Changelog

The Modo Energy NEM forecast of power prices and battery revenues updates periodically. Here is a summary of the changes from one version to the next.

October 2026 release (update from July 2026)

Market pricing model updates

• Secure transfer limits on 19 flow corridors: The Australian Energy Market Operator’s (AEMO’s) secure transfer limits now cap net flow across 19 corridors, extending limits from the five interstate interconnectors to routes within states, such as the southern approach into Sydney. Limits vary by direction and season, and rise as Integrated System Plan (ISP) projects commission. Network projects now enter the price forecast dispatch on the day they enter service rather than at a mid-year cutoff. See Transmission.

• Stack-aware battery bidding: Battery bids in the fundamentals model are now placed against each state’s thermal supply stack, rather than derived from capital cost and historical bidding curves. Batteries now dispatch against coal and gas from the first forecast years. See Storage.

• 12-hour batteries and a minimum offshore wind build in the capacity expansion model: Battery storage can now be built in 2-hour, 4-hour, 8-hour and 12-hour durations. Offshore wind was already an investment technology but never cleared on cost; the model now builds a minimum of 2,000 MW in south-east Victoria between 2035 and 2037. See Capacity Buildout.

• Renewable profiles at ISP sub-region level: New-build wind and solar capacity factor profiles are now aggregated from AEMO Renewable Energy Zone (REZ) traces to each of the 15 ISP sub-regions, replacing the nine substates used in the July 2026 release. See Renewable Generation.

Dispatch model updates

• Cell-based round-trip efficiency and conversion losses: The battery efficiency input is now the round-trip efficiency of the cells alone (default 96%), and the dispatch model adds the conversion losses between the cells and the grid. A 96% cell gives an 88.1% grid round trip for standalone, alternating current (AC)-coupled and reverse direct current (DC)-coupled sites, and 85.0% for standard DC-coupled sites. Modelled solar crosses the inverter and AC stage before the export limit, while customer-uploaded solar and wind profiles are taken at the connection point. See Co-located Sites.

• New asset configurations: The dispatch model now supports standalone solar, standalone wind, wind and solar, wind and battery, and wind, solar and battery sites, alongside standalone batteries and solar and battery sites. Wind is modelled as AC-coupled, uses AEMO REZ traces by default, and is read at the connection point. See Co-located Sites.

• Contracting strategies on the shared contracting module: Battery contracts now use the contracting module shared with Modo Energy’s other regions. The terminal offers three types, toll, revenue swap and cap and floor, with annual or monthly settlement, a choice of price unit, and settlement in the Monte Carlo revenue distribution. The separate capacity swap type and the LTESA and CIS presets are replaced by the toll type and by entering the floor and cap shares directly. See Contracting Strategies.

Input data updates

• Transmission updated to the final 2026 ISP: Network augmentation timing and the nodal network follow AEMO’s final 2026 ISP, replacing the draft ISP inputs used in the July 2026 release. The price forecast dispatch now includes two Victorian projects that raise transfer limits into Melbourne: Eastern Victoria Reinforcement from July 2033 and South West Victoria Expansion from July 2045. See Transmission.

• Demand updated to the 2026 ESOO: Demand projections now follow AEMO’s 2026 Electricity Statement of Opportunities (ESOO) Step Change scenario. Total operational demand grows from around 182 TWh in 2026 to 262 TWh in 2050 in the Central scenario. See Demand.

• Capital costs updated to the final GenCost 2025-26: Capital cost assumptions for capacity expansion technologies now follow the Commonwealth Scientific and Industrial Research Organisation’s (CSIRO’s) final GenCost 2025-26 report as adopted in the 2026 ISP. Utility solar capital cost for 2030 is A$1,351/kW, 39% higher than in the July 2026 release. Battery energy storage system (BESS) capital costs continue to follow Modo Energy’s own cost curve and are unchanged. See Capacity Buildout.

• Gas and coal futures refreshed: Wallumbilla gas futures for 2027 are A$10.74/GJ (nominal), down 5% from the July 2026 release. Newcastle coal futures are 6.5% lower at US$139/t. See Commodity Prices.

• LGC prices follow refreshed futures: Large-scale Generation Certificate (LGC) prices now follow calendar-year futures, replacing the flat $2.40/certificate used in the July 2026 release. Certificates generated in 2026 start at $8.25, falling to $4.50 in 2028 and recovering to $6.00 in 2029 and 2030, before declining to a $1 residual from 2031 when the Renewable Energy Target ends. See Commodity Prices.

• Data-centre demand forecast revised: In the Central scenario, Modo Energy’s National Electricity Market (NEM) data-centre demand forecast is now 5.0 TWh in financial year (FY) 2026, 15.2 TWh in FY2030 and 40.1 TWh by FY2050, compared with 5.5, 14.2 and 36.8 TWh in the July 2026 release. The High scenario reaches around 56 TWh by FY2050. The forecast now draws on a larger project register, as described in the data centre demand section of Demand.

July 2026 release (update from April 2026)

Market pricing model updates

• Nodal transmission model: The fundamentals model has moved from a 9-substate zonal representation to solving a transmission network with over 200 nodes, capturing line-level thermal limits and ISP-scheduled network augmentations. Energy continues to be settled at the Regional Reference Node (RRN), as in the real NEM, but nodal prices now capture congestion between individual connection points rather than a substate average, with asset-specific forecasts reflecting the specific node at each asset’s connection point. Losses continue to be applied separately via Marginal Loss Factors (MLFs) in the dispatch model. See Transmission.

• Forecast Marginal Loss Factors: Marginal Loss Factors (MLFs) used in the battery dispatch model are now forecast from the nodal model’s actual line flows, replacing the previous machine-learning-based MLF forecast. Forecasts are produced per node and technology, and battery energy storage systems (BESS) receive separate import (charging) and export (discharging) loss factors. See Marginal Loss Factors.

Input data updates

• 2026 ISP inputs rebuild: Input assumptions have been rebuilt on AEMO’s 2026 Forecasting Assumptions Update (FAU) and 2026 Integrated System Plan (ISP) dataset, replacing 2024/2025 ISP-vintage inputs. This includes existing generator data, future capacity assumptions, ramp rates, minimum stable levels, rooftop PV, and electric vehicle (EV) allocations by scenario. See Generation and Storage and Demand.

• Technology costs refreshed to CSIRO GenCost 2025-26: Capital cost assumptions are now sourced from AEMO’s 2026 ISP inputs, which embed CSIRO’s GenCost 2025-26 report, and projected 2035-36 capex is around 26% lower for large-scale solar PV and 27% lower for small open-cycle gas turbines (OCGT). Near-term gas peaker costs have risen approximately 32% due to global turbine supply constraints, and the High scenario is now calculated as Central capex multiplied by 1.10, rather than using a separate cost file. Battery energy storage system (BESS) capex continues to be set by Modo Energy’s own market intelligence, refreshed to a February 2026 cost curve and unaffected by the GenCost update. See Capacity Buildout.

• Gas futures refreshed: Wallumbilla gas futures have softened by around $1/GJ in the near term, for example from $12.01/GJ to $11.35/GJ in 2027. Victorian gas futures have moved lower by a similar margin. Newcastle coal futures are unchanged from the April 2026 release. See Commodity Prices.

• LGC prices flattened: Large-scale Generation Certificate (LGC) price assumptions have been flattened to $2.40/certificate across the forecast curve, replacing a curve that fell from $9.88 in 2027 to below $1.50 by 2030. This lowers the effective revenue support renewable generators receive from LGCs in the near term relative to the April 2026 release. See Commodity Prices.

• Data-centre demand now Modo Energy’s own forecast: Data-centre electricity demand is now sourced from Modo Energy’s own forecast rather than AEMO’s in-scenario assumption, projecting NEM-wide demand rising from 5.5 TWh in FY2026 to 36.8 TWh by FY2050 in the Central scenario. This is a change in data source rather than a new demand category; data-centre load was already modelled in the April 2026 release. See Demand.

• Household battery forecast uplift: Modo Energy’s household battery energy storage forecast has been revised upward to 28.7 GWh by 2030, from 18.1 GWh in the April 2026 release, a 59% increase. Household batteries continue to be modelled using the same mechanism as before: a 1.7-hour duration, split into coordinated and passive storage using the AEMO ISP Step Change ratio. See Demand.

• Coal retirement updates: Gladstone units 3 and 4 have been brought forward to retire at the end of 2033. Manual retirement overrides for Loy Yang A and Loy Yang B have been removed in favour of dates from AEMO’s generator registry and Forecasting Assumptions Update (FAU). Callide B now follows AEMO’s 2026 FAU retirement date of 2031, having previously been assumed to retire in December 2028. Retirements across the Queensland OCGT cluster (Braemar and Oakey units) now occur progressively, one unit per year from 2048. See Thermal Generation.

• Market Price Cap updated: The Market Price Cap (MPC) has been updated to the AEMC’s 2026-27 reliability settings, rising to $23,200/MWh for FY2026-27, and is indexed forward on the AEMC’s published schedule for subsequent years.

April 2026 release (update from February 2026)

Market pricing model updates

• Export-exposed coal pricing: Fuel costs for export-exposed black coal plants (Eraring, Mt Piper, Vales Point B, Gladstone) are now derived from ICE Newcastle coal futures rather than ISP commodity prices. This better reflects the opportunity cost these plants face in the global seaborne coal market, and is a key driver of higher near-term wholesale prices in this release. Other black coal plants continue to use ISP-derived fuel prices. See Thermal Generation and Commodity Prices.

• BESS pipeline improvements: The near-term battery buildout model has been simplified and improved. Delay assumptions are now applied uniformly by project status, with granularity of on-time, delayed 1 quarter, 2 quarters, 3 quarters, or 1 year. Projects classified as “Discontinued” are now excluded, and the underlying asset database has been expanded with broader coverage of project name mappings and multi-stage developments. See Storage.

• Household CER battery forecast: Behind-the-meter battery storage projections have switched from a blended AEMO ISP assumption to Modo Energy’s Conservative household BESS forecast, with an assumed duration of 1.7 hours. This provides a more grounded view of household storage uptake, which affects operational demand and long-term price formation. The coordination ratio continues to be sourced from AEMO ISP Step Change. See Demand.

• Custom scenario modelling: Users can now override key input assumptions when requesting a custom forecast run, enabling bespoke scenario analysis beyond the standard Central, High, and Low cases. See Scenario Modelling and Running a Forecast.

• Tomago DSR retirement removed: The previously assumed 2029 retirement of the Tomago aluminium smelter demand-side response (500 MW, NNSW) has been removed. The load now persists through the full forecast horizon, aligned with AEMO’s ESOO Step Change assumptions.

• CER allocation correction: State-level consumer energy resource allocations have been corrected. The previous version applied these proportions with a one-year offset, which has been resolved.

• Synthetic reference year: The model now seeds projections with a synthetic reference year spliced from months of different historical years (2016 to 2025), replacing the previous use of 2023 as a single reference year. Each month is selected to keep simulated prices as close as possible to the ten-year median for each state, materially reducing the regional price bias that any single-year choice imposes. See Reference Years.

Input data updates

• Coal prices: ICE Newcastle coal futures have risen approximately 25-30%, from A$6.40/GJ to A$8.50/GJ in the near term. This directly increases wholesale price forecasts during periods when export-exposed coal plants are marginal.

• Gas prices: Wallumbilla gas futures have softened, with Q2-Q3 2026 prices declining from $12.50/GJ to $11.40/GJ. See Commodity Prices.

• Marginal Loss Factors: MLFs have been updated from the FY 2025-26 final determination to the FY 2026-27 draft determination. See Marginal Loss Factors.

February 2026 release (update from November 2025)

Market pricing model updates

• Minimum synchronous generation: The model now enforces minimum synchronous generation requirements per NEM state to maintain system security. Thresholds decline over time as synchronous condensers and grid-forming inverters are deployed. See Generation and Storage.

• PPA bidding tiers: Renewable capacity is now partitioned into three distinct PPA bidding tiers reflecting different contract structures (no-floor CfD, floored CfD, and LGC-rational). See Renewable Generation.

• Coal forced outage modelling: A new two-category approach models units that are offline at the start of the day separately from running units that experience partial outages. See Thermal Generation.

• Dynamic hydro dispatch: Reservoir hydro output now adjusts dynamically based on residual demand conditions, replacing the previous fixed scaling approach. See Reservoir Hydro.

• Thermal generation improvements: Outage sampling is now filtered to high-capacity-factor plants. See Thermal Generation.

Input data updates

• Coal retirement timeline updates: Eraring (NSW, 2,880 MW) retirement extended to April 2029, Callide B (QLD, 700 MW) set to retire December 2028, and Yallourn West (VIC, 1,450 MW) set to retire September 2028, reflecting the latest announced timelines. See Generation and Storage.

• AEMO REZ profiles: Renewable capacity factors for new builds are now sourced from AEMO Renewable Energy Zone generation traces, providing location-specific profiles across all 9 NEM substates. See Renewable Generation.

• Rooftop solar assumptions: Rooftop solar projections have been updated from AEMO ISP Progressive Change to Step Change, reflecting a higher assumed uptake of distributed solar.