Electricity price regulation is never perfect


Richard Lenton

On Tuesday (19 March 2024), the Australian Energy Regulator (AER) released its draft determination for the 2024-25 Default Market Offer (DMO). The DMO determines the maximum price, or price cap, an electricity retailer in NSW, SE QLD and SA can charge a residential or small business customer on a standing offer, meaning customers who have not entered into a market-based contract with a retailer. This is its primary purpose. It is worth noting that approximately 10 per cent of residential and 18 per cent of small business customers are on standing offers and are therefore directly subject to the DMO price.

Moreover, the DMO price acts as a reference price to help the other 90 per cent of customers who are engaged in the market compare different retail electricity offers. Retailers are required to provide a comparison of their offer against the DMO price, typically expressed as a percentage discount.

The 2024-25 DMO has received significant attention, both in anticipation of its release, with speculation around which way and how much it would change relative to the 2023-24 DMO given the large increases in the 2023-24 DMO price, and since its release.

The DMO price, along with retail electricity prices, consists of several components that reflect the costs incurred by retailers in supplying electricity to customers. These components include wholesale energy costs, various environmental scheme costs, transportation costs (transmission and distribution), other costs (such as market fees) and a retail margin. The largest component is the Wholesale Energy Cost (WEC), making up approximately 40-45 per cent of the total 2024-25 DMO price. Around five years ago, the WEC made up about a third of the retail electricity price. Recent movements in the DMO price are largely attributed to fluctuations in the WEC, reflecting higher prices in the wholesale electricity market.

The AER, as part of its DMO determination process, engages ACIL Allen to assist with estimating the WEC. We have been providing this service for the past five years. Additionally, for approximately 10 years, we have supported the Queensland Competition Authority (QCA) in determining regulated electricity prices in regional Queensland.

While our company may not inherently advocate for price regulation, we acknowledge the reasons why governments implement it. However, instead of debating the pros and cons of price regulation, today we are highlighting an important change made in estimating the WEC and the reason for the change, along with exploring its potential implications.

The method to estimate the WEC attempts to emulate, albeit in a simplified way, how retailers procure electricity from the wholesale market and manage price risk. Retailers purchase their electricity needs for their customers in real-time from the wholesale electricity spot market, often referred to as the National Electricity Market (NEM) or the spot market. 

The spot market can be extremely volatile, reflecting real-time demand-supply dynamics. This poses a challenge for retailers since they are purchasing their electricity needs from this very volatile spot market and then on-selling to their residential and small business customers at a (typically) fixed price. Retailers manage this asymmetric price risk through various means, including entering into forward or future wholesale hedges at an agreed price, using their own generation capabilities or entering into financial contracts with generators. This allows them to build up a “hedge book” over time, in advance of the given determination year.

We won’t delve into the intricacies of how the WEC is calculated (you can read about that in our report to the AER[1]). However, generally, there are three factors that influence the WEC:

  1. The level and profile or shape (such as the time-of-day shape) of spot price outcomes
  2. The price level of forward contracts 
  3. The profile or shape of the demand of residential and small business customers.

The shape of the demand profile is a large driver of the WEC. For instance, if your demand profile is high when spot prices are high (such as during the evening peak period from around 6pm to 8pm) then the WEC will be higher (all other things equal) than what it would be if your demand profile was low during the evening peak and higher during daylight hours, when prices are low due to the abundance of solar production. 

Price regulation, even a regulated price cap such as the DMO, is inherently imperfect. It is not possible to calculate a WEC for each individual customer, reflecting their individual demand profiles. Even if it were possible, it would not be practical.

Instead, a representative demand profile is used to calculate the WEC for all residential and small business customers within each distribution network. This means that all customers have the same WEC, regardless of whether they are residential consumers or small businesses, whether they have rooftop PV or batteries, or whether their business operates during daylight hours or at night. Essentially, it is assumed that every customer has an identical demand profile, which is far from reality. However, as mentioned earlier, regulation is never perfect.

Prior to the 2024-25 determination, the representative demand profile used to calculate the WEC was the Net System Load Profile (NSLP). The NSLP represents the aggregate demand profile of all residential and small business customers using traditional accumulation meters, which most consumers have. Accumulation meters are manually read every quarter (or so) and provide only the accumulated demand consumed from the grid between readings, providing no information on demand shape by time of day. Interval meters, on the other hand, record consumer demand taken from the grid at a resolution of at least every half hour. Approximately 30 to 40 per cent of consumers now have interval meters thanks to the Power of Choice reforms. However, a few years ago, nearly all of us were on accumulation meters with the exception of Victoria, which implemented a mandatory rollout of interval meters over a decade ago.

AEMO, the market operator, calculates and publishes the NSLP by essentially taking the profile of all demand across the market and then subtracting from that the ‘known’ demand profiles of customers with interval meters (including large industrial customers). The remainder, known as the net profile, is the NSLP. This process is conducted within each distribution network.

For this DMO, the approach has changed slightly. The representative demand profile is now defined as the sum of the NSLP (the profile used in previous determinations) and the demand profile of those residential and small business customers with interval meters. This adjustment is appropriate, given the continued rollout of interval meters. In the next couple of years, the majority of consumers will have shifted from a traditional accumulation meter to an interval meter. The recent suite of reforms by the AEMC aims to ensure that all consumers are on interval meters by 2030 (only six years away).

Continuing to rely solely on the NSLP as the representative demand profile when estimating the WEC increases the risk of the demand profile no longer reflecting the consumption pattern of all residential and small business consumers.

However, there is a twist. The DMO deliberately represents the price for consumption from the grid. It does not represent the price for times when a customer with rooftop PV may be exporting to the grid. What does this mean for consumers who have rooftop PV and at times export their excess solar to the grid? 

Currently, the AER (and DMO) does not regulate what retailers pay consumers with rooftop PV for their PV exports. Therefore, retailers are free to choose what they pay their customers for rooftop PV exports.

Consequently, the “carve out” of solar exports should not be included in the representative demand profile, since exports are clearly distinct from consumption. 

It is not possible to separate out the PV export carve out from the NSLP data due to the limitations of accumulation meters, as mentioned earlier. However, the carve out can be separated from the interval meter demand profile. This is precisely what we have recommended to the AER for this latest DMO determination: define the representative demand profile as the sum of the NSLP (inclusive of the rooftop PV export carve out since it cannot be separated out) and the interval meter demand profile (excluding rooftop PV export carve out) when estimating the WEC for 2024-25.

Will retailers welcome this change in approach? It is highly unlikely. Excluding the carve out of rooftop PV exports results in a “flatter” demand profile, which all other things equal, is cheaper to supply and consequently has a lower WEC estimate, resulting in a lower DMO price.

Is it perfect? No. But price regulation is never perfect. 

Is it a better representation of the aggregate profile of consumption from the grid of residential and small business customers? Undoubtedly. 

So, aside from resulting in a lower WEC estimate, what are the implications of this change?

For one thing, it might influence a change in how PV exports are valued. At the moment, PV export prices (or “feed-in tariff”) paid by retailers range between approximately 5 to 8 cents per kilowatt hour (kWh). However, our analysis suggests that, given the large uptake of rooftop PV and the development of utility-scale solar farms, wholesale spot prices during daylight hours will continue to decline. Consequently, the wholesale value of PV exports is estimated to be between 1.5 to 3 cents per kWh. Obviously, customers with rooftop PV won’t want their feed-in tariffs to decline further, and as such will be unhappy with us raising this point. But this is the reality of the current situation in the market – we have a very large oversupply of solar generation and until we get substantial deployment of energy storage projects, such as large-scale batteries or pumped hydro to soak up this excess generation, the value of rooftop PV exports will remain low.

The other implication of this change in approach is that it opens the door for future consideration of different WECs for different customer types. Earlier, we discussed that the NSLP does not allow for the separation of demand profiles into different customer types. However, the rollout of interval meters and the additional data they collect changes this, and in theory, could allow us to develop representative demand profiles for key customer groups. The key question is: how are the interval meter demand data sliced and diced? 

There is no simple answer. But a good place to start is considering what might be the representative demand profiles of consumers on standing offers. After all, it is for this customer group that the DMO primarily exists. If the DMO is to continue to be of value for those customers engaged in the market, then using an appropriate set of representative demand profiles may help by providing more meaningful reference prices.