Price forecasting methodology and discussion


ITK’s NEM price forecast is underpinned by our electricity market model. The model produces an electricity generation mix and resulting nominal prices for each half hourly interval for an average day, for each financial year from 2019 to 2025.
The NEM is split into three regions in the model: New South Wales, Queensland, and a combined Victoria, South Australia and Tasmania region. Prices in each region are determined by using available supply aggregated by fuel type, subject to a predetermined merit order, to satisfy demand. Supply sources are attributed a bid price level, based on marginal cost plus any relevant adjustments, and the bid of the marginal fuel source determines the wholesale electricity price for each interval.

Forecast prices

We forecast price for each region, and a volume weighted average for the NEM. The price categories we forecast are:
– Flat load. An average price across all half hourly intervals in the day
– Peak load. An average price for the intervals from 7am to 10pm
– Off peak load. An average price for the periods 12am to 7am, and 10pm to 12am
– Solar and wind dispatch weighted. A weighted average price across the intervals solar and wind are generating

Half hourly model structure

Each half hourly interval for each year features the following data points:

Underlying demand. This is total electricity demand across the National Electricity Market and is driven by FY 2018 underlying demand, subject to our annual growth estimates

Rooftop solar generation. Our rooftop capacity estimates are based on annual capacity growth assumptions. Capacity is scaled by the average FY 2018 daily rooftop generation shape

Ex-rooftop demand. The demand for grid supplied electricity; underlying demand minus rooftop generation

Utility solar. Grid connected solar generation reflects our inputs on solar capacity build. Capacity is scaled by average daily generation profile, currently based on NSW profile data

Wind. Generation from wind is based on our capacity build inputs. Capacity is scaled by average daily generation profile for each state; Queensland is currently based on NSW profile data

Must run coal, gas and hydro. We have incorporated minimum volumes of thermal and hydro generation that must be generated, as a result of technical considerations at thermal plants, water license obligations for hydro, and a minimum level of market share coal generators are likely to want to maintain in future – this is especially relevant for New South Wales. We treat these must run volumes as non-price setting volumes, and enter the merit order effectively at zero cost

Coal. For demand that remains unsatisfied by variable renewable energy (VRE) and must-run sources, we asses coal to the be the next cheapest, and therefore next dispatched, fuel source for Queensland and the combined Victoria, South Australia and Tasmania region. Coal plant capacities are capped at the maximum volume generated on average for each half hourly interval in FY 2018. For New South Wales, interconnector imports from Victoria and Queensland take precedence in the regional merit order over domestic NSW coal as a result of cost competitiveness. NSW coal therefore contributes to the supply and demand balance after imports from Victoria and Queensland (see below for interconnector flows)

Combined cycle gas. Following VRE, must-run sources and coal, combined cycle gas (Gas CC) is the next contributor to meeting remaining demand. Aggregate gas CC capacities for each region are kept flat at FY 2018 levels.

Hydro. We assume that price sensitive (i.e. non-must run) hydro volumes are dispatched when required following gas CC. Total hydro volumes are capped at the average of FY 2018 levels for each half hour.

Open cycle gas. Based on our assessment of marginal costs, open cycle gas (gas OC) is the last fuel used to meet demand in each half hour. Gas OC aggregate capacities for each state are kept flat at FY 2018 levels. The exception to this rule is during evening peak periods, where OC gas may enter the generation mix prior to combined cycle given it often has a faster start time.

Interconnector flows. As the state with the highest coal generation costs, New South Wales imports electricity from Victoria, South Australia and Queensland in the price model, subject to capacity limits and timing assumptions for upgrades and new connection build. Availability of export volume is calculated as the excess of VRE, must-run sources and coal over ex-rooftop demand. Demand for imports in New South Wales is calculated as the deficit of VRE and must-run sources under ex-rooftop demand. Actual flows are determined by the minimum of availability, demand, and interconnector capacity, with a floor value of zero.

Physical assumptions

Demand and rooftop generation

We expect underlying demand for electricity to grow year on year, albeit at a slow rate. Much of the increase in underlying demand is offset by growth in rooftop solar generation, driven by government based incentives and high retail electricity prices. Average daily grid demand does rise over the forecast period although the increases are very small, and midday grid demand falls as a result of the rooftop generation shape.

Utility scale renewable generation capacity

Our base case incorporates significant utility scale wind and solar construction, prompted by both federal and state energy policies. Committed projects enter the model from our database of assets undergoing commissioning, under construction, at financial close or with a credible offtake contract. We also forecast unannounced future commissioning volumes which represent projects that have not yet secured financing or offtake contracts.

Thermal generation capacity

We expect installed gas generation capacity to remain relatively flat over the forecast period, with the exception of a small number of fast start facilities.
We have imposed both maximum and minimum generation limits for coal. To generate annual average results, we have limited New South Wales coal generation to 85% of notional capacity. For Queensland and Victoria, we have limited coal generation to a maximum of FY 2018 levels in each half hourly interval.

For New South Wales we have implemented a minimum generation level of 2 GW, to limit the degree of morning and evening ‘ramping’ that results from high levels of solar penetration, and the likely desire of coal generators to defend a certain minimum market share.

Inter-state interconnector capacity (inbound to NSW)

Notional increases in interconnector capacity are incorporated into our forecast, including the construction of a SA-NSW link. We adjust the interconnector notional capacities in the model to reflect constraints that limit their effective throughput.

Costs and prices

We allocate a price to each fuel type which reflects our expectation of how generators of that fuel are likely to bid into the NEM. The fuel specific price has a number of components:

– Fuel cost. The cost per MWh of procuring coal and gas for generation. This is determined by multiplying our coal and gas price forecasts with an average heat rate for that fuel type (where the heat rate represents the energy required from each fuel to generate one MWh). Renewable energy sources of course have no energy costs.
– Fixed operating expenses. While not a component part of the short run marginal cost (SRMC), generators will need to recover fixed operating expenses over the course of a year in order to keep operating.
– Sustaining capital expenses. Again, not part of the SRMC, but capital spending on existing plants will need to be recovered.
– Coal uplift. To reflect the concentration of generation ownership in the NEM, and the ability at times for generators to bid higher than marginal cost, we have added an uplift for certain fuels in certain years to capture strategic bidding behavior. A central assumption in our forecast is that the increase in renewable generation will reduce the available market share for incumbent coal generators. This will create greater competitive tension, forcing bids down towards SRMC over time.
For hydroelectric generation, we have assumed it bids into the market at the same price level as open cycle gas, but hydro volumes are taken before gas OC.

How wholesale prices are determined in the model

The half hourly model calculates a price for each region based on the marginal generation fuel type in each half hour, and the interconnector flows in or out of that region. The half hourly interval prices are averaged to provide an average forecast price per year for each region, and for each price category (flat, peak, off peak, solar, wind).

For an importing region (NSW). 

If the region is importing, but the interconnector flows are below maximum capacity, the regional wholesale price is set by the price of the generator that satisfies the marginal unit of demand. This will be a local generator is it is required (which is most of the time), or a generator in an exporting region in the event that demand is fully satisfied before local coal generation is required in the market.

If the region is importing and interconnector flows have reached maximum capacity, the price is set by the local fuel required to meet marginal demand, plus an uplift to reflect the lack of local competition that has arisen from the region becoming “islanded”.

For an exporting region. If interconnector flows are below maximum capacity, and local generation is still required in the importing region, prices for the exporting region are set by the marginal generator in the importing region. A price reduction is applied for the exporting region to reflect transmission losses across the interconnector. 

If interconnector flows have reached maximum capacity, the local generator in the exporting region that is required to meet marginal local demand sets the price in that region.


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