THE AUSTRALIAN NATIONAL ELECTRICITY MARKET: CHOOSING A NEW FUTURE

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1 Australian Energy Market Commission THE AUSTRALIAN NATIONAL ELECTRICITY MARKET: CHOOSING A NEW FUTURE World Energy Forum May 2012 Quebec City, Canada Conference Paper John Pierce Chairman 1

2 Inquiries Australian Energy Market Commission PO Box A2449 Sydney South NSW 1235 E: T: W: Citation AEMC 2012, The Australian National Electricity Market: Choosing a new future, Conference Paper, World Energy Forum on Energy Regulation V, May 2012, Quebec City, Canada. This work is copyright. The Copyright Act 1968 permits fair dealing for study, research, news reporting, criticism and review. Selected passages, tables or diagrams may be reproduced for such purposes provided acknowledgement of the source is included. 2

3 The Australian National Electricity Market: Choosing a new future. Mr John Pierce Chairman Australian Energy Market Commission 1 Presented to session: the environmental impacts of the current electricity generation mix Tuesday 15 May 2012 World Forum on Energy Regulation Quebec City, Canada. 1. Introduction Traditionally, the key objectives of energy markets have been to deliver a secure and reliable supply of electricity to customers at an efficient price. In Australia, the National Electricity Market (NEM) has delivered these outcomes under a particular set of physical realities. Specific fuel resources tend to predominate in different parts of Australia and the NEM has allowed these natural advantages to be utilised. As one of the longest single interconnected power systems in the world, the NEM has supplied a geographically dispersed load, across multiple climatic zones. What is being asked of electricity markets around the world is rapidly changing; the NEM is no exception. While consumers continue to expect the safe and reliable delivery of efficiently priced electricity, the NEM is now being asked to move away from the current fuel mix and to produce electricity from less carbon intensive sources. Australians are also changing the way in which we use electricity. Structural shifts in the Australian economy have seen a general reduction in the energy intensity per unit of Australian GDP, even as our overall use of energy continues to grow. Residential energy use continues to drive increases in peak demand, while consumers are becoming increasingly involved in the market and beginning to demand services which reflect their particular needs. All of these changes place further demands on the networks of the NEM These changes mean transitioning to the use of fuel resources which would not necessarily be selected by the market on a least cost basis. It also means that the market must begin to offer more specific energy services to consumers, rather than 1 The author wishes to acknowledge the contributions of AEMC Commissioners and staff to the research and writing of this paper. I am particularly grateful for the contribution by Christiaan Zuur in researching and drafting for the paper. I am also grateful for comments on drafts and collaboration provided by my fellow commissioners, Neville Henderson and Brian Spalding, the AEMC s Chief Executive Steven Graham, and Senior Director Paul Smith 3

4 providing a largely homogenous product. As with any major structural change, a large number of risks accompany this process. The challenge for policy makers and the NEM regulatory bodies over the coming years will be to develop a co-ordinated and competitive approach to facilitate these new demands. This approach must recognise that market systems are effective at delivering desired outcomes the challenge is developing clear, concise policy and regulatory frameworks that allow markets to function effectively. This paper begins by providing an overview of the NEM, including a description of the process of policy development and implementation which brought the NEM into being. We then examine a number of the current challenges facing the NEM, including the incorporation of renewables into the generation mix, the impact of a growing gas sector and changes in the nature of demand. 2. The NEM: Governance structures, operations and implementation 2.1. Governance structures and objectives The NEM is the interconnected power system that services the eastern seaboard Australian states and territories of New South Wales (NSW), Victoria (Vic), Queensland (Qld), South Australia (SA), Tasmania (Tas) and the Australian Capital Territory (ACT). The population and gross domestic product of these states and territories is included in table 2.1 below. Table 2.1: State gross domestic product and population State Gross state product (% growth) Population NSW 2.2 7,300,000 Vic 2.5 5,620,000 Qld 0.2 4,580,000 SA 2.4 1,660,000 Tas ,500 ACT ,600 Note: the state of Western Australia and the Northern territory are not included in these figures as they do not form part of the NEM National gross domestic product: 2.1% National population: 22,882,642 Source: Australian Bureau of Statistics, 5220 Australian National Accounts: State Accounts

5 The governments of these states have different levels of involvement in electricity service provision within their jurisdictions, including, in some cases, oversight of the setting of retail price regulation and network reliability standards. 2 Ministerial energy representatives from the commonwealth, states and territories provide co-operative oversight of the NEM through the Standing Council on Energy and Resources (SCER). This ministerial council in turn reports to the Council of Australian Governments (COAG), consisting of the Prime Minister and Australian state premiers. The SCER and COAG are responsible for the overarching legal framework of the NEM, the National Electricity Law (NEL), which sets out the responsibilities of the various NEM institutions as well as a national electricity objective (NEO). The NEO is the main statutory objective to which all of the NEM market regulatory bodies must adhere. It is set out in section 7 of the NEL: The objective of this Law is to promote efficient investment in, and efficient operation and use of, electricity services for the long term interests of consumers of electricity, with respect to: a) Price, quality, safety, reliability and security of supply of electricity; and b) The reliability, safety and security of the national electricity system. The NEO refers to issues of economic efficiency; environmental and social issues are dealt with through other pieces of legislation and specific policies. The Australian Energy Market Commission (AEMC) is the market institution responsible for developing changes to the National Electricity Rules (NER), which is the general statutory framework under the NEL which describes NEM functions. The AEMC is also responsible for market development and provides policy advice to the SCER. 3 The Australian Energy Market Operator (AEMO) operates the power system as well as the retail and wholesale gas markets of south eastern Australia. AEMO are also responsible for long term planning of the interconnected power system, including forecasting demand and supply scenarios and network development. AEMO are also responsible for implementing changes to the rules made by the AEMC. The Australian Energy Regulator (AER) is responsible for the economic regulation of the non-competitive sectors of the NEM, including electricity distribution and transmission networks as well as some gas networks. The AER is also responsible for the enforcement of compliance with the NER. 2 Noting that there are substantial differences in the level of state government involvement between the jurisdictions. 3 The AEMC is not empowered to itself make changes to the Rules, other than for administrative purposes or to make a non-material change. Rule changes may be proposed to the Commission by any individual, including market participants, the MCE or by any member of the public. 5

6 Figure 2.1: NEM institutions Source: AEMC 2.2. A few physical realities A primary physical characteristic which has shaped the NEM is the narrow but dispersed distribution of load and generation centres along the east coast of Australia. The NEM spans a geographic area over 5,000kms in length, from Port Douglas in north Queensland, to Port Lincoln in South Australia and Hobart in Tasmania. 4 The majority of load is concentrated in a relatively narrow band within 100km or so of the coast. Across this geographic spread there are markedly different climatic and environmental characteristics, driving very different energy consumption patterns across the system. To serve such a widely distributed load, the NEM incorporates over 750,000 kms of distribution and 40,000kms of transmission infrastructure. As a comparison, in the United Kingdom there are around 800,000 kms of distribution and 25,000 kilometres of transmission infrastructure serving a population which is more than three times that served by the NEM Australian Government Productivity Commission, Electricity Network Regulation Electricity: Issues Paper, February 2012, p.8; UK Department of Climate Change, The Current British Electricity Network, accessed from 12 March

7 In , the NEM supplied over 204 TWh of energy to around 9 million customers. This energy was supplied by 305 generators, with a total installed capacity of MW. Around 78% of the energy consumed in the NEM is produced by coal fired generation, 12% by gas fired generation and 8% by hydroelectricity. Wind generation is the primary non-hydro renewable and currently provides around 2.7% of total energy consumed. 6 Figure 2.2: The NEM Source: AER, State of the Energy Market 2011 The nature of the generation mix reflects the relative abundance of various fuel resources along the east coast of Australia. These resources include extensive black and brown coal deposits in SA, Vic, QLD and NSW; natural and coal seam gas in SA, QLD, NSW and Vic; and hydro resources in Tas, NSW, Vic and QLD. 6 Australian Energy Regulator, State of the Energy Market 2011, p.25; Electricity Supply Association of Australia, Electricity Gas Australia 2011, p.19 7

8 In recent years there has been some entry of wind generation in SA, Vic, NSW and Tas, as these regions have the most favourable wind resources. 7 The extent of this wind generation entry has been substantial in some jurisdictions; for example, in South Australia, total installed wind generation is approximately 20% of total installed capacity. 8 Given these relative resource endowments, the NEM has utilised a mix of different fuel types in proportion to their relative costs: generally, black and brown coal fired generation has been used for base-load, black coal or combined cycle gas turbine (CCGT) for mid merit, open cycle gas turbine (OCGT) gas for peaking and OCGT gas or liquid fuel for super peaking. Figure 2.3 below is a stylised example of an expected NEM dispatch pattern. The NEM includes a number of hydroelectric generators with large nameplate capacities. However the relatively limited water inflows to some of these units mean that they may be energy constrained. For example, Snowy Hydro, which has large energy constrained hydroelectric units located between NSW and Vic tends to serve a peaking role within the overall dispatch pattern. Conversely, Hydro Tasmania, operating units with relatively higher levels of inflows, tends to operate these units more frequently. Figure 2.3: Expected dispatch pattern Source: AEMC. 7 Although a primary driver of investment in wind is the enhanced Renewable Energy Target, which is described in more detail later in this paper. 8 Energy Supply Association of Australia, Electricity and Gas Australia 2011, ESAA,

9 Figure 2.4 provides an illustration of an optimal generation mix. As the load duration curve moves to the left (high demand levels which occur less frequently), the marginal generator selected moves from high capital cost/low variable cost baseload to low capital cost/high variable cost peaking units. This demonstrates an economically optimal use of different fuel resources to meet increasing levels of demand. Figure 2.4: Load duration and the optimal generation mix Peaking Intermediate Baseload Total cost Operating hours Peaking Intermediate Capacity (MW) Load duration curve Baseload Source: AEMC Demand duration: hours 9

10 As will be discussed later in this paper, the effect of market regulation and intervention can result in changes to the various functions described in figure 2.4 above. The NEM is an energy only, gross pool market, meaning that all energy is traded through the central clearing mechanism. As figure 2.5 demonstrates, a market clearing price is calculated for each half hour trading interval, based on the bids and offers of scheduled generators and consumers. A separate spot price is calculated in this way for each of the 5 regions of the NEM. While the market determines a separate spot price for each region, spot prices tend to be aligned for a majority of the time. 9 However, price separation can occur when inter-regional transmission assets are constrained, or when system security requirements limit inter-regional flow. Figure 2.5: The central dispatch process Source: AEMC; AER State of the Energy Market 2009, p.75. As figure 2.6 overleaf illustrates, spot prices in the NEM are capped by the application of the market price cap (MPC) of $12,500/MWh, while a cumulative price threshold (CPT) limits total market exposure to price risk. The CPT is currently set at a value of $187,500; when the sum of all spot prices in a seven day period exceeds this amount, an administered price period (APP) is triggered. During an APP, 9 In , spot prices across all of the mainland regions of the NEM were aligned for 61% of the time. Additionally, some price separation is related to losses on inter-regional connection assets rather than transmission congestion or security limitations. AER, State of the Energy Market

11 market prices are collared between two administered prices until the cumulative price has again dropped below the threshold limit. This arrangement is in contrast with the situation in some other international jurisdictions, where energy spot prices are uncapped. Under such market arrangements, allowing the market to always determine a final clearing price means that the scarcity value of electricity is always reflected in the market price. This high price also ensures that the marginal market generator is able to recover both its variable and fixed costs when dispatched. 10 Figure 2.6: Price caps in the NEM Source: AEMC A common criticism made of the NEM market design is that regulatory intervention to cap the maximum market price leads to a missing money problem. Put simply, this argument states that capping the maximum allowable market price during periods of scarcity reduces the extent of payments to generators that could be applied toward the fixed operating costs of existing generating plant and the investment costs of new plant. This reduces incentives to maintain existing plant or build new generation facilities. 11 In order to address this risk, the reliability panel of the AEMC sets the level of the MPC and the CPT such that the market price and cumulative price are capable of reaching levels which are sufficiently high to ensure that the most marginal generator earns revenue sufficient to cover its fixed and variable costs. The level at which the MPC and CPT are set therefore strikes a balance between sending efficient investment signals and mitigating the overall price risk faced by market participants. 10 It should be noted that other jurisdictions may also include emergency intervention powers for government in certain circumstances, including extended high prices. Alternatively, other factors such as the existence of capacity markets may change the extent and impact of high market clearing prices. 11 W Hogan, On an Energy Only electricity market design for resource adequacy, 23 September 2005, p

12 To date, these mechanisms have been invoked only rarely. Since market start, the CPT has been breached and an APP triggered on five occasions. Instances of the spot price approaching the price cap are also relatively rare: in 2011, spot prices were in excess of $12,000/MWh for a total of four and a half hours across all five jurisdictions of the NEM and did not reach the level of the spot market price cap on any occasion. Since NEM start, spot prices have tended to follow a typical pattern throughout each trading day. Figure 2.7 compares average hourly spot prices against average daily prices, between 1999 and Spot prices tend to be above the average price during periods of higher demand from mid-morning through to the early evening before dropping away during the later evening and into the early morning. These fluctuations reflect the common peak and off-peak demand patterns. Figure 2.7: Relative hourly prices in the NEM 1999 to % 100.0% Average Price = 0% 80.0% 60.0% 40.0% 20.0% 0.0% -20.0% Average hourly price compared to daily average price -40.0% -60.0% -80.0% Source: PricewaterhouseCoopers, Investigation of the efficient operation of price signals in the NEM, report to the AEMC, December 2011, p.7 While spot prices tend to follow an average pattern throughout most days of the year, at certain times they may also exhibit significant volatility. Figure 2.8 overleaf demonstrates the extent of spot price variance that can occur between an average and peak demand day. The dashed lines refer to spot prices in NSW on a day with peak demand (1 February 2011) and a day with average demand (17 July 2011), as referred to the left hand side axis showing spot prices. The solid lines refer to the corresponding levels of demand, as referred to the right hand side axis showing demand in MW. Figure 2.8 clearly demonstrates that spot prices on a peak demand day may be several orders of magnitude greater than prices expected on an average demand day. The capital intensive nature of generation businesses means that it is not feasible to base the revenue streams of such businesses around volatile spot market prices. Accordingly, participants have developed a number of mechanisms to hedge against this volatility. 12

13 As highlighted above, the NEM is a gross pool market, meaning that all energy is traded through the central clearing mechanism. Secondary markets facilitate the trading of hedging arrangements which help parties to address the volatility of prices that can occur in the gross pool. This contracting helps to provide a degree of cost and revenue certainty for both producers and consumers of electricity. Figure 2.9 overleaf demonstrates the physical and financial flows in the NEM and two particular types of hedging arrangement which have been designed around these flows. Figure 2.8: Average and peak spot price and demand in NSW across an average and peak demand day Source: AEMO half hourly price and demand data 13

14 Figure 2.9: Physical and financial flows in the NEM Source: AER, State of the energy market There are two primary derivative contractual hedging arrangements entered into by NEM participants. 12 Over-the-counter (OTC) contracts are bilateral arrangements entered into between participants, while futures contracts are bought and sold through a central exchange. Within these general headings, a number of specific contract types and arrangements have been developed by participants. One of the most common hedging arrangements is an OTC swap contract. As shown in figure 2.10 overleaf, swaps are based around a negotiated strike price and require difference payments to be made by the relevant counterparty depending on the level of the spot price. Where the spot price is below the strike price, the customer (usually a retailer) will pay the difference to the generator. Where the spot price is above the strike price, the generator pays the difference to the retailer. Table 2.2 overleaf provides a more detailed overview of the financial exchanges associated with the operation of an OTC swap contract. In this example a generator and retailer have established a strike price of $25 for 100MW of capacity for a defined period of time. This generator is dispatched for this volume, the retailer consumes the full volume of contracted energy and both parties are then settled by AEMO for their respective payments. Difference payments occur between the two counterparties after they have been settled by AEMO; importantly, these flows between counterparties are separate to the central settlement mechanism operated by AEMO. 12 The other type of hedging arrangement involves obtaining a mixed generation and retail portfolio in order to provide a physical hedge. This hedging strategy is described in further detail below. 14

15 Figure 2.10: An OTC swap contract Source: AEMC Table 2.2: Financial flows for an OTC swap contract Strike price is below spot price Strike price is above spot price Contract volume 100MW 100MW Strike price $25 $25 Spot price $30 $20 Retailer pays AEMO Generator is paid by AEMO Generator pays retailer Retailer pays generator Generator Net position Retailer Net position $30 x 100MW = $3000 $20 x 100MW = $2000 $30 x 100MW = $3000 $20 x 100MW = $2000 ($30 - $25) x 100MW = $500 Nil Nil ($25 - $20) x 100MW = $500 $ $500 = $2500 $ $500 = $ $ $500 = -$2500 -$ $500 = -$2500 Note dollar values are in $/MWh. 15

16 Another common hedge is an OTC cap. As shown in figure 2.11, a cap contract is based around a negotiated cap price. A customer, usually a retailer, pays a generator a premium for this contract in order to cap the amount they will pay for electricity. While the spot price is below the strike price, the customer continues to pay the spot price. However, once the spot price exceeds the strike price, the generator pays the customer the difference between the spot price and the strike price. Figure 2.11: An OTC cap contract Source: AEMC Financial exposure may also be managed through the use of exchange traded futures. A futures contract, as the name implies, is based on an expectation of the future wholesale price for electricity. The price of a futures contract on the exchange is based on the market s expectation of the spot price over the futures contract period. Futures contracts may take a range of forms, including baseload and peaking coverage. Parties buy or sell a position in relation to a future price of energy and then pay or receive a daily margin reflecting their relative position to the price on that day. Figure 2.12 demonstrates how margin payments are calculated in reference to the difference between prices (P1 and P2). The diagonal line represents the payoff profile for a buy position on a futures contract. This would be the typical position taken by a natural purchaser of electricity, such as a retailer, who wishes to hedge against high prices in the spot market. Over the course of a day, high prices in the spot market will result in an increase to the price of the futures contract from P1 to P2. A retailer who entered into the futures contract at P1 will receive a margin receipt from the exchange to offset the cost of its purchases in the spot market. This margin receipt will be funded by a margin payment from a countervailing participant who holds a similar futures contract on the exchange but with an opposing sell position. The holder of a futures contract 16

17 with a sell position would typically be a participant who wishes to hedge against low prices in the spot market, such as a generator. Similar to OTC cap contracts, cap futures contracts also exist, which allow a participant to hedge against spot prices above a certain level. In this case, movements in the price of the futures contract, and subsequent margin payments, will only occur when the wholesale spot price moves above the capped level. Exchange traded options are also utilised to hedge price risk. These arrangements provide the buyer of the contract with the right (but not the obligation) to buy or sell a futures swap or futures cap contract at a defined price. Figure 2.12: A futures contract Source: AEMC Another, increasingly common arrangement in the NEM is vertical integration between retail and generation businesses, in order to develop a physical hedge against spot price fluctuations. A firm may utilise a mix of physical and contract arrangements in order to deliver a mixed hedge portfolio, as demonstrated in figure 2.13 below. In this case, the firm has constructed a mix of contracts and physical capacity which matches its average retail load and a separate mix reflecting its maximum expected load. 17

18 Figure 2.13: A vertically integrated hedging strategy Source: AEMC Contracting is used extensively in the NEM to manage exposure. In 2010/11, total traded volumes of futures contracts for the Vic, NSW, QLD and SA regions were equivalent to around 284% of underlying electricity consumption. 13 Figure 2.14 provides an illustration of the extent of futures and options contracts traded on the Australian stock exchange. Figure 2.14: Futures, options and underlying physical demand Source: Australian Financial Markets Association, Australian Financial Markets Report, AFMA, AER, State of the energy market 2011, November 2011, p

19 There has been a general change in the types of contract utilised by participants in the NEM to hedge price risk. While OTC contracting has traditionally been the predominant hedging mechanism, recent years have seen a marked increase in the use of futures. As demonstrated in figure 2.15, total volumes of electricity futures and options are now in excess of total volumes of OTC contracts. This may reflect a number of underlying causes, including uncertainty surrounding the price of carbon and the effects of the global financial downturn on perceptions of counterparty risk and credit availability. Figure 2.15: Volumes of OCT vs. futures contract trading in the NEM 14 Source: AFMA, 2011 Australian Financial Markets Report, p.2 The risk hedging mechanisms described above help participants to manage the price uncertainties inherent to electricity trading. In helping to manage these uncertainties, hedging arrangements underpin the viability of investment in the NEM. The types of hedging arrangements that are traded reflect assessments of wholesale market outcomes, which in turn influence the type of generation investment favoured by investors. Traditionally, wholesale market outcomes have reflected patterns of market demand and supply and related trends in average and peak wholesale prices. This in turn has some influence on investment trends The data on OTC volumes included here has been sourced from the Australian Financial Markets Association (AFMA), who conducts a survey of market participants to determine OTC volumes and values. While this survey is managed by AFMA to check integrity of reported volumes, its accuracy cannot be verified in the same way as futures and options volumes, for which information is available through the central clearing mechanism of the Australian stock exchange. 15 For example, participants who are considering investment in high capital cost baseload units are likely to consider whether there is sufficient market demand for baseload swap contracts with a strike price that will allow them to recover their long run average costs. Market demand for contracts at this price in turn depends upon the expected level of, and fluctuation in, wholesale prices and the cost exposure faced by participants if they remain unhedged. 19

20 Figure 2.16 highlights overall investment trends in the NEM over the previous 10 years. Of these, the most noticeable trend is the relatively low levels of investment in baseload coal fired generation as opposed to gas fired generation and wind generation. Figure 2.17 provides another representation, showing a clear decrease in black and brown coal fired generation as a percentage of total capacity and an increase in gas and wind. 16 This trend has been partly influenced by the previous exploitation of resources on the east coast of Australia. For example, during the 1970s and 1980s, significant volumes of black and brown coal fired baseload generation investment took place to take advantage of cheap coal resources. The extent of this investment provided a relative surplus of baseload capacity at NEM commencement, contributing to reduced levels of demand and investment in new coal-fired baseload generation to date. This kind of investment pattern is expected; construction of additional coal fired baseload generation in the presence of a relative baseload surplus would not be an efficient outcome. Figure 2.16: Investment since market start Source: AER, State of the energy market 2011 Other factors may also influence this trend. As discussed in further detail later in this paper, market uncertainty around the introduction of a carbon price mechanism is likely to have reduced appetite for investment in carbon intensive generation. Conversely, there is a greater appetite for investment in lower emissions intensity gas fired generation. Similarly, the introduction of various subsidy schemes for renewable and gas fired generation 17 has led to a marked increase in levels of investment in these technologies Noting that this figure refers to installed capacity; coal fired generation continues to meet almost 80% of Australia s energy demand. 17 For example, the Queensland Gas scheme requires retailers to source a prescribed percentage of their electricity from gas fired generation. More information is available here: 18 For further information on key generation investment trends, see AEMO, 2011 Electricity Statement of Opportunities, August Available at 20

21 Figure 2.17: Installed capacity by fuel source 2000 to 2011 Source: AEMO, 2011 Electricity Statement of Opportunities, p The formation of the NEM The interconnected power system and the wholesale market mechanisms which comprise the NEM are the product of conscious design and careful implementation. The process of creating an integrated market capable of supplying secure and reliable electricity is likely to be of some interest in those international jurisdictions currently considering the integration of multiple power systems. Since its commencement, the NEM has effectively met its statutory objective of serving the long term interests of consumers by delivering reliable, safe and secure energy. While the process of development is ongoing, the creation of this large and complex interconnected system provides a useful example of how separate power systems and markets can be effectively integrated to deliver net benefits for consumers. The process of market integration was made possible through the co-ordinated development of overarching policy reform processes and co-operation between the various levels of Australia s federal political system. It also involved careful consideration of the physical realities of the power system itself, as linking the many load and generation centres required skilled management. To provide context, prior to the 1990s, provision of electricity in each of the eastern seaboard states of Australia was the responsibility of vertically integrated jurisdictional public utilities. Each of these utilities had sole responsibility for the generation, transmission, distribution and, in some cases, retailing of electricity to customers in each jurisdiction. Each vertically integrated utility co-ordinated the dispatch of generation through a centralised process. However, interconnected utilities did engage in marginal cost sharing, a co-operative process which involved the manual selection of the lowest cost generation between regions and dispatching these generators accordingly. While this process did not have the price discovery capabilities of market-based exchange mechanisms, it nevertheless recognised the major cost savings available through inter-regional connection and resource sharing. 21

22 The initial rationale for integrating these separate jurisdictional systems has its origins in a series of policy reviews conducted by the Australian commonwealth government in the late 1980s. At that time, the commonwealth Industry Commission undertook a study examining the potential for a single, national transmission system to contribute to national productivity growth. Subsequent to these policy reviews, the development of the National Competition Policy (NCP) reform agenda added a degree of impetus to the development of a single national electricity market. This reform process, developed throughout the early to mid-1990s, included a wide range of issues and specific programmes but generally sought to introduce competition as a driver of productivity gains in a range of industries which had previously been closed to the private sector. In regards to the energy industry, a primary focus was the introduction of competitive neutrality by extending trade practice law to state owned businesses and allowing private sector entry into a previously state controlled industry. This in turn necessitated the development of effective access regimes and market mechanisms to facilitate trade. The National Grid Management Council (NGMC) was established in The NGMC was tasked with developing open access to the eastern and southern Australian grid and encouraging free trade in bulk electricity for generating companies, public utilities and private and public energy customers. In 1992, the NGMC produced a national grid protocol (NGP) which established a set of rules, responsibilities and technical requirements for connecting to the national grid and participating in trade of bulk electricity. While initially limited to generators and large customers, the NGP established an initial framework for the development of a single national market. The NGMC also oversaw a number of test market trials, which were operated by the various vertically integrated utilities in each of the jurisdictions. These trials were designed to determine how an efficient dispatch process might be managed through a market mechanism. As these reforms were progressed, many of the state based power systems went through processes of major structural readjustment. For example, in 1993 the Victorian government began the vertical disaggregation of its single electricity utility, splitting generation from transmission and then splitting the generation business into smaller entities. Stapled retail and distribution businesses were also created by splitting these businesses from transmission. This was followed by privatisation of the generation assets and the stapled distribution / retail businesses. Similar restructuring processes took place in other states, although this did not necessarily proceed to privatisation in all cases. Through 1996, NSW and Victoria developed a market mechanism to facilitate dispatch. This precursor of the NEM, known as NEM1, allowed participants to trade energy within and between their respective jurisdictions. NEM1 began operating as a live market in In 1998, the NEM itself came into operation, under a national electricity code which established its functions and operations. At that time only NSW, SA and Vic were 22

23 physically interconnected; while the national electricity code covered Qld, that state operated as an isolated region of the NEM. Physical interconnection between Qld and the rest of the NEM occurred in 2000 and 2001 with the construction of the Terranora DC interconnector and QNI AC interconnector, respectively. A similar process was adopted for the integration of Tasmania into the NEM, which became a part of the NEM in 2005 but was not physically interconnected until 2006 with the formal commencement of operation of the Basslink DC interconnector. The development of the NEM has been influenced by the physical realities around which the original jurisdictional systems were developed. For example, the regional nature of the NEM reflects these underlying physical characteristics; spot prices in the NEM continue to be calculated on a regional basis, reflecting the nature of inter and intra-regional networks and the distribution of generation and load. Similarly, a key area of ongoing policy discussion relates to the interconnection of the various NEM regions, including how this interconnection is planned, managed and paid for. Price difference between the various regions is another area of review and development, particularly in relation to the impact of transmission interconnection on these differences. 3. A changing policy environment The establishment of the NEM was part of a series of multi-sectoral and multijurisdictional processes which required the co-ordination economic reform policies with the careful development of market specific frameworks. This process occurred over a number of years but in a consistent and coordinated direction. This approach continues to be essential as the NEM responds to new policy reform processes. As a well-designed and robust market mechanism, the NEM is capable of delivering the outcomes of these reforms, provided that the policies themselves are carefully designed and implemented New policies affecting the NEM Perhaps the most obvious set of new demands being placed on the NEM are the various climate change policies. These policies include: Enhanced Renewable Energy Target (enhanced RET): This policy mechanism is designed to ensure that 20% of Australia s energy consumption in 2020 is produced from renewable resources. This target is currently set at a total of 45,000GWh by 2020 and will remain at this level until 2030, at which point it will conclude. The enhanced RET consists of two separate mechanisms, the Large-scale Renewable Energy Target (LRET) and the Small-scale Renewable Energy Scheme (SRES). Both of these schemes allow for the creation of certificates equivalent to a volume of energy produced from renewable resources: the LRET consists of large scale generation certificates (LGCs), while the SRES consists of small scale technology certificates (STCs). Collectively, these certificates are referred to as renewable energy certificates (RECs). Retailers are required to acquire 23

24 and surrender a volume of RECs in proportion to the level of their customers consumption. The LRET is currently driving large volumes of wind investment, as firms seek to take advantage of the most mature technology available in order to maximise potential revenue from the scheme. In Australia, the southern states of Tasmania, Victoria and South Australia have seen significant volumes of wind entry due to the RET and it is likely that New South Wales will see similar increases in coming years. The SRES, in conjunction with various jurisdictional subsidies, is helping to drive significant volumes of small scale solar PV investment and other small scale energy measures. 19 Clean Energy Future policy package (carbon price mechanism): The federal government has introduced a carbon pricing mechanism which will come into effect on July Initially, the Clean Energy Future policy package will put a price of $23 per tonne on carbon dioxide and a range of equivalent gasses, rising by 2.5% per year until On 1 July 2015, this will transition to a flexible market determined price per tonne of CO 2 e-. Some international linking will be allowed once the fully flexible price is introduced and a price ceiling and floor will apply for the first three years of the flexible price period. Importantly, the carbon pricing mechanism will apply to all sectors of the Australian economy, creating liabilities for a wide range of large emissions intensive producers. The stationary energy sector will be particularly affected by the scheme as it is responsible for around 51% of Australia s total domestic emissions, with electricity generation being the primary contributor to the emissions intensity of the sector. 20 The carbon pricing mechanism is creating some uncertainty in the stationary energy sector, as many participants are unclear as to the effects of the scheme, or whether the scheme itself will survive a change in government. These effects are discussed in more detail below. Specific subsidies: A wide range of schemes have been introduced by the federal and state governments to achieve particular environmental outcomes. These include small customer solar feed in tariff schemes in the various state jurisdictions, subsidies designed to encourage uptake of gas fired generation and energy efficiency schemes which mandate minimum energy consumption standards for appliances and buildings. 21 Some market based 19 The AEMC has undertaken a detailed analysis of the impact of the enhanced RET on energy markets. Further information can be found at: 20 The stationary energy sector accounted for more than 51 per cent of Australia s total domestic emissions in 2009 at 295 Mt CO2-e. Electricity generation accounts for the largest proportion of stationary energy emissions, projected to average 203 Mt CO2-e per year over the Kyoto period and to be 213 Mt CO2-e in Further information can be found at:

25 energy efficiency schemes have also been developed for specific large energy users. 22 Some of these policies have seen larger than expected levels of uptake; in some cases this has required amendment or cancellation of schemes. For example, the NSW Solar Bonus scheme was reduced and then cancelled due to larger than expected uptake and subsequent cost increases. 23 This scheme originally offered a feed in tariff to small customers of 60 C /KWh for electricity produced by rooftop solar PV units, almost three times the regulated electricity retail tariff of 22 C /KWh. 24 Expressed another way, this gross feed in tariff equated to a payment of approximately $600/MWh, around 13 times the volume weighted average wholesale price of $45/MWh in NSW during The NSW Independent Pricing and Regulatory Tribunal (IPART) has recommended the introduction of a feed in tariff which is substantially lower than the regulated electricity retail price, recognising the various costs associated with supporting these schemes. 25 IPART have recommended the introduction of a feed in tariff of between 5.2 to 10.3 C /kwh. These policies will have profound effects. In some cases, these are already occurring, as policies such as the enhanced RET drive significant changes in the generation mix. Other policies, such as the Clean Energy Future package, have not formally commenced. However, their effects are already being felt, as levels of uncertainty impact on the funding, investment and operational decisions of many participants Integration of new technology types To date, a key aspect of the NEM frameworks has been a commitment to technology neutrality. 26 Technology neutrality means that investors are unlikely to select new renewable technologies on their own merit, as in many cases they are currently more expensive than fossil fuel generation such as black and brown coal. 22 The Australian Productivity Commission has carried out extensive analysis of emission reduction policies in various international economies. This study includes a detailed review of the range of subsidies and energy efficiency schemes in place in Australia. For more information refer to Appendix P of this report. Available at 23 data/assets/pdf_file/0007/386926/nsw-govt-places-hold-onsolar-bonus-scheme.pdf 24 Energy Australia, Residential Customer Price List, accessed 20 April Available at: data/assets/pdf_file/0010/33121/nsw_res_pl_2011b.p df 25 IPART, Solar feed in tariffs: Setting a fair and reasonable value for electricity generated by small-scale solar PV units in NSW, March Available at: 26 Clause of the national electricity rules states that a key market principle of market design is avoidance of any special treatment in respect of different technologies used by market participants. 25

26 The introduction of policies such as the Clean Energy Future policy package, the enhanced RET and the various subsidy schemes are designed to influence this process of market selection. This may be achieved by providing support to specific technology types in order to make them more competitive in the marketplace. Alternatively, the internalisation of formerly external costs is intended to make particular technologies comparatively more expensive and less competitive in the market; for example, a carbon price mechanism is intended to internalise the environmental cost of carbon dioxide. The end effect of either mechanism is to change the costs that are faced by different types of generator. These changed costs are factored into the bidding behaviour of generators, which may in turn change the overall pattern of dispatch. While existing market mechanisms are capable of incorporating renewable technologies in this way, there are a number of consequences associated with the entry of large volumes of renewables. This reflects the fact that the generation and revenue profiles of renewables are markedly different to the generation types that have previously been selected by the market. While the challenges posed by the integration of these new technology types are by no means insurmountable, they will require some creative thinking to resolve. A number of specific policies are driving these significant changes to Australia s stationary energy sector. The impacts of these policies are described in further detail below The enhanced RET and wholesale price impacts As described above, the purpose of the enhanced RET is to encourage investment in renewable generation, with the aim of sourcing 20% of Australia s projected energy consumption in 2020 from renewable resources. The enhanced RET consists of a large scale and small scale component (the LRET and SRES respectively), which are designed to support different technology types. Wind generation is likely to be the primary generation type utilised in delivering the large scale LRET target of 41,000GWh of renewable energy by This is because, at present, it is the cheapest and most mature renewable generation technology. While other forms of renewables are available, they are either constrained by fuel resource availability (biofuel renewables), are less mature (geothermal) or more expensive (solar thermal and solar PV). Figure 3.1 provides an indication of the relative levelised costs of electricity costs for renewables in Australia. Given the cost of wind and its relative maturity, as well as the limited time scale of the RET, it is likely that investors will seek to maximise possible revenue by building wind generation early on in the scheme. 26

27 Figure 3.1: Levelised cost of electricity for renewables in Australia Source: Electric Power Research Institute, Australian Electricity Generation Technology Costs Reference Case 2010, report to the Australian government Department of Resources Energy and Tourism, February The scale of potential new wind generation entry in the NEM is substantial. AEMO have reviewed the total number of new projects (renewables and non-renewables) in varying stages of development and have determined that of the 31,500MW of potential capacity that may be installed by 2020, approximately 14,300MW, or 45%, is wind generation. 27 Wind generation currently makes up around 3.5% of total installed capacity (measured in total MW installed), and supplies around 2.7% of the total energy produced in the NEM. 28 Those jurisdictions of the NEM with particularly favourable wind resources have seen significantly higher volumes of wind generation entry. In SA, wind generators make up around 20% of total MW installed capacity. 29 Around 22% of the total energy generated in SA for the year ending June 2010 was produced by wind generation These figures are based on a list of all projects which are at varying stages of development. For example, some of the projects listed have been publicly announced but have not yet acquired land, equipment, finance, planning approval or set a date for construction. Accordingly, these projects represent the outer bound of likely investment in new capacity. Further information can be found at 28 Energy Supply Association of Australia, Electricity Gas Australia 2011, pp Note that this figure refers to total installed capacity, including scheduled, semi scheduled and nonscheduled generation. Consideration of only large scale scheduled and semi-scheduled wind generation reduces this figure to 11% of total installed capacity. 30 Energy Supply Association of Australia, Electricity Gas Australia 2011, pp It should be noted that these figures do not distinguish between how energy was consumed that is, whether energy was consumed domestically in SA or exported to other regions. For example, while total SA energy generation was 14,620GWh in the year ending July 2010, total SA consumption was 12,896MW. 27

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