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2022 | OriginalPaper | Buchkapitel

Australia’s National Electricity Market: An Analysis of the Reform Experience 1998–2021

verfasst von : Paul Simshauser

Erschienen in: Revisiting Electricity Market Reforms

Verlag: Springer Nature Singapore

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Abstract

Australia’s National Electricity Market (NEM) commenced in 1998. The centrepiece of NEM reforms was the restructuring of vertical monopoly electricity utilities and the creation of an energy-only, gross pool wholesale market and associated forward market. For most of the past 20+ years, NEM has displayed consistent economic and technical performance. But missing policies relating to climate change, natural gas and plant exit produced results that tested political tolerance in 2016–2019. However, as with prior episodes of high prices, market participants responded—most recently—with a renewable investment supercycle. Prices have since reverted, but power system security remains challenging as the plant mix changes.

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Fußnoten
1
All financials are expressed in AU$ unless specified otherwise.
 
2
As Pollitt (2004) notes, vertical and horizontal restructuring was completed by 1981 and enabling legislation enacted in 1982.
 
3
The exception to this was the Queensland Electricity Commission, which at that time had the fifth lowest electricity prices in the world. See Booth (2000).
 
4
Following a serious downgrading, a Labour Victorian state government was virtually forced to privatise its newest power station as a result.
 
5
The Productivity Commission was then known as the Industry Commission.
 
6
In 1992, the federal government established a committee to investigate a national competition policy framework. The committee handed down its blueprint for the implementation of a formal competition policy in August 1993, with the report becoming known as ‘The Hilmer Report’, after the committee chair, Professor Fred Hilmer.
 
7
This included four portfolio generators in Queensland, four in New South Wales (NSW) (including Snowy Hydro), five in Victoria, three in South Australia.
 
8
This included two in Queensland, six in NSW, one in the Australian Capital Territory, five in Victoria, and one in South Australia.
 
9
The NEM’s fifth region, Tasmania, is somewhat complicated by the fact that it only joined NEM in 2006, and for a range of reasons including politics and scale, remained a largely monopoly regional market.
 
10
It also ensured retailers had substantial asset backing.
 
11
Networks have stable regulated returns, whereas retailers exhibited increasingly volatile results—a natural outworking of retail contestability and the extreme volatility of wholesale prices in an energy-only market setting, although in New Zealand, forced divestiture seemed to produce very little benefit and a loss on competition (Nillesen and Pollitt 2011, 2019).
 
12
Indeed, the states of Queensland and NSW consolidated their own retail supply businesses from nine down to just four before or during privatisation processes in 2007 and 2011, respectively. There were originally three franchise retailers in Queensland and six in NSW. In Queensland, Origin Energy and AGL Energy purchased the retail businesses. In NSW, Origin Energy and Energy Australia purchased the retail businesses.
 
13
Forward integration also became the dominant strategy amongst incumbent generators—many of which have formed large vertical businesses.
 
14
Australia’s ‘Big Three’ are AGL Energy, Origin Energy, EnergyAustralia. Two other large integrated rivals are Alinta Energy and Snowy Hydro (and retail business Red Energy). Godofredo et al. (2017) noted the term Gentailer was commonly used in Great Britain, Australia, and New Zealand.
 
15
See, for example, the Australian Competition and Consumer Commission’s 2018 ‘Restoring Electricity Affordability and Australia’s Competitive Advantage’ Report, AER’s 2011 State of the Energy Market Report, and, in the case of Great Britain, see Ofgem’s 2014 State of the Market Assessment Report.
 
16
See the Treasury Laws Amendment (Prohibiting Energy Market Misconduct) Bill 2019), known as the ‘Big Stick Bill’.
 
17
An electricity transmission line linking generation and retail load is an example of bottleneck infrastructure.
 
18
Vertical integration is an organisational form of last resort that occurs in response to non-trivial market frictions and, in most circumstances, is welfare enhancing—even when horizontal issues take on a considerable importance. Once the long list of explicit and implicit assumptions underpinning standard economic models are relaxed, boundary changes are likely when firms face hazards associated with asset specificity, incomplete forward markets, bounded rationality, asymmetric information, and regulatory and policy uncertainty. When non-trivial hazards exist in relation to ex ante investment commitment and the ex post performance of highly specific assets, vertical integration will invariably achieve ‘more adaptive, sequential decision-making procedures’ than anonymous spot and forward market transactions, especially as market conditions change.
 
19
That is, to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers of electricity with respect to price, quality, safety and reliability, and security of electricity supply.
 
20
Although, as MacGill (2010) pointed out, the market operator produces a very transparent 40 h pre-dispatch forecast, which is continuously updated.
 
21
In Victoria, AEMO undertakes transmission planning. This is unique to Victoria.
 
22
The approval of transmission investments is subject to a net-benefits test, known as the RIT-T, the ‘Regulatory Investment Test—Transmission’.
 
23
In theory, from a power system planning perspective, the overall objective function is to minimise \(VoLL \times USE + \sum_{i = 1}^n {c\left( R \right)\left| {VoLL \times USE + c\left( {\hat{R}} \right)} \right.~} = 0\), where \(VoLL\) is the value of lost load, \(USE\) is unserved energy, and where \(c\left( R \right)\) is the cost generation plant, and \(c\left( {\hat{R}} \right)\) is the cost of peaking plant capacity. Provided these conditions hold, it can be said that there is a direct relationship between reliability and the market price cap. An alternate expression where the reliability criteria are based on loss of load expectation is \(LoLE = CONE/VoLL\), where CONE is the cost of new entry. For an excellent discussion on the relationship between a market price cap and reliability criteria, see Zachary et al. (2019).
 
24
Fixed and sunk costs in energy-only markets are, in theory, recovered during price spike events. But participants are unable to optimise the frequency and intensity of price spikes (Cramton and Stoft 2005). Moreover, market price caps are frequently set too low (Batlle and Pérez-Arriaga 2008; Joskow 2008; Petitet et al. 2017; Bublitz et al. 2019; Milstein and Tishler 2019) in which case a stable financial equilibrium can only be reached if the power system is operating near the edge of collapse (Bidwell and Henney 2004; Simshauser and Ariyaratnam 2014).
 
25
This included 230,000 MW in the US; 13,000 MW in Australia; and more than 6,000 MW of new plants in the United Kingdom. See Joskow (2006), Finon (2008), and Simshauser (2010) for details.
 
26
See, for example, Chester (2006), Anderson et al. (2007), Howell et al. (2010), and Simshauser et al. (2015).
 
27
Three broad policy remedies are typically suggested to deal with the missing money and risks to timely investment, viz. (i) introducing capacity markets or strategic reserves, (ii) raising the market price cap, or (iii) introducing additional operating reserves. On capacity markets see (Bidwell and Henney 2004; Green and Staffell 2016). On setting higher VoLL and vertical integration, see, for example, Joskow (2006), Finon (2008). and Simshauser et al. (2015). On increasing the requirement for operating reserves and enhancing reliability of supply, see Hogan (2005, 2013). Hogan (2013) noted there is no simple way to observe and measure delivery in capacity markets. Conversely, Cramton and Stoft (2008) observed that even if capacity is overbuilt as a result of capacity mechanisms, the incremental cost to consumers is small because excess ‘peaking plant’ is the cheapest form of capacity (viz. an extra 10% of peak capacity may increase consumer costs by, say, 2%). Additionally, Spees et al. (2013) observed that on balance capacity markets in the United States have delivered good results in that they met their objective function, mobilised large amounts of low-cost supply including demand response, energy efficiency, transmission interconnection, plant upgrades, deferred retirements, and environmental retrofits.
 
28
Performance improvements included average cost, price, plant availability, and reserve margins (see Simshauser 2005). In more recent research, the wholesale market was one of the few areas of the electricity market that was performing well. From mid-2016 however, market performance deteriorated significantly.
 
29
On 20 November 1997, Australian Prime Minister Howard announced that the Commonwealth would work with the state governments to ‘set a mandatory target for electricity retailers to source an additional 2% of their electricity from renewable energy sources by 2010’ and ‘Australia also believes that an international emissions trading regime would help minimise costs of reducing emissions’. (see Parliament of Australia at: http://​parlinfo.​aph.​gov.​au/​parlInfo/​search/​display/​display.​w3p;query%3DId%3A%22chamber%2Fhansardr%2F1997-11-20%2F0016%22 (accessed April 2020).
 
30
The reserve margin adjusts for the firmness of the VRE but treats the plant stock as if a perfect transmission system exists.
 
31
I use the Australian dollar to US dollars exchange rate of $0.75.
 
32
The South Australia black system event was not a resource adequacy/reliability problem, but a system security issue (i.e. an unstable system in which a voltage collapse led to plant disconnecting, with the rate of change of frequency falling faster than supply and demand resources could respond to.
 
33
An important feature of the NEM is the ability of the market operator to step in and procure additional resources if the reliability standard is forecast to be breached. These emergency powers have been utilised over time, and have served the market well. Under the rules, they are triggered up to 9–12 months in advance if forecast lost load is expected to breach the reliability standard. Sources of supply are typically demand response (closing the gap between the value of lost load and the market price cap) and out-of-market emergency generation packs (e.g. diesel gensets).
 
34
Including some generators that detuned governors in response to conflicting regulatory signals.
 
35
NEM’s Frequency Operating Standard does not place any specific requirement or limitation on the system operator, AEMO, as to how frequency should be maintained within the normal band, AEMO is in effect free to select the appropriate mix and quantity of services to procure. Currently, this includes frequency regulation and three forms of frequency contingency services (i.e. 6 s, 60 s, 5 min). Apart from increasing the quantity of FCAS Regulation, AEMO has not chosen to augment its services. The author sponsored a rule change to add fast frequency and operating reserves to the FCAS suite.
 
36
This occurred in 2012 with an average VRE market share of 26%, maximum VRE for a single day was 68%, and more than 20 days were higher than 50% market share.
 
37
In my prior role as Director-General of the Queensland Department of Energy and Senior Official to COAG Energy Council, I had argued for a review of FCAS quantities (viz. an increase in regulated FCAS demand, and a localisation of some component of that demand) from April 2017. In a note to stakeholders on 3 October 2018, AEMO advised that ‘Regulation FCAS’ volumes have not been revised for many years, over which time significant system changes have occurred; less governor-based frequency support and increased penetration of intermittent generation are most notable’. Regulated FCAS quantities were set in 2004 when the NEM had no intermittent renewable resources.
 
38
In NEM, the FCAS is determined dynamically in each 5 min interval. The FCAS is also procured ‘globally’ across regions subject to no network congestion. In periods of higher variability, FCAS regulation on procurement automatically rises from the typical set point of 130 MW to as much as 230 MW (in 60 MW increments) to maintain frequency. Threshold quantities of FCAS contingency (6 s–, 60 s–, and 5 min–spinning reserves) are based on the single largest contingency event—the potential loss of the largest generating unit and when combined with FCAS regulation typically adds to about 900–1,000 MW.
 
40
The fault related to control systems configurations, which triggered disconnection after 2 min of continuous voltage dips (which in hindsight, the wind farms should have been able to ride through).
 
41
NEM Rule 4.3.1 states (amongst other things) that the system operator should ‘initiate action plans to manage abnormal situations or significant deficiencies which could reasonably threaten power system security’. Deficiencies are noted without limitation, viz. (i) power system frequency and/or voltage operating outside the definition of a satisfactory operating state, and (ii) actual or potential power system instability.
 
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Metadaten
Titel
Australia’s National Electricity Market: An Analysis of the Reform Experience 1998–2021
verfasst von
Paul Simshauser
Copyright-Jahr
2022
Verlag
Springer Nature Singapore
DOI
https://doi.org/10.1007/978-981-19-4266-2_4