The State of the Australian Energy Market

John Tamblyn Inaugural Chairman, Australian Energy Market Commission

DOWNLOAD PDF VERSION

Introduction

Let me start by thanking the organizers for asking me to present at this conference. I have had an opportunity over the last couple of days to meet and talk to some of you about the challenges confronting energy markets here in the US. During this time I have been struck once again by the widespread enthusiasm there is to address those challenges. While I am here I am very much hoping to learn from your own experiences, and share my experiences in the context of the Australian market with you.

These challenges resonate loudly because we in Australia are facing many, if not all, of the same problems. I hope that some of my observations on the Australian energy market might therefore inform your own thinking on how best to meet those challenges – or in some cases how not to meet them. However, as I will explain, I am confident that we are heading in the right direction and are well placed to meet the challenges we face in years ahead.

Australia’s energy markets are going through an unprecedented transformation. This transformation is being driven by a combination of:

• growing peak demand as Australians try to escape the searing 100 degree summer heat by switching on their air conditioners;
• policies to reduce our greenhouse emissions, which of course may also reduce the need to switch on those air conditioners; and
• increasing linkages between gas and electricity markets.

The critical questions that we are facing include:

• Will the market deliver the new generation investment we need to meet that growing demand?
• Will the accompanying electricity transmission and gas network investment needed to transport that increased load be timely and efficient? and
• If not, is there a need to change the market design and incentives to improve outcomes?

Put simply, is our market design capable of delivering beneficial outcomes to Australia given the circumstances we face?

Fortunately, the regulatory and institutional structure of the Australian energy market provides the flexibility for these questions to be considered, and for changes to be implemented where they are warranted. This means we are well placed to face these emerging challenges.

Today I will focus on two things:

• First, the evolution of Australia’s national energy reforms to promote competition and efficiency. What worked well, what didn’t, and what is left to do?
• Second, I want to outline some of the challenges facing each part of the electricity supply chain in the Australian National Electricity Market, and, as you will see, the USA is also facing many of these same challenges.

Current market arrangements

But before I outline the evolution of energy reforms, let me first give you a very brief description of the current Australian energy market arrangements – for those of you who might be less familiar with them.

Its critical features are:

• a wholesale energy-only spot market, where prices are determined by the interaction of generators and purchasers, with generators placing bids for each five minute interval of the day up to 24 hours in advance;
• the market is made up of five interconnected regions that align with the main states on the east coast of Australia, and the market is settled separately for each region. Geographically, the NEM is as large as the east coast of the US but in terms of energy supplied it is about the same size as the PJM.
• the transmission and distribution network operates as a common carriage network, meaning that end-users pay for investment in and use of the shared network. In this arrangement, generators only pay dedicated costs of connection. This fact is important later when I talk about extensions to the network; and
• electricity retail competition has been implemented for large and small users, but safety net regulated tariffs remain for small business and household customers in most state jurisdictions.

The market is now supported by a national regulatory framework and institutional structure provided through market rules that govern its operation and provide for the economic regulation of the network.

The Australian Energy Market Commission, which I chair, is responsible for assessing proposed changes to the market rules, market development reviews and policy advice for both the electricity and gas markets. We are obliged to accept rule change proposals that are consistent with promoting economic efficiency in the provision of electricity and gas services. As many of you will appreciate – this is not a straightforward task.

What is unique about our arrangements is that in the great US-tradition of the ‘separation of powers’, the policy and rule making functions have been separated from compliance and enforcement. While the Commission makes the rules, the Australian Energy Regulator implements and enforces them. The AER also conducts price reviews for transmission and distribution network services.

There are many benefits from this separation. The Commission is able to impartially assess rule change proposals that can be made by market participants, individuals, consumer groups or the regulator itself. In particular, because it does not enforce the rules it is not tempted to draft the rules in such a way that ‘makes life easy’ for the enforcer. Rather, it can independently consider all of the arguments made by all parties before making a decision, consistent with its rule making test. It also allows the Commission to consider market development options and its energy policy advice at a more strategic level – focusing on the longer term efficiency benefits. This means that there is a high degree of confidence in the market framework and the processes for amending it amongst market participants, investors and energy consumers.

In summary, Australia has a national approach to energy policy that relies on decentralized decision-making by energy suppliers and users, based on the promotion of competition where feasible, and regulation only where absolutely necessary. The national institutions are split into policy advising and rule making by the Commission, and compliance/enforcement by the Australian Energy Regulator. The current structure is the product of a long voyage of discovery that has involved a number of distinct phases.

How did we get to our current arrangements?

It wasn’t that long ago that Australia’s energy market was dominated by vertically integrated government owned monopolies, which had little incentive to improve efficiency. Back then the game was to convince the price setting entity – usually a government minister – that price increases were necessary to recover rising costs. These businesses were large, inefficient and unmanageable.

The early 1990s were a unique period in Australia’s public policy development. During this period the Council of Australian Governments was formed – made up of the Premiers of each state and the Prime Minister of the Commonwealth Government. This heads of government council provided the forum for major interstate and national economic reforms to be developed.

As part of a national reform process through COAG, Australia set about putting in place leaner and more efficient regulatory and institutional arrangements. This was not easy. There were many challenges, particularly in convincing state jurisdictions to relinquish some control over their electricity utilities. However, through perseverance and by staging the reforms to manage state needs for some local control, the desired outcome has been achieved. And the benefits of doing so have been substantial.

First, the focus was on structural separation. Businesses were separated into potentially competitive and non-competitive parts. Meanwhile, a single national framework for energy policy was being developed. This included market and regulatory rules that sought to promote competition and provide incentives for efficiency improvements. There was a very clear focus on improving efficiency of energy services and the steps necessary to achieve this.

When these early reforms were being implemented through a national policy framework, each jurisdiction wanted to retain some control over energy services

State based independent regulators were therefore given the responsibility for implementing the national rules in each state. As part of transition arrangements, states were also given an opportunity to derogate away from those parts of the rules that were deemed to be inappropriate for the conditions in their states. However, these derogations were time limited – and were only intended to manage transition to the new arrangements.

The second phase of reform began around 2001 as dissatisfaction with the arrangements led to an independent review of the reforms. It was at this time that the Ministerial Council on Energy comprising each jurisdiction’s energy minister was established to provide national leadership on energy policy and the reforms. The AEMC and AER were established as national institutions to develop and administer the national energy market rules. The dissatisfaction centered around the divergent application of the national framework by state jurisdictional regulators, particularly on rates of return, and the method for valuing the regulatory asset base. In hindsight this should perhaps not have come as a surprise – there are often as many answers as there are regulators, although we are not alone – economists and lawyers share the same trait!

Thus in the second phase of reform Australia has implemented a national framework for the governance of the national energy markets.

The important messages here are that:

• the reforms occurred within a national framework, while taking account of state concerns, and involved a number of distinct phases;
• the current regulatory structure separates rule making from rule compliance and enforcement; and
• there is flexibility for the rules to evolve in a nationally consistent way, while contributing to the promotion of efficiency.

Now let me turn to the challenges for electricity generation and the market arrangements for delivering the new generation investment that Australia will need in coming years.

Electricity generation and market arrangements

There is a confluence of factors facing the energy market, which are creating challenges for the market, namely:

• tightening demand and supply conditions, as a prolonged period of excess generation capacity diminishes – a legacy of the pre-market arrangements where there was less focus on cost efficiency and so excess capacity was built to guarantee supply in almost all circumstances; and
• proposed introduction of a carbon pollution reduction scheme and a renewable energy target as the centre pieces of the Government’s climate change risk mitigation policies.

The slide provides evidence of the tightening demand and supply conditions. While the picture for the NEM as a whole suggests that the system is working well, the picture changes when looked at from a regional level, for example Victoria and South Australia.

There are two main planks to the Government’s greenhouse emission reduction approach, being:

• a carbon pollution reduction scheme, where permits will be issued to the main greenhouse gas emitters in Australia; and
• a national renewable energy target, where electricity retailers will be required to purchase a predetermined portion of their electricity needs from renewable sources.

Tightening demand and supply conditions means that new generation investment will be required in the medium term. Climate change policies are expected to affect the choice of generation investments.

The questions that we face are therefore:

• What will replace coal generation as the primary electricity source in a carbonconstrained world? and
• When and how will this occur?

In the future, Australia’s reliance on coal-fired generation is expected to reduce. Climate change policies are expected to promote investment in gas-fired generation – which is likely to have the lowest marginal cost per unit of output once emissions are priced in – and renewable generation.

This raises questions about the capacity of Australia’s domestic gas market to meet potentially significant increases in gas demand.

Fortunately, in addition to being endowed with significant coal reserves, Australia also has significant gas reserves. And these reserves have been growing through technological improvements in the extraction of coal seam methane, which has been found in abundance particularly in Queensland. Now that this source of gas has become reliable, investors are looking to build LNG facilities on the east coast of Australia to export gas to the rest of the world.

The implications for the domestic price of gas following the construction of LNG facilities are uncertain. Gas prices will undoubtedly increase in the future. Domestic gas prices will likely range somewhere between current prices and the world netback price, according to the future demand and supply conditions both in Australia and elsewhere.

The national renewable energy target is also expected to drive an expansion in wind generation in the short- to medium-term. The resulting increase in intermittent generation will test the operation of the market, particularly if it is concentrated in one region, say South Australia. Having a large proportion of intermittent generation in one region can lead to reliability problems in circumstances where demand is high, wind generation is unavailable, and inter-connectors are constrained. This means that there may need to be some reserve capacity available for these circumstances to satisfy system security and reliability requirements.

Increased wind investment in one or more regions means that there will no longer be a close alignment between demand and supply in each region. New inter-connector investments and augmentations to the transmission network will therefore also be required.

The role of demand-side participation in the market, as an alternative to both generation and network investment is being closely examined. To date, demandside participation has been passive within the market. However, the Commission has been carefully considering whether there are impediments to its efficient uptake, and whether changes should be made to the market to encourage its development.

Can Australia’s energy only market deliver needed generation?

As most of you are aware, the Australian national energy market operates as a single interconnected regionally priced and settled energy-only market. Incentives for new generation investment are created through generation returns in excess of marginal production cost.

Wholesale price volatility is managed through swap contracts between retailers and generators, which also provide important incentives for new investment. The regulatory arrangements that are in place to manage the energy-only market, are:

• a wholesale price cap, known as the value of lost load or VoLL, which is set at $10,000 MWh and is proposed to increase to $12,500 MWh;
• a cumulative price threshold, where cumulative prices over seven consecutive day periods cannot exceed $150,000, and is proposed to increase to $187,500; and
• arrangements for short term reserve capacity procurement, where the market operator tenders for reserve capacity in circumstances where a short term capacity shortfall is forecast.

The value of the market price cap is based on a tradeoff between managing price volatility risk and the scope for the exercise of generator market power, and providing financial incentives for new generation investment. The Commission has recently recommended an increase to the cap – and looking forward, further increases may be warranted.

The reason Australia adopted an energy-only market approach was to minimize the cost of providing generation by lowering investment distortions. The incentive for new investment has been created by letting prices rise to a sufficiently high level to make such investments financially viable. The critical debate is how high the price cap should be set to provide sufficient incentives to promote new investment, while continuing to manage price risks and the potential for generators to exercise market power.

So far, the current market price cap parameters have worked very well.

Investors have responded to the incentives created when prices are high during peak periods by investing in peaking capacity. However, the real test will be whether the market can deliver the required new base load generation and adequate reserve capacity when the economics of and technologies for future generation are being strongly influenced by new climate change policies. Critical to these investment decisions will be clarity about the new policy parameters and the resulting expectations about financial returns.

Under current arrangements, financial returns are influenced by the market price cap, availability of contracts, expectations about average spot market prices, and the operation of climate change policies. Given climate change policies, determining whether the current market price cap is sufficient to encourage appropriate investment is absolutely critical. If it is not, then either the market price cap will need to rise, or alternative consideration will need to be given to some form of capacity payment to provide sufficient capacity. The advantages and disadvantages of these alternative options will require further more detailed examination.

However, I am confident that the institutional arrangements are sufficiently flexible to allow any necessary changes to the current market design to be implemented in order to address the new generation investment challenges the market is facing.

Providing sufficient network capacity

Now let me turn to networks. I mentioned earlier that wind is likely to be the shortto medium-term solution for Australia’s renewable energy requirements. However, this creates two potential problems, namely:

• system security and reliability because wind is an intermittent source of generation; and
• a need for major extensions to the existing shared transmission network, and network augmentations, to provide sufficient transfer capability for the new wind generators.

It is likely that most of the new wind generation will be constructed in South Australia. However, the major load centers are elsewhere – mainly in New South Wales and Victoria. This means that to transport that intermittent generation ‘from A to B’ two things must happen: major remote extensions to the shared network must be undertaken and augmentations to the existing shared network must be constructed.

Ongoing reforms of the transmission planning and investment framework are likely to help this process. Over the last year or so a single national transmission planning function has been developed to operate across the entire market. Previously, Australia’s electricity transmission and distribution networks have been planned and managed along state jurisdictional lines.

These reforms are consolidating transmission planning into a new national entity, to better address these issues – but it may not be enough. The problem is that transmission investment is currently mainly funded within a single jurisdiction. The upshot is that where benefits are delivered in another jurisdiction, there is little incentive under the current arrangements for the investment to be undertaken. In fact, there is probably a disincentive, because the investment would lead to higher electricity prices within the primary jurisdiction, with no associated benefits for consumers – an undesirable outcome for any jurisdiction when considered alone. In other words, this narrow focus can lead to investment opportunities being foregone that are clearly desirable when assessed through a broader lens.

To fix this, a system of inter-regional charges is being developed, which is aimed at providing incentives for each jurisdiction to undertake investments that are in the interest of the market as a whole. This will allow a transmission business to claim part of the cost of an investment from a neighboring jurisdiction, where that jurisdiction is set to benefit from the investment. We expect this will remove any disincentives under the current arrangements.

Establishing appropriate funding arrangements for major network extensions required to connect generators to the transmission network will be another important challenge. For example, network extensions will in most cases be required to connect new renewable generation to the shared network. The question is – who should pay for these investments?

The current approach in Australia is for the first connecting generator to pay for the entire new line. Any generator that comes along subsequently then compensates the first generator for connecting to the now shared line. The problem is that this loads all of the risk that new generators will materialize on the first connecting generator – and therefore creates an incentive to minimize the capacity of the line. This has the unfortunate consequence of promoting inefficient duplication of assets. This is clearly suboptimal and unlikely to result in efficient new network investment to support renewable generation.

The spectrum of options for solving this problem will need to be considered ranging from market-based solutions to more directed planning solutions. For example they could include:

• at one end, conducting ‘open seasons’ by auctioning capacity in a proposed new transmission line and optimizing the construction on the basis of interest in its capacity; or
• at the other end, undertaking a cost benefit assessment of an extension and directing the relevant transmission business to undertake an investment where the expected benefits outweigh the costs, however defined.

Whatever the approach, under the current arrangements there will need to be greater intervention in network planning and investment than currently occurs.

The final network investment and planning challenge is to create incentives to encourage efficient tradeoffs between gas pipeline and electricity transmission investments. Under current network charging arrangements, any pipeline investments need to be paid for by the generator while any necessary transmission augmentation investments do not. In principle then, one might expect the generator to favor substituting gas pipeline investments (that it must finance) for transmission investments (the cost of which are shared amongst all end users).

However, in practice this outcome is unlikely. This is because ultimately, a generator’s locational investment decisions are likely to be primarily motivated by the market fundamentals (ie, expectations of future demand and supply, and therefore price), of which network cost differences would be only one element. The fundamental economic considerations are therefore likely to overwhelm any consideration of the tradeoff between electricity transmission and gas pipeline costs.

Thus, in terms of electricity networks, the critical issues are linked to generation – most notably, providing sufficient network capacity in locations where it is needed. The common carriage nature of the network means that there will need to be improved network planning and investment frameworks that take into account:

• the need for major extensions to the network;
• tradeoffs between gas and electricity networks; and
• the need to provide networks at least cost.

Electricity retailing

The final area I want to briefly touch on is the retailing sector and particularly the importance of retail competition for the incentives created for generation investment.

The development of retail competition for all customers has been a significant advance in recent years, and represents the final remaining area of energy market reform. Retail competition was first introduced to large commercial customers – and then to small residential customers over the last 6 years. In most capital cities – it is now possible to choose between two to three suppliers – some of whom also provide bundled electricity and gas supply contracts.

Competition has been developing, which has led to the Commission recently recommending the removal of residual price cap regulation for default customer tariffs in Victoria and South Australia. However, default tariff arrangements still apply to those customers who have not decided to shift to a contract tariff in the remaining states. The removal of these arrangements as competition is found to be effective is the final element of the energy reform process.

Concluding remarks

Finally and to conclude, I am happy to report that the Australian National Electricity Market has a healthy future, despite the challenges it is currently facing. This can be attributed in no small part to the extensive market reforms that have occurred over the last ten years, which focused on promoting competition and providing regulatory incentives for efficient outcomes.

There are three messages that I would like to leave you with:

• First, providing significant new generation investment is the critical challenge facing Australia’s energy-only market. Making sure that the parameters that influence investment decisions strike an appropriate balance between market price risks and incentives for investment is crucial. 
• Second, Australia’s approach to managing greenhouse emissions – through a carbon pollution reduction scheme and a national renewable energy target amongst other measures – means that more intermittent generation is likely to be constructed. This is likely to lead to increased volatility in wholesale prices as the price cap needs to be sufficiently high to provide incentives for backup generation for these wind generators, to maintain system reliability. Consideration may also need to be given to the alternative of a capacity market if a high price cap in future carries the risk of unacceptable price volatility and greater risk of market power being exercised.
• Third, transmission network investments are no longer going to be incremental in nature. The urgent need for major extensions and the growing interconnection with the Australian gas market means that more proactive and likely centralized planning and investment decisions will be needed in some circumstances. Making sure this does not adversely affect incentives for network investment will require careful consideration.

Finally – efficient markets inherently rely on confidence and trust – trust in how they operate now and in the future and in the associated institutions and rules that govern their operations. The global financial crisis has provided us with a painful reminder of what can happen in markets where confidence and trust evaporates.

In Australia we have established an energy market where there is confidence and trust in the market frameworks that govern the decentralized interactions between numerous market participants in maintaining the efficient and reliable energy services we require. Promoting competition within an incentive-based regulatory framework has been the key objective.

Market participants and investors also have confidence in the institutional arrangements and rules framework, which provides a firm basis from which challenges to the arrangements can be managed.

I hope that you may obtain relevant insights from our experiences and consider how the Australian experience may inform your own responses to the challenges we all are facing. For my part, I am also looking to learning from and understanding your own energy market experiences and to hearing more from you over the remaining days of this conference.

Thank you.

Ends