Boardroom Energy
Bulletin

This week

Basslink: a series of unfortunate events

– Wither gas networks?

– The Europeans are coming

– Chart of the week: Basslink history

In brief

The two week climate PR campaign that was COP26 in Glasgow has ended, and predictably UK Prime Minister Boris Johnson said it went extremely well. The Australian government gave itself an elephant stamp for the watering down of a key declaration on coal phase out. It also explained that when it told the rest of the world it would look at revising its 2030 target it actually meant it wouldn’t. Then it put out its modelling of its net zero target. Few were impressed. It’s plan appears to be to neatly gift wrap climate and energy before Christmas as a job done as it battens down for a protracted election campaign.

The ALP is deciding how to respond, with latest reports that they are mulling over three options  – all more ambitious than the Coalition. The tension for Labor will be appeasing the left while not presenting too big a target for the Coalition to attack. Labor’s state counterparts in Queensland announced they would sit tight on their existing 2030 target.

One of the differences between the main parties at the next federal election is likely to be their level  of enthusiasm for electric vehicles. There is plenty of consumer enthusiasm in Australia, just not a lot of EVS. So it will surprise few to learn that an international comparison that ranks Australia last on policies to drive EV uptake. We blogged this week that the underlying issue is lack of EVs globally, not just locally.

Former Chief Scientist Dr Alan Finkel had the unenvious task of defending the underwhelming record of carbon capture and storage (CCS), and its potential role in producing low emissions “blue” hydrogen. CCS got a minor boost with the commissioning of the first Allam cycle power plant in Texas, which would make it easier to capture CO2 emissions from power plants.

The owner of Basslink put the asset into voluntary administration rather than pay up for the extended outage of 2015-2016. We take a look into the history of Basslink and consider the lessons for other underwater cable projects.

In company news, Brookfield edged closer to acquiring AusNet, leaving APA free to pursue Basslink. The field of potential buyers of Meridian’s Australian business is down to three European giants. We look at this trend further below.

ARENA is currently launching its Bioenergy Roadmap, which will sit alongside its Hydrogen Roadmap and the Technology Investment Roadmap. One thing is for sure, the roadmap industry is booming.

Twiggy watch: Andrew Forrest has a new adversary – former Greens leader Bob Brown. Bob thought it was worth his foundation taking out a full page ad to criticise Forrest’s imaginary hydro project in the DRC.

Basslink: a series of unfortunate events

Australia’s only unregulated, merchant transmission line, the Basslink cable between Victoria and Tasmania, has gone bust. It’s a commercial failure laden with warnings and advice for a world heading towards big transmission, if only we pause long enough to heed them.

Almost nothing is as it seems with Basslink. The company might be bankrupt, but the 500MW transmission cable is anything but a failure. It has been immensely valuable to both Tasmanians and mainlanders since it came online in 2006. It continues to shift electrons under the Tasman Sea and will almost certainly be snapped up and re-contracted, with an operational life extending well into the 2030s.

What went wrong? Inexperienced contracting, inadequate contingency planning for major outages and the unique challenges of running a major transmission asset into a small monopsony market. It couldn’t happen again, could it?

Tasmanians had been living in an oversupply of hydro electricity for most of the second half of the 20th century, and had been thinking about subsea transmission to sell their power to the mainland.

In the end their hand was forced by the High Court in 1983 when it ruled against the Gordon-below-Franklin dam, launching The Greens political party and effectively ending the expansion of hydro generation in Tasmania. This forced successive Tasmanian governments to look further afield for the additional generation needed to power economic and population growth.

The commercial failure of Basslink has been a slow train coming. It is the result of a series of unfortunate events, but mostly it fell foul of the blackest of black swans. A hole in the undersea cable in December 2015 knocked Basslink out of operation for six months. This occurred when Tasmanian water storages – the state’s battery – were below 30 per cent.

The islanding of the Island state created a critical electricity supply crunch in Tasmania. 200MW of portable, containerised diesel generators were shipped over and installed in Tasmania to augment supply as Basslink’s owners frantically pulled the cable to the surface to find and repair the fault.

Hydro Tasmania later claimed the hole was caused by constant overpowering of the cable. Experts for Basslink rejected this. Major industrial customers were required to reduce activity for six months. Estimates vary but high side numbers put the total cost to the state at more than $500 million.

Based on their contract drafted in 2005 and a lengthy legal battle, Basslink were ordered in 2020 to pay $105 million to the state government and Hydro Tasmania. Last Friday Basslink’s owners, Keppel Infrastructure Trust, appeared to decide that the future risk-adjusted earnings were likely to be lower than the fine.

That the future earnings are likely to be so modest is a product of the terms of the original service and operations agreement. Tasmania is a single client, monopsony market. The state government owns and controls all generation and effectively sets the wholesale electricity price. Normal merchant transmission deals involve the asset owner exploiting arbitrage opportunities between the two connected markets.

In lieu of this, Hydro Tasmania cut a deal with Basslink to pay them a fixed fee and payments for the value of arbitrage when power prices were highest in Victoria. The value of the arbitrage was to some extent set by the state government. While specific terms are confidential, it is not sufficiently lucrative for KIT to hang around for another decade.

The tension in the Hydro-Basslink deal was Hydro Tasmania trying to maximise its revenues and sharing as little as possible with Basslink, and Basslink running the transmission as hard as possible to make some money. As importantly it revealed the operational risk of such assets, and the likely undervaluation of such outages in the pursuit of short-term returns.

Basslink has been extremely effective. Most of its early years of operation were pumping electricity into drought affected Tasmania, allowing Hydro Tasmania to save water for when wholesale electricity prices were highest and returns greatest.

There will be plenty of interest in the asset. APA is already back kicking the tyres, and others may join them. They key will be in the contracting terms. This time the deal will be struck with more experience on all sides.

Undersea transmission of electricity, even over a trifling distance of 370kms, is not without risk or cost. It will be more expensive, and take longer, to fix a much, much longer cable. The Basslink failure has no real impact on the Marinus Link proposed to augment the Basslink cable. Basslink was useful. So too would Marinus be, if someone is willing to pay for it.

Wither gas networks?

As we head towards net zero a large question mark hangs over the future of gas infrastructure. For gas assets in the competitive market – gas production, gas storage, LNG trains – the market will decide their worth and when they close. For regulated assets – some transmission pipelines and distribution networks, there is a regulatory conundrum. The basic premise is that these assets receive a low, but guaranteed, regulated return. Providing they are reasonably efficient, they’ll be able to earn a steady profit and recover all their costs including the full cost of their pipelines. But what happens if their customer base starts to shrink, whether due to government policy (such as the ACT) or to customers voting with their wallets as electric alternatives become increasingly cost-competitive?

The main regulator of such assets in Australia, the AER, has released an information paper setting out a framework for considering such issues. The problem is that customer defection (if it happens) will not happen all at once, but likely be spread over a couple of decades. The AER paper identifies that the following problems could start to emerge:

  • There will be fewer customers to cover the largely fixed costs of the network, so prices will rise.
  • Future customers will be picking up the tab for past investments that the departing customers benefited from.
  • Some of the network assets may be economically stranded.
  • Uncertainty about their ability to recover future costs may inhibit gas networks from spending money even where it is economically justified (replacing old compressors for example).
  • The price impact could cause even more customers to leave the network.

The AER then considers how it could manage or mitigate this problem, should it need to – the status quo is still an option. The options it considers can be divided into three categories:

  1. Accelerating cost recovery – accelerated depreciation, compensation for future stranded asset risk, removing capital base indexation
  2. Mitigating demand reduction – exit fees, increased fixed charges
  3. Reducing revenues – cost sharing, asset base revaluation

While they are careful to point out that it will make any decisions on a case by case basis, they appear to clearly favour accelerated depreciation. This brings forward more of the cost of long-term capital investments to the present day, leaving a lower capital base to be funded by future gas users.

While this approach is unlikely to be popular with consumers, the second category is likely to less popular still, especially the prospect of exit fees. The idea of paying for the right to no longer use gas is politically a hard sell, and likely to be blocked by jurisdictional governments.

In either case, the network still gets its money back, unlike under the third category. The idea of forgoing regulated revenue will be unpopular with networks and their investors. Even proposing a cost sharing mechanism could cause financing problems for a gas network because of the risk that it might be the start of a slippery slope.

But if a network is unable to face the prospect of reduced revenue, then there is a risk of disorderly exit, where enough customers defect that the networks cannot realistically recover all their costs from remaining customers  – even if they are notionally “captive” as the AER suggests. This then devolves into potential bankruptcy of the network, raising the possibility of abrupt cessation of service and all the problems that could cause for remaining customers. There are also risks to shippers/retailers who have contracted for future gas supply but now can’t get it to end users in such a scenario. Such a scenario could arise even if the AER applies one of the options canvassed above, if the adjustment doesn’t fully reflect the pace of change.

A disorderly exit scenario is not considered in the paper. Presumably the AER intends for the paper to reassure stakeholders that it has several options and at least one of them will be applied if necessary. But if this scenario is not considered a material risk, then it’s hard to see the justification for accelerated depreciation/other cash flow advancement, at least while the future trajectory of gas demand is uncertain. After all, the regulatory framework is set up to be in customers’ interests, with investors’ interests only relevant to the extent this serves customers’ interests. Why is it in customers’ long-term interests to pay more today if not to protect their future selves from disorderly exit? There is also no incentive for gas networks to propose cost-sharing or similar approaches to try to get ahead of the issue in a managed way if their asset value is not ultimately in jeopardy. Understandably the networks themselves do not want to contemplate such a scenario, so it’s up to the regulator to do so.

But are we just jumping at shadows? Will the issue arise any time soon? Research by Energy Consumers Australia suggests only a small proportion of residential customers have seriously considered switching off gas. Perhaps the carrot of a lower home loan rate might move the dial? In the meantime, gas networks are rushing to prove up their ability to transport hydrogen instead of methane, in order to demonstrate they have a future in a net zero world.

The Europeans are coming

With local hopefuls Telstra and Origin having dropped out, the battle for Kiwi energy business Meridian’s Australian assets appears to be between three European heavyweights. Anglo-Dutch oil major Shell is up against two electric utilities, Spain’s Iberdrola and Italy’s Enel.

All three have a global footprint and rank among the largest energy companies in the world. By market capitalisation, Enel is the second largest electricity company and Iberdrola the fourth, both valued at around A$100bn. Shell, at closer to $200bn is almost as large as the two of them together. But Enel and Iberdrola have the advantage that Meridian Australia’s core businesses, electricity generation and retail (through its Powershop brand) is also theirs, while Shell is trying to pivot into electricity to diversify away from its higher emissions hydrocarbon businesses.

Two of the three bidders are on their second bite of Australian electricity assets. Iberdrola beat off a Filipino challenger to acquire Infigen energy last year, while Shell picked up business retailer ERM Power in 2019 to add to its upstream gas portfolio here.  Even Enel already has a small portfolio of three solar farms, plus its demand management business Enel X.

What does this mean for the Australian energy sector? On the positive, the scale of interest shown by global utilities in Australian electricity businesses undermines activists’ claims that Australia’s weak climate policies makes it an energy investment pariah. These companies – along with Engie which has been in the domestic market since 2010 – bring global expertise and the ability to deploy large amounts of capital at competitive rates. They have or are developing expertise in generation, networks, green hydrogen, e-mobility and more. This will be invaluable knowledge as Australia works its way through the energy transition.

The knowledge flow is two-way – Australia is an interesting place to invest in right now as it really is on the cutting edge of renewables integration due to its skinny grid, high rooftop PV penetration and lack of neighbours to share power with. Meridian Australia is expected to fetch around A$1bn, which is small beer next to some of their individual projects such as Iberdrola’s East Anglia offshore wind farm complex (c.A$10bn) or Shell’s floating LNG plant, Prelude (c.A$20bn).

On the down side, that these European behemoths have elbowed out the local competition serves to highlight the lack of any homegrown energy champion. The same ranking of listed electricity sector companies that has Enel and Iberdrola at 2 and 4 has Origin at 110. The other remaining listed Australian electricity generation and retail company is AGL, which is falling down the list further every day.Origin does at least have a handful of international investments, most notably its share of Octopus, a fast-growing UK-based retailer and energy CRM platform.

Claims that we can somehow leverage off our energy transition to develop new export markets in cleantech need to be seen in this light. Australia is  a relatively small domestic electricity market and if we haven’t managed to use that as a base for overseas expansion to date, it’s not a given, even with a theoretical future abundance of green hydrogen, why this would be different in the future. 

Meanwhile as second tier electricity generation/retail businesses get snapped up, the two remaining listed electricity network businesses are in the process of being acquired by North American investors. It should be noted that Meridian is currently owned by a NZ company – but of course that doesn’t really feel like foreign ownership.

Nationalism aside, foreign ownership doesn’t have any direct impact on Australian consumers, thanks to our legal and regulatory frameworks. Powershop customers aren’t going to see price rises just because their retailer has a new owner.

With so many interested parties, this sale process may have other electricity asset owners wondering if now is a good time to cash in. Don’t be surprised to see another business on the auction block before too long.

Chart of the week: Basslink history

Basslink has been shifting electricity between Victoria and Tasmania since 2006. It is very much a bi-directional transmission line. Typically Hydro Tasmania will export when spot prices are high in Victoria, and import when they are low.

Originally it was assumed that Tasmania would export more than it imported, but the Millennium drought at the start of the decade reduced Tasmania’s generation capacity and made it more reliant on Victorian brown coal until around 2010. By 2011 HT was storing as much water as possible ready for the introduction of a carbon tax in 2012, which enabled it to sell into a wholesale market which had already added a plus $20/MWh premium for the carbon price, but of course HT didn’t have to pay.

The resulting surge in hydro generation during this two-year period was the reason why emissions noticeably fell during the application of the carbon tax. It was a one-off windfall gain for Snowy Hydro and Hydro Tasmania, who made the most of it knowing, almost as soon as the tax started, that it would likely be repealed after the 2013 election. The carbon tax would not have delivered the same level of emissions reductions if it had been ongoing.

The Basslink outage in December 2015 came at the end of this fast burn by Hydro Tasmania. Since it came back on line in 2016 the new normal has been cycling imports and exports through the year, with winter the time of biggest net electricity exporting from Tasmania. That’s probably because rooftop solar PV output is lower during winter, and overall prices are higher.

Hydro Tasmania still exports the maximum rating of the interconnector during summer heatwaves, but these have been less frequent and enduring in recent years. But they will no doubt return soon.

Chart 1: Basslink flows over time (MW)

Source: Boardroom energy analysis from NEM Review