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Stimulating fair competition in the SA energy market. The 5th Annual South Australian Energy Market briefing, 21 June, Adelaide.

The 5 th Annual 

South Australian Energy Market 



21 June Adelaide




"Stimulating fair competition 

in the SA energy market"




Rod Shogren 


Australian Competition and Consumer Commission


Stimulating fair competition in the SA energy market




As you would all be aware, South Australia’s gas and electricity markets have recently faced significant challenges. There has already been discussion at this conference of the current difficulties facing these markets, including capacity shortfalls, high prices and large price fluctuations. Such problems have led some observers to question the benefits of energy sector reforms that have taken place over the last decade.


Given the ACCC’s involvement in reform of these sectors, I hope it will be helpful to discuss the role that the Commission plays in these markets.


Today I want to address head on the key concerns being expressed about energy markets:


• the perceived lack of strategic direction among electricity regulators;

• the integration of network services into the energy market;

• the role of State governments in the ongoing development of the National Electricity Market;

• calls to regulate bidding and rebidding behaviour by generators;

• retail competition in electricity; and

• the need to develop regulated interconnectors.


I will also talk about:


• initiatives to bring gas into South Australia from new sources;

• the issues surrounding the concept of market derived tariffs;

• upstream competition in gas; and finally

• whether regulation is discouraging new investment in gas pipelines.




I will begin by discussing electricity.


NEM governance


The NEM and its institutions are increasingly becoming the object of political scrutiny. In particular, the NEM participating jurisdictions have suggested that governments need to be brought back into the policy-making process through a ministerial forum. I would like to offer my own suggestions on where we can improve the arrangements. Before this, however, I think it is useful to recall the origins of the NEM governance arrangements.


The institutions of NEMMCO and NECA were created in May 1996 following commitments made by the Federal and State/Territorial Governments to National Competition Policy in April 1995. Setting out the rules for the National Electricity Market was the National Electricity Code, developed by the National Grid Management Council, a joint jurisdictional initiative established in July 1991.


NEMMCO was established to operate and administer the NEM. NECA, as the Code administrator, enforces, maintains and develops the Code.


While NEMMCO and NECA were created by the five NEM jurisdictions and the Commonwealth for the purposes of operating and administering the NEM and the Code, the ACCC was established by the Commonwealth Government in 1995 for the purposes of administering the Trade Practices Act 1974 and the Prices Surveillance Act 1983 . Indeed, the main functions which the ACCC performs in the electricity market are exercises of general powers in the TPA to authorise - ie provide legal immunity for - agreements and arrangements that may have anti-competitive elements but with offsetting public benefits.


The ACCC’s formal involvement with the NEM began in November 1996 when NECA and NEMMCO submitted the National Electricity Code as an application for authorisation under Part VII of the TPA. Then, in April 1997, NECA submitted an application to the Commission under Part IIIA of the Trade Practices Act to accept the NEM Access Code as an industry-wide access undertaking for administering third party access to electricity and distribution networks.


From recent public statements by State policy makers, it appears a major concern with the governance arrangements is the division of accountabilities between the ACCC, NECA and NEMMCO leading, it is said, to lack of strategic direction in the development of the NEM. This will be an issue addressed by the NEM Minister Policy Forum to be held on 26 June this year.


If we look at the governance issue in a little detail the following come to light. First, the governance arrangements were set up by the NEM jurisdictions in the first place. Second, the boards of NEMMCO and NECA are appointed by the NEM governments. Third, NEM governments through processes such as Statements of Corporate Intent (SCI) can influence the broad direction of NECA and NEMMCO. Fourth, some years back the NEM governments established a review of the governance arrangements of the NEM. That review, headed by Peter Limbers, made recommendations about streamlining the responsibilities of NEM institutions, particularly the roles of NECA and NEMMCO. Fifth, there have been other reviews undertaken on behalf of NEM jurisdictions dealing with the responsibilities and liabilities of NEM institutions, including reviews into market and system operation and system operation liability issues.


My concern is that no progress has been made on NEM governance notwithstanding the Limbers’ Report, nor the fine-tuning of NECA and NEMMCO SCIs, nor the consideration of NEM responsibilities coming out of other reviews. Consequently, I am a little puzzled about whether good governance has the same meaning for those involved in criticising the current arrangements as it does for me. This is not to say there are not real issues to resolve, as I have previously expressed concerns about NEM governance. But my concern is the need to give NEM institutions a clear mandate to provide leadership and direction to the market, and the independence to do their jobs properly. I hope that governments’ true concerns with the regulatory institutions are not their very independence, ie that they have too much of it. This would be the wrong diagnosis of the problem. I hope that NEM governments genuinely seek to improve NEM institutions, not to stand in the place of those institutions.


The governance issue is one that is raised in the context of the roles of NEM institutions in the code change process. One element of this is whether it is appropriate for the market institutions to decide on changes to the Code or whether this is something best left to governments. In my view, the role of government is to decide on the broad strategic framework for the market. However, in the case of the NEM, I would have thought many of these issues were settled when the National Grid Management Council finalised the national electricity market arrangements in the mid 1990s.


While there remains an issue of the possible overlap in the roles of the institutions within the NEM, I believe that the issue of code change overlap is overstated and easily resolved through some changes to the process for bringing forward code changes. To this end, the ACCC and NECA have had discussions about streamlining the code change process to reduce delay and uncertainty.


Further, as NEM Code changes concern the effective operation of the market and the interplay of competitive forces, it is eminently sensible to involve the ACCC in the code change process, given both our role as the national competition agency and our long association with the development of the market and access arrangement. No doubt there are other issues concerning overlap between NEM institutions, but these are also manageable through sensible allocation of functions and through communication and consultation. It would be disappointing if a lot of time and effort was spent by governments revisiting old ground, given that governance has already been the subject of a number of reviews, including the Limbers’ review.


I acknowledge that many in the business and consumer sector would like rationalisation to go further, with the creation of a single national energy regulator. I am unsure as to what model such arrangements would take and indeed whether governments are currently even thinking about this possibility. However, such a body, like the current institutions, could only provide the necessary leadership and direction to the market as long as it is allowed to operate independently. I do acknowledge that to move to such a regulatory model in the current climate is a difficult step for governments. But for newly reformed industries such as electricity the ability of the market to deliver the level of investment needed to ensure reliable and efficiently priced energy depends on the governance arrangements being clear and the market institutions being free of direct government involvement.


The shortcomings of the current arrangements have become more pronounced over the last year as the code change process has been placed under pressure by NEM governments. That is, the ability of the regulatory institutions to act independently and in the best interests of developing the NEM is being frustrated. In such a climate it is difficult for NEM institutions to resolve outstanding issues. Nor is the ACCC able to give the guidance that we believe is needed, given our limited role in the code change process.


Integration of energy markets with network services


To illustrate this, consider the proposals to integrate network services into the energy markets. The generation sector of the market has, I believe, been successfully reformed, with competition leading to significant increases in productivity and efficiency. Retail competition continues to be introduced in stages, and as it becomes more prevalent will become a driver in achieving further benefits from the reforms. The integration of the regulation of transmission and distribution networks into this deregulated market setting remains unresolved, and is detracting from the benefits the reforms have so far achieved.


This is actually part of a bigger set of issues. The NEM design is based on an energy-only model whereby participants are rewarded according to the trade of energy in the spot market and, obviously, the interplay of the spot price with contracts that underpin the majority of the financial transactions in the market place. In this design, the behaviour of the spot market is critical in terms of the signals it provides for the use of resources and the need for future investment. In my view, two issues arise from this. The first is how the use and pricing of other services fits with a market dominated by a commodity trading model. That is, how can you have a network pricing methodology that is indifferent to the operation of the spot market and the pricing signals created in that market?


Not surprisingly, we say the pricing of network services does need to be integrated with the spot market for energy.


Second, there has been some discussion about the operation of the spot market, including here in South Australia. Often you will hear proposals for price caps, controls on generator bidding or suggestions for fast tracking interconnection. While any or all of these may have their place, very few commentators have thought about how this fits with an energy only market. Indeed, if you restrict the bidding of generators or cap market prices then presumably you need other mechanisms to compensate generators, such as capacity payments. Consequently, these issues are often more complex than a first look would reveal. Some, including Rob Booth, believe that we need to revisit the market design and embrace an alternative such as a net pool or bilateral contract market. I will come back to the issues of rebidding and price caps briefly later.


The governance arrangements of the NEM have failed to quickly resolve the issues regarding the integration of energy markets with network services, largely because of the political nature of the issue. There has been a clash of opinion on whether, in creating a national electricity market, networks should also be included in the competition and efficiency objectives of the reforms, or whether networks sit outside the market. This is a significant issue and although transmission is only 10 per cent of the final cost of delivered energy, it does not follow that pricing signals in transmission do not matter.


In most other markets, the cost of transport is an important factor influencing not only price but also decisions on where to source product and what markets to serve. In these markets, transportation costs are directly determined by distance travelled, amount of capacity needed and market conditions - scarce capacity resulting in higher charges and surplus capacity leading to lower costs. Similarly, in electricity transmission, pricing signals can directly influence decisions on where new power plants and loads may be sited. It can also influence decisions on whether new investment in transmission is justified compared with demand side and supply side alternatives.


Not surprisingly the ACCC is attracted to the economic efficiency objectives of introducing pricing into transmission that reflects the usage of existing transmission capacity and draws network investment decisions closer to investment decisions in the energy market. I acknowledge there are contrary views that networks should be viewed as passive participants and therefore any pricing should reflect equity rather than economic efficiency objectives. For example, the theoretically economically efficient means of pricing transmission usage is through nodal pricing. However, nodal pricing would highlight variable energy costs between different regions, which some governments seem to fear.


In this context NECA has therefore had to walk a tightrope, balancing the political interests of its owners, the NEM jurisdictions, with the objective of developing an efficient market. Furthermore, it has not been possible to proceed with changes to network pricing in any coherent, integrated fashion as the outcome of the reviews of network pricing have resulted in a number of separate recommendations for incremental changes to the Code. The first set of Code changes to be submitted to the ACCC were those arising from the Transmission and Distribution Pricing Review. The second set of changes came from the review of Network and Distributed Resources, and a final set of changes will be submitted to us upon completion of the Review of the Integration of Energy Markets and Network Services (RIEMNS).


Faced with considering each set of Code changes separately, and while we obviously have firm views about the future direction of the market and what are the current and emerging issues for resolution, it must be remembered that the Commission does not have regulatory powers at large in respect of the electricity market. Consequently, while we have indicated many times in the past that we favour moving towards nodal pricing, we cannot impose it; rather we seek to encourage debate. In the light of this background it is not surprising that the code change process has failed to deliver a suitable answer and direction regarding the integration of network service with energy markets.


Role of government


The CoAG meeting on 8 June set in train a number of processes affecting energy policy generally and the NEM in particular.


I have already expressed a degree of scepticism about some of the criticism of NEM governance arrangements, and my concerns that the independence of NEM regulatory bodies not be compromised.


Nevertheless, I in fact have a good deal of sympathy for the concerns of the NEM jurisdictions. Having set up the NEM institutional arrangements, some of them now, I believe, feel that they have insufficient control of their creation. Clearly the political consequences of things going wrong in the electricity market could be catastrophic. It is entirely understandable that governments should want to decide the overall framework in which the market develops and have some assuredness that it will perform well.


However, the vital distinction needs to be made between overseeing the strategic direction and being involved in market operations.


Out of the CoAG meeting we have:


• a new Ministerial Council on Energy;

• a NEM Ministerial Policy Forum; and

• an independent review of energy market directions.


It is difficult as yet to see how these all fit together. For example, the independent review will report to the Ministerial Council and will identify strategic issues and policies required, including regulatory approaches. The Ministerial Council will look at opportunities for increasing interconnection and system security. The Ministerial Policy Forum will also look at interconnection and a string of other issues including transmission pricing, rebidding, regional boundaries and demand side participation. The Forum will report to members of CoAG.


CoAG itself has requested reviews of VoLL and bidding and rebidding rules.


There seem to be a number of parallel processes here. I suspect it would be useful if, contrary to Euclid, these processes were to converge.


If all of this can be pulled together, there is a real opportunity for progress in electricity markets. But first, some words of caution about that distinction between market operations, which should be the province of the NEM institutions, and the market framework, where governments have a legitimate strategic role.


Many of the matters I listed above as being considered by the Ministerial Policy Forum look awfully like detailed issues of how the market operates.


The danger is that in addressing these issues State governments may leave themselves a greater role in the ongoing development of the NEM. Past experiences of government market involvement highlight the dangers.


First, in dealing with immediate problems, governments are likely to make decisions that protect their constituents from negative short-term impacts but which compromise the ability of the market to deliver long-term benefits. And it must be remembered that it is the long-term benefits of the reforms that contribute overall to the competitiveness of the Australian economy.


Second, it is hard to be confident that policy makers will make decisions in the overall interests of the market, of competition, and thus of end-users, given that some jurisdictions continue to have vested interests in the market as owners of generation and retail businesses.


The dangerous consequences from partial deregulation and government intervention in the market have been illustrated in California. I consider that the NEM has the potential to imitate the Californian experience if governments do not clearly set a framework for the operation of the market. That framework must delineate the role of governments and limit it to the broader policy issues and leave the operation of the market to market participants. Anything short of this will deter investors in the market.


But let us look to the positive side. The NEM jurisdictions have been right to draw attention to the need for clearer energy market directions. In the CoAG Communique, all governments reaffirmed their existing commitments to currently agreed principles, reforms and timetables.


It is clear that the current code change process cannot cope with the big issue of integrating network services into the energy spot market, because the NEM institutions find they do not have sufficient mandate from the jurisdictions. In the light of their recommitment to reform, governments must now follow through with the further market development that is required to realise the objectives of reform.


Following careful consideration of principles and issues, they will, I hope, commit to a genuine national electricity market.


And, having accepted the implications of market objectives for the overall policy framework, they will, I hope, renew the mandate of NEM institutions to follow through those objectives into market development. Of course, I accept that they will look at the NEM institutions and regulatory arrangements as part of their review process.


The CoAG process has some great achievements to its credit. Taking the half-reformed electricity market to its full potential would rank with those earlier successes.


Incidentally, in my view, the continued interest and involvement of central agencies from State and Commonwealth governments will be necessary if the overall vision, focus on the national interest, and policy impetus are to be brought to bear.


South Australia


While there are a number of unresolved issues, as indicated from the above discussions, the Commission nevertheless considers that the electricity market reforms have delivered significant benefits. But South Australians cannot be expected to be happy with paying the highest average prices in the NEM. However, we need to understand why prices are higher in SA and whether having high prices is necessarily a bad thing, given how our market operates.


At this conference we have heard about examples of new investment in generation and unregulated interconnection that have been announced, encouraged by the high prices in SA. So, in the medium term, we could expect improved market outcomes with the introduction of additional generation capacity, new interconnection and even heightened demand side participation. I want to come back to this theme because there is always a question about impediments to competition over the medium to longer term, and whether there will be the necessary level of competition in generation and retail to deliver benefits to SA customers. In this context, the regulatory arrangements for new network investments, particularly regulated interconnectors, are important.


In the short term, however, we could expect to see a continuation of high pool prices for a number of reasons. First, decisions that were taken about the structure of the industry in SA will continue to have some impact. I say a bit more on this later. Second, we have adopted a commodity trading model for our market that sets the pool price according to the bid of the last generator dispatched, the price being the half-hour average of the marginal price for each five-minute dispatch interval: the so called gross pool model.


To elaborate a little, the gross pool has two consequences. One is, as marginal plant sets the price in SA, that usually means gas-fired plant. Gas-fired plant is going to be more expensive than most coal-based plant in the NEM, hence you would expect prices to be higher in SA. Another is that the market is a compulsory one. Therefore, while contracts cover the vast majority of the financial transactions in the market, the spot price is nevertheless influential in both setting contract prices and the balance between contract and spot price exposure that generators and retailers are prepared to take. I am sure that all of you listening who have gone through the current round of contestability are well aware of this interplay between the contract market and pool prices.


Third is that the market design is based on spot energy prices driving both current consumption decisions and future investment needs. Consequently, the market is extremely flexible, allowing generator bids to be changed up until dispatch, along with a high price cap. I will talk a little more about this as well in the context of NECA’s review of bidding and rebidding rules.


Now, is it possible to deal with the concerns that have been raised while preserving the medium term outlook? We could look at capping the market, or restricting the ability to modify bids or even regulating delivered energy prices in the local market. No doubt, there are other options. However, I don’t see how you can intervene in the market in such a critical fashion without damaging the prospects for investment in SA over the medium term.


Further, any intervention in the market must interfere with an energy-only price driving current consumption and future investment decisions and, therefore, immediately invites the need for additional market support mechanisms, such as capacity or availability payments and levies to fund the caps on the market. You only need to look at California, and the billions spent by the government there to support energy purchases, to realise that intervention is not as simple as it sounds.


I will be very interested in the recommendations coming out of the current SA review into the electricity market on the issue.


Competition in generation


From market start, there have been questions raised about whether the structural reforms undertaken in generation were sufficient to sustain vigorous competition. You may recall that the ACCC raised some concerns about market structure in its final determination on the NEM Code, and also in the draft determination expressed some concern about the level of bidding flexibility in the Code. Over the past summer we have witnessed a number of instances of bidding and rebidding behaviour by generators aimed at maximising their financial position. In some cases this has impacted on the pool price and in other cases the normal conditions of supply and demand have resulted in higher pool prices. Some commentators have suggested that these outcomes point to a lack of competition in generation or the use of market power to maximise profitability.


Currently under the Code generators are permitted to structure their bids in a stack based on price and volume. These initial bids can be modified at any time in terms of the volumes offered for dispatch, although the offer price cannot be changed. This ability to rebid is an essential tool in the generation market, as bids and their modification are the main mechanisms generators have to make themselves available (or unavailable) given the prevailing market conditions. While there is concern that this flexibility is used to push prices higher, comparisons of forecast prices based on initial bids undertaken by NECA suggest that rebidding leads overall to lower prices than would otherwise have been the case.


However, concerns with certain aspects of the recent bidding and rebidding strategies of generators have led NECA to investigate the potential to impose additional safeguards against this behaviour, and CoAG has asked for early attention to be given to the issue.


The Commission welcomes the rebidding review by NECA. We consider, however, that market power issues need to be addressed primarily in terms of market structure rather than redefinition of the market rules. We also consider that while additional rules and restrictions on bidding and rebidding may limit the number of times generators rebid, they cannot address any underlying source of market power due to the structure of the generation market, the interplay with the design of the market or the constrained ability of interstate generators to compete with instate generation. The most effective way of ensuring competitive prices are delivered in the market is by ensuring strong competition among market participants.


In the initial restructuring of the South Australian market the Commission expressed the view that while the creation of three generator companies was to be applauded, further horizontal separation of generation assets was required to ensure effective competition. Structural concerns in the generation sector of the South Australian market have been compounded with the delaying of the proposed interconnector between South Australia and New South Wales (SNI). This development could have introduced substantially more competition into the wholesale market in South Australia from interstate generators, potentially producing lower electricity prices for the State. However, the SNI project is still only a proposal at this stage and has yet to be granted status as a regulated interconnector by the IRPC.


While developments in new interconnectors, new generation, and new gas pipelines may alleviate these concerns in the medium term, the local market will continue to pay higher prices in the short term because of the interplay between industry structure, the level of market power and the market rules.


One thing that is continually brought home to me in my experience in the ACCC - whether dealing with energy, or telecommunications or, indeed, with airlines - is that trying to engineer competition into a market that does not have a competitive structure is an uphill battle. And dealing with anti-competitive conduct after the event runs a poor third.


Competition in retail


A competitive retail market is also essential if end-use customers are going to benefit from the NEM. While the contract prices being offered to newly contestable customers in South Australia have been driven by the underlying market situation, increased competition in the retail sector would have provided customers with wider options than those that have been offered.


As with the generation sector, the structure of the retail sector in South Australia determines the extent of competition in the retail market. At the time of industry restructuring the Commission considered that there should be two distributor retailers within the South Australian market, rather than the one that was established. I believe that what we have seen recently here with the treatment of newly contestable customers confirms the correctness of that view.


The level of new entry will also affect competition in the retail market by retailers. New entry will only occur when insurance against volatile wholesale spot prices is obtained. In practice this is usually undertaken through some form of bilateral hedge between the retailer and generator. Without contract cover, or any other form of insurance, a retailer will be subject to high risks in supplying an end-use customer with electricity at a set price. Therefore, the extent to which the retailers can obtain insurance from volatile prices is a critical factor in determining the competitiveness of any retail market.


For retailers wishing to enter the South Australian market from other regions, where they may have already obtained some degree of bilateral contract cover, the issue of obtaining some inter-regional insurance against the price variation of the two regions becomes a critical concern.


I believe that the market is beginning to deliver products that can be used by retailers, and also generators, that enable them to offer supply in regions other than where they buy or generate electricity.


In this light, the development of an entrepreneurial interconnector enables market participants to enter capacity contracts with the project’s proponent. Such contracts would operate similarly to those between generators and retailers and would effectively give the rights holder some protection against the price volatility in the regions in which it was supplying.


The auctioning of inter-regional settlement residues also facilitates entry of retailers into new regions. The inter-regional settlement residue is the difference between the value of energy in one region and the value of that energy once it has been transferred to another region. This difference in value is primarily due to the price difference between regions. By making the settlement residue available to the market place, the risks of trading between regions can be better managed.


An issue that currently exists with use of settlement residues as an inter-regional hedge is that they do not provide a firm or certain level of insurance against prices. For example, if the interconnector is constrained for some reason related to the operation of the network, then the effectiveness of the settlement residue units as a hedge against inter-regional prices is diminished.


NECA has acknowledged such shortcomings in the summary draft report on the scope for integrating the energy market and network services. In this draft report NECA proposes a three-stage process for improving the firmness of the existing settlement residue auction arrangements which would involve:


• improving information flows;

• developing market-based performance measures on the assets that affect notional interconnectors; and

• introducing contracts against those performance measures designed to encourage behaviour that maximises market benefit.


The continuing development of entrepreneurial interconnectors, together with the firming up of settlement residue units as a form of inter-regional hedge will greatly assist in the development of a more competitive retail sector in South Australia in the medium term.


Development of interconnectors


As mentioned, interconnectors provide a means of inter-regional trade, and therefore facilitate greater competition in both generation and retail markets of the market. The regulatory framework for the development of regulated interconnectors has therefore had, and will continue to have, a large influence on the competitive outcomes in the NEM. This issue is particularly relevant to South Australia, where there are a number of proposals for both regulated and unregulated interconnectors. Under the current Code arrangements, if a party wishes a new interconnector to be granted regulated status, NEMMCO must apply the regulatory test. The test is whether the proposed project maximises the net present value of the market benefit, having regard to alternative projects, timings and market development scenarios. The ACCC plays an important part in this approval process as we developed and now maintain the regulatory test.


At present there has not been a regulated interconnector approved under the regulatory test. The Queensland New South Wales (QNI) interconnector proceeded under a derogation from the Code approved by the ACCC. TransGrid’s SNI proposal is therefore the only interconnector to be considered under the Code arrangements. NEMMCO is at present applying the regulatory test to this proposal.


The lack of development of regulated interconnectors, and hence the limiting of inter-regional trade in the NEM, has led to criticisms of the regulatory arrangements. For example, the National Competition Council’s report titled ‘NCP - Third Tranche Assessment Framework’ stated that delays in resolving the SNI project have been excessive and mean that the NEM objective of no discriminatory legislative or regulatory barriers to interstate and/or intrastate trade is not being met.


The concerns regarding the nature of the regulatory process for new regulated augmentations have been addressed in the set of Code changes brought to the Commission titled ‘Network and Distributed Resources’. These Code changes amend the process to be followed if an interconnector is to achieve regulated status. Included in the changes is the removal of NEMMCO’s responsibility of applying the regulatory test. Instead the proponent TNSP would be responsible for applying the regulatory test, but its determination would be subject to a two-stage dispute resolution process, including the ACCC having a final right of review.


In addition to these Network and Distributed Resources Code changes, NEMMCO has established an Interconnector Working Group to investigate and report on the processes involved in the assessment of proposals to establish new interconnectors or augment existing interconnectors. The working group is required to include the proposed Code changes regarding Network and Distributed Resources when undertaking the review of the processes.


While the arrangements for the approval of regulated interconnectors are the subject of discussion and Code changes are currently before the Commission, I consider that the questions surrounding the development of regulated interconnectors need to be considered in the context of the direction of the market. Are we moving towards a zonal/nodal pricing market, where congestion rents signal the need for new investment, or are investment decisions to be left with networks and regulators under some form of common carriage regime where investment is undertaken to ensure no network congestion?


As I indicated earlier I do not believe the current NEM institutions are in a position to answer such questions in the light of the government debate about NEM governance. That is in part why I welcome the renewed policy interest State governments have taken through the Ministerial Policy Forum and would encourage them to consider how we can build on the start we have made to our electricity reforms, reforms that are well recognised around the world. We need to encourage timely and efficient investment in the electricity market, promote competitive outcomes, and efficient prices, and ensure that those who pay for and benefit from such investment decisions are given an interest in the outcome.


Let me say, however, that in my view the choice is starker than some seem to realise. Unless we move to market-based prices signalling the need for new network investment, we will be left with a set of separate regional (ie State) electricity markets. Although they will be interconnected, these will not be a truly national network.


If we don’t move all the way to a zonal/nodal pricing market the next-best alternative would be a centrally-planned national network. But we wouldn’t have that either. We’d have the great Australian railway story: separate State networks each going its own way. In fact, that’s what we do have. Are we satisfied to leave it that way?


Indeed, how could we leave it that way in view of the objectives that governments agreed on back in 1994? Those objectives include non-discriminatory access to the interconnected transmission and distribution network. How could we pretend access was non-discriminatory if generators or customers on different sides of arbitrary regional boundaries faced different costs of getting their product to market or of purchasing in the market?




I would now like to move on togas issues.


The South Australian government has been attempting to encourage additional gas supplies into the State. The ACCC is aware that a number of proposals have been canvassed. I shall outline the key features of the regulatory regime in gas, and then explore how each proposal might be treated under the regime.


The gas regulatory regime as it stands stems from the 1994 CoAG commitment to "free and fair trade in natural gas", which led to the 1997 Natural Gas Access Agreement that each State and Territory would commit to the introduction of the Gas Code. This Code establishes a single set of principles to govern access by third parties to all transmission and distribution pipelines. The Code was developed in a joint process involving the Commonwealth, States and Territories and the industry.


The Code is given legal effect by State/Territory-based legislation. Each State/Territory applies to the National Competition Council (NCC) to have its regime "certified" such that it becomes an "effective" regime under Part IIIA of the Trade Practices Act.


Under the Gas Pipelines Access Law, the ACCC is the relevant regulator for access to services provided by transmission pipelines in all States and Territories except Western Australia. Access to services provided by distribution networks is regulated by independent State/Territory-based regulators. The NCC recommends to the relevant Minister which pipelines should be regulated under the Gas Code. This method separates decisions on the approval of the regime and the extent of its application from the regulators that operate under it.


Currently, the ACCC is in the process of approving access arrangements for all pipelines covered under the Code.


Service providers of new facilities may also give an access undertaking under Part IIIA of the Trade Practices Act. Such an undertaking allows the service provider to remove uncertainty as to what access conditions will apply to the service, by agreeing to certain access arrangements with the Commission in advance. The ACCC assesses any application for an undertaking against the criteria set out in Part IIIA. When calculating the reference tariff for an undertaking, the Commission expects reference tariffs to be based on the efficient cost of providing reference services. Further, prices should converge towards efficient costs over time. These matters mean that proponents of access undertakings must provide adequate information enabling the ACCC and third parties to assess these issues.


I would also like to mention the implications of the recent CoAG meeting for gas regulation. The tasks of the new Ministerial Council on Energy include examining issues such as future energy use scenarios for Australia, the potential for harmonising regulatory arrangements, and opportunities for increasing interconnection and system security in electricity and gas.


The terms of reference of the independent review, which is to be overseen by the Ministerial Council, encompass a broad range of issues, including "examining regulatory approaches that effectively balance incentives for new supply investment, demand responses and benefits to customers".


Accordingly, the review may provide guidance to the Commission on the balance to be struck between facilitating greenfields investment and limiting the exercise of market power by pipeline operators.


Another of the proposed issues of the review is to "identify the means of encouraging the wider penetration of natural gas including increased upstream gas competition, value adding processes for natural gas and potential other uses such as distributed generation…"


The prospect of increased upstream competition would be strongly endorsed by the Commission. As will be discussed later, upstream competition holds the potential to increase the benefits to consumers of third party access to pipelines.


To put the Commission’s role as a gas transmission regulator in a broader perspective, the Commission aims to achieve a balance between, on the one hand, the pipeline owner receiving a fair return that will encourage appropriate new investment in the industry and, on the other, producing efficient tariffs that allow gas users to compete and invest in other markets. In pursuing these aims, the Commission is aware of the need to ensure compliance costs are minimised and that the regulatory process is objective, transparent and as light-handed as possible.


I would now like to discuss how the regulatory issues flowing from this overarching legal framework affect the South Australian gas market


As you would be aware, South Australia currently obtains all of its gas supplies from the Cooper Basin via the Moomba to Adelaide pipeline, generally known as MAPS. As this is a covered pipeline, the operator, Epic Energy, is currently working with the ACCC within the regulatory framework to arrive at an Access Arrangement. The revised Access Arrangement is currently out for comment, and the Commission is seeking submissions from interested parties by June 29. In its approved form, the Access Arrangement is likely to be a key reference point for future tariffs in the market.


A significant issue in relation to MAPS is how expansions of the pipeline are to be treated. At issue is whether the cost of expansions should be borne by all users through a general tariff increase, or whether the cost should be borne by incremental users only. This becomes particularly important if proposals to source gas from the Timor Sea go ahead, as will be discussed shortly.


We would welcome your comments on this issue.


Following the receipt of submissions, the Commission will seek to expedite finalisation of the Access Arrangement.


Market-derived tariffs


Given the status of MAPS as South Australia’s sole current supply of gas, projects to bring gas into the State from other basins are of great interest. These include proposals to ship gas from the Timor Sea.


We are aware of two proposals, from Epic and APT. Both these proposals would use MAPS. Accordingly, were either to proceed, MAPS would need to be expanded. Epic’s proposed pipeline, which would carry up to 200 petajoules annually, and deliver gas to South Australia by the first quarter of 2005, invites further discussion because of the proposed approach to setting tariffs.


Epic has requested that it be allowed to charge market derived tariffs to users. A market derived tariff differs from the more traditional cost of service tariff generally used by the Commission. The cost of service tariff calculates the revenue that would allow a pipeline operator to recover its costs, as well as earn a fair return on equity. By contrast, a market derived tariff basically refers to the price that customers in the market place have signalled their willingness to pay.


The view of the Code developers on this matter is that third parties require sufficient transport information to enable them to derive a reference tariff.


The Commission’s attitude to Epic’s proposal is that the issue of market-derived tariffs can only be considered in the context of the specific proposal. Potential customers of the Darwin-Moomba pipeline are unlikely to provide meaningful views on market-derived tariffs unless they can examine specific details of the service offered by Epic. Only then can a conclusion be reached on the potential of the service provider to exercise market power.


There is a further question as to the perceived efficiency of market-derived tariffs. The fact that a pipeline operator can find customers who are willing to buy gas at a particular tariff does not of itself demonstrate an efficient tariff. Any monopolist, charging a revenue-maximising price, will still attract customers.


The market-derived tariff must be examined to determine whether the tariff reflects the exercise of unilateral or co-ordinated market power, or whether it has been driven to efficient levels through competitive pressures.


In other words, the willingness to buy and the existence of market power are separate questions, and must be examined in each particular circumstance.


Greenfields regulation and market derived tariffs


The market derived tariffs issue has important implications for greenfields projects. Compared with established infrastructure, greenfield projects typically have an uncertain volume profile and a variety of specific risks. The Commission recognises these specific risks associated with greenfield investments and has examined several options to deal with them. In the Commission’s approval of the greenfields Central West Pipeline, the final access arrangement incorporated a number of features that are a definitive signal to industry that the Commission recognises the risks associated with greenfields developments.


When it comes to tariff setting, greenfields pipeline operators are likely to be aware of the different implications of regulation under Part IIIA of the Trade Practices Act compared with regulation under the Gas Code. Operators may take the view that market derived tariffs are not available under a Gas Code Access arrangement, but may be obtained under a Part IIIA Access undertaking.


In relation to this issue, greenfields operators would be well advised to understand the interplay between the application of the two regimes. They may make their own conclusions as to the likelihood that their proposal will be covered by the Code.


Upstream competition


The greenfields regulation issue is likely to arise in respect of any proposal to bring gas from Victoria to South Australia, taking advantage of gas discoveries in Victoria’s Otway Basin.


There have been recent press reports that fieldwork has already commenced on a 670 km pipeline from Port Campbell to Adelaide, to be owned by Australian National Power and Origin Energy. Reports indicate the pipeline could deliver a volume of gas equivalent to 50 per cent of the gas currently received from the Moomba pipeline. This adds to a broader picture of a multiplicity of projects to pipe gas into South Australia, which are at various stages of development and certainty. From our perspective, this raises both regulatory and competition issues.


Dealing first with the regulatory angle, there has been some speculation that following the Australian Competition Tribunal’s decision in the Eastern Gas Pipeline matter, the proposed Port Campbell to Adelaide would not be covered under the Gas Code.


While such a determination is outside the ACCC’s purview, my view is that the Tribunal’s decision on the Eastern Gas Pipeline appears to have been made mainly on the facts of the particular situation, rather than making any new definitive statement of the law relating to coverage under the Gas Code. Accordingly, each project must be assessed on its merits in the context of the specific circumstances of the project.


Should the proposed pipeline be covered, the ACCC remains committed to a facilitative approach to regulation, with a view to encouraging long-term solutions to South Australia’s energy problems.


New pipeline projects raise the prospect of competition between upstream sources of gas. Such competition can potentially deliver more certainty of supply and lower prices to South Australian consumers.




So that’s the view from one regulator. We and our colleagues in NECA, NEMMCO and the State regulators will proceed within the frameworks governments have given us. But over the coming period, much of the focus will shift back to governments. Their renewed interest in energy matters and markets must be seen as welcome. There are dangers to be avoided, but the potential gains are great.


Let us all do our best to see that the efforts of governments are directed towards market-based outcomes, that time isn’t wasted reinventing wheels and throwing open reasonably settled issues, and that interstate rivalries and jealousies do not override the national interest.