Underlying electricity demand reached a new quarterly high, supported by electrification, population growth, and data centre expansion, though this was largely offset by record rooftop solar output. At the same time, batteries are increasingly influencing price outcomes, softening evening peaks while lifting daytime pricing, and fundamentally changing how the market behaves.

Gas prices have also declined despite global volatility, reflecting lower domestic demand and reduced reliance on gas-fired generation. However, this dynamic may not persist, particularly as the market approaches winter and global conditions continue to evolve.

As the market becomes more complex, with lower average prices but ongoing volatility and structural change, it remains important to stay close to both electricity and gas developments. Read on for all the key points from AEMO’s latest QED report.

Demand Growth Offset by Rooftop Solar

• Underlying electricity demand reached a new quarterly record (+1.2% YoY), driven by heat events, electrification, population growth, and data centres.
• However, record rooftop solar output (+8.1%) offset this growth, keeping grid demand broadly flat.

Renewables Rising, Thermal Generation Falling

• Renewables reached 46.5% of total generation (new Q1 record).
• Coal generation declined (-4.4%), while gas generation fell to its lowest level since 1999.

Batteries Are Now Influencing Prices

• Battery capacity has more than doubled year-on-year, significantly reshaping supply patterns.
• Batteries are now setting prices in ~32% of intervals, overtaking hydro.
• Evening peak prices softened, while daytime prices lifted due to charging behaviour.

Electricity Prices Lower Overall, But Volatility Remains

• Average wholesale prices fell to $73/MWh (-12% YoY).
• However, prices remain elevated vs last quarter (+47%) and volatile during extreme events (e.g. South Australia January spike). 

Gas Prices Fall Despite Global Tension

• East coast gas prices averaged $10.61/GJ (down from $13.26/GJ YoY).
• This occurred despite higher global LNG prices and geopolitical disruption.
• Lower demand (especially from gas generation) was a key driver.

WA Prices Stable, Gas Market Tightening, and Renewables Driving Transition

• WA wholesale energy prices remained relatively flat (~$88/MWh) with lower volatility due to battery activity.
• Domestic gas consumption and production both declined (~4-5%), with storage and pipeline constraints flagged late in the quarter.
• Underlying demand declined (-2.3% YoY) due to milder weather, while rooftop solar output increased (+6.5%), further reducing daytime grid demand.
• Renewable share increased to 46.1%, while battery discharge surged (+305%) following significant new capacity additions.

Market Outlook & Bottom Line

• Demand pressures are building, particularly from electrification and data centres
• Renewables and batteries are reshaping price dynamics, not eliminating volatility
• Gas remains a key swing factor, with downside risk to prices if global conditions flow through
• Price outcomes will increasingly depend on timing, load profile, and flexibility

With Iona gas storage on track for full capacity ahead of winter and battery capacity continuing to grow, conditions entering Q2 appear more balanced than a year ago. However, winter demand uplift, continued gas export competition from LNG markets, and ongoing South Australian grid constraints remain key risks to watch. The accelerating shift of price-setting to batteries will continue to structurally alter intraday price profiles, relevant for customers with flexible load or on time-of-use contracts. For large energy users, this reinforces the need for active procurement strategies and ongoing market engagement rather than passive contract management.

If you’d like to discuss your energy contract with one of our experts, simply reply to this email or get in touch via our website.

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Here are some of the key insights from the Australian Energy Market Operator’s (AEMO) most recent Quarterly Energy Dynamics (QED) report.

Demand and Generation Mix

• Operational demand in the NEM rose 2.3% year-on-year, underpinned by record underlying consumption and growing battery load.
• Distributed solar PV continued to offset daytime grid demand, setting new low demand records in several states. Despite this, higher evening peaks and electrification trends kept total system demand elevated.
• Renewable generation continued its rapid expansion, with wind and large-scale solar output up 16% year-on-year, and batteries discharging 150% more energy to support evening peaks.
• Renewables supplied a record 42.7% of total generation, driving emissions intensity to a new low of 0.57 tCO₂-e/MWh.
• Coal output edged slightly lower overall, while gas generation declined 11% amid lower evening peaking needs.

Wholesale Electricity Prices

• Wholesale electricity prices fell across all NEM regions, averaging $87/MWh. The key drivers were:
  • A stronger renewable generation share displacing high-cost peaking plant.
  • Subdued volatility, with high-price events (> $300/MWh) down 82% year-on-year.
  • Lower fuel input costs and improved inter-regional transmission flows.
• Queensland recorded the lowest average price at $72/MWh, while South Australia remained the highest at $104/MWh, reflecting greater exposure to intermittency and lower firming reserves. Negative or zero-price intervals surged, especially in Queensland, highlighting ongoing pressure on midday market pricing.

East Coast Gas Market

• East coast gas largely stable on the year.
• Demand softened marginally due to reduced gas-fired generation and LNG export volumes. Domestic supply, however, declined more sharply as Queensland export projects and the Moomba plant curtailed output, increasing reliance on the Iona underground storage facility, now at its lowest Q3 inventory since 2021.
• Tight supply margins and limited new field development continue to underpin medium-term gas price risk.

Western Australia

• In the WEM, operational demand rose 11% and renewable output hit a new Q3 record at 36.4%.
• Average wholesale electricity prices increased 27% to $101.76/MWh, driven by higher load and fewer mid-day low-price periods.
• Domestic gas production reached its highest level since 2020, offsetting a modest fall in consumption.

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Compared to last year’s ESOO, forecast reliability has improved, helped by more than 10 gigawatts (GW) of additional projects that now meet AEMO’s committed and anticipated criteria (2.9 GW/7 gigawatt hours of utility storage, 4 GW of grid-scale solar and 3 GW of wind).

Electricity consumption is forecast to increase 28%, from 178 terawatt hours (TWh) to 229 TWh, predominantly driven by the rapid expansion of data centres, the broader inclusion of prospective industrial load and accelerating business electrification.

Supply Developments: New generation and storage commissioning must accelerate to 5.2–10.1 GW annually over the next five years (up from 4.4 GW in 2024-25). Delays to projects (common in recent years) represent a material risk to supply security.

Reliability Risks: Qld (80 MW reliability gap forecast for summer 2025-26 due to demand growth and slower project commissioning); SA (390 MW gap forecast in 2026-27 with Torrens Island B retirement and EnergyConnect delay); NSW (reliability gaps previously linked to Eraring closure no longer forecast but system security remains a challenge); Vic (gaps tied to Yallourn closure no longer forecast, though gas supply and outage management risks persist).

Major Retirements: Torrens Island B (SA, 2026), Eraring (NSW, 2027), Yallourn (VIC, 2028). Replacement capacity must be delivered ahead of these closures.

System Security Requirements: As synchronous coal plants retire, new services are critical (system strength, frequency control, ramping capability, and restart services). Consumer energy resources (rooftop PV, batteries, EVs) must be effectively coordinated under the National CER Roadmap to avoid operational challenges.

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This article outlines the key insights from the recent Q2 2025 report, including the primary factors driving electricity and gas prices in the National Electricity Market (NEM) and Western Australia.

Key Factors Affecting East Coast Electricity Prices

1. Renewable Penetration and Demand Shifts
   Underlying electricity demand hit a Q2 record of 24,118 MW (+0.7% YoY), but strong growth in rooftop PV (+15%) reduced operational demand by 0.7% to 21,760 MW. Mild and sunny conditions near the start of the quarter supported high rooftop solar output, setting new lows for minimum demand levels, while cold, wet and windy winter evenings later in the quarter pushed heating needs and operational demand, especially in Victoria, which set a new winter demand record.

2. Variable Renewable Energy (VRE) and Storage
   VRE generation surged, with wind output up 31% and grid-scale solar up 17%. Renewables supplied nearly 38% of total NEM demand (up from 32.2% in Q2 2024), cutting emissions intensity to new lows. Battery storage also played a growing role, with discharge volumes more than doubling YoY. These technologies helped dampen price pressures during periods of high supply, but couldn’t fully offset shortfalls during still, cold evenings.

3. Price Volatility in June
   While the quarterly average wholesale electricity price rose modestly to $140/MWh (+5% YoY), June alone averaged $232/MWh, up sharply from April and May (~$95/MWh). This was driven by cold, still weather and peak heating demand, which coincided with low wind generation and forced increased reliance on gas and batteries. Just three extreme June days contributed $32/MWh to the quarterly average, with 12 June recording the highest daily NEM-wide price in market history.

East Coast Gas Market Dynamics

1. Reduced Demand Eases Prices
   East coast wholesale gas prices averaged $12.36/GJ, down from $13.66/GJ in Q2 2024. Overall demand fell 3%, due to lower gas-fired electricity generation and weaker LNG export volumes. Victoria continued to lead reductions in industrial and residential gas usage.

2. Supply Adjustments and Storage Drawdown
   While Queensland LNG projects pulled back domestic supply, Victorian production rose modestly, supported by increased output from Otway and Orbost. Iona Gas Storage was heavily drawn upon in June to meet gas-fired generation needs, setting new withdrawal records, but inventories remained healthy thanks to strong pre-winter injections.

Western Australia Gas and Electricity Dynamics

1. Rising Demand Offset by Rooftop Solar and Embedded Generation
   Cooler weather and increased battery charging drove underlying demand up 8.6%, but operational demand rose only 4.4% due to strong growth in distributed PV (+31%) and embedded generation.

2. Renewables Supply Over One-Third of Demand
   Renewables met 35.1% of demand, with a record 78.8% share in a single interval. Emissions intensity fell 5.5% despite rising consumption.

3. Energy Prices Up, But System Service Costs Plummet
   Average energy prices rose to $90.46/MWh due to higher demand and market changes. However, FCESS and uplift costs fell 72% thanks to increased competition and rule reforms.
4. Gas Demand and Production Down Slightly
   Compared to Q2 2024, domestic gas consumption declined 4.6% and production dropped 1.4%, while gas storage withdrawals surged to support winter demand.

Brief Outlook

Energy prices remain highly weather-dependent. While renewable output and battery storage continue to grow, their intermittent nature, especially during winter peaks, means gas-fired generation remains critical for reliability and price stability. In the near term, expect continued volatility during extreme conditions, though increasing renewable and storage capacity may gradually smooth price spikes over time. Longer-term pricing will depend on the pace of coal retirements, renewable integration, and gas market flexibility heading into summer 2025.

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This article outlines the key insights from the recent Q1 2025 report, including the primary factors driving electricity and gas prices in the National Electricity Market (NEM) and Western Australia.

Market Drivers and Outlook

The primary upward price pressures were:

• Increased demand in southern states
• Higher cost of marginal generation from coal and hydro (coal marginal prices rose from $71 to $84/MWh; hydro from $85 to $123/MWh)

Offsetting downward pressures included:

• Fewer extreme price events
• Increased penetration of grid-scale wind and solar (which set prices in 15% of intervals, up from 10% YoY)
• Growth in battery storage output (+86%)

Price drivers in the short term will continue to include fuel costs (especially coal and gas), weather-driven demand volatility, and the pace of renewable generation and storage integration. Increased renewables and batteries are mitigating peak price events but also contributing to low and negative prices during solar peaks. These dynamics, if sustained, suggest continued regional price divergence and moderate wholesale price volatility heading into winter 2025.

National Electricity Market (NEM)

Q1 2025 saw underlying electricity demand across the NEM reach a record high, averaging 25,162 MW (+1.4% YoY), largely due to heatwaves in Victoria and South Australia. However, operational demand declined slightly (-0.8%) as distributed photovoltaic (PV) generation hit a record 3,782 MW (+16%), setting new minimum demand records in multiple states. Queensland was the outlier, setting a new maximum demand record of 11,144 MW.

Average wholesale electricity prices stabilised across the NEM at $83/MWh, up 9% YoY but slightly down from the previous quarter. Regional outcomes were mixed:

• Tasmania saw the sharpest increase (+67%) to $111/MWh, primarily due to higher-priced hydro generation offers.
• Victoria and South Australia also saw price increases (+15% and +20%, respectively), driven by elevated operational demand.
• New South Wales prices remained stable (+1%) despite higher coal prices, due to robust variable renewable energy (VRE) output.
• Queensland saw prices fall 24% to $90/MWh amid reduced volatility.

Gas

Average wholesale gas prices across all AEMO markets hit a Q1 record high of $13.26/GJ (up from $11.60/GJ), although easing from Q4. Price pressure stemmed from reduced LNG supply into the domestic market, partially offset by increased production from Victoria’s Longford and Otway facilities.

Overall gas demand fell 2% due to reduced industrial and gas-fired generation use, especially in Victoria.

Renewables

Grid-scale wind and solar generation grew by 18% and 10% respectively, while battery output soared to 86%. Coal generation declined while renewables supplied 43% of total NEM generation, contributing to lower emissions, which fell to new Q1 lows.

Western Australia (WEM)

Electricity: Underlying demand hit a record 2,826 MW, driven by hotter nights and higher battery charging. Operational demand rose slightly (+0.6%) as solar and embedded generation increased.

Prices & Services: Average energy prices rose 11% to $89.03/MWh due to temperature and battery trends. FCESS (system services) costs fell by 51%, driven by competition from batteries.

Gas: WA gas production rose 1.1%, while consumption dropped 5.7%. Storage withdrawals continued for a fifth quarter, with isolated pipeline constraints posing no major issues.

Renewables: Renewable contribution reached 41.6% (a Q1 record), supported by more distributed PV, battery growth, and new hybrid facilities. Coal output declined, leading to a 5.2% drop in emissions intensity.

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• A serious incident at Queensland’s Callide C3 coal-fired generator (described as an “explosion”) has forced the unit offline until at least the end of May. Scheduled maintenance outages are planned for the remaining units in May and June. CS Energy maintains there is sufficient generation to meet demand for the June quarter and said outage schedules can be adjusted if needed. (The Australian)
• The Callide B power station will now stay open up to three years longer than its original 2028 closure date. Extensions to other QLD state-owned coal generators will be detailed by the end of 2025, as part of the LNP’s new “energy roadmap.” The 2021 Callide explosion, which caused blackouts and price spikes, is cited as a reason for prioritising maintenance and reliability. (AFR)
• The closure of EnergyAustralia’s Yallourn coal plant in 2028 (1.48 GW capacity, ~20% of Victoria’s electricity) increases pressure to deliver replacement capacity. (AFR)
• Timeframes for grid connections are stretching to up to 36 months as well as cost blowouts, and some unregulated connection requests are being rejected due to capacity constraints. Contractors and grid developers are concerned that the trade war and resulting global supply chain pressure may delay or further increase project costs. (AFR)
• The Coalition claims electricity bills would fall by 3% under its proposed gas policy, which includes diverting uncontracted LNG exports to the domestic market. (The Australian)

Gas

• The Coalition’s policy would require east coast LNG exporters to reserve more gas for domestic use by applying a de facto levy (a “security charge”) to make local sales more attractive than exports. The gas industry and analysts argue the policy is flawed and could reduce long-term supply and investment. AEMO warns the east coast gas market faces structural supply deficits as early as 2029 due to depleting traditional sources. (The Australian)

Renewables

• Treasurer Janetzki announced that Queensland would abandon legislated renewable energy targets and may amend the 2035 emissions reduction goal (75% cut from 2005 levels). (The Australian)
• Queensland argues its coal fleet is younger and cleaner than other states’, pointing to the Kogan Creek plant (opened 2007) as an example. This policy shift follows similar moves in NSW, where the Eraring coal station is being kept open until 2027 with state subsidies. (AFR)
• The trade war, particularly the US tariffs on Chinese goods, could disrupt global supply chains and raise costs for grid and renewable energy projects in Australia. Energy-intensive manufacturers like Brickworks and BlueScope remain concerned about rising power prices linked to the cost of building out the transmission grid. (AFR)

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