Perfect storm drives down NEM wholesale electricity prices, but “the only way is up”?

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In this update, we discuss our expectations for wholesale prices in the National Electricity Market (NEM) in line with our latest Australian Electricity Outlook (AEO).

Our quarterly AEO provides an outlook for wholesale electricity prices in the NEM over medium- (16 quarters) and long-term horizons (annually to 2040). 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.

‘Perfect storm’ comes to fruition, driving down wholesale prices

As we flagged in our earlier update, the coronavirus pandemic has helped to create a perfect storm for the wholesale electricity market, with lower gas and coal prices, reduced operational demand, the commissioning of large renewable energy projects, and increased hydro and coal-fired availability seeing NEM regional average prices fall to to $33-59, 17 to 45% below the same period last year, the lowest level since 2014-15.

Figure 1: Weighted average NEM wholesale price (average all regions)

We discuss the current price environment and the key drivers of our Central Case forecast below.

Lower operational demand

Despite the widespread economic impact of the COVID-19 pandemic, its impact on Australia’s total electricity demand was modest (compared to international markets) due to the large reduction in commercial demand being offset by large increases in residential demand, along with the continued operation of large industrial facilities, which make up a relatively large proportion of Australian electricity demand.

Compared to Q2 2019, operational demand is down 2 per cent, with COVID-19 contributing an estimated 2 per cent reduction and increased distributed photovoltaics (PV) resulting in a further 1 per cent reduction, partially offset by a 1 per cent increased heating requirements due to cooler weather. The overall decline remains within recent trends, however, energy consumption is projected to continue to decline for the next several years, leading to a medium-term loosening in the supply-demand balance though the first half of the decade.

Commissioning of large-scale renewables

Just 0.6 GW of solar and wind capacity have been commissioned so far in 2020, down from 2.6 GW in 2019. Although utility-scale solar and wind continue be built at an impressive rate, the final step of delivering electricity into the grid has experienced major delays in some zones due to outdated grid infrastructure.

Despite this, more than 3.8 GW of new wind and solar remains committed to enter the NEM. Existing supply between construction and final commissioning will also increase output as transmission restrictions and other curtailment issues are resolved. In total, we anticipate the commissioning of 4.7 GW of large-scale renewables over the next two years, driven by large wind projects in NSW and VIC. This excludes more than 2 GW per year of behind-the-meter supply that will also be added at current build rates.

Collapse in fossil fuel prices

Figure 2: Gas versus coal input costs

Source: AER analysis using Newcastle coal index.

The largest driver of the drop in wholesale prices is the role of gas. COVID-19 has caused demand to collapse, driving significant price volatility in the oil, LNG and thermal coal markets. Brent Crude oil prices reached a low of around A$30 per barrel towards the end of April, before recovering to between A$60-65 per barrel. Japan Korea Market (JKM) liquified natural gas (LNG) prices fell to a record low of A$2.77/gigajoule (GJ).

As a result of decreased exports, Australian east coast gas inputs costs fell below traditionally cheaper black coal input costs in NSW. Coal export prices, however, have also fallen sharply as the pandemic and recession impacts coal purchases. This has reduced input costs for some Australian generators but jeopardises the sustainability of some higher-cost coal mining operations, which could create a logistical scramble for reliable sources of coal.

While gas makes up only a small percentage of the NEM’s total generation mix, lower gas prices have indirectly resulted in lower offers from other units, even if gas-fired generation is not dispatched. Although Australian east coast gas prices are forecast to grow over the long-term, this is off a base of around $4 per GJ. We expect spot gas prices to average less than $8 per GJ for the next decade, or until the global gas glut is overcome. This primarily affects gas-dependent Queensland and South Australia, but also depresses daily peak pricing across all regions.

Gas (and pumped hydro) likely to lose the fight to become Australia’s ‘bridging fuel’

Even if gas prices remain relatively low over the next several years, gas plants are expected to struggle in the new Five-Minute Settlement (5MS) market, which will now begin on 1 October 2021. Other than low fuel costs and well-placed transmission access, gas generators have little competitive advantage in a shorter-term trading market, where large-scale batteries are likely to emerge as the most economical way to trade, dampening extreme pricing and reduce ancillary costs such as frequency control.

In the medium-term Snowy 2.0 is assumed to add long duration storage – although at only a fraction of its 2,000 MW nameplate capacity – to shift excess variable renewable energy generation into peak pricing periods. Our Central case forecast suggests there eventually needs to be enough of a simple arbitrage opportunity – e.g. averaging $130 to $300/MWh – for pumped hydro to earn a return. This daily energy differential is modelled to begin emerging between mid-day minimums and evening peaks in the months of February and September for solar-heavy states. Seasonal arbitrage opportunities between the spring and summer months are also anticipated to begin emerging as traditional ‘baseload’ generators close.

Current data suggests that pumped hydro is a more cost-effective energy arbitrage solution for the multi-hour timescale, however, a lack of flexible revenue streams, long project development timelines and policy uncertainty are forecast to inhibit the commercial growth of pumped-hydro over the next few years. Rapidly falling battery costs could tip the economics of energy storage towards batteries in the two- to four-hour timescale. Durations beyond four hours of storage may also become the domain of batteries due to recent advances in long duration chemical battery technologies.

While the recent drop in gas prices means that gas has a renewed competitiveness in providing flexible capacity today, this is unlikely to be sustainable given the capital costs and charging costs for energy storage are likely to continue to decline. This suggests some other form of energy storage will eventually beat out gas for the role of balancing variable renewable energy and ‘bridging’ our way to a clean energy future.

The only way is up for wholesale electricity prices?

Given that the current low wholesale price environment is being driven by a perfect storm of downward drivers (which are likely to persist), as one or more of these factors change, wholesale prices may now have nowhere to go but up in the longer-term.

Low fossil fuel prices, along with continuing soft demand, are anticipated to keep wholesale prices significantly lower than we have recently experienced over the medium-term. We forecast prices to stabilise around current levels, between $40 and $65 per MWh, except during summer quarters when the market is estimated to remain tight during certain periods.

Figure 3: Annual average wholesale electricity price – Avg all regions (Central Case).

Source: RepuTex Energy, 2020

After 2021, steadily rising gas prices (off a low base) are expected to begin to break the low price environment. We expect all states to see steadily rising gas prices, but with differing results based on gas’ relative influence on prices. In the northern regions, prices are forecast to rise slightly as black coal finds some relief from rising gas prices along with the withdrawal of Liddell.

The commissioning of large-scale renewable energy projects, particularly VIC wind, is likely to keep prices in southern regions slightly lower. QLD and VIC are forecast to continue to be dominated by relatively low-priced coal generation during the non-summer quarters over the next four years, exporting to other regions when renewable generation increases. NSW is forecast to continue importing energy due the higher cost of NSW coal-fired generation and the closure of Liddell after the summer of 2022-23.

Despite the impact of higher gas prices, the continued 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 some downward pressure on wholesale electricity prices. We continue to forecast renewable energy generation will grow to almost 50 per cent of electricity in the NEM by 2030, despite the absence of a federal policy framework beyond the LRET. Even without further policy, renewable energy is calculated to make up 75 per cent of generation by 2040.

Neither renewable energy threshold is estimated to trigger large increases in wholesale electricity prices. As shown in Figure 3, at no time in the outlook period are annual average wholesale prices (average all regions) forecast to exceed $100/MWh under our Central Case, with the weighted average wholesale price remaining below $75 per megawatt-hour (/MWh) for the foreseeable future.

However, as renewable energy investment slows, the closure of major coal-fired facilities may exacerbate steady growth in energy consumption after the mid-2020s. This is forecast to lead to higher wholesale electricity prices in the 2030s, assuming the continued absence of a policy framework to accelerate investment in new generation and utility storage ahead of expected coal-fired facility retirements.

As we have previously noted, with no NEM-wide coordination to guide new investment prior to large coal-fired generation retirements, renewable energy and storage investment is again expected to slow, with current prices deterring all but the largest developments from proceeding.

An alternative… or reality?

As has been noted in recent media (read more here), AEMO’s latest ISP underscores the current rate of renewable energy commissioning, with its “step change” scenario not currently reflecting the stretch target that its name implies.

Committed increases in the clean energy generation indicate that the market is already following AEMO’s ‘step change’ trajectory. However, market rules and transmission infrastructure are now curtailing constructed projects from contributing a larger proportion of generation. As a result, the significant growth of renewable energy contribution is likely to be blunted, remaining between 30 and 40 per cent under our Central Case until key infrastructure issues are addressed.

Figure 4: Percentage renewable energy generation in the NEM

Source: Adapted from @simonahac, RepuTex Energy 2020

The Step Change scenario (which we run as our Alternative Case, not presented here) 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 is underpinned by the implementation of a carbon budget for the electricity sector from 2020-50, achieving net-zero emissions prior to 2050.

This scenario therefore provides an important reference point for future investment necessary in the NEM under the Paris Agreement, with the alternative quickly becoming a reality in terms of both new capacity and competitive dynamics.

Contact our electricity advisory team

If you have any questions, comments, or to arrange a briefing on this outlook, please contact our Electricity team leader, Bret Harper.

Click here to access our full Australian Electricity Outlook (AEO), including our medium- and long-term expectations for wholesale prices under our Central and Alternative cases. If you are not a current subscriber, you can click here to learn more.

Kind Regards,
The RepuTex Team
Australian Electricity Markets

About our Australian Electricity Outlook (AEO)

Our 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 our 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.

The AEO 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.

Click here to learn more about our Australian Electricity Outlook (AEO) service.


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