Boardroom Energy
Bulletin

This week:

– The black market for carbon

– How low can you go? Minimum demand in SA

– The coalition that doesn’t like coal

– Chart of the week – emissions intensity of electricity by state

In brief

In 2019 global energy giant Shell signalled its intention to diversify into the Australian electricity market with its $617 million acquisition of business energy retailer ERM Power. In case you thought they weren’t really serious, they have returned with another $1 billion for Meridian Energy’s Australian businesses. This includes 185,000 customers via residential retailer Powershop and nearly 300MW of renewable generation. The acquisition further disrupts the shape of the domestic electricity market and shows one pathway for conventional fossil fuel businesses to re-orient themselves in the 21st century. Activists are apparently not happy that Shell wants to be a part of future energy markets. GetUp! thinks it helped build Powershop under its old management, so it thinks it can tear it down too.

In a similar vein gas pipeline business APA is making further moves towards acquiring bankrupt electricity transmission business Basslink, as it also diversifies its future. How dare they.

Retail electricity prices are predicted to go up next year when the Liddell coal fired power station closes in NSW. But then they should come back down as more supply comes online. The net effect should be lower prices in two years’ time for everyone who doesn’t live in the ACT, where the 100 per cent renewables policy is costing more than expected.

The Victorian government is spending $40 million on 3 offshore wind farms in Victoria to see if they are commercially feasible, which sounds like the government has already made up its mind that they are.

The Asian Development Bank is leading a consortia to start buying coal fired power stations and close them. There are more than 1,600 coal generations in the region, so they will be busy for a while.

Woodside has decided to develop its $16 billion Scarborough gas field, a decision that has been endorsed by Federal Labor currently leading in the Sportsbet poll.

Twiggy watch: It looks like Fortescue is already signalling it might spin off its fledgling renewables business later this decade. Assuming there is something to actually spin off that is.

The black market for carbon

For 15 years Australian governments have been debating the merits of putting a price on greenhouse emissions. The idea has been politically discarded, parked in the too-hard basket.

Yet demand for a carbon market endures. Some companies want to buy carbon certificates to offset their emissions, and others are willing to sell them. The domestic prices for these transactions appear to be linking. What is creating our unofficial carbon price, will it endure and what direction is it headed?

2021 has been the year that the value of voluntary carbon offsets (ACCUs) and mandatory renewable certificates (LGCs) have started to converge. They currently both sit just north of $40 per tonne. It is a price meeting of the two domestic mechanisms available to Australian companies to manage their carbon risk.

Chart 1: ACCU v LGC prices

Source: Demand manager, CER

ACCU-LGC convergence could be an early indicator of a voluntary carbon market in Australia. It suggests that companies wishing to offset their carbon risk are at least aware that they have a choice between the offset market or the renewables market.

The two certificate classes are entirely different beasts. Only a handful of businesses breaching generous safeguard mechanism thresholds must surrender ACCUs. The Emissions Reduction Fund scheme is mostly voluntary and remains heavily underwritten by the Federal Government, keen to demonstrate modest abatement without economic pain.

Conversely, creation of Large Generation Certificates (LGC) is bounded by the strict requirements of the Renewable Energy Target, the product of bipartisan support for renewables subsidies. Electricity retailers must acquire and surrender LGCs to the value of a proportion of their retail sales.

Over the past two years, companies have begun to adapt the purpose of these schemes. They are starting to buy ACCUs in small but increasing volumes as domestic offsets for their own emissions. And they are also buying and voluntarily surrendering LGCs as an electricity offset (a practice started by the ACT government to meet its 100 per cent renewable target). Voluntary surrender of LGCs rather than sale to retailers has the effect of increasing LGC scarcity, which increases it price, which increases demand for new renewable generation. It’s a roundabout but effective way of offsetting emissions.

The price for both ACCUs and LGCs has continued to increase above expected values. Since 2015 most ACCUs have been contracted to the Federal Government at around $16 per tonne, which meant only low-cost abatement projects would be eligible.

Demand from some corporates and intermediaries looking to manage climate risk has increased commercial ACCU sales in 2021, at much higher prices. The value of LGCs were predicted to fall away sharply after the RET target was reached in 2019. But since then the LGC price has stabilised and recovered, driven by scarcity caused by voluntary surrender.

There seems to be a lot of upside potential in these markets. Are they becoming carbon price proxies, or are they just the product of short-term demand?

ACCUs market

The Emissions Reduction Fund was introduced by the Abbott Government in 2015 as a soft replacement for the carbon tax abolished a year earlier. As a precursor of the Coalition’s current climate narrative, it was a purely voluntary scheme where low-cost carbon abatement projects could get Federal Government funding. Auctions have been run twice a year since April 2015, with the average contract price paid for abatement ranging from $10 to $17 per tonne of CO2.

The scheme targets relatively small amounts of abatement compared to national emissions: Australia emits around 500 million tonnes of CO2 per annum, but the scheme only buys around 12 millions tonnes a year – around 2 per cent.

Successful ERF projects have been those able to exploit very low-cost abatement: tree planting, landfill gas abatement, savannah burning. There is a growing library of methods eligible for the scheme. Scheme proponents don’t have to submit their projects to government auction. They can get their scheme certified under an approved abatement methodology with the Clean Energy Regulator and can sell verified ACCUs entirely to willing commercial buyers.

To date most projects have relied upon the guaranteed revenue from government contracts. Increased interest from businesses looking to secure a pipeline of offsets to manage their climate risk/reputation has more than doubled ACCU prices in 2021. The Clean Energy Regulator has reported project developers with flexible government contracts are holding on to more ACCUs hoping to realise higher returns. Around a million ACCUs (tonnes/CO2) are expected to be voluntarily surrendered by offsetting companies. This is still less than 10 per cent of ACCU supply and 0.2 per cent of total annual emissions. There is a lot of potential upside demand.

ACCU supply is increasing. The number of new projects registered has more than doubled in 2021. The higher prices being paid in the secondary (commercial market) suggests both buyers and sellers anticipate increased demand in the future. The commercial ACCU market is still small and illiquid. It could quadruple supply and still not offset 10 per cent of Australia’s emissions.

Progress at COP26 in Glasgow on international trading of voluntary offset markets is a long term positive for high integrity voluntary offsets like ACCUs, but has not had a bearing on ACCU prices this year. Most of the ACCU market shifts appear to be the result of domestic suppliers hoarding surplus ACCUs in anticipation of higher prices and domestic buyers starting to secure a strategic position. In a small, illiquid market with a lot of potential, they can have a big impact on price.

LGCs

The LGC market is deeper, more liquid and easier to see. Around 32.6 million LGCs will need to be surrendered in 2021. LGCs are the mechanism that delivers the subsidy for renewables generation. The number of LGCs needed to be surrendered each year is a function of retail electricity sales. An LGC is created by producing 1 MWh of renewable electricity. Retailers need LGCs to meet their obligation. They either built them or they bought them.

The LGC obligation extends to 2030, a measure designed to ensure the final projects needed to meet the 2020 target could get ten years of LGC revenue – otherwise they might never get built. Once the RET target was met LGCs prices were expected to fall towards zero by around mid-decade. Prices have been supported by the LGC offset market. This year more than 5 million LGCs will be purchased by businesses and governments and voluntarily surrendered rather than sold to retailers. This creates scarcity in the LGC market, which pushed up prices and increases demand for new renewables projects.

The LGC market is finite and time limited. It will end by 2030, and state-backed measures to accelerate renewables investment will increase supply. The long-term price trend (by 2030) for LGC is towards zero. On current design it is an inescapable reality.

An LGC has a lower greenhouse abatement value than an ACCU. The emissions intensity of a MWh is around 0.7 tonnes of CO2, so LGCs formally should trade at a discount compared to ACCUs, which represent a full tonne of abated CO2.

But because all this activity is voluntary, there are no formal rules. Voluntary surrender is still as much about branding as emissions, and renewables are more popular than landfill gas. The LGC voluntary surrender market is five times bigger than the ACCUs, and still trades at a carbon premium.

Conclusion

There has been significant increases in both LGC and ACCU prices in 2021. Demand for these high integrity measures to offset or abate emissions is increasing from Australian companies. The size of these unconventional markets is small but growing. European carbon prices are currently trading above AUD$100/tonne. This is a result of short-term gas scarcity. But the sustained nature of ACCU and LGC price increases suggests the market is valuing abatement at a price above $40/tonne.

Currently Labor is ahead on the betting to win the next election. It is more likely to put in measures to increase demand for these certificates.

The Clean Energy Regulator is launching its carbon exchange in 2023. This will increase transparency and liquidity for the ACCU market, renewable certificates and guarantee of origin certificates for products. Given the scarcity value of carbon appears to be higher than any of these current certificate trading prices, more transparent markets is likely to reveal this. It’s also a small but necessary step towards international linking of carbon.

How low can you go? SA minimum demand

A milestone was reached last Sunday when South Australia became the first region in the NEM to register negative scheduled demand. This occurred at 12.35 on Sunday 21 November, when the figure reached -46MW. This means that all electricity demand in the state was met by either rooftop solar or non-scheduled wind. There was around 100MW of the latter, so rooftop solar didn’t quite manage to meet demand all on its own. But that day is not far away.

This didn’t mean there were no other large generators running. South Australia’s grid would not be secure with just wind and solar on their own. AEMO requires two synchronous generators to be on at all times, which in South Australia means gas plants. So Torrens Island and Pelican Point were running at their minimum levels.

Also, the interconnector was exporting surplus electrons to Victoria. That meant there were other large generators on (wind and solar) but their output wasn’t needed locally.

It’s fortunate that this didn’t occur in January last year, when South Australia was islanded due to the interconnector being damaged. If exports weren’t possible, then the requirement to keep two gas plants on would mean that the only way to balance demand and supply would have been to curtail rooftop solar. This has already happened  – in March 2021 – when demand was low (but not as low as last Sunday) and AEMO saw a risk of islanding.

Another fortunate development was the implementation on 1 September of new rules on how to settle the market when demand is very low or negative. AEMO’s formulae that it applies to allocate non-energy costs such as frequency control break down when demand is negative. There is also a risk that if some retailers or large users have net negative demand and others net positive, that those with net negative demand actually receive payment meaning that those with net positive demand end up paying more than the total costs to be allocated. The new rule allows AEMO to work around this by using average demand figures over a longer period.

These issues indicate that though many observers assume that being able to periodically supply all demand from rooftop solar must be a good thing, it’s actually a real challenge. So what can be done to manage these situations?

The obvious solution is to find new sources of demand at these times to soak up the excess supply. SA Power Networks have introduced a “solar sponge” tariff that means electricity is cheapest between 10am and 3pm. Wholesale prices in south Australia are now routinely negative at this time, too. Accordingly, new retailer IO Energy is offering a retail tariff that is a third of the price at this time compared to their peak prices on either side. Commercial and industrial users should also be able to source power deals that enable them to take advantage of the middle of the day surplus.

This is all predicated on households and businesses deciding to care about when they use electricity. Households typically just want reliable supply at a reasonable price and businesses prefer to focus on their actual business rather than a side-hustle of playing the electricity market. But if retailers and other service providers can package things up in a way that means customers don’t have to think about it, there’s money to be had.

The South Australian government is also developing a Virtual Power Plant (VPP), that will orchestrate Tesla batteries scattered around Adelaide. The latest phase focuses on supplying batteries into public housing at no charge to the occupants.

The biggest impact in the next few years, however, is likely to come from Project EnergyConnect, linking NSW and South Australia, with a transfer capability of 800MW. This will provide a new way to balance excess solar – export it to NSW. The new interconnector will also allow AEMO to run the South Australia grid without any synchronous generation which will further assist with the energy balance at minimum demand periods.

In the longer-term, NSW and the rest of the NEM will start to look like South Australia and export will cease to be a solution. At this point, we will all have to look to demand flexibility to balance the grid, especially if AEMO is still relying on having some synchronous generation online. Part of the hype around hydrogen is its potential to soak up excess solar, but it’s premature to assume hydrogen, Li-ion batteries or any other one technology will be the magic bullet.

The coalition that doesn’t like coal

Two months after the general election, Germany finally has a new government. The cause of the delay was intense haggling between the three-way coalition of the Social Democrats, Free democrats (i.e., liberals) and the greens.

Unsurprisingly for a government with a significant Greens presence, the parties’ joint manifesto includes ambitious climate targets. For the energy sector, the key targets are phase out of coal “ideally” and 80 per cent renewables by 2030.

Looking at renewables growth over the previous decade, the 80 per cent target may look fairly straightforward. Their share has grown from around 12 per cent in 2010, to 46 per cent last year. If Germany can add 34 per cent in one decade, surely it can do so this decade, too?

Source: Clean Energy Wire

There may be some challenges along the way. 2021 may report a fall in renewables share for the first time as consumption recovers from COVID-19 restrictions and the European wind drought has an impact – after the first half of the year, the renewables share was around four per cent lower than last year.

Also, to date Germany has used energy efficiency as a key tool in managing emissions and so as the chart above shows, electricity consumption has been stable over the last decade. But as other sectors decarbonise partly through electrification and green hydrogen, annual demand is expected to rise – the electricity industry association predicts 700TWh annual demand by 2030, almost 20 per cent more than 2019 (2020 being an abnormal year). So even if the percentage change for the 2020s is similar to that achieved through the 2010s, the absolute level of deployment will need to be significantly higher.

To that end, Germany is reorienting regulations to put climate first. The climate goals will override other environmental concerns, Germany’s states will be required to set aside 2 per cent of their land for wind farms, rooftop PV will become more or less mandatory for new buildings, and the offshore wind sector will need to ramp up heavily.

There’s also the question of what will provide the other 20 per cent. The nuclear phase-out is expected to be complete next year, and so if coal is gone by 2030, gas is likely to be the main source of the non-renewable 140TWh supply. Currently gas provides about 90TWh/year and so this implies a ramp-up of up to 50 per cent of gas generation. Germany imports virtually all its gas. Notably, the 177-page policy document put together by the coalition has no mention of the controversial Nord Stream 2 pipeline from Russia, currently stalled in the German courts. But it’s hard to see where else the gas is going to come from. So, ironically, the climate goals may make Germany – and by extension Europe – even more dependent on fossil fuel imports from Russia.

At least gas is a flexible power source. It will need to be. To average 80 per cent variable renewables across the year will in practice require renewables to produce 100 per cent or more much of the time, since during periods of Dunkelflaute (dark, still winter weather) they may only be contributing 10-20 per cent. This represents a real grid management challenge. Fortunately – unlike Australia – Germany is in the midst of several other countries from whom it can import and export as it needs to. Some of these countries have stable nuclear (France) or highly flexible hydro (Sweden, Austria) that will provide an important anchor for the continent as a whole as it decarbonises.

The vast-scale of renewables deployment will shift the pattern of location of generation. Much of the wind generation, for example, will be in the north of the country (or beyond, in the case of offshore wind) while most of the larger cities are in the South, near the nearly-defunct coal fields of the Ruhr. Already there is significant congestion on the north-south transmission links. But NIMBYism has stalled the necessary transmission upgrades. The solution has been to agree to run these links underground. Just one of them, Suedlink, will as result cost 10bn euros (A$15.6bn). more are likely to be required to meet the new ambitions.

Realising the cost of all this, the coalition has decided to stop the regressive policy of loading up household electricity prices (industrial users are exempted) with charges and taxes that pay for the transition. Instead, it will go on to the federal budget.

Like most countries, Germany has treated the electricity sector to date as an “easy” source of emissions reductions. But its 65 per cent emissions reduction target for 2030 (on the way to net zero by 2045) will also require more effective action in other sectors (notably transport and heating) than it has managed to date.

Chart of the week – emissions intensity of electricity by state

The emissions intensity of electricity generation in Australia has been falling steadily this decade. The two events that caused the single biggest one-off reduction in emissions intensity were the closures of Northern (brown coal) in South Australia in 2016 and Hazelwood (also brown coal) in Victoria in 2017.

South Australia’s 60 per cent plus renewables blend puts its now just below 0.2 tonnes of CO2 per MWh. By contrast Victoria’s high emissions brown coal generators hold it at the top of the emission rankings, but it has been making steady improvement since the closure of Hazelwood. In fairness to Victoria this dataset from AEMO does not factor in transfers. So the extra brown coal electricity sent from the Latrobe Valley to keep South Australia’s lights on is counted in Victoria.

Queensland’s emissions intensity has remained static over the past three years, as increased rooftop solar PV is offset by growing demand, met by increased coal fired generation.

Interestingly South Australia is showing a seasonality in its emissions intensity: emissions increase in winter when solar generation is lower and reduce in summer when there is more solar. This has probably been assisted by recent mild summers, as high temperatures would increase dispatchable generation.

Chart 1: emissions intensity of electricity by state over time

Source: Boardroom energy analysis from AEMO data