May 2026 had near-zero average daily prices to over $180/MWh in 18 days. Two strong days reshaped a month defined by renewable oversupply, collapsing LGCs, and a daily price curve increasingly sculpted by the sun. The energy transition, in full view and not yet complete.
May 2026 was a month of two very different electricity markets — separated by days in the calendar but connected by the same underlying tension between abundant renewable supply and brief, fierce bursts of scarcity.
For the first two weeks, the NEM looked like a market awash with energy. South Australia and Victoria opened the month with near-zero or negative daily prices, gas costs were tracking 30–40% below their 2025 levels, and Large Generation Certificates had collapsed to just $2.00–$2.50 per certificate, a fraction of the $6.75 recorded only five months earlier.
The message from the market was clear: renewable supply was plentiful, and the structural shift in the generation mix was eroding the traditional price premiums that energy assets had relied upon.
Then the market reminded everyone that abundance and volatility are not mutually exclusive. On 18 May, NSW hit $181.68/MWh, the highest daily price of the month, with QLD at $176.40 and VIC at $171.21 close behind. A second wave followed in the final week where SA reached $164.11/MWh on 27 May, and NSW $157.10. These two spike events were responsible for nearly half of each region's monthly average, pulling NEM-wide prices to $79.35/MWh despite the soft bookends on either side.
The price band analysis laid bare just how spike-dependent the month was. In SA, 66% of the monthly average spot price came from intervals priced above $100/MWh, the highest share of any Region. Yet the Risk-of-Change data showed the market was not sitting on a knife's edge: a 100MW shift in supply or demand would have moved daily prices by less than $7/MWh on average, suggesting the spikes were driven by specific, time-bound demand events rather than chronic structural tightness.
Beneath the headline numbers, the daily price shape is quietly but unmistakably changing. Normalised price analysis across four years shows the midday solar trough deepening in NSW and QLD — the duck curve is becoming more pronounced — while the sharp, narrow evening spike of 2023 has given way to a broader, more moderate evening elevation (we will talk more about the role of batteries in our next Generation Report). In VIC and SA, the daily curve flattened markedly in May, as spike events distributed high-price intervals across the day rather than concentrating them in the traditional ramp window.
Two structural signals stand out beyond the spot market. Negative price incidence, while low in May at 1–15% across regions, has risen dramatically since 2019 — SA recorded near-zero negative prices six years ago and nearly 48% in November 2025.
LGC prices at $2.00–$2.50 across all tenors through to Cal-30 signal a market that sees no foreseeable tightening in renewable certificate supply — welcome news for retailers and customers wanting to improve their voluntary sustainability objectives, but a meaningful headwind for new renewable project economics.
In short, May 2026 was a month where the energy transition was visible in every metric: in suppressed midday prices, collapsing certificate values, historically low gas costs, and a daily price shape increasingly defined by the rhythm of the sun. The spike events served as a reminder that the transition is not yet complete — and that when renewable supply temporarily falls short of demand, the market still knows how to move.
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1.0 Overview
This section provides a brief overview of monthly electricity and gas spot prices.
1.1 Electricity Spot Price Summary
Spot prices across the National Electricity Market have continued to soften, with rolling 12-month averages now sitting below Cal-25 levels in every mainland Region except SA. Year-to-date Cal-26 outcomes are materially lower than calendar-2025 averages across the board — most dramatically in VIC, where the year-to-date average of $45.84/MWh is around 41% below 2025, and in NSW (down roughly 30%). QLD has eased by a similar magnitude, while SA and TAS have softened more modestly. May 2026 delivered the lowest monthly average in six years across all mainland states, reinforcing the downward trend that has been in place since September 2025.
1.2 Gas Spot Price Summary
Gas spot prices have followed a similar downward trajectory to power, with May averages running well below recent norms and continuing to pull the year-to-date figures lower. Across the eastern hubs, BNE, SYD and VIC are each tracking roughly $2.30–$2.45/GJ below their calendar-2025 averages, with ADL showing the same direction of travel. The compression across hubs has narrowed the basis between Regions and reinforces the broader theme of softer wholesale energy outcomes through the first half of Cal-26.
The sharp decline in gas prices relative to 2025 has direct implications for electricity spot prices: cheaper gas reduces the marginal cost of gas-fired generation, lowering the price floor for evening and peak demand periods when gas peakers are typically on the margin.
2.0 Electricity Prices
This section provides a snapshot of:
- Daily spot prices
- Normalised spot prices
- Spot prices band contribution
- Proportion of negative prices
- Risk-of-Change
2.1 Daily Spot Prices
May 2026 divided broadly into four phases.
1–4 May — Soft opening. The month began with subdued conditions across the southern mainland. SA and VIC recorded near-zero or negative daily prices on 1–3 May, with SA reaching –$0.91/MWh on the 3rd and VIC –$1.80/MWh on the 2nd. NSW and QLD were moderate at $38–$67/MWh. TAS held firm above $79/MWh throughout, consistent with its hydro generation floor.
5–16 May — Recovery and consolidation. A step-change higher began on 5 May, with SA jumping to $109/MWh and all regions lifting materially. Prices then settled into a sustained elevated range — NSW and QLD between $48–$84/MWh, SA between $24–$117/MWh, and TAS consistently above $82/MWh. The 9–10 May period was notably firm in SA ($97–$117/MWh) while the remaining mainland regions tracked more moderate levels.
17–18 May — First major spike. The month's most significant price event. On 17 May all regions surged, and 18 May became the highest-priced day of the month: NSW reached $181.68/MWh, QLD $176.40/MWh, and VIC $171.21/MWh. TAS peaked at $119.70/MWh. A partial retreat followed from 19 May, though prices remained above pre-spike levels.
24–29 May — Second major spike. A second sustained high-price period developed from 24 May. SA recorded its monthly peak of $164.11/MWh on 27 May, with NSW ($157.10), QLD ($141.23), and VIC ($127.53) all recording their second-highest days. The 28–29 May period remained elevated before a sharp retreat on 30–31 May returned conditions close to those seen at the month's start.
Month-end pullback. The final two days saw prices fall sharply across all regions — SA dropped to $23.57/MWh on the 30th, VIC to $20.16/MWh — mirroring the soft conditions that opened the month and pointing to the influence of high renewable generation in the absence of demand stress.
2.2 Normalised Spot Prices
Normalised prices express each half-hourly outcome as a number of standard deviations from that month's average price. This removes the influence of absolute price level, allowing the shape of the daily price curve — the relative timing and depth of peaks and troughs — to be compared cleanly across years. A value of 0 means the interval priced at the monthly average; positive values mean above average; negative values mean below average. Values beyond ±1.0 represent unusually extreme intervals.
The daily shape reflects the interplay of demand patterns, solar generation, and the evening demand ramp. The characteristic "duck curve" — a morning peak, a midday solar trough, and an evening recovery — is visible to varying degrees across all regions, and its evolution across years reveals the growing influence of rooftop and utility-scale solar.
QLD:
Queensland shows the most volatile normalised shape of any region, with the widest gap between trough and peak. The 2026 solar trough at –0.91 (11:00) is the second deepest in the dataset after 2024's –1.29, consistent with QLD's strong solar generation profile. The morning peak at +0.72 was the second highest recorded, again pointing to a sharp pre-solar demand ramp.
The most striking QLD feature is the sharp decline in evening spike amplitude. After three consecutive years where the 17:30–18:00 period reached +1.73 to +1.83 standard deviations, 2026 fell to just +0.77 — less than half the prior year average. This does not mean the evening was cheap in absolute terms (the monthly average was $76/MWh), but that the relative premium for evening intervals has narrowed significantly, suggesting a more balanced supply stack through the evening transition period.
NSW:
In 2026, NSW displayed the deepest solar trough of any year in the dataset, reaching –0.57 standard deviations at 11:00 — more than double the 2023 and 2025 troughs. This reflects the continued growth of rooftop and utility solar suppressing midday prices relative to the monthly average. Notably, the morning peak (07:00) was the strongest on record at +0.48, as demand ramps before solar generation takes hold.
The evening recovery in 2026 was more sustained but lower in amplitude than prior years. The extreme 18:00 spike of 2023 (+2.15) has moderated considerably, and 2026's +0.63 represents a flatter, broader evening elevation that persists well into the late evening (+0.25–0.31 from 21:00 to 23:30). This overnight residual elevation is a 2026 feature not present in earlier years, suggesting the month's broader high-price character lifted the entire non-solar period relative to the average.
VIC:
Victoria shows the clearest year-on-year trend of any region, and 2026 marks the most significant structural shift. The solar trough, which had been deep and consistent from 2023 to 2025 (ranging –0.75 to –0.87), rose sharply to just –0.28 in 2026 — less than a third of recent depth. The evening peak simultaneously declined from a consistent +0.94–1.07 range to +0.47, and the morning peak fell to +0.39 from +0.87 in 2024.
The 2026 VIC normalised profile is notably flat compared to prior years — the peak-to-trough amplitude is roughly half that of 2023–2025. This does not mean the duck curve has disappeared, but that the relative dispersion of half-hourly prices around the monthly average was much lower. In the context of May 2026's elevated average ($64.77/MWh), this suggests that the high-price spike events distributed value more broadly across the day, compressing the normalised shape even as absolute prices were well above historical averages.
SA:
South Australia shows the most notable flattening of the daily shape in 2026. Both the morning peak and the solar trough are shallower than any prior year — the trough at –0.19 is far less pronounced than 2024 (–0.93) and 2025 (–0.85), and the morning peak at +0.23 is less than a third of its 2023–2025 levels. The evening premium is also modest at +0.41.
This reflects the bimodal pricing character identified earlier in this report: SA's average in May 2026 was dominated by high-price intervals above $100/MWh distributed across the day (driven by the two day events) rather than a clean intraday pattern. When stronger spot price occur at varying times of day, they smooth out the normalised shape even while the absolute price level is elevated.
TAS:
Tasmania's normalised profile is distinctly different from the mainland, reflecting its hydro-dominated generation mix. There is no solar trough — midday is not systematically cheap relative to the monthly average. In 2026, the midday period (11:00–13:00) averaged +0.08, meaning it priced essentially at the monthly average — a sharp contrast to 2024 (–0.52) and 2025 (–0.61), when midday prices in TAS were noticeably below average, likely reflecting interconnector flows from solar-oversupplied mainland markets.
The 2026 overnight period (00:00–05:00) averaged –0.24, the deepest overnight suppression in the dataset for TAS — suggesting lower off-peak hydro dispatch or reduced interconnector import during those hours. The evening premium at +0.35 was present but moderate, consistent with a market that responded to mainland demand patterns without the sharp spike dynamics seen in prior years.
Cross-Regional Summary
The normalised price analysis reveals two distinct 2026 patterns across the NEM. In NSW and QLD, the solar trough deepened further in 2026 — the duck curve's midday suppression is becoming more pronounced year-on-year, pointing to ongoing solar penetration growth. However, the evening spike amplitude has moderated: the sharp, narrow post-sunset spikes of 2023–2025 have given way to a broader, lower evening elevation that persists further into the night.
In SA and VIC, the opposite occurred — the daily shape flattened considerably, with shallower troughs and smaller peaks. This reflects the dominant influence of the two day spike events in May 2026, which were not confined to the traditional evening ramp window and therefore distributed the high-price intervals more evenly across the day, smoothing the normalised curve.
TAS remains structurally different from the mainland, with no solar trough and a more muted intraday shape, though 2026 showed a notable shift — midday returned to near-average pricing after two years of below-average midday outcomes driven by mainland interconnector flows.
2.3 Spot Price Band Contribution
Prices above $100/MWh were a dominant driver across the NEM
The $100–$250/MWh range contributed $36.93 to the NEM-wide average of $79.35 — nearly 47% of the total. Despite a moderate-looking average, almost half of it was built from intervals priced above $100/MWh, reflecting the two major events (17–18 May and 27–28 May) that drove sustained high pricing across all regions.
QLD spent more time in the $50–$100 range than any other region
Queensland's $50–$100 contribution of $41.30 was the highest of any region, indicating a greater share of intervals priced in that mid-range. Its $100–$250 contribution of $30.32 was the lowest on the mainland, suggesting QLD was somewhat less exposed to the greater than $100 spikes that drove up averages in NSW, SA, and VIC.
NSW reached the highest price extremes
NSW was the only region with a meaningful $300–$600/MWh contribution ($0.46), consistent with its daily peak of $181.68/MWh on 18 May. It also recorded the second-highest $250–$300/MWh contribution at $1.30, behind only VIC ($1.44). Together, these extreme ranges added $1.76 to NSW's average — modest in absolute terms but indicative of genuine price spikes reaching the upper end of the scale.
VIC had the highest exposure to prices above $250/MWh
Victoria recorded the largest $250–$300/MWh contribution ($1.44) of any region. Combined with its relatively low $50–$100 contribution ($25.01), VIC's pricing profile reflects a market that spent less time in the mid-range and more time at the extremes — both negative (–$0.29) and very high ($1.44 above $250/MWh). This is consistent with VIC's high renewable penetration driving price suppression at one end, while tight demand conditions during spike events pushed prices well above $250/MWh.
SA's average was overwhelmingly shaped by prices above $100/MWh
South Australia's $100–$250/MWh contribution of $51.03 accounted for 66% of its $77.49 average — the highest share of any region. SA spent more time in the $100–$250 range than any other state, while its $50–$100 contribution of just $20.39 was the lowest on the NEM. SA's pricing profile was notably bimodal: either very low (including negative prices) or above $100/MWh, with relatively little time in the $50–$100 mid-range.
TAS prices never fell below $50/MWh or exceeded $300/MWh
Tasmania recorded zero contribution from all ranges below $50/MWh and above $300/MWh. All price formation occurred between $50–$250/MWh, split between $50–$100 ($61.12) and $100–$250 ($34.86). TAS's hydro-dominated generation profile provided a consistent $50+ price floor, insulating it from the renewable-driven price suppression experienced on the southern mainland.
Negative price exposure was modest but present in all mainland regions
No region recorded any contribution from prices below –$100/MWh, indicating extreme negative prices were avoided during May. However, all mainland regions experienced some negative pricing, with VIC (–$0.29) and SA (–$0.27) most affected. These were driven by periods of excess renewable generation, predominantly on 2–3 May. NSW had negligible negative price impact (–$0.02), and TAS had none at all.
2.4 Proportion of Negative Prices
May 2026 saw the lowest negative price incidence in over a year
Negative price proportions fell sharply across every region in May 2026 compared to April, and were also lower than May 2025 for all regions. This is consistent with the month's pricing character: two major spike events and elevated mid-range prices dominated the period, leaving limited room for renewable-driven oversupply to suppress prices into negative territory.
SA and VIC, which had recorded negative price proportions of 30–32% in April 2026, fell to 12.80% and 15.14% respectively in May — still the highest on the mainland, but a significant reduction. TAS recorded 0.00%, its first zero-negative month since July 2025.
Longer-term context: negative prices have surged since 2019
The historical data reveals a clear upward trend in negative price incidence across the NEM since 2019, driven by the rapid growth of solar and wind generation. SA has consistently recorded the highest proportions — reaching a peak of 47.96% in November 2025, meaning nearly half of all dispatch intervals in that month settled at a negative price. VIC has followed a similar trajectory, hitting 44.32% in November 2025.
NSW and QLD have also trended upward but from a much lower base. NSW, which recorded near-zero negative price incidence through most of 2019–2021, reached 29.53% in November 2025 before easing back in 2026. QLD peaked at 33.44% in September 2025.
TAS has remained far less exposed to negative prices throughout the period, typically below 5%, reflecting its hydro-dominated generation mix which doesn't produce the same midday solar oversupply conditions seen on the mainland.
May 2026 in historical perspective
Despite the sharp month-on-month improvement, May 2026's negative price proportions remain elevated relative to the early part of the decade — particularly for SA (12.80% vs. 1.56% in May 2019) and VIC (15.14% vs. 0.16% in May 2019). The structural increase in negative price frequency reflects an irreversible shift in the generation mix, and the low May 2026 result is better understood as a demand/weather-driven anomaly than a reversal of the underlying trend.
2.5 Risk-of-Change
Risk-of-Change (RoC) measures how sensitive the spot price would have been to a small shift in supply or demand during the month. It is expressed as the average $/MWh price impact of a 100MW change in the large regions (NSW, QLD, VIC) or a 50MW change in the small regions (SA, TAS). A low RoC means prices were relatively stable and difficult to move — the market had depth on either side. A high RoC means prices sat close to a steep part of the merit order, where even a modest change in supply or demand could have caused a large price swing.
May 2026 had low RoC across all regions
All five regions recorded modest RoC values in May 2026, with spreads ranging from $6.96 (NSW) to $10.57 (TAS). This indicates the market had reasonable depth on both sides of the dispatch curve — prices were elevated during the month's spike events, but the merit order was not sitting at an unusually thin or steep point on average. In practical terms, a 100MW shift in supply or demand would have moved prices by less than $7/MWh in NSW and VIC, and less than $5/MWh in QLD.
The asymmetry between supply-side and demand-side sensitivity is notable for most mainland regions. The downside impact (e.g. supply increase) was consistently larger in absolute terms than the upside impact (e.g. demand increase). For NSW, supply sensitivity (–$5.03) was 2.6 times the demand sensitivity (+$1.93), and for SA (–$6.75 vs +$2.46) the ratio was similar. This suggests prices were positioned on a mildly asymmetric part of the supply curve, where there was more room to fall than to rise from small changes — consistent with the high renewable penetration in these regions.
TAS was the exception, with upside sensitivity (+$7.14) roughly double the downside (–$3.43). This reflects the tighter hydro dispatch stack in Tasmania, where adding 50MW of demand would push into higher-cost generation bands more sharply than adding 50MW of supply would release lower-cost capacity.
Comparison with April 2026 and May 2025
May 2026 RoC was broadly comparable to April 2026 across most regions, though SA and TAS saw a reduction in spread — particularly SA, which fell from $16.07 to $9.21, indicating a less volatile price environment despite both months having elevated average spot prices.
The contrast with May 2025 is striking. A year earlier, NSW had a spread of $36.68 — with both the Low (+$12.74) and High (+$49.42) values positive — meaning even adding 100MW of supply would still have raised prices. This reflects a market under acute supply stress, where the merit order was on a steep upward section. May 2026's equivalent NSW spread of $6.96 signals a considerably more stable underlying market, despite the two spike events during the month.
Historical extremes in context
The dataset highlights how sharply RoC can deviate in stressed conditions. June 2025 saw NSW reach a High of +$99.66/MWh and SA a High of +$87.56/MWh — meaning a 100MW/50MW withdrawal of supply could have moved prices by nearly $100/MWh. At the other extreme, January 2026 saw SA record both Low and High as deeply negative (–$96.04 and –$68.49), indicating an oversupplied market where even increasing demand would have lowered prices — a hallmark of extreme renewable oversupply conditions.
May 2026's contained RoC values sit well within normal bounds relative to these episodes.
3.0 LGC Prices
Prices have collapsed across all tenors since December 2025
LGC prices fell sharply and consistently across all calendar year tenors between December 2025 and April 2026, before a modest partial recovery in May 2026 for the near-term tenors. Cal-26 dropped 63% in six months — from $6.75 to a low of $2.00 in April before closing May at $2.50. Cal-27 followed an almost identical path, also closing at $2.50. The longer-dated tenors (Cal-28 through Cal-30) did not share the May recovery, all closing the month at $2.00.
The pace of decline was steep and largely uninterrupted. Between December 2025 and March 2026, prices fell by roughly $1.00–$1.25 per month across each tenor. The April 2026 result marked the trough for most tenors, with the modest May uptick in Cal-26 and Cal-27 (+$0.50) providing only a minor reprieve.
The forward curve has collapsed to near-flat
By end of May 2026, the forward curve was essentially flat at $2.00–$2.50/MWh across all five tenors. This convergence is significant: the market is assigning almost no premium for certificates in future years relative to the present. A flat or inverted LGC curve at these levels is a strong signal that the market expects renewable generation to continue exceeding RET obligations well into the decade, with no foreseeable tightening in certificate supply.
This stands in sharp contrast to the structure visible in December 2025, when the curve showed clear positive slope — Cal-26 at $6.75 sitting well above Cal-29 at $4.50 — suggesting the market still expected some near-term scarcity. That premium has now entirely eroded.
Implications for renewable generators
At $2.00–$2.50/certificate, LGCs are providing minimal revenue support to renewable generators beyond the spot price. Historically, LGCs have traded at $20–$80/certificate during periods of renewable undersupply, representing a significant portion of a project's total revenue. At current levels, LGC income is essentially negligible on a per-MWh basis, placing greater reliance on spot market revenues and contracted prices to underpin project economics.
We will discuss this further in our May Generation report.
For retailers and liable parties, the low LGC price significantly reduces the cost of meeting RET obligations — a meaningful reduction in the green component of electricity procurement costs. However, it also removes a price signal that previously incentivised new renewable investment.
Disclaimer and Notes
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