Boardroom Energy
Bulletin

This week

Will traditional energy businesses win the battery race?

Is climate branding about to get more expensive for corporate Australia?

You can get it forecastin’

– Chart of the week: UK retailer carnage

In Brief

The Federal Parliamentary year has ended for 2021, and with it the political career of Greg Hunt. Hunt was an early mover on climate change policy within the Coalition. He was its first Shadow Minister for climate change, and as Environment Minister designed the Safeguard Mechanism and Clean Energy Fund for the Abbott Government, while helping to dismantle the Gillard Government’s carbon tax. Hunt’s policy tools have endured and both Labor and the Business Council have suggested the Safeguard Mechanism be adapted to frame national carbon policy. Hunt’s legacy in Australian climate policy is probably in the same basket as the Chinese diplomat Zhou Enlai’s 1972 evaluation of the French Revolution: “too early to say”.

Labor leader Anthony Albanese is ahead in the sports betting and picking his fights carefully. He has rejected tighter standards for vehicle emissions that might push up the cost of cars and is set to announce a 40 per cent emissions target by 2030. Importantly there are no new policies to help get there. Now that’s a small target.

Engie has announced a 150MW/150MWh battery on the site of its closed Hazelwood power station in Victoria’s La Trove Valley. This follows AGL starting to build a 250MW/250MWh battery next to its gas power stations in Adelaide. It looks like the first movers without big government support will be sited on old power stations. We take a closer look.

The Clean Energy Regulator has just released its excellent Quarterly Market Report for September 2021. It reports another 2-3GW of new large scale renewables in 2021, another 3.2GW of rooftop solar PV, and strong growth in demand for offsets and voluntary surrender of related certificates, like LGCs. We take a look at the possibly big changes to the global offset market made at the Glasgow meeting in November to see what impact this might have on the supply of very cheap offsets from the not-so-clean Clean Development Mechanism.

ANZ has decided it will follow NAB and keep lending to oil and gas companies, but only if they can show how they are getting out of the oil and gas business. The AEMC is promising lower electricity prices and lower emissions, just in time for Christmas. Conversely the International Energy Agency is warning of higher commodity prices pushing up the cost of renewables.

Twiggy watch: Andrew Forrest is spruiking for more customers for his gas import terminal at Port Kembla. While he’s at it, he might need a few more for his SunCable project too.

Will traditional energy businesses win the battery race?

Boardroom Energy has been tracking the emerging utility scale storage sector for some time. We’ve noticed, in compiling our battery project list, that there are a lot of projects proposed but very few getting built – unless they get government support. But in the last week, ground has been broken on two separate, privately-funded projects. The common theme is that both are located on the site of old power plants and are being built by large gentailer businesses. Is this going to be the winning business model for large-scale batteries in the NEM?

The two projects in question are the ENGIE/GIG battery at the site of ENGIE’s former Hazelwood power station in Victoria and AGL’s Torrens island battery in South Australia. The Hazelwood battery project, using Fluence batteries, is 150MW/150MWh and is expected to be completed by November 2022. The AGL battery is being built by Wartsila and the 250MW/250MWh project is expected to be operational early 2023. Unlike the Hazelwood site, Torrens Island still has traditional generation operating, the old Torrens Island Power Station (TIPS) B gas plant and the new Barker Inlet fast start gas plant. TIPS A is about to be retired. So, AGL will have three complementary resources with different start-up profiles that it can manage collectively.

While this is both companies’ first big battery project in Australia, AGL has plans for several other batteries, including more at the site of its existing thermal plant. Planning approval has been obtained for a 200MW/800MWh battery at Loy Yang A in Victoria’s Latrobe valley and a 500MW battery at Liddell in NSW’s Hunter Valley.

The other two large gentailers, Origin and Energy Australia, have similar plans even if they are not as far advanced. Origin have announced plans for a battery of up to 700MW capacity at Eraring in NSW, while Energy Australia have agreed to build a 350MW battery at Jeeralang as part of its deal with the Victorian government to close down it coal plant at Yallourn in 2028.

While one can’t be certain all these batteries will get built, there’s good reason to think that the traditional energy suppliers will have a head start against the other 19,000MW of proposed battery capacity.

Batteries are highly flexible in their location. The footprint of a large battery is not small, but it’s a lot less than most equivalent-sized generation facilities. And batteries don’t rely on weather patterns, access to fuel or water, unlike the varying types of generation. So, a project with even a small cost advantage can trump other projects. The advantages these projects all have are three-fold:

Network location – because they are being built on the site of existing/recently decommissioned generators, they are in a great network location. The Hunter and Latrobe valleys are fairly close to the major load centres of Sydney and Melbourne respectively and have excellent transmission links to them. Torrens Island is virtually on the outskirts of Adelaide and is more or less the centre of the South Australia grid. Accordingly, loss factors are favourable, congestion risk is low and system strength is robust. By contrast renewables projects – one of the other obvious location points for batteries  – are often on the edge of the grid where they may suffer from system strength or marginal loss issues or are waiting for a Renewable Energy Zone to be built out to them.

Existing infrastructure and skilled labour force – grid connections should be cheaper for these projects. The planning documents for the Eraring big battery indicate that the project will be able to connect to the network at an existing switchyard (which as it happens has a spare gantry bay for the connection). Origin will only have to run lines for 400m from the battery substation to the switchyard. Most greenfield projects would have to cover the cost of the local TNSP building a new connection point and have a longer distance to travel to connect to the shared network. The companies also have an existing skilled workforce. While big batteries employ far fewer people than  a coal plant, they will still play a role in helping that workforce transition by providing some local ongoing employment.

Retail offtaker -all four companies highlighted have household retail businesses. While they have not necessarily confirmed that the retail arm is contracting with the battery or provide peaking services, for example, it’s an obvious option. It’s looking likely that retailers will need to meet the Retailer reliability obligation (RRO) in each region annually, and big batteries will be a useful source of RRO-qualifying contracts.

Coincidentally, this week also saw the final rule for integrating storage into the NEM. This will help all battery proponents by clarifying the way batteries are registered, dispatched and charged for non-energy services. The latter has been a bone of contention, with many battery proponents unhappy that batteries won’t get a blanket exemption from paying transmission charges (TUoS) when they are importing power. As the AEMC has been at pains to point out, the rule does not mean that batteries will definitely be charged TUoS, but that they have the option to either pay prescribed charges or negotiate with the local TNSP and see if they can get a better deal. The experience to date is that storage projects often end up not having to pay TUoS, because the times they are charging are times when the grid is not under stress and so they are not adding incremental cost. Because the big gentailer battery projects are connecting into existing transmission infrastructure at a point at which there is a lot of transfer capacity, they are likely to be amongst the projects that can negotiate zero TUoS. So that’s another potential advantage.

The gentailers largely missed out on the renewables boom – even though they underwrote a lot of projects, due to their renewable energy target liabilities. They are not going to make the same mistake with batteries.

Is climate branding about to get more expensive for corporate Australia?

The pace and cost of Australia’s fast growing, multi-million-dollar climate neutral “industry” may be significantly impacted by the biggest outcome at the recent climate negotiations in Glasgow.

Forget all the speeches and the pledges, the big reform from COP26 was to finalise revised rules for voluntary carbon trading markets. Known as Article 6 of the Paris Agreement, these changes to eligibility for what can be counted as global carbon offsets may materially impact some major Australian companies. Around two-thirds of offsets voluntarily surrendered this year will come from abatement projects in developing countries (1 million tonnes from ACCUs, 6 million tonnes from renewables certificates, 12 million tonnes from developing countries).

The credibility of at least some of these offsets created under the Clean Development Mechanism (CDM) has been questioned by activists and others for the past two decades. That hasn’t stopped some Australian companies from using them to deliver against their latest carbon neutral commitments, at a bargain basement price that may indeed be too good to be true.

How cheap? In the Clean Energy Regulator’s most recent quarterly carbon market report Certified Emissions Reductions (CERs) created under the CDM cost 56 cents a tonne. That compares to more than $40 for a tonne of offsets from ACCUs and LGCs. The price of a tonne of carbon in Europe is well north of AUD$100 per tonne. Current prices for Certified Emissions Reductions on the UN platform start from $2.50 a tonne.

How can the cost of abating the same thing vary so much? Well, exactly.

The Clean Development Mechanism is the world’s biggest carbon offsets market. It was created back in 1997 in the development of the Kyoto Protocol by the United Nations, allowing rich countries with fixed targets to pay for abatement in poor countries without targets, to help reach their targets.

The CDM was one way of addressing the rich-poor country divide that sits at the middle of global negotiations on climate. It created a development vehicle to transfer investment from rich countries and started to establish a global market for carbon. That was the good news.

The bad news was that verification of the abatement and the projects in poor developing countries was inconsistent. There have been constant allegations that some projects are sold and re-sold, some are completely confected, that the emissions reduction was being counted in both the selling and purchasing countries. There is also the big problem of additionality, meaning whether a project, and therefore the abatement, would have proceeded without selling any CERs. If it would or could have, then the CERs achieved no abatement.

The UN has been aware of this. However developing economies have stubbornly refused to give up or modify the CDM, as they understandably value the income it derived. So the UN has presided over, and effectively authorised, transactions of dubious integrity because they couldn’t broker a solution.

This had to come to an end in 2016 when the Paris Agreement replaced Kyoto, because now all countries were making pledges, and so the risk of CERs being double counted was so great as to be unsustainable. Even then it took five years to crunch out agreement at Glasgow, which will limit roll over of CERs to those from schemes certified after 2013. It agreed on a method which will limit the carryover of dodgy CDMs from a few billion, down to 320 million.

There is still work to do to determine how the methodologies will be applied and enforced to ensure genuine additionality, no double counting and complete verification. These are difficult to apply in some cases.

Mindful of this, Australia’s Clean Energy Regulator has decided to beef up the gate keeping at home. It has developed a Corporate Emissions Reduction Transparency Report designed to provide a voluntary, independent assessment of the climate disclosures by Australian companies. A pilot has just been opened and so far 11 companies have opted in for 2022. It’s still unclear how deep the CER will go in verifying actual tranches of CERs (yes, it’s confusing) and other offsets.

There are already third-party verifiers of CDM projects like Verra and The Gold Standard, while many of these purchases are made via a market of Australian offset brokers.

Leading large-scale corporate users of CDMs include EnergyAustralia, Telstra and Westpac. The cost of voluntary surrender of these offsets is tens of millions of dollars cheaper than the fully verified local ACCUs and other less risky products. If cheap offsets disappear, either because of article 6, or because the CER rules them inadmissible for CERT reports, then meeting climate targets will get a whole lot more expensive for some companies. Even those that have stuck to local offset certificates will find there’s an increase in demand and thus price, if other companies have to switch out of CDMs.

The real test of whether the Glasgow reforms to Article 6 genuinely tighten up the credibility of offset schemes will be the price paid. Those companies relying on super-cheap offsets to validate marketing/sustainability claims may find they become a lot more expensive in the future.

You can get it forecastin’

Forecasting electricity demand in 20th century Australia had about the same difficulty as marketing VB beer. The beer became hugely successful in the 1970s, supported by a series of TV ads voiced by iconic Australian actor John Meillon. The “You can get it riding” ads first screened in 1968 and continued for more than three decades. Even though Meillon died in 1989, CUB continued with Meillon’s voice into the 21st century. The rule with selling VB was, simple: if it aint broke, don’t fix it.

In the second half of the 20th century Australian electricity demand tracked economic growth with a mechanical certainty.

There was an economic logic to it: GDP growth was driven by increased economic activity, population growth and increased labour productivity. All these factors drove increased demand for electricity. Electricity demand even dipped during the 1991 recession. Forecasting demand, and the infrastructure planning that derived from it, was as safe as houses.

Chart 1: Electricity demand and GDP, Australia 1980-2020

Source: ABS, Australian Energy Statistics

That predictable world began to change in the 21st century. There were big licks of industrial demand that began to dial off as the economy de-industrialised. (Mitsubishi, Adelaide 2008, Kurri Kurri (Aluminium), NSW 2012, Port Henry (Aluminium), Victoria 2014, Ford, Geelong 2016, Holden, Adelaide 2020).

The headlines for this were framed by the closure of Australia’s car industry and one third of its aluminium smelters. Energy efficiency advocates claimed minimum standards in appliance efficiency and residential lighting technology were having an impact. Rooftop solar PV systems began to have an impact on scheduled (dispatched) electricity demand from around 2010, and this has increased over the decade. The economy has steamed along with very steady annual growth, but electricity demand wavered and then basically plateaued since 2010. It was a complete decoupling of the relationship.

Forecasting demand has proved to be an increasingly difficult task for transmission companies, and AEMO since 2012. And it is unlikely to become much easier in the future.

Chart 2: NEM demand forecasts and actuals, 2010-20

Source: AI Group

Scheduled demand has continued to underperform most forecasts over the past decade. AEMO’s reliability outlook looks a decade ahead to inform transmission and generation investment. There are multiple factors that could drive demand in either direction over the next decades.

Demand reducers

  • More rooftop solar PV
  • Continued energy efficiency improvements
  • Continued deindustrialisation
  • Pandemics
  • Mild weather (La Nina)

Demand increasers

  • Population growth
  • Increased economic activity
  • Increased electrification of transport (EVs)
  • Increased electrification of households (replacing gas)
  • Development of hydrogen electrolysis at scale, including exports
  • Hot weather (El Nino)

Some of these have considerable potential for variability. AEMO forecasts the difference between low and high electrification by 2031 to be 80 TWh a year – a potential increase of up to 40 per cent of demand that may or may not eventuate.

Chart 3: NEM electrification by scenario 2031

Source: AEMO

In a recent note to clients Morgan Stanley noted that electricity demand is down 1 per cent so far in 2021-22 as a result of lockdowns, La Nina and rooftop solar PV.

Electricity demand forecasting is critical for investment planning, especially given the likelihood of a number of large coal generators likely to exit over the coming decade. Usefully some technologies like renewable generation and batteries can be installed quickly, but others like pumped hydro take a number of years, and the planning and approval for major transmission infrastructure is also time intensive.

It is likely that planners will continue to err on the side of caution, and take a high side view of demand to ensure adequate supply. But given the technology uncertainty around many of the key drivers, demand forecasting is likely to be a challenging occupation for decades.

Chart of the week: UK retailer carnage

The eye-wateringly high gas prices Europe is suffering under have driven a mass collapse of energy retailers in Great Britain. To date 26 retailers have failed this year, as they found their hedging strategies inadequate to the squeeze between soaring wholesale prices and the retail price cap for household energy.

In only a few months, the GB retail energy market has been wound back several years. Back in the early 2010s, the market was dominated by six suppliers. Five of these were the successors of the privatised electricity businesses (SSE, Scottish Power, Eon, nPower and EDF), while one was the incumbent gas supplier (British gas) who had become the largest electricity retailer through aggressive marketing of dual fuel deals. Small suppliers collectively held one per cent of the market.

Concerned about market dominance and lack of customer switching to new suppliers, the energy regulator Ofgem actively encouraged new entrants to the market and promoted switching. Around the same time however, it introduced a retail price cap.

By 2017, more than 50 new suppliers had entered the market and the market share of the six incumbents was down to 80 per cent. Some of the new suppliers were already up at about a million customers (there are over 30 million retail energy accounts in GB).

Chart 1: Household energy suppliers in GB over time

Source: Ofgem

The big 6 market share continued to erode through 2019 and two of them exited the market. SSE sold its retail business to OVO energy, and nPower was rolled into Eon. But much of this has been undone by the recent wave of collapsing suppliers. Customers are protected from supplier failure through a scheme called the Retailer of Last Resort (ROLR) which means they get picked up by another supplier and are free to switch away from their new supplier if they wish. Naturally, the larger retailers are best placed to be the ROLR and the new big 6, including Ovo and fast-growing Octopus energy (part owned by Origin), have picked up 1.5m new customers in the last few months. Shell, with the backing of its leviathan oil and gas business has also taken on ROLR customers.

However, the collapse of Bulb energy, which was the 7th largest supplier has resulted in 1.7m customers needing a new home. This is too  big a chunk for any one other company to take on at once and Ofgem has put the company into special administration. Presumably in the long-term the big retailers will take on these customers, perhaps sharing them around. As a result, the small suppliers’ share has collapsed back to 2 per cent, where it was eight years ago.

Chart 2: Household energy retail market share by supplier size

Source: Boardroom Energy analysis of Ofgem data

Could this happen here? Potentially, yes, as there are a lot of similarities between the GB and Australian retail markets. Both are – on the face of it – competitive, with many suppliers and relatively high switching rates. Both have retail price caps and ROLR schemes to protect customers from collapse. In both cases, it will always be harder for smaller retailers to effectively hedge against wholesale market volatility. On the other hand, some small suppliers claim that Ofgem made a number of bad decisions and failed to act on pleas for support that exacerbated the crisis in GB.

In any case, this may shed some light on Victorian regulator ESC’s recent finding that customers have a preference for larger suppliers. While the ROLR provides strong protection for customers, it’s unsurprising that customers instinctively head for retailers least likely to collapse.