This Chapter will note the historical success of the National Electricity Market, and then examine the two main challenges to network planning and investment on the grid: system stability and reliability. The Chapter will also consider the changing relationship consumers are having with the grid. The Committee will propose some options to consider in managing the grid of the 21st century, including increased planning and a focus on investment.
A 21st century grid
The Committee travelled to each of the mainland National Electricity Market (NEM) states where it heard evidence as to how the grid could be modernised to better meet the challenges of the future.
The national electricity grid is a complex system of generators, transmission lines, interconnectors, poles and wires. It features a mix of private and public investment, and is increasingly called upon to manage a new and changing power supply.
Electricity grids have been described as the world’s largest machines. Australia’s transmission and distribution network infrastructure operates over 900,000 kilometres of wires, synchronising frequency whilst balancing supply and demand instantaneously.
The management of this grid is changing. It is predicted that by the year 2050, customers will determine more than a quarter of all system investment decisions, to a value of $224 billion.
The Committee heard that Australia has an unusual system in that it features the separation of a modest number of middle sized cities separated by very large distances, which means that transmission plays an unusual role in our country, with that role changing significantly. The Committee also heard that whilst investments in generation have largely been left to market participants to determine, transmission has largely been determined by the regulatory system, with that only changing in recent times.
The Australian Energy Regulator reflected on the success of the NEM:
… certainly our position at the AER has been that the NEM market model, the underlying economics of it being based on the structure that it has, delivered safe, reliable energy for quite a significant period of time. We saw investment. It may not have been investment in a lot of base load. There was some. But that wasn't necessarily what the market needed at that time. In fact, my recollection of what some of the big investment needs were in the early days of the NEM were some more fast-start peaking plants, because we moved into an increasingly volatile demand response. We saw the increasing penetration of air conditioners et cetera as they became more common as a consumer item. That really led to some very significant changes in the peak. And what we saw then were investment signals and responses by the market, by building faster-start peaking plant.
The Committee heard that regardless of the changing nature of the generation of electricity, the continuing necessity of a grid was likely due to matters of scale:
The reason is that there are innate efficiencies in the scale of generation of electricity, whether it's renewable or thermal. While we do see increasing use of distributed generation and storage and dispatch—and that will continue to evolve and change the nature of the operation of the grid—it is still incredibly cost-effective to produce and generate electrons at large scale. Given the nature of cities and industrial processes, it's hard to see that that will be replaced at any time during the 21st century.
However, given that the modern grid is facing new challenges in the form of intermittent variable technologies like renewables, the Committee heard that the grid cannot continue to be operated how it was run in the 20th century.
This section of the Chapter will review system stability, sometimes referred to as system security. It will define system stability, noting why it has not historically been a problem faced by the grid. This section will then provide some recommendations as to how we can ensure that system stability is maintained on the grid.
What is system stability?
As outlined in Chapter 3, system stability, or system security, refers to the physics of the grid whereby the power system is kept stable and operating within technical limits. Through the provision of energy from generators, the elements that deliver this stability include inertia to help the power system manage rapid changes and disturbances. Stability is also achieved by having the tools and information to understand the changing power system, including information to generators’ models and data, as well as frequency operating standards and an understanding of how each generator connectsto the system.
System security (stability) services
Frequency response refers to systems designed to maintain the system at its frequency of 50 Hertz.
Professor Michael Brear, Director of the Melbourne Energy Institute, University of Melbourne, gave evidence about frequency response adequacy. Work done by the Institute indicated that the grid would experience issues in relation to frequency response adequacy in the future, regardless of what technology was powering the grid. The Institute also found that there are a number of technologies and services that can provide so-called fast frequency response and play a significant role in supporting frequency control and frequency regulation. These include demand response, energy storage and synthetic inertia (provided by wind and solar, for example), and frequency response could be managed via operational measures in electricity market design.
Synchronous generation is energy generation that maintains inertia on the grid.
The Committee heard that the science currently suggests that in circumstances where renewable penetration exceeds 40 per cent of the grid, system stability in the form of inertia needs to be addressed, including through planning. Unless addressed by the market operator and the renewable energy industry, this lack of inertia may limit the ability of renewable sources of energy to further penetrate the grid.
The Melbourne Energy Institute found that the system could securely run with a minimum generation output in the order of 25 per cent of the minimum demand, being four gigawatts, of synchronous generation. The corollary of this is that the system could run securely with up to 75 per cent of asynchronous generation. The Institute noted that different technologies can provide this service and may not be currently utilised. One of the key challenges posed by the reform process is to identify those capabilities and exploit them. In addition to coal-fired power stations, synchronous power can be provided by pumped hydro, thermal power, batteries or other devices that simulate big, heavy machines.
Whilst the Committee heard evidence about synthetic inertia, it also heard that ‘it is a very brave claim for anyone to say that we don’t need mechanical inertia in a modern power system’, whether or not that mechanical inertia was provided by coal-fired power stations, thermal power stations or via pumped hydro. The Committee also heard of the advantages of co-locating the pumped hydro storage with renewables.
The Committee also heard evidence that in order to ensure inertia remained on the grid, it was a service that needed to be paid for to sufficiently incentivise the delivery of inertia as a service.
Timeframes and periods of notice for generator retirement
The Committee heard evidence that understanding when significant pieces of network infrastructure are likely to be retired from the grid was essential for system stability. The Australian Energy Market Operator (AEMO) gave evidence that in other jurisdictions, a mandated notice period for the closure of infrastructure gives the market operator the opportunity to calculate whether that will compromise reliability or security of the grid. If it will, the market operator can enter into a contract with that generator so that generator may recover its cost and going-forward expense for the period of time until the market can react. The market operator’s funds would be generated by transmission rates.
Whilst some concern was raised in relation to potential anti-competitive practice and restrictive trade practices, the Committee heard that it was important for planners to know years in advance when particular types of power generation were to be retired from the grid.
Stability provided by coal-fired power generation
Two of the issues relating to the energy trilemma – stable and affordable energy – have been historically addressed on the grid through the supply of coal fired power. This source of power has proven to be a cheap source of energy in Australia, and given that it is continuously produced it had the effect of providing a stable and continuous source of energy onto the grid.
Following Australia’s climate change commitments, this source of power is becoming less viable and as the coal fired production plants reach retirement age there do not appear to be any current plans within the National Electricity Market to replace these coal fired power plants with the same energy source. Whilst historically coal-based sources of power have been expensive to establish, the cost of establishing renewable energy generation is reducing.
The introduction of instability to the grid
Given Australia’s commitments to reducing carbon emissions, and the ageing nature of Australia’s coal power fleet, the mix of energy generation in Australia is changing. The increase of solar and wind in the mix will have an impact on the transmission network, which was historically designed to transport large-scale synchronous generation — located close to major energy resources — to load centres. Renewable generation is expected to connect to the grid in areas with high wind and solar radiation, which tend to be weaker parts of the grid designed to supply only local load.
It is not only the power sources that are creating instability on the grid. The timing of demand is also having an impact on stability. The demand profile for electricity consumption typically follows a dip during the day with an increase in demand later in the day when workers arrive home and turn on their air conditioning units. Known as the duck curve, Professor Ertugrul from the University of Adelaide described the circumstances creating the electricity usage profile as ‘dangerous’ because it puts greater demand on balancing the frequency of the grid, which needs to maintain a frequency of 50 Hertz.
Stability whilst being technology neutral
This section considers the proposition that the NEM would work best by being technologically neutral, empowering the operating body to bring on power and auxiliary services as necessary to maintain system stability and enabling the market to decide which forms of energy it will invest in.
The Committee heard from Mr Graham Davies, an engineer and an advocate of renewable energy, who outlined that whilst ‘renewables, along with ancillary services … offer the most secure, reliable way for electricity going forward … there will still be coal and gas being used as a transition’ fuel.
The Committee heard that a key driver of the investment in renewables had been the Renewable Energy Target (RET), with the RET providing the economic incentive to bridge the gap between the cost of renewables and what people consider normal grid energy prices that come from the wholesale pool. However, the Committee considers it timely to analyse past and current programs in order to learn lessons for future programs.
The Australian Renewable Energy Agency (ARENA) gave the following evidence in relation to the competitiveness of renewables in the NEM:
I looked at my app to see what the current market prices are. They range from, in the different states, $67 per megawatt hour to roughly $120 per megawatt hour. You can get a new wind farm for between $50 and $60 a megawatt hour and a new solar farm for between $70 and $80 a megawatt hour. With these kinds of current prices, and all of the forward prices are above $100, if you got a contract price in the future then why wouldn't you just buy renewables, even without any incentives?
The Australian Energy Market Commission noted the advantages of operating in a regulatory environment which focuses on a technology neutral approach. Given that the prices of various commodities are uncertain, a model that is technology neutral — such as an emissions intensity scheme — can drive ‘whatever the right mix is’. This could involve solar and storage, or solar thermal or pumped hydro,
But something technology neutral, like an EIS, is likely to give you the best price outcomes not matter what those assumptions are. You cannot model an uncertain future.
AEMO confirmed that it, too, was ‘fuel neutral’.
System reliability through interconnection
The Committee heard that two ways of balancing intermittent energy generation are storage and greater interconnection. Storage can be a very expensive approach whereas interconnection can be more viable. Increased interconnection is an alternative method of stabilisation. Geographic diversity can also assist in providing reliability, because over larger areas weather conditions are less correlated. Storage can work alongside geographic diversity to deliver energy security and reliability.
The grid relies on interconnectors to increase the flow of energy around the NEM. AEMO gave evidence to the Committee that interconnection provides the NEM with the opportunity to take advantage of geographic and time diversity. This also provides the NEM with the opportunity to avoid building redundancy locally in states and create a more national market.
Interconnectors will continue to play an integral role in the modern grid. However, given the changes to the power sources on the grid the kinds of interconnection might be required change. The Committee heard that in Europe and China, in order to facilitate increasing levels of wind and solar PV energy a new type of transmission interconnection is being utilised, being high voltage direct current (HVDC). This involves the use of voltage source converters (VSC).
There is evidence that there would likely be a positive benefit in establishing an additional interconnector. Under the NEM Rules, when a new interconnector is built the cost of that interconnector is borne by the consumers of the states joined by the interconnector.
Professor Bartlett outlined that Victoria and New South Wales have sufficient interconnection as both states have interconnectors coming from different directions. However, Queensland and South Australia have limited interconnection as they are at the ends of what is a single line of transmission. Professor Bartlett concluded that this will result in the system failing at high power levels, as the system did on 28 September 2016 in South Australia. He noted that given the amount of synchronous generation that exists in Queensland, an additional interconnector between South Australia and Queensland would build additional system strength and avoid future collapses.
The Committee heard evidence that for the last five years Queensland and South Australia have had the highest average wholesale prices in the national market. Professor Bartlett argued that this was because
The way it works, the national market, is that as soon as one of those interconnectors—and if you only have one interconnector, there is only one—reaches its limit, as soon as it constrains, they constrain the market and, they say, no longer can cheap generators from New South Wales and Victoria compete in Queensland if its interconnector is constrained. No longer can cheap generation from Victoria and New South Wales compete in South Australia if its interconnector is constrained.
What happens? The price goes absolutely sky high. It normally runs at about $40 to $100 a megawatt hour. It can get to $14,000 a megawatt hour, and that is why we've had the highest wholesale prices in Queensland and South Australia not just for the last few months but for the last five years.
Professor Bartlett noted that the solution was additional interconnectors.
The Committee also heard evidence about the benefits that would flow from connecting the Western grid with the NEM, primarily because of the time difference. Solar power from the west could supplement the requirements of the east after sunset on the eastern seaboard. The estimated cost is between $2 billion and $2.5 billion.
More interconnectors could be provided in two ways. The first would involve any market participant, with permission, building a market interconnector that arbitrages price differences. An example of such an interconnector is the Basslink between Tasmania and Victoria, which is leased to Hydro Tasmania. The second type of interconnector is a regulated interconnector, where the proponent — usually a transmission network — carries out a modelling review of the benefits that they believe would accrue to consumers from reducing the price differential between the regions and compare that to the expected cost of the asset. Then, if the benefits exceed the cost and the test is reviewed by the AER, they can go ahead and build it.
Following this, the Committee heard evidence that the cost of trying to achieve a uniform flat price across the NEM would involve consumers paying for more transmission than they require.
However, the introduction of additional interconnectors would change the way the grid responds in times of crisis. More interconnectors would enable the grid to take advantage of significant energy resources and infrastructure in remote parts of Australia. For example, a second interconnector in Tasmania, a Basslink interconnector, could take advantage of the ‘roaring forties’ winds.
Notwithstanding the possible advantages of greater levels of interconnection, AEMO warned that interconnection does not necessarily solve all challenges, noting that local network and non-network options are also needed to maintain a reliable and secure electricity supply:
Synchronous condensers, or similar technologies, will be required to provide local system strength and resilience to frequency changes;
AEMO modelling suggests benefits from augmenting transmission in western Victoria to accommodate over 4 gigawatts of projected new renewable generation capacity.
Professor Bartlett noted that given the number of coal-fired power stations that will be exiting the NEM in the coming decades, it was important that the synchronous energy that exists within the NEM not become stranded. He argued that this could be achieved through a stronger interconnection system.
Other interconnection plans
AEMO’s National transmission network development plan also highlights the advantages of co-ordination and contestability which maximise the benefits of transmission investments across the NEM. AEMO found:
Modelling shows greater total net benefits when these developments are combined, creating a more interconnected NEM. These benefits are projected to increase as the energy transformation accelerates.
Geographic and technological diversity smooths the impact of intermittency and reduces reliance on gas-powered generation. Greater interconnection facilitates this diversity and delivers fuel cost savings to consumers.
A more interconnected NEM can improve system resilience.
Contestability in transmission should make development more competitively priced, reducing costs for consumers.
The Committee heard evidence from the South Australian Government that it had allocated $500,000 to co-sponsor with Electranet, the transmission company in South Australia, a regulator investment test for a new transmission interconnector with the eastern states. The links being reviewed included:
Tailem Bend to Horsham, Victoria;
Riverland in Berri to New South Wales;
Port Augusta to Sydney; and
Port Augusta to Brisbane.
The most economic appears to be through the Riverland to New South Wales.
Meshing the grid
The Committee also heard evidence that the current configuration of the grid features a single chain of transmission. It was argued that this makes the Australian grid ‘the longest, weakest system in the world running at AC’. Professor Bartlett outlined that where the grid has additional interconnectors and is ‘meshed’, if one part fails other parts step in immediately.
In its December 2016 report, National transmission network development plan, AEMO outlined that notwithstanding cost, there would be benefit for potential interconnection developments, including:
A new interconnector linking South Australia with either New South Wales or Victoria from 2021.
Augmenting existing interconnection linking New South Wales with both Queensland and Victoria in the mid to late 2020s.
Hurdles to greater interconnection
The Committee heard that in circumstances where transmission lines are weak, there is limited opportunity to transmit generated electricity. The Committee heard that, generally speaking, one kilometre of transmission line costs $1 million to construct. Given the costs involved, the Committee heard that the economic signal to an individual company to build additional interconnection may not eventuate. Achieving a balance between market forces and government initiatives was considered imperative.
The Committee also heard that as energy sources change – for example using hydrogen on a gas line — a DC line presents difficulty as it is not easy to tap into along the line; resulting in the choice of interconnector being a ‘tricky’ question.
However, the Committee heard that there did not appear to be a more economical way of transporting energy from renewable energy zones than the existing DC transmission lines.
An additional problem noted by the Committee was the risk that the cost of building additional interconnectors may not pass the RIT-T test.
A second Bass Strait interconnector from 2025, when combined with augmented interconnector capacity linking NSW identified above, although the benefits are only marginally greater than the costs.
A Regulatory Investment Test for Transmission (RIT-T) will be required in each case to fully determine the optimal development to serve consumers.
The Committee heard that without changes, the Regulatory Investment Test for Transmission (RIT-T) is unlikely to deliver sufficient timely investment in transmission infrastructure to cope with the needs of Australia’s future electricity system. The Clean Energy Finance Corporation notes that as currently implemented, the RIT-T favours smaller upgrades to transmission capacity and does not adequately consider the option value of proposed new investment, it uses inappropriately high discount rates and does not consider all relevant externalities. In addition, its single-asset focus means it cannot take into account the joint benefits of coordinated augmentations, even when coordinating transmission investments can lead to a more interconnected NEM.
The Committee also heard that the RIT-T should work in tandem with future planning opportunities and recognise any emissions objective.
System reliability through storage
As outlined above, the Committee heard that two ways of balancing renewables include storage and greater interconnection. Professor Kenneth Baldwin, Director of the Energy Change Institute at the Australian National University, quantified the cost of balancing renewables through the cost of storage. Noting that guaranteeing supply of electricity at times when renewable sources are not operational was an essential service, Professor Baldwin outlined that whilst renewables cost $50 per megawatt hour, the additional balancing cost is approximately $25 per megawatt hour.
System stability is essential to the successful operation of the grid in the future. Ensuring sufficient ongoing supply is important. To achieve this, the Committee considers it important that the market mechanisms allow for change and that those mechanisms should be technology agnostic to allow for investment in appropriate technologies.
The Committee notes that the capped spot price in the NEM, $14 000, was designed to bring in additional investment when required. In circumstances where there appears to be insufficient supply in the market, it would seem to the Committee that this mechanism is not operating as it ought to.
The Committee considers it appropriate that an assessment be made as to whether the current rules appropriately incentivise investment in infrastructure to capture future benefit.
Government schemes and/or subsidies exist to internalise externalities, including emissions. Any future review of the grid should be mindful of the holistic manner in which the grid and the National Electricity Market operate.
In order to maintain system stability, the Committee considers that a rule outlining an appropriate notice period before the closure of a sizeable generator is important.
In circumstances where storage alone is an expensive approach to stabilising renewables on the grid, the Committee considers that interconnection should be considered as an additional approach to achieving this outcome.
The Committee is keen to ensure that the infrastructure and rules are such that new sources of generation are not prevented or discouraged from connecting to the grid. In particular, the Committee is keen to take advantage of Australia’s natural resources, including wind and sun.
The Committee would like to see a framework that enables Australia to take advantage of its energy resources. Whilst the Committee has looked to international jurisdictions to better understand how other nations are responding to the challenges of a modernising energy supply market, the Committee is particularly aware of the unique position Australia finds itself in as an island nation.
Given that the current RIT-T does not require consideration of how the grid may be expanded in the future, or reduced carbon emissions, the Committee considers it timely for the RIT-T to be reviewed to ensure that this test is not an impediment to proper planning or reducing carbon emissions.
The Committee recommends that the Minister for the Environment and Energy, through the Council of Australian Governments Energy Council, undertake a review of past and current subsidies and incentive schemes to inform the design of future schemes to ensure they are appropriate for a modern electricity grid.
The Committee recommends that, independent of the Regulatory Investment Test for Transmission (RIT-T) process, the Australian Energy Market Operator be funded to undertake further feasibility studies to ascertain whether:
additional interconnectors are required on the grid and, if so, where; and
additional transmission is required in certain areas of the grid, including appropriate planning for renewable energy zones.
The Committee also recommends that the relevant rules, including the RIT-T process, be reviewed to take into account:
future expansion of the base for generating electricity; and
emissions reduction in the electricity sector.
The Committee recommends that system security services necessary for grid stability be ascribed a value that encourages investment in those services, with the Australian Energy Market Operator provided with the authority to take any steps necessary to ensure that there is a sufficient supply of system security services available.
This section of the Chapter will review how reliability is delivered to the grid, how this differs depending on the jurisdiction and whether the high levels of required reliability are resulting in disproportionate costs. Forecasting demand and demand management as tools in the guarantee of the reliable supply of electricity are also examined.
What is reliability?
The Australian Energy Market Commission noted that reliability is about having sufficient capacity on the grid when it is required. A reliable system requires system security and reliable transmission and distribution works.
The Australian Energy Market Operator gave evidence that Australia’s power system operates extremely effectively, with a reliability standard of 99.998 per cent.
The Committee heard that as the cost of electricity doubled in the last 10 years, reliability had improved. Excluding impacts following floods and cyclones, customers who previously experienced an average of two interruptions a year now experience one interruption each year.
Reliability is managed differently by each of the states who have maintained this responsibility, except for Victoria where reliability of the grid is managed by AEMO.
In Victoria AEMO has a planning process that explicitly looks at estimates of the customer value of reliability so that whenever an investment is made it assesses how this will improve reliability and whether the cost of the reliability is a reasonable impost on the customer. In the other states, it is a matter for the state governments. Within each state there are different standards, with Ausgrid in Sydney required to deliver services with far fewer outages than the country New South Wales area served by Essential Energy.
As a consequence of the Somerville Inquiry in 2004, the Queensland government significantly increased the reliability standards it imposed on its networks. The New South Wales government subsequently looked at its reliability standards and increased those in line with Queensland. As a result, there is a very prescriptive requirement for reliability in those states, which can result in redundant assets. The “N minus one” test requires the networks in New South Wales and Queensland to guarantee that they can meet peak demand in that geographic area even if a significant part of the system is lost as a result of storm damage or a similar catastrophic event.
Box 4.1: Reliability
81.5 per cent of respondents rated their electricity service either reliable or very reliable.
Delivery of reliability
In addition to requiring networks to deliver reliability through infrastructure, the Committee understands that reliability is delivered through the NEM as retailers already use so called ‘cap’ contracts which act as a de facto capacity market. AEMO announced that it has contracted all the reserve capacity it has calculated that is needed throughout the summer of 2017-18.
Cost of reliability
The Committee heard evidence that historically around 20 per cent of the capital employed by network businesses was used for around three per cent of time throughout the year. Given that the spend on transmission and distribution was found to be about $5 billion per annum, the Australian Energy Regulator agreed that historically that meant that $1 billion dollars was spent annually to deal with a few days of electricity demand. The AER gave evidence that it considers the alternative of demand management when making its network investment decisions.
Box 4.2: Reliability – the international experience
Reliability in context: the international experience
Through the delegation to Germany and the United States, the Committee heard about various approaches to ensuring reliability in a modern electricity grid. These included:
installing much more (in the order of 50 per cent more) capacity than would ever be required;
setting a reliability benchmark which transmission system operators are required to meet. System operators are paid for performing better than the benchmark, or charged for failing to meet the benchmark;
creating flexibility on the supply and demand sides;
acquiring and paying for capacity through a capacity market, or a regulated capacity (or flexible capacity) requirement;
making better use of energy storage, including pumped hydro storage;
acquiring reserve capacity (a generator on standby, not permitted to bid into the energy only market), with very high financial penalties for any system operator that causes the reserve capacity to be activated - this results in system operators ensuring they acquire sufficient capacity (the reserve capacity in Germany has never been activated and there was a view that the design of the regulatory regime was such that the reserve capacity would never be activated).
One important aspect of delivering reliable energy is accurate forecasting of demand. Mr Ivor Frischknecht, Chief Executive Officer of the Australian Renewable Energy Agency, noted the importance of forecasting:
It is not only forecasting of demand but also forecasting of supply that is important. If you have a renewable resource like wind and solar, they are obviously not always available, but if you know a day ahead, an hour ahead or a minute ahead — and your forecasts will get increasingly better as you get closer to the actual time of dispatch — then you can plan for it. You can plan to reduce demand, you can plan to have alternative generation available.
The importance of forecasting with respect to the modern grid is underlined by the fact that under the previous system, consumers bore the cost. In the new world, consumers now have an option if they don’t like the price — install renewables and sometimes batteries. In this context, the Committee heard that
… you have to be very, very careful to get your forecast right and get those numbers right because if what comes through the line does not look like value for money there are a lot of people that will move.
The Committee also heard that new usage patterns will make demand peaks unpredictable. Professor Ertugrul, from University of Adelaide’s School of Electrical and Electronic Engineering, noted that quick charging an electric bus would take between five and 15 minutes. The power required would be 1, 000 amps, which is the equivalent amount of energy consumed during the same time by 50 households. Given the unpredictably of demand, forecasting becomes important in order to safeguard grid stability.
Unforeseen drop off in consumption – difficulty forecasting demand
The Committee heard that at the same time the energy companies were investing in infrastructure to deliver reliability, there was an unpredicted downturn in consumption. The Committee heard the factors contributing to the lower than predicted consumption included:
energy efficiency standards;
customers responding to price; and
investment driven by feed-in tariffs for solar.
Notwithstanding the importance of forecasting as a tool for managing grid stability, the Committee recognises that forecasting is not a precise science.
Demand response, sometimes referred to as demand management, is having the capacity to remove demand from the grid by agreement. This leads to grid reliability, as the market can have confidence that at times of peak demand there are mechanisms to remove some of that demand rather than just relying on supply tools to meet peak demand.
The Committee heard evidence that there are opportunities for a market operator to make agreements with industry and/or consumers to assist to reduce demand at times when the grid is struggling to meet demand. The Australian Energy Council noted that the cheapest way of not having a 1,000 megawatt generator running is to use demand by finding customers prepared to shed load and negotiate a mutually beneficial deal.
Energy Networks Australia agreed that spending $1 billion per annum to manage peak demand that only occurs three or four days a year could be avoided:
I think there were more efficient ways of us achieving a balance between supply and demand. Part of that comes back to the need to signal the cost of increased demand on the system. That is where our focus around tariff reform and demand based tariffs has been so important, partly because at the moment we do not really reward customers that help beat the peak, so you end up with system investment that is larger than it needs to be. When we look out to the longer term with that network transformation roadmap analysis, that is telling you that, partly through augmentation expenditure to meet peak demand and partly through replacement expenditure, we can avoid $16 billion in network investment.
Following a change to the National Electricity Rules in 2015, the Australian Energy Regulator (AER) is required to develop a Demand Management Incentive Scheme and the Demand Management Innovation Allowance. This is focused on distribution network services. If consumers want lower electricity bills, the Committee heard that demand management will play a key role.
The Committee heard that:
There is also unfinished business in that there has been a longstanding commitment to review the demand management incentive scheme, which was first proposed in 2012 in the Power of Choice review by the Australian Energy Market Commission … There is a guideline that the Australian Energy Regulator is preparing to undertake and that is, if you like, another piece in providing a more balanced set of incentives, or it should address that concern about the balance of incentives.
The Committee heard evidence that, when it was being employed, demand response was working well. When asked about an aluminium smelter at Tomago being required to cease using power for a period of time in the summer of 2016/17 in New South Wales, economist and engineer Paul Hyslop told the Committee:
I am not privy to all the details of the Tomago contract, but my understanding is that, in fact, part of the deal in the price they got in the contract was that they are actually used to shed supply on occasion, when the rest of the system cannot meet that supply. To be frank, from an economics perspective, to shed the smelter once or twice a year for a couple of hours would be a much more sensible thing to do than building another 300 or 400 megawatts of peaking capacity.
However, the Committee also heard that utilising industry such as Tomago in demand response was not always ideal. The Committee visited Tomago and heard about the consequences to the plant during peak usage shut downs. The Committee also heard from the Energy Efficiency Council that requiring a very large aluminium smelter to reduce its demand is a very bad idea because it can cause setting of the pots in that industrial facility.
The Committee heard evidence from the Australian Renewable Energy Agency (ARENA) that it was working with AEMO on a demand response initiative.
The Committee also heard that demand response initiatives should be targeted at particular industries and during specific stages of the production process. During its visit to the United States, the Committee heard of the plan by utility Con Edison to save US$1 billion on infrastructure spending in New York’s Brooklyn and Queens neighbourhoods by asking utility customers in 32 US zip codes to sign up to a program which features storage hosted at customer sites which will then be aggregated into a virtual power plant and used to mitigate peak demand.
The National Electricity Rules provide that once regulated revenue is set, there are incentives for network service providers to limit their spending within each regulatory period. If a network service provider spends less than the amount that the Australian Energy Regulator determined to be an efficient estimate of capital expenditure or operating expenditure, it remains some of the savings and passes the remainder on to consumers through reduced network charges in the next regulatory period. It has been argued that the power of the incentive to undertake capital expenditure is greater than incentives to undertake operating expenditure on non-network options such as embedded generation or demand management programs. It is argued that this influences network business behaviour, leading to a preference to select capital expenditure options over alternatives that rely more on operating expenditure, even if the operating expenditure options would result in lower term prices for consumers.
Energy efficiency is another mechanism that can improve the reliability of the grid. It achieves this by promoting infrastructure that does not require as much energy to operate.
The Committee heard that: ‘it's clear that the cheapest form of abatement is energy efficiency. Energy efficiency was also described as the ‘first fuel’. The Energy Efficiency Council noted that it was ‘the biggest source of new capacity in the market’. Of particular interest to the Committee was the evidence that:
The capacity just in industrial efficiency identified in Australia is the equivalent of two Hazelwoods. We could be providing two Hazelwoods of demand response. You might have a blackout, or a generator goes down and suddenly you need to provide extra capacity. You can say to all the industrial clients: “We'll pay you to reduce your demand a bit, for a little time.” That gives you two Hazelwoods worth of capacity. That is done everywhere else in the world. Australia is a long way behind the rest of the world on this. It is standard practice.
Indeed, in California, the Committee heard that energy efficiency initiatives had made a significant contribution to lowering electricity demand.
Furthermore, the Committee heard that energy efficiency will mean that the grid does not need to be made up of such a high percentage of renewables in order to meet the emissions target set out in the RET:
… if we do not do energy efficiency, we will have to go to at least 70 per cent renewables. If we do sensible energy management, it means we only have to go to 50 per cent or lower—depending on how hard we go. The point is that, in getting to the emissions target that is set by the government at the moment, the costs will be extraordinarily high if we don't do energy management.
The Committee also heard that many small businesses were not aware of what new practices or machinery could be adopted to achieve a more energy efficient — and possibly cheaper — outcome. In particular, ageing machinery and appliances could be replaced with more energy efficient products with a view to reducing the amount of energy required.
Box 4.3: Electricity consumption
85 per cent of respondents reported that they had taken action to reduce electricity consumption in the past three years.
Removing causes of unreliability – off grid
The Committee heard that there is currently ageing infrastructure that involves long transmission lines that might only serve one or two customers. For the network businesses, it may be considerably more efficient, when the line gets to the end of its life, to provide those customers with solar and storage and new technologies, rather than replace the transmission line.
The Committee also heard evidence that it may be more cost effective to remove communities from the grid that require transmission line to be run through bushfire prone land. The undergrounding requirements of these lines may not compare favourably with providing those customers with solar and storage. However, the rules do not currently provide for off grid approaches in these circumstances.
It is important to note that, under the current rules and legislation, off-grid customers may not be subject to the states’ reliability standards and associated consumer protections.
Box 4.4: Consequences of being off grid
I think allowing people to disconnect from the grid is a terrible idea. I fear it will create a two-tier energy situation where those who can afford it (and have adequate solar access on roof) will essentially get unlimited free energy (and via electric cars travel), while those in areas with poor solar access (such as those living in apartments) or poor finances (who cannot afford roof-top solar) will be forced to shoulder the increased costs of maintaining an electricity grid. The grid provides benefits to everyone, not just those whose dwelling connects to it, and I think everyone should pay to maintain the grid, not just those whose dwellings are connected to it.
Removing causes of unreliability – micro grids
The Committee heard that an alternative to increased amounts of interconnection is the introduction of micro grids, with their own back-up systems. The Committee heard that this could prove to be more economical than increased interconnection on the NEM. The NSW Farmers Association gave evidence indicating that groups of farmers who are located at the end of transmission lines can benefit from setting up a micro grid as they may have differing electricity usage patterns and do not necessarily make demands on the grid at the same time.
The Committee heard evidence that one alternative to transporting energy from renewable energy zones via existing DC transmission lines, was to consider the use of interconnected microgrids and smaller systems. This would involve creating the energy, storing it in a battery and then dispatching it when required.
The Committee considers the reliable supply of electricity to be of the utmost importance as part of the service delivery of a modern grid. However, the Committee is aware that reliability carries implications for price. The Committee considers it essential that the energy market and policy makers are innovative in pursuing cost effective methods of achieving reliability.
Given the importance of reliability to the performance of the NEM, the Committee considers it timely to transfer responsibility for reliability from the NEM state governments to AEMO, as Victoria has already done.
As with system security, the Committee notes the essential nature of system security services to system reliability and considers it appropriate to either ascribe system security services a value that should be paid for within the NEM, or require all generated sources of electricity to provide a certain amount of ancillary services. The provision of a certain amount of ancillary services could be achieved through a contract between a generator and the provider of such ancillary services.
Given the costs involved in building additional infrastructure that is designed to deliver greater levels of reliability to the NEM, the Committee prefers a more concerted investment in demand response and energy efficiency policy settings. Because the networks have not had a consistent practice of implementing demand response and energy efficiency mechanisms, the Committee considers that demand management should be the coordinated by a national energy planner.
The Committee acknowledges the expenses involved in operating at the fringe of the grid, and is supportive of innovative approaches to managing the reliable delivery of electricity to those customers in a more cost effective manner which may involve investment in resources other than grid resources. A modern grid needs to facilitate these sorts of innovations.
Having heard evidence from generators, retailers, users, and the regulatory and operating bodies, the Committee considers that a more interconnected grid, with pumped hydro and co-located renewables may be a key feature of a modernised grid. Another key feature may be a grid which better incorporates demand response techniques which may be a viable alternative to creating more energy.
The Committee recommends that the Minister for the Environment and Energy take to the Council of Australian Governments Energy Council a proposal that all of the National Electricity Market states refer reliability regulation to the Australian Energy Market Operator, in keeping with the Victorian approach, and operate under the customer value of reliability model.
The Committee recommends that the Minister for the Environment and Energy audit large scale industrial manufacturing processes to identify short-term and long-term opportunities for demand response and energy efficiency.
The Committee expects that these opportunities will result in possible future revenue streams for industry and may avoid the need for investment in additional generation and transmission capacity.
The Committee recommends that the Minister for the Environment and Energy update resources that promote energy efficiency in small industry and businesses.
The Committee recommends that the Australian Energy Market Commission review any rules preventing users at the edge of the grid from being serviced via alternative means, whilst safeguarding reliability requirements and associated customer protections.
Role of consumers
Consumers are having multiple impacts on the way the grid functions. This section of the Chapter will review how consumer behaviours have led to the grid becoming bidirectional and has reduced the demand on the grid both through demand response and via departure from the grid.
Much of the planning that is happening on the NEM relates to the increasingly proactive role consumers are playing as not only users but also as generators of energy. As well as implementing rule changes to enable consumer to lead and drive change in the way energy services are provided to them, the AEMC reported that there was uptake of consumer participation in the grid particularly via solar PV.
Costs and Consumers
The price of retail electricity bills has doubled in the past 10 years. The Committee heard that the impact of price rises has been acutely felt by retail and business customers. The Committee heard from Energy Consumers Australia that one option for alleviating this impact would be dynamic networking pricing, where customers are invited to change their consumption habits in exchange for cheaper electricity bills. Furthermore, the Committee heard that in order to bring about change, consumers required more access to data to better understand how usage impacts on electricity bills. Energy Consumers Australia was very supportive of the demand side response trials being operated by ARENA and AEMO. Smart meters and other technological devices that can track usage will be important tools moving forward.
The Chair put the proposition to AGL that at a time when AGL was making a profit of $800 million, consumers were experiencing record high electricity bills. AGL acknowledged that prices are high and noted that one of its responses is to invest in more supply.
The Committee heard evidence that the ‘solution to high prices is high prices, because high prices allow people to bring forward new solutions’. Mr Hyslop observed that policy uncertainty, high gas prices, the movement away from coal and a waiting period before renewable prices come down in price further, will keep prices high for some time. However, he predicted that prices would fall significantly in the next two to three years.
The AER indicated that whilst it collected data on the number of customers claiming hardship, receiving payment plans and being disconnected, there was no capacity for longitudinal monitoring of specific customers.
A bidirectional grid
As well as drawing power from the grid, consumers now have the capacity to put energy back on to the grid. This follows any generation resulting from infrastructure the consumer may have installed, which is typically solar PV or wind turbines.
The Clean Energy Finance Corporation gave evidence to the Committee that whilst investing in renewables and storage in advance of coal capacity closure would minimise costs to consumers and maintain energy security, it is smart technology solutions that are important for improving system resilience and lowering costs.
Bidirectional flow requires smart inverter technology, which assists in managing the voltage for import/export. It also assists with AC/DC conversion. “You need a hybrid of both local or synthetic inertia, and that’s what these smart inverters can do”. Household batteries sold for the purpose of harnessing energy from solar PV or wind include a smart inverter.
The relationship between retailer and consumer is becoming more bidirectional, as well. A dynamic and transparent power bill may also be of use to consumers who either want more or clearer information about the costs that are built into their electricity bill.
The Committee heard further evidence of the bidirectional nature of the relationship between retailers and consumers when the AER described as a ‘very strong focus’ its work empowering consumers to make informed decisions about their energy use and to encourage them to engage with the market. The AER reported that it was gratified to have experienced unprecedented levels of traffic to its Energy Made Easy website over the preceding months. The AER is also reviewing the retail pricing information guidelines, which assist consumers to more easily compare offers by standardising how retailers present their offers. The AER also outlined a concerted effort to engage with customers who are not comfortable in the digital space.
Box 4.5: Understanding electricity bills
One third of respondents indicated that they did not have sufficient information about the components that make up the total price that they pay for electricity.
Behind the meter
When consumers set up their own electricity generation, these activities are typically referred to as being ‘behind the meter’. There are a number of reasons consumers may choose to go behind the meter, including a preference for renewable energy, seeking to minimise how much they spend on electricity in the medium to long terms, and a perceived reliability of supply.
When considering network planning and investment, the Committee is mindful of the growth of energy being generated off-grid. The Committee heard evidence of the establishment of micro-grids and the incentives for consumers to produce energy behind the meter.
The Committee also heard evidence that in circumstances where consumers were not able to produce a continuous and reliable source of energy, or where they wished to feed their excess power back onto the grid, there was a continued dependence on the shared national grid. In addition, the Committee heard evidence of the greater cost to individuals who remained on the grid, as they bore the ongoing network costs no longer paid by consumers exiting the grid. Furthermore, the Committee heard that the individuals with the greatest level or socioeconomic disadvantage were the least likely to have rooftop solar PV.
The Committee heard evidence about virtual power plants, where a group of consumers have their own sources of energy and batteries. AGL gave evidence that customers can achieve $500 per annum in bill savings because a software algorithm optimises the use of solar and battery to the benefit of the consumer.
The Committee also heard that if forecasting was not properly managed, and the cost to consumers of using the NEM was too high, there was a risk that those consumers who could afford to do so would move behind the grid with implications for those consumers who are left on the grid.
Given these new ways of using the grid, the Committee considers it important that the costs of interacting with the grid be reviewed. It may be that recovering costs through network charges is regressive in nature.
Box 4.6: Behind the meter experiences
My 4.2kW inverter-charger is programmed to run my house from the 6kWh battery bank from 6am till 11pm, (peak & shoulder periods). If the battery state of charge is below 70% it will re-charge from the grid during the "off peak" period. This rarely happens as my daily use does not often discharge the battery that far. Now that I am no longer receiving the TFiT (33-32c/kWh) I am seriously considering disconnecting from the grid so that I no longer have to pay $490+ per year to be able to export six times more power than I import.
60% of our generation capacity goes into a battery bank (20kWh in size), and provides about 99% of our annual energy usage needs.
I do not have batteries, but I do have an electric car: a Nissan Leaf. If I were to place batteries on my house then I would lose my 64c per kWh feed-in tariff to the grid. This special feed-in tariff expires in 2024, at which time I will put in more solar PV and batteries.
We are waiting to see if the price of the Tesla Batteries will come down a bit so we can install our own solar system with battery storage. We will not get panels until the battery is available at a reasonable cost.
Demand response and energy efficiency
As outlined in the section on reliability above, consumers’ participation in the electricity grid also involves reducing demand in accordance with an agreement with a regulator or retailer and purchasing infrastructure that is more energy efficient than the infrastructure it replaces.
The Committee was interested to hear of the bidirectional relationship between retailers and consumers. The Committee supports dynamic billing and is keen to ensure that each consumer has access to as much clear information as possible in relation to their electricity bill and electricity usage.
The Committee recommends that the Australian Energy Market Operator work with retailers to ensure bills are dynamic, providing customers with control over how much information they receive in relation to cost and usage.
The Committee recommends that the Australian Energy Market Operator:
review how grid costs are recovered with a view to improving equity; and
address how consumer led initiatives are affecting the use of the grid and the potential effects this has on users remaining on the grid who are unable to access these options;
without discouraging the uptake of renewable energy.
The Committee recommends that the Australian Energy Market Operator investigate the benefits of virtual power plants and other trading platforms that may have an effect on demand management and consider how they can be incorporated into the electricity grid to assist with stability.
National planning and governance
This section of the Chapter notes the evolution of a national approach to energy and electricity planning in Australia. It then reviews the evidence the Committee received about the advantages of more planning, particularly in relation to how these matters are managed in other international jurisdictions, distribution services, ensuring system strength, creating renewable zones, providing certainty, coordination and regulation. Much of the section is a discussion of where and how the market does not successfully drive outcomes on the grid.
Constitutionally, energy is primarily a state matter, but as the Australian Energy Market Commission pointed out ‘it was recognised that you cannot have a national market in a five-minute auction across the entire country unless there is one set of rules’.
Since 2004 and the signing of the Australian Energy Market Agreement, there is now a shared responsibility that is coordinated through the COAG Energy Council. As noted in Chapter 2, the Commonwealth Minister for the Environment and Energy, the Hon. Josh Frydenberg MP, is the Council’s chair.
Status quo planning
Within Australia, there are a number of agencies tasked with planning certain aspects of the NEM. The authority and responsibilities of these agencies see them take on the character of planners. Outlined in Chapter 2 of this report, these agencies include the Australian Energy Market Commission (AEMO), the Australian Energy Market Operator (AEMO), the Australian Energy Regulator (AER), the Australian Renewable Energy Agency (ARENA) and the Clean Energy Finance Corporation (CEFC).
A lack of planning
The Committee heard evidence that some decisions that are being made on the NEM would be better made if there was an overall planning body. For example, an 80 megawatt solar project was due to be connected on an already constrained part of the network. The Committee was told that as a result the nearby gas-fired plant would not have been able to export to the grid or would have been ‘constrained off’. The Committee heard that whilst this should have been highlighted during the planning stage or during the funding application to ARENA, there was no mechanism to test this issue.
The Committee heard evidence of the dangers of governments acting as participants in the electricity system in terms of the impact on certainty:
… governments owning stuff or intervening in ways that are not predictable is very difficult for a market ... The way [AEMO] does that and the rules by which it interacts with the market need to be better defined. The rules now are very different from the rules we used five or six years ago to run this system. So that's going to be the critical issue. How does AEMO do that?
The Committee also heard that the length of time to receive transmission approval for connection to the grid by a new generator is up to two years in Australia.
The overseas approach to planning
The Committee heard evidence that the modernisation of Australia’s electricity system has also had comparatively less governmental coordination than seen in other jurisdictions, such as New York, California and the United Kingdom.
The Melbourne Energy Institute gave evidence that planning of the transmission network in the United States is commonly done by independent, not-for-profit organisations, whose objective is secure and reliable low-cost electricity to consumers. The Institute noted that ‘genuinely independent, disinterested and good public planning is essential’:
In my view, you need to have fearlessly independent planning and you need to be able to let the wholesale market reform itself quickly and in a technologically neutral way in order to keep building the stuff we want.
AEMO gave further evidence to the Finkel review about the need for increased planning. An example provided was the market operator and planner PJM, in the United States, which highlighted the importance of having an operator and planner with a nuanced understanding of the interplay between engineering and economics.
Box 4.7: Transmission planning – the international experience
Transmission planning in context: the international experience
The modernisation of the grid in Germany is driven by a national policy: the Energiewende, or energy transformation. The policy has strong community and industry support, and is backed by political consensus. There has been a significant increase in the proportion of renewables in the German energy sector, over a short space of time. This has presented engineering, policy, and economic challenges.
In the United States, policies relating to renewable energy are state-based, and most electricity grids are operated on a regional basis across several states. Delegates visited New York, California, and Washington D.C. to gain an appreciation of the different approaches taken in different states, and to understand some of the cross-jurisdictional issues.
For example, New York State has taken a more market-based approach to grid modernisation. Regulators have been working to establish policies to provide incentives to capital to build the grid of tomorrow. Three key policies include:
Locational price signals for distributed energy resources - encourage more DERs in places where they are of most value. For example, at the end of the grid where voltage declines and capital costs for transmission and distribution increase, or in other areas of 'grid constraint'.
Changing financial incentives for utilities - moving away from a rate-based model of compensation, to a model where utilities are given the incentives to identify more innovative or 'non-wires' alternatives, such as demand management, energy storage solutions, micro grids, and energy efficiency.
Developing robust competitive distribute energy resource markets around consumers - seeking to harness the opportunities presented by significant technological changes in customer behaviour and interaction. Financial incentives for utilities and market rules should be designed in a way that facilitates customer-led initiatives, such as aggregation of solar PV supply, micro grids, and so on.
California, by contrast, has taken more of a mandate-driven approach to grid transformation. California has legislated ambitious renewable energy targets: 50 per cent of electricity from renewable energy sources by 2030, and 100 per cent by 2050. The California Public Utilities Commission has identified its priority over the next 10 years as the effective integration of these sources into the grid. It has an Integrated Resource Planning Process, which will consider the appropriate portfolio of resources and will direct procurement as appropriate, through the mechanism of renewable energy certificates.
Planning and the distribution network
AusNet Services gave evidence that it envisages a distribution system operator — much like AEMO operates the transmission network — to ensure the appropriate operation of the distribution networks. AEMO gave evidence noting that the management of distributed energy resources needs to be better integrated.
However, the Grattan Institute did not think there was sufficient evidence to support an increased distribution function for network operator AEMO:
I think distribution is still the trickier one because we have got much less clarity around the interface between distribution and, even in generation, consumption. I think, for example, the AER is more than capable of dealing with the need for more distribution. I personally do not see any justification right now for changing distribution towards a more interventionist planning role for AEMO or anybody else. The point I made before was that there is a great need to move forward on three or four things in distribution: cost-effective tariffs; the way in which the businesses make the decision between new investment and efficient alternatives; and the boundaries between private sector investment in generation and network investment and how that works.
At the moment we have got an issue to deal with: you can refit the activities within the distribution business. It feels like a short-term solution to me, but the long-term solution is yet unclear. So there are all those issues, and there are some very important social issues as well to deal with the essential service characteristics where distribution has a critical role. My view at the moment would be that I would certainly put more power and planning responsibility for causing it to happen in the hands of AEMO for transmission and possibly generation, but I think there is some more work to be done. I think AER, particularly with the additional resources they have been given now, is in a better position to do that.
Planning and system stability
AEMO gave evidence that it is not only operating a market, but also operating a physical system. Similarly, the Committee heard evidence that part of the national planning needs to pay particular focus to the engineering aspects of the system.
The Committee heard from witnesses such as Professor Ertugrul, a power engineer from the University of Adelaide, of the importance of coordinating the grid well — of looking at the grid as a whole and the importance of controlling it centrally. He noted that this was particularly important in relation to the stability of the grid so that critical points can be identified and appropriate responses deployed in a timely manner.
Planning and renewable energy zones
A key role for a planner would be responding appropriately to the new sources of energy entering the grid. AEMO gave evidence to the inquiry that renewable generation is geographically specific. As such, mechanisms for planning would look at the best places to locate these resources, followed by the kinds of grid connections that would optimise that so that costs to consumers are reduced.
In particular, the Committee notes the Finkel Review recommendation that planning be undertaken in relation to renewable energy zones.
Planning and certainty
One aspect of a grid planner would be to provide some level of policy certainty. In its December 2016 National transmission network development plan, AEMO noted that ‘Beyond 2030, the scale and timing of generation mix changes is highly uncertain and largely depends on the decision of coal-fired generators and the ongoing direction of energy policy’. In particular, AEMO noted that the timing of the retirement of coal generation that is likely to reach its technical end of life in the 2030s is crucial to determining future investment in the gas industry. This would have implications for gas supply and reserves.
Planning and coordination
The Committee heard that in relation to large scale projects, there was a lack of coordination. For example, the Clean Energy Finance Corporation (CEFC) is involved in Genex, which is a pumped storage facility proposed between two gold mines in Kidston, North Queensland. The CEFC has committed to assist in building a solar facility first, and is working with ARENA to develop that into pump storage that complements renewables. CEFC gave evidence that at some point transmission will probably need to be augmented to get the full benefit of that project. Given the inter-reliant aspect of the project, the CEFC gave evidence that:
It is essentially a coordination challenge, getting the transmission provider, project proponents and presumably governments at the state and federal levels to recognise the value that you could unlock by a project proposal. So a body to take the lead and coordinate that is really [important].
Planning and regulation
The Committee noted that, whilst it is difficult to compare jurisdictions because usage differs depending on the unique climactic circumstances of each jurisdiction, electricity appeared to be cheaper in jurisdictions where retail electricity prices are regulated.
The Grattan Institute argued for greater planning in the NEM:
It is demonstrably the case that we have needed to introduce an extra level of planning and regulation in a number of areas. But how far that goes and where we say, “We have now restabilised the system,” is the question. The key issue here is about—we have mentioned this already—energy that is renewable and intermittent.
Furthermore, the AER has engaged with Energy Networks Australia and Energy Consumers Australia to announce a joint initiative to explore collaborative regulatory approaches. They are aiming for improved sector engagement and to identify opportunities for regulatory innovation.
The Committee heard that changing AEMO’s functions with respect to transmission may facilitate better pricing:
On many occasions the previous management of AEMO had a concept of transmission planner as their role. But all they were doing was identifying an opportunity or a reason that you might want more transmission. They had no capacity to influence whether that was actually delivered or not.
The point that Audrey Zibelman, the new CEO of AEMO, has made is that the market isn't the objective; the market is the mechanism by which we achieve our objectives. If the market isn't doing what we want, because there are barriers to the way it should operate created by whatever circumstances, then the role of government is to fix that.
AEMO gave evidence about what planning would mean:
What we want to do is do the analysis to look at all the options so that we can think about where it could be and the market can identify [preferences]. But as you know, having pumped hydro with no transmission means you can't deliver it to where it needs to go. So we have to look at both.
This is a system. It was built by engineers after World War II who looked at all these things and made some decisions based on the information at that time and based on the technology at that time.
It is not just a market. We do have to have some planning, because some of these investments take 10 to 12 years to get done, and if we don't identify them and agree that this seems to provide us the greatest amount of optionality they will never get done, because it is very difficult to build something 12 years ahead of time unless government agrees that it is a good idea.
The Committee is of the view that given the current state of the network, there is scope to explore the appropriateness of a national planner. One avenue that may be explored is broadening the role of AEMO to combine the transmission function with a broader function in relation to distribution, or in the alternative establish an independent planning body.
The Committee considers that the Australian Energy Market Operator, or a similar independent body, would be well placed to take on the responsibilities of planning for the future of the both the national energy market as well as the national electricity grid. Such a body would have an ongoing planning role, rather than the Energy Security Board which is a body that meets from time to time constituted of representatives from other agencies.
The Committee agrees with the evidence it heard that the Finkel review was a great starting point, but that experts now needed to operationalise the findings.
The Committee recommends that the Minister for the Environment and Energy review the Australian Energy Market Operator’s current planning role with a view to incorporating a distribution planning role that enables planning along the National Electricty Market. In the alternative, the Committee recommends the establishment of a new independent planning body for the National Electricity Market.
The Committee also recommends that the Australian Energy Market Operator, utilising its current transmission planning functions, consider the establishment of renewable energy zones.