AEMC’s blinkered, unresponsive policies are fragmenting the NEM
In recent years it’s become clear that the AEMC has stopped listening . We hear a bit these days about politicians being tone deaf but it seems to me that the AEMC has become simply deaf.
It’s partly a problem with the “executive chairman” concept long recognised in the private sector. In the private sector the “chair” is generally non executive for what seem to me to be obvious reasons.
In our view when AEMC executive chairman John Pierce retires, he will leave an industry in a bigger mess than when he started at the AEMC.
Consider first that complaints from transmission companies about the “do no harm” rule imposed on new generators – and the transmission companies should surely know what’s best – are ignored.
Transmission planning rules and issues have become so objectionable that the Victorian Government has stepped outside them, and perhaps is not to far away from moving right away from the cooperative federalism embodied in the National Electricity Law.
The only check on Pierce is the Energy Security Board, and the ESB has obvious key person risk in Kerrie Schott surely closer to the end than the beginning of her career.
Arguably if the AEMC had a better sense of what was required there wouldn’t have been any need for the ESB. Looking at the progress and direction being taken in the Western Australian market shows how common sense can build a coalition of willing participants when compared to a blinkered ideology.
The changes required in the NEM have been obvious for some time and as the years have passed what were shadows have moved into ever sharper focus, but the AEMC has been mired in fighting the last war instead of the current one.
The most fundamental problem is a lack of a carbon objective in the National Electricity Law. Unfortunately, this was one thing the Finkel Report didn’t make clear. No-one knows the NEL and its implications better than Pierce, but he has stood silent on this issue.
The perceived inadequacy of the current system has led to a major review of the NEM being undertaken by the ESB.
The agenda that the rules need to organise around
In ITK’s view the objectives are:
- – Decarbonise the NEM;
– Replace about 70% of the generator fleet in the NEM over the next 15 years;
– Develop a control system that doesn’t rely on synchronous generation or inertia;
– Integrate a distributed energy sector likely to be nearly as large as the utility side into an efficient, low carbon whole of generation/consumption system;
– In the process of doing the above maintain system security and reliability and keep the price manageable.
I would argue that virtually no policy implemented by the AEMC is particularly helpful to that agenda or indeed any agenda other than trying to remove any ability to plan the future of the NEM. The table below has the first four policy areas of interest that came into mind. I excluded 5 minute settlement but it could be the exception.
Let’s think about the AEMC focus areas over the past decade relative to those goals. Maybe we could start with integrating distributed energy. The AEMC years ago could have done much better at requiring rules for the registration of distributed energy devices.
The AEMC’s one major rule in this area was “the power of choice” for communicating meters which essentially said “we have no interest, you consumers buy the meters you want”.
As a result we don’t even know how many communicating meters there are or what their capabilities are. Same with inverters. Not enough planning is going to cause lots of rework, refits and increase costs to consumers. Under prescription is as bad as over prescription.
Another example would be network household tariffs which according to micro economic theory will be most efficient if they are based on marginal costs.
The AEMC loves this and has been trying to push network providers that way for years. But guess what, the vast majority of household network costs are determined at the time the network is built. If we look to West Australia they plan to move household tariffs to accomplish a policy goal, eg incentivising consumption to move out of evening peak time.
COGATI and MLFs: The AEMC’s 20 year battle
Nowhere is the AEMC’s complete obstinacy and pursuit of ideological perfection over a good outcome more obvious than in the COGATI (co-ordination of generation and transmission investment) and the MLF (marginal loss factors) reform process.
No matter what the industry says, no matter what the evidence, the AEMC knows best. As a reminder, the AEMC has been pursuing nodal pricing or some version of it since about 2008, with the 2008 version killed off in part by existing user rights fights.
In a recent investor survey run by the AEMC, 100% of respondents said that they believed COGATI would raise their cost of capital by more than 1%. Yes you read that right, every single respondent said the same thing.
That is a significant increase driving up costs to consumers in several ways, not just because it raises the required electricity price to justify a project but also in that it restricts the amount of new supply.
And it’s not just survey respondents talking their book, it’s easy to see in a theoretical sense because financial transmission rights [FTRs] increase fixed costs thereby increasing the variability of cash flows and increasing project risk.
What is COGATI supposed to achieve?
It’s supposed to overcome the problems of “unconstrained access”. That is, simply, put the current right of a new generator that fulfils its performance standards to be connected to the NEM.
Unconstrained access gives rise to “congestion risk”, too many generators wanting to access the same transmission line. Congestion risk is to be managed by “nodal pricing” and by the use of a new financial instrument “Financial Transmission Rights” [FTRs]
In Pierce’s mind, or at least in the AEMC’s original plan, and this seems to me to be one and the same thing, FTRs were to be used for transmission planning but that was such an obviously stupid idea that even the AEMC has retreated.
One objectionable feature of the AEMC approach is the failure to consider alternative approaches
Innogy, a German renewable developer, presented the AEMC with a comparative survey by Hertie Institute authors in late 2019 when the AEMC was looking at marginal versus average loss factors. The paper noted that there are over 4,100 other academic papers dealing with some aspect of locational pricing, and yet there is no consensus whatsoever on the best way to do it.
The conclusion from that paper was that there is no consensus on the best way to manage grid access for new generators.
FTRs are designed to stop two largely trivial problems.
– Transmission companies managing return to customers of Intrastate settlement residue because customers pay on an average MLF of 1 and generators less than 1. And;
– A “race to the bottom” that is supposed to happen when out of merit generators outcompete lower cost ones on constrained transmission lines.
Objections to FTRs include:
– Increases WACC. NERA, the AEMC’s consultant states that it thinks WACC’s will reduce. A survey of investors demonstrated that 100% of investors responding to the survey believe that WACC had already increased 1% or more due to COGATI and another 1% to the related issue of MLF uncertainty. ITK believe that in terms of the cost of equity, NERA’s theoretical arguments are unconvincing, little more than armchair theorising and even then weak at best. We look at this point below.
– FTRs have inherent uncertainty because transmission constraints can arise beyond the control of FTR buyers and sellers. Obvious examples are generation restrictions in North West Victoria and in Northern Queensland.
– Existing generators feel with some justification they should get FTRs for free, but this benefits them v everyone else. The AEMC has not dealt to this issue yet because they know it will be highly contentious.
– Cost v benefit analysis is unsupportive
-FTR rollover risk, where the length of an FTR contract is likely to be shorter than the life of the generator.
– “Eye off the ball” risk. This too is my own idea, and it’s simply that the main issue in the NEM is the transition , and that there are so many more important issues to worry about than FTRs
AEMC commissions NERA to write a report supporting the AEMC
Actually that headline is not the way the AEMC would put it, and I’m sure NERA objects strongly to having its carefully written, lengthy report characterised as a puff piece to support the AEMC process, but that’s the way it looks to me.
NERA presented a report to the AEMC on the benefits of financial transmission rights and locational marginal prices as found in overseas markets. The report is long both in text and theory with plenty of micro economics diagrams. The executive summary states in part:
Nonetheless, the benefit of introducing LMP and FTRs for dispatch alone based on these benchmarks (range of AUD 30 million to AUD 137 million per year) exceeds the latest- available estimate of implementation costs (for Ontario, a one-off cost of AUD 149 million) on a Net Present Value basis.
The report also states both the benefits and the costs may be understated. No allowance for annual costs appears to be included in the estimates. Such a lot of angst for such a small benefit.
In very round numbers, for 200TWh of electricity per year at a forward price of say $50/MWh amounts to $10 billion. Even if the exercise does save $100 million a year, even if it all goes to consumers, it’s a 1% benefit.
For 15 years the AEMC has been fighting tooth and nail for something that produces a 1% benefit. Never mind that in the NEM as a whole the transmission system, the control system and the carbon mix are not fit for purpose.
Regarding the cost of capital, NERA is at odds with generators. Generators, who responded to a formal AEMC survey without excepted stated that they expected the introduction of FTRs would increase their cost of equity.
We knows this because the AEMC ran a formal but not public survey for investors/generator companies which in part asked about the impact of ALF/MLF and separately about the impact of COGATI on the WACC. We read that a very large majority of survey responses said MLFs raised the cost of equity compared to ALFs and 100% of survey respondents said that COGATI would increase their cost of capital by over 100%.
On the other hand NERA stated:
“Conceptually, we do not expect any material impact on the cost of equity as a result of access reform under the CAPM. This is because we do not expect the risk factors, such as constraint risks and basis risks, to be strongly correlated with the market return. The market return is driven by macroeconomic variables such as aggregate economic growth, and reflects long- term expectation. In contrast, the constraint risk and basis risks are determined by variations in local electricity prices, which in theory would not co-vary with market return movement.“
Even if we stay within the limited CAPM framework, we think NERA’s view is wrong. Generator cash flows do vary with the economy as is blindly obvious in the current situation. Anything that increases the volatility of equity cash flows, most obviously debt but fixed costs as well will increase Beta and thereby the cost of equity. You can see this by breaking Beta down to the correlation between the market and the asset:
B = COV (asset, market)/(variance asset * variance market)
For NERA’s statement to be true the variance of the asset cash flows would have to be unchanged or fall even if fixed costs were increased as a share of total costs. We think that unlikely.
NERA also states:
In addition, the current access model likely results in a large proportion of intra-regional congestion revenue accruing to generators thereby resulting in higher costs of electricity for consumers.
Of course this will only be true if the generation market is not competitive. If it is competitive any returns to generators will be competed away to a fair level.
REZ with transmission built into capital cost, a way forward
NSW REZ may represent a path forward that combines elements of both transmission rights and generators contributing to cost.
In this model the NSW Govt funds a strong transmission link to a REZ. Generators then get in a queue to be connected to the transmission link. Generators can then pay their share of the capital cost of the transmission link and build that into the capital cost of the project. The NSW Govt could charge something less than full cost if it wanted to pursue a decarbonisation or security policy objective.
It could charge a one-off fixed price or an annual cost but the key point is that access to transmission is locked in for the life of the generator. Annual operating costs, largely fixed in total, would continue to be recovered via TOUS but otherwise the annual transmission costs currently paid by consumers would fall on the generator in the first instance and then be recovered from consumers.
Of course the government, or if it on-sold the asset to, in this case, Transgrid once the line was full and de-risked, could continue to charge consumers rather than the generator by having the asset rolled into the regulated asset base. Generators would still be guaranteed to access to the line, essentially based on their place in the queue.
Doing it the latter way would provide a built-in incentive to get new generation approved and built in order to be guaranteed a seat at the table.
In either case the risk falls on the Govt to ensure that the capacity in the line is about right. A problem with any new transmission line into any REZ is to ensure sufficient capacity utilization.
It’s costly if only solar wants to access the line and it’s unused at night time. That’s why a mixture of wind and solar is likely to be favoured in any REZ. As for firming, if it’s battery then the economics are around transmission utilization versus being close to load and minimising physical losses.
David Leitch is a regular contributor to Renew Economy. He is principal at ITK, specialising in analysis of electricity, gas and decarbonisation drawn from 33 years experience in stockbroking research & analysis for UBS, JPMorgan and predecessor firms.