Overview

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 2030. 

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 dispatch weighted. A weighted average price across the intervals solar is 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.
  • 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.

Demand is forecast to grow at 1% or less, depending on region, rooftop solar is forecast to grow at close to 1 GW per year. Existing new supply under construction is allowed for and we then assume enough additional supply to achieve a 50% renewable energy share by 2030.

The new supply will supplant existing supply and we assume by and large that higher cost supply will be the first to be supplanted. This means gas and then NSW coal. This forces dispatchable power into a smaller daily operating range, that is the morning and evening peaks.

A key driver in our model is the industry price response of coal generators to lower volumes. We see the price range for coal generators as the roughly their annual operating costs, fuel, maintenance and capex at the low end and the price of the next alternative gas on the high end. That window can be say around $20 MWh with the outcome dependent on behaviour.

  • note that our forecast pages have scroll bars and some charts and tables may not be visible without scrolling both horizontally and vertically.

*

Last Updated on