t seen as sufficiently low carbon or sustainable to actively pushing businesses of all types to progressively decarbonise. Investment giant BlackRock has been flexing its muscle by voting against numerous board directors in companies it owns shares in because it didn’t consider they were taking climate issues seriously enough. Meanwhile, former rockstar central banker Mark Carney – who now works for another investment giant, Brookfield – told the Australian super industry’s annual conference that investors should “go where the emissions are” and help drive decarbonisation at those companies.
When big mainstream investment managers like BlackRock and Brookfield start zeroing in on climate issues, it’s no longer just activists and specialists that are driving the trend. Governments would do best to stop complaining about what investors or banks will or won’t invest in and treat the situation as a reality that they need to work with. This is not to say that all investors are the same. There will always be pools of private equity looking to invest against the trend and pick up fossil fuel assets on the cheap. And in any case, for all the focus on what Exxon or Shell might do next, most fossil fuel reserves are held by state-owned businesses in China, Russia the Middle East and elsewhere.
Mark Carney’s exhortation may have come too late for Australia’s second oldest listed company, AGL, as it seeks to split itself in two to minimise the drag on its value for being labelled a climate laggard. As part of the plan, shareholders will be given a greater say on both spin-off’s climate reporting. This is unlikely to be enough to satisfy the investment activists, who having berated AGL for buying coal plants like Loy Yang and Bayswater are now complaining about AGL selling them. Of course investors with an enthusiasm for seeking out emissions to reduce will have plenty to interest them in Accel energy, the son-of-AGL that will own its remaining coal plants.
Offshore wind – fewer reports, more turbines please
Most new or emerging technologies are more expensive than their competition. They haven’t had time to exploit economies of scale, and they are still working their way down their technology and operational cost curves. That doesn’t mean they are guaranteed to make it. Technologies like carbon capture and storage and solar thermal have been around for decades but are no more cost competitive now than a decade ago.
When assessing the progress of these technologies, it can be hard to work out reality from spin, whether a technology is making genuine progress or not. The ultimate test is the market. If a technology isn’t crossing the financial line and getting investment without extra financial assistance, then that is the clearest indicator that it can’t compete. But proponents of a technology or application often continue to insist the breakthrough is just around the corner. Their expertise, time, effort and reputation are often heavily invested in the success of the technology. Reporting of progress can be enthusiastic and full of hope.
Which brings us to offshore wind. Wind energy now accounts for around 10 per cent of Australia’s electricity supply, all of it onshore wind.
Australian renewables developers have eschewed offshore renewables for one simple reason: it’s significantly more expensive. A new report from the Blue Economy CRC suggests Australia should take another look at offshore wind. Ok then, let’s.
The media headline given to the report “offshore wind key to Australia’s clean energy future” claims there are more than 2000GW of offshore wind generation sites along Australia’s vast coastline. Sure. The southern coastline of Australia sits on the edge of the roaring 40s. It has great wind.
The report identifies “more than 10” offshore wind projects under development with a combined capacity of more than 25GW. The generation capacity of the NEM is around 75GW, so that’s pretty ambitious, suggesting the offshore wind crowd don’t get out of bed for less than 1000MW a project.
The report evaluates three things: the quality of the wind resource, how offshore wind tends to have higher capacity factors (it runs more often and for longer) than onshore wind and solar PV, and how many jobs it would create. But nowhere does the report discuss cost. Which is possibly a bit of an oversight.
The International Energy Agency (IEA) released a bullish report on offshore wind in 2019, assisted by most of the offshore wind experts in Europe, who are, of course, heavily invested in the technology. Offshore wind is big in Europe because onshore land is scarce, or as conservative US writer PJ O’Rourke once described it, “you can’t swing a cat without sending it through customs.”
Offshore wind was developed in Europe for two reasons: the land was already pretty crowded and the surrounding sea shelf was shallow. That meant you could build large wind turbines anchored to the ocean floor without too much additional cost, although servicing and transmission costs were still more expensive, as is anything you do in the ocean. On the positive side going offshore allows for larger turbines which are more efficient, and there are fewer neighbours to manage.
Australia’s coastline is more challenging, the sea floor dropping away faster and closer to shore than in Europe. This would require the installation of floating wind turbines, which is a newer and more expensive technology than seabed anchored turbines and pose additional habitat risks.
All these reports remain oddly coy about the specific costs of offshore wind deployment. The lack of transparency is always a warning sign that the technology developer is trying to mask true cost and make up for it with a pitch for creating jobs or regional development.
In March 2019, the $8bn, 2.2 gigawatt (GW) Star of the South offshore wind project off the southern coast of Gippsland in Victoria, was announced as “Australia’s first offshore wind project”. If it’s such a great technology for the Australian market, then surely Star of the South will be commissioned soon.
One market participant category to rule them all
Battery fans will be pleased with the progress being made by the AEMC in smoothing the way for the technology’s entry into the NEM. The AEMC’s draft rule on Integrating Energy Storage systems into the NEM, which will be finalised in October following stakeholder feedback, aims to resolve a range of anomalies and ambiguities in the rules as they relate to storage assets.
The original NEM design was based around two clear and different categories of participant: generators (suppliers) and customers (users). The rules allowed for various sub-categories of each depending on size and type, but everyone was either one or the other. Except for, that is, a couple of pumped hydro storage assets, which sometimes looked like customers (when they were using electricity to pump water up hill) and sometimes looked like generators (when they were using the stored water to drive a turbine). The solution was to get them to register in both categories. Because these were large generators and generally owned by governments, they simply went along with what to them were minor inefficiencies and costs in the way the rules treated them.
But as batteries – both large and small (but potentially aggregated up to wholesale market scale) -begun deploying in recent years, these issues began to loom larger. This may be partly due to their being smaller and likely to have faster charging and discharging cycles than pumped hydro. Accordingly, the market operator AEMO collected up all the issues it could find and put in a rule change to get them resolved.
Some stakeholders urged the AEMC not to get too carried away, and to do the minimum necessary, given that bigger, longer-term issues were due to get picked up in the ESB’s post 2025 market design review. In the draft rule, however, the AEMC, having taken the lead in promoting a long-term vision of a two-sided market where demand plays as active a role as supply, decided to lay the groundwork towards this future. A key part of the reform is to create a new category of market participant: the bi-directional resource provider. In one sense this is a step away from the two-sided market future, in which rules are aimed at services provided and consumed, rather than on particular participant types. The AEMC’s cunning plan is that, over time, all participants will become a (potential, at least) bi-directional resource provider, i.e., that this will become the universal participant type.
In the short -term, only batteries and pumped hydro will fit into this category. It is designed to also encompass hybrid assets – i.e., a co-located generator (probably wind or solar, but in principle could be any generator type) and storage unit. This is a useful step forward, as hybrids may be a way for renewables developers to manage some of the grid issues they face such as negative prices, congestion and loss factors, given that it will allow them to send their output to market at a different time from other similar assets nearby.
However, while the draft rules will reduce the cost of storage by removing some double-charging and providing developers with more clarity about the way they will be treated and operated, this will only change the economics of new storage at the margins. Most of the many GW of proposed projects will still be looking for government support to make their project viable. Maybe taxpayers will save a few dollars then…
Chart of the week: gas prices and electricity prices
Spot gas prices have been an important driver of spot electricity prices in the NEM, because most peaking generation must buy gas at spot prices, and then bid into the NEM to recover the cost of the gas. There are other factors like demand/weather which also inform gas and electricity prices, but there’s a clear relationship between the two.
Gas spot prices (dotted) and electricity spot prices over the past decade, NEM
At the start of 2021 we noticed spot electricity prices appeared to decouple from gas prices. As the impact of COVID retreated oil and gas prices recovered to pre-COVID levels in the first quarter of 2021. Wholesale electricity prices continued to fall, off the back of a mild summer and renewables oversupply. It would be commercially significant if gas generators could not recover their operating costs to run peakers. Really significant. Like they wouldn’t run unless ordered on.
This risk appears to have abated. Gas prices have been continuing to recover since May, and electricity spot prices have also been firming.
Sharp increases in gas prices at the start of July have been caused by a cold snap on the eastern seaboard, partial outages at Longford gas plant in Victoria, switching to gas following the Callide C explosion and declining gas storage at Iona.
In July domestic gas prices increased and took electricity prices with them. This affirms that the relationship between gas and electricity prices is not broken, at least not yet.
Spot gas and electricity prices May to present