In part two of this two-part series we discuss our long-term expectations for wholesale electricity prices in the NEM to 2040, derived from our quarterly Australian Electricity Outlook (AEO).
Modelling considers two key pathways for the future development of the NEM, including our Central case for the “current transition” of the market, and an Alternative case, reflecting AEMO’s “step change” shift to renewable energy in line with a “well below 2°C” carbon budget under the Paris Agreement.
As asset owners and investors seek to make informed long-term decisions, modelling provides an independent view of price dynamics in each region of the NEM, underpinned by the likely economic effects of different technology pathways, and the impact of renewable energy and new flexible capacity on competitive market dynamics, providing an important reference point for future investment and policy decisions.
Modelled scenarios for the NEM
Modelling of scenarios serves an important role in understanding the impact of potential futures on the market, helping decision makers to assess potential risks, opportunities and development needs in the NEM.
While there are many combinations for possible future market development, the scenarios modelled within our AEO capture two key pathways, including a Central case for the “current transition” of the market, and an Alternative Case, reflecting AEMO’s “step change” shift to renewable energy in line with a “well below 2°C” commitment under the Paris Agreement.
Table 1: Summary of modelled scenarios
In particular, the Step Change scenario recognises the need for more aggressive action on climate change under the Paris Agreement, assuming a faster rate of technology cost reductions for low emissions technologies, and the idealised design of policy to drive the uptake of renewable generation resources with more ambition than current state and federal frameworks.
The scenario is underpinned by the implementation of a cumulative electricity sector “carbon budget” of 1,465 Mt CO2e from 2020-50, achieving net-zero emissions prior to 2050, consistent with an average temperature rise of “well below 2°C” (1.4 to 1.8°C).
Modelling of this Alternative scenario therefore provides an important reference point for the level of future investment necessary in the NEM under the Paris Agreement.
Additional sensitivities are also considered (not presented in this article) as a complement to the scenarios, with an emphasis on fuel price sensitivities, helping to quantify the magnitude of key assumptions and underlying risks that may materialise over the forecast period.
Our quarterly Australian Electricity Outlook (AEO) provides an outlook for wholesale electricity prices for each region of the NEM over medium- (16 quarters) and long-term horizons (annually to 2040), along with forecast outcomes such as change in capacity and generation mix, and analysis of the major factors impacting the market.
Analysis is underpinned by our proprietary National Electricity Market Renewable Energy Simulator (NEMRES), which calculates annual generation and transmission expansion decisions in each region of the NEM as well as intra-hourly least-cost dispatch to replicate AEMO’s Integrated System Plan scenarios.
A common set of assumptions is applied in each modelled case, including announced closures (e.g. the last 3 units of Liddell in April 2023) and the commencement of Snowy 2.0 by 2025, with different settings for policy, consumption, technology cost, economic retirements and new capacity additions overlayed in each case.
Economically optimised capacity additions and closures are proposed by our electricity model based on annual dispatched generation.
Proposals are cross-checked by analysts to find indicative units based on capacities that best meet retirement volume criteria and RepuTex’s view on the relative economics and forecast profitability of each unit.
Many combinations of technology-type closures could meet these requirements; therefore, any named facility retirements should be treated as indicative only.
In addition, each region is required to have a minimum level of firm capacity available, with additional firm capacity able to be shared across regions based on interconnector capabilities and typical coincident available capacities in neighbouring regions.
This is supported by new network developments, which are assumed to be undertaken in both cases to address network strength as new capacity comes online, occurring in a staggered way to match AEMO’s Integrated System Plan (ISP).
Key findings for each case are summarised below.
1. Australia on track to exceed 75% renewables by 2040
As noted in our earlier outlooks, we continue to forecast Australia will reach 50 per cent renewable energy generation by 2030 under our Central case, despite the absence of a federal policy framework beyond the Underwriting New Generation Investment (UNGI) scheme.
Even without further policy, renewable energy generation is forecast to grow to 75 per cent of NEM generation by 2040.
New capacity additions are expected to initially be driven by state renewable energy targets, with the Queensland Renewable Energy Target (QRET) forecast to drive almost 28,000 GWh of new renewable energy generation, and the Victorian Renewable Energy Target (VRET) forecast to drive more than 5,000 MW of new capacity in Victoria.
Solar is expected to make up the largest component of new generation, at almost 22 GW of new large-scale capacity, along with 11.5 GW of distributed PV to 2040.
Rooftop solar installation achieved record levels in 2019, and although lower rates are forecast we continue to anticipate growth in small-scale solar, representing around 27 per cent of all renewable capacity needed for the NEM to reach 75 per cent renewables by 2038.
Figure 1: Change in annual capacity in the NEM – Central case
2. Headwinds for thermal generators under current policy
Under the Central case, major thermal power plant closures are assumed to occur in line with announcement timelines, with more than 18 GW (53 per cent of Australia’s thermal capacity) modelled to exit the market by 2040, replaced by a best value combination of 41 GW of new solar and wind generation.
By the mid-2020s, the Central case forecast indicates a shift in coal and gas generation, with fossil fuel output giving way to renewables as coal generation falls about 8 TWh from today’s levels and gas approximately 17 TWh.
The much larger decline in gas generation is attributed to its relatively higher fuel price, and the role of new interconnectors reducing the need for continuous gas generation to support energy security. Gas’ role as available backup generation could also be eroded as renewable energy is made more dispatchable by committed storage projects, such as Snowy 2.0 which assumed to be commissioned by the mid-2020s, contributing hundreds of GWh of firmed generation.
Meanwhile, lower cost coal generators in New South Wales, Queensland, and Victoria may be able to replace conventional ‘baseload’ volumes by substituting for new markets as regional interconnectors are completed.
Beyond 2030, however, modelling suggests that even the more flexible black coal-fired facilities will be largely replaced by renewables.
As fixed and operating costs increase for aging fossil fuel generators, and firmed renewable costs continue to decline, this is modelled to drive more capacity closures.
As this occurs, reliability is expected to be supported by a combination of behind-the-meter batteries, other demand side participation, and increased transmission interconnection.
While large-scale energy storage like large-scale batteries and pumped hydro will play a critical role, much of the capacity that can contribute to electricity system reliability is modelled to accumulate from relatively small distributed demand side resources and investment in transmission.
3. Renewables to drive lower prices to 2030, but policy gap to hit
Under our Central case, the commissioning of renewable energy capacity, along with investment under the VRET and QRET and the installation of small-scale rooftop solar, is forecast to maintain downward pressure on wholesale prices though the 2020s.
Wholesale prices (average all regions) are forecast to remain between $50 and $70/MWh over the next decade.
However, as renewable energy investment remains low due to lower prices and a lack of energy policy, the inevitable closure of major coal-fired facilities in the 2030s may exacerbate prices, at the same time as assumed growth in energy consumption kicks in after 2030.
With no NEM-wide policy framework to guide new investment prior to large coal-fired generation retirements, modelling suggests a return to elevated wholesale prices would be needed to incentivise new capacity additions, triggering a return to higher wholesale electricity prices in the 2030s.
4. Step-change would lead to deep decarbonisation by 2030-40
Under the Alternative “Step Change” case, characterised by more aggressive action on climate change and a “well below 2°C” carbon budget, we consider AEMO’s pathway where economic growth is strong, underpinning faster and larger greenhouse gas emission abatement activity.
The net effect is a higher total amount of electricity consumption, a ‘peakier’ demand profile (due to lower demand-side measures), and a faster power system transformation.
Over a long-term horizon, a decline in energy consumption – from the grid’s operational perspective – is forecast to be stronger across almost all regions, driven by the rapid pace of distributed PV self-generation and Virtual Power Plant (VPP) batteries.
Under this scenario, an average of 10 GW more distributed PV (than the Central case) and 1 GW of VPP capacity is added for the first five years.
As these distributed assets accumulate, ‘baseload’ demand profiles are forecast to be eroded, helping to maintain average wholesale prices below $60 per MWh, and increasing the value of flexible capacity to balance the higher penetration of variable renewable energy generation.
This dynamic, along with long-term carbon budget restrictions, is a fatal combination for coal-fired units. By 2030, about 35 per cent of current thermal capacity is forecast to exit the market, growing to 64 per cent by 2040.
This is modelled to see Australia reach 70 per cent renewable energy generation by 2030 under the Alternative case, growing to 90 per cent in 2040.
Figure 2: Change in annual capacity in the NEM – Alternative case
With the forecast closure of more than 11 GW of coal-fired assets in NSW, QLD and VIC by 2029, major electricity generator exits are almost 8.8 GW greater than the Central case over the same period. Coal-fired retirements, along with increasing consumption from electrification, are projected to lead to higher and more volatile prices in the 2030s.
However, annual average prices are expected to remain below $80 per MWh though 2040 due to continued reductions in energy storage costs.
Aside from rising average prices, major generator closures in coal-fired dominant regions could lead to higher and more variable prices in the 2030s due to a reliance on variable generation for 70 to 90 per cent of energy.
Most remaining large capacity units are therefore likely to be required to perform more flexibly to follow variable generation changes throughout the day and shift traditional down-times for maintenance to better match seasonal surpluses in variable renewables in their region.
5. Step-change shift is likely to maintain lower wholesale prices
Notably, modelling suggests that renewable energy penetration of around 75-90 per cent under the Central and Alternative cases is not forecast to trigger large increases in wholesale electricity prices, owing to continuing advances in demand side resources and cost decreases for energy storage technologies, which are forecast to firm renewables at lower cost than fossil fuel facilities by the 2030s.
Replacing Australia’s aging thermal power stations with new flexible capacity is therefore able to maintain lower wholesale prices.
Modelling therefore indicates that it is possible to de-carbonise the NEM, maintain reliability, and keep wholesale electricity prices below $80/MWh, however, de-carbonisation is unlikely to occur unless the energy transition is accelerated from our Central case outlook.
In particular, this will necessitate the design of policy measures to incentivise investment in new generation and utility storage ahead of expected coal-fired facility retirements, rather than requiring a return to elevated wholesale prices to incentivise new capacity additions after thermal retirements.
In addition, changes in the generation mix will require new regulatory and market rules to support the technical shift in the grid and support new investment in network infrastructure, with new markets for key services (such as system strength and the incorporation of synthetic inertia) to be critical given the peakier demand profile of the grid and the need for a faster power system transformation.
Despite this, a power system dominated by renewables by 2030-40 is forecast to deliver reliable and affordable electricity, subject to the willingness of regulators and policymakers to overcome current policy uncertainty and establish clear investment signals for the market.
This article is published under RepuTex’s Australian power market service. RepuTex’s quarterly Australian Electricity Outlook provides an outlook for wholesale electricity prices for each region of the NEM over medium- (16 quarters) and long-term horizons (annual to 2040); along with expectations for LGC prices to 2040, forecast outcomes such as change in capacity and generation mix, and analysis of the major factors impacting the market in the forecast period. Click here to learn more.