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Increasing generation share of intermittent renewables will cause average wholesale prices to fall (and sometimes even be negative), though create regular and intermittent pricing peaks that could be much higher than in current/traditional systems.

Can these price risks be successfully hedged using existing or new physical/financial contracts, or is vertical integration between generation and retailing a more effective way to manage those risks?

• e.g. simulations using systems modelling using real data, and/or theory modelling taken to data, etc

Increasingly decentralised and uncoordinated intermittent renewables (e.g. rooftop solar), BESS, and EVs (as variable load with potentially large peaks, but also as storage or generation) transform traditional electricity retail customers into potential rival suppliers (as “prosumers”).

How will this affect wholesale pricing and competition, and what strategies might large-scale generators adopt to support or frustrate these consumer-level innovations?

What regulatory measures might be needed (or need to be avoided) to ensure such competition unfolds in a socially desirable way (i.e. in terms of consumer outcomes, emissions reductions, etc).

What role is there for coordination (or competition) between large-scale generators and distributors, since distributors will play a key role in either enabling/accelerating or delaying such innovations (i.e. so as to maintain distribution reliability, avoid waterbed effects between lines customers, etc)?

What are distributors’’ incentives to facilitate socially-desirable retail-level innovation, given it will compete at the margin with distribution?

Increasing penetration of intermittent renewables generation is likely to lead to “cliffs” that result in sudden/lumpy retirement of thermal generation, while increasing the need for firming/peaking generation (and/or economic storage, such as large-scale BESS, pumped hydro, large-scale interruptible demand – e.g. green hydrogen production?), unless and until there is sufficient overbuild of renewables that intermittency is adequately resolved.

What does this imply for:

average and peak wholesale pricing? (e.g. if firming/peaking generation enjoys enhanced market power in the transition)
the need for and viability of price (if they eliminate the scarcity rents needed to pay for fixed generation costs)?
What regulatory or market reforms might be needed?

e.g. capacity pricing for peaking or for all generation (instead of, or in conjunction with, energy-only pricing)
How can this be achieved competitively?

What is the socially-desirable level of generator market power in the transition?

At what point does solar penetration make lines contestable rather than network monopolies that need to be regulated?

What are equity implications if wealthier lines customers can defect from the network and leave less-wealthy households to bear lines fixed costs?

Under what conditions will there be a death spiral (i.e. less-wealthy customers left bearing an unsustainable burden of fixed lines costs so quality deteriorates and defection accelerates), or a cliff (i.e. a hard threshold is reached at which the lines operator is no longer viable)?

• e.g. do agent-based simulation of differentiated (e.g. wealthy/not, owner/renter) household uptake of DERs, and see how this changes their demand for network services – whether for supply or to inject to grid?
• at what PV price and/or electricity buy price will defection beat staying grid-connected – especially if there is BESS and/or EVs with V2G capacity (i.e. physical electricity transportation)?

• Hnrs/ Masters
• IT skills – Java and database engineering
• If an Hnrs project: then consists of
  • Literature review of AEMO and the rule making body AEMC
  • Explore the changes in ISP over time
  • Create specifications for input database to facilitate updates with changes to ISP
• If Masters
  • As above
  • Code new input data base in Java with front end

• Hnrs/ Masters
• IT skills – Java, database engineering, Matlab, Excel, specialised IT audio-visual software
• If an Hnrs project: then consists of
  • Literature review of AEMO and the rule making body AEMC
  • Explore the changes in ISP over time
  • Create specifications for input database to facilitate updates with changes to ISP
• If Masters
  • As above
  • Code new input data base in Java with front end

• With Bentley systems
• Build a visualisation of the electricity grid to demonstrate changes in modelled output such as power flows, generator dispatch or spot prices under different scenarios over a 24 hour period

• Hnrs/ Masters
• IT skills – Java and computer science
• If an Hnrs project: then consists of
  • Might have to be done in conjunction with Griffith computer science faculty
  • Literature review of options to enhance efficiency and run-time speed of computer software
  • Involve examining core/thread behaviour of the program and capacity to enhance multithreading capability
• If Masters
  • As above
  • Code new input data base in Java with extension to five-minute dispatch horizon.

• Literature review on transmission design limits, surge impedance loading, thermal, voltage stability and steady-state limiting characteristics, St Clair Curves under realistic line loading/steady state conditions
• Explore wind, solar, PHES and BESS dispatch and charging characteristics
• Most likely would require collaboration with Griffith University School of Electrical Engineering and Powerlink

• Literature review on reinforced learning algorithms and strategic games
• Other relevant learning algorithms – e.g. potentially game theory, artificial intelligence (at Masters level)
• Review of ANEM and application of learning algorithms/strategic behaviour in the model.

• Literature review on reinforced learning algorithms
• Build a simulation model to optimise consumer surplus – affecting both the objective function, equality and inequality constraints of the model
• Modelling the economic consequences of smart meter effects – e.g. withdrawal of demand in response to high electricity prices
• Energy policy implications – e.g. difference between demand response mechanisms and energy efficiency programmes

• Collate material on different energy sources and their minimum/maximum operation levels
• Develop a simulation model to assess behaviours of different combinations of generation sources under different market scenarios
• Implications for system balancing, reliability and emission outcomes under various decarbonisations scenarios such as the ISP scenarios.

Consideration of relevant issues could include:

• Treatment of revenue from spot and contract (e.g. hedge) markets
• Hybrid schemes that jointly involve both renewables and storage projects
• Behind the meter versus grid access arrangements
• Adequacy of existing hedge products and the role that financial innovation might play in producing new hedge products that more closely align with the special characteristics of both variable renewable and storage technologies – for example, proxy revenue swaps.

Relevant considerations could include:

• Investigate the linkage between network adequacy and system balancing requirements that are needed to achieve resource adequacy and a reliable electricity supply
• Required network augmentation under different NEM decarbonisation pathways, closely aligned with the ISP process
• Undertake cost-benefit analysis of an identified transmission augmentation accounting for the implications of any significant changes in fuel mix associated with deep decarbonisation pathways and/or potential closure of thermal plant
• Investigate the adequacy of the existing RIT-T framework to facilitate the required investment, how it can be improved, and the potential need for additional public or private sector investment incentivisation mechanisms
• How different transmission access models could influence broader consideration of transmission network adequacy and financing of transmission augmentation projects.

Relevant considerations could include:

• Undertake cost-benefit analysis of identified transmission augmentation accounting for the implications of any significant changes in fuel mix associated with deep decarbonisation pathways and/or potential closure of thermal plant
• Investigate the adequacy of the existing RIT-T framework to facilitate the required investment in transmission infrastructure in REZs, how it can be improved and the potential need for additional private or, public investment funding mechanisms
• Role of different transmission access regimes and funding/compensation arrangements
• Broader interaction between the REZ and rest of the transmission network including impact of congestion arising outside of the REZ, access regime arrangements and potential flow on effects to financial compensation arrangements determined for generation located within the REZ.

Consideration of relevant issues could include:

• What is system balancing and how can firming technologies contribute to this in a system with high penetration of variable renewable energy sources – e.g. time-shift, ramping
• Different types of firming technologies – e.g. BESS, PHES, OCGT, potential role of renewable hydrogen OCGT
• Advantages and limitations (in terms of technology characteristics and network balancing requirements) of shallow, deep and seasonal storage.