18 January, 2018
The Australian energy market is currently undergoing a period of profound change. This article serves as a brief introduction to Australia's east coast National Electricity Market (NEM) and the impact of recent events on it and its future, and the causes of higher electricity and gas prices. Its aim is to demystify the current political rhetoric surrounding energy policy in Australia.
Introduction
As in other advanced economies, in Australia the dominance of centralised thermal electricity generation (coal-fired (73 per cent of supply) and gas-fired (seven per cent of supply)) is being challenged by increased investment in renewable generation incentivised by emissions reduction policies. Unlike some other advanced economies, Australia has some of the best conditions for solar and wind power generation in the world, and should be able to achieve relatively efficient renewable power generation.
Nevertheless, there are a number of factors that have raised concerns about energy security and affordability, and the state of the NEM: the fact that the renewable energy industry is still developing; the loss and planned further withdrawals of significant levels of synchronous generation; and a black system event affecting the entire State of South Australia in September 2016 and load shedding in December 2016. These issues have also brought into focus the need for a clear energy policy.
The changes in the supply side of the electricity industry are occurring at the same time as Australia moves to being the world's largest exporter of LNG, with historic levels of LNG exports under long-term contracts. This, coupled with several state-based moratoriums on new onshore gas exploration, is perceived1 as resulting in higher gas prices.
In this context, there has been no shortage of ideas as to how to overcome system security and wholesale electricity price pressure. However, there are a number of challenges that need to be overcome to implement them, including:
- the existence of current economic disincentives to investment in new gas peaking plant to smooth the transition between thermal and renewable generation;
- the need to increase interest in innovative technologies such as utility-scale battery storage to ensure system security and stability; and
- frequent changes in energy policy and the inability to achieve a cohesive energy policy between the State and the Federal Governments.
What is the National Electricity Market?
Overview
The NEM is one of the world's longest interconnected electricity networks, spanning approximately 5,000 kilometres and six Australian jurisdictions: the Australian Capital Territory and the States of New South Wales, Queensland, South Australia, Tasmania and Victoria. It supplies approximately nine million customers per year and has a total generating capacity of approximately 52.5 GW (as of April 2017).
Spot market and hedging transactions
The NEM is a spot market in which fiscal arrangements between generators and customers are separated from physical supply arrangements.
Generators are dispatched in five-minute trading intervals by the Australian Energy Market Operator (AEMO) in merit order based on bids submitted in pricing bands and forecast electricity demand. Renewable generators such as solar and wind farms participate in central dispatch (in a limited manner) – their generation may vary but they are required to comply with turndown instructions from AEMO.
Wholesale electricity customers pay a spot price to AEMO for each megawatt hour of electricity consumed, which then pays the spot price to generators for each megawatt hour of electricity generated. The spot price is calculated on a half-hourly basis as the average of the price of the last megawatt hour to be dispatched by AEMO in each trading interval within that half-hourly period.
However, the National Electricity Rules (Rules) have recently been amended to reduce the 30-minute financial settlement period in the NEM to five minutes to match the five-minute dispatch interval. This amended rule is anticipated to improve NEM pricing signals for fast response generators such as battery storage projects attached to intermittent renewable generators. This change will commence on 1 July 2021, with some transitional arrangements commencing on 19 December 2017.
As the spot price can fluctuate significantly between settlement periods and regions (i.e. the various States) in the NEM, many generators and customers separately enter into OTC derivative transactions to manage spot price risk2. These transactions typically take the form of swaps and caps (and some swaptions) documented using the ISDA 2002 Master Agreement or a bespoke power purchase agreement (PPA).
Although short-term hedges are relatively common, there has recently been an increased willingness for large electricity retailers to offer longer-term contracts to renewable generators to 31 December 2030. This is the date on which Australia's Renewable Energy Target (RET) scheme (and the renewable generator's right to create and trade large-scale generation certificates (LGCs) created under that scheme) closes.
Our insights: These longer-term contracts and the ability of renewable generators to create LGCs are highly significant for the bankability of new renewables projects. Although LGCs can be traded independently of the generator's electrical generation, retailers are often willing to offer a bundled price for "black" electricity and "green products" such as LGCs.
Given the number of policy proposals developed in response to recent developments in the NEM (discussed later in this article), there is a high probability of significant changes to the legal framework applying to generators, including the introduction of a generator reliability obligation (requiring intermittent renewable generators to pair with dispatchable energy sources such as battery storage or gas-fired generators) and new "green product" schemes.
The change in law clauses in PPAs must be sufficiently robust to properly allocate the risks and costs of these changes in law as between the generator and offtaker. PPAs should also deal with the likely ability of renewable generators to create new "green products" in the future, and in particular, whether the generator must sell those to the offtaker at zero cost (as part of a bundled price PPA).
Key regulators
As a market essentially created by subordinate legislation, the effective performance of the NEM relies on the interplay between a series of government bodies, including the following:
- Council of Australian Governments (COAG) Energy Council – comprising Commonwealth (i.e. federal), state and territory energy ministers, the COAG Energy Council provides a forum to initiate, develop and monitor the implementation of national energy policy reforms where cooperation is required between the Commonwealth and state and territory governments;
- Energy Security Board (ESB) – a body established by the COAG Energy Council to coordinate the implementation of the recommendations from the recently-released Finkel Report (discussed later in this article) and to provide whole of system oversight for energy security and reliability;
- Australian Electricity Market Operator (AEMO) – the body responsible for, among other things, electricity market functions (including the operation of the spot market and central dispatch process), NEM system operations and national transmission planning;
- Australian Energy Market Commission (AEMC) – the body responsible for making the Rules, which are the principal piece of subordinate legislation that governs the operation of the spot market and central dispatch processes, power system security, network expansions and planning and meting. The AEMC also advises the COAG Energy Council on energy reform;
- Australian Energy Regulator (AER) – which provides economic regulation of transmission and distribution network service providers and monitors compliance with the Rules; and
- other State and Territory regulators (e.g. the Queensland Department of Energy and Water Supply) – which are responsible for administering other relevant electricity legislation which may contain other approval requirements (e.g. to obtain a generation authority under the Electricity Act 1994 (Qld)).
Our insights: The regulatory landscape of the Australian renewable energy market is complex, with regulators potentially adopting different solutions to complex problems or novel solutions presented by project proponents. Maintaining a good working relationship with each of the regulators interacting with generators on a day-to-day basis (AEMO, AER and State bodies) is critical to meeting project development time frames and when operating the project.
The Rules are a complex, technical and lengthy instrument which are often supported by guidelines developed by the AER and AEMO (e.g. the Network Service Provider Registration Exemption Guidelines). Regulators are generally willing to consider a project proponent's interpretation of the Rules in novel situations, but individual exemptions for a project proponent from any requirement of the Rules (as opposed to class exemptions set out in those Guidelines) in "grey areas" are often not forthcoming.
It is therefore important to understand the full regulatory (including exemption), technical and policy landscape to ensure that efficient, commercial and technically sound solutions are developed in new renewable energy projects.
Western Australia and Northern Territory markets
For completeness, we note the State of Western Australia and the Northern Territory operate separate electricity markets (e.g. Western Australia operates a capacity-based wholesale electricity market) to the NEM and are subject to significantly different regulatory frameworks and market structures. In addition, in contrast to the NEM, they have not been subject to impacts such as gas supply issues or reduced generation affecting wholesale prices.
Current state of the NEM
Generation composition
In 2015-16, the NEM was powered by the following fuels3:
FUEL SOURCE | REGISTERED CAPACITY | OUTPUT SUPPLY |
---|---|---|
Coal | 52% | 73% |
Gas | 19% | 7% |
Hydro | 15% | 10% |
Wind | 7.5% | 6% |
Solar | 6.5% | 4% |
Recent pressure to move away from coal-fired power has been motivated by a goal to reduce Australia's carbon emissions, with the energy sector responsible for one-third of those emissions (mainly due to reliance on high emitting coal-fired generation). To achieve this, Australia has made an international commitment to reduce its total carbon emissions by 26-28 per cent below 2005 levels by 2030, and has also made national abatement commitments.
Australia's current national emissions reduction policy involves:
- the Commonwealth purchasing emissions reductions from businesses through an Emissions Reduction Fund; and
- requiring that the nation's largest emitters do not increase their emissions above business-as-usual levels and offset the reductions purchased.
Significant interest in utility-scale solar PV facilities was recently kick-started by an A$86 million investment into the development of solar farms in the NEM by the Australian Renewable Energy Agency (ARENA) in its large-scale solar photovoltaics competitive funding round. ARENA was established to increase the competitiveness of renewable energy in Australia by funding projects that have met feasibility and commercialisation requirements, in exchange for knowledge sharing. ARENA has also recently committed to funding demand response pilot projects (with a total capacity of 200 MW).
Battery storage does not currently play a significant role in the NEM. However, the rapidly declining costs of battery technology and its ability to complement renewable generation has received significant interest in recent times. This is also coupled with the likely impact of reliability obligations that will be "paired with" variable renewable generation. For example, Tesla and Neoen (a French renewables company) recently completed construction of a 100 MW battery storage system to be paired with the Hornsdale Wind Farm in South Australia.
Our insights: We see battery storage playing an increased role in the NEM in the future, both when paired when renewable generators and when providing ancillary services to the system. However, there are significant regulatory and commercial challenges involved with retrofitting a battery storage system to an existing renewable generator.
Despite their goal of being technology-neutral, the Rules have not been written in a manner that facilitates the import and export of electricity to and from batteries in a "behind the meter" style arrangement. We expect further developments on this front and a number of Rule changes. Close attention will need to be paid by regulators and industry alike to ensure that battery storage is given the chance to fully participate in the NEM.
Challenges facing the market
As mentioned above, like other markets around the world, the NEM is facing a number of challenges, including:
- forecast flat demand over the next 20 years in most regions, in part due to increasingly efficient electrical appliances;
- the increased installation of distributed rooftop solar PV generation by both domestic and business/industrial customers and flow-on effects of this trend for network design and the legacy effect of State based schemes that resulted in long-term high cost feed-in tariffs for the electricity exported from small-scale solar systems into the NEM – these schemes have been wound back but continue to impact on the market;
- an aging thermal baseload generation fleet that is increasingly being retired (e.g. Alinta closed the Northern Power Station in March 2016, Engie closed the 1,600 MW coal-fired Hazelwood Power Station in March 2017 and AGL has announced plans to close the 2,000 MW Liddell Power Station in 2022), without replacement by similar levels of baseload generation;
- the price of gas has risen significantly over the last two to three years, which reflects the shift in gas prices associated with the reduced availability of gas to the domestic market – this has not been assisted by several state-based moratoriums on new onshore gas exploration;
- the integration of utility-scale renewable generators (primarily wind and solar PV) and battery storage technology while maintaining sufficient levels of power system stability and security: the Australian regulatory system for transmission and distribution networks tends to encourage this to be considered on a connection by connection basis, rather than a system wide basis; and
- frequent changes to Federal government energy and climate change policies, coupled with State-based renewable energy targets that are significantly higher than those under the Federal government policies.
In particular, the rise of non-dispatchable variable generation renewable projects (which only generate while the wind is blowing or the sun is shining) has led to the NEM having a reduced capability to continue supplying electricity to consumers in the event of shocks to the network, such as the loss of transmission network assets during severe weather (as happened in the State of South Australia in September 2016, as discussed later in this article).
The challenges have also all led to a two to three year period of increasingly high wholesale power prices for residential and business consumers (after 10 years of relatively flat wholesale electricity prices). This has been particularly contentious and been the subject of extensive political commentary and action taken to encourage cost reductions in the wholesale market – including the Australian Competition and Consumer Commission (ACCC) inquiry on retail electricity pricing4, and the action taken by the Queensland government to direct its state-owned generators to take action to reduce power prices.
We are now seeing large industrial consumers considering entering into corporate PPAs with generators to manage their exposure to high prices, while consumers are continuing to install rooftop solar PV to reduce the load they draw from the NEM (and consequently, their electricity bills).
Our insights: These challenges are not unique to Australia and are currently being experienced in a range of other advanced economies.
However, it is notable that these challenges are being experienced in a country with ample solar resources (Australia is a world leader in the adoption of rooftop solar PV), a booming LNG export market (but without concurrent increases in gas supplies, leading to a tightening gas market), and other high-quality natural resources (e.g. coal, gas and uranium) capable of fuelling a baseload generation fleet.
Unfortunately, there is no quick fix for these issues. State-based moratoriums on onshore gas exploration have meant the ability of gas-fired power stations to smooth the transition from a coal-fired nation to a renewable energy nation has been significantly diminished, at the expense of industry and consumers alike.
Renewable Energy Target as a driver for investment in renewable generation
A key driver for renewable energy investment in the NEM has also been the Commonwealth Government's RET. In 2015, this target was revised in a bipartisan agreement between the major political parties to be 33,000 GWh per annum of generation from renewable sources by 2020 (with lower targets ramping up to that figure in preceding years), being approximately 23.5 per cent of Australia's electricity generation. Until the bipartisan agreement on the RET, Australia had experienced a dearth of investment in renewable generation as ongoing policy debate created significant uncertainty for investors.
The RET is apportioned among retailers and wholesale energy purchasers in proportion to their total annual wholesale energy acquisitions. Liable entities meet their liability by acquiring LGCs that are created by accredited renewable energy generators for each MWh of electricity purchased, failing which they must pay a penalty of A$65/MWh (non-tax deductible) for each MWh that they fall short of.
Commentators have suggested that an additional 5,000 MW of renewable capacity (measured against 2015 installed capacity) will need to be installed in Australia by 2020 in order to meet this target.
In addition, State and territory renewable energy target schemes range from support for the Commonwealth RET (e.g. in New South Wales) to policy targets (e.g. 50 per cent by 2030 in Queensland) and legislated targets (e.g. 100 per cent by 2020 in the Australian Capital Territory). Both Victoria (650 MW) and Queensland (400 MW) are currently conducting reverse auctions for long-term offtake contracts to further develop new renewable generation.
Our insights: The RET scheme has undoubtedly been successful in increasing the levels of renewable energy generation in Australia since its introduction in 2001. However, we see liable entities offering flat or declining prices for LGCs after 2020, being the date on which the RET will be fixed at 33,000 GWh until 31 December 2030.
This means that a new mechanism will be required after 2020 if generators are to derive a secondary revenue stream from creating renewable energy. One such potential mechanism is the National Energy Guarantee that may involve a trading scheme among retailers (as discussed later in this article).
However, with the increasing reduction in costs of developing renewable generators and sustained high wholesale electricity prices, we think that renewable generators could become cost-competitive with baseload generators for the first time (so as to not require the support of a certificate scheme in order to be economical and profitable to operate). As a result, notwithstanding proposed policy changes and the variable nature of the generation, we expect to see increased deployment of renewable generators over other technologies (including fossil fuel technology).
Recent developments in the NEM
South Australian Black System Event
The State of South Australia has become increasingly reliant on renewable energy. In addition, the closure of a coal-fired power station at Port Augusta meant that limited dispatchable, gas-fired generation capacity was available in the State in September 2016.
On 28 September 2016 South Australia experienced a "black system" event – the first state-wide blackout since the creation of the NEM. The black system event arose as a consequence of extreme weather which caused significant damage to transmission network infrastructure, creating voltage instability.
That instability tripped a number of wind farms offline, and caused several others to reduce output, and the AC Heywood Interconnector between South Australia and Victoria (used to transfer electricity across state lines/NEM regions) to exceed its operating limits and also trip offline, leading to a black system event affecting the entire state (approximately 850,000 consumers).
The black system event sparked a national conversation concerning the security and reliability of the NEM and the place of renewable energy in the Australian generation mix. It culminated in the commissioning of an Independent Review into the Future Security of the NEM (Finkel Report) by the COAG Energy Council by an expert panel led by Australian Chief Scientist Dr Alan Finkel AO.
The Finkel Report
The Finkel Report was released in July 2017. It sets out a number of recommendations which seek to deliver four key outcomes: increased security, future reliability, rewarding consumers and lowering carbon emissions. Its recommendations include:
- the adoption of a clean energy target (CET) to drive investment in low emissions generators across Australia;
- the introduction of a package of energy security obligations, including inertia requirements in each region or sub-region of the NEM, generator fast frequency response capabilities, and a wholesale update to connection standards;
- a shift towards a market-based mechanism for procuring fast frequency response services where there is a demonstrated benefit in doing so;
- the implementation of a generator-reliability obligation to ensure that each region of the NEM retains adequate dispatchable capacity; and
- giving AEMO a "last resort" power to procure or enter into commercial arrangements to have gas-fired generators available to maintain reliable supply (but without a broader shift to a capacity market).
Our insights: The Finkel Report was widely seen as an opportunity to reset Australia's often fractious energy and emissions policy debate. Notably, it did not recommend any major reform to the operation of the wholesale electricity market. Nor did it contain significant detail on a number of items that we expected to feature significantly given the surrounding press coverage and political environment (e.g. in relation to the adoption of five-minute trading intervals, which was nevertheless separately progressed by the AEMC).
However, with a number of recommendations also requiring further analysis to be performed and work to be done by the AEMC and AEMO, the Finkel Report was very much a starting point and a blueprint for future reform, rather than a complete solution to the challenges facing the NEM.
The Clean Energy Target becomes the National Energy Guarantee
Chief among the Finkel Report's recommendations was the introduction of a CET by 2020. The CET was intended to assist Australia in reaching its Paris COP21 emissions reduction target of 28 per cent by 2030 based on 2005 levels.
The CET was expected to operate in a similar manner to the existing RET scheme and was considered a pragmatic policy compromise given previous statements by the Australian Prime Minister ruling out the introduction of an emissions intensity scheme or an emissions trading scheme (reflecting the fractious energy policy debates experienced in Australia over the past decade).
However, on 17 October 2017, the Commonwealth Government announced that it would introduce a National Energy Guarantee (NEG) in place of the CET. The NEG would consist of an obligation on electricity retailers to meet the following guarantees:
- a reliability guarantee to deliver certain levels of dispatchable generation capacity, as determined by the AEMC and AEMO; and
- an emission guarantee to deliver emissions reductions, as determined by the Commonwealth Government and enforced by the AER.
In modelling prepared to support the NEG, the Energy Security Board found that adopting the NEG would lead to a fall in wholesale electricity prices by 23 per cent by 2023 (being 30 per cent lower than in a business-as-usual case) and the renewables share of total output by 2030 would be approximately 36 per cent, of which approximately 28 per cent would be intermittent generation.
At a meeting of the COAG Energy Council on 24 November 2017, the Commonwealth and a majority of the States/Territories voted to support further extensive work on the design of the NEG, including consultation in early 2018.
The COAG Energy Council is due to next consider the design of the NEG in April 2018.
Our insights: The adoption of the NEG by the Commonwealth Government and the States would represent a significant breakthrough after a decade of significant debate on Australia's energy and emissions policy. However, the NEG is still subject to detailed design work, final agreement in COAG, and adoption in legislation. This process may yet prove to be challenging as the current governments of South Australia, Queensland and the Australian Capital Territory appear to favour an emissions intensity scheme or CET.
The mechanism that has been proposed for the implementation of the NEG contemplates the retailers relying on the energy contracts between the retailers and the generators. We have concerns about how this will operate given the extent of the derivative market in the NEM.
Previous emissions policy uncertainty, associated in particular with a price on carbon introduced by the Clean Energy Act 2011 (Cth) (now repealed) and the precise MWh target for renewable generation under the RET scheme, all led to a significant decline in investment in new renewable energy facilities. It will be important for industry to participate fully in the consultation to be undertaken by the ESB on the design of the NEG to ensure it provides the certainty required to underpin significant investment in new generation.
In summary
This article provides a brief overview of the NEM, the challenges it faces, and the impact of recent events on its future. Innovative technologies and new policies offer a path forward from the current state of play, which has been marked by high power prices, limited but growing investment in renewable generation and difficult policy debates. However, with increasing interest in and levels of investment in utility-scale renewable facilities and battery storage in the last 12-18 months, these challenges are by no means insurmountable, and it is hoped that the awakening to the need for policy certainty will allow Australia to exploit its solar and wind resources.
Co-Author: Tristan Shepherd, Associate.
1.We say perceived because the reporting of these issues tends to be incomplete. For example, the higher gas prices are an eastern seaboard dynamic, with the eastern seaboard LNG projects being coal seam methane projects in Queensland – projects that would not have been developed but for overseas buyers of LNG entering into long-term LNG SPAs, and that were developed without a domestic gas reservation requirement at a policy level. As such, the debate and reporting has been less nuanced than the facts require.
2. The current mark cap price is A$14,100/MWh and market floor price is negative A$1000.
3. AER State of the Energy Market Report 2017
4. The preliminary report was issued in September 2017 and final report to be issued in 2018.
For further information, please contact:
Paul Newman, Partner, Ashurst
paul.newman@ashurst.com