The electricity, gas and renewables sectors are currently undergoing significant changes as the industry transitions from a primarily coal-based generation mix to greater levels of variable renewable generation. High electricity and gas prices, network system security issues and emerging new technologies are major drivers in the transformation of the energy market. Amidst the boom in the development of wind and solar projects in recent years, the emergence of flexible storage technologies (i.e. batteries, and pumped hydro) is driving the shift away from coal and gas while assisting renewables to respond to the highly political issues of security, reliability and affordability of generation.
Australia continues to struggle to implement a policy mechanism to balance reducing carbon emissions, maintaining energy security, and enabling energy affordability. As a result, the regulatory frameworks around the energy sector are currently unsettled and are likely to evolve.
Australia has a number of separate electricity systems. The largest of these in the National Electricity Market (NEM) which encompasses Queensland, New South Wales, Victoria, South Australia, Tasmania and the Australian Capital Territory followed by the Wholesale Electricity Market (WEM) which operates throughout the South West Interconnected System (SWIS) in Western Australia. Smaller systems include the North Western Interconnected System in the remote Pilbara region of Western Australia and the Northern Territory Electricity Market which operates in the Northern Territory of Australia.
National Electricity Market
The NEM is the largest electricity system in Australia comprising approximately 40,000km of transmission lines, around 9 million customers, and over 54,000MW of generating capacity with approximately A$16.6 billion worth of electricity traded each year. The NEM was established under the National Electricity Law (first passed in South Australia and then uniformly adopted in each jurisdiction) and commenced operation in 1998. The NEM is primarily governed by the National Electricity Rules.
The NEM is operated and regulated by the following independent bodies:
- Australian Energy Market Operator (AEMO) – market operator, market registrations;
- Australian Energy Market Commission (AEMC) – responsible for rule changes;
- Australian Energy Regulator (AER) – enforcement, retail and network licensing / exemptions, network revenue determinations; and
- Energy Security Board (ESB) –provides whole-of-system oversight of the NEM.
While many legal and regulatory aspects of the sector are governed by the National Electricity Law and the National Electricity Rules, certain key aspects can differ from State to State. These include planning and environmental approvals, transmission and distribution network licensing, retailer licensing (Victoria only) and generation licensing (other than NSW).
Participants in the NEM can be divided into three broad groups: generators, network service providers (i.e. transmission and distribution network operators) and market customers (i.e. electricity retailers). Most of the generators, network services providers and retailers in the NEM are now privately owned, however some level of Government ownership remains in each category. Large energy retailers in the NEM typically also own significant generation capacity, known as ‘gentailers’, however network services providers typically only hold transmission or distribution assets and do not participate in electricity generation or sale.
The retail price for electricity sold to consumers connected to the NEM is now largely ‘unregulated’ however a cap on the retail price for small customers on ‘default’ or ‘standing offer contracts’ has been re-introduced in Victoria, NSW, South Australia and South East Queensland. Further, electricity transportation costs (i.e. the charges that must be paid to network services providers) continue to be regulated by the AER in accordance with the National Electricity Rules.
The NEM itself is a gross power pool, in which the wholesale electricity price is determined for each region of the NEM (Queensland, New South Wales / Australian Capital Territory, Victoria, Tasmania and South Australia) every 5 minute trading interval.
To set this price, AEMO runs a reverse auction in the lead up to each trading interval and generators make offers (bids) to generate certain quantities during the trading interval at various prices. AEMO dispatches generation in the trading interval starting with the cheapest offer and moving through the bids until sufficient supply has been dispatched to meet demand.
The wholesale price for that trading interval will be the highest price that was bid by any generator that AEMO dispatched. The same wholesale price is received by all generators that were dispatched during the trading interval regardless of whether they bid a cheaper price. Currently the NEM wholesale price may range from -A$1,000/MWh to A$15,500/MWh in any trading interval. Consistent high market prices in recent years have resulted in increased pressure on governments to reform the NEM.
AEMO operates as a clearing house for settlement purposes by receiving from market customers (i.e. retailers) the wholesale price for all electricity consumed by their customers during the relevant trading interval and paying the wholesale price to all generators who generated electricity during the relevant trading interval.
Retailers generally charge their customers a fixed price for the electricity they consume. Retailers typically manage their exposure to the fluctuating wholesale electricity price by entering into hedges or other derivative contracts with other market participants or by purchasing electricity futures contracts.
The SWIS over which the WEM operates incorporates over 7,800 km of transmission lines, supplies about 18 terawatt hours of electricity each year has more than one million customers and 5,798MW of registered generation capacity, including 513 MW of non-scheduled generation. Unlike the NEM, the WEM is a net market (i.e. bilateral contracts between participants still play a large role) which trades both capacity (through its Reverse Capacity Mechanism) and electricity. AEMO is also system operator in the WEM.
When the NEM was established, the generation of electricity in the NEM was largely provided by coal and gas-fired generation. However, in the last decade this generation mix has been changing. One of the significant changes has been the halting of further development of coal-fired generation and a significant acceleration in the closure of major coal-fired power plants particularly in NSW and Victoria. At the same time, a number of gas-fired generators have been 'mothballed' as the result of significant increases in wholesale gas prices following the development of major LNG facilities in Queensland.
At the same time there has been a growing penetration of renewable energy in the NEM, predominantly from onshore wind and utility-scale solar PV plant. This growth has been supported by a number of State and Federal regulatory arrangements. More recently, storage technologies are being deployed to meet network system security and stability requirements as well as provide flexible ‘generation’.
In order to replace dispatchable base load coal-fired power, massive growth in renewable generation and the network infrastructure and energy storage facilities required to support it, will be required. As of 2022 the Australian government has introduced its ‘Powering Australia Plan’, which is designed to generate around A$76 billion in investment by 2030. Particularly, the Government plans to invest:
- A$20 billion to upgrade the electricity grid to support renewable generation;
- A$200 million to maximise rooftop solar and install 400 community batteries nationwide;
- A$500 million toward developing clean hydrogen industrial hubs and carbon capture, use and storage projects; and
- A$3 billion to support renewables manufacturing and the deployment of low-emission technologies.
In addition to government action the private sector has also directly supported the growth of renewable generation. In response to high electricity prices and voluntary ESG targets that include requirements for up to 100% renewable electricity, large corporates, government bodies and universities (among others) are now regularly contracting directly with renewable energy generators to manage electricity costs, and purchase green products, under arrangements known as corporate power purchase agreements (PPAs). Corporate PPAs are re-shaping electricity procurement for many organisations and can assist to support financing of renewable energy developments across the NEM.
Climate change commitment
Australia is a signatory to the Paris Agreement under the United Nations Framework Convention on Climate Change. The Paris Agreement includes a commitment to limit the increase in global average temperature to below 2 degrees Celsius (above pre-industrial levels) and to pursue efforts to limit the increase in global average temperature to 1.5 degrees Celsius (above preindustrial levels).
As of 2022, Australia has committed to reduce greenhouse gas emissions to ‘43% below 2005 levels by 2030’ and to reach net-zero emissions by 2050. This builds on Australia’s previous Paris Agreement target of ‘26-28%’ below 2005 levels and its 2020 Kyoto Protocol target of reducing emissions by 5% below 2000 levels.
Climate change policy
Various initiatives have been introduced by the Federal and State governments that aim to reduce Australia’s carbon emissions and promote greater renewable energy generation. The two key Federal Government policy initiatives are:
- the Renewable Energy Target (RET); and
- the Emissions Reduction Fund (ERF)
State governments have also demonstrated increasing policy ambition to address rising electricity costs, secure energy supply and reduce emissions, while attracting investment.
The key driver for investment in renewable generation in Australia has been the RET scheme which commenced in 2000 and is currently scheduled to operate until 2030.
Under the RET, renewable power generators may create Renewable Energy Certificates (RECs) with a REC being equivalent to around 1 MWh of electricity production from the renewable source. Electricity Retailers must purchase these RECs in a quantity that is equivalent to approximately 23.5% of the quantity of electricity they sell to consumers. Retailers are required to surrender RECs to the Clean Energy Regulator in respect of their electricity sales on a calendar year by calendar year basis. Failure to surrender sufficient RECs incurs a shortfall charge.
The RET Scheme is divided into the Large-scale Renewable Energy Target (LRET) and the Small-scale Renewable Energy Scheme (SRES). The two schemes create different categories of RECs with each category having a separate surrender target and pricing:
- under the LRET Large-scale Generation Certificates (LGCs) are created progressively based on metered output from renewable installations with a capacity of at least 100kW such as utility scale wind or solar projects; and
- under the SRES Small-scale Technology Certificates (STCs) are created from smaller renewable installations with a capacity below 100kW. These are typically residential or commercial rooftop installations. Unlike LGCs, the STCs for a smaller project can be created ‘up-front’ upon installation based on anticipated generation and are often sold by the customer to the installer in exchange for a discount on the cost of the system.
In January 2021, the RET’s surrender target for LGCs of 33,000 GWh of ‘additional renewable energy’ output was reached. However, there has recently been an unexpected surge in demand for LGCs driven by large corporate and government organisations purchasing additional LGCs to support voluntary renewable electricity targets. This has led to approximately 5.8 million LGCs being cancelled in 2021 and a material increase in the market price of LGCs.
As of 2022, the Clean Energy Regulator has stated that despite the generation eligible for LGCs reaching approximately 44,000 GWh it anticipates that the market price of LGCs will remain at similar levels.
Emissions Reduction Fund and Safeguard Mechanism
The Emissions Reduction Fund was established in 2014 as part of the Federal Government’s Direct Action Plan. Under this A$4.5 billion Fund, the Government offers businesses, landholders and other participants that run projects, which prevent releasing greenhouse gas emissions or sequester carbon, opportunities to earn Australian carbon credit units (ACCUs). Each ACCU represents ‘one tonne of carbon dioxide equivalent' emissions that are stored or avoided.
The primary legislative instrument governing the Emissions Reduction Fund is the Carbon Credits (Carbon Farming Initiative) Act 2011 (Cth).
The ACCUs can be sold to generate income either to the Government through carbon abatement contracts, to private buyers or on the secondary market.
As of 2022, approximately half of the A$4.5 billion fund has been spent to abate 217 million tonnes of emission reduction.
However, it is important to note that as of 2022, the Minister for Climate Change and Energy announced an independent panel review into the integrity of ACCUs under the Emissions Reduction Fund, which is anticipated to publish its findings by 31 December 2022.
In 2015, as part of the Government’s Direct Action Plan, a Safeguard Mechanism was established to ensure that the emissions reductions purchased by the Government under the Fund are not offset by significant increases in emissions above business-as-usual levels elsewhere in the economy. The legislative framework of the Safeguard Mechanism is set out in the National Greenhouse and Energy Reporting Act 2007 (Cth) (NGER Act) through the amendments to the Carbon Farming Initiative Amendment Act 2014 (Cth).
The Safeguard Mechanism applies to approximately 212 large businesses that have facilities with direct emissions of more than 100,000 tC02-e per year, which covers around half of Australia’s emissions. Facilities which exceed this baseline have the option to purchase and surrender ACCUs to offset emissions.
In 2022, the Government also released a Safeguard Mechanism Reforms Consultation Paper outlining its proposed reforms to the Mechanism, with final changes to be implemented by July 2023.
Greenhouse and energy reporting
The NGER Act, establishes the NGER Scheme, which is a national framework for reporting information about greenhouse gas emissions and energy consumption. Specifically, the NGER Act provides for the mandatory reporting of significant energy consumption, energy production, and greenhouse gas emissions, which exceed certain threshold amounts. However, the NGER Act only applies to energy consumed or produced in, or greenhouse gases emitted from Australian territory.
The scheme is administered by the Clean Energy Regulator, which monitors the compliance of scheme participants. The responsibility for reporting under the scheme is assigned to the company at the top of a corporation hierarchy (the 'controlling corporation' under the NGER Act). Penalties for non-compliance with the NGER Act include criminal as well as civil penalties, including fines of up to A$444,000 and personal liability for certain corporate officers.
Network Infrastructure and Energy Storage
In 2022, the AEMO published an Integrated Systems Plan (ISP) setting out a comprehensive 30-year roadmap for the NEM to support the transition toward renewable energy and achieve Australia’s climate change commitments by 2050. AEMO anticipates that the grid will lose approximately 14GW of coal-fired generation by 2030 as a result of the retirement of existing thermal generation and the clean energy transition.
In addition to ongoing direct support for additional renewable generation, the focus of regulatory reform and government policy in the energy sector has recently shifted towards supporting the enormous investment in electricity transmission and storage infrastructure that will be required to ensure that renewable generation can provide a reliable and secure electricity supply in the absence of traditional base-load thermal generators.
Renewable Energy Zones (REZs)
Renewable energy zones are areas around Australia which have the best potential for generating renewable energy. Conceptually the identification and development of REZs is intended to support co-ordinated investment in the development of renewable generation, energy storage and, critically, the transmission infrastructure needed to connect these zones (which are often far from load centres) to the broader grid.
Currently NSW is leading the development of REZs in Australia. Under its Electricity Infrastructure Roadmap, NSW has committed to developing five REZs - Central-West Orana, New England, South-West, Hunter-Central Coast and Illawarra. The Central-West Orana REZ is the first designated REZ, anticipated to unlock approximately 3GW of capacity.
Other States are also developing REZs including:
- Victoria - identified six proposed REZs in South-West Victoria, Western Victoria, Murray River, Central North, Ovens Murray, and Gippsland; and
- Queensland - proposed three REZ corridors in Southern Queensland, Central Queensland, and North Queensland.
Priority Transmission Projects
AEMO’s 2022 ISP identifies that to meet Australia’s increasing energy demand and prepare the system for renewables, approximately A$12.7 billion of investment in electricity transmission projects and over 10,000 km of new transmission is required.
Particularly, AEMO has stated that urgent action is required to develop five priority transmission projects - HumeLink, VNI West, Sydney Ring, New England Transmission Link and Marinus Link.
Interconnectors, which are connections between different transmission networks that allow power to flow between different regions in the NEM, also play an important role in these developments.
Currently, the Australian Government is investing in various interconnector projects across Australia including:
- EnergyConnect – a project to build a 900 km interconnector which links South Australia to NSW, with a separate link between NSW and Victoria. This interconnector is anticipated to unlock up to 30 new wind and solar projects (approximately 5.3GW). In 2021 the Government announced its intention to invest up to A$295 million to help finance this project; and
- Marinus Link- a proposed 1500 MW capacity under sea and underground interconnector between Tasmania and Victoria. In 2022, the Government announced it will invest a further A$75 million in addition to a previous offering of A$56 million to Tasmania to support the project.
Batteries and long duration storage (such as pumped hydro schemes) are also anticipated to play an important role in the energy transition. In recognition of this role, various state-government schemes have been initiated to directly procure or otherwise and support the development of battery and pumped hydro projects.
In Victoria the State Government has (through AEMO) directly procured system support services from multiple large battery projects. As part of a System Impact Support Scheme these services are intended to help maintain the stability of the transmission network despite system shocks such as unexpected outages of major infrastructure.
In NSW the State Government has entered into contracts for the development of the Waratah Super Battery (WSB) to also provide system support as part of a System Impact Support Scheme. In the case of the WSB the services are primarily intended to increase power transfer capacity on transmission lines that connect generation in the northern and southern regions of NSW to major load centres.
These arrangements are increasing and reflect a trend started by the South Australian government of taking advantage of the relatively rapid deployment capabilities of utility scale battery energy storage systems to address urgent grid reliability and system stability issues.
Beyond batteries, governments are also identifying a need for longer term energy storage capability to complement the increase in renewable generation.
The NSW Government recently established a A$50 million ‘Pumped Hydro Recoverable Grants Program’ to support developers undertaking feasibility studies for pumped hydro projects within the State. At the same time the NSW Government is offering Long Term Energy Services Agreements as part of the development of its REZs which will provide long term financial support for pumped hydro project developers through a competitive process commencing in 2022.
In September 2022, the Queensland Government announced its intention to establish the largest pumped hydro scheme in the world. Currently, Queensland has one operational pumped hydro plant however, under its A$62 billion ‘Energy and Jobs Plan’, Queensland intends to invest A$12 billion to establish two pumped hydro projects at Pioneer-Burdekin and Borumba Dam by 2035. These plants will have a collective 5GW capacity and are expected to play a pivotal role in helping achieve Queensland’s targets of 80% renewable by 2035.
ESB Post-2025 Reforms of the NEM
We expect that the next 5 to 10 years will bring major changes to the shape of the Australian energy market. The changes will be driven by the ongoing exit of traditional thermal generators, the proliferation of additional renewable generation and major investment in transmission and energy storage infrastructure.
From a regulatory standpoint the extent of the potential change is outlined in the ESB’s 2021 ‘Post-2025 Market Design Directions Paper’ which sets out various options to redesign the NEM and facilitate the energy transition.
The ESB proposed four interrelated reform pathways:
- resource adequacy – reforms designed to incentivise the provision of a mix of energy resources and ensuring sufficient storage capacity and reserves are established to support the closure of thermal plants;
- essential system services – ensuring essential services which support the grid such as operating reserves and frequency control are properly procured, valued and dispatched;
- integration of distributed energy resources – unlocking the potential of small-scale distributed energy or ‘customer-side resources’ such as rooftop solar and increasing the participation of consumers in the NEM; and
- access and transmission –delivering additional network capacity, ensuring efficient use of network infrastructure as well as coordinating new renewable generation including developing REZs.
The breadth and depth of the reforms under consideration are significant. Two in particular stand out as having material ramifications for the energy sector.
In June 2022, the ESB published a draft high-level design to introduce a capacity mechanism for the NEM.
The introduction of a capacity mechanism will allow generators to receive payment for their ability to have capacity available when required and establish a capacity market which pays generators for the energy produced as well as their installed capacity. This is anticipated to enhance the NEM’s predictability and reliability.
The ESB’s design was informed by various international examples as well as Western Australia’s ‘Reserve Capacity Mechanism’.
Some key features of the draft design include:
- permitting the participation of all new and existing generators including coal-fired generators and renewable energy providers. However, State and Territory governments will have the final decision on which energy sources can participate in the capacity market;
- a centralised procurement processes whereby AEMO will be responsible for forecasting capacity requirements and will recover costs from consumers through retailers; and
- providers will be issued capacity certificates and be required to meet certain performance obligations to receive capacity payments.
The final design of the capacity market is expected to be delivered by the ESB in 2023 and if approved,
ESB REZ Model
Finally, under its Post-2025 Reform ‘access and transmission’ pathway, the ESB was tasked with developing a framework to support the development and integration of REZs.
To address AEMO’s concerns that increasing new generation might worsen congestion (when the network does not have sufficient capacity to transport all electricity produced in an area to other regions where it is required), the ESB proposed a ‘congestion management model’ (CMM) in 2021.
This model attempts to address the emerging congestion management needs of the system by helping generators prioritise network considerations when determining where to build. This involves imposing congestion charges on all significant generators and providing rebates to eligible generators including those in REZs.
However, upon considering negative stakeholder feedback in 2022, the ESB has decided to pursue a hybrid ‘congestion zone/connection fee-based’ model to balance concerns surrounding investor flexibility with the need to prevent congestion. The ESB will continue working with stakeholders to develop a preferred design model to recommend to Energy Ministers.