A Eurocratic energy crisis
Closing in on Glasgow
The great disappearing act of energy networks
Chart of the week: Renewables spot price by month
Europe’s energy crisis continues to deepen by the day. A serious gas shortage has sent retail gas and electricity prices soaring, sending small UK energy retailers to the wall. Already 1.5 million retail energy customers have been affected and more is likely to follow. Steel mills, food supplies as well as heat and electricity are threatened. Given it’s still only September and gas demand increases with the onset of winter, analysts are warning worse is to come. The excuse being rolled out is either a “perfect storm” of market events and/or Russian manipulation of gas supplies. Perhaps Europe is learning the hard way that a more pragmatic, less ideological approach to decarbonisation is required. You can’t power a continent on climate ambition.
China might be punishing Australia’s coal exports, but it’s quite happy to buy as much gas as it can as it manages a summer heatwave and lots of middle class Chinese with air conditioners. China’s willingness to outbid anyone on loose gas supplies is a big part of the reason for the European predicament.
Closer to home it looks like the Coalition is shuffling up to a net zero by 2050 commitment in time for COP26 in Glasgow in November. This will diffuse the symbolism of a net zero target ahead of the looming Federal election. China has meanwhile committed to not building any new coal fired power stations overseas, although they are still coy about whether they will keep building them at home. Which means they probably will.
Australia’s nuclear submarine deal with the US and UK has struck a chord with the public, who it appears are more scared of China than embracing nuclear technology. This suggests it might be easier for the public to consider nuclear energy in the future, that is, until they see the price tag.
Everyone wants to buy distribution and transmission business AusNet Services with a bidding war between Canadian giant Brookfield and pipeline owner APA. The latest M&A activity reinforces the growing desirability of regulated asset businesses in an increasingly interventionist energy transformation.
The most popular grid scale battery in the world at the Hornsdale wind farm in South Australia has been put in the naughty corner. The regulator claims it failed to deliver frequency control (FCAS) services to Queensland like it was supposed to in 2019. Given that in a high renewables future, batteries are expected to be a major provider of such services, it will be important to understand what went wrong.
A Eurocratic energy crisis
Europe is in the midst of a big energy squeeze. Unusually low winds and drought-constrained hydro have meant lower renewables output. So, traditional fossil fuel and nuclear sources have had to fill the gap. But many European countries have been enthusiastically phasing out coal to help meet their climate commitments. Some have doubled down on their disdain for baseload by also backing away from nuclear power. Germany is the most high-profile example, and as the continent’s largest economy the most important. But the UK* and Spain have almost totally phased out coal, and Belgium is phasing out nuclear power. This leaves natural gas to do the heavy lifting of filling the energy deficit and maintaining reliability.
Demand for gas is surging globally as other countries also decarbonise their energy systems. Gas might be demonised by governments and activists, but it remains a lower emissions alternative to coal, a globally traded commodity, a flexible source of dispatchable power, an industrial feedstock and provider of domestic heat. So, as the global economy bounces back from the impacts of COVID-19, gas prices are shooting up around the world. Europe is a major gas importer, and so does not have the option of, say, middle eastern countries, to just hold down domestic energy costs. Further, its main import source is Russia, which means Vladimir Putin has his hand on the gas taps. The cost impact of heavy gas reliance is exacerbated by the EU’s carbon trading scheme (ETS). More fossil fuel combustion (including bringing some of those old coal plants back online) means more demand for permits, which pushes the price higher. This then flows on to other sectors covered by the ETS.
So it seems clear that Europe is not especially well prepared for what looks like a foreseeable set of circumstances (of course, it’s always easier with hindsight). This means the best place to look for clues as to why it’s not prepared is the governance of its energy systems. While a full diagnosis requires a deep dive into the arcana of EU energy regulation, there is an obvious tension between ambitious decarbonisation goals on the one hand, which require extensive regulatory intervention and subsidies, and on the other hand an existence on free and harmonised markets to solve for the supply-demand balance.
EU officials are some of the most enthusiastic supporters of efficient markets as the solution to all problems. To this end they have been taking steps to pull the 27 members’ electricity markets into line. Because these markets are physically interconnected (and expected to get even more so over time), the market design choices of one country affects its neighbours. So the EU polices national markets very carefully for what they consider to be “distortions”. One of their targets is capacity mechanisms. While a well-designed capacity mechanism is straightforwardly a payment for a service – a commitment to provide power when required – the EU continually brands them a subsidy. To put the issue into perspective, a recent EU review of energy subsidies found that capacity mechanisms represented a “subsidy” of around $2.2bn annually while subsidies to renewables were around three-quarters of all subsidies – in the order of $70bn pa.
If a country wants to implement a capacity mechanism, they have to demonstrate to the EU’s satisfaction that they have a resource adequacy problem. The power system modelling that supports this includes assumptions about how much can be imported from neighbours. The risks of overestimating import availability when there are systematic supply issues can be significant as California found to its cost last year. The crisis is all the more intense in the UK because a major interconnector with France is out of service.
A capacity market is not a panacea, and comes with its own set of drawbacks. But it assists in focussing minds on the levels of dispatchable power in a system. And if part of the problem is an atomistic focus on individual countries, then a pan- Europe approach would be part of the answer. This is starting to happen, with Europe-wide resource adequacy assessments being carried out by the association of system operators (ENTSO-E). The value of these is limited, however, by the fact that they include announced projects but without any assessment of economic viability. In any case, such exercises generally assume upstream – i.e. fuel markets are working and not impeded by, let’s say, a powerful autocrat with geostrategic goals. The flip side of a single source of “the truth” on resource adequacy is that the impact of flaws in the assumptions are magnified. If weather traces don’t account for unusual future patterns, then the conclusions on availability of renewables may be badly wrong, for example. Similarly with demand projections, which are more complex when decarbonisation is driving electrification of transport and other sectors, meaning the past is no longer a good guide to the future.
So, where does the EU go from here? In practice, it means building in a greater error margin in scenarios and modelling and recognising the necessity of ready access to energy via long-term storage. In the 2030s and beyond this may manifest as green hydrogen, which the EU is enthusiastically supporting, and/or nascent technologies such as compressed air (CAES). In the short term it will need to recognise that the realistic source is natural gas and review its gas storage capabilities accordingly. But it also needs to realise that decarbonisation goals are a signal to the market that the economic life of gas storage assets may be curtailed (they are unlikely to be able to be simply repurposed for hydrogen storage), and so the market may not naturally solve for this. The UK’s largest gas storage facility came to the end of its economic life a few years ago and was never replaced. Outside the EU, the UK can choose to do things differently now, of course. But inside it, Brussels will have to find a way to reconcile its market purity with its enthusiasm for driving decarbonisation.
* yes, the UK is no longer an EU member. But its energy policy is heavily shaped by its decades of membership, it participates in the EU carbon permit scheme and it is physically interconnected to the continent with both gas pipelines and electricity transmission.
Closing in on Glasgow
It’s pretty clear now the Morrison Government intends to commit to a net zero emissions target by 2050 in time for the Glasgow climate summit in early November. There is no sudden epiphany, this is pure politics, both national and global.
The groundwork for the Coalition’s climate pivot has been under development for weeks now. Coalition backbenchers in marginal electorates have been calling for the shift for the last few months.
Strategists are acutely aware that committing to net zero by 2050 is attracting the same kind of iconic popular status as ratifying the Kyoto Protocol was ahead of the 2007 election. No one knows quite what it means, but they think we should do it anyway.
Ignoring that threat resulted in political catastrophe for the Coalition. They’re unlikely to make the same mistake twice. Removing net zero from the political table will neutralise one of the few points of differentiation still Labor has on climate, having quietly moon-walked away from carbon pricing over the last two years.
And so the strategic retreat has begun. The ground zero of opposition to the commitment has been the party’s base, conservatives and key Nationals. Earlier this month leader Barnaby Joyce, who will have seen the polling too, started to make public signals of détente, offering to trade support for net zero in exchange for regional infrastructure spending.
In what appears increasingly like a choreographed dance, Nationals backbenchers and moderate Liberal back benchers both stepped up their calls for net zero this week. Prime Minister Scott Morrison then said Australia will aim for net zero by 2050 while chatting with US President Joe Biden. It’s always a good way of drawing attention to something.
Federal Treasurer and former Energy Minister Josh Frydenberg today will warn that failing to commit to net zero will increase borrowing costs for Australian investors. The Nationals Party room remains pivotal to the pivot.
New Nationals leader Barnaby Joyce was once a key hold out on net zero. Now his conciliatory tone suggests a pragmatic shift is coming. He wants to portray sufficient reluctance on a net zero deal to not lose face with his supporters.
Making a commitment for a date 29 years away does not require any other short term policy shifts, like carbon pricing or forced closure of coal mines. Morrison’s political focus is squarely in the very short term.
A net zero deal will enable him to go to the COP26 in Glasgow, neutralise the politics of climate change, and head to an early 2022 poll which will probably be a referendum on COVID-19 management.
The great disappearing act of energy networks
Market-watchers have been agog this week at the bidding war that has erupted for Ausnet Services, owner of gas and electricity networks in Victoria. It follows hard on the heels of the takeover of Spark, another networks owner, by global buyout giant KKR and Canadian pension fund OTTPB. IF Brookfield wins the battle, there will no longer be any regulated network owners listed on the ASX. This has some big repercussions for the way the AER sets network revenues.
Around half of network’s allowed revenue is based on the allowed rate of return – in other words, the AER’s estimate of the cost of capital for the networks it regulates.
The standard way to calculate the cost of capital is:
(Cost of equity/market value of equity) + (cost of debt/market value of debt)
The cost of equity can be further broken down using the Capital Asset Pricing Model as:
Risk free rate + (systematic risk (beta) x market risk premium)
Without getting too caught up in the finance theory jargon, some of these parameters are economy-wide variables that are easy to observe. For example, the risk free rate is commonly taken as the yield on government bonds, since these are the least risky investments going. Others are more industry specific, such as beta or the balance between debt and equity (gearing). While some of the networks (or at least companies whose main business was owning the networks) were listed on the ASX, then there was some publicly available data with which to calculate these parameters (without going into detail they are both ultimately derived from company share prices). Without them they are not.
What are the AER’s options? There are two sources of information they could use instead. One is ASX -listed companies with similar businesses – infrastructure companies like Transurban (toll roads) or Aurizon (rail). These have the merit of being part of Australian capital markets. Of course, there is no guarantee that these will stay publicly listed either, given private equity’s enthusiasm for infrastructure (see Sydney airport for an example outside energy). And they don’t necessarily face the same risks as energy networks, operating in a different industry and different regulatory regimes.
The other is overseas energy network companies. There are plenty of listed companies still in Europe and the Americas, several of whom look a bit big to be gobbled up by private equity. But these are different capital markets, and they operate under different regulatory regimes. Also, many are vertically integrated, meaning they own competitive generation, gas production and/or retail businesses too. These are typically higher risk businesses.
So, in either case, it is hard to be sure that the results the AER get from such businesses are a good proxy for Australian energy networks. In the case of international networks for example, they appear to often have higher betas. This would push up the rate of return and in turn energy prices.
Another element of allowed revenue that may change is the tax allowance. This is adjusted for the assumed use of franking credits on dividends. The AER’s current benchmark is based on data from large, listed companies. But under private ownership and often overseas ownership, the use of franking credits could be lower. If the aER changed its benchmark, this would also increase prices.
On the other hand, there are the broader signals these deals send. Sophisticated buyers are paying premium prices for these regulated assets. This is despite networks and their owners’ criticism of the AER’s 2018 decision on the allowed rate of return, which is progressively flowing through to network revenues. But the early indications from the current review, which will conclude in 2022, is that the AER will adopt a similar approach in many aspects of their decision. So, the buyers seem pretty comfortable with the way the AER sets the rate of return. But transaction values are hard to interpret and the AER has previously indicated it is hard to put a lot of weight in such evidence.
Nothing is certain here. If APA wins the battle for Ausnet, there will still be one listed network owner. Although since APA’s main business is gas transmission pipelines, which are not revenue regulated like the networks, there will still be some complexity in interpreting its market data. And complexity is a feature of these important decisions. Even though the decision will affect all east coast energy users for years to come, only four organisations who aren’t networks or their shareholders submitted to the AER’s latest consultation. Having less public data available only makes it harder for energy users to participate in these processes.
Note: the author is a member of the Consumer Reference Group, which is advising the AER on its 2022 Rate of Return instrument. Any views expressed are his own.
Chart of the week: Renewables spot price by month
Increased investment in solar and wind means more supply of solar and wind at the same time. This creates gradual oversupply of generation at the times when it’s sunny and windy. We can see this over time, with the price paid to renewables generates falling, and the price paid at times of renewables generation falling at an accelerating rate relative to the wholesale spot price.
Chart 1: Renewables volume-weighted average (VWA) spot price by state by month ($/MWh)
This is apparent from the spread of renewables prices from the spot wholesale price, which is increasing over time.
Chart 2: Wind and solar spread from wholesale spot price by state ($/MWh)
A winter recovery in wholesale prices in 2021 translated into some strengthening of renewables spot prices but these prices were still lower relative to the prices paid to firm generators. This is why renewables generators want to see rapid exit of coal. This, they believe, will result in an increase in wholesale prices which will improve value for renewable generation. What’s not clear from this is how reliability will be maintained under accelerated coal exit.
Chart 3: Monthly VWA wind and solar revenue by state ($/MWh)
The wholesale spot price continues to demonstrate a relationship with oil prices (a proxy for gas prices) as shown by the average monthly Brent crude oil price in USD.
Chart 4: Wholesale market spot prices ($/MWh) and Brent crude oil spot price ($US/barrel)