Energy Information Administration
Contents
Introduction
Creation of The National Electricity Market
Implementation
- The National Electricity Code
Buying
Electricity in the National Market
Electricity
Reform at the State and Territory Levels
Reforms in Price
Regulation
Privatization
and Reform Outcomes
Prior to the reforms of recent years, the supply of electricity in Australia was provided by vertically-integrated, publicly-owned state utilities meeting the needs of individual states and territories. 1 The electricity industry had never operated on a national basis. Interstate grid connections were weak and electricity trade had been limited between the interconnected states. 2 The state governments were responsible for operational and planning activities, and tariff structures. The National Commonwealth government's only involvement in the industry was through its principle shareholder status in the Snowy Mountains Hydro-electric Scheme in which the two states of Victoria and New South Wales also hold shares. Some regulatory controls by the Commonwealth were exercised, however--mainly through control over state borrowing limits, taxation, foreign ownership, and environmental regulations. 3
In 1995, Australia's population of 18 million was roughly one third that of the United Kingdom and half of Argentina's population. Australia's landmass totals almost three million square miles, almost double the size of Argentina and nearly thirty times the size of the United Kingdom. However, the majority of the population is concentrated in three states (New South Wales, Victoria, and Queensland) located in the eastern portion of the country ( Table 14 ). Consequently, these three states account for most of Australia's electricity industry. Per capita electricity consumption in Australia is roughly ten times that of Argentina and more than twice that of the United Kingdom. In 1995, Australia's electricity generation was 160 million kilowatts per hour ( Table 15 ). Australia's two most populous states New South Wales and Victoria accounted for 35 percent and 23 percent, respectively, of total domestic electricity consumption ( Table 14 and Table 15 ). 4 Electricity generation was provided primarily through coal-fired power stations, which represented about 80 percent of the total fuel usage. The remaining 20 percent of electricity generation is fueled through a combination of natural gas and hydroelectricity. Nuclear power plants have never been used for electricity generation. 5
Unlike the situation in the United Kingdom (UK), electricity reform and privatization in Australia have occurred at both the state and national levels. Although the Australian and U.S. electricity industries are in many ways very different, Australia's dual path to electricity reform bears some similarities to current developments in U.S. electricity markets. One result of Australia's dual state/national approach to electricity reform is that each state has pursued different reforms with reform efforts at the national level providing more guidance than direction. Reform at the state level differs from UK reform, which was entirely a central government effort. These distinctions are noted below. Victoria has pursued the most aggressive electricity reform measures in Australia and has most closely followed the UK model, while other states have pursued various degrees of more limited reform.
At the national level, Australia's electricity reform also differs significantly from the UK model in the operation of the national electricity pool, in the authority of the national electricity regulator, and the level of regional control. In other ways, national reforms have been quite similar to those of the United Kingdom. Australian governments have generally split up their electrical industries along functional lines, with the state of Victoria adopting the UK model's separation of electricity into four segments. A national grid and national pool are currently operating and are expected to be further developed. The new national regulatory regime is to be "light handed" and a form of price regulation (intended to promote efficiency) will be applied to the regulated sectors.
The privatization of energy is a recent, but internationally widespread, trend which has placed greater reliance on market forces and less dependence on government in the allocation of resources. Australia's electricity industry is part of this trend as state government involvement in and ownership of this industry has moved toward corporatization and privatization since 1995. The "over-capitalized investments" 6 made by the state governments in the electricity sector (generation capacity, transmission systems, and distribution) had resulted in "high levels of reserve plant margins combined with high debt levels with minimum returns." 7 Monetary restraints and debt placed pressures on the federal and state governments to reduce expenditures and increase efficiency while still providing service for the public. 8
The objective of reform in Australia was to "deliver more efficient and sustainable use of capital infrastructure and energy resources and to improve Australia's domestic and international economic performance." 9 To achieve these objectives, the government considered competition the most effective tool. In addition, the state governments estimated that electricity reform would add an estimated $5.0 billion annually 10 to the Australian Gross Domestic Product. 11
The electricity reform effort has been underway since 1991, when the various state and territorial governments agreed to work cooperatively to introduce a competitive electricity market in the southern and eastern regions of Australia.
At a special conference in November of 1990, the Industry Commission (a federal statutory body whose main objective was to improve the efficiency of the Australian economy) was appointed by the Commonwealth to review the electricity industry and discuss the feasibility of a national electricity grid. The Industry Commission recommended reforms that would eventually lead to the privatization of the electricity market. These reforms included: unbundling the electricity industry into separate generation, transmission, distribution sectors; privatizing and corporatizing the separate (but still state-owned) electricity transmission and distribution sectors; introducing competition into the generation sector; combining the state-owned transmission units into a single national grid; and restricting transmission and distribution businesses to the transport of electricity. In addition, the Industry Commission recommended that after privatization, tariffs should be reflective of actual costs, and cross-subsidies (from urban to rural consumers) should be eliminated. 12 Six months later, the Commonwealth, state and territorial heads of government established the National Grid Management Council as an intergovernmental advisory body to develop the National Electricity Code in consultation with industry, stake-holders, and the public. 13
In October 1994, the National Grid Management Council prepared the first draft of the national electricity market report entitled "Restructuring of the Electricity Supply Industry in Australia." This report addressed the broad objectives for the proposed national electricity market, as well as the different types of trading arrangements to be provided, how it would operate, and how its security would be maintained. The report's recommendations were endorsed by each of the state governments and the Australian Capital Territory. In September 1995, the National Grid Management Council prepared a second report that outlined the market functions of the proposed national electricity market. The National Electricity Code (the Code) establishes the rules and procedures for operating in the competitive national electricity market. The Code was completed in September 1996 and was sent to the Australian Competition and Consumer Commission for approval in November 1996. 14
A further impetus to reform was the release of the 1993 National Competition Policy Review, known as the Hilmer Commission Report. The report identified industries where reform could yield substantial benefits to Australia's economy. Electricity was one of these industries. In April 1995, the Council of Australian Governments agreed to a national competition policy reform, the National Competition Reform Act of 1995, which provides for uniform protection of consumer and business rights and increased competition in all jurisdictions. This policy would also enhance the national economic interest by improving Australia's international competitiveness, as well as encourage competition in the trading activities of government-owned enterprises.
As part of the reform package, the Commonwealth agreed to provide financial assistance payments to the states and territories totaling $4.2 billion Australian dollars 15 in return for the states meeting their agreed obligations, including the reform of their electricity, gas, water, and road transport industries. 16
As specified, the objectives of the competitive national electricity market are:
The Australian national electricity market (NEM) is to develop in stages until a fully competitive market for electrical generation and retail supply is achieved by 2001. Although it is referred to as a national market, NEM will initially include the states of Victoria, New South Wales, South Australia, Queensland, and the Australian Capital Territory, with the possibility of an expansion into Tasmania following its grid interconnection. Western Australia and the Northern Territory will not participate in the market due to geographical and cost factors. Victoria, New South Wales, and the Australian Capital Territory are currently operating in a transitional phase of the national electricity market (NEM1). South Australia will enter the market in 1998 and Queensland is scheduled to connect to the national grid by 2001.
The first phase of the NEM was scheduled for 1995 (covering New South Wales, Victoria, and the Australian Capital Territory), but the actual startup of phase 1 began on May 5, 1997. A national electricity generation pool was introduced when Victoria and New South Wales began an interstate wholesale electricity trading market, with the Australian Capital Territory participating in the linked market through New South Wales. In this market, the states still operate under a separate wholesale power pool but generators compete directly with each other (see the section entitled "National Australian Power Pool" for a discussion on the operation and structure of the new national power pool). When less expensive electricity is available in one state (e.g., Victoria), the pool allows another state (e.g., New South Wales) to import this cheaper electricity. The new power pool is intended to create a national electricity market in Australia.
Before the national electricity market can become fully operational in the southern and eastern regions of Australia, three main transmission links need to be built to interconnect these regions to form a national electricity grid. 18 Currently, the states of New South Wales, Victoria, South Australia, and the Australian Capital Territory (ACT) are connected to form a grid network. However, each government grid is not directly connected to the other state grids; instead, they are all linked together via Victoria. The grids of Victoria and New South Wales are linked with a maximum transfer capability of 1,100 megawatts (with the largest capacity transmission net-work running through the Snowy Mountains Hydro-electric Scheme). Victoria and South Australia are linked with a total transfer capability of 500 megawatts. 19 The ACT does not generate electricity; it imports its electricity from New South Wales. In 1995, interstate flows of electricity represented on average less than 2 percent of total electricity consumed within the states mentioned above (excluding ACT).
The three main links that must be built to interconnect the southern and eastern regions of Australia to form a national grid are (1) New South Wales and South Australia, (2) New South Wales and Queensland, and (3) a sub-sea link between Victoria and Tasmania with a 300-megawatt interconnection after the year 2000. In 1993, a feasibility study to evaluate the economic and environmental implications of the Victoria to Tasmania sub-sea link was both initiated and completed. In 1996, similar feasibility studies were initiated for the other two necessary grid links. In 1997, New South Wales and Queensland announced their intentions to build the actual link interconnecting their two states by 2001. 20 As of early 1997, the remaining feasibility study was still in progress. 21
The introduction of a national electricity market will change the structure, operation, and regulations of the traditional Australian electricity industry. The expected changes include:
The National Electricity Code ("the Code") establishes the regulatory and operational framework of the new Australian national electricity market and binds all participants in the wholesale power generation market to the specified rules. 23
The Code addresses the following: market rules; grid connection and access; metering; network pricing (transmission and distribution); and system security and procedures for Code administration. The Code also contains a chapter on transitional matters which specifies permissible short-term deviations from the Code and the transitional paths that will be adopted by the participating state jurisdictions to reach conformity by the end of the transition phase. The Code is not legislation enacted by the Australian national government. However, it is binding on all market participants. In addition, the Code also outlines the objectives, roles, and functions of two new national regulatory bodies, the National Electricity Market Management Company (NEMMCO) and the National Electricity Code Administrator Limited. These bodies were established by the participants of the national electricity market (state and territory governments). The Code must be submitted to the Australian Competition and Consumer Commission (ACCC) for approval before it can be implemented. In addition, changes in the Code can be made only with the approval of the ACCC. In November 1996, the Code was submitted to the ACCC, with approval expected in late 1997. 24
There are four groups who will participate in the wholesale power generation market. These groups are required to become participant members of the National Electricity Code Administrator Limited and are subject to all the Code rules. The first group is comprised of market participants (contestable customers, generators, marketers, and brokers). Initially, only contestable customers a consumer with an annual electricity consumption of at least 10 megawatts will be eligible to participate in the market. However, as the market matures, all customers will eventually have the option to participate because eligibility requirements will be reduced. All generators with a net export in excess of 30 megawatts are required to participate in the wholesale power generation market. 25 Smaller generators can also participate on a voluntary basis. The other three groups are NEMMCO, network service providers (transmission and distribution), and regional system operators ( Figure 9 ).
The national electricity market will offer a range of options to suit the specific needs of electricity buyers and sellers. Contestable customers have two options: (1) participate in the wholesale market, or (2) participate in the retail market. If the contestable customer decides to participate in the retail market, all of their electricity will be supplied through a marketer and they can not participate in the wholesale market. On the other hand, if the contestable customer chooses to trade in the wholesale market they must register as a participant with the NEMMCO.
Wholesale Trading Market. In the wholesale trading market there will be three levels of trading: via a long-term bilateral contract; via a short-term forward market; and via a spot trading market. Participants in the wholesale market can operate in any combination of these markets. All wholesale electricity trading will be accounted for through the pool. For example, electricity provided to the network from wholesale suppliers (generators) and electricity taken from the network by contestable customers and marketers will be recorded. Marketers will participate in the wholesale market on behalf of those contestable customers who have made a decision not to participate in the wholesale market or who have not met the megawatt eligibility requirements to participate in the wholesale market. In the wholesale environment, electricity buyers could be both end-use customers as well as marketers. Sellers of electricity could be generators as well as marketers.
Although each form of trading operates independently, the operations and results in each trading market affect the others. For example, when a contestable customer has a long-term contract with a generator, it can operate its business in a secure environment knowing that their costs are fixed for electricity generation. In addition, long-term contracting provides the foundation for contestable customers to make long-term plans. On the other hand, short-term forward trading allows the contestable customer to make changes to its contract coverage one or two days before actual trading begins, in turn, giving the customer the flexibility of purchasing more electricity at less expensive prices. Spot trading is a vehicle that is used to balance supply and demand in half-hour increments (in Australia) and establish the price of electricity at that specific time. 26
Retail Trading Opting Out Of The Pool. In addition to the wholesale trading arrangements described above, contestable customers have the choice to purchase electricity under a retail contract and thereby forfeit the opportunity to participate in the pool (perhaps due to risk). Under retail trading, the buyer and seller can enter into any type of contractual arrangement and are not bound to restrictions like those of the wholesale trading market. Customers have the opportunity to negotiate competitive contracts with the marketer of their choice, thereby adding competitive pressure on suppliers for better service and lower prices. In a typical contract, the marketer would pay for the customer's electricity usage and network charges and, in turn, would charge the customer for these services. Prices for network service payments and energy payments would be unbundled in the bill. These charges would look similar to traditional tariff arrangements; however, the payment under the retail contract would reflect competitively-determined prices. 27
Since low-cost coal is relatively abundant, total generating capacity in the Australian electricity industry is dominated by large coal-fired power stations. Even though fuel usage varies from state to state (depending on the availability of natural energy resources), coal is the dominant fuel source, accounting for 80 percent of primary energy consumption ( Table 16 ). The state of Tasmania is the exception, where electricity generation is mostly fueled through hydroelectric power.
In the past, electricity generation in Australia was developed independently by the individual states on a need basis (the Australian Capital Territory, however, does not generate its own electricity). Total generation capacity varies among individual states and territories. For example, the states of Victoria, New South Wales, and Queensland account for a substantial majority of Australia's total electricity consumption. However, in the national electricity market, states will no longer supply electricity to customers directly in their respective states, but will participate in the national power pool.
The Australian electricity industry has implemented significant reforms in preparation for their eventual entry into the national electricity market. Although some states will not participate in the market, they have implemented reforms where possible to gain efficiencies to supply customers and generators. Each state government has made different arrangements (and adopted different time schedules) for separating the segments of their electricity industries for entrance into the national competitive market. The state of Victoria is the first and most advanced in its reform in the electricity sector compared to reform in the other states and the single territory (the Australian Capital Territory) that are participating in the national electricity market.
In October 1993, the state of Victoria began its reform with the separation of the electricity system. The State Electricity Commission of Victoria was vertically separated into three segments: generation, distribution, and transmission. In 1994, only a year later, Victoria restructured its state-owned electricity industry further with the intention of privatizing it ( Figure 10 ). The generation sector was divided into 5 companies, and the Victorian Power Exchange was established to operate the wholesale power generation market. The former 29 electricity distribution companies were restructured into 5 companies. 28 The transmission sector was divided into two components: PowerNet Victoria owns the high voltage transmission grid network and was made responsible for its maintenance; and the Victorian Power Exchange was made responsible for pool operations and system dispatch. In addition, the Office of the Regulator General was created to promote competition in the generation and marketing sectors; to maintain an efficient and economic system; and to protect the rights of customers. 29
Victoria permitted each of the five distribution companies to retain monopoly rights to supply power to customers in their respective geographic regions. However, in 1996 (in an attempt to introduce competition into what was still a state-owned system), large users (the contestable customers) were free to purchase electricity from any of the five distribution companies. The current monopolies that the five distribution companies have to supply electricity to noncontestable customers will be phased out by December 2000. In December 2000, all customers in Victoria will be contestable. 30
In 1995, Victoria began the privatization of its electricity assets ( Table 17 ). Since launching its privatization program, the state has generated almost $16 billion in revenue, an amount which is mostly being used to repay state government debt.
Through the auction process, Victoria sold off all of its five electric power distribution companies (United Energy, Solaris Power, Eastern Energy, Powercor, and Citipower) in 1995 ( Table 17 ). Companies from the United States, and their consortia, led the way in purchasing these plants.
Victoria pursued a markedly different approach to privatizing its electricity industry than that undertaken in the United Kingdom. In contrast to the United Kingdom (where electricity assets were sold at prices set by the national government), Victoria conducted a series of staggered auctions of its five electricity distribution companies and its four generation companies being privatized. Furthermore, all of the distribution and generation companies were sold intact, and to other companies or consortia of companies. No restrictions were placed on foreign investors.
In the end, all of the newly-privatized Victorian electricity companies were, at least in part, purchased by U.S. and UK utilities. As a consequence, corporate control over these companies was concentrated in no more than a handful of companies, unlike in the United Kingdom where, at least initially, the new shareholders were exclusively portfolio investors. In all cases a premium was paid for shares in the newly-privatized Victorian electric companies. The Victorian treasury benefited fully from these premiums.
Interestingly, the pattern of the disposal of Victoria's electricity assets bears some resemblance to current electric utility restructurings in the United States. A case in point is the recently announced intention of New England Power (a wholly-owned subsidiary of New England Electric) to sell its electricity generation units intact to Pacific Gas and Electric. Apparently, maximum value was achieved via a transfer of corporate control to Pacific Gas and Electric. The divestiture could have been undertaken via a leveraged buyout, or via the creation of a new generation company and a distribution of shares in this company to New England Electric shareholders.
The first distribution company to be sold (United Energy) was purchased by UtiliCorp United (a U.S. company), and its Australian partners 31 for $1.2 billion. 32 Initial bidders on the plant were Pacific Gas and Electric, (a U.S. utility), the French government-owned Electricite de France, and Scottish Power (a United Kingdom company). However, the latter two withdrew from the bidding process. 33 The second distribution company, Solaris Power, was sold to Energy Initiatives (a subsidiary of General Public Utilities, a U.S. company) and the Australian Gas Light Company for $713 million 34 plus an additional $110 million in franchise fees. 35 Texas Utilities (a U.S. company) purchased Eastern Energy for $1.6 billion 36 in November 1995. Two other groups (Pacific Gas and Electric and PacifiCorp, both U.S. companies), as well an Australian consortium bid on the plant. In November 1995, PacifiCorp won the bid for Powercor for $1.6 billion. The fifth distribution company, Citipower, was sold in January 1996 to Entergy (a U.S. company) for $1.2 billion. 37
Between late 1992 and 1997, Victoria sold its four electric power generating plants ( Table 17 ). In December 1992, Victoria began its private sector involvement in the generation sector with the 51-percent sale of its Loy Yang B power station to the U.S.-based Edison International's Mission Energy Company for $2.4 billion, with the agreement that the government would purchase the station's electricity over the life of the plant. Almost five years later, in May of 1997, Edison Mission Energy purchased the remaining stake in the Loy Yang B power station for $66 million thus terminating Victoria's take-or-pay contract with the company. The trmination of this contract has enabled Victoria to further reduce its future state debt. 38
A second generation company, Yallourn-W, was sold in March 1996 to PowerGen PLC (of the United Kingdom) for $1.8 billion. 39 PowerGen PLC outbid several U.S. companies. 40 In August 1996, the Victorian government sold the Hazelwood coal-fired plant and coal mine for $1.9 billion to a group led by National Power PLC of the United Kingdom. National Power PLC purchased a 51.9-percent interest. Others in the consortium included U.S.-based PacifiCorp (a 19.9-percent interest), U.S.-based Destec (a 20-percent interest), and the Commonwealth Bank Group of Australia (an 8.2-percent interest). 41
In May 1997, Victoria sold another power plant (the Loy Yang A coal-fired power station) and a coal mine. This was the largest energy asset privatization in Australian history. The Loy Yang A has the largest coal mine in Australia and is the lowest-cost electricity generator in Victoria, comprising 35 percent of the state's electric supply. 42 A group led by the U.S. company CMS Energy (50-percent interest) won the bid in May 1997 for $3.7 billion. Other partners in the consortium were NRG Energy (a subsidiary of Northern States Power of the United States) and Horizon Energy Australia, which each purchased a 25-percent interest. 43 Other assets in Victoria scheduled for privatization include the Newport and Jeeralang gas-fired power plants, and Victoria's 29-percent interest in the Snowy Mountains Hydro-electric Scheme. 44 PowerNet Victoria Transmission, the owner of the state's high-voltage electricity transmission grid, is expected to be sold in late 1997. 45
Victoria also announced that it will privatize its state-owned gas utility. The utility will be separated into two or three distribution businesses and its retail sector will be divided into two or five businesses. The state's gas pipelines, Gas Transmission Company, will be sold as a single company.
In contrast to Victoria, New South Wales (the most populous of the Australian states ( Table 14 )) has not privatized its electricity industry. Instead, it unbundled the industry into corporatized state-owned entities. Reforms in New South Wales have focused on the separation of the Electricity Commission of New South Wales' generation and transmission corporations. In August 1991, the Electricity Commission of New South Wales was renamed Pacific Power and was restructured internally into six smaller business units. Pacific Power's total generating capacity is 11,512 megawatts, excluding the Snowy Mountains Hydro-electric Scheme's generation, and contributes 32 percent to Australia's generation capacity. In 1994, Pacific Power's electricity transmission network business unit was established as a separate legal entity. The Electricity Transmission Authority was separated from Pacific Power in February 1995 and was formed as a separate state-owned corporation now called Trans Grid ( Figure 11 ) . The management, operation, and maintenance of the state's high voltage transmission grid is the responsibility of TransGrid. 46 In October 1995, the previous 25 distribution boards were aggregated into six businesses and were later corporatized in March 1996 ( Table 18 ).
The New South Wales interim wholesale market began in March 1996 and became fully operational in May 1996. The market is regulated by the Independent Pricing and Regulatory Tribunal, and Transgrid operates the state's power pool. 47 In July 1997, customers with energy consumption of 750 megawatts per year became eligible to choose their electricity marketer. This eligibility requirement brings the state in line with Victoria's eligibility requirements, which have existed since 1996.
The state government initially declared it would not privatize its electricity assets to compete in the national market but would continue to maintain ownership of electricity assets. However, in May 1997, the New South Wales treasurer, Michael Egan, recanted this decision and announced his intentions to privatize all of the state's electricity assets. This new decision is expected to face opposition within the state's ruling Labor Party as well as in the labor unions. The proposed privatization would generate an estimated $22 billion dollars in revenue, 48 which would be used to retire government debt. 49 All of the assets would be auctioned off without restrictions excluding Pacific Power, which would be sold with a retained Australian majority ownership interest. 50 So far, only three privately-owned projects have been initiated. In December 1995, Sithe Energies (a U.S.-based independent power producer which is 29-percent owned by the Japanese company Marubeni) and Broken Hill Proprietary (Australian-owned) began the construction of a 175-megawatt cogeneration plant at Smithfield (near Sydney, Australia), 51 with commercial operations to begin in 1997. 52 Energy Developments Limited is involved in a small-scale (4-megawatt) gas-fired power generation plant, and a proposed 90-megawatt coal steam methane power plant. 53
A consortium consisting of Air Liquide Australia Ltd, Itochu Corporation (a Japanese company), and Energy Australia (New South Wales' electricity distributor) was formed in 1995 to develop a 350-megawatt congeneration plant in Sydney. However, Energy Australia announced in 1997 that it would sell its interest in the project, citing that the company's long-term strategic objectives have changed due to its experience with the first stages of deregulation in the national electricity market. The company's 20-percent interest in the project will be sold to Itochu Corporation. 54
The Australian Capital Territory (ACT) consists of Canberra and a number of surrounding areas. The ACT corporatized 55 its combined electricity and water utility company in July 1995 ( Table 18 ). This process included separating electricity regulation from the water regulatory function. The ACT does not generate its own electricity and must rely on imports from New South Wales and the Snowy Mountains Hydro-electric Scheme. In March 1996, the ACT began to participate in New South Wales' electricity market. In May 1997, the ACT began to operate in the national electricity market in conjunction with New South Wales and Victoria and will begin competition in electricity marketing in late 1997. 56
In January 1995, the Queensland Electricity Commission was restructured and corporatized to form two new government corporations AUSTA Electric and the Queensland Transmission and Supply Corporation (QTSC). AUSTA Electric is responsible for electricity generation and QTSC is responsible for retail supply, distribution, and transmission. The QTSC has eight subsidiaries: the transmission section of the former Queensland Electricity Commission (Powerlink) and seven regional corporations in charge of distribution and marketing ( Table 18 ) 57
To further its commitment to the competitive national electricity market, the Queensland government plans to transform its monopolistic electricity industry into a competitive market by the end of 1997. AUSTA Electric has been split into three generating companies that will compete amongst themselves to supply the seven existing government electricity distributors. In addition, three new electricity marketing corporations will be created with operations to begin in July 1997. Currently, there is no physical electricity grid link between Queensland and the southern states; however, Queensland and New South Wales have announced that they will proceed with an interconnection between the two states by 2001. 58
Queensland began the privatization of its generation sector with the 37-percent equity sale of its Gladstone power station to a consortium led by Comalco (an Australian company) and Northern States Power (a U.S. company). Although there are no further plans to privatize electricity assets, the government will no longer control either electricity prices or AUSTA Electric's investments. 59 The Broken Hill Proprietary Company (an Australian company) began construction of a 105-megawatt gas-fired power station in 1994. 60 By 1997, 30 percent of Queensland's generating capacity was owned by the private sector; that proportion is expected to increase as new power stations are constructed to meet expected electricity demand from 1998 through 2006. 61 Energy Equity (an Australian company) has announced plans to build a gas- fired facility at Barcaldine. Australia Shell has started a feasibility study for the construction of a power station in Callide, Queensland. 62 Also in 1996, Pacific Gas & Electric (a U.S. company) purchased Queensland's natural gas pipeline. AUSTA Electric is also considering additional supply options for new generating capacity. Proposals for the 1998-to-1999 time period include the recommissioning of the Collinsville and Callide-A plants; grid interconnection with the New South Wales transmission link; and construction of a 440-megawatt plant between the years 2000 to 2002. In the years 2003 to 2006, the state plans to build a power plant with generating capacity between 600 and 1,400 megawatts. 63
South Australia accounts for 5.1 percent of Australia's total generating capacity ( Table 15 ). In 1995, the vertically-integrated state-owned utility, Electricity Trust of South Australia, was restructured and corporatized as ETSA Corporation ( Table 18 ). The corporation has four subsidiaries: ETSA Generation, responsible for generation; ETSA Transmission, responsible for transmission, system control, and system planning; ETSA Power, in charge of distribution and marketing; and ETSA Energy, responsible for gas trading. 64 In January 1997, ETSA Generation was separated from its parent company and became an independent government business (ETSA Generation was formerly a subsidiary of ETSA Corporation). 65 South Australia is scheduled to participate in the national electricity market in 1998. 66
Western Australia accounts for 7.6 percent of Australia's generating capacity ( Table 15 ). In January 1995, the vertically-integrated state-owned utility, State Electricity Commission of Western Australia, was divided into two independent electricity and gas corporations, trading as Western Power and Alinta Gas, respectively ( Table 18 ). Both corporations are currently state-owned. However, the Western Australia government has now decided to permit foreign investment in independent electricity generation, separate and apart from the Western Power and Alinta Gas operations. In 1995, Edison International (a U.S. company), through its subsi- diary Mission Energy, began a project to build a $111-million power plant. 67
Like Queensland, Western Australia is also privatizing other energy assets. Western Australia has announced its intention to privatize its gas pipelines. The CMS Gas Transmission Storage Company (gas pipeline), a subsidiary of CMS Energy (a U.S. company), will purchase a 100-percent interest in the West Australia Natural Gas (WANG) Pipeline near Perth, Australia. In addition, the company will purchase the Western Australia petroleum assets operated by Chevron, Texaco, Mobil and Shell. 68
The Hydro-electric Commission of Tasmania (HEC) passed legislation in June 1995 to allow the entry of new participants and extend customer choice in the industry ( Table 18 ). The HEC remains a vertically-integrated, state-owned electricity business with separately organized generation, transmission and distribution. A 1993 feasibility study concluded that while it was technically possible to construct a subsea-link between the states, the project would not be economically viable until the year 2000. 69 In April 1997, the government announced intentions to introduce retail competition in its electricity industry and to sell some of its equity interest. 70
The Snowy Mountains Hydro-electric Scheme is a cooperative venture between the Australian Commonwealth government, New South Wales, and Victoria. It represents a vital part of both Victoria's and New South Wales' electricity supply arrangements. The Scheme sells power to the central government of Australia and to the electric distributors in the states of New South Wales and Victoria. It has a generating capacity of 3,740 megawatts, representing over 10 percent of Australia's capacity.
Under the national electricity market reforms, the Scheme will not compete with New South Wales and Victoria in generation. However, prior to the completion of the national electricity market, the Scheme will be corporatized. It will then be expected to sell electricity on the national grid in competition with other state and interstate generators.
The current Australian national electricity reform aims to create a fully competitive national market in the generation and marketing sectors and to provide the incentives for efficient outcomes at the state level in the transmission and distribution sectors. 71 The price for electricity generation will be determined by the spot price or the pool price. As in the United Kingdom, Australia has instituted a form of price and revenue cap regulation that has been applied to the transmission and distribution sectors (because these segments are still deemed natural monopolies).
Currently, only the states of New South Wales and Victoria have a wholesale power generation market and have instituted reforms in price regulation (the Australian Capital Territory is participating in the national electricity market via the New South Wales electricity system). The other states that will participate in the national electricity market do not have a state-level wholesale power generation market. Since the first phase of the national electricity market (NEM1) is already underway, Queensland will not develop its own price arrangements prior to participating in the national electricity market but will operate its electricity system on the basis of rules specified in the Code.
The planned national electricity market is designed around a power generation pool (or spot market). The pool ensures that the demand and supply of electricity are balanced at all times every day is divided into half hour segments. Prices are effective for these half-hour periods and this price is paid to any generator supplying electricity during that period and is the same price charged to any customer who consumes it during that period. All generators with a generating capacity of greater than 30 megawatts are required to participate in the national market. Customers with an annual usage of at least 10 megawatts will be eligible to participant in the market, along with retail electricity suppliers. Generators and customers must submit their bids 24 hours in advance to specify the amount of power and the price they will supply and purchase generation, respectively.
Currently, the national electricity market's power pool is operating in a transitional phase, NEM1. In NEM1, the goal is to integrate the wholesale power markets of New South Wales and Victoria into one market in order to ease the eventual full transition to the national electricity market.
In the operation of NEM1, there is a central entity (called the "interconnection scheduling module") where both states' transmission operators, the TransGrid (New South Wales) and the Victorian Power Exchange (Victoria), submit the generation bids and the estimated electricity demand of their individual states. In turn, the demand for generation is forecast, and the amount of interstate power trading between the states is determined. A dispatch order is established and is sent back to each state market operator (TransGrid and the Victorian Power Exchange), who dispatches generation. The price of the highest-priced generator dispatched in a given period (the "marginal" generator) sets the pool price for that period. This price is received by all generators who dispatch electricity in that period and is paid by customers who take electricity.
After the National Electricity Code is approved and the full national electricity market is implemented, the National Electricity Market Management Company (NEMMCO) will assume the functions of the interconnection scheduling module.
The Code realized that in order to give the correct market signals in the spot market, it is important for the spot price to be allowed to approach realistically high values. The Code also recognizes that in an immature market, such as Australia, allowing the spot price to operate at a level where supply and demand are balanced may result in a very high price which would expose inexperienced participants to unnecessarily high financial risks. Therefore, the Code makes provisions for a temporary Value of Lost Load (VoLL) price cap. The price cap is set (in Australian dollars) at $5 per kilowatt hour. 72 The Code set the value of the price cap at this level in order to strike a balance between the highest price that purchasers of power might consider acceptable and a price high enough to ensure that generators would not be discouraged from investing in plants with high operating costs.
In the implementation of the full national market, the National Electricity Market Management Company (NEMMCO) will be responsible for the operation of the power pool and the short-term forward trading market.
At the state level, the wholesale power generation market operates almost like the operations contemplated for the national electricity market (the fully transitional national market will begin in the first half of 1998). The state (Victoria and New South Wales) operates its own pool, and generators compete in the pool to supply the energy needs of their individual states ( Figure 10 and Figure 11 ). The wholesale power market in New South Wales began in 1996. Victoria's wholesale power market began in 1994. In NEM1, generators in Victoria and New South Wales will supply electricity to an integrated wholesale power pool, and (through that pool) they will compete with each other to supply the combined energy needs of the two states and the Australian Capital Territory.
Pricing in the transmission and distribution sectors of the Australian electricity industry are set by a cap, above which prices or revenues are not permitted to rise. Victoria's tariff regulation is mainly a price cap. 73 A price cap consists of a ceiling where a company has complete price flexibility as long as its price stays below that level; that is, prices can move up and down but they must stay under (or at) the ceiling. The price cap can serve to keep prices (both unit electricity costs and distribution network costs) from rising too high, and it can protect electricity customers from large and/or frequent price fluctuations. It can also provide an incentive for productivity improvement and cost efficiency. In other words, operators have incentives to cut costs and increase efficiencies. 74 However, it can also result in unusually high levels of profitability, which can raise public concern.
The price cap is commonly referred to as "CPI (Consumer Price Index) minus X." As in the United States, the "CPI" is a measure of inflation. The "X" is a productivity factor. The theory behind the use of the "CPI-X" price ceiling is that a regulated company must be allowed to recover inflationary increases in its input costs, but should not receive additional benefit from productivity improvements that result in lower operating costs which also offset inflationary increases in input costs. The Australian CPI-X formula is similar to the RPI-X form of regulation adopted in the United Kingdom.
In New South Wales, a revenue cap is applied in the transmission and distribution sector. 75 Revenue cap regulation works much the same way as price-cap regulation. However, instead of indirectly limiting a company's revenues by controlling its prices (the price-cap approach), under a revenue cap the CPI-X formula directly limits the total amount of revenue a company can receive.
Currently, the regulations for both transmission and distribution are established by state regulators. The regulator in New South Wales is the Independent Pricing and Regulatory Tribunal, and the regulator in Victoria is the Office of the Regulator General. (As previously stated, Victoria's electricity tariff regulation is mainly a price cap, whereas in New South Wales a revenue cap is mainly applied.) Regulatory arrangements in transmission pricing under state jurisdiction will end in June 1999 in New South Wales, and in December 2000 in Victoria. 76 Thereafter, the Australian Competition and Consumer Commission (ACCC) will become responsible for transmission regulation. The ACCC has not made a final decision on the regulatory guidelines and rules to be used in determining transmission pricing except that the guidelines will be cost-reflective and will utilize revenue or price capping or a combination of both. After this decision has been made, transmission network service providers must develop their own pricing structures and tariffs and submit them to the ACCC for approval. Additionally, the ACCC will produce a "Statement of Regulatory Intent," which will establish guidelines as to how it will exercise its power in this regulatory area. 77
In the area of distribution, the Code provides national objectives and economic principles that each state should follow; however, the states retain jurisdiction over distribution pricing. The Code recognizes that it may be inappropriate to apply national guidelines to state jurisdictions because of existing distribution service pricing regimes. Nonetheless, the Code has made provisions which allow the states to develop a set of national guidelines for distribution service pricing. However, any such proposed distribution pricing guidelines must be unanimously approved by all of the states and must not conflict with or override any pre-existing distribution regulations in any of the individual states. 78
The ACCC will be responsible for three missions. First, it will ensure that economic efficiency gains are realized by customers (in terms of price, level of service, and quality of service) and by generators (in terms of optimizing their generating plants and lowering operating costs). Second, its role is to ensure that generators do not raise prices to reap excessive profits. Third, it will ensure that anti-competitive pressure is not exerted by generators to exclude potential competitors from entering the market. 79
The level of foreign investment in the Australian electricity industry has increased and is expected to continue to expand as reforms and privatization in the electricity industries continue. 80 The reforms aimed at developing fair and open competitive markets are leading to opportunities for private investment in the electric industry. In 1995, the direct investment position in Australia in the category "other industries" (of which electricity is the major part) almost tripled from the prior year's level partly due to the acquisition of Australian electricity assets. 81 (According to the U.S. Department of Commerce, direct investment involves the establishment of a new firm, the expansion of an existing firm, or the acquisition of a business enterprise or real property in which a foreign person or company obtains direct or indirect ownership of at least ten percent of controlling equity). 82 The 1995 total direct investment position in Australia (by the United States and other countries) was $104.2 billion, a $13.1- billion increase from investment during the prior year ( Figure 12 ). 83 Of this increase ($13.1 billion), the United States accounted for almost $5 billion and total direct investment has increased every year since 1988 ( Figure 13 ).
American companies' attraction to foreign investment in Australia can in part be traced to the passage of the 1992 Energy Policy Act in the United States, which, for the first time, permitted U.S. utilities to own an equity interest in foreign utilities.
The introduction of electricity reform in Australia has given U.S. companies (as well as companies from other countries) the opportunity to invest in an electricity system which has the potential for improved efficiency. In fact, some U.S. companies have stated that investments in Australia's electricity market would give them expertise in operating in a deregulated electricity market and therefore would give them an added advantage when deregulation begins in the United States. 84 Slow economic growth in the United States, Australia's low political risk, and their new regulatory climate for electricity are additional factors. 85 Efficiency gains are already evident in New South Wales and Victoria, the two states with the greatest degree of reform and privatization.
In February 1997, the New South Wales Independent Pricing and Regulatory Tribunal reported that wholesale electricity prices in Australia have steadily decreased since 1993, representing a 32-percent drop in real terms over a four-year period. 86 Victoria has also realized a decline in electricity prices of 6 percent as well as improvements in service quality. Due to continued improvements in labor productivity between the years of 1991 and 1995, returns on assets have also increased. The labor productivity increases have, in particular, been attributed to Victoria's reform and privatization efforts. 87
An Australian Chamber of Manufacturers' (ACM) survey of its contestable customers (large end users) in Victoria reported that approximately 2,500 Victorian companies were eligible to enter the wholesale power market in 1996. The survey was developed to examine prices, customer satisfaction with service, and supply conditions in the market. Of the 800 contestable customers who were given the survey, the ACM had 312 respondents. Of the 312 respondents, about 78 percent of the respondents believed their negotiated electricity prices were cheaper compared to rates prior to the 1994 beginning of the Victorian wholesale power market. Only 10 percent believed they were worse off under the new arrangements. The average price reduction response per respondent was about 10 percent, with savings varying between 1 percent and 39 percent. While price was the major consideration for most customers when choosing a supplier, almost 33 percent of the contestable customers reported an improvement in service, while almost 64 percent reported no change. As for supply conditions, of the 312 respondents, 93 percent had negotiated a new contract subsequent to the 1994 reform. Thirty-five percent of the respondents who had negotiated a new distribution contract had also changed their electricity supplier. 88
In constructing its national electricity market reform, Australia plans to expand upon the UK model by large end users (contestable customers) to directly compete for generated power in the national electricity pool. This concept was tested (on a smaller scale) by allowing these customers to compete for power within the individual power pools of their own states (first in Victoria in 1994, and then in New South Wales in 1996).
If the results of the ACM survey of this type of customer (large end users) are considered to be representative of all of the large end users in Australia, several questions might arise. Why are the majority of these customers choosing to use the marketing services of a distributor to compete in the power pool on their behalf, instead of cutting out this "middleman" and directly competing for their own power needs themselves, as the electricity reform allows? The answer to this question is not entirely clear. It may be that the large end users need time to acquire the skills and gain the experience necessary to effectively operate in the competitive power pool process. It may also be that purchasing these services through contractual arrangements from a distributor experienced in the power pool bidding process lowers the risk of pool competition for a relatively small charge. Perhaps purchasing these services is simply more convenient. Or, it is possible that this trend (of large end users retaining distributors to compete for power on their behalf) is transitory, and that more and more of these customers will compete in the power pool as they acquire the necessary skills to do so. As the national electricity market in Australia matures, the nature of the relationship between "middleman" distributors/marketers and large end users requiring power from the national pool may become more apparent.
