The Negative Price Puzzle — Why Generators Pay to Produce Electricity

Negative electricity prices sound like a malfunction in reality.

How can something be so abundant that the seller pays the buyer?

But negative prices in the NEM aren’t a glitch. They’re a feature: a way to clear a market where supply and demand must match every instant, and where some generators can’t (or rationally won’t) turn off just because lunchtime is sunny.

In this article I want to build a simple intuition:

• Why prices go negative

• Why coal and gas sometimes prefer paying to keep running

• Why wind and solar can bid negative and still come out ahead

• Why this can be “beneficial” (or at least rational) for everyone involved

Most commodities have storage. If the price collapses, you pile your widgets in a warehouse and wait for a better day.

Electricity doesn’t do that. The grid is not a warehouse. It’s a tightrope.

When the system has too much generation (relative to demand + export capability + storage), the market needs a signal that says:

“Please stop producing. Now.”

In the NEM, that signal can go all the way to the market price floor of -$1,000/MWh. Negative prices exist precisely to create a strong disincentive to generate when the system is oversupplied.

And the mechanism is brutally simple: AEMO dispatches the lowest-priced offers first. If you bid lower than everyone else (including into negative territory), you’re more likely to be dispatched.

That’s why you see negative bidding at all: bidding negative is often a way to avoid being turned down.

AEMO’s own summary of the modern pattern is basically the entire story in one sentence: negative prices are highest during daytime hours when operational demand is low because distributed (rooftop) PV is high, large-scale wind/solar output is strong, and coal plants maintain minimum stable output.

In Q4 2025, South Australia recorded negative prices in 48.4% of all dispatch intervals (the highest of any region).

This is the “negative price canyon”:

• Rooftop PV suppresses grid demand hard at midday

• Utility-scale solar and wind may also be strong

• Interconnectors and system constraints limit how much surplus can be exported

• Some thermal generation elsewhere can’t or won’t fully back off

• The market clears by pushing price negative to force someone to blink

Coal generators typically have high startup costs. Turning a large unit off and back on isn’t like flicking a light switch; it’s a process with fuel, wear, and risk.

So a coal plant can face a choice:

• Stay online at minimum stable load through the solar glut, even if prices are negative

• Or shut down and pay the startup penalty (plus higher forced-outage risk, maintenance, etc.)

When negative pricing lasts a limited number of hours, it can be cheaper to “ride it out” and pay the market than to stop and restart. The AER makes this point directly: paying to continue generating for a limited period can be more cost-effective than being switched off and restarting.

South Australia no longer has coal plants, but SA is still coupled to the broader NEM through interconnectors, and a large fraction of imported energy can be coal-fired (in my NEMWeb analysis for 2025 it was roughly two-thirds). When those coal units in Victoria and NSW “choose” to stay online, that behaviour leaks into regional pricing—especially when SA can’t export surplus and local demand is low.

Gas generators are usually more flexible than coal, but they still face:

• startup and minimum-run constraints (especially combined-cycle plant)

• efficiency penalties at low output

• cycling and maintenance costs

• the operational need to be “ready” for the evening shoulder

The AER also notes that some gas generators increasingly avoid short on/off cycles by offering at very high prices when they do not plan to run, because fluctuations in wind/solar can otherwise require them to come on for short periods. That’s the mirror image of negative bidding: the market is pricing the value of not being jerked around.

So gas can behave in two ways during oversupply:

• Some units back off (or don’t start).

• Some choose to stay on at low output and accept some negative pricing if the alternative is worse.

Wind and solar have marginal costs near zero, which means they’re happy to generate whenever they can—unless the price becomes negative enough to overwhelm their other revenue.

Two big “other revenues” matter:

1. Renewable Energy Certificates (LGCs)
   Under Australia’s Renewable Energy Target, eligible renewable generators can create one LGC for each MWh produced and sell those certificates.
   Liable entities (mostly retailers and some large users) must acquire and surrender LGCs each year, which is what creates demand for them.

2. Contracts / PPAs
   Many wind/solar projects also have contracts that reduce their exposure to spot prices. The AER notes that some wind and solar generators source revenue from PPAs and the sale of renewable certificates, and may operate profitably even when wholesale prices are negative.

Put those together and you get a very practical rule-of-thumb:

If your “side revenue” is worth +$X/MWh, you can bid down to roughly -$X/MWh and still be whole (before other costs/clauses).

That’s the heart of “why would a solar farm pay to generate?”
Because the spot price is not the only thing they’re being paid.

Here’s a subtle but important point: negative prices can become more frequent while becoming less extreme.

AEMO observed exactly this in Q4 2025: 86% of negative prices were between -$30 and $0, up from 33% a year earlier. AEMO links this shift to a collapse in LGC prices: LGCs averaged about $9/certificate in Q4 2025 vs $34/certificate in Q4 2024.

Lower LGC value means renewable generators have less incentive to tolerate very negative prices. They curtail sooner, or bid less negative, and the market doesn’t dive to the floor as often—even if oversupply remains common.

The Clean Energy Regulator’s own quarterly carbon market reporting also describes LGC spot prices falling as supply increases (for example, spot prices fell to $10.80 from $16.50 over the September quarter 2025, with forward prices tracking down).

So LGCs don’t just “subsidise renewables”; they actively shape the depth of negative prices.

Mostly yes—technically it’s easy:

• Solar farms can curtail output quickly via inverter control.

• Wind farms can pitch blades / feather and reduce output quickly.

So why don’t they always curtail the instant price goes negative?

Because curtailing is not free in their business model. Curtailment means giving up:

• LGC creation for those MWh

• contracted revenues tied to generation (depending on contract design)

• and sometimes operational preferences (frequent cycling / ramping constraints / compliance details)

As the AER puts it: wind and solar may bid negative to “guarantee dispatch” when conditions are optimal and competition for dispatch is intense, and some can still be profitable with certificates and contracts even at negative spot prices.

“Beneficial” depends on what you mean.

But it’s rational for each group:

• Coal and some gas: negative prices can be cheaper than shutdown/restart + wear + risk.

• Wind/solar: negative spot prices can still be profitable when certificates/contracts are included.

• The market/system: negative prices are how the NEM clears surplus supply and signals that flexibility (storage, demand response, transmission, curtailment capability) is valuable. The market price floor exists specifically to help clear low-demand/surplus conditions.

The deeper punchline is that negative prices are the shadow of a system learning how to run on variable generation. They’re not proof renewables “don’t work”; they’re proof the grid is running into a new constraint:

Not “can we generate enough?”
but “can we control enough?”

In the next article I’ll zoom in on the LGC machinery: what it is, who pays for it, why the value collapsed, and why that one policy lever quietly changes real-time price behaviour.

Note A — Price floors aren’t a “subsidy”:
The market floor (-$1,000/MWh) is a rule setting that allows the market to clear surplus supply and signals oversupply. It’s discussed explicitly in the AER’s market overview and in the NEM wholesale market settings review.

Note B — SA imports coal share:
The “~two-thirds of SA imports coal-generated in 2025” figure is calculated from NEMWeb. It’s not a published official statistic.