Solar farms across the NEM are earning less than 30 cents for every dollar of softening baseload prices, while LGC prices have collapsed. The wind sector is not immune and is facing higher canibilisation risks. PPA sellers may feel protected for now, but PPA buyers are already feeling the pain.
1.0 Introduction
In our Solar Eclipse Continues article from March, we documented the accelerating decline in solar bundled prices. Three months on, the picture has broadened. This article looks at both wind and utility solar across all five NEM regions, examining how well each technology captures the prevailing spot price and what is happening to the LGC revenue stream that large renewable generators earn alongside it.
Two metrics frame the analysis:
- GWA (Generation-Weighted Average) — the average spot price a generator actually realises, weighted by its own output. This is what a generator earns in the spot market.
- TWA (Time-Weighted Average) — the average spot price weighted by time, equivalent to a flat baseload position. This is the market benchmark a generator is compared against.
The ratio of GWA to TWA — the capture rate — is the most direct measure of how well a technology captures the prevailing spot price. A capture rate below 100% means the generator earns less than a flat position in the same market.
LGC revenue is a separate income stream that eligible large renewable generators can earn outside the spot power market. It is examined independently in the sections below.
2.0 Performance
2.1 Wind and Solar Capture Rates
The divergence in capture rates between wind and solar is significant across the NEM, though the picture for wind is more nuanced than it might appear. Wind generators earn a consistent premium over solar in every region — reflecting their tendency to generate outside the oversupplied solar window .
Only in Queensland does wind capture rate of 98.1% approach the flat baseload price, but the Queensland wind sector is relatively small although is expanding fast. Elsewhere, wind capture rates range from 75.5% in NSW to 57.1% in VIC and 61.7% in SA , well short of the flat price benchmark. Solar generators, flooding an already oversupplied midday window, are capturing a much smaller proportion across every region.
A QLD solar generator captures 29%, less than 30 cents for every dollar of baseload price. Victoria and NSW are not far behind. VIC solar at 30.7% and NSW solar at 40.2% are deep in cannibalisation territory. SA at 49.6% looks like the relative outlier, but that reading requires an important qualification.
| Region | TWA | Wind GWA | Wind Capture | Solar GWA | Solar Capture |
|---|---|---|---|---|---|
| NSW | $109.84 | $82.92 | 75.5% | $44.20 | 40.2% |
| QLD | $90.54 | $88.82 | 98.1% | $26.54 | 29.3% |
| SA | $92.70 | $57.15 | 61.7% | $45.97 | 49.6% |
| TAS | $97.99 | $68.14 | 69.5% | N/A | — |
| VIC | $77.63 | $44.35 | 57.1% | $23.80 | 30.7% |
12-month rolling averages to May 2026. All prices $/MWh. TWA is the time-weighted average spot price — common to all technologies within a region. Capture rate = GWA ÷ TWA.
To track the performance of each technology we measure the rolling annual power price and LGC price, and by doing so reflects the seasonal nature of the generation profile. The first chart below shows the Solar Rolling Annual Average Price by region. For reference purpose we also show the rolling annual time weighted price, and the level of curtailment on the second y-axis. To zoom-in simply swipe the x-axis, and by mousing-over will show the values.
When the incoming month has a lower spot price than the outgoing month it replaces, the rolling average falls even if the capture rate is unchanged. This is precisely what is happening now.
As documented in our May Spot Prices report, 2026 monthly spot prices have been materially softer than their 2025 equivalents in every mainland region. May 2026 delivered the lowest monthly average across the NEM in six years. Year-to-date Cal-26 averages are running approximately 30% below calendar-2025 in NSW and around 41% below in VIC. The downward trend has been in place since September 2025.
As each of these softer 2026 months rolls into the 12-month window in place of a stronger 2025 month, the rolling GWA declines mechanically, month by month. The 2025-to-2026 replacement effect means this unwinding is still in progress: there are months ahead where a relatively stronger 2025 month is facing the prospect of a weaker 2026 equivalent, putting further downward pressure on the rolling GWA.
The Wind Rolling Annual Average Price by region is shown below:
2.2 Curtailment: The hidden cost
A higher capture rate is not always a sign of a healthier market outcome. In SA, the relatively resilient solar GWA is in part a product of high curtailment. When a solar farm stops generating during periods of negative or very low spot prices, those intervals are removed or diluted from the GWA calculation, mechanically lifting the weighted average. The cost is simply lost generation and lost revenue.
| Region | Solar Curtailment | Wind Curtailment |
|---|---|---|
| NSW | 18.0% | 4.5% |
| QLD | 17.1% | 4.5% |
| SA | 38.9% | 14.3% |
| TAS | N/A | 2.4% |
| VIC | 19.8% | 15.2% |
12-month rolling curtailment to May 2026. All figures at or near record highs — curtailment is rising across all regions.
On a rolling annual basis, SA solar is curtailing nearly 39% of its potential generation, a record high and nearly double the rate of any other region. This filters out the worst-priced intervals and keeps the rolling GWA from falling as far as QLD or VIC. But a generator earning $45.97/MWh on 61% of its potential output is not in a better position than one earning $26.54/MWh on 83% of its output as the curtailment loss has to be counted.
SA wind at 14.3% and VIC wind at 15.2% are also elevated — notably higher than NSW and QLD wind at 4.5%. For wind, curtailment at these levels is beginning to represent a meaningful drag on total generation revenue, not just a statistical distortion of the GWA.
The broader point is that curtailment and capture rate are two sides of the same coin. As cannibalisation intensifies, generators face a choice between accepting lower prices or curtailing more often. Either way, revenue suffers. A stable GWA achieved through rising curtailment is not a stable revenue outcome.
2.3 The Underlying Price Has Also Fallen
The capture rate problem would be significant enough on its own. But the TWA, the flat baseload benchmark generators are being compared against, has also fallen sharply from its mid-2023 rolling peak, impacted by the Global Energy Crisis of 2022.
This matters because even a wind generator with a near-perfect capture rate is earning materially less than it was two years ago, not because of cannibalisation, but because the underlying market has repriced.
For solar, the compression is compounded: both the benchmark and the capture rate have deteriorated simultaneously.
The three-part solar squeeze — lower capture rate, lower baseload benchmark, and (as we discuss below) lower LGC revenue — is the defining financial challenge facing the sector.
| Region | TWA (May-26) | TWA Peak | Δ from Peak |
|---|---|---|---|
| NSW | $109.84 | $172.8 (Jun-23) | −36% |
| QLD | $90.54 | $191.9 (May-23) | −53% |
| SA | $92.70 | $147.6 (Jun-23) | −37% |
| TAS | $97.99 | $135.5 (Jun-23) | −28% |
| VIC | $77.63 | $125.5 (Jun-23) | −38% |
12-month rolling TWA to May 2026.
3.0 LGC
3.1 LGC Revenue: The third headwind
Large renewable generators can earn LGC revenue outside the spot power market. The LGC weighted average represents the LGC spot income per MWh of eligible generation and sits alongside, not within the GWA or TWA figures.
For the rolling year to May 2026, LGC weighted average is sitting at approximately $17–19/MWh across all regions and technologies. That figure, while providing meaningful additional revenue, has itself declined sharply.
The rolling LGC weighted average of about $17–19/MWh reflects the last 12 months of actual spot LGC prices, which were higher earlier in the window and have been falling toward current levels throughout. As the older, higher-priced months roll out of the 12-month average, the LGC weighted average will continue declining, unless the spot LGC price recovers.
3.2 LGC Prices: The future
The LGC forward market provides an indication of where future spot LGC prices could settle. That outlook has deteriorated sharply over the six months to May 2026.
The Cal-26 forward price fell from $6.75/MWh in December 2025 to $2.00/MWh in April, a 70% fall in four months before recovering slightly to $2.50/MWh in May. The entire curve from Cal-26 through Cal-30 now sits at or below $2.50/MWh.
The cause is structural, and the forward market is consistent with the regulator's own outlook. The Clean Energy Regulator (CER) has forecast a sustained LGC surplus that it expects to persist until the end of the Renewable Energy Target scheme in 2030. In 2025, 59.7 million certificates were created, already exceeding the CER's own 54–57 million forecast. The regulator expects 64–66 million creations in 2026 as new capacity continues to be commissioned. The CER anticipates 3.5–4.5 GW of additional large-scale renewable capacity to be approved for LGC issuance this year alone.
On the demand side, while non-RET voluntary surrenders are rising with a forecast at 16–19 million in 2026, driven by corporate net-zero commitments, that uplift is not sufficient to absorb the surplus. The CER estimates a net surplus of approximately 15 million certificates in 2026.
The forward market's $2.00–$2.50/MWh pricing is, in other words, not a temporary dislocation, it reflects a consensus view that supply will continue to materially outpace demand for the remainder of the decade. Looking beyond 2030, the Renewable Electricity Guarantee of Origin (REGO) scheme is expected to provide a post-RET framework, but what LGC-equivalent prices will look like in that regime remains uncertain.
If future spot LGC prices settle near the level the forward curve is pricing, the rolling LGC weighted average of about $17–19/MWh, and will continue falling toward that $2–3/MWh range as higher-priced historical months cycle out. For renewable generators whose financial models assumed LGC revenue significantly above current forward prices, this is a meaningful adverse signal.
4.0 Implications
The revenue environment for NEM renewable generators has deteriorated across all three components simultaneously:
- Spot capture rates have fallen, most severely for solar, which is generating into a midday market it has largely made cheap itself.
- The flat baseload price (TWA) has fallen from its rolling peak for the year to mid-2023, and then 2026 prices are tracking lower than last year, reducing what even a perfectly-timed generator earns.
- LGC weighted average has fallen approximate;y 65% from its rolling annual peak for the year to November 2023, with the forward curve indicating further declines ahead.
Wind is in a materially better position than solar on the first measure, but as the wind sector expands will face the growing risk of rising cannibalisation. However, it is the second and third headwinds of a lower baseload price and declining LGC revenue, which affect both technologies equally.
5.0 Power Purchase Agreements
5.1 PPAs: Re-distributing the pain
The merchant outcomes described above do not tell the whole story, because a large proportion of NEM renewable assets operate under Power Purchase Agreements. A PPA effectively shifts the merchant spot price exposure from the renewable generator to the off-taker, at least for the duration of the contract. On the surface, asset owners appear insulated. However, curtailment can still affect an owner directly as minimum generation assurances may become an issue, and PPA revenue will be reduced by any curtailment that occurs.
But insulated does not mean painless. For the off-taker, the pain has already moved as they are buying at contracted prices against a market that has repriced significantly lower. The years when that PPA looked like a good deal are quickly forgotten; what concentrates the mind now is the gap between what was contracted and what the market offers today. For the asset owner, the pain is softened or deferred but the real test is renewal, when the PPA no longer shields them from the market they will then face.
PPA off-takers included corporate buyers, retailers, or energy-intensive industrials, may have contracted at prices that made sense when the market was tracking much higher, and may have had a windfall gain through the 2022–2023 period. However, many are now buying energy at a PPA price that is materially above current spot market levels. Depending on the PPA price, contractual structure, asset, technology, term, impact of curtailment and negative spot price are all contributing to the dynamic of "PPA regret."
The question of how much pain flows through depends heavily on individual contract terms, but a significant cohort of PPA buyers struck agreements that now look expensive relative to the market they could access today.
5.2 PPAs: Expiry implications
The more consequential question for asset owners is what happens at renewal. A PPA provides revenue certainty for its term; it does not protect against the market that exists when that term ends. As existing PPAs roll off over the coming years, asset owners will be exposed to the prevailing merchant market, the same market this article has been describing.
If a project was valued on the assumption that post-PPA revenues would reflect conditions similar to those when the PPA was struck, those valuations now need revisiting. A solar asset generating at about 30% capture rate into a $90/MWh flat market, with LGC revenue converging toward $2–3/MWh, is a fundamentally different proposition from the one underwritten in 2021 or 2022.
Write-downs appear to be a logical consequence for many solar assets and potentially some wind assets, if post-PPA revenue assumptions are marked to current and forward market conditions. Whether those write-downs have been recognised, are pending, or are being deferred pending a hoped-for market recovery is a question only individual asset owners can answer. But the data suggests the market recovery needed to avoid them is not imminent.
5.3 Mitigation: Batteries help, but ...
On-site battery storage is frequently cited as the business case remedy for a struggling solar farm. The logic is straightforward: a battery can shift generation from low-value solar hours into the evening peak, improve capture rates, and potentially absorb curtailed energy rather than letting it go to waste. In principle, a solar-plus-battery hybrid addresses the core cannibalisation problem.
In practice, it requires more capital, potentially significant capital, invested into an asset that may already be under financial stress. For owners facing write-downs or covenant pressure, committing further funds to a hybrid conversion is not a simple decision.
There is also a more fundamental question about whether the battery actually needs the solar farm. A standalone battery charging from the grid during periods of negative or near-zero spot prices, the same periods that force solar farms to curtail, has access to some of the cheapest energy in the market. It does not need a solar farm to charge. In fact, charging from the grid during curtailment periods is likely to be lower cost than charging from a co-located solar farm at any internal transfer price, because a battery will happily charge during negative spot prices where a solar farm would curtail or at a spot price lower than the transfer solar price.
There are two genuine advantages of co-location. The first is the potential to capture curtailed solar energy that would otherwise be lost entirely, though whether that materialises depends on the relative capacity of the two assets and the state of charge at the time of curtailment. The second is avoided grid connection costs and the time that comes with them. A co-located battery can share the solar farm's existing connection, which can represent a very significant capital saving compared to a standalone battery that must fund its own.
Obtaining a new grid connection in the NEM can also be a lengthy process, so co-location can bring a battery to market materially faster than a greenfield development. Where connection costs are high and connection queues are long, this combination of cost and speed can be a material part of the co-location business case.
The conclusion from our March article still holds: a solar farm may need a battery, but a battery does not need a solar farm. For an owner weighing a hybrid conversion under financial stress, that asymmetry should be a central part of the analysis.
6.0 Conclusion
The solar eclipse continues and the underlying flat price has also faded. LGC revenue that has historically softened the blow for large renewable generators is pricing toward levels that will provide only modest support.
There are genuine demand-side forces that will eventually help absorb the surplus. Large-scale data centres bring significant and largely flat load profiles that consume around the clock. Home batteries, perhaps being deployed without co-located solar, will charge from the grid during cheap daytime periods. Electric vehicles, as charging infrastructure and grid-interactive capabilities mature, add a further layer of flexible daytime demand. Each of these will contribute to lifting daytime prices over time.
Policy changes are also on-foot. The AER's national Solar Sharer Offer, commencing 1 July 2026 in NSW, South East Queensland, and SA, requires retailers to offer a plan with three hours of free electricity from 11am to 2pm — precisely the midday window where solar surplus is most acute. Victoria's Midday Power Saver follows on 1 October 2026, offering the same window to households on participating plans. Both are opt-in and require a smart meter, so uptake will build gradually rather than arrive as an immediate demand shift.
However, these changes may take time to impact and so the challenge of low daytime prices may be facing the solar industry for many years to come, and the growing risk of cannibilisation for the wind sector is also a very real risk.
Disclaimer and Notes
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