Renewables could have far-reaching ramifications amid a de-carbonising world, allowing nations to reduce carbon footprint, providing opportunities for non-carbon investments, and most importantly, empowering economic activity with a clean footprint.
In December 1998, the National Electricity Market (NEM) started to function as a wholesale electricity spot market. It comes under the cohort of state-operated – Australian Energy Market Operator (AEMO). The infrastructure of NEM includes state and private assets, with industry participants managing them.
The wholesale market connects five regional jurisdictions in the country that includes New South Wales (NSW), Queensland, South Australia, Victoria, and Tasmania, with the NSW region also including Australian Capital Territory. However, WA and Northern Territory doesn’t come under the NEM. The electricity market underpins a supply of about two-hundred terawatt hours of energy to consumers each year.
- Transporting electricity through high-voltage transmission lines from generators to large industrial energy users;
- Transmitting electricity to local electricity distributors in each region, allowing distributors to light up homes and businesses;
- Facilitating electricity transmission from generators to consumers through its spot market, which aggregates the output from all generators and schedule at a five-minute interval to meet demand.
The electricity market leverages sophisticated systems to communicate with generators, instructing electricity generators about the requirement in every five minutes. Thus, it allows to match consumer demand, and derive the current energy price.
Renewables Powering Half of Demand
The renewable energy market achieved the composition of just over 50% in total electricity demand at some point of time on Wednesday, 6 November 2019. The data from NEM suggested that the renewables were providing 50.2% of electricity to the consumer markets.
However, the renewables achieved this composition despite weak production, as some of the major renewables plants
in the country were only generating 50% of the capacity, according to media reports.
The list with constrained electricity output included four out of five solar plants in Victoria, Broken Hill solar farm in New South Wales, and Tailem Bend in South Australia, suggested media reports.
The 50.2% composition included a 23.7% contribution from rooftop solar, 15.7% contribution from wind power plants and 8.8% contribution from large-scale solar power plants, with hydroelectricity contributing 1.9%. Coal was generating rest of the energy with a 35.7% contribution from black coal, and 13.5% from brown coal plants.
Energy Prices Hitting Lows in States
The below figure shows average wholesale electricity price in Q3 2019.
In Queensland, the growth of large scale and rooftop solar in absence of storage capacity had dragged by average midday price of electricity in the region close to zero in the September quarter, according to the Australian Energy Market Operator.
In its Quarterly Energy Dynamics Q3 2019, AEMO quoted;
“With low operational demand and high daytime solar output, de-rating of the interconnector led to excess Queensland supply and several trading intervals reaching prices below -$400/MWh”
In South Australia, the spot price for electricity was zero or negative 8.4% of the time in the September 2019 quarter, compared to 3.4% of the time in Q3 2018, while the frequency of negative prices remained comparatively lower in the other regions (NSW, Victoria and Tasmania) served by NEM.
Factors that drove negative prices in South Australia included high variable renewable energy (VRE) output, and major negative intervals occurred when SA VRE output exceeded 1,100 MW.
In addition, the interconnector constraints also led prices to hit negative territory, and AEMO also invoked constraints to limit energy transfer on the VIC-SA interconnectors due to abnormal weather conditions.
Is Supply At Risk?
Industry participants in the renewable energy markets in the country are facing heat from the Australian Energy Market Commission (AEMC). AEMC, having rejected ambitious plans of industry participants to move away from the existing method of assessing transmission and network losses, has insisted its proposals.
The method-in-use presently – “marginal loss factors”, which is used to calculate power lost during transmission, would not go out of service, while rejecting industry participants’ push for average loss factors method, suggested an AEMC draft ruling.
Industry participants have voiced out opinions, warning that new investments are at the risk as financiers and developers are losing confidence in the Australian markets, according to media reports.
The rule change request was placed before AEMC by Adani Renewables along with other wind and solar developers, including a highly sophisticated group of investors that had advised investments would vanish without the changes.
Electricity generators are pushing for a modification in the structure of the way losses of electricity during transmission are allocated, after witnessing downgrades in the expected revenue.
AEMC noted that investments in new wind and solar plants would be encouraged in the strongest part of grid. It was said that a change in the rule would potentially result in consumers paying for inefficient investments in generators located in remote and congested areas.
However, AEMC has also acknowledged the need for more flexible terms in loss calculation, emphasising to improve the predictability of losses around the network due to transmission.
Meanwhile, the commission is working on several reforms, including right sales to generators to have greater control over access to the network, adoption of new technologies by national electricity grid such as electric vehicle
and battery storage, among others.
In Q3 2019, the ASX Electricity futures had depicted an upward trend, while calendar 2020 (Cal20) swaps made record average high across all regions.
Meanwhile, in Q3 2019, the Victoria Cal20 averaged $102/MWh, an increase of approximately $7.50 each MWh compared to Q2 2019, and Q1 2020 cap product increased by around $11 MWh compared to Q2 2019.
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