MLFs – an underappreciated risk to renewables projects

Marginal loss factors (MLF) are an often overlooked element of the regulation of the National Electricity Market (NEM). The Australian Energy Market Operator (AEMO) has just released its draft MLFs for 2019-20. These results provide a sharp reminder of the risks posed by MLFs to generation projects.


What is a MLF? A MLF is a measure of the marginal transmission losses for a generator (or load) on the NEM. It reflects the physics inherent in our electricity network – that energy suffers losses due to resistance, relative to the distance travelled between the generator and end user (and the capacity of that part of the transmission network). MLFs are a multiplier that decreases (or increases) the revenue for generators to account for transmission losses between the generator and the regional reference node (the notional load centre point of each State). Formulaically, from a revenue perspective, the impact of MLFs can be seen as follows:


Revenue = MLF x RRP x Output

Where:

MLF = marginal loss factor

RRP = regional reference price

Output = output in MWh measured at the plant gate (ie before transmission losses).


MLFs scale up (or down) generation at the farm gate. Historically, they have typically been between 0.95 and 1.05. That is, a generator with a MLF of 0.98 would get 98% of the state pool price per MWh for each MWh generated.


AEMO calculates MLFs for each generator on a financial year basis. MLFs are estimated based on the pattern of generation and demand for the last year. This accounts for when a generator generates as well as its location relative to demand. Generators that are distant from load centres (at the time they generate) and/or transmit over weak or congested parts of the transmission network will have poor MLFs (ie an MLF less than one). By contrast, generators that are close to large demand centres (that are using power at the time they generate) will have good MLFs (ie MLFs greater than one).


Exactly the same process is applied to load centres, and electricity users have their demand for electricity scaled up or down by the MLF for their local substation. This provides a fair basis by which transmission costs are allocated between generators and users of electricity.


While this is fair, there are some dynamics of MLFs that are particularly important to renewable generators that mightn’t feel particularly fair at the moment. In particular, MLFs can change rapidly as new generation is built in a particular location. Let’s consider an example of a new solar farm being built in the west of NSW (although this dynamic is broadly applicable elsewhere). This generator will initially have a very attractive MLF – often above 1 – as it is effectively supplying the local demand (and therefore saving the transmission costs of power that would otherwise be transmitted from large baseload generators – which are mainly on the east coast).


However, as more generators are built in the same area, that part of the network will move to be a net exporter of power (as generation exceeds local usage) and, hence, generation effectively then needs to be transmitted to large load centres to the east (eg Sydney). This is a long transmission distance involving high losses (as transmission losses are largely a function of distance (and voltage)) and, hence, the MLF will fall sharply.


This MLF applies to all generators in the area, so the first generator is “penalised” by a fall in MLF that affects all generators in the region. That is, the first mover is penalised by the crowding caused by late arrivals.


An example of this is the Broken Hill Solar Farm. It has seen its MLF go from well above 1 in 2016-17 and 2017-18, before falling to 0.98 in 2018-19 and an estimated 0.73 for 2019-20. These are incredible swings – a 40% decline from peak to the current estimate. This means at a constant pool price – output from Broken Hill Solar farm has fallen in value by more than 40% (and 25% over the past year).


The decline in MLFs has been driven by the surge in new generation in the same part of the network. The largest driver of MLF falls for Broken Hill Solar Farm is probably the Silverton Wind Farm (MLF 0.7990) which has also been developed by AGL/PARF (so a significant portion of the MLF is probably self-inflicted and, presumably was factored into their investment case).


Importantly, in most cases, even a fully contracted project is hit by the impact of MLF changes (there are some legacy PPAs where the MLF impact is borne by the offtaker). Most power purchasing agreements are drafted as contracts for difference, where the offtake counterparty pays the difference between a fixed price and the regional reference price (or pool price) and the project is assumed to earn the regional reference price in the spot market for its own generation. For these contracts, MLF risk sits with the project, that is a lower MLF will feed directly through into lower revenue.


The MLF changes in the latest draft decisions from AEMO are particularly violent. The table below summarises the key results – from the perspective of renewable generators.


In summary:

  • Solar has experienced larger falls in MLF than wind;

  • Victoria and NSW have had the largest declines on a State basis. In part, this reflects the relatively modest new build activity in SA compared to other States.

  • The largest moves in MLFs seem to be focused in particular areas within some states – most notably the far West of NSW and the North West of Victoria.

The next table shows the five largest declines in MLFs for wind and solar projects (irrespective of location).


The scale of the largest changes, if confirmed with the final MLFs for 2019-20 are released, will have very substantial impacts on project revenues. Typical fully contracted projects have debt sized based on target debt service coverage ratios (DSCRs) of 1.25-1.35x and debt covenants at 1.1-1.15x. This usually provides a 15-20% buffer between expected revenues and debt covenants. Clearly some of these changes are big enough to potentially to tip projects into default/lockup.


While many investors will be shocked by the draft MLFs – they shouldn’t be shocked by the direction. After they have had some time to digest the direct impacts – the next question inevitably will be – what about next year? Can MLFs fall even further? In this regard, it is worth heading AEMO’s words in the report covering the 2019-20 outcomes.

“As more generation is connected to electrically weak areas of the network that are remote from the regional reference node, then the MLFs in these areas will continue to decline.”


The key driver of the MLF falls is expansion in new capacity – particularly in locations a long way from large load centres. While AEMO have accounted for projects currently under construction and expected to be in operation in 2019-20 in their calculations, there are further projects in the pipeline. These would see MLFs fall further.


However, beyond what is currently under construction, for projects in the development phase, the fall in MLFs will be sufficient to see projects cancelled. An example of this, although there may be other issues at play as well, is Windlab’s decision to defer development of its “Big Kennedy” project in Queensland.


Variation in MLFs are a substantial source of uncertainty for new projects. While most projects obtain MLF forecasts prior to construction – the usefulness of these forecasts is pretty low. This raises the question of whether there is a better way? Once policy idea out there is a for renewable energy zones, where strong transmission networks are constructed to areas with attractive wind/solar resources, and where generators who connect to that part of the network would be guaranteed a MLF floor. This would remove a key risk for generators – which is a positive – but it is important to remember the other side of this for consumers. Putting a floor on MLFs would inevitably shift the burden of transmission losses onto power users.


All of this highlights the key role that MLFs play in allocating transmission losses – which can be substantial – amongst electricity users. If nothing else, the size of changes in the 2019-20 has ensured that they will be on market participants’ radars going forward.

© 2018 Infradebt