Why peak electricity capacity matters
Australia’s peak electricity demand is set to grow significantly thanks to data centres and electrification of vehicles and appliances — even after accounting for self-consumption from solar and batteries.
Actual and forecast regional annual 50% POE maximum operational demand by state, 2025 ESOO Step Change and 2024 ESOO Central scenario, 2020-21 to 2054-55. AEMO
To meet this demand we’ll need more generation capacity, particularly peak capacity, like gas peaker plants and battery storage, to come online — probably a lot (see increases in utility storage and flexible gas over the next 25 years below). Ideally, we’ll also have a lot more demand management — such as flexible demand that can scale down at peak times — so we need less generation.
NEM capacity from 2009/10 to 2049/50 in the Step Change scenario. AEMO
How to incentivise capacity investment
Some markets, like PJM in eastern USA, incentivise more generation capacity with a capacity market, where generators are paid to be available and provide electricity during peak demand when called upon. Australia’s National Electricity Market (NEM) doesn’t have a capacity market, but rather incentivises capacity through several levers including having the highest wholesale electricity Market Price Cap (MPC) in the world ($20,300/MWh for FY25/26)1.
A high MPC means peaking generators and batteries stand to make more money during high price events, and so developers are incentivised to build more. The case for having a higher MPC has been that it would incentivise more generation and reduce energy costs for consumers in the long term.
The NEM’s MPC will increase from $20,300/MWh in FY25/26 to $23,200/MWh from 1st July 2026 — a larger increase than the typical annual adjustment with inflation.2 This begs the question — is it working?
Future values have been adjusted using RBA inflation forecasts. ECA/Baringa
Pros and cons of raising the Market Price Cap
The case for a higher MPC is that an energy-only market like the NEM needs scarcity prices high enough to incentivise investment. Gas peakers and batteries run infrequently — less than 5% of the time on average — and rely heavily on a small number of high-priced intervals to recover their costs. If the MPC is too low, these assets can’t earn enough through the wholesale market alone to justify new builds, so reliability suffers and consumers end up paying more for electricity in the long run. The Australian Energy Market Commission’s 2023 determination argued that raising the cap would bring forward new investment, ultimately reducing prices and improving reliability for consumers over the long run.
A higher MPC comes at a cost. Baringa/ECA estimated that increases to the MPC since 2019 have resulted in $4.7 billion in additional wholesale costs to consumers across the NEM, over $3 billion of which was in 2024 alone.
The rising MPC doesn’t just reward peaking plants and batteries — because of the NEM’s marginal pricing, it rewards everyone who happens to be generating during a high-price event. From 2019–2024, peaking capacity (gas, hydro, and battery storage) collectively earned less than 40% of total market revenues during price periods above $10,000/MWh. The majority went to non-peaking generators — predominantly coal (but also solar/wind) — that were already running anyway.
The impact of merit order
In the NEM, every generator bids the price at which they’re willing to supply electricity, and AEMO stacks these bids from cheapest to most expensive — the “bid stack” or merit order. It then dispatches generators from the bottom up until supply meets demand. Every dispatched generator gets paid the same price — the price bid by the last (most expensive) generator needed to balance the system. So, if a gas peaker bids $15,000/MWh and that bid sets the price because there’s sufficient demand, a coal plant that bid $50/MWh also gets paid $15,000/MWh for that interval.3
An example of SQE
I (Claude) made a simplified visualisation4 of how marginal prices change with increasing demand, and how much infra-marginal rent lower-priced sources of generation like wind, solar, and coal can generate during high price periods. Have a play to see how high marginal prices benefit low-priced generation.
Baringa/ECA also argue that the high MPC was set in a time when there were few other levers to incentivise capacity, but that’s less true today given the advance of state (e.g., LTSAs) and Commonwealth (e.g., CIS) out-of-market programs to incentivise capacity. Given that, “there is reason to reconsider whether the current value of the MPC and its anticipated rise continue to be fit-for-purpose when considering investment signals”, they say.
The next post in this series will be a breakdown of the implications of market design for electricity prices, particularly with the rise of data centre load. Please subscribe if you’d like to see that post and more about the intersection of energy and AI.
All views are my own, and do not represent my current or previous employers.
- New Zealand doesn’t technically have a price cap, but prices are effectively bounded at NZ$20,000/MWh by its scarcity pricing mechanism (I think — it’s hard to find a more recent source than 2013). As of 2022 scarcity pricing had never occurred in New Zealand. ↩︎
- The lesser-known cousin of the MPC, the Cumulative Price Threshold (CPT), is also increasing. The CPT limits how long high wholesale prices can be sustained. ↩︎
- Marginal pricing exists to encourage generators to bid their true short-run marginal cost — the actual cost of producing one more unit of electricity. If you’re a coal plant and it costs you $40/MWh to generate, you should bid $40/MWh. You don’t need to inflate your bid to make money, because you’ll be paid whatever the marginal generator sets. The “infra-marginal rent” that cheaper generators earn (the gap between their costs and the clearing price) is what funds their capital recovery and profits. ↩︎
- The main simplification to call out is the choice to make the bidding periods 1 hour rather than 5 minutes to line up with the h in MWh. ↩︎