Basslink: Turning a blind eye to its lessons

 

A compulsive obsessive desire to ignore the lessons of history is slowly choking us.

If Tasmania is to become a renewable energy powerhouse, shouldn’t we have some understanding how existing wind farms and the Basslink interconnector work, who profits and who pays?

What’s the difference between regulated and unregulated interconnectors and what are the ramifications of the termination of the Basslink Services Agreement announced on 10^th February, an agreement covering an interconnector that was supposed to have a life of 60+ years but is falling apart after only 15 years.

Without stopping to analyse what went wrong with Basslink we seem to be careering ahead to build an even more expensive one, whilst the State refuses to face up the underlying fiscal sustainability of a government  which is gradually falling behind in attending to its core functions.

At the centre of energy policy is a Minister who is the shareholder minister in charge of Hydro, TasNetworks and the retailer Aurora Energy, and who pretends he is able to seamlessly resolve any conflict between competing parties whilst also looking after the interest of renewable energy proponents, consumers and Tasmanian taxpayers.

If it sounds too good to be true that's because it is.

Basslink profitability

We’re on the brink of having another interconnector foisted upon us but neither the government nor Hydro Tasmania are prepared to tell us the profitability of the existing Basslink cable. The annual report tells us the quantity of electricity imported and exported but that’s it. How much money is made from the importing and exporting? Given the proposed Marinus cable will have three times the capacity of Basslink it would be useful to know. All we know from Hydro’s annual report is that it’s becoming harder to make money.  Budget forward estimates suggest lower profits in the future from Hydro.

The info which the government/Hydro prefers wasn’t discussed is all publicly available. Both AEMO, the Australian Energy Market Operator and AER, the Australian Energy Regulator publish masses of data. AEMO manages the NEM, the National Electricity Market and strives to recover costs from all participants. AER has a monitoring and enforcement role and perhaps most significantly sets network prices. OTTER, the Office of the Tasmanian Economic Regulator sets retail prices and has a regulation and monitoring role in the wholesale market.

OTTER publishes the $ value of Basslink imports and exports weekly. Here’s an example, covering NEM week 52 from 19^th to 25^th December 2021.

Exports for the week were 18.33GWh and imports 40.32 GWh. The $ revenue was $481,280 from exports and $1,469,350 from imports giving total revenue of $1,950,630 for the week. 

Over the 52 weeks from 28^th Jun 2020 to 26^th June 2021, NEM reported total BL exports of 1,021 GWh and imports of 1,612 GWh. (NB Hydro’s 2021 Annual Report reported BL exports of 1,007GWh and imports of 1,612 GWh for the financial year 2020/21. The minor difference in the export figure is almost certainly due to the financial year being a slightly different period from the 52 weeks covered by the NEM figures).

The revenue (or inter regional revenue as it’s more correctly called) from BL for the 52-week period was $42 million from exports and $31 million from imports, for a total of $73 million for 2020/21. That implies exports averaged $41 per MWh and imports $19 per MWH.

To understand what this means a bit more background is needed.

The BL interconnector, owned and operated by Basslink P/L but currently in receivership, generates revenue in a similar way to generators in the NEM, by bidding into the spot market its capacity to deliver energy, with the returns determined by the price difference and the energy flows between Victoria and Tasmania. These returns are the inter-regional revenues. Under the arrangement with Hydro pursuant to the Basslink Service Agreement (BSA), Basslink as the owner/operator of the interconnector agreed to swap the inter-regional revenue for an agreed fixed facility fee, plus performance-related payments covering availability adjustments and commercial risk sharing. The agreement also gave Hydro the rights to control the way in which Basslink bids its interconnector capacity, either flowing in or flowing out of Tasmania.

On 10^th February Hydro decided to terminate the BSA. Minister Barnett implied the recent lengthy arbitration proceedings which determined the cable was unable to perform as required, led to the termination decision. But there was likely much more to the story than that. (More about this can be found below in the section Termination of BSA).

Even though the BSA has now ended it is useful to understand how it worked. Basslink P/L receives a weekly payment from NEM representing a week’s worth of inter-regional revenues. Inter- regional revenue, whether from exports or imports is a net figure. In the case of exports, Basslink P/L buys electricity from a Tasmanian generator (almost certainly Hydro) and sells it into the Victorian market. NEM will collect the sale amount, pay the Tasmanian generator for the purchase and remit the balance being the inter-regional revenue to Basslink P/L. 

Under the BSA, Basslink P/L then forwarded the inter-regional revenue to Hydro and Hydro paid Basslink P/L the facility fee plus the performance adjustments each month. The inter-regional revenues were legally earned by Basslink P/L, as operator of the cable, but were  included as Hydro’s income pursuant to the BSA arrangement. Basslink P/L included the facility fee as income and paid all the operating expenses associated with the interconnector.

Hydro also pays Macquarie Bank a monthly fee which represents costs incurred by Hydro when it was sweettalked into a hedging arrangement with Macquarie Bank to protect it from interest rate rises during construction of the link and from interest rates embedded in the facility fee. Rates have since plummeted. The hedging arrangements adds roughly another 50 per cent to the facility fee which means Basslink currently costs Hydro about $125 million per year. That is confirmed by the Basslink current liabilities of $125.8 million listed in Hydro’s books as at 30^th June 2021. A current liability is one expected to be paid in the next 12 months.

Hence Hydro has needed to earn a lot extra to pay the fees. As we have seen total inter-regional revenues for 2020/21 were $73 million. This is before the losses from transmission over the BL cable of approx 3 per cent plus another 1 per cent when electricity is converted from alternating AC to direct DC at the beginning of transmission and vice versa at the other end of the cable. Total transmission losses are estimated to be about 5 percent which means Hydro probably made $70 million from BL trading in 2020/21. Hydro’s financials recorded expected inter-regional revenues as financial assets. The amount listed as a current asset, in other words expected in the next 12 months, was $64 million for the 2020/21 year. The actual inter-regional revenue received for 2020/21 was likely to have been $70 million. With costs of $125 million, that’s a big loss.

Money is made importing and exporting. The precondition for making profits are the different spot prices in Tasmania and Victoria.

The following table shows the average quarterly spot prices since 1^st July 2020.

Average quarterly spot prices
NEM quarters		Unit: $/MWh
		VIC	TAS	Difference
2020 Q3	July 20 to Sept 20	54	51	3
2020 Q4	Oct 20 to Dec 20	40	46	-6
2021 Q1	Jan 21 to March 21	27	34	-7
2021 Q2	Apr 21 to June 21	77	47	30
2021 Q3	July 21 to Sept 21	64	27	37
2021 Q4	Sept 21 to Dec 21	33	30	3

 

Note: The NEM year is a calendar year

The table is just a snapshot of average spot prices each quarter. There is a lot of variation within quarters, from day to day and from hour to hour. Care need to be taken when drawing conclusions. But where Vic spot prices are well in excess of Tas spot prices as occurred in 2021 Q2 and Q3, electricity will be exported to Vic. The exports in 2021 Q2 for instance, only represented 17 per cent of BL flows (both export and import) for Hydro’s 2021 year but they earned 38 per cent of inter-regional revenue for the year. The pattern continued for the next quarter 2021 Q3, covering July to Sept 2021 (the first quarter of Hydro’s 2022 year).

The earlier two quarters in the 20/21 year (2020 Q4 and 2021 Q1) saw Tas spot prices exceeding spot prices in Vic. This led to more imports during those quarters, accounting for 30% of inter-regional revenue for 20/21. Imports and exports for the rest of 20/21 weren’t significant in $ terms. The following table has the figures, prices and quantities, for inter-regional revenue.

 

NEM quarters		Exports			Imports
		Amount GWh	Value $m	Av per MWh $	Amount GWh	Value $m	Av per MWh $
2020 Q3	July 20 to Sept 20	287	6.5	23	332	5.3	16
2020 Q4	Oct 20 to Dec 20	180	5.7	32	461	11.2	24
2021 Q1	Jan 21 to Mar 21	111	1.7	15	577	10.4	18
2021 Q2	Apr 21 to June 21	444	28.2	63	242	4.0	16
2021 Q3	July 21 to Sept 21	581	33.1	57	173	3.1	18
2021 Q4	Oct 21 to Dec 21	383	8.8	23	285	7.4	26

 

Just to reiterate, the revenue figures are not the gross revenue received, but rather the differences between the spot prices in Vic and Tas.  Basslink P/L buys in one market and sells in the other. NEM pays it the difference each week. In the case of exports, it’s the extra earned by exporting to Vic compared to selling on the spot market in Tas.

Going back to the table of average spot prices, another striking feature is the low Tas spot price in 2021 Q3 from July to Sept. As the Australian Energy Regulator AER noted in its quarterly report, this was the lowest quarterly price for any of the five NEM regions since 2012. (NB The regions are Tas, Vic, NSW, Queensland and SA). The low figure was probably caused by favourable rains over winter and spring in the northern and western rivers in Tas and the increased electricity from wind with Cattle Hill and Granville Harbour wind farms now fully operational. The additional wind capacity which has doubled Tasmania’s electricity from wind from 10 to 20 per cent of our needs, will likely put downward pressure on Tas spot prices and make importing electricity a less attractive proposition. Hydro power can reasonably comfortably supply the other 80 per cent.

The latest AER quarterly report covering July to Sept 2021 also noted spot prices declined in every NEM region. There was a record number of negative prices in every region. In Victoria prices were negative 22% of the time. Under NEM rules, wholesale prices can fall as low as negative $1000 a megawatt-hour, meaning in theory generators have to pay to deliver power into the spot market. Prices generally fall into the red around the middle of the day when wind and solar generators and coal power plants are competing to dispatch their energy. There’s not much point sending electricity into a market with negative prices but stopping and restarting generators can be even more costly. One of the market responses to negative prices is to instal batteries with the aim of withholding electricity from the market and waiting for a better price. This is now occurring on the mainland. Many will remember then Treasurer Scott Morrison pooh-poohing Tesla’s large battery proposed for South Australia back in 2017:

“"I mean, honestly, by all means have the world's biggest battery, have the world's biggest banana, have the world's biggest prawn like we have on the roadside around the country, but that is not solving the problem.”

People making investment decisions disagreed. Batteries are becoming more widespread, even being proposed to run alongside aging coal-fired generators hoping to get a few more years of use before they go the way of dinosaurs. Batteries will tend to lower price variations, the very thing which has made exporting to Vic via Basslink a profitable (at times) activity for Hydro.

Lower spot prices and smaller differences between Tasmanian and Victorian prices were looking likely to impact Hydro’s profits. The forward estimates in the Budget papers showed payments from Hydro to the government (income tax equivalent payments and dividends) declining in real terms.

A doubling of electricity from local wind generators has already lessened the opportunities to import electricity profitably, and the increasing use of batteries on the mainland will lessen the opportunities to export electricity profitably. That’s been Hydro’s dilemma. Casting a giant shadow over Hydro was another 10 years of Basslink where costs of $125+ million per annum would have coincided with inter-regional revenues of about $70 million per annum, but under increasing pressure. Some of the shadow may have been removed with the decision to terminate the BSA. (More on this below in the last section headed Termination of the BSA.)

Paradoxically the Marinus interconnector would likely make it even harder to profit from the arbitrage advantages that arise when spot prices in Tasmania and Victoria differ. By its very nature a regulated interconnector will reduce arbitrage advantages that may exist between NEM regions as the costs and benefits of a regulated connector and are spread across all network users. Diminished arbitrage advantages across the network are inevitable.

One doesn’t expect Hydro or the government to shout about Basslink’s unprofitability from the rooftops. But the kneejerk response to claim commercial-in-confidence at every turn rather than assist the understanding of publicly available information is a step too far in a world where the peddling of falsehoods is becoming the norm rather than the exception.

As we will see below, another reason the government and its electricity businesses don’t want to dwell too much on the financial lessons of Basslink is because they see themselves building a completely new electricity system for the 2030s. TasNetworks’ new Chair Roger Gill made this clear during the December 2021 Leg Co scrutiny hearings. Planning for the future is commendable but that shouldn’t mean ignoring past lessons. If Tasmania is going to produce twice as much energy as it needs surely some understanding of how trading via the current interconnector works, what are the problems and how will the new electricity system make it better.

Regulated vs non-regulated interconnectors

There are currently three major interconnectors in the NEM….. Basslink, Murraylink and Directlink.

Basslink, at 370km long, is the world’s second longest subsea electricity interconnector with a nominal capacity to export 594 MW from Tasmania to Victoria, and import 478 MW. It cost $874 million to build and was commissioned in April 2006. It’s owned by Basslink P/L a subsidiary of Keppel Infrastructure Fund listed on the Singapore Stock Exchange and part owned by the Singapore Government. Basslink P/L is currently in Receivership looking for new owners. Basslink is part of NEM but is an unregulated link.

On the other hand, both Murraylink and Directlink are regulated interconnectors. Both started as unregulated links but swapped because life was too difficult. Both were unviable as unregulated links. Becoming regulated means spreading the costs amongst a wider number of network users.

Basslink P/L was not a true MNSP Merchant Network Service Provider, as unregulated links are often called, because of the exclusive arrangement with Hydro which entailed the payment of an agreed facility fee which removed most of the trading risks from Basslink P/L. Murraylink and Directlink didn’t have sugar daddies when trying to survive as unregulated interconnectors. Basslink is about to experience what life is like without a regular facility fee.

Prices that can be charged by regulated interconnectors are determined by AER, the Australian Energy Regulator. This is no different to TasNetworks’ transmission and distribution networks, both of whose prices are regulated by AER via price determinations every five years.

Murraylink is an interconnector between South Australia and Victoria. approximately 176 kms long, rated at 220MW and commissioned in 2002 at a cost of $177 million. It is currently owned by Energy Infrastructure Investments Group EII, but operated by APA.  The ownership of EII is split between APA with 19.9%, Japan-based Marubeni Corporation with 49.9%, and Osaka Gas with 30.2%. APA is an ASX listed company which has recently bought $99 million worth of Basslink P/L’s debt, for a price likely to have been less than the face value of the debt, but which gives APA a seat at the table when discussing future ownership of Basslink with the Receivers.

The main transmission service providers in each region are ElectraNet in SA and AusNet Services in Vic. How the system of regulated interconnectors work can be gleaned from AER’s determinations The following cut and paste  from page 10 of  Murraylink determination discusses the expected impact of the regulated price for the Murraylink interconnector on residential electricity bills.

 The annual electricity bill for customers in each region in the national electricity market will reflect the combined cost of all the electricity supply chain components – wholesale generation costs, transmission and distribution network costs, the retailers’ costs and profit margin, and the cost of environmental policies including subsidies for renewable energy, such as solar feed-in tariffs. The transmission network charge component of electricity bills for SA and VIC represent about 9 per cent of an average customer's annual electricity bill in SA and about 6 per cent in VIC.

Murraylink’s network charges are built into transmission charges in SA and VIC. The main transmission service providers in each region (ElectraNet in SA and AusNet Services in VIC) take a portion of Murraylink’s allowed revenue in developing the applicable transmission charges to apply to and collect from customers in their respective regions. Murraylink is then compensated by ElectraNet and AusNet.

Murraylink is a small component of the broader transmission networks that serve SA and VIC. This small proportion explains the modest impact this final decision on Murraylink is likely to have on average annual electricity bills in SA and VIC.

Murraylink’s value as determined by AER for price setting purposes, it’s RAB or Regulated Asset Base, is around $120 million. What it may have cost to build ($177 million) is irrelevant. AER determines a price based on what it reckons the asset is worth. For comparison purposes TasNetworks’ transmission RAB is valued at $1,287 million and its distribution assets at $1,737 million. In simple terms AER allows providers to make returns on regulated assets after allowing for expected expenses including capital upgrades. The current returns are around 5 per cent pa. Distribution costs are between three- and four-times transmission costs

In the case of Murraylink the value of the link is only $120 million. Hence there is not a huge impact on electricity prices in Vic and SA, the two connected States. As AER noted:

The transmission network charge component of electricity bills for SA and VIC represent about 9 per cent of an average customer's annual electricity bill in SA and about 6 per cent in VIC.

Directlink is a smaller interconnector designed to link northern NSW with southern Queensland, 59 km in length and commissioned in 1999 at an estimated cost of US$70 million with a total rating of 180 MW. Directlink’s RAB is currently about $145 million.

Directlink is also owned by EII, the same as Murraylink. APA is the operator. Given that APA has indicated it sees Basslink’s future as a regulated interconnector, it wouldn’t be hard to visualise Basslink with the same owners as Murraylink and Directlink, and all operated by APA. The termination of the BSA makes this possibility much more likely. Basslink will struggle to survive as an unregulated asset, just as Murraylink and Directlink did, now that Hydro has stopped propping it up with the monthly facility fee.

When Basslink becomes a regulated asset, the AER will assess the value of its RAB which will determine how much will be paid to Basslink’s new owners. This amount will be recovered from network users in the same way as for Murraylink, described above. The issue for Marinus is whether agreement can be reached to enable Marinus’ costs to be recovered for all net work users. At this stage other States aren’t keen for their electricity users to fork out for Marinus

Meanwhile Marinus is not the only new interconnector on the NEM drawing board. Humelink a proposed interconnector in NSW is facing the same hurdles as Marinus. These were laid out in detail by Bruce Mountain, Ted Woodley and Hugh Outhred  in a recent article in Renew Economy.

Specifically the authors said:

Those in favour of projects in the Report (AEMO’s 2021Transmission Cost Report) and in the Integrated System Plan (ISP) invariably suggest that AEMO’s inclusion of such projects amounts to an endorsement of their economic benefit.

However, AEMO’s ISP is a system-wide expansion study in which committed generation projects are taken as inputs.

This means that in the assessment of HumeLink, for example, since Snowy 2.0 is deemed to be committed, the ISP treats this as a sunk cost.

But of course Snowy 2.0 and HumeLink are intertwined complements. Like a train station and a train line, the one has much less value without the other.  Treating one as “committed”, biases the decision to commit the other.

To address this, in evaluating the economic merit of HumeLink, it is therefore essential to include the cost of Snowy 2.0.  AEMO does not do this – as explained Snowy 2.0 is treated as a committed project and so its costs are ignored in the ISP’s analysis of HumeLink.

This means that AEMO’s analysis can not conclude that HumeLink is an economically sensible transmission expansion, it can only conclude that having ignored the costs of Snowy 2.0, its model finds that HumeLink is necessary in order to not waste the storage potential of Snowy 2.0.

This fundamental modelling issue is not widely understood.  It is important that it is, since the inclusion of projects such as HumeLink in AEMO’s ISP is treated by influential but distant actors – such as parliamentarians – as credible proof of endorsement.

Considering the importance of AEMO’s position on power system development, it is essential that AEMO states more clearly the basis upon which major augmentations such as HumeLink and Marinus Link are included in its development plans, and how the economic merit of such inclusions should be understood.

The case for Marinus stacks up, so we’re told, because there’ll be 200 per cent of renewables looking for a market. At the same time the case for 200 per cent renewables makes sense because there’ll be a 1500 MW cable ready to transport electricity to mainland markets. Marinus is needed so we’re told, to be able to export all the surplus wind power, which coincidentally is only being built to take advantage of Marinus. It’s an intellectually dishonest, self-fulfilling circular proposition.

If the 200 per cent renewables projects and Marinus were considered as one project requiring a viability assessment before proceeding, they wouldn’t be built. It would have already happened if they were viable.

Instead we have a system, a conspiracy of subterfuge, which is the only way that otherwise uneconomic projects can proceed. This system is supported by two other dodgy factors. The first of those is being able to ignore a range of costs by treating them as sunk costs and therefore not relevant when assessing project viability. The second is being able to have the relevant assets accepted as regulated assets thereby guaranteeing participants guaranteed income over a longer period. That’s the prize being sought. Any public policy errors are papered over with sunk costs and guaranteed income streams.

Both Murraylink and Directlink were nonviable as unregulated assets. They both needed to become regulated and have all network users help give them a return.

On the matter of sunk costs, it mustn’t be forgotten that being categorised as such doesn’t mean they don’t have to be paid. It only means they can be ignored when assessing project viability. Basslink had sunk costs. The Expert Panel which reported on Basslink in March 2012 explained how the $50 million deposit paid by Hydro when Basslink was being built and all the hedging arrangement entered into during constructions were treated as sunk costs and ignored when assessing the project viability. Yet Hydro is still paying the $150+million of construction hedging arrangements incurred prior to 2003. These are included in the monthly fee paid to Macquarie Bank . They may be sunk costs but they still impact Hydro’s cash flow.

A grand plan or a hotpotch of competing interests?

The major problem with providing promoters an opportunity to treat project costs as sunk costs is that it encourages aberrant behaviour. If that’s not moral hazard on steroids then what is? If a viable project results, it will be by good luck rather than sound planning. The authors of the Renew Economy paper further explain the problems with projects like Marinus:

The fundamental commercial driver for transmission companies is to maximise revenues through building more regulated assets. Hence, there is an inherent incentive to underestimate costs to get a project to the proposal stage.

History bears this out.  We are unaware of any transmission project where the cost decreased after the initial estimate.

Naturally, a project develops momentum as it progresses, and it becomes more difficult to stop, even with the inevitability of escalating costs and decreasing (even negative) net benefits.

Estimated costs need far more scrutiny, right from the initial stages of a proposal, and some form of reprimand when shown to be understated.

History certainly does bear this out. Basslink at $874 million cost double its original estimate. And that figure doesn’t include the $150+ millions of sunk costs conveniently overlooked.

Having assets that will be regulated is the key. Regulated returns where costs are borne by all network users is a big attraction.

Marinus’ major proponent, TasNetworks is beastly careless how much Marinus will cost as it won’t have to fund it. Any addition to its RAB is always welcome as it means more guaranteed income which all network users will pay.

TasNetworks’ position highlights the inherent conflicts between all parties…. the government, Hydro as the major generator, TasNetworks as the transmission company, private investors hoping to step in and build more generation assets to reap the rewards of guaranteed income streams and consumers looking for lower prices. It is highly unlikely that the conflicts will be satisfactorily resolved as the Minister in charge in is Guy Barnett, someone who is yet to come across a problem that wasn’t the fault of his political opponents, and every proposed solution is disingenuously described as being in the best interest of all Tasmanians. And by the way, there’s no such thing as a subsidy. Anything that gives a return can’t be a subsidy if evidence given by Mr Barnett to the recent parliamentary hearing into government electricity businesses is any guide.

However, we are starting to see conflicts play out.

TasNetworks has received grants to explore/justify Marinus’ viability knowing it won’t have to fund it and knowing that any increase in its RAB with more on-island transmission assets will be given a regulated price by AER which will enable it to get the necessary funds from Tascorp to construct the assets. Abundant moral hazard rarely leads to sound public policy decisions.

The government insisted Hydro sign a power purchase agreement PPA with the Granville Harbour Windfarm. Hydro was obviously unimpressed because it lists the subsidy given to Granville as a Community Service Obligation alongside support for Cricket Tasmania and the Hobart Hurricanes. Why would Hydro as a generator be interested in subsidising another generator? It makes a semblance of sense for a retailer like Aurora Energy to enter into PPA with a windfarm like it did with Cattle Hill, but to insist Hydro as a generator do so suggests heavy handed meddling by the government.

The PPA between Hydro and the Woolnorth Wind Farm WWF signed to facilitate the 2014 sale of 75 per cent of WWF to Shenhua , a Chinese State-owned company (Hydro retains the remaining 25 per cent) disguises an ongoing subsidy to WWF. In its latest reporting year, the 2020 calendar year, WWF received a $14.66 million subsidy from Hydro for purchases of electricity and an estimated $15 million for the purchase of large scale renewable energy certificates LGCs . That’s a total of $30 million. The cash dividend for the year received by Hydro from WWF was only $4 million. Hence Hydro’s 25 per cent share in WWF produced cash losses of $26 million. Then there’s the non-cash effects. At the end of the 2020 reporting period WWF listed the future benefit of the deal to sell LGCs to Hydro as being worth $96 million. That means there must be a corresponding liability in Hydro’s books of a similar amount. It’s included in Hydro’s onerous contracts which were listed as a liability totalling $240 million at 30^th June 2021. Different accounting rules apply to the treatment of LGCs and electricity purchases. The former are financial assets and need to be valued at fair value each year. The expected value is recorded as an asset (or liability) and any movement recorded in the P&L each year. Electricity purchases on the other hand are recorded when the purchase occurs. Hence expected subsidies of future electricity purchases aren’t recognised until electricity is delivered. Now $96 million, the estimated future subsidy to WWF via LGC purchases (NB the agreed purchase price is greater than the expected market price of LGCs. Hydro will make future losses buying LGCs from WWF at an agreed price and on-selling them in the market for less) may not be a particularly large figure but in balance sheet terms it’s 5 per cent of Hydro’s equity. It also means Hydro’s interest in WWF which is listed as being worth $71 million, actually has a negative value of $25 million. Heaven forbid if Senator Abetz ever finds out his electricity bills are subsidising the Chinese government. (More info on WWF’s PPA is presented below in the section Who will benefit?)

It’s all very well to say an onerous contract was not onerous at the time it was signed but risk managers should have pointed out the problem that if a PPA does become onerous and requires Hydro to find cash, it is likely to occur at the same time as Hydro will itself be feeling cash flow pressures. As Hydro reaches into its pockets to satisfy the onerous contracts it will likely find there’s less cash there for the exact same reasons as caused the PPA to become onerous, viz a fall in electricity spot and LGC prices. A double whammy. Government policy of propping up other generators via PPAs can only ever undermine Hydro. It is little wonder Hydro is under increasing pressure. Governments encouraging others to feast at Hydro’s table looks like a dumb idea.

That didn’t stop the government from giving public support to Twiggy Forrest’s desire to buy a sizable chunk of Hydro’s electricity for his proposed hydrogen plant, possibly as much 20 per cent of Hydro output which is around 9,000 GWh pa, at a giveaway price of $20 per MWh, as was reported by ABC reporter  Emily Baker. .If Hydro could otherwise sell the power for $45 per MWh that amounts to a subsidy of $25 per MWh. 2,000 GWh means the subsidy amounts to $50 million pa. Fortunately, Hydro seems to have resisted government demands to subsidise Twiggy to that extent. Hydro’s Ian Brooksbank was  reported as saying Hydro’s role in supporting the possible hydrogen industry in Tasmania would be via the provision of a “firming” service, to fill the gaps which may occur with the erratic nature of electricity from wind. To not have resisted would have meant Twiggy would have eaten most of Hydro’s lunch, a dumb idea given its unique suite of assets.

All the above serves to emphasise that there are a host of conflicting interests in the electricity space which Minister Barnett tries to pretend can all be satisfied by the 200 per cent renewable target/Battery of the nation/Marinus/ hydrogen/Jobs jobs jobs/lower prices leaving everyone being better off. It’s a silly notion. There will be winners and losers who need to be identified before we reach the point of no return, which the campaign of misleading information and unsubstantiated assertions appears designed to achieve before people realise the full implications of the grand plan.

Who will benefit?

The government’s 200 per cent renewable energy goal will require more wind farms plus a new connector. It may be useful to have a closer look at a current wind farm operation and at Basslink to understand where money comes and goes. The publicly available financial statements for WWF, which produces about 1,000 GWh pa or about 10 per cent of our needs, and for Basslink P/L, the owner operator of Basslink (currently in Receivership) are an essential starting point to understanding the $s involved.

First let’s look at WWF. The latest financials are for the calendar year ending 31^st Dec 2020. The following is the profit and loss statement:

A healthy profit of $132 million is evident in the latest year, not bad for a company with net assets of $264 million. Most of the profits are attributable to subsidies from Hydro. Specific items needing a closer look are sales revenue, operating expenses, and fair value gains.

This is the breakup of sales revenue:

Energy sales relates to electricity. Environmental energy products are large scale generation certificates LGCs. Both are covered by PPAs with Hydro.

In the 2020 year WWF produced 1,036 GWh of electricity. 2019 was a windier year producing 1,205 GWh (These figures are from NEM figures posted on Wiki). This suggests LGCs are bought at a contracted price of around $46 per LGC. (NB One MWh creates one LGC meaning one GWh produces 1,000 LGCs and 1,000 GWh produces 1,000,000 LGC. LGC prices have fluctuated between about $20 and $90. Currently they are in the low $30s).

In the case of electricity sales, the revenue fall over the 2 years is quite striking. From approx $75 per MWh to $33 per MWh. These are the gross amounts obtained by selling through NEM.  These aren’t the net amounts that WWF end up with after the PPA agreement with Hydro. To work out the net amount one needs to look at the breakup of operating expenses.  This is the relevant snapshot:

 

As can be seen in the 2019 year WWF paid $33 million to Hydro as a result of the PPA, and in 2020 it received $14.6 million (the receipt is shown as a negative expense).

That means, in net terms, WWF received $57 million in 2019 and $49 million in 2020, round about $46 per MWh in each year. When the market price is below that figure Hydro pay WWF. When the reverse occurs, WWF pays Hydro. That’s how PPAs work.With more wind coming on line, spot prices will likely fall meaning Hydro will be subsiding WWF until the deal expires in 2028.Ouch.

Altho’ both electricity and LGCs are covered by a PPA they are treated differently in the financial statements. Electricity sales are treated just like any goods and services are treated by any business. Sales are recorded at the time of sale. Any possible future subsidy is ignored. There is not sufficient certainty as to the amount of the future subsidy. The actual subsidy only becomes apparent at the time of sale. This is why the power purchase agreements with major industrials in Tasmania which accounts for almost half of Hydro’s total sales (in quantity terms) do not appear as onerous contracts in Hydro’s books The sales of electricity to major industrials are recorded at the time of sale and no provision is made in the financials for possible future contracted subsidies. (altho’ they may be indirectly included when generation assets are valued based on future income.)

LGC’s on the other hand are financial assets. A PPA which includes financial assets need to be valued each year for accounting purposes. The future expected subsidy to be received for LGCs needs to be estimated. Changes over a year are recorded as fair value changes in the P&L, with the value  at the end of the year included in the balance sheet as an asset. In 2020 WWF included $106 million as a fair value gain for the year. This was the change in the fair value of LGCs for the year. At the end of 2020 WWFs financial asset re LGCs was recorded as $96 million. This represents what WWF expects to receive from Hydro for LGCs over and above the market price. In other words, the expected future LGC subsidy from Hydro.

From Hydro’s viewpoint it records a similar figure as a liability, viz the value of the onerous contract with WWF.

In 2020 the subsidy re electricity was $14.6 million. This was actually paid. In the case of LGCs the subsidy was also paid and included in LGC sales of $47.9 million. It is likely to have been approx $15 million for the year.

Hence the PPA with WWF meant Hydro subsidised WWF to the tune of $30 million for the year. That’s to produce roughly 1,000 GWh or 10 per cent of Tasmania’s annual needs. How much will it cost in subsidies if the 200 per cent renewable target is reached?

The operating expenses detailed above indicates the relatively small level of operating expenses, the flow on costs which spruikers of projects often use to hype their projects. Consultant/contractor costs are $11 million. This will comprise both labour and materials. The local component will only be a fraction of this. In the case of employee expenses, they totalled $4.4 million in 2020. But WWF reported to ASIC there were only 6 employees. The only conclusion is that they earned on average $750k for the year. They’re unlikely to be locals paying Tasmanian payroll taxes and drinking at the pub in Smithton.

The flow on benefits from wind farm operations are relatively small. Most wind farms are either owned by foreigners or interstate investors (in the case of Granville) so income ends up in their hands after bankers grab whatever is owing to them.

The meagre benefits that trickle down from interconnector businesses are similar to windfarms. Take a look at Basslink’s latest P&L:

This is the year that recorded the costs of Basslink’s legal outcomes with Hydro. There are lots of non-recurring entries.

The loss of $96.6 million highlights BL’s problems which led to a Receiver being appointed

BL had to write off $30.8 million in facility fees which it had previously included as income, but Hydro had refused to pay following the 2015/16 cable outage. The revenue was accordingly reduced from $84 million to $53 million.

General & admin costs of $90 million include all the compensation payable to Hydro and the State of Tasmania (not all was paid during the year), plus BL’s legal costs.

Fair value losses of $15.5 million and finance costs of $26 million relate to the costs of Basslink Groups’s finance costs for the year.

Operating outlays were minor. Network and maintenance costs were $2.8 million and employee costs were $4.2 million. There were 21 employees, so they averaged $200k each pa. Not too bad if you can’t get a job at WWF. A few may have been locals. The trickle-down effect into the local economy wouldn’t have been much more than from a neighbourhood milk bar. The downstream effects of windfarms once built are negligible. There’s little there for locals. Absentee owners bankers and other paper shufflers snaffle most of the lucre.

There’s absolutely no reason for thinking the downstream effects of a new interconnector and a landscape full of windfarms will produce a different result. Saving the planet provides a very convenient camouflage for the self-interests of a few.

 

Termination of the Basslink Services Agreement BSA

On the 10^th February Hydro put out a media release:

Hydro Tasmania confirms it has terminated the Basslink Services Agreement (BSA) as announced by the Minister for Energy and Emissions Reduction today. 

Hydro Tasmania remains willing to discuss with receivers an alternative commercial model that could include key elements of the BSA, that would provide funding during the receivership and help transition the asset to an alternative commercial model. 

Consistent with this Hydro Tasmania has made a good faith offer to the Receivers for an interim arrangement, under which the key elements of the BSA would be put back in place for one month whilst the parties discuss possible alternative arrangements.

The Minister for Energy and Emissions Reduction’s announcement on the same day said:

Consistent with the Tasmanian Government and Hydro Tasmania’s decision in November last year to protect and progress Tasmania’s legal rights in relation to the Basslink cable, Hydro Tasmania has taken another step in that process terminating the Basslink Services Agreement (BSA).

This follows the 2020 arbitration concerning the cause of the 2016 major Basslink outage, which found in the State and Hydro Tasmania’s favour, confirming the link cannot meet the capacity requirements set out in the BSA and that the owner of Basslink should pay compensation to the State.

Since November last year, Hydro Tasmania along with the State, has been in negotiations with the receivers of Basslink regarding an alternative commercial arrangement.

The termination of the BSA will not impact Tasmania’s energy security, which remains on firm footing, with very strong hydro storage levels, the Cattle Hill and Granville Harbour wind farms, while the cable will remain in service.

The Tasmanian Government and Hydro Tasmania will continue to engage with Basslink's financiers and receivers on alternative commercial arrangements, suitable for the receivership period.

Tasmanians can be assured that our energy security is stronger than ever and that the Government will continue to act in the best interests of Tasmanians.

Lat’s try to make sense of this:

The actual default by BL which gave Hydro room to terminate the BSA is not clear….. whether it was the arbitrator’s findings about the cable’s shortcomings or due to the appointment of a receiver or because the Receiver intends to sell the cable to another party, it’s not clear. All may be grounds for default by BL which then allowed Hydro to quit the agreement.

With the termination of BSA, BL’s Receivers will retain the ongoing inter-regional revenues IRR and Hydro will cease paying the facility fee.

In most months the IRR is less than the facility fee so Hydro will be better off.

BL will continue to buy Hydro’s electricity if it wishes to export but the profits from the deal will belong to BL. Likewise electricity will still be imported by BL.

It is not clear what will happen to the arrangements with Macquarie Bank MBL currently costing about $4 million per month. Part of what Hydro pays MBL each month relates to the sunk costs incurred pre 2003 so no doubt they will still need to be paid, but part relates to the hedging arrangements re the interest rate component of the facility fee. If the facility fee ceases to be payable what happens to the facility fee swap arrangement with MBL? Another lawyers picnic?

The Basslink Group owes financiers approx. $640 million. It’s actually not on BL’s books, rather it’s owed by an associated company called Premier Finance Trust Australia. What is on BL books is an interest swap arrangement designed to hedge interest rates on the Group’s borrowings. Interest rates have fallen so the latest fair value of the hedging arrangement shows a further liability of $162 million. That’s an estimate of the amount needed to quit the hedging deal.

BL also has a liability of $23 million labelled Provision for decommissioning costs, which is an estimate of the costs needed to clean up at the end of the cable’s life.

Another of BL’s liabilities is the amount still due to the Tasmanian government of approx. $50 million following  successful legal action.

There is also a $50 million deposit paid by Hydro to BL back in 2003 which was to be offset against the facility fee payable from 2029 onwards. If the fee is no longer payable, what happens to this deposit?

The messiness of BL’s financials suggests it is unlikely that anyone will buy the company as a way to acquire the cable. Instead, what will likely happen is the cable itself will be sold.

The BSA had another 10 years to run at the time it was terminated. At that time BL’s income was via the facility fee from Hydro of approx. $85 million pa, which gave BL an EBITDA  (earnings before interest tax depreciation and amortisation) of roughly $50 million . With the facility fee being government guaranteed the earnings multiple may have been as high as 10 times giving BL (or at least the cable) a value of $500 million.

However with the termination of the BSA, the cable’s income will be the inter-regional revenue and that is a riskier proposition which further means a lower earnings multiple will be needed to calculate the cable value. If the IRR is estimated to be $70 million pa, that makes the EBITDA $35 million. Applying a 7 times earnings multiple gives the cable a value of $245 million.

The termination of the BSA means the cable is now an unregulated asset without a guaranteed monthly facility fee which means it’s value could fall by as much as 50 per cent.

By terminating the BSA Hydro will also have given up any pre-emptive rights it may have had to acquire the cable should it be sold. But because it (and the Tasmanian government) are still owed money by BL, it still has a place at the negotiating table to discuss BL’s future.

For the cable to become a regulated asset a new owner will have to be found. It’s likely APA will be involved. It doesn’t make much sense for Hydro to have a share. That only made sense if the BSA remained intact for another 10 years, and Hydro ended up paying the facility fee to itself.

It would make more sense if TasNetworks ran BL, but it is hellbent of trying to get Marinus to the start line.

 Whatever the value of the cable for the new owner, its likely Regulated Asset Base RAB will end up being roughly similar once the cable becomes a regulated asset. That in turn will underpin how much the new owner will receive as a regulated asset.

Which still leaves the big unknown….. how will Marinus be regulated? How much and who will pay? It is likely  that whatever Marinus ends up costing, if the estimated cost is currently $3.5 billion, the final cost will be well in excess of that figure, how much will the value of its asset base be for the purposes of determining the cost burden on all network users. The RAB figure will be far less than the cost, that’s for sure. Which means that much of Marinus’ cost will be immediately written off. It’ll be reminiscent of Tas Irrigation which builds water infrastructure. Using a very rough rule of thumb, for every $3 spent on new works, $1 is recouped from the sale of water rights, $1 of value remains on TI’s balance sheet being the value of the asset which earns money from water rights holders each year and $1 is written off. In the case of TI there are arguably spill over benefits (forgive the bad pun) from building new water infrastructure. The growth of industries which benefit from the new water justifies the community’s investment in an asset which loses 33 per cent of its value as soon as it is built.

For Marinus the picture won’t be anywhere near as rosy. The likely spin off benefits of Marinus and new wind farms, as shown above by examining the affairs of existing wind farms and interconnectors are likely to be considerably less. For a State facing momentous fiscal challenges it would be reckless to spend so much for the benefit of so few.

What is quite extraordinary is that the latest BL financials cheerily expected the BSA to last until 2072. But barely a few months later, the cable may only be worth 25 per cent of its original $875 million cost, after a mere 15 years of life.

Yet we are contemplating doing the same again, going down the same path, without the slightest interest in learning any of history’s many lessons.

 (updated 21st Feb to correct a typo)