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The inquiry into electricity supply in New South Wales
ARTICLE IN PRESS Energy Policy 37 (2009) 570–576
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The inquiry into electricity supply in New South Wales Anthony D. Owen School of Economics and Finance, Curtin Business School, Curtin University of Technology, Perth, WA 6845, Australia
a r t i c l e in f o
a b s t r a c t
Article history: Received 23 May 2008 Accepted 10 September 2008 Available online 18 November 2008
In May 2007, the Premier of New South Wales (NSW) announced the establishment of an Inquiry into Electricity Supply in that State to be undertaken by the author of this paper. Fundamental to the Inquiry was the perceived need for additional baseload generating capacity, the identification of the available technologies, carbon constraints and the policy options that would encourage the private sector to undertake the required investments. Although NSW is part of the competitive National Electricity Market, State-owned generators dominate baseload supply. In addition, the State operates three electricity retailing businesses, has a monopoly on transmission and distribution, and provides price stability for NSW residential consumers through the Electricity Tariff Equalisation Fund. Overall, therefore, the State dominates the industry and, not surprisingly, potential private investors are sceptical that its market roles may be based upon criteria other than the purely commercial. The Inquiry’s report, which was publicly released in September 2007, recommended sale of all State assets in both electricity generation and retail. This paper provides a rationale for that recommendation. & 2008 Elsevier Ltd. All rights reserved.
Keywords: Electricity New South Wales Privatisation
1. Introduction The Australian National Electricity Market (NEM) was established in 1998 to provide a competitive wholesale market for the supply of electricity in New South Wales (NSW), Queensland, South Australia, Victoria, the Australian Capital Territory and, in 2005, Tasmania.1 Prior to the NEM, these States all had centrally planned electricity supply which were often characterised by over-investment in generating capacity due to the lack of marketbased price signals. As a result, capital expenditure was allocated in a sub-optimal manner, effectively at a real cost to taxpayers and electricity consumers. The Industry Commission (1991) estimated that the surplus generation capacity in NSW alone in (financial year) 1989–90 had an annual opportunity cost of $443 million.2 The NEM is a compulsory gross pool market. Generators bid to supply the market with specific amounts of electricity at fixed offer prices for half-hour periods throughout the day. The National Electricity Market Management Company (NEMMCO) dispatches generation by meeting demand in the most cost-effective way, dispatching the lowest bid generators first. During dispatch, prices are calculated at five minute intervals and then averaged over the half-hour trading interval for settlement purposes. There is a price
E-mail address: [email protected] Thus only the Northern Territory and Western Australia are not part of the NEM. Their exclusion is due to the vast distance between their load centres and the interconnected electricity network across the NEM member States. 2 All monetary amounts in this paper are expressed in Australian dollars.
cap of $10,000/MW h, and a price floor of negative $1000. Retailers purchase in the pool market, but the eventual price paid by them will depend on what hedging contracts they have in place to give them their desired degree of price stability. Various market regulations exist to ensure security and reliability in the NEM.3 The NEM permits electricity to be traded over State borders, subject to physical transmission constraints. Currently, Queensland transmits considerable quantities of baseload power to the NSW market, whilst NSW and Victoria draw power from the Snowy Mountains Hydro-electric Scheme. Until mid-1990s, in Victoria, South Australia and Tasmania the four functions of generation, transmission, distribution and electricity retailing were undertaken within a single, vertically integrated, monopoly business. In NSW and Queensland, generation and transmission were contained in a single monopoly business, while distribution and retailing were undertaken by a number of businesses, each with a monopoly franchise, covering a specified geographical area within the State. During 1990s, the industry underwent a major restructuring with the objective of unbundling these four functions into separate businesses. Victoria and South Australia then sold their electricity businesses to the private sector. Although NSW and Queensland still retain State ownership of their existing generation assets, the private sector is encouraged to invest in new plant in competition with State generators. The retail sector is fully contestable in all States except
1
0301-4215/$ - see front matter & 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2008.09.084
3 A guide to Australia’s NEM can be found at: http://www.nemmco.com.au/ nemgeneral/000-0187.pdf.
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Tasmania, although State retailers in NSW continue to exist in competition with the private sector. Most of the current electricity generation capacity in NSW was built during 1980s. In the early 1980s, the generation reserve in NSW was well over 40%, even reaching nearly 55% in 1983 and 1984. As a result of this oversupply of capacity, no new baseload power station has been commissioned in NSW since Mt Piper in 1992, with the exception of a small (150 MW) plant at Redbank in the Hunter Valley. Over the same period, electricity consumption in NSW, as elsewhere in Australia, has experienced significant growth. The NSW generation reserve now has fallen to around 22%. The expected continuing growth in electricity consumption, albeit at a slower rate than that of recent experience, is likely to see it fall to around 15% by around 2103–14, the lower end of international best practice. Thus, in the absence of any major demand-side (downward) shifts, NSW will reach a point during the next decade when new baseload generation capacity will become necessary. It was in this context that the Inquiry was established, with the following terms of reference:
construction. These include the combined cycle gas turbine (CCGT) plant under construction at Tallawarra (private) and two open cycle gas turbine (OCGT) ‘‘peaking’’ plants under construction at Colongra (State-owned) and Uranquinty (private). Snowy Hydro Limited is jointly owned by the NSW, Victorian and Commonwealth Governments. It comprises 16 large dams and seven power stations in the Kosciusko National Park area. Its total generation capacity is about 3700 MW, and it predominantly meets the bulk of the peak and intermediate generation requirements of NSW. Non-hydro renewable energy currently accounts for 0.4% of the energy consumed in NSW. About 17 MW of wind power has been installed, with projects amounting to a further 540 MW under development. There is also one wave power generator which has a peak capacity of 0.5 MW. Renewable projects under development include two 30 MW bagasse co-generation plants and a solar thermal electricity plant being developed by Macquarie Generation at its Liddell power station. The latter is expected to generate the equivalent of 4.4 GW h annually through displacement of coal for pre-heating boiler feed water.
1. Review the need and timing for new baseload generation that maintains both security of supply and competitively priced electricity. 2. Examine the baseload options available to efficiently meet any emerging generation needs. 3. Review the timing and feasibility of technologies and/or measures available both nationally and internationally that reduce greenhouse gas emissions. 4. Determine the conditions needed to ensure investment in any emerging generation, consistent with maintaining the State’s AAA credit rating.
2.2. Transmission
The Inquiry received 74 written submissions and held meetings with 50 stakeholders. It was supported by three expert reports covering viable power technology options for NSW, gas availability in Eastern Australia, and securing private investment in new generation. The Inquiry report was released on 11 September 2007.4
In NSW, most of the transmission network is owned and operated by Transgrid, a State-owned corporation. Its assets comprise 12,440 km of high voltage transmission lines and 82 substations and switching stations. Transmission prices and revenues are regulated by the Australian Energy Regulator. 2.3. Distribution The NSW distribution network is divided between three Stateowned corporations: EnergyAustralia, Integral Energy and Country Energy. Their respective areas of operation are eastern Sydney and urban areas to its immediate north, western Sydney and urban areas to its immediate west and south and rural/regional areas. Distribution prices and revenues are regulated by the Australian Energy Regulator. 2.4. Retail
2. Current characteristics of the NSW electricity market 2.1. Generation Currently, NSW relies on coal-based thermal power generation for the bulk of its baseload electricity production, using pulverised coal-firing technology. Baseload power is also supplied through inter-connectors from the Snowy Mountains Hydro-electric Scheme and from Queensland. Whilst it would be possible to expand imports from Queensland, this would only be a viable option if there are substantial differences in fuel costs between the two states and if expansion of interconnector capacity were justified commercially. Neither of these situations is considered to be likely over the next decade. The current generation capacity in the NSW region of the NEM is about 12,600 MW, with the State-owned corporations owning all coal-fired power stations with the exception of the small Redbank station (Table 1). In addition to the one small privately owned gas-fired power plant at Smithfield, there are a number of gas-fired power stations currently either planned or under
The retail sector comprises businesses that purchase wholesale electricity in the NEM and sell it to end users. Businesses supplying energy to retail customers in NSW must hold an electricity supplier’s licence. There are currently 24 licensed electricity retailers, including the State-owned corporations EnergyAustralia, Integral Energy and Country Energy. NSW was the first state in Australia to introduce full retail competition for both electricity and gas in 2002. Consumers can, therefore, choose to enter into supply contracts with their preferred retailer under competitive or negotiated pricing arrangements. Alternatively, small customers may continue to receive their electricity supply from the ‘‘standard’’ retailer in their local area under regulated prices. The NSW Government, in common with all other Australian state and territory governments, has committed to the removal of retail price regulation in the electricity sector, when markets are shown to be sufficiently competitive.
3. Addressing the terms of reference 3.1. Term of reference 1
4
The Inquiry web site contains the full report, the expert reports, and all submissions received: http://www.premiers.nsw.gov.au/WorkAndBusiness/DoingBusinessInNSW/OwenInquiryIntoElectricitySupplyInNSW.htm.
The Inquiry reviewed a considerable body of work on demand and supply projections for electricity in NSW, and concluded on
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Table 1 Existing or committed generation in NSW Generator
Ownership
Year commissioned
Fuel
Munmorah Liddell Wallerawang Vales Point Eraring Bayswater Mt. Piper Redbank Bendeela Kangaroo Valley Smithfield Tallawarra Colongra Uranquinty
Delta electricity Macquarie generation Delta electricity Delta electricity Eraring energy Macquarie generation Delta electricity Babcock & brown Eraring energy Eraring energy Marubeni TRUenergy Delta electricity NewGen
1968–69 1971–73 1976–80 1978–79 1982–84 1985–86 1992–93 1999 1977 1977 1995 2009 2009–10 2009–10
Coal Coal Coal Coal Coal Coal Coal Coal Hydro Hydro Gas Gas Gas Gas
Total
Nameplate rating (MW)
700 2000 1000 1320 2640 2640 1320 150 80 160 160 440 660 660 13,930
Expected maximum energy capabilitya (GWh/annum)
Maximum technical capacity factora (%)
0b 13,000 6500 8700 20,800 20,800 10,400 1000 Negligible Negligible 1000 2300 300 300
0 74 75 75 90 90 90 76 – – 72 60 5 5
85,100c
a Maximum capacities, output and annual energy capability, on nameplate rating. The impact of recent drought conditions in NSW have not been taken into account. b Delta Electricity informed the Inquiry that a significant refurbishment would be necessary for the Munmorah power station in order to extend its life beyond 2012. Munmorah’s output has, therefore, not been included in this table. c The expected maximum energy supply capability of existing and committed power stations within NSW is at most 85,100 GWh/annum. This is based on the assumption that the maximum capacity could be sourced simultaneously from each power station.
the basis of these studies that the state would need to be prepared for additional baseload capacity from 2013–14, or shortly thereafter. In addition, submissions to the Inquiry were broadly in agreement on the need for and timing of such investment. Transgrid prepares an annual planning report setting out forecast energy consumption and maximum demand in NSW over a 10 year horizon, identifying future constraints in the network and providing options for their removal.5 These projections are used by NEMMCO in the preparation of its annual Statement of Opportunities, which considers the supply– demand balance, with a focus on peak demand in the NEM rather than baseload. Over the next decade, Transgrid estimates that electricity consumption in NSW will increase by an average of 1.8% per annum as compared with 2.5% per annum over the past decade.6 This decline in the rate of growth of consumption is largely due to the impact of energy efficiency initiatives and the public’s growing awareness of the environmental impacts of power generation based upon fossil fuel technologies. Since these offsets are factored into the forecasts, it must be new initiatives that will alter the projected path of consumption. With carbon pricing anticipated to be introduced into the power generation sector in 2010, it could be expected that the rate of growth of consumption will decline further. On balance, the risk-averse approach would be to recommend that preparation for a 2013–14 timeline be adopted, with the intention of delaying the process if the time horizon moves outwards. Depending on the technology, the lead-time for planning and building a new baseload power plant ranges from five to seven years, so the process should commence immediately.7
5
The latest report is: Transgrid, Annual Planning Report, 2008. Assuming that there are no new large industrial loads. 7 There are a number of sites that already hold the various regulatory and environmental instruments that would permit construction to commence at short notice, so these time frames can be reduced significantly if required. 6
3.2. Term of reference 2 The most technologically advanced, commercially viable, options currently available for the next tranche of baseload generation in NSW are CCGT and Ultra-supercritical Coal (USC). A CCGT plant has lower capital costs than USC technology, a shorter construction period, and about half the level of CO2 emissions per unit of power generated. However, the relative fuel cost advantage of coal over gas has, in the past, given coal a distinct commercial advantage for system baseload. NSW has vast coal resources, with estimated recoverable reserves of around 10 billion t. In 2005–06, the NSW coal industry produced 161 million t of raw coal of which around 30 million t was consumed by the State’s power plants. Due to its high ash content, coal destined for NSW power stations is not generally suitable for export, and hence its price reflects this limitation. It is also typically sold under long-term contracts (10–12 years), which limits the ability of producers to raise prices to netback world parity.8 The Inquiry was informed that the real weighted average coal price delivered to NSW power stations was $1.36/GJ for 2007–08 delivery, which equates to around $10/MW h of electricity generated. The submission of one of the State’s generators, however, quoted a delivered fuel cost of around $0.90/GJ. In contrast, the gas resource base of NSW is relatively underdeveloped, with existing supplies coming from sources where production was expected to decline from around 2012–14.9 However, there is significant potential for coal seam gas, known as coal seam methane (CSM), in a number of basins in Eastern Australia,10 many of which are already covered by exploration
8 Of course it also protects producers against sharp price falls in the international market. The long-term contracts typically contain price escalation clauses, but largely based upon domestic criteria. 9 Current gas demand in NSW is supplied by two transmission pipelines, from the Cooper Basin in South Australia and from the Gippsland Basin offshore Victoria. 10 NSW and Queensland in this context.
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licences. CSM production has grown significantly from around 5 PJ in 2000 to over 100 PJ in 2007. Over the same period, CSM proven and probable (2P) reserves have grown from around 200–4000 PJ (the vast bulk of it in Queensland). These are sufficient to underpin a significant increase in CSM production from 2009 to 2015 (up to 300 PJ per annum), but further growth in reserves will depend on the level of growth of demand. Clearly, there is little incentive for CSM producers to invest in upgrading potential gas resources to 2P if they are to remain in the ground unproduced for a long period of time. Compared with Queensland, the NSW 2P gas reserve is very modest. However, there are a number of projects in the early stages of production assessment in NSW, and potential gas developments will have the benefit over their Queensland counterparts of proximity to demand if future NSW baseload capacity is to be based upon gas technology. Eastern Australian gas is currently available at around $4/GJ, which equates to around $25/MW h of electricity generated. Whilst this is more expensive than coal on a MW h basis, the much higher capital cost of coal plant means that CCGT generators would have a lower total average cost than coal at below 50% utilisation. However, there is a significant degree of uncertainty around gas prices. Currently the Queensland CSM gas reserves are stranded and the gas price reflects this fact, but the prospect of exporting CSM as LNG could force domestic prices up to the much higher netback LNG price. The advent of carbon trading within Australia, however, would offset the cheaper fuel costs of coal technologies to (at present) an unknown extent. This uncertainty tends to make gas technologies the preferred choice for risk-averse investors, given their lower carbon footprint. Reducing coal technology’s CO2 emissions using carbon capture and storage could reverse this situation, but the enabling technology is still under development and is unlikely to be available outside of pilot plants until after 2020. Wind power displaces baseload, but currently the vast majority of installations in the NEM states are located in Victoria, South Australia and Tasmania. The Commonwealth Government is committed to a Mandatory Renewable Energy Target of a 20% share for renewable energy in Australia’s electricity supply by 2020, and the bulk of this is expected to be based upon wind technology.11 However, at present, the wind resource in NSW does not appear to offer opportunities comparable to those in these three southern states. Emerging technologies, such as geothermal and solar thermal, would not be commercially available within the required timeframe, but clearly have great potential for future additions to baseload, particularly in a carbon-constrained environment. Nuclear power is also a viable enabling technology but, despite its relatively good history on safety, has environmental and nuclear proliferation issues that would invariably cause long development delays due to public and political scrutiny in Australia. In addition, the regulatory environment for enabling Australia to become self-sufficient at all stages of the nuclear fuel cycle does not currently exist. Nuclear power would also require a significant carbon price in order to compete with coal or gas for baseload. It should be noted, however, that in his speech to the NSW Parliament on 9 May 2007, the Premier stated ‘‘there will be no consideration of nuclear energy for NSW whatsoever’’.
11 To permit greater precision, the target has been set at 45,000 GWh. The scheme will be phased out over the period 2020–30 as Australia’s carbon pricing regime matures.
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3.3. Term of reference 3 A carbon emissions ‘cap-and-trade’ scheme is scheduled to commence at a national level in Australia in 2010. Precise details of the proposed scheme have not been announced, but it is clear that the electricity generation sector will be included when the scheme starts. Thus, in the context of the NSW electricity sector and current technology options, the price of carbon permits will play a critical role in determining the relative competitiveness of coal and gas-based technologies following the introduction of the scheme. Whilst existing generators may receive a free allocation of emissions permits to cover some or all of their historical emissions, new investments may need to have to purchase permits to cover all of their emissions.12 Thus future investors in electricity generating plant in NSW must factor in the cost of carbon in assessing their commercial viability. With CCGT plants producing approximately half the CO2 emissions of USC plants, the cost of carbon will be a major element in the choice of investment technology for additions to baseload capacity. At present a number of key commercial parameters relating to a national carbon trading scheme are uncertain13:
The national emissions targets and associated dates for achieving such targets are vague;
The proposed carbon emissions cap for the electricity sector, and its transition path, are unknown;
The criteria for allocation of emissions permits to current emitters have not been specified; and
The penalty price, and any other penalties, for non-compliance have not been established. The high level of emissions market uncertainty tends to favour CCGT technology given its lighter carbon footprint, but other uncertainties surrounding capital and relative fuel costs will also be major determinants of the choice of technology.14 3.4. Term of reference 4 Under current market conditions, the private sector is very unlikely to invest in baseload generation in NSW given the dominance of the State-owned generators.15 Rightly or wrongly there is the perception that the NSW Government, via the Stateowned generators, may adopt investment criteria which are not solely commercially based. A possible scenario is given in Fig. 1, which illustrates the impact of uncertainty that Government policy may create if it pre-empts the market. Thus private investment in generation could be discouraged by the possibility it would be stranded by untimely Government investment (particularly where the latter has a portfolio of generation assets to assist it to offset the problem it has created). This cycle of 12 It is very unlikely that power generators will receive such a generous allocation of free permits as did their European Union counterparts when the European Union Emissions Trading Scheme commenced. 13 The Garnaut Climate Change Review was commissioned by the Commonwealth, state and territory governments to examine the impacts, challenges and opportunities of climate change for Australia. The final Report was delivered to the Commonwealth government on 30 September 2008. The Commonwealth has also produced a Carbon Pollution Reduction Scheme Green Paper that outlines its proposed measures for implementation of Australia’s emissions trading scheme. However, the design and scope of the scheme upon its introduction in 2010 remains far from clear. 14 Another uncertainty would be public reaction to any new coal-fired plant in NSW. It is likely that any proposal would be held up for a significant period of time by public opposition expressed through the NSW Land and Environment Court. 15 The State accounts for almost 98% of currently operating nameplate installed capacity in NSW.
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Private sector commits to invest in generator Once only Government invests to address perceived security problem
Leads to delay in private sector commitment
Government locked in to all generation investment
Private sector investment stranded by government investment
Private sector fears further government investment
Fig. 1. Uncertainty in government investment policy in generation. Source: TRUenergy
uncertainty could result in the Government being locked into making all future generation investment. To break this cycle, it would be necessary for the Government to make a credible commitment not to invest further in generation. The private sector will invest in generating capacity when wholesale prices and market-related conditions permit a decision based upon commercial behaviour. The current market structure in NSW, however, gives rise to a number of inhibiting factors and uncertainties that discourage private sector investment. This is particularly the case for additions to baseload, where there is the perception that investment behaviour of the State-owned generators could be determined by political, rather than commercial, criteria. This could give rise to excess capacity and hence a devaluation of generation assets. Since additions to baseload involve large, lumpy investments, the State generators with their portfolios of generating assets could adjust capacity accordingly. However, a new entrant could well be left stranded with costly surplus capacity. Investment in peaking plant is less of a problem, since its modular, smaller nature gives it a much greater flexibility in responding to changing prices and other market-related conditions. Thus the option is for either the State to undertake all future baseload investment itself or for the generation sector to be privatised and reliance placed upon investment by private investors operating within the competitive environment of the NEM. Effectively this transfer would reduce State borrowings by around $7–8 billion over the next decade, in addition to net sale proceeds of the assets. In the absence of such a sale, over the next 15 years, the State would also be required to invest in the order of $3–4 billion to retro-fit some existing power plants with carbon reduction technologies. Such obligations, particularly in a high risk industry such as electricity generation, could have an adverse impact on the State’s AAA credit rating with Standard and Poor’s, with its implications for the cost of future State borrowings.16 The Inquiry considered the electricity retail function to be comparable with a financial intermediary, much like an insurance 16 The high cost of the NSW Government’s capital works program is the major concern of Standard and Poor’s. Augmenting this with a substantial obligation for funding additional power generation plant, rather than using the sale proceeds from electricity privatisation to offset the cost of the capital works program, raises the spectre of a negative reaction from Standard and Poor’s.
company. However, the three State-owned retailers, which are also responsible for owning, operating and maintaining the distribution infrastructure, are currently hindered in their retail operations by an inability to expand both vertically and horizontally beyond their energy retailer functions. As a result, their competitors, unconstrained by Government policies, were undermining their customer base and, consequently, their market value. To bring them into line with their private sector counterparts, the State would be required to invest around $2–3 billion over the same period to permit investment in (for example) ‘‘peaking’’ plant, inter-state energy services, a gas resource base, etc. Transferring the State retailers to the private sector would release such funds to enhance the NSW Government’s capacity to deliver other services outside of the power sector. Retailers have a strong incentive to enter generation, particularly investing in ‘‘peaking’’ capacity as a hedge against extreme spot price volatility where the supply of hedge contracts may be limited. Essentially hedging is being ‘‘internalised’’ rather than relying on external counterparties. Conversely, generators have corresponding incentives to invest in retail. This form of vertical integration, creating what is known as ‘‘gentailers’’, has become a relatively common feature in ‘‘restructured’’ electricity markets around the world and thus transferring both retail and generation to the private sector could be expected to be more attractive to potential purchasers than the sale of just one or the other. Whether such a practice encourages competition is open to debate (see, for example, Bushnell et al., (2005)).
4. Recommendations Based upon the above rationale, the Inquiry made the following recommendations: 1. Divest the State of the retail arms of EnergyAustralia, Integral Energy and Country Energy. 2. Divest the State of the generation businesses of Macquarie Generation, Delta Electricity and Eraring Energy. 3. In the event that the Government does not wish to sell generation, then it should implement an appropriately structured long-term leasing of current generation assets. The State
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4.
5.
6.
7.
8.
would retain ownership of the assets, with operational and commercial control by the private sector. Actively monitor the progress of reforms to NSW planning, development approval and environmental licensing process to ensure that proposals for new generation capacity, and associated fuel supplies, are considered expeditiously, and in a cost-effective and predictable manner, without compromising the quality of environmental assessment. Support the planned review of the effectiveness of retail competition by the Australian Energy Market Commission in 2010, and consider the removal of regulated retail price caps at that time, should the review find effective competition in the NSW retail market. Encourage the Commonwealth Government to bring forward the timetable for establishing a national emissions trading scheme. At a minimum, the Commonwealth should resolve and announce: The national greenhouse gas reduction target and short-term caps and associated penalties. The basis for allocating emissions permits. Develop and implement clear and timely transitional rules for existing State-based greenhouse gas and emission schemes to the national emissions trading scheme (in the event of its introduction). Encourage and support energy efficiency initiatives where possible.
The first three of the above represent the major recommendations, with the remainder being either enabling or best practice supporting recommendations. At first sight, the third recommendation may appear to be redundant given the second recommendation. However, the Premier of NSW is on record as stating in Parliament on 9 May 2007 that ‘‘there will be no sale of electricity generation, transmission or distribution’’. Thus the third recommendation was included so that he would not be seen to be reneging on this undertaking. Nevertheless, the second recommendation would provide the optimal outcome in the view of the author. Transmission and distribution are highly regulated natural monopolies in NSW and thus, by implication, it was recommended that there be no change to the status quo.
5. Criticisms that followed release of the report As could be expected, a barrage of criticism was levelled at the recommendations of the Inquiry, particularly from the relevant trade unions and some green groups. What the author considers to be the four main lines of criticism are outlined below, together with the author’s response. 5.1. Criticism 1 The Inquiry recommended investment in coal or gas baseload plant(s) and ignored energy efficiency and renewables. 5.2. Response 1 The Inquiry recommended that NSW be ‘‘prepared’’ for investment in additional baseload. If enhanced energy efficiency, carbon pricing or renewables can offset increasing demand that would not present a problem. Investments can be postponed, but being ‘‘prepared’’ at least ensures that additional baseload capacity would be available when, and if, required.
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5.3. Criticism 2 Private retailers would have an incentive to sell more electricity and hence encourage emissions of CO2. 5.4. Response 2 Private retailers have that incentive now! In any case, the pricing of carbon emissions will make this concern redundant. 5.5. Criticism 3 The NSW Government can mandate no further coal plants if it retains ownership. Private industry may select coal because it is cheaper than gas. 5.6. Response 3 This criticism ignores the fact that private industry typically operates over shorter business horizons and higher discount rates than State entities investing in public goods. Gas plant can be built as modules, commencing with OCGT and then closing the cycle (to CCGT) when warranted by demand. Compared with coal plant, this gives private power plant investors lower up-front capital costs, an earlier revenue stream, and hence lower risk (than USC plant). However, coal technology may still be attractive for replacing older coal plant if it comes with free emissions permits. 5.7. Criticism 4 The price of electricity will rise following privatisation of generation and retail. 5.8. Response 4 This is probably true, since the industry is moving into a different era. Regulated prices for residential consumers will be phased out by 2013, provided there is evidence of a competitive retail sector in NSW. These prices are currently well below wholesale prices and realignment must be expected, although competition could offset some of this expected increase. In addition, the switch to gas will probably lead to price increases due to higher fuel costs, particularly if the domestic gas market has to compete with gas destined for export as LNG. Finally, carbon trading is intended to increase prices and hence modify consumer demand and encourage investment in energy efficiency, renewables and low-carbon technologies. It must be remembered, however, that since only 40–45% of the retail cost of electricity comes from its wholesale price, with transmission, distribution and retailing collectively accounting for the balance, the ‘‘pass-through’’ will be correspondingly lower.
6. The government’s decision Early in 2008, the NSW Government announced that it would sell the State-owned retailers and implement long-term leasing of the State generation assets, as recommended in the report. However, trade union pressure on a significant number of Labor Members of Parliament threatened to defeat the enabling bill in Parliament unless the support of the main opposition Liberal Party could be guaranteed. Although the leader of the opposition was on record as favouring the sale of the State’s power sector assets, the political reality was that they would not support the government’s
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bill when it was presented to Parliament on 28 August 2008. Faced with certain defeat on the floor of Parliament, the government withdrew the bill.17 Immediately, it announced that Parliamentary approval for the sale of the retailers was not necessary and that the sale would proceed. In an attempt to regain some semblance of Government cohesion, the Premier then attempted to reorganise his Cabinet but was thwarted by internal Party opposition. On 5 September the Premier resigned. Whilst the sale of the state retailers is still on the Government’s agenda, sale or leasing of the generation assets appears to have been postponed indefinitely (or at least until the Liberal Party gain office).
17 The news brought an immediate response from Standard and Poor’s, placing the State under credit watch.
Acknowledgement The author wishes to acknowledge the helpful comments of two referees on an earlier draft of this paper. References Bushnell, J., Mansur, E.T., Saravia, C., 2005. Vertical arrangements, Market structure, and competition: An analysis of restructured US Electricity markets, Centre for the study of energy markets, Working paper 126, University of California Energy Institute. Industry Commission, 1991. Energy generation and distribution, Report no. 11, three volumes, AGPS, Canberra.
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Energy Policy journal homepage: www.elsevier.com/locate/enpol
The inquiry into electricity supply in New South Wales Anthony D. Owen School of Economics and Finance, Curtin Business School, Curtin University of Technology, Perth, WA 6845, Australia
a r t i c l e in f o
a b s t r a c t
Article history: Received 23 May 2008 Accepted 10 September 2008 Available online 18 November 2008
In May 2007, the Premier of New South Wales (NSW) announced the establishment of an Inquiry into Electricity Supply in that State to be undertaken by the author of this paper. Fundamental to the Inquiry was the perceived need for additional baseload generating capacity, the identification of the available technologies, carbon constraints and the policy options that would encourage the private sector to undertake the required investments. Although NSW is part of the competitive National Electricity Market, State-owned generators dominate baseload supply. In addition, the State operates three electricity retailing businesses, has a monopoly on transmission and distribution, and provides price stability for NSW residential consumers through the Electricity Tariff Equalisation Fund. Overall, therefore, the State dominates the industry and, not surprisingly, potential private investors are sceptical that its market roles may be based upon criteria other than the purely commercial. The Inquiry’s report, which was publicly released in September 2007, recommended sale of all State assets in both electricity generation and retail. This paper provides a rationale for that recommendation. & 2008 Elsevier Ltd. All rights reserved.
Keywords: Electricity New South Wales Privatisation
1. Introduction The Australian National Electricity Market (NEM) was established in 1998 to provide a competitive wholesale market for the supply of electricity in New South Wales (NSW), Queensland, South Australia, Victoria, the Australian Capital Territory and, in 2005, Tasmania.1 Prior to the NEM, these States all had centrally planned electricity supply which were often characterised by over-investment in generating capacity due to the lack of marketbased price signals. As a result, capital expenditure was allocated in a sub-optimal manner, effectively at a real cost to taxpayers and electricity consumers. The Industry Commission (1991) estimated that the surplus generation capacity in NSW alone in (financial year) 1989–90 had an annual opportunity cost of $443 million.2 The NEM is a compulsory gross pool market. Generators bid to supply the market with specific amounts of electricity at fixed offer prices for half-hour periods throughout the day. The National Electricity Market Management Company (NEMMCO) dispatches generation by meeting demand in the most cost-effective way, dispatching the lowest bid generators first. During dispatch, prices are calculated at five minute intervals and then averaged over the half-hour trading interval for settlement purposes. There is a price
E-mail address: [email protected] Thus only the Northern Territory and Western Australia are not part of the NEM. Their exclusion is due to the vast distance between their load centres and the interconnected electricity network across the NEM member States. 2 All monetary amounts in this paper are expressed in Australian dollars.
cap of $10,000/MW h, and a price floor of negative $1000. Retailers purchase in the pool market, but the eventual price paid by them will depend on what hedging contracts they have in place to give them their desired degree of price stability. Various market regulations exist to ensure security and reliability in the NEM.3 The NEM permits electricity to be traded over State borders, subject to physical transmission constraints. Currently, Queensland transmits considerable quantities of baseload power to the NSW market, whilst NSW and Victoria draw power from the Snowy Mountains Hydro-electric Scheme. Until mid-1990s, in Victoria, South Australia and Tasmania the four functions of generation, transmission, distribution and electricity retailing were undertaken within a single, vertically integrated, monopoly business. In NSW and Queensland, generation and transmission were contained in a single monopoly business, while distribution and retailing were undertaken by a number of businesses, each with a monopoly franchise, covering a specified geographical area within the State. During 1990s, the industry underwent a major restructuring with the objective of unbundling these four functions into separate businesses. Victoria and South Australia then sold their electricity businesses to the private sector. Although NSW and Queensland still retain State ownership of their existing generation assets, the private sector is encouraged to invest in new plant in competition with State generators. The retail sector is fully contestable in all States except
1
0301-4215/$ - see front matter & 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2008.09.084
3 A guide to Australia’s NEM can be found at: http://www.nemmco.com.au/ nemgeneral/000-0187.pdf.
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Tasmania, although State retailers in NSW continue to exist in competition with the private sector. Most of the current electricity generation capacity in NSW was built during 1980s. In the early 1980s, the generation reserve in NSW was well over 40%, even reaching nearly 55% in 1983 and 1984. As a result of this oversupply of capacity, no new baseload power station has been commissioned in NSW since Mt Piper in 1992, with the exception of a small (150 MW) plant at Redbank in the Hunter Valley. Over the same period, electricity consumption in NSW, as elsewhere in Australia, has experienced significant growth. The NSW generation reserve now has fallen to around 22%. The expected continuing growth in electricity consumption, albeit at a slower rate than that of recent experience, is likely to see it fall to around 15% by around 2103–14, the lower end of international best practice. Thus, in the absence of any major demand-side (downward) shifts, NSW will reach a point during the next decade when new baseload generation capacity will become necessary. It was in this context that the Inquiry was established, with the following terms of reference:
construction. These include the combined cycle gas turbine (CCGT) plant under construction at Tallawarra (private) and two open cycle gas turbine (OCGT) ‘‘peaking’’ plants under construction at Colongra (State-owned) and Uranquinty (private). Snowy Hydro Limited is jointly owned by the NSW, Victorian and Commonwealth Governments. It comprises 16 large dams and seven power stations in the Kosciusko National Park area. Its total generation capacity is about 3700 MW, and it predominantly meets the bulk of the peak and intermediate generation requirements of NSW. Non-hydro renewable energy currently accounts for 0.4% of the energy consumed in NSW. About 17 MW of wind power has been installed, with projects amounting to a further 540 MW under development. There is also one wave power generator which has a peak capacity of 0.5 MW. Renewable projects under development include two 30 MW bagasse co-generation plants and a solar thermal electricity plant being developed by Macquarie Generation at its Liddell power station. The latter is expected to generate the equivalent of 4.4 GW h annually through displacement of coal for pre-heating boiler feed water.
1. Review the need and timing for new baseload generation that maintains both security of supply and competitively priced electricity. 2. Examine the baseload options available to efficiently meet any emerging generation needs. 3. Review the timing and feasibility of technologies and/or measures available both nationally and internationally that reduce greenhouse gas emissions. 4. Determine the conditions needed to ensure investment in any emerging generation, consistent with maintaining the State’s AAA credit rating.
2.2. Transmission
The Inquiry received 74 written submissions and held meetings with 50 stakeholders. It was supported by three expert reports covering viable power technology options for NSW, gas availability in Eastern Australia, and securing private investment in new generation. The Inquiry report was released on 11 September 2007.4
In NSW, most of the transmission network is owned and operated by Transgrid, a State-owned corporation. Its assets comprise 12,440 km of high voltage transmission lines and 82 substations and switching stations. Transmission prices and revenues are regulated by the Australian Energy Regulator. 2.3. Distribution The NSW distribution network is divided between three Stateowned corporations: EnergyAustralia, Integral Energy and Country Energy. Their respective areas of operation are eastern Sydney and urban areas to its immediate north, western Sydney and urban areas to its immediate west and south and rural/regional areas. Distribution prices and revenues are regulated by the Australian Energy Regulator. 2.4. Retail
2. Current characteristics of the NSW electricity market 2.1. Generation Currently, NSW relies on coal-based thermal power generation for the bulk of its baseload electricity production, using pulverised coal-firing technology. Baseload power is also supplied through inter-connectors from the Snowy Mountains Hydro-electric Scheme and from Queensland. Whilst it would be possible to expand imports from Queensland, this would only be a viable option if there are substantial differences in fuel costs between the two states and if expansion of interconnector capacity were justified commercially. Neither of these situations is considered to be likely over the next decade. The current generation capacity in the NSW region of the NEM is about 12,600 MW, with the State-owned corporations owning all coal-fired power stations with the exception of the small Redbank station (Table 1). In addition to the one small privately owned gas-fired power plant at Smithfield, there are a number of gas-fired power stations currently either planned or under
The retail sector comprises businesses that purchase wholesale electricity in the NEM and sell it to end users. Businesses supplying energy to retail customers in NSW must hold an electricity supplier’s licence. There are currently 24 licensed electricity retailers, including the State-owned corporations EnergyAustralia, Integral Energy and Country Energy. NSW was the first state in Australia to introduce full retail competition for both electricity and gas in 2002. Consumers can, therefore, choose to enter into supply contracts with their preferred retailer under competitive or negotiated pricing arrangements. Alternatively, small customers may continue to receive their electricity supply from the ‘‘standard’’ retailer in their local area under regulated prices. The NSW Government, in common with all other Australian state and territory governments, has committed to the removal of retail price regulation in the electricity sector, when markets are shown to be sufficiently competitive.
3. Addressing the terms of reference 3.1. Term of reference 1
4
The Inquiry web site contains the full report, the expert reports, and all submissions received: http://www.premiers.nsw.gov.au/WorkAndBusiness/DoingBusinessInNSW/OwenInquiryIntoElectricitySupplyInNSW.htm.
The Inquiry reviewed a considerable body of work on demand and supply projections for electricity in NSW, and concluded on
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Table 1 Existing or committed generation in NSW Generator
Ownership
Year commissioned
Fuel
Munmorah Liddell Wallerawang Vales Point Eraring Bayswater Mt. Piper Redbank Bendeela Kangaroo Valley Smithfield Tallawarra Colongra Uranquinty
Delta electricity Macquarie generation Delta electricity Delta electricity Eraring energy Macquarie generation Delta electricity Babcock & brown Eraring energy Eraring energy Marubeni TRUenergy Delta electricity NewGen
1968–69 1971–73 1976–80 1978–79 1982–84 1985–86 1992–93 1999 1977 1977 1995 2009 2009–10 2009–10
Coal Coal Coal Coal Coal Coal Coal Coal Hydro Hydro Gas Gas Gas Gas
Total
Nameplate rating (MW)
700 2000 1000 1320 2640 2640 1320 150 80 160 160 440 660 660 13,930
Expected maximum energy capabilitya (GWh/annum)
Maximum technical capacity factora (%)
0b 13,000 6500 8700 20,800 20,800 10,400 1000 Negligible Negligible 1000 2300 300 300
0 74 75 75 90 90 90 76 – – 72 60 5 5
85,100c
a Maximum capacities, output and annual energy capability, on nameplate rating. The impact of recent drought conditions in NSW have not been taken into account. b Delta Electricity informed the Inquiry that a significant refurbishment would be necessary for the Munmorah power station in order to extend its life beyond 2012. Munmorah’s output has, therefore, not been included in this table. c The expected maximum energy supply capability of existing and committed power stations within NSW is at most 85,100 GWh/annum. This is based on the assumption that the maximum capacity could be sourced simultaneously from each power station.
the basis of these studies that the state would need to be prepared for additional baseload capacity from 2013–14, or shortly thereafter. In addition, submissions to the Inquiry were broadly in agreement on the need for and timing of such investment. Transgrid prepares an annual planning report setting out forecast energy consumption and maximum demand in NSW over a 10 year horizon, identifying future constraints in the network and providing options for their removal.5 These projections are used by NEMMCO in the preparation of its annual Statement of Opportunities, which considers the supply– demand balance, with a focus on peak demand in the NEM rather than baseload. Over the next decade, Transgrid estimates that electricity consumption in NSW will increase by an average of 1.8% per annum as compared with 2.5% per annum over the past decade.6 This decline in the rate of growth of consumption is largely due to the impact of energy efficiency initiatives and the public’s growing awareness of the environmental impacts of power generation based upon fossil fuel technologies. Since these offsets are factored into the forecasts, it must be new initiatives that will alter the projected path of consumption. With carbon pricing anticipated to be introduced into the power generation sector in 2010, it could be expected that the rate of growth of consumption will decline further. On balance, the risk-averse approach would be to recommend that preparation for a 2013–14 timeline be adopted, with the intention of delaying the process if the time horizon moves outwards. Depending on the technology, the lead-time for planning and building a new baseload power plant ranges from five to seven years, so the process should commence immediately.7
5
The latest report is: Transgrid, Annual Planning Report, 2008. Assuming that there are no new large industrial loads. 7 There are a number of sites that already hold the various regulatory and environmental instruments that would permit construction to commence at short notice, so these time frames can be reduced significantly if required. 6
3.2. Term of reference 2 The most technologically advanced, commercially viable, options currently available for the next tranche of baseload generation in NSW are CCGT and Ultra-supercritical Coal (USC). A CCGT plant has lower capital costs than USC technology, a shorter construction period, and about half the level of CO2 emissions per unit of power generated. However, the relative fuel cost advantage of coal over gas has, in the past, given coal a distinct commercial advantage for system baseload. NSW has vast coal resources, with estimated recoverable reserves of around 10 billion t. In 2005–06, the NSW coal industry produced 161 million t of raw coal of which around 30 million t was consumed by the State’s power plants. Due to its high ash content, coal destined for NSW power stations is not generally suitable for export, and hence its price reflects this limitation. It is also typically sold under long-term contracts (10–12 years), which limits the ability of producers to raise prices to netback world parity.8 The Inquiry was informed that the real weighted average coal price delivered to NSW power stations was $1.36/GJ for 2007–08 delivery, which equates to around $10/MW h of electricity generated. The submission of one of the State’s generators, however, quoted a delivered fuel cost of around $0.90/GJ. In contrast, the gas resource base of NSW is relatively underdeveloped, with existing supplies coming from sources where production was expected to decline from around 2012–14.9 However, there is significant potential for coal seam gas, known as coal seam methane (CSM), in a number of basins in Eastern Australia,10 many of which are already covered by exploration
8 Of course it also protects producers against sharp price falls in the international market. The long-term contracts typically contain price escalation clauses, but largely based upon domestic criteria. 9 Current gas demand in NSW is supplied by two transmission pipelines, from the Cooper Basin in South Australia and from the Gippsland Basin offshore Victoria. 10 NSW and Queensland in this context.
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licences. CSM production has grown significantly from around 5 PJ in 2000 to over 100 PJ in 2007. Over the same period, CSM proven and probable (2P) reserves have grown from around 200–4000 PJ (the vast bulk of it in Queensland). These are sufficient to underpin a significant increase in CSM production from 2009 to 2015 (up to 300 PJ per annum), but further growth in reserves will depend on the level of growth of demand. Clearly, there is little incentive for CSM producers to invest in upgrading potential gas resources to 2P if they are to remain in the ground unproduced for a long period of time. Compared with Queensland, the NSW 2P gas reserve is very modest. However, there are a number of projects in the early stages of production assessment in NSW, and potential gas developments will have the benefit over their Queensland counterparts of proximity to demand if future NSW baseload capacity is to be based upon gas technology. Eastern Australian gas is currently available at around $4/GJ, which equates to around $25/MW h of electricity generated. Whilst this is more expensive than coal on a MW h basis, the much higher capital cost of coal plant means that CCGT generators would have a lower total average cost than coal at below 50% utilisation. However, there is a significant degree of uncertainty around gas prices. Currently the Queensland CSM gas reserves are stranded and the gas price reflects this fact, but the prospect of exporting CSM as LNG could force domestic prices up to the much higher netback LNG price. The advent of carbon trading within Australia, however, would offset the cheaper fuel costs of coal technologies to (at present) an unknown extent. This uncertainty tends to make gas technologies the preferred choice for risk-averse investors, given their lower carbon footprint. Reducing coal technology’s CO2 emissions using carbon capture and storage could reverse this situation, but the enabling technology is still under development and is unlikely to be available outside of pilot plants until after 2020. Wind power displaces baseload, but currently the vast majority of installations in the NEM states are located in Victoria, South Australia and Tasmania. The Commonwealth Government is committed to a Mandatory Renewable Energy Target of a 20% share for renewable energy in Australia’s electricity supply by 2020, and the bulk of this is expected to be based upon wind technology.11 However, at present, the wind resource in NSW does not appear to offer opportunities comparable to those in these three southern states. Emerging technologies, such as geothermal and solar thermal, would not be commercially available within the required timeframe, but clearly have great potential for future additions to baseload, particularly in a carbon-constrained environment. Nuclear power is also a viable enabling technology but, despite its relatively good history on safety, has environmental and nuclear proliferation issues that would invariably cause long development delays due to public and political scrutiny in Australia. In addition, the regulatory environment for enabling Australia to become self-sufficient at all stages of the nuclear fuel cycle does not currently exist. Nuclear power would also require a significant carbon price in order to compete with coal or gas for baseload. It should be noted, however, that in his speech to the NSW Parliament on 9 May 2007, the Premier stated ‘‘there will be no consideration of nuclear energy for NSW whatsoever’’.
11 To permit greater precision, the target has been set at 45,000 GWh. The scheme will be phased out over the period 2020–30 as Australia’s carbon pricing regime matures.
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3.3. Term of reference 3 A carbon emissions ‘cap-and-trade’ scheme is scheduled to commence at a national level in Australia in 2010. Precise details of the proposed scheme have not been announced, but it is clear that the electricity generation sector will be included when the scheme starts. Thus, in the context of the NSW electricity sector and current technology options, the price of carbon permits will play a critical role in determining the relative competitiveness of coal and gas-based technologies following the introduction of the scheme. Whilst existing generators may receive a free allocation of emissions permits to cover some or all of their historical emissions, new investments may need to have to purchase permits to cover all of their emissions.12 Thus future investors in electricity generating plant in NSW must factor in the cost of carbon in assessing their commercial viability. With CCGT plants producing approximately half the CO2 emissions of USC plants, the cost of carbon will be a major element in the choice of investment technology for additions to baseload capacity. At present a number of key commercial parameters relating to a national carbon trading scheme are uncertain13:
The national emissions targets and associated dates for achieving such targets are vague;
The proposed carbon emissions cap for the electricity sector, and its transition path, are unknown;
The criteria for allocation of emissions permits to current emitters have not been specified; and
The penalty price, and any other penalties, for non-compliance have not been established. The high level of emissions market uncertainty tends to favour CCGT technology given its lighter carbon footprint, but other uncertainties surrounding capital and relative fuel costs will also be major determinants of the choice of technology.14 3.4. Term of reference 4 Under current market conditions, the private sector is very unlikely to invest in baseload generation in NSW given the dominance of the State-owned generators.15 Rightly or wrongly there is the perception that the NSW Government, via the Stateowned generators, may adopt investment criteria which are not solely commercially based. A possible scenario is given in Fig. 1, which illustrates the impact of uncertainty that Government policy may create if it pre-empts the market. Thus private investment in generation could be discouraged by the possibility it would be stranded by untimely Government investment (particularly where the latter has a portfolio of generation assets to assist it to offset the problem it has created). This cycle of 12 It is very unlikely that power generators will receive such a generous allocation of free permits as did their European Union counterparts when the European Union Emissions Trading Scheme commenced. 13 The Garnaut Climate Change Review was commissioned by the Commonwealth, state and territory governments to examine the impacts, challenges and opportunities of climate change for Australia. The final Report was delivered to the Commonwealth government on 30 September 2008. The Commonwealth has also produced a Carbon Pollution Reduction Scheme Green Paper that outlines its proposed measures for implementation of Australia’s emissions trading scheme. However, the design and scope of the scheme upon its introduction in 2010 remains far from clear. 14 Another uncertainty would be public reaction to any new coal-fired plant in NSW. It is likely that any proposal would be held up for a significant period of time by public opposition expressed through the NSW Land and Environment Court. 15 The State accounts for almost 98% of currently operating nameplate installed capacity in NSW.
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Private sector commits to invest in generator Once only Government invests to address perceived security problem
Leads to delay in private sector commitment
Government locked in to all generation investment
Private sector investment stranded by government investment
Private sector fears further government investment
Fig. 1. Uncertainty in government investment policy in generation. Source: TRUenergy
uncertainty could result in the Government being locked into making all future generation investment. To break this cycle, it would be necessary for the Government to make a credible commitment not to invest further in generation. The private sector will invest in generating capacity when wholesale prices and market-related conditions permit a decision based upon commercial behaviour. The current market structure in NSW, however, gives rise to a number of inhibiting factors and uncertainties that discourage private sector investment. This is particularly the case for additions to baseload, where there is the perception that investment behaviour of the State-owned generators could be determined by political, rather than commercial, criteria. This could give rise to excess capacity and hence a devaluation of generation assets. Since additions to baseload involve large, lumpy investments, the State generators with their portfolios of generating assets could adjust capacity accordingly. However, a new entrant could well be left stranded with costly surplus capacity. Investment in peaking plant is less of a problem, since its modular, smaller nature gives it a much greater flexibility in responding to changing prices and other market-related conditions. Thus the option is for either the State to undertake all future baseload investment itself or for the generation sector to be privatised and reliance placed upon investment by private investors operating within the competitive environment of the NEM. Effectively this transfer would reduce State borrowings by around $7–8 billion over the next decade, in addition to net sale proceeds of the assets. In the absence of such a sale, over the next 15 years, the State would also be required to invest in the order of $3–4 billion to retro-fit some existing power plants with carbon reduction technologies. Such obligations, particularly in a high risk industry such as electricity generation, could have an adverse impact on the State’s AAA credit rating with Standard and Poor’s, with its implications for the cost of future State borrowings.16 The Inquiry considered the electricity retail function to be comparable with a financial intermediary, much like an insurance 16 The high cost of the NSW Government’s capital works program is the major concern of Standard and Poor’s. Augmenting this with a substantial obligation for funding additional power generation plant, rather than using the sale proceeds from electricity privatisation to offset the cost of the capital works program, raises the spectre of a negative reaction from Standard and Poor’s.
company. However, the three State-owned retailers, which are also responsible for owning, operating and maintaining the distribution infrastructure, are currently hindered in their retail operations by an inability to expand both vertically and horizontally beyond their energy retailer functions. As a result, their competitors, unconstrained by Government policies, were undermining their customer base and, consequently, their market value. To bring them into line with their private sector counterparts, the State would be required to invest around $2–3 billion over the same period to permit investment in (for example) ‘‘peaking’’ plant, inter-state energy services, a gas resource base, etc. Transferring the State retailers to the private sector would release such funds to enhance the NSW Government’s capacity to deliver other services outside of the power sector. Retailers have a strong incentive to enter generation, particularly investing in ‘‘peaking’’ capacity as a hedge against extreme spot price volatility where the supply of hedge contracts may be limited. Essentially hedging is being ‘‘internalised’’ rather than relying on external counterparties. Conversely, generators have corresponding incentives to invest in retail. This form of vertical integration, creating what is known as ‘‘gentailers’’, has become a relatively common feature in ‘‘restructured’’ electricity markets around the world and thus transferring both retail and generation to the private sector could be expected to be more attractive to potential purchasers than the sale of just one or the other. Whether such a practice encourages competition is open to debate (see, for example, Bushnell et al., (2005)).
4. Recommendations Based upon the above rationale, the Inquiry made the following recommendations: 1. Divest the State of the retail arms of EnergyAustralia, Integral Energy and Country Energy. 2. Divest the State of the generation businesses of Macquarie Generation, Delta Electricity and Eraring Energy. 3. In the event that the Government does not wish to sell generation, then it should implement an appropriately structured long-term leasing of current generation assets. The State
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4.
5.
6.
7.
8.
would retain ownership of the assets, with operational and commercial control by the private sector. Actively monitor the progress of reforms to NSW planning, development approval and environmental licensing process to ensure that proposals for new generation capacity, and associated fuel supplies, are considered expeditiously, and in a cost-effective and predictable manner, without compromising the quality of environmental assessment. Support the planned review of the effectiveness of retail competition by the Australian Energy Market Commission in 2010, and consider the removal of regulated retail price caps at that time, should the review find effective competition in the NSW retail market. Encourage the Commonwealth Government to bring forward the timetable for establishing a national emissions trading scheme. At a minimum, the Commonwealth should resolve and announce: The national greenhouse gas reduction target and short-term caps and associated penalties. The basis for allocating emissions permits. Develop and implement clear and timely transitional rules for existing State-based greenhouse gas and emission schemes to the national emissions trading scheme (in the event of its introduction). Encourage and support energy efficiency initiatives where possible.
The first three of the above represent the major recommendations, with the remainder being either enabling or best practice supporting recommendations. At first sight, the third recommendation may appear to be redundant given the second recommendation. However, the Premier of NSW is on record as stating in Parliament on 9 May 2007 that ‘‘there will be no sale of electricity generation, transmission or distribution’’. Thus the third recommendation was included so that he would not be seen to be reneging on this undertaking. Nevertheless, the second recommendation would provide the optimal outcome in the view of the author. Transmission and distribution are highly regulated natural monopolies in NSW and thus, by implication, it was recommended that there be no change to the status quo.
5. Criticisms that followed release of the report As could be expected, a barrage of criticism was levelled at the recommendations of the Inquiry, particularly from the relevant trade unions and some green groups. What the author considers to be the four main lines of criticism are outlined below, together with the author’s response. 5.1. Criticism 1 The Inquiry recommended investment in coal or gas baseload plant(s) and ignored energy efficiency and renewables. 5.2. Response 1 The Inquiry recommended that NSW be ‘‘prepared’’ for investment in additional baseload. If enhanced energy efficiency, carbon pricing or renewables can offset increasing demand that would not present a problem. Investments can be postponed, but being ‘‘prepared’’ at least ensures that additional baseload capacity would be available when, and if, required.
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5.3. Criticism 2 Private retailers would have an incentive to sell more electricity and hence encourage emissions of CO2. 5.4. Response 2 Private retailers have that incentive now! In any case, the pricing of carbon emissions will make this concern redundant. 5.5. Criticism 3 The NSW Government can mandate no further coal plants if it retains ownership. Private industry may select coal because it is cheaper than gas. 5.6. Response 3 This criticism ignores the fact that private industry typically operates over shorter business horizons and higher discount rates than State entities investing in public goods. Gas plant can be built as modules, commencing with OCGT and then closing the cycle (to CCGT) when warranted by demand. Compared with coal plant, this gives private power plant investors lower up-front capital costs, an earlier revenue stream, and hence lower risk (than USC plant). However, coal technology may still be attractive for replacing older coal plant if it comes with free emissions permits. 5.7. Criticism 4 The price of electricity will rise following privatisation of generation and retail. 5.8. Response 4 This is probably true, since the industry is moving into a different era. Regulated prices for residential consumers will be phased out by 2013, provided there is evidence of a competitive retail sector in NSW. These prices are currently well below wholesale prices and realignment must be expected, although competition could offset some of this expected increase. In addition, the switch to gas will probably lead to price increases due to higher fuel costs, particularly if the domestic gas market has to compete with gas destined for export as LNG. Finally, carbon trading is intended to increase prices and hence modify consumer demand and encourage investment in energy efficiency, renewables and low-carbon technologies. It must be remembered, however, that since only 40–45% of the retail cost of electricity comes from its wholesale price, with transmission, distribution and retailing collectively accounting for the balance, the ‘‘pass-through’’ will be correspondingly lower.
6. The government’s decision Early in 2008, the NSW Government announced that it would sell the State-owned retailers and implement long-term leasing of the State generation assets, as recommended in the report. However, trade union pressure on a significant number of Labor Members of Parliament threatened to defeat the enabling bill in Parliament unless the support of the main opposition Liberal Party could be guaranteed. Although the leader of the opposition was on record as favouring the sale of the State’s power sector assets, the political reality was that they would not support the government’s
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bill when it was presented to Parliament on 28 August 2008. Faced with certain defeat on the floor of Parliament, the government withdrew the bill.17 Immediately, it announced that Parliamentary approval for the sale of the retailers was not necessary and that the sale would proceed. In an attempt to regain some semblance of Government cohesion, the Premier then attempted to reorganise his Cabinet but was thwarted by internal Party opposition. On 5 September the Premier resigned. Whilst the sale of the state retailers is still on the Government’s agenda, sale or leasing of the generation assets appears to have been postponed indefinitely (or at least until the Liberal Party gain office).
17 The news brought an immediate response from Standard and Poor’s, placing the State under credit watch.
Acknowledgement The author wishes to acknowledge the helpful comments of two referees on an earlier draft of this paper. References Bushnell, J., Mansur, E.T., Saravia, C., 2005. Vertical arrangements, Market structure, and competition: An analysis of restructured US Electricity markets, Centre for the study of energy markets, Working paper 126, University of California Energy Institute. Industry Commission, 1991. Energy generation and distribution, Report no. 11, three volumes, AGPS, Canberra.