The National Energy Guarantee Consultation Regulation ... · contracts used to meet the emissions...
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The National Energy Guarantee Consultation Regulation Impact Statement 29 June 2018 ENERGY SECURITY BOARD The Energy Security Board has five members: Dr Kerry Schott AO Independent Chair Clare Savage Independent Deputy Chair Paula Conboy Chair of the Australian Energy Regulator John Pierce AO Chair of the Australian Energy Market Commission Audrey Zibelman CEO of the Australian Energy Market Operator
Transcript of The National Energy Guarantee Consultation Regulation ... · contracts used to meet the emissions...
The National Energy Guarantee
Consultation Regulation Impact Statement 29 June 2018
ENERGY SECURITY BOARD
The Energy Security Board has five members:
Dr Kerry Schott AO Independent Chair
Clare Savage Independent Deputy Chair
Paula Conboy Chair of the Australian Energy Regulator
John Pierce AO Chair of the Australian Energy Market Commission
Audrey Zibelman CEO of the Australian Energy Market Operator
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Contents
1 Introduction ............................................................................................................8
1.1 The electricity supply chain ........................................................................................................... 8
1.2 The National Electricity Market ..................................................................................................10
1.3 The NEM’s spot market and financial markets .....................................................................12
1.4 NEM governance ............................................................................................................................13
1.5 Reliability in the NEM ....................................................................................................................15
1.5.1 The NEM’s reliability standard and reliability settings ........................................................16
1.5.2 Generation reliability ......................................................................................................................17
1.6 The Renewable Energy Target (RET) and the growth of renewable generation .....18
1.7 The Australian Government’s Paris Commitment ...............................................................20
1.8 The National Greenhouse and Energy Reporting (NGER) scheme .............................20
1.9 Emissions from electricity generation ......................................................................................21
2 Problem .................................................................................................................24
2.1 Overview ............................................................................................................................................24
2.2 Increased electricity prices ..........................................................................................................24
2.3 Increasing risk of unreliability......................................................................................................26
Reducing emissions....................................................................................................................................29
2.4 Generator financial incentives decoupled from system needs ........................................29
2.5 Summary ............................................................................................................................................30
3 Objectives .............................................................................................................31
4 Options ..................................................................................................................32
4.1 Business as usual ...........................................................................................................................32
4.2 National Energy Guarantee .........................................................................................................32
4.2.1 Emissions reduction requirement ..............................................................................................33
4.2.1.1 Overview................................................................................................................................33
4.2.1.2 Electricity emissions targets ...........................................................................................34
4.2.1.3 Applying the emissions reduction requirement ........................................................35
4.2.1.4 Flexible compliance options ............................................................................................40
4.2.1.5 Reporting and compliance ...............................................................................................43
4.2.1.6 Other considerations .........................................................................................................47
4.2.2 Reliability requirement ...................................................................................................................48
4.2.2.1 Overview................................................................................................................................48
4.2.2.2 Step 1: Forecasting the reliability requirement .........................................................49
4.2.2.3 Step 2: Updating the reliability requirement ..............................................................50
4.2.2.4 Step 3: Triggering the reliability obligation .................................................................50
4.2.2.5 Step 4: Liable entities ........................................................................................................52
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4.2.2.6 Step 5: Qualifying contracts ............................................................................................53
4.2.2.7 Step 6: Procurer of Last Resort .....................................................................................57
4.2.2.8 Step 7: Compliance ............................................................................................................58
4.2.2.9 Step 8: Penalties .................................................................................................................59
4.3 Physically Backed Contracts .......................................................................................................59
5 Impact Analysis ....................................................................................................65
5.1 Business as usual ...........................................................................................................................65
5.2 National Energy Guarantee .........................................................................................................68
5.2.1 Price impacts ....................................................................................................................................69
5.2.1.1 Wholesale price impacts ..................................................................................................69
5.2.1.2 Retail bill impacts................................................................................................................71
5.2.1.3 Ability to achieve emissions reduction target ............................................................72
5.2.1.4 Investment and retirements ............................................................................................73
5.2.1.5 Generation output ...............................................................................................................75
5.2.2 Qualitative assessment of the Guarantee ..............................................................................76
5.2.2.1 Certainty of achieving policy objectives ......................................................................77
5.2.2.2 Technological and geographic neutrality ....................................................................78
5.2.2.3 Appropriateness of risk allocation .................................................................................78
5.2.2.4 Impact on contract market liquidity ...............................................................................78
5.2.2.5 Implementation flexibility ..................................................................................................79
5.2.2.6 Adaptability and sustainability ........................................................................................79
5.2.3 Distributional impacts ....................................................................................................................79
5.2.3.1 Impacts on prices ...............................................................................................................79
5.2.3.2 Impacts on market customers ........................................................................................80
5.3 Physically Backed Contracts .......................................................................................................90
5.3.1 Price impacts ....................................................................................................................................90
5.3.2 Financial market impacts .............................................................................................................90
5.3.3 Competition impacts ......................................................................................................................91
5.3.4 Emissions impacts ..........................................................................................................................91
5.3.5 Regulatory burden ..........................................................................................................................91
5.4 Summary ............................................................................................................................................92
6 Consultation .........................................................................................................93
6.1 Consultation for the detailed design papers and consultation Regulation Impact Statement ..........................................................................................................................................94
7 Conclusion ............................................................................................................95
8 Implementation/Review .......................................................................................96
8.1 Implementation and governance ...............................................................................................96
8.1.1 Implementation through NEM governance arrangements ................................................96
8.1.2 Relevant Commonwealth legislation ........................................................................................97
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8.1.3 Advice on including Western Australia in the emissions reduction requirement ......97
8.1.5 Summary of key steps and issues ............................................................................................98
8.2 Reviews ..............................................................................................................................................99
Abbreviations and defined terms ..............................................................................100
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EXECUTIVE SUMMARY
The Energy Security Board (ESB) is consulting on a mechanism designed to integrate
energy and emissions policy in a way that encourages new investment in clean and low
emissions technologies while allowing the electricity system to continue to operate
reliably. Providing long-term policy confidence is critical to lowering investment risk in
the National Electricity Market (NEM) and ultimately bringing down electricity prices.
This Consultation Regulation Impact Statement (RIS) explains the problem being
addressed, sets out policy options and invites comments from interested parties. It is a
COAG requirement that if regulatory options that impose mandatory requirements upon
business and the community have a more than minor or machinery impact then
Ministerial Councils must subject these options to a regulatory impact assessment
process through the preparation of a Consultation RIS and Decision RIS.
The past decade has been characterised by changes in emissions reduction policies,
and the absence of a clear long-term policy. Electricity prices have been rising, partly
as a result of this uncertainty affecting investment decisions.
Without a policy commitment to achieve emissions reductions in the NEM, emissions
may exceed the electricity sector’s share of Australia’s international commitments
under the Paris Agreement.
At the same time, the proportion of available dispatchable generation capacity in the
NEM is declining. Australia’s ageing generators are becoming less reliable and in
recent years the retirement of old plant (mainly coal) has been replaced mainly by
variable renewable alternatives. From a reliability standpoint, variable renewable
generation is not a direct replacement for coal-fired generation. The reduction in
dispatchable generation presents risks to the reliability of electricity supply in the NEM.
The ESB’s proposed National Energy Guarantee (the Guarantee) is a mechanism
designed to integrate energy and emissions policy in a way that encourages new
investment in clean and low emissions technologies while allowing the electricity
system to continue to operate reliably. Providing long-term policy confidence is critical
to lowering investment risk in the NEM and ultimately bringing down electricity prices.
The Guarantee has two requirements:
The emissions reduction requirement is an annual obligation on retailers and large
customers who directly purchase electricity in the wholesale market (market
customers) in the NEM to ensure the average emissions intensity of their load is
at or below the prescribed electricity emissions per MWh target for that
compliance period.
The reliability requirement builds on existing spot and financial market
arrangements in the electricity market to facilitate investment in dispatchable
capacity. If a reliability obligation is triggered, liable entities may be expected to
demonstrate future compliance by entering into qualifying contracts for
dispatchable capacity to cover their share of system peak demand at the time of
the gap.
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The ESB has designed the Guarantee to have a mechanism to reduce emissions and
provide sufficient dispatchable generation to ensure reliability. A business-as-usual
approach will not be sufficient to ensure those objectives are met. The alternative to the
Guarantee considered in this Consultation RIS is a variation of the Guarantee as
proposed in the ESB's February 2018 consultation paper. The alternative requires
contracts used to meet the emissions requirement and the reliability requirement to be
physically backed by a generator (physically backed contracts). Compared to the
alternative, the Guarantee is expected to achieve its objectives at a lower cost, and
with a larger net benefit.
The ESB’s final position will be reflected in a Decision RIS, after it has considered
stakeholder submissions and refined its impact analysis. The Decision RIS will be
published following consideration by the COAG Energy Council in August.
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1 Introduction
1.1 The electricity supply chain
The electricity supply chain is the infrastructure and organisations that deliver electricity
from generators to our homes and businesses. The existing electricity market design,
and the regulatory framework that governs it, has historically been based on a linear
supply chain: from generator to transmission network to distribution network to
consumer. However, changing consumer preferences and technology developments
are enabling electricity customers to make decisions that serve their own interests as a
user, or producer, of electricity. This is leading to distribution networks experiencing
two-ways flows, as shown in Figure 1.1.
Figure 1.1: The electricity supply chain
Source: Australian Energy Market Commission1
1 Australian Energy Market Commission, https://www.aemc.gov.au/energy-system/electricity/electricity-
system/electricity-supply-chain access 29 June 2018
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Figure 1.2 shows the contribution of various fuel sources to Australia's electricity
generation.
Figure 1.2: Australian electricity generation by fuel type, 2016-172
Source: Clean Energy Regulator, Australian PV Institute3
Transmission and distribution networks
Transmission networks are high voltage lines that transport electricity from generators
to major demand centres. Distribution networks transport electricity at lower voltages to
end-user consumers, such as homes and businesses.
Electricity networks are natural monopolies and in the NEM they’re regulated by the
Australian Energy Regulator (the AER).
Retailers
Energy retail markets provide the interface between retailers and their customers. They
allow energy retailers to sell electricity, gas and energy services to residential and
business customers.
2 Percentages are based on electricity generated (MWh) for the whole of Australia including in the
NEM, other networks and large freestanding generators, such as on remote mining sites. 3 Clean Energy Regulator, Electricity Sector Emissions and Generation Data 2016-17, Australian PV
Institute, Monthly PV Output by State, http://pv-map.apvi.org.au/analyses accessed 22 June 2018
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Competitive retail markets with appropriate consumer protections provide a basis for
innovation, product choice and competitive pricing.
Retailers seek to recover the costs that they pay (e.g. purchasing energy from the
wholesale market, as well as network charges) from their consumers as well as
recovering a margin for the task of providing a retail service. The AEMC publishes an
annual report that provides an understanding of the cost components of the electricity
supply chain that contribute to the overall price paid by residential consumers; and the
expected trends in these components.
1.2 The National Electricity Market
The National Electricity Market (NEM) is an electricity system covering around
40,000 km of transmission lines. It comprises five interconnected regions in eastern
and south eastern Australia and supplies around 80 per cent of Australia’s electricity
consumption.4 The regions are:
Queensland
New South Wales (which includes the Australian Capital Territory)
Victoria
Tasmania
South Australia
Figure 1.3 shows the extent of the NEM.
Western Australia and the Northern Territory are not connected to the NEM. They have
their own electricity systems and separate regulatory arrangements5.
4 Australian Energy Market Commission, https://www.aemc.gov.au/energy-system/electricity/electricity-
system/national-electricity-market accessed 8 June 2018 5 The Northern Territory applies some parts of the NEM’s National Electricity Rules, discussed below .
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Figure 1.3: The National Electricity Market
Source: Australian Energy Market Commission
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1.3 The NEM’s spot market and financial markets
In electricity systems the amount of electricity generated needs to continuously match
the amount of electricity consumed. The NEM has a formal spot market, operated by
the Australian Energy Market Operator (AEMO), to ensure supply meets demand plus
an appropriate amount of reserves.
Almost all electricity generated in the NEM must be settled through the spot market.
The spot market matches bids from market generators to demand from market
customers (retailers and some large industrial user) every 5 minutes.
Prices are calculated at each regional reference node. This process determines a spot
price for each region. The spot price is settled (averaged) over a 30 minute period
(trading interval) and this is the price generators are paid for the electricity they
produce and retailers pay for the electricity their customers consume6.
Buyers and sellers manage the risk of price volatility through financial hedge contracts,
such as swaps and caps settled against the spot price, to reduce the exposure of both
parties to high prices. These contracts can be exchange traded or over-the-counter (i.e.
bilaterally rather than through an exchange).
The financial derivatives market has been an integral part of the operation of the NEM
since its inception. A generator's revenues and a retailer’s costs are determined by
their net exposure to the spot market and the financial derivatives market. Hedging
against spot market risk can significantly reduce market participants' (and ultimately
consumers') exposure to high price events.
6 The AEMC has recently made a final determination to move to five-minute settlement from mid-2021.
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Figure 1.4: Hedge contracts in the NEM
Source: Australian Energy Market Operator7
1.4 NEM governance
Electricity legislation is the jurisdiction of each state and territory. The NEM is governed
by the National Electricity Law (NEL) and the National Electricity Rules (NER). The
NEL was enacted in the South Australian Parliament through the National Electricity
(South Australia) Act 1996. The NEL is applied in every other state and territory
participating in the NEM by application statutes.8
The Council of Australian Governments (COAG) Energy Council is a Ministerial forum
for the Commonwealth, states and territories. It has overarching responsibility and
policy leadership for Australia's electricity markets and developing Australia’s energy
and mineral resources. The COAG Energy Council’s governing principles are:9
Promoting the interests of electricity consumers by overseeing the development
and maintenance of competitive electricity and gas markets and effective
regulation of network monopoly infrastructure.
Greater productivity, energy efficiency and sustainability.
Industry and other stakeholder participation in policy development and
implementation.
7 Australian Energy Market Operator, http://www.abc.net.au/mediawatch/transcripts/1234_aemo2.pdf,
accessed 13 June 2018
8 Australian Energy Market Commission, https://www.aemc.gov.au/regulation/legislation, accessed
12 June 2018
9 COAG Energy Council, http://www.coagenergycouncil.gov.au/about-us/our-role, accessed
12 June 2018
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Regulation and governance reform to streamline processes and decision-making
and deliver outcomes more efficiently and consistently.
The operation, regulation and development of the NEM is the responsibility of three
market bodies.
The Australian Energy Market Operator (AEMO) operates the NEM and Western
Australia's Wholesale Electricity Market. AEMO is responsible for maintaining the
security (ensuring parameters like frequency and voltage are within defined technical
limits) and reliability (ensuring supply meets demand) of the NEM in operational
timescales, subject to parameters set out in the NER. It also has network planning and
forecasting roles. AEMO is funded by market participants through market fees.
The Australian Energy Market Commission (AEMC) is the rule maker for Australian
electricity and gas markets. It makes and amends the National Electricity Rules,
National Gas Rules and National Energy Retail Rules. It also provides market
development advice to governments. The AEMC is funded by state and territory
governments.
The Australian Energy Regulator (AER) regulates electricity networks in all jurisdictions
except Western Australia, and sets the amount of revenue network businesses can
recover from customers for using these networks. The AER enforces the laws for the
NEM's spot market and monitors and reports on the conduct of market participants and
the effectiveness of competition. The AER also enforces the National Energy Retail
Law in New South Wales, South Australia, Tasmania, the ACT and Queensland, which
protects household and small business consumers. The AER is funded by the
Commonwealth Government and shares staff, resources and accommodation with the
Australian Competition and Consumer Commission.10
In addition to the three energy market bodies is the Energy Security Board (ESB),
created by the COAG Energy Council in 2017 at the recommendation of the
Independent Review into the Future Security of the National Electricity Market, led by
Australia's Chief Scientist, Dr Alan Finkel AO. The ESB's role is to coordinate the
implementation of the Review's reform blueprint. The ESB also provides whole of
system oversight for energy security and reliability to drive better outcomes for
consumers. The ESB comprises an Independent Chair, Independent Deputy Chair and
the heads of the AEMC, AEMO and AER. The ESB reports to the COAG Energy
Council. Each year the ESB delivers a Health of the National Electricity Market report
to the COAG Energy Council that tracks the performance of the system, the risks it
faces, and the opportunities for improvement. Figure 1.5 shows the NEM’s institutional
governance framework.
10 Australian Energy Regulator, https://www.aer.gov.au/about-us , accessed 12 June 2018
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Figure 1.5: NEM governance framework
Source: COAG Energy Council
1.5 Reliability in the NEM
In the NEM, reliability means having enough generation, demand response and
network capacity to supply customers with the energy they demand, with a very high
degree of confidence. This has several elements including: efficient investment;
adequate capacity to meet demand plus a sufficient level of reserves; a reliable
transmission network; a reliable distribution network, and maintaining the system in a
secure operating state (see Box1.1).
This involves longer-term considerations such as having the right amount of
investment, as well as shorter-term considerations such as making appropriate
operational decisions.
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Box 1.1: Reliability vs security in the NEM
Security: A secure system is one that operates within defined technical limits, such as for
voltage and frequency, even when there is a loss of a major transmission line or large
generator. Security events are mostly caused by sudden equipment failure, often associated
with extreme weather or bushfires.
Reliability: A reliable system is one with enough energy (generation and demand side
participation) and network capacity to supply consumers. A reliable supply needs reserves that
allow demand and supply to balance when there are unexpected demand changes.
1.5.1 The NEM’s reliability standard and reliability settings11
The reliability standard is the level of reliability sought from the NEM’s generation and
transmission assets. The standard currently requires sufficient generation and
transmission interconnection so 99.998 per cent of annual demand for electricity is
supplied.
The reliability settings promote investment to achieve the reliability standard. The
settings protect the long term integrity of the market by limiting the extent to which
wholesale prices can rise and fall. They are set at a level so as not to interfere with the
price signals needed for efficient investment and operation. The settings comprise the:
Market price cap: this imposes a maximum price that a generator may bid.
The cumulative price threshold: this limits participants’ financial exposure to
prolonged high prices by capping the total market price that can occur over seven
consecutive days.
The administered price cap: this is the ‘default’ price cap that applies when the
cumulative price threshold is exceeded.
The market floor price: this is the minimum price that a generator may bid during a
dispatch interval.
The reliability standard and reliability settings are set in the National Electricity Rules
(NER).12 Under the NER, they are required to be reviewed by the AEMC’s Reliability
Panel every four years13.
11 Australian Energy Market Commission, https://www.aemc.gov.au/energy-
system/electricity/electricity-system/reliability, accessed 12 June 2018
12 Australian Energy Market Commission, https://www.aemc.gov.au/regulation/energy-
rules/national-electricity-rules, accessed 12 June 2018
13 The AEMC may instruct the Panel to conduct an interim review before the next scheduled review.
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1.5.2 Generation reliability14
AEMO must continuously monitor levels of generation in the short term, as generator
availability changes for things like maintenance, and the medium and long term, as
generators retire from the market and new generators take their place.
In the short and medium term, AEMO assesses supply adequacy through its Projected
Assessments of System Adequacy (PASA) process. This involves collecting
information and analysing if the electricity supply can meet the reliability standard in the
short term (a one week outlook) and medium term (a two year outlook).
In the long term, AEMO’s Electricity Statement of Opportunities (ESOO)15 assesses
supply adequacy across the NEM ten years ahead, taking into account any significant
developments, such as expected power station closures and committed new build.
AEMO has mechanisms it can use if it believes electricity supply and demand will not
meet the reliability standard. The mechanisms it uses will depend on the immediacy
and size of the expected supply short-fall. These mechanisms include:
Invite generators to bid any spare supply into the market, or bid load reduction to
reduce their consumption in the market
Activate the Reliability and Emergency Reserve Trader (RERT) mechanism (see
below)
Direct a generator to increase its output, if possible and can be done safely
Direct a large energy user, such as an aluminium smelter, to temporarily
disconnect its load or reduce demand.
Direct network businesses to shed load following schedules provided by the
relevant state government.
Box 1.2: The RERT16
The RERT is a function conferred on AEMO to maintain power system reliability and system
security using reserve contracts. It allows AEMO to contract for electricity reserves ahead of a
period where it projects a shortage of reserves or, where practicable, for power system
security. AEMO can call for tenders to provide these reserves where it has 9 months’ notice of
a projected shortfall. Alternatively, AEMO may maintain a panel of RERT providers that can
provide short notice (between three hours and seven days) and medium notice (between 10
weeks and 7 days) reserve if required. The panel allows AEMO to run an expedited tender
process. Reserves can include customer load that can be curtailed and generation that is not
available to the market.
14 Australian Energy Market Commission, https://www.aemc.gov.au/energy-system/electricity/electricity-
system/reliability, accessed 12 June 2018
15 Australian Energy Market Operator, https://www.aemo.com.au/Electricity/National-Electricity-Market-
NEM/Planning-and-forecasting/NEM-Electricity-Statement-of-Opportunities, accessed 8 June 2018
16 Australian Energy Market Operator, https://aemo.com.au/Electricity/National-Electricity-Market-
NEM/Emergency- Management/RERT-panel-expressions-of-interest, accessed 15 June 2017
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1.6 The Renewable Energy Target (RET) and the growth of renewable generation17
The RET is an Australian Government scheme designed to reduce greenhouse gas
emissions in the electricity sector and encourage additional electricity generation from
sustainable and renewable sources.
The RET has been modified several times since its inception in 2001. In its initial form
fixed targets were set to achieve 9.5 TWh of additional renewable energy generated
per annum by 2010 or approximately 2% of demand. In August 2009 this target was
increased to 41 TWh or approximately 20% of demand. In June 2010 further
modifications to the RET were legislated due to the unforeseen rapid uptake in small
scale solar, and subsequently the RET was split into the Large-scale Renewable
Energy target (LRET), which applies to large power stations, and the Small-scale
Renewable Energy Scheme (SRES), which applies to solar PV systems and solar hot
water heaters installed by households and small businesses.
The LRET and SRES create large-scale generation certificates (LGCs) and small-scale
technology certificates (STCs), respectively, for each MWh they generated from
accredited renewable sources. Electricity retailers are required to purchase certificates
proportional to the amount of wholesale electricity they purchase and submit them to
the Clean Energy Regulator (CER). This creates a market which provides financial
incentives to both large-scale renewable energy power stations and the owners of
small-scale renewable energy systems.
Between 2009–10 and 2013–14 demand in the NEM fell 1.8% per annum on
average18. This decline combined with a fixed LRET increased the expected share that
the 41 TWh target would have from 20% to 28% of demand. Subsequently in 2015 the
2020 LRET was revised down to 33 TWh.
The 2017 Independent Review into the Future Security of the National Electricity
Market found that “the existing Large-scale Renewable Energy Target scheme should
remain unchanged to the end of its design life, but not be extended in its current
form”19.
The current LRET is an annual target that increases each year to the ultimate target of
33 TWh by 2020. The target then remains at this level until 2030, when the scheme
ends. The SRES target depends on the number of small PV and solar hot water
installations and is set each year by the CER so STC demand matches STC creation.
17 Clean Energy Regulator, http://www.cleanenergyregulator.gov.au/RET, accessed 18 June 2018
18 Australian Energy Market Operator,
https://www.aemo.com.au/media/Files/Other/MediaReleases/AEMO_NEFR2014_NEM.pdf
accessed 20 June 2018
19 Commonwealth of Australia, Independent Review into the Future Security of the National
Electricity Market (Finkel Review), June 2017
https://www.energy.gov.au/publications/independent-review-future-security-national-electricity-
market-blueprint-future
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STCs are created up front following the installation of an eligible system, and are
calculated based on the amount of electricity a system produces or replaces (that is,
electricity from non-renewable sources) over set a period of time. Generally,
householders who purchase these systems assign the right to create their certificates
to an agent in return for a lower system price.
The RET's cost is passed through to consumers20. The electricity purchased by
emissions-intensive trade-exposed (EITE) industries is exempt from a retailer's liable
electricity.
Since 2010, the increase in large-scale renewable generation in the NEM from the
LRET and the growth in rooftop solar PV (due in part to the SRES) has coincided with
declining NEM demand. Further, many renewable generators are paid through
contracts with retailers to supply LGCs and are not reliant on spot market revenues,
undermining spot market fundamentals. This resulted in a period where wholesale
electricity prices declined to levels that contributed to the departure of dispatchable
capacity.
Over the last decade around 5,200 MW of thermal (coal and gas) generation was
withdrawn from the NEM21.Of the 2,600 MW of generation capacity added over the six
years to March 2018, 90 per cent was intermittent renewables built primarily for the
RET22. An intermittent generator is a generator whose output is dependent on factors
beyond the control of its operator, such as wind speed or solar radiation. The last
dispatchable generator built in the NEM was in Victoria more than five years ago. A
dispatchable generator can generate electricity and adjust its output up or down at the
request of the market operator, given adequate notice and supply of fuel.
After a record year for renewable energy investment in 2017, which included 4,900 MW
of announced and fully financed new capacity, and 6,553 MW of capacity built or under
construction since January 2016, the CER said the RET is on track to achieve its target
of 33 TWh of generation from additional renewable sources in 202023 24. It should be
noted there is no proposal to change the operation of the RET under any of the options
examined in this RIS.
In addition to large scale generation, solar photovoltaic (PV) generation on the roofs of
houses and businesses has grown rapidly. At March 2018, Australia’s total rooftop
20 The RET made up 3.6% of the national average cost of electricity in 2016-17. AEMC, Residential
Electricity Price Trends Report 2017, December 2017
21 Australian Energy Market Operator, Advice to Australian Government on Dispatchable Capacity,
September 2017
22 Australian Energy Regulator, State of the Energy Market 2017 – updated with AEMO Generation
Information
23 Clean Energy Regulator, Record year of investment means Australia’s 2020 Renewable Energy
Target will be met, media release, January 2018
http://www.cleanenergyregulator.gov.au/RET/Pages/News%20and%20updates/NewsItem.aspx?L
istId=19b4efbb%2D6f5d%2D4637%2D94c4%2D121c1f96fcfe&ItemId=468
24 Clean Energy Regulator, http://www.cleanenergyregulator.gov.au/RET/About-the-Renewable-
Energy-Target/Large-scale-Renewable-Energy-Target-market-data/large-scale-generation-
certificate-market-update/large-scale-generation-certificate-market-update-may-2018 accessed
22 June 2018
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capacity was approximately 7.8 GW25. Figure 1.6 shows the change in the NEM’s
renewable generation capacity.
Figure 1.6: Renewable generation contribution to NEM electricity supply26
Source: AER, State of the Energy Market 2017
1.7 The Australian Government’s Paris Commitment27
In August 2015 the Australian Government committed to reducing Australia's
greenhouse gas emissions to 26–28 per cent below 2005 levels by 2030, as part of the
Paris Agreement.
The Paris Agreement is under the United Nations Framework Convention on Climate
Change. The agreement is a framework for all countries to take climate action from
2020, building on existing international efforts in the period up to 2020.
The Paris Agreement came into force 4 November 2016 when the threshold was met of
55 countries ratifying the agreement and covering 55 per cent of global emissions.
1.8 The National Greenhouse and Energy Reporting (NGER) scheme28
NGER is the national framework for reporting and disseminating company information
about greenhouse gas emissions, energy production, energy consumption and other
information. It is administered by the CER.
NGER considers the emissions of corporations and facilities and classifies emissions
as scope 1 or scope 2. Scope 1 emissions are greenhouse gases released into the
atmosphere as a direct result of an activity. For example, emissions from burning coal
to generate electricity at a facility are scope 1 emissions. Scope 1 emissions will be
used to calculate the emissions per MWh of a generator for the Guarantee.
25 Australian PV Institute, http://pv-map.apvi.org.au/analyses, accessed 12 June 2018. 26 Note: Rooftop solar PV generation is not traded in the NEM’s spot market but acts to reduce spot
market demand. 27 Department of the Environment and Energy, http://www.environment.gov.au/climate-
change/government/international/paris-agreement, accessed 13 June 2018. 28 Clean Energy Regulator, http://www.cleanenergyregulator.gov.au/NGER/Reporting-cycle/Assess-
your-obligations/Understand-your-corporate-group, accessed 15 June 2018.
21
Scope 2 emissions are greenhouse gases released into the atmosphere as a direct
result of one or more activities that generate electricity, heating, cooling or steam that is
consumed by a facility but do not take place at the facility. For example, the emissions
from the electricity a facility consumes from an electricity network are scope 2
emissions. A facility's scope 2 emissions are counted as scope 1 emissions at another
facility. Scope 2 emissions are not considered in the Guarantee.
NGER applies to a controlling corporation, which is usually the corporation at the top of
a corporate hierarchy, but can also be another corporation. A controlling corporation
must register for NGER reporting if it meets the facility or corporate group annual
thresholds:
Facility threshold:
o 25,000 tonnes or more of scope 1 and scope 2 emissions
o Production of 100 TJ (27.8 GWh) or more of energy
o Consumption of 100 TJ or more of energy
Corporate group threshold:
o 50,000 tonnes or more of scope 1 and scope 2 emissions
o Production of 200 TJ (55.6 GWh) or more of energy
o Consumption of 200 TJ or more of energy
Corporations submit their NGER reports at the end of each financial year.
1.9 Emissions from electricity generation
Figure 1.7 shows electricity generation is the largest source of emissions in Australia’s
National Greenhouse Gas Inventory. It accounted for 35 per cent of Australia’s
greenhouse gas emissions in the year to December 2017. Approximately 80 per cent of
generation emissions are from the NEM.29
29 Department of the Environment and Energy, Quarterly Update of Australia’s National Greenhouse Gas
Inventory: December 2017.
22
Figure 1.7: Australia’s emissions contribution by sector, year to December 201730
Source: Department of the Environment and Energy , Quarterly Update of Australia’s National Greenhouse Gas Inventory: December 2017
Australia’s electricity sector emissions have declined 12.9 per cent in the year to
December 2017 from the sector’s emissions peak in the year to December 2008.
Figure 1.8 shows carbon dioxide emissions in the NEM have declined 12.5 per cent (or
5 Mt) over the past decade.
Reasons for these declines include, on the generation side, increased wind and solar
capacity and the closure of coal-fired generators in South Australia and Victoria. On the
demand side, NEM demand has gradually declined for a number of reasons including
the loss of some industrial load and the growth of rooftop PV, which displaces NEM
demand.
30 LULUCF means Land Use, Land Use Change and Forestry.
23
Figure 1.8: Quarterly NEM electricity emissions
Source: Department of the Environment and Energy , Quarterly Update of Australia’s National Greenhouse Gas
Inventory: December 2017
24
2 Problem
2.1 Overview
Fifteen years of climate policy uncertainty has complicated long-term investment
decisions in the NEM, contributing to compromised system security and reliability. This
has left our energy system vulnerable to escalating prices while placing pressure on
the ability for the system to remain reliable and secure. Accordingly, this has shifted
security and reliability needs across the NEM, impacting the system’s operation.
2.2 Increased electricity prices
In real terms, electricity prices for households increased by 80 to 90 per cent between
2007-08 and 2015-16.31 As shown in Figure 2.1 below, these price increases have
exceeded those in other parts of the economy, and have not been matched by wage
growth, causing significant affordability challenges, particularly for low income
households.32
Figure 2.1: Electricity, All CPI Groups and Wage Price Index - Australia (December quarters)
Source: Australian Bureau of Statistics, Catalogue Number 6401.0, 6345.0
Business has also experienced large increases in prices, particularly in the past 18
months, following the renegotiation of expiring contracts. The significant increase in
31 Australian Competition and Consumer Commission, Retail Electricity Pricing Inquiry, Preliminary
Report, September 2017, p.12.
32 See for example, submissions to the National Energy Guarantee Draft Design Consultation Paper
by the Australian Council of Social Services, March 2018, p.9 and Queensland Council of Social
Service March 2018, p.1.
25
business input costs undermines the international competitiveness of Australian
businesses and the economy. In 2004, Australia had the fourth cheapest electricity
prices in the OECD (and below the OECD average), but by 2016 had slipped to ninth
cheapest, behind Norway, Canada, United States, Mexico, Israel, Switzerland, Korea
and Finland (and above the OECD average).33
In December 2017, the report Small to Medium Enterprise Retail Energy Tariff Tracker,
prepared by Alviss Consulting (with Energy Consumers Australia) reported that on
average, annual electricity bills for small to medium enterprises consuming 20,000 kWh
per annum increased by 19 per cent between April 2016 and October 2017. South
Australian SMEs typically experienced increases of 36 per cent, per annum during this
period, while businesses in Tasmania and the Northern Territory experienced
increases well below the national average.34
The ACCC found extensive evidence that higher prices were impacting businesses
across the economy. As reported in its Retail Electricity Pricing Inquiry, Preliminary
Report, September 2017, the doubling of wholesale prices between 2016 and 2017
across the NEM has seen significant increases in the prices offered to commercial and
industrial users. Submissions to the report from businesses confirmed cases of
electricity prices doubling or tripling, against their most recent electricity offer.
According to the Australian Industry Group this may be because businesses were
coming off long running (3 to 5 year) contracts when wholesale prices were suppressed
by higher levels of supply, decreasing demand, and the removal of the carbon price.35
Submissions to the ESB’s National Energy Guarantee Draft Design Consultation Paper
and presentations at the public consultation on 26 February 2018 reiterated the
challenges high electricity prices are posing for the community and businesses. The
Queensland Farmers Federation described the challenge its members were facing in
its submission:
“In response to price increases, farming businesses, including irrigators, have
been installing energy efficiency measures and renewable energy and, in many
cases, simply reducing demand. Much of these gains however, have been
diminished by the increasing electricity costs; whilst simply reducing demand
has also come at a cost either through reduced productivity or farmers simply
choosing not to plant a crop.”36
33 Australian Competition and Consumer Commission, Retail Electricity Pricing Inquiry, Preliminary
Report, September 2017, p.25 34 Alviss Consulting (with Energy Consumers Australia), Small to Medium Enterprise Retail Energy
Tariff Tracker, December 2017, http://energyconsumersaustralia.com.au/wp-content/uploads/SME-
Retail-Tariff-Tracker-Final-Report-December-2017.pdf, accessed 8 June 2018. 35 Australian Competition and Consumer Commission, Retail Electricity Pricing Inquiry, Preliminary
Report, September 2017, p.18 36 Queensland Farmers Federation submission to the National Energy Guarantee Draft Design
Consultation Paper, March 2018, p.3.
26
2.3 Increasing risk of unreliability
The reduction in dispatchable coal and gas generation and the greater penetration of
intermittent technologies such as solar and wind generation present risks to the
reliability of our electricity supply.
Historically, most of the installed generation capacity has been “dispatchable” (that is,
able to generate as required) provided by coal, gas and hydro-electric plants. Provided
these generating units have sufficient fuel (that is, coal, gas, stored water) and their
operational positions allow it – and assuming no unexpected outages or transmission
constraints – they can be called upon by AEMO to increase or decrease their output at
any time in a predictable manner, given enough notice.
However, Australia’s ageing generators are becoming less reliable and in recent years
the retirement of old plant (mainly coal) has been replaced by cheaper variable
renewable alternatives or gas-fired power stations. Since 2000, over 10,000 MW of
variable renewable generation has been built or is expected to be built; and about
5,500 MW of generation fleet has retired.37 From a reliability standpoint, variable
renewable generation is not a direct replacement for coal-fired generation, due to
having a lower capacity factor.
Figure 2.2 shows the change in electricity production by fuel source in the NEM for
comparison.
Figure 2.2: Annual NEM electricity generation by fuel, year to March
Source: Department of the Environment and Energy, Quarterly Update of Australia’s National Greenhouse Gas Inventory: December 2017
There will continue to be increasing penetration of intermittent renewable generation in
the form of large-scale wind and solar plant driven by the Renewable Energy Target
37 Clean Energy Regulator and Australian Energy Market Operator data.
27
(RET), state-based renewables schemes, and the rapidly declining costs of these
technologies.
As a result of these factors, the proportion of available dispatchable generation
capacity in the NEM is declining. While some new wind and solar investments in
Australia are seeking to make themselves “dispatchable” by co-locating with a battery
or storage such as pumped hydro, this is not currently true for the majority of these
resources.
It is a fundamental physical requirement in any electricity system that the volume of
electricity generated (supply), must be balanced with the volume of electricity
consumed (demand) on a second-by-second basis at all and every location on the
system.
For the supply of electricity to be reliable, the power system must have sufficient
capacity beyond expected consumer demand, known as reserves, to allow for both
supply and demand fluctuations over time. For this reason AEMO monitors the NEM’s
reserve generation capacity and issues notices to the market when reserves drop
below certain levels.
It is worth noting that in 2016/17, AEMO issued 22 lack of reserve notices (see Figure
2.3 below). This was the highest number of lack of reserve notices since 2008/09. In
the summer of 2017/18 AEMO declared 31 lack of reserve conditions (not shown in
Figure 2.3)38. In one sense, this is an early warning of reliability concerns that could
arise in the future. Despite this, the current reliability standard is not forecast to be
breached.
38 Australian Energy Market Operator, https://www.aemo.com.au/-
/media/Files/Media_Centre/2018/Summer-2017-18-operations-review.pdf, p.19. Note new
arrangements for determining lack of reserve conditions were implemented on 15 February 2018 so
2017/18 may not comparable to previous years.
28
Figure 2.3: NEM Lack of Reserve (LOR) notices, 2008-09 to 2016-17
Note: This f igure uses the history of Market Notices of LORs being issued, w hich is similar to how the AEMC has
counted LORs in reporting market performance. The count does not exactly match the number of times LOR conditions
have existed, but it show s the same trend and also enables us to go as far back as 2008-09.
Source: AEMO 39
Legend for Figure 2.3 – Lack of Reserves (LOR) levels
LOR 1 - An indication to the market to encourage more generation. No impact to
power system reliability is expected.
LOR 2 - No impact to power system reliability is expected, however AEMO will
bring in available additional resources if required.
LOR 3 - Signals a deficit in the supply/demand balance. With no market response,
controlled load shedding by AEMO may be required.
Source: AEMO https://www.aemo.com.au/Media-Centre/AEMO-market-notifications-
explained)
39 Australian Energy Market Operator, Summer Operations 2017-18, November 2017
https://www.aemo.com.au/-/media/Files/Media_Centre/2017/AEMO_Summer-operations-2017-18-
report_FINAL.pdf page 11, accessed 12 June 2018
29
Reducing emissions
Under the Paris Agreement, Australia has committed to reducing its emissions by
26 to 28 per cent on 2005 levels by 2030.40 The electricity generation sector accounts
for around one-third of Australia’s emissions.
The past decade has been characterised by changes in emissions reduction policies.
The absence of a clear long-term policy has seen a range of different instruments,
subsidies and renewable energy targets employed at state and federal levels to
attempt to deliver emissions reductions. Prices have been rising partly as a result of
this uncertainty affecting investment decisions. Without a specific policy commitment to
reduce emissions from electricity use, Australia may exceed its 2030 emissions
reduction target.41
The principal national mechanism to reduce emissions in the wholesale electricity
generation sector currently is the RET. The RET is a policy mechanism designed to
encourage investment in large-scale renewable energy technologies. The RET policy
sits outside the energy market framework and the design of the RET is not focused on
working with the risk allocation and incentive mechanisms built into the NEM that align
the financial incentives of market participants with the physical needs of the power
system.
2.4 Generator financial incentives decoupled from system needs
Many renewable generators receive the majority of their revenue as a result of the
LRET. A common example is a generator that enters into a contract for difference to
supply a retailer with large-scale generation certificates based on an agreed NEM spot
price. The generator receives a certificate for each MWh they dispatch to the NEM.
When the spot price is above the agreed price, the generator pays the retailer the
difference for the certificates it supplies the retailer. When it is below, the retailer pays
the generator. This gives both parties price certainty.
As a result, the generator is insulated from the spot price and does not have a strong
financial incentive to be available when the physical system needs it.
This contrasts with hedge contracts (e.g. swaps or caps) used by many generators that
are not part of LRET. For example, a swap creates a link between the needs of the
system for capacity and the financial rewards that accrue to generators from being
available and dispatched, and the losses or penalties they incur if they are not. The
various types of hedge contracts and the payments and receipts flowing from them
have this effect because they are linked to the NEM spot prices reflecting the demand-
supply balance at a particular point in time.
New generation financed under the RET adds to the physical capacity of the system
but does not directly result in a corresponding increase of hedge contracts.42 This is
because typically, renewable generation is intermittent and so cannot easily enter into
40 Australian Government, http://www.environment.gov.au/system/files/resources/c42c11a8-4df7-
4d4f-bf92-4f14735c9baa/files/factsheet-australias-2030-climate-change-target.pdf.
41 Energy Security Board, The Health of the National Electricity Market, 2017 Annual Report, p.23.
42 In this report, ‘contract’, ‘firm -capacity hedge contract’ and ‘firm contract’ are terms used
interchangeably unless noted otherwise.
30
these contracts without undertaking other investments e.g. having a hybrid site with
both wind and solar or installing a battery.
2.5 Summary
As the section has described, business as usual does not have the incentives to deliver
the emissions reductions required to help meet Australia's international commitments.
There are also concerns that the increasing penetration of renewables and the
retirement of dispatchable generation may be a risk to the NEM's reliability.
At the same time there is a need to reduce electricity prices, which are causing
significant affordability challenges, particularly for households with low incomes or
vulnerabilities, and leading to a loss of international competitiveness for many
businesses.
31
3 Objectives
The COAG Energy Council's objectives are to:
Maintain the NEM's reliability
Achieve the emissions reductions required to help meet Australia's international
commitments
Achieve these objectives at the lowest overall cost.
32
4 Options
This section describes business as usual and the options being considered.
4.1 Business as usual
One option for the COAG Energy Council is to leave the NEM as it is: business as
usual. The NEM's operation and policy settings have been described in the Introduction
and Problem sections and are summarised as follows.
The RET continues as the main emissions reduction mechanism for the generation
sector. The RET's Large-scale Renewable Energy Target (LRET) reaches 33 TWh of
generation around 2020 and stays at this level until 2030, when the scheme ends.
Similarly, the RET's Small-scale Renewable Energy Scheme (SRES), which requires
market customers to purchase in each year the small-scale technology certificates
created by solar PV, solar hot water and heat pump hot water installations, continues to
its 2030 end date.
The NEM's reliability continues to be managed by the market and AEMO under the
current reliability framework. AEMO's market projections – the ESOO and the short and
medium term PASAs – and the NEM's reliability settings are used to encourage the
market to meet any projected supply shortfalls. In the event there isn't a timely
response from the market, AEMO has various mechanisms, such as the Reliability and
Emergency Reserve Trader (RERT) mechanism, to meet the shortfall.
The COAG Energy Council, through the NEM's energy market bodies, continues to
implement the recommendations of the Independent Review into the Future Security of
the National Electricity Market (the Finkel Review), with the exception of a clean energy
target. These recommendations cover security, reliability, system planning, governance
and consumers.
4.2 National Energy Guarantee
The National Energy Guarantee (the Guarantee) is a mechanism designed to integrate
energy and emissions policy in a way that encourages new investment in clean and low
emissions technologies while allowing the electricity system to continue to operate
reliably. Providing long-term policy confidence is critical to lowering investment risk in
the NEM and ultimately bringing down electricity prices.
The emissions reduction and reliability requirements work together to ensure the
market has a fair opportunity to deliver adequate reliability whilst lowering emissions.
The Guarantee will provide a clear investment signal, so the cleanest, cheapest and
most reliable generation (or demand response) gets built in the right place at the right
time.
Market participants are expected to contract in a variety of ways to meet both of these
requirements. Increased contracting in deeper and more liquid contract markets would
be expected to reduce the level and volatility of spot prices. Cognisant of the risks to
liquidity and transparency in the contract market, the ESB has sought to ensure that
the contracting approach to meet compliance remains flexible.
33
The Guarantee has been specifically designed to ensure it does not undermine but
rather enhances the liquidity, transparency and the level of competition in the retail and
wholesale electricity markets.
The Guarantee will require liable entities to contract with generation, storage or
demand response so that:
there is a minimum amount of dispatchable energy available to meet consumer
and system needs (reliability requirement), and
the average emissions level of the electricity they sell to consumers supports
Australia’s international emissions reduction commitments, as set by the
Commonwealth Government (emissions reduction requirement).
The emissions reduction and reliability requirements of the Guarantee will require
retailers to support a range of different generation and demand-side technologies
through their contracting. This will result in increased contracting levels, which in turn
will create deeper and more liquid contract markets. This is expected to reduce the
level and volatility of spot prices.
The Guarantee will be implemented through the NEM’s existing governance
arrangements. Using an established framework, with clear accountabilities and change
processes, will give businesses and investors the confidence and certainty they need
to invest in the long-term and deliver cheaper, cleaner and reliable electricity for
Australian consumers.
4.2.1 Emissions reduction requirement
4.2.1.1 Overview
The emissions reduction requirement will be an annual obligation on market customers
to ensure the average emissions per MWh of generation allocated against their load is
at or below the prescribed electricity emissions target for a given compliance period.
It will be established by the COAG Energy Council under the existing national electricity
governance framework (see Chapter 8). The Commonwealth Government will set the
trajectory of annual electricity emissions targets, expressed as annual average
emissions per MWh.
Many State and Territory Governments in Australia have also established schemes to
encourage renewable energy and to reduce electricity sector emissions. All State and
Territory renewable energy schemes can operate with the Guarantee and contribute
towards achieving the emissions reduction trajectory for the Guarantee.
Compliance with the Guarantee’s emissions reduction requirement will be assessed
and reported annually, based on a financial year compliance period. The first
compliance year is proposed to be the 2020-21 year. The AER will be the agency
responsible for monitoring and enforcing compliance.
34
An emissions registry (the registry) will be used to support the allocation of generation
and associated emissions to a market customer’s load. This approach will ensure the
Guarantee works in a way that is integrated with existing electricity market operations
without compromising financial market liquidity. Importantly, it will draw on existing
reporting obligations with which participants already comply.
The registry provides the necessary infrastructure to facilitate efficient compliance with
the emissions reduction requirement. It allows market customers to be allocated a
share of a generator’s output and associated emissions, for which they have obtained
the rights. This can be based on any contractual arrangement held with a counterparty
outside the registry, as long as both parties verify the agreement in the registry. Market
customers can choose to enter into contracts to allocate generation in the registry with
the same generators that they enter into hedging contracts with, but there is no
requirement for these parties to be the same.
To provide flexibility in how market customers meet the emissions reduction
requirement while reducing the costs of compliance, market customers will be allowed
to carry forward a limited amount of a previous year’s over-achievement for use in the
next compliance year, and will be allowed limited deferral of compliance to future
compliance years.
At the end of the compliance period, and following a four month reporting and revision
window, the AER will assess the compliance of each market customer based on final
information in the registry. There will be a robust framework for the AER to monitor and
enforce compliance.
4.2.1.2 Electricity emissions targets
Annual average emissions per MWh targets for the electricity sector are proposed to be
legislated by the Commonwealth Government.
The Commonwealth Government will set these in Commonwealth legislation as a table
of annual emissions per megawatt hour (MWh) targets (known as electricity emissions
targets) for the financial years ending 2021 to 2030.
The National Electricity Law (NEL) would adopt the target set in Commonwealth
legislation for the purpose of the Guarantee.43
The Commonwealth Government is undertaking a separate consultation process in
respect of its proposed design of the Commonwealth elements of the emissions
reduction requirement, including its approach to setting electricity emissions targets.
See http://www.coagenergycouncil.gov.au/publications/national-energy-guarantee-
draft-detailed-design-commonwealth-elements for further information on the
Commonwealth elements.
43 The NEL is a schedule to a South Australian Act – the National Electricity (South Australia) Act
1996. It is applied in the states and territories that participate in the National Electricity Market by
the various application Acts of those jurisdictions.
35
4.2.1.3 Applying the emissions reduction requirement
Entities covered by the emissions reduction requirement
Entities subject to the emissions reduction requirement will be each entity registered by
AEMO as a market customer under the Rules (mostly retailers, but also other parties
that purchase electricity directly from the NEM).
The market customer’s performance against the electricity emissions target will be
determined as the average emissions associated with its generator allocations from the
registry, per MWh of its load.
The allocation of generation against a market customer’s load, and the calculation of
that load is discussed below.
Generation and emissions allocation approach
Allocation rules
Market customers will be responsible for meeting the electricity emissions target.
At the start of the compliance period, all generation and associated emissions will be
unallocated.
Unallocated generation and associated emissions in the registry will have a ‘residual’
emissions per MWh. This will be a floating value, which varies over the compliance
period as allocations are recorded. Market customers that do not have generation
allocated for some or all of their load by the end of the compliance and reporting period
will be assigned the residual emissions per MWh for that load.
To record the allocation of generation in the registry, it must be requested by one party,
and approved by the counterparty.44 The parties can record allocations at any time
during the compliance period. They will also have four months after the end of the
compliance period to continue to adjust their portfolios by recording reallocations. This
includes three months before all data is taken as final at 30 September, plus one
further month.
An additional measure to support retail market competition will be included such that
the first 50,000 MWh of any market customer’s load will be exempt from the emissions
reduction requirement, and instead spread over other market customer load (this is
similar to the approach used for exempt emissions-intensive trade-exposed (EITE)
load). As a market customer’s load increases above 50,000 MWh, its exempt
proportion decreases. This measure will help smaller market customers meet the
emissions reduction requirement, while not having a material impact on overall
coverage.
Shifting the small market customer exemption to non-exempt load, excludes around
half of all small market customers, but only adds around 1 per cent additional load to
the non-exempt load amount. Shifting the EITE exempt load adds around 15 to 20 per
cent of load to non-exempt load. In both cases it does not result in any market
44 It is not intended that output could be directly allocated between generators.
36
customer having to meet an unreachable target. This is because the emissions per
MWh target of the load is unchanged. The exempt load is shared across retailers.
The ESB is considering the merits of introducing an anti-avoidance regime which could
address matters like the risk of a market customer splitting into multiple market
customers to gain the benefit of this exemption and avoid responsibility for meeting the
electricity emissions target (see section 4.2.1.5 under Reporting and administrative
requirements).
To ensure the registry operates efficiently, generators will have some administrative
requirements under the emissions reduction requirement. They will be required to enter
or confirm allocations in a timely manner to allow AEMO to provide regular updates of
the contents of the unallocated pool and its emissions intensity. They will have an
administrative requirement to allocate all generation and associated emissions by the
reporting and compliance date.
To ensure that a competitive market is fostered, there will be a legal requirement that
market customers and generators do not unreasonably withhold any allocations for
anti-competitive purposes. These requirements are detailed further in the Technical
Working Paper on Compliance and Penalties for the Emissions Reduction
Requirement.45 The AER may take enforcement action for breaches of these
requirements.
Over-allocations
It is reasonable for a market customer to initially contract more generation than their
expected load to allow for load uncertainty. However, since total generation must equal
total load in the registry for each compliance period, over-allocation of generation at the
end of this period by a market customer would mean at least one market customer
couldn't be allocated generation, either through contracts or from the residual
unallocated generation pool, to cover their load.46 Further, a market customer could
seek over allocation at the end of the compliance year for competition reasons, for
example, to force others into non-compliance and face the resulting penalties.
To deter over allocation, a market customer would be assigned a deemed emissions
per MWh for allocated generation above its load after the compliance year reporting
deadline of 31 October. The deemed emissions intensity will be set at the level of the
highest emissions intensity generator in the NEM. In addition, the market customer
would face a civil penalty (as discussed in section 4.2.1.5 under Enforcement tools for
emissions reduction requirement). These measures are expected to incentivise market
customers to reallocate generation in advance of the reporting deadline to avoid being
over-allocated.
45 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports -papers.
46 Over-allocation refers to an instance in which a market customer allocates more generation than it
has load. This is distinct from over-achievement where the generation matches the market
customer load but the emissions intensity is less than the electricity emissions target.
37
This approach will also incorporate adjustments for exempt EITE load and to exclude
voluntary GreenPower load.
These elements are outlined below and are detailed further in the Technical Working
Paper on Market Customer Load (the adjustment for exempt EITE load is detailed
separately, in the Technical Working Paper on Exempt Load).47
Pool generation and wholesale pool purchases
All pool generation and wholesale pool purchases will be defined ‘at the node’:
Pool generation data will be measured at the transmission node identifier, with
generator imports netted against exports, and then adjusted by the marginal loss
factor.
Wholesale pool purchases will be measured by applying transmission and distribution
loss factors to the metered volumes.
This approach ensures that pool generation and wholesale pool purchases will require
minimal scaling to match (estimated to be within around 1 per cent).
For grid-connected batteries that are registered in the NEM as both a scheduled load
and scheduled generator, their generation will be netted against their load, such that
only their net wholesale pool purchases are included in their market customer load.
Stakeholders have raised concerns that pre-1997 renewable generation that is
currently not included in the Renewable Energy Target would be included in the
emissions reduction requirement. While the Guarantee is substantially different, the
treatment of this generation will be further considered by the ESB.
Non-market embedded generation and solar PV
To ensure that the emissions reduction requirement remains technology neutral, some
load supplied by non-market embedded generators and behind the meter resources
will be added to a market customer’s load in the registry. In order for total generation to
match total load, corresponding generation will be automatically allocated to that same
market customer in the registry.
Non-market embedded generation will be captured by adding its exports to the relevant
market customer’s load48. Similar to the wholesale pool purchases, transmission and
distribution loss factors will be applied to the embedded generation exports. The
embedded generation exports (and associated emissions) will be automatically
allocated to that market customer in the registry.
Rooftop and other small-scale solar PV will be captured by adding the net exports from
PV installations to the relevant market customer’s load, and will also be automatically
allocated to that market customer in the registry as zero emissions generation.
47 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports -papers.
48 To avoid capturing back-up plant that rarely runs.
38
Exempt EITE load
The Commonwealth Government intends to exempt EITE load from the emissions
reduction requirement.
All EITE activities exempt under the Renewable Energy Target (RET) will be eligible for
exemption under the emissions component of the Guarantee.
EITE entities will apply to the Clean Energy Regulator (CER) for an exemption, as they
do under the RET. The application process and audit requirements will be streamlined
to minimise duplication.
The CER will be responsible for determining the electricity eligible for exemption under
the Guarantee. This will be based on a method established in Commonwealth
legislation consistent with the ‘electricity use method’ under the RET.
To ensure the required emissions target is achieved, the total exempt MWhs will be
shared across all non-EITE load as an adjustment to the annual load used for
compliance.
The ESB’s proposed approach to give effect to this is that each market customer’s load
for the purposes of the emissions reduction requirement will be reduced by any EITE
load it supplies in a compliance year. Across all market customers, each MWh of non-
EITE load will then be scaled-up by a factor such that it equals the total system load for
the purposes of the emissions reduction requirement.
The scaling factor will be calculated three months after the end of the compliance
period, based on the proportion of total system load to non-EITE load for that
compliance period. To provide market customers with greater certainty, the scaling
factor will be capped at a maximum based on the prior year’s proportion of system load
to non-EITE load (or based on a best estimate of future EITE load).
GreenPower load
Some businesses and household consumers undertake voluntary action to reduce
emissions associated with their electricity use. A prominent example is the
GreenPower program.49
The ESB proposes to facilitate the treatment of GreenPower in the emissions reduction
requirement to allow consumers to make an additional contribution to emissions
reduction beyond that required by the target.
Conceptually, this would be achieved by deducting a market customer’s GreenPower
load and associated renewable generation occurring in the compliance year from its
49 The GreenPower Program is a government managed scheme that enables Australian households
and businesses to displace their electricity usage with certified renewable energy, which is added to
the grid on their behalf. By purchasing GreenPower, households and businesses commit their
GreenPower Providers to purchasing the equivalent amount of electricity from accredited
renewable energy generators, which generate electricity from sources like wind, solar, water and
bioenergy. See https://greenpower.gov.au/About-Us/What-Is-GreenPower/ for more information.
39
total load and allocated generation. Similar to the wholesale pool purchases,
transmission and distribution loss factors will be applied to GreenPower loads.
However, the GreenPower arrangements were designed around ensuring additionality
to the RET, and do not contemplate the emissions reduction requirement.
Complications will arise to the extent that surrendered large-scale generation
certificates (LGCs) under GreenPower cannot be matched to an allocation of
generation in the registry. Subtracting GreenPower load from a market customer’s load
without subtracting any generation from the registry would leave it unbalanced.
The ESB intends to work with the National GreenPower Steering Group to find a way to
achieve the policy goal of additionality within the framework of the Guarantee.
Registry operations
The registry provides the necessary infrastructure to facilitate efficient compliance with
the emissions reduction requirement. It allows market customers to be allocated a
share of a generator’s output and associated emissions, and to present this for the
purposes of compliance in respect of their load. The proposed approach to registry
operations is outlined below and is detailed further in the Technical Working Paper on
the Emissions Registry.50
It is proposed that the registry will be administered by AEMO, as an enhancement to its
existing systems. AEMO already holds most of the data relevant for the Guarantee’s
operation – in particular, pool generation and wholesale pool purchases. It also has
some existing data exchange protocols in place with the Clean Energy Regulator
(CER). As the registry administrator, AEMO’s responsibilities will include developing
detailed procedures for interacting with the registry and managing IT requirements. The
AER will have complete access to the registry to facilitate its role in monitoring and
enforcing compliance.
The registry will record the emissions per MWh for each generator to apply to a given
compliance year. This will occur before the start of the compliance year.
Emissions data used to calculate the emissions intensity will primarily be sourced
from NGER, for the financial year two years prior to the compliance year.
Any gaps in the NGER emissions data will be addressed in appropriate
legislation, regulations or Rules. For instance, provisions will be made for
estimating the emissions per MWh of new or refurbished generators.
From the start of the compliance period, pool generation and wholesale pool
purchases data will be provided into the registry. This data is settled by AEMO in
weekly batches, and each week’s data first becomes available four weeks in
arrears. The wholesale pool purchases data is subject to 20 and 30 week
revisions, but will be taken as final for the purpose of compliance as at 30
September following the compliance year.
50 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports -papers.
40
Figure 4.1: Example of information recorded in the registry
The registry will also record other information, including output from embedded
generation and rooftop solar PV and exempt EITE loads. Depending on the source
availability, this data may be recorded during or after the compliance period, but no
later than 30 September following the compliance year, at which point all data is taken
as final for the purpose of compliance. The registry will also record the use of flexible
compliance options.
Throughout the compliance period and prior to the reporting deadline, the registry will
match emissions to each market customer based on the allocated generation volumes
as recorded at the point in time. Market customers will be able to use this information to
monitor their compliance position. Following the reporting deadline, the information
recorded in the registry will be used by the AER to assess compliance.
Only market customers and generators will have accounts in the registry. Some
information will be made public at given intervals. For instance, for each generator, its
unallocated generation will be published by AEMO on a regular basis (e.g. weekly or
monthly), alongside its pre-assigned emissions intensity.
4.2.1.4 Flexible compliance options
Providing flexibility in how market customers meet the emissions reduction requirement
will minimise instances of non-compliance and reduce the costs of the mechanism to
market customers, and in turn, electricity consumers. This flexibility will allow market
customers to manage variables such as unexpected generator outages and potential
delays to the entry of new generators. Importantly, providing this flexibility will not
change the emissions outcome for the NEM. The required emissions outcome for the
NEM will still be achieved over the medium-term despite year to year fluctuations.
41
The proposed approach to implementing the flexible compliance options is outlined
below and is detailed further in the Technical Working Paper on the Emissions
Registry.51
Carrying forward over-achievement
Market customers will be permitted to carry forward a limited amount of a previous
compliance year’s over-achievement, for use in a later compliance year. This is
expected to incentivise investment when the market needs it and should enable market
customers to achieve compliance at a lower cost.
Each year, a market customer will be able to carry forward an amount (in tCO2-e) of up
to:
5 per cent of the electricity emissions target for the first year of the emissions
reduction requirement for each MWh of load, plus
a fixed amount of 60,000 tCO2-e.
No market customer will be allowed to carry forward an amount more than 100 per cent
of the first year’s target as applied to its load.
Example of carrying forward over-achievement52
Hypothetically, the electricity emissions target for the first year of the emissions reduction
requirement is set at 0.8 tCO2-e/MWh.
Market Customer A has 10,000,000 MWh of load.
They can carry forward a total amount of up to 460,000 tCO2-e, calculated as: 400,000 tCO2-e [= 5% × 0.8 × 10,000,000], plus
the fixed amount of 60,000 tCO2-e
This carry forward amount is equivalent to 5.75% of their load. Market Customer B has 50,000 MWh of load.
They cannot carry forward the full amount of 62,000 tCO2-e, calculated as:
2,000 tCO2-e [= 5% × 0.8 × 50,000], plus
the fixed amount of 60,000 tCO2-e This is because this full carry forward amount is equivalent to more than 100% of their
load at
0.8 tCO2-e/MWh [= 62,000 / (0.8 × 50,000) = 155%]
Instead, they can only carry forward 40,000 tCO2-e.
51 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports -papers.
52 This example assumes the 50,000 MWh exemption as discussed in section 3.3.2 is already
accounted for.
42
This approach ensures that the largest market customers will face an effective carry
forward limit of around 5 per cent of the first year’s target as applied to their load,
whereas smaller market customers will have a higher effective limit.
There would be no need to apply a carry forward limit if all market customers have
access to enough low emissions generation to meet the electricity emissions target in a
given compliance period. However, this can only be assessed once the compliance
position of each market customer is known. Accordingly, the limit would be lifted in any
year where all market customers were found to be compliant with the electricity
emissions target.
To remain appropriate to market conditions, the limit will be able to be updated through
rule-change processes in the future.
Deferring compliance
To provide adequate flexibility for market customers while ensuring the emissions
reduction trajectory is met, market customers will be able to defer 10 per cent of the
electricity emissions target per MWh of load.
The limit will be cumulative over two years, with the market customer required to make
good in the third year on the first year’s deferral amount. This will provide sufficient lead
time for market customers to make investments in generation to meet the electricity
emissions target, as needed. It will also assist market customers to manage annual
variability in demand, variable renewable generation and hydro production.
Beyond this limit, any additional increase in the market customer’s emissions intensity
above the electricity emissions target will mean the entity is non-compliant.
To remain appropriate to market conditions, the limit will be able to be updated through
rule-change processes in the future.
This approach balances the need for flexibility without undermining the objective of
providing long-term policy confidence through delivery of the requirements of the
Guarantee.
Use of offsets
The Commonwealth Government is continuing to consider whether market customers
should be able to use external offsets as a flexible compliance option to meet the
emissions reduction requirement, and if included, whether to apply conditions, such as
an overall cap on the number of offsets that could be used.
If offsets are permitted, the NEL and Rules would provide details regarding their use.
This would include a mechanism for linking offsets surrendered in the Australian
National Registry of Emissions Units (ANREU) for the purpose of the emissions
reduction requirement, to compliance calculations for market customers.
In addition, if the Commonwealth Government set an overall cap on the number of
offsets that could be used across the electricity sector, the NEL and Rules would
43
address how to establish individual allowances of offsets across market customers in
the NEM.
Further information on the treatment of external offsets can be found in the Department
of the Environment and Energy's Draft Detailed Design for Consultation –
Commonwealth Elements document.53
4.2.1.5 Reporting and compliance
For the Guarantee to achieve its policy objectives, it is important to have a robust
framework for monitoring and enforcing compliance with the emissions reduction
requirement and its associated reporting requirements.
A market customer will be deemed ‘compliant’ with the emissions reduction
requirement for a given compliance year when the emissions intensity of its allocated
generation is below the electricity emissions target for that year or when it exceeds the
electricity emissions target by a margin less than or equal to the deferral limit (see
section 4.2.1.6 under Deferring compliance). A market customer which exceeds its
electricity emissions target by more than the deferral limit will be deemed ‘non-
compliant’.
The primary aim of enforcement is to ensure policy objectives are met. Effective
enforcement requires the enforcement agency to have resources to determine when an
entity has not complied with its obligations, and to impose an appropriate penalty – one
that is proportionate to the offence, acts as a deterrent, and provides greater certainty
that the policy objectives are to be met.
Some key elements of reporting and compliance – including defining compliance, the
approach to reporting on compliance, the timeframe for assessing compliance,
reporting and administrative requirements, and enforcement options – are detailed
further in the Technical Working Paper on Compliance and Penalties for the Emissions
Reduction Requirement.54
The AER as the enforcement agency for the Guarantee
The AER was established in 2005 and enforces the laws for the NEM, and monitors
and reports on the conduct of market participants and the effectiveness of competition.
The AER is also the economic regulator of the electricity networks. This role currently
extends to electricity networks in all jurisdictions except Western Australia. The AER
operates under the Competition and Consumer Act 2010 (Cth) and shares staff,
resources and accommodation with the ACCC.
In light of the need to integrate the dual requirements of the Guarantee with the
functioning of the energy markets, and the fact that the enforcement agency for the
Guarantee will need to enforce requirements set out in the NEL and Rules (see
53 National Energy Guarantee Draft Detailed Design for Consultation – Commonwealth Elements
http://www.coagenergycouncil.gov.au/publications/national-energy-guarantee-draft-detailed-design-
commonwealth-elements
54 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports -papers.
44
Chapter 8), the AER is considered best placed to monitor and enforce compliance with
both requirements of the Guarantee. In doing so, it will use information provided by
agencies such as AEMO and the CER.
In carrying out its role, the AER will draw on a range of enforcement tools that already
exist under the NEL. These are discussed under Enforcement tools for emissions
reduction requirement below.
The AER will report annually on high-level compliance outcomes for each compliance
year, by 31 December following the compliance year. The information published will
identify by name all market customers and their emissions intensities for the given
compliance year. The information published will also include other relevant parameters,
such as:
the final emissions intensity of unallocated generation in the registry
any over-allocation by market customers
the extent of the use of flexible compliance options
the extent of EITE exemptions provided, and
the amount of load allocated to GreenPower.
This publication approach will help to promote and maintain a culture of compliance
and provide transparency to electricity consumers.
The compliance period
The compliance period for the emissions reduction requirement will be on a financial
year basis.
There will be a specified reporting and revision window after the end of each
compliance period, with a deadline of 31 October. This will allow for relevant data to be
finalised by 30 September and any allocation imbalances in the registry to be resolved
in the following month. The AER will commence assessing compliance for the period
from 1 November onwards.
Figure 4.2 shows a timeline for the compliance period, including the timing for
availability of key data inputs – in particular, exempt EITE load and NGER emissions
data (to be sourced from the CER), and transmission and distribution loss factors (to be
sourced from AEMO). These data inputs and their timing were outlined in section
4.2.1.5).
45
Figure 4.2: Simplified timeline of the compliance period for the emissions reduction requirement
Reporting and administrative requirements
The proposed compliance framework for the emissions reduction requirement has
been designed to minimise the reporting burden on market customers and generators.
Where possible, the reporting required to assess compliance will build on existing data
sources (for which the existing frameworks for monitoring and enforcing reporting
requirements will continue to apply). Where new information is required to assess
compliance, such as emissions data for generation not currently captured in NGER,
additional reporting requirements will be introduced. In doing so, the ESB will be
cognisant to minimise duplication of existing reporting requirements and to draw on
existing systems and associated compliance arrangements wherever possible.
The ESB is considering the merits of introducing an anti-avoidance regime in the NEL
that relates to the Guarantee. This is intended to prohibit an entity which has a potential
obligation under the Guarantee from restructuring or taking other action for the purpose
of avoiding or minimising that liability. Anti-avoidance regimes are often included in
taxation and revenue laws to prevent tax structuring for the purposes of avoidance. The
anti-avoidance regime would be general in its scope, as distinct from specific
avoidance or anti-gaming measures which might be included in respect of specific
obligations. Such a provision could help to reduce the complexity of the regulatory
framework giving effect to the Guarantee.
Enforcement tools for emissions reduction requirement
If, despite the flexible compliance options described in section 4.2.1.4, market
customers fail to meet the emissions reduction requirement, the AER needs to be able
to enforce compliance in a way that minimises costs for consumers. The AER already
has access to a range of compliance tools and discretion in deciding whether to take
enforcement action and the nature of that action. Each case is assessed on its merits.
In determining an appropriate enforcement response, the AER considers all relevant
factors and circumstances.
The AER will publish guidance on the enforcement options within its power and the
circumstances in which they are likely to be applied in the context of the Guarantee and
the emissions reduction requirement.
46
Culture of compliance
The primary approach will be to build a culture of compliance. Minimising non-
compliance through informing, educating and engaging stakeholders is better than
enforcement action after a breach has occurred. The AER will actively educate and
engage with the market to ensure participants understand their obligations and
encourage compliance under the Guarantee. Annual reporting of compliance will also
encourage a culture of compliance.
Civil proceedings
The AER can initiate civil proceedings in the courts for alleged breaches of civil penalty
provisions of the NEL:
A court may order an injunction requiring a person to do something or desist from
doing something.
A court may order that an entity pay a financial penalty (a ‘civil penalty’) as a
result of breaching its obligations.
The existing definition of civil penalty in the NEL should be amended in order to provide
for more meaningful penalty levels to apply under the Guarantee.55 A civil penalty with
a new upper limit of $100 million will apply in the following circumstances:
Non-compliance by market customers with the emissions reduction requirement,
in exceedance of the deferral limit.
Any non-compliance by market customers with the requirement to not over-
allocate generation to their load in the registry (as discussed under Generation
and emissions allocation approach in section 4.2.1.3).
It is likely a court would take into account the circumstances and reasons surrounding
the non-compliance and other relevant factors in awarding a penalty within the upper
limit. The guidance published by the AER will outline the factors which are likely to be
taken into account when determining a civil penalty level.
Additional enforcement options
The AER, at its discretion, may seek to undertake other enforcement options in place
of or in addition to civil penalties:
Administrative undertakings are a more informal and less intrusive enforcement
option which the AER would use to resolve certain matters. The AER may be
more likely to act administratively where the effect of an actual or potential
contravention is limited, and an entity has taken (or agreed to take) appropriate
steps to end the conduct and to remedy any harm done.
55 It is likely this will need to occur irrespective of proposed changes to civil penalties currentl y being
considered by the COAG Energy Council as part of its AER Powers and Civil Penalty Regime
review.
47
Infringement notices give a recipient an option of paying a penalty in full (without
there being an admission of breach) or electing to have the matter heard in court.
The existing infringement penalty for a breach of a relevant civil penalty provision
is up to $20,000. It is proposed that infringement notices of additional value are
created to provide more meaningful penalty options to apply under the Guarantee.
These could be applied to breaches of reporting requirements or other breaches
of a similar nature.
Court enforceable undertakings are written statements from an entity that it will
take specified actions (for example, entering into contracts in order to resolve a
breach), and will be used in addition or as an alternative to infringement notices.
Compliance can be enforced by the courts. The AER may use enforceable
undertakings to manage situations where market customers have clearly shown
efforts to enter into contracts or arrangements but they have not delivered as
expected. The AER may also use enforceable undertakings to require a market
customer to make up in future years for a previous failure to meet its electricity
emissions target, to help ensure that the NEM as a whole does not fall short of the
emissions reduction trajectory set by the Commonwealth Government.
4.2.1.6 Other considerations
Interaction with the Large-scale Renewable Energy Target
The Large-scale Renewable Energy Target (LRET) is designed to deliver 33,000 GWh
of large-scale renewable generation per annum by 2020, the target does not increase
beyond this. The current target operates in isolation of broader energy policy and
consequently investment has been driven without regard to the security and reliability
of the NEM. The Finkel Review found that “the Large-scale Renewable Energy Target
scheme should remain unchanged to the end of its design life, but not be extended in
its current form”.
The Guarantee brings together climate and energy policy for the first time,
consequently future investment in low emissions technology will be rewarded through
the emissions reduction requirement of the Guarantee. However, the existence of the
LRET and any participation in this scheme does not preclude this generation from also
being included in the Guarantee and contributing to achieving the emissions reduction
trajectory for the sector. Some stakeholders have argued that the LRET should be
locked to new entrants once the target is met. This would artificially inflate the price of
large-scale generation certificates and unnecessarily increase costs to customers.
The ESB supports the Finkel Review conclusion that no changes should be made to
the LRET, which is legislated to continue through to 2030. Following the
implementation of the Guarantee, the LRET should continue as legislated without
closure to new entrants as suggested by some stakeholders. All renewable generators
will contribute to achieving the emissions reduction trajectory established for the
electricity sector under the Guarantee.
48
Interaction with State and Territory renewable energy targets
Some States and Territories in the NEM have renewable energy targets that imply
greater ambition out to 2030 than the proposed emissions reduction trajectory for the
Guarantee. All State and Territory renewable energy schemes can operate with the
Guarantee and contribute towards achieving the emissions reduction trajectory for the
Guarantee.
4.2.2 Reliability requirement
4.2.2.1 Overview
The reliability requirement of the Guarantee is designed to incentivise retailers and
large customers (liable entities) to support the reliability of the power system, through
their contracting and investment in resources.
If the reliability obligation is triggered, liable entities may be expected to demonstrate
future compliance by entering into qualifying contracts for ‘dispatchable’ capacity
(including demand response) to cover their share of system peak demand at the time
of the gap.
The eight high-level steps to the reliability requirement are:
1. Forecasting the reliability requirement
2. Updating the reliability requirement
3. Triggering the reliability obligation
4. Liable entities
5. Qualifying contracts
6. Procurer of last resort
7. Compliance
8. Penalties
These steps are outlined in sections 4.2.2.2 to 4.2.2.9 below, and are detailed further in
the Technical Working Papers.
Figure 4.3 below presents an overview of the timelines of the various components of
the reliability obligation. If the requirements are met, the reliability obligation will be
triggered three years out from the forecast reliability gap. Once the reliability obligation
is triggered, liable entities are put on notice that they may be required to demonstrate
future compliance.
At one year from the forecast reliability gap (T-1), if a sufficient gap persists, AEMO will
seek approval from the AER to use its safety-net procurer of last resort to access the
RERT framework to procure the required resources to close the remaining gap, and
liable entities will have to disclose their contract positions to the AER. If actual system
demand (at T) exceeds that which would be expected to occur one in every two years,
49
then the AER will assess the compliance of liable entities.
Figure 4.3: Simplified timeline for various components of the reliability obligation
4.2.2.2 Step 1: Forecasting the reliability requirement
Using the Electricity Statement of Opportunities (ESOO), AEMO will forecast whether
the reliability standard is likely to be met (or not) in each NEM region over a 10-year
outlook period. If the forecast is that the reliability standard will not be met, AEMO will
identify the size of any ‘gap’ in supply/demand response.
The Guarantee is based on using unserved energy (USE) forecasts reported in the
ESOO to assess reliability in each region for the next ten years. To support liable
entities to make informed decisions, additional descriptive information will be required
to provide further context to support these USE forecasts including:
an indication of the additional capacity required to ‘close’ the gap by reducing
USE to an acceptable level
the pipeline of potential generation projects over the forecast period, along with
progress of their development
likely time of occurrence of the shortfall, such as season and time of day
duration of the expected shortfall, and
indicative examples of conditions under which USE is occurring.
Since AEMO’s ESOO forecast could form the basis of a regulatory obligation, they will
be subject to a robust and transparent process along with an annual performance
review.
Sufficient information will be made available so that the ESOO forecast is reproducible
(or close to) by an independent forecaster or reviewer.
50
To provide confidence to market participants in the quality of the ESOO forecast,
AEMO will be required to assess its forecasting process against AER best practice
guidelines.
AEMO will be required to consult on its forecasting process with stakeholders
through a more formal consultation process (set out in published guidelines).
AEMO will consult with stakeholders on defining performance metrics and
consider back-casting as part of the performance monitoring. Forecast
performance will be reported and published at least on an annual basis.
AEMO will be required to publish and consult on a proposed improvement
program, and then report on it as part of the next ESOO.
AEMO will continue to work with the Reliability Panel on the appropriateness of the
current Reliability Standard in the face of an increasingly ‘peaky’ supply-demand
balance. The intention of the Guarantee is to remain aligned to the Reliability Standard
while ensuring there are adequate resources available to meet peak (as opposed to
average) demand.
4.2.2.3 Step 2: Updating the reliability requirement
The ESOO publishes expected USE forecasts to assess reliability in each region over
a 10-year outlook. As expected USE is consistent with the framing of the reliability
standard, it is proposed that this expected USE by region and year continue to form the
backbone of reliability assessment under the Guarantee.
Annual updates to the ESOO will continue unless there is a need to update forecasts
more frequently due to a material change to the supply/demand outlook. AEMO may be
required to undertake a six monthly ESOO update following a decision to trigger the
obligation, with little advance 'notice', at year T-3; that is, where there is a significant
change in ESOO outcomes from year to year.
4.2.2.4 Step 3: Triggering the reliability obligation
Calculating the materiality of the ‘gap’
The identification of a reliability gap will signal to the market the additional generation
output or demand response required over the period in question.
If AEMO has identified a reliability gap in its ESOO forecast three years out from the
period in which the gap is forecast, it will need to form a view on whether the gap is
sufficiently ‘material’ to trigger the reliability obligation of the Guarantee. If it is, AEMO
will be required to submit a request to an independent entity to trigger the reliability
obligation on retailers and large customers.
The basis for the assessment of materiality must be clearly defined and transparently
communicated to support liable entities to predict their potential liability and to close the
gap as efficiently as possible. Determining whether a reliability gap is ‘material’ requires
a balance between certainty and predictability together with flexibility to accommodate
changing market conditions. This can be achieved by the use of more objective criteria
51
such as a percentage of maximum demand in a region persisting for a given period of
time.
The Rules will set out a transparent framework to allow AEMO (and the independent
entity) to determine the materiality of a reliability gap. This could be similar to that
which applies to reviews of the market reliability settings by the AEMC’s Reliability
Panel. The framework will specify:
The timing of the materiality assessment.
Prescriptive requirements which must be adhered to as part of the materiality
assessment.
A requirement that AEMO must publish a guideline, as part of the annual ESOO
development consultation process, outlining how it will determine materiality.
How a material gap, and decision to trigger the reliability obligation, is
communicated to market participants.
The reliability obligation is intended to incentivise liable entities through contracting and
investment in resources to support the reliability of the power system. If a reliability gap
is identified through the ESOO forecast, then liable entities are placed on notice that
until the gap closes they may be required to demonstrate future compliance.
The role of the independent entity
The objective of the independent entity’s assessment is to provide confidence to
stakeholders that the information and processes informing any decision to trigger the
reliability obligation is robust given concerns about relying on forecasts to determine
the required level of capacity in the market.
The role of the independent entity is to provide a check on a request by AEMO to
trigger the reliability obligation. If approval is given, the reliability obligation is triggered.
The independent entity will require technical capability to check AEMO’s assessment
as to whether there is a material reliability gap, must be impartial and not affected by
the outcome of the decision, and have clear and express powers to trigger the reliability
obligation.
The AER will be assigned the role as the independent entity, as expected functions of
this role align with the AER’s existing energy market regulation remit. The AER will
need to develop technical capabilities to fulfil this function and will be tasked with
determining whether to accept a recommendation from AEMO to trigger the reliability
obligation.
The AER as the independent entity should follow a transparent and efficient process,
set out in a guideline, to give stakeholders confidence that the decision to trigger the
reliability obligation is justified.
To implement the preferred ‘light touch’ approach, the AER may develop appropriate
procedural check points with AEMO. This may include annual checks on AEMO’s
adherence to Consultation Procedures, regular forecast performance monitoring and
52
reporting on definitions and measures used, assumptions, modelling and analytical
approaches to estimating reliability gaps.
4.2.2.5 Step 4: Liable entities
The reliability requirement is designed to provide sufficient incentives for liable entities
to support the reliability of the system to prevent gaps in reliability emerging.
Retailers, in aggregate, should be willing to help manage the long-term reliability of the
power system on behalf of their residential and small-to-medium enterprise customers
because they are confident in their future demand for electricity.
The high-level design also noted the benefit of including large customers along with
retailers as liable entities. As acknowledged by some stakeholders, there is a range of
very large customers in the NEM whose future demand for electricity is unknown and is
unknowable to retailers. Without a long-term contract from these customers, retailers
(in aggregate) may be unwilling to help support the long-term reliability of the power
system on behalf of these customers without charging a significant risk premium.
Further, if the reliability obligation is placed only on retailers (on behalf of all their
customers) then the majority of the obligation to purchase contracts will be with a
concentrated number of market participants making it more difficult for smaller retailers
to compete, negatively impacting the affordability of electricity.
Giving large customers the choice to contribute to the reliability of the power system
directly, or to contract with a retailer, should ensure that the reliability requirement is
managed at least cost.
All retailers (large and small) will then be able to compete to manage the reliability
requirement on behalf of large customers. This should have significant benefits for
competition in the electricity market.
However, some large customers have suggested that this additional optionality would
negatively – rather than positively – impact upon them. Further consideration will be
given to the treatment of large customers under the reliability obligation prior to
completing the final detailed design of the Guarantee.
It is currently proposed that the Guarantee will set a threshold size of 5 MW peak
demand at a single site for large customers to be deemed liable entities under the
reliability requirement. This threshold includes an estimated 100 sites with total load of
36 TWh or 20 per cent of annual consumption in the NEM.
A large customer’s peak demand will be determined by historical load
performance, covering a period of at least 12 months to ensure the liability is
based on an accurate reflection of their operational demand profile. The entity
that has entered into the supply contract will be deemed liable.
New entrants – for example, entities commencing operations during the
compliance year – will be required to take steps to secure contracts or enter an
agreement with a retailer to manage their obligation for load over the forecast
gap period. Compliance with this requirement would be demonstrated by the
new entrant through it reporting relevant actions to the AER.
53
The ESB considers that the administrative burden involved in identifying relevant sites
and associated customers will not be excessive.
If the reliability obligation is triggered, then all liable entities that have not transferred
their obligation to a retailer will need to assess their likely share of system peak
demand and secure sufficient qualifying contracts to cover this. The existing contracts
of liable entities that are large customers, will be considered qualifying contracts (up to
the load covered by the contracts in place).
Liable entities will need to cover their share of the level of system peak demand which
would be expected to occur one in every two years. This requirement should provide a
safe harbour within the reliability obligation which helps prevent excessive costs being
incurred by over-contracting.
Customers falling below the 5 MW threshold will be provided the flexibility to ‘opt-in’ to
manage their own reliability obligation if they believe they can do so better, and at a
lower cost, than a retailer. For example, a corporate entity with a large load spread
over a number of sites may consider self-management of their load to support a more
cost-efficient outcome.
As a further safe harbour to promote competition and avoid disincentives to take on
additional commercial and industrial customers below the 5 MW threshold, under
specific circumstances, liable entities will be able to adjust their contract position within
the compliance year. This will allow liable entities to account for a specified material
change in circumstances; such as where a retailer has taken on additional large
commercial and industrial customers that are below the 5 MW threshold. However, to
ensure the objectives of the reliability requirement to promote efficient contracting are
maintained, retailers will not be able to adjust their T-1 contract position where they
take on new customer sites above the 5 MW threshold.
4.2.2.6 Step 5: Qualifying contracts
If the reliability obligation is triggered, liable entities will be required to enter into
sufficient qualifying contracts to cover their share of system peak demand at the time of
the reliability ‘gap’ to meet possible future compliance.
Qualification framework
Two approaches were considered in defining qualifying contracts: prescriptive; and
high level framework. Given that the key factor was to provide a financial incentive to
make available sufficient resources to close any gap, it is considered that any
wholesale contract with direct links to the electricity market which a liable entity uses to
reduce exposure to high spot prices should qualify, rather than being prescriptive about
the specific types of contracts that can be used.
In other words, the qualification framework with the reliability obligation will be based
on the principle that physical capacity follows the financial instruments used to hedge
54
physical market risk.56 Further, rather than require liable entities to provide all their
contracts to the AER at T-1, if a sufficient gap persists:
Liable entities will be required to aggregate all qualifying contracts which have
been bought and sold in the relevant region over the period of the gap and
submit their net contract position to the AER.
Liable entities will be required to ensure that the net position submitted has
been appropriately adjusted for the ‘firmness’ of contracts used for compliance
i.e. they will need to ensure that each contract is assigned an appropriate
‘firmness factor’, similar to the ‘delta’ used for risk measurement in financial
markets.
This firmness will be approximated by a ‘firmness factor’ which will consider
contract characteristics such as strike price, likelihood of cover over the period
of the gap, and volatility.
To provide assurance to the AER that liable entities have adopted a reasonable and
widely accepted approach to measuring the firmness of different instruments, they will
be required to submit an independent auditor’s report confirming the appropriateness of
the methodology adopted.
To help manage significant stakeholder concerns about the liquidity and transparency
of contract markets and the level of concentration in the electricity market, the ESB
considered five options as follows:
1. Centrally cleared contracts only would qualify.
2. Contracts recorded in trade repositories would qualify, with appropriate
reporting developed to facilitate transparency.
3. Large, vertically integrated retailers are covered by a ‘Market Liquidity
Obligation’ when the gap is triggered.57
4. A combination of options 1 and 2.
5. A combination of options 2 and 3.
Centrally Cleared Contracts
Centrally cleared contracts are contracts that are traded and centrally cleared on an
exchange (e.g. ASX Trade24 for derivatives including wholesale electricity contracts).
To promote liquidity these contracts are standardised in their design. For example, the
ASX currently lists $300 caps in each region in the NEM (other than Tasmania) but not
caps for other strike prices. To mitigate default risk these markets are managed
through a central counterparty, backed by a diverse range of financial institutions and
underpinned by a prudential and margining framework that is a party to all trades (i.e.
56 Submissions to the Department of the Treasury’s “Implementation of a framework for Australia’s
G20 over-the-counter derivatives commitments” highlighted the largely physical nature of electricity
contract markets that are primarily used to hedge physical market risk rather than for speculation.
57 All contracts and physical generation would qualify subject to the firmness test except when
combined with option 2 where contracts must be reported in a trade repository.
55
they become the buyer to every seller and the seller to every buyer.)
A centrally cleared only approach would be likely to enhance transparency and liquidity
as all positions would need to be traded through the market. However, the risks to this
approach are:
Limiting flexibility through use of only standardised contracts;
Reducing innovation as new product development is hindered;
Increased prudential, margining and transaction costs that could
disproportionately harm smaller participants;
Creating an illusion of liquidity while volumes can continue to be traded through
off-market trading mechanisms (Block Trades and ‘Exchange for Physical’).
Trade Repositories
Trade repositories are entities that centrally collect records of Over the Counter (OTC)
derivatives in a number of sectors. Under current ASIC requirements, the choice of
trade repository is up to the participant in the relevant market, with data stored
accessible only by ASIC for the purposes of monitoring the risks of financial contagion.
To enhance transparency in the event that the reliability requirement is triggered, a
regulator would need to access the repository data and then publish this in some form.
This would need to reflect privacy and competition concerns, which may involve the
cleansing and aggregation of data before publishing.
The use of trade repositories in the NEM has been limited as electricity derivative
reporting requirements are currently exempt. An intermittent trade repository
requirement that was aligned to the triggering of the reliability obligation would be
challenging due to lead times and set up costs for integrating systems and processes
with a repository. A key benefit of allowing trade repositories over a centrally cleared
only approach is the ability to support flexible, innovative and bespoke contracting.
While a trade repository and reporting approach could increase the transparency of
internal transfers at vertically integrated entities, the flexibility that trade repositories
provide and the opportunity this creates for bespoke contracting may undermine these
potential benefits.
Beyond the benefit of capturing internal transfers of vertically integrated entities, a
further opportunity for increased transparency can be delivered through the capturing
of relatively opaque ‘OTC’ contract markets. In 2014-15, the Australian Financial
Markets Report (AFMR)58 produced by the Australian Financial Markets Association
identified that approximately 16 per cent of surveyed electricity derivative volumes were
traded ‘OTC’, with the balance traded on centralised exchanges. While the AFMR
ceased surveying the electricity market in 2014-15, anecdotally the percentage of
‘OTC’ volumes traded has not increased.
58 Australian Financial Markets Association, https://afma.com.au/data/AFMR
56
Market Liquidity Obligation
A key concern raised by stakeholders is that trade repositories on their own may not
support liquidity. An important element in ensuring that the Guarantee does not
negatively affect liable large customers and small retailers is through a safety net
mechanism that provides liable entities with the confidence of being able to access
contracts when they need them. Given the challenges identified with a centrally cleared
only approach, the ESB is considering the benefits of an alternative mechanism called
a Market Liquidity Obligation.
The Market Liquidity Obligation would require large vertically integrated retailers to
make contracts available, for the period of the gap, on a centrally cleared platform.59
This would manage stakeholder concerns about access to contracts in the event that
the reliability obligation had been triggered. Obligated participants would be determined
based on a size threshold (ownership of a percentage share of generation) in a given
region and would need to involve more than one party in each region. Obligated
participants would be required to post bid and offer spreads for the quarterly flat and
peak swap products in the region over the quarter corresponding to the gap period.
Maximum bid-offer spreads would apply to both products, however pricing beyond this
would be at the discretion of the obligated parties.
Energy Security Board recommended approach
The ESB’s draft preferred approach is to adopt option 5 that combines the Market
Liquidity Obligation with a trade repository and reporting requirement. Qualifying
contracts would need to be either centrally cleared or reported in a trade repository;
including where vertically integrated retailers wanted to use their own generation.
Option 5 is preferred because this approach is most likely to ensure that if the reliability
requirement were triggered that it would not be detrimental to liquidity, transparency
and competition.
A key question for the ESB in finalising the detailed design of the Guarantee is whether
the benefits of implementing the trade repository requirement would warrant the costs
incurred by industry.
Voluntary ‘book-build’
In the high-level design the ESB agreed to further develop a voluntary book-build
approach to facilitate competitive market outcomes and provide liable entities with
additional optionality to traditional contracting processes in meeting their obligations
under the reliability obligation. Given the preferred approach is to implement a Market
Liquidity Obligation further consideration by the ESB will be made finalising the detailed
design on whether the voluntary book-build is required. The ESB invites feedback from
industry on the benefits and costs of a voluntary book-build.
If implemented in the final design, the primary benefit of the mechanism will be to
provide an opportunity for liable entities to secure contracts which are underpinned by
the prospect of physical resources. It will additionally provide contracting options to
assist liable entities – in particular, small retailers and large customers – to lock in
59 Further consideration is needed on how this requirement would apply to the Tasmanian region.
57
qualifying contracts in the event that the market is not sufficiently liquid. Contracts
delivered through the book-build will qualify for compliance under the reliability
obligation.
If the reliability obligation is triggered, AEMO will invite interested parties to lodge an
expression of interest to participate in the ‘book-build’. The ‘book-build’ will be
conducted by inviting sellers to make offers to sell new contracts for the duration of the
gap and for buyers to make offers to buy new contracts. AEMO will aim to match
buyers and sellers in a way that delivers the maximum closure of the gap. AEMO will
not take on any financial exposure or credit risk, with all risks to be borne by the
participants.
The book-build process will be run by AEMO three years out from a forecast gap if the
reliability obligation has been triggered. If a reliability gap continues to persist then
AEMO will have the option to re-run the book-build again two years before the reliability
gap is forecast to occur.
If implemented, AEMO would be required to consult with industry and other
stakeholders to develop a set of guidelines and procedures outlining how it will conduct
the book-build process.
Demand response contracts
The development of demand response products that qualify under the reliability
obligation will be central to ensuring the reliability requirement of the Guarantee is met
at least-cost. Products will qualify provided they meet the same criteria as other
financial instruments, that is, it must have a direct link to the electricity market which a
liable entity used to manage exposure to high spot prices. The demand response will
have to be ‘in-market’, meaning it is not eligible to be contracted by AEMO through the
Procurer of Last Resort, and allocated to a liable entity and a supply region.
In addition, to provide AEMO visibility of demand response in its forecasting processes
and support compliance, demand response contracts will need to be registered with
AEMO via its Demand Side Participation Portal. To avoid under or over-counting, rules
will apply to the treatment of relevant load as part of the reliability obligation’s
compliance and penalties regime (see steps 7 and 8 below).
4.2.2.7 Step 6: Procurer of Last Resort
The Procurer of Last Resort is the ‘safety net’ for the reliability obligation. If the
reliability obligation has been triggered and a sufficient reliability gap persists one year
out the AER will activate the requirement for retailers to provide details of qualifying
contracts.
Concurrently, AEMO will be able to commence procurement of resources through the
RERT framework to address the remaining gap.
Any resources procured via the RERT framework will be for supply ‘outside of the
market’ to avoid distorting the operation of the electricity market.
AEMO will work with relevant state governments and other market bodies on an
ongoing basis to ensure the nature of any reliability ‘gap’ is well understood along with
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the pipeline of potential projects to resolve the reliability ‘gap’. If, at any time, AEMO
and/or a relevant state government feel that the specific circumstances in a particular
jurisdiction dictate that prudent action is required to ensure the ongoing reliability of the
electricity system, then either AEMO or the relevant state government can make a rule
change request that would be processed via a six week, expedited process. The rule
change could enable AEMO to commence its Procurer of Last Resort function earlier
than one year before the forecast reliability gap given the extenuating circumstances in
that jurisdiction at that time. It is not the intention of the Guarantee for AEMO to
become the default procurer of capacity for the NEM.
4.2.2.8 Step 7: Compliance
If AEMO identifies a ‘material’ gap in capacity three years in the future through the
publication of the ESOO, it will make a request to the AER to trigger the reliability
obligation. As the independent entity, the AER reviews AEMO’s request to trigger the
reliability obligation, and if consistent with an assessment framework, the request is
approved.
If the gap persists in one or more NEM regions one year out, retailers and liable entities
in the affected regions will be required to submit their contract position to the AER to
demonstrate they have sufficient enduring qualifying contracts over the gap period.
Following the compliance period, if AEMO has procured additional resources and peak
demand actually exceeds the one in two year forecast threshold, the AER will assess
the contract positions submitted by liable entities and confirm if the level of contract
coverage was adequate to meet their obligation.
The AER will use data for each trading interval in a region in which demand exceeded
the one in two year forecast to determine each liable entity’s share of demand in that
interval. It will then compare liable entities’ contract positions with their share of
demand in that interval, scaled back to the one in two year forecast consistent with the
‘safe harbour’ provision that contracts should only be required to meet the one in two
year forecast. The calculation of each liable entity’s actual demand will be determined
by the AER based on metering data provided by AEMO.
The ‘compliance period’ will be a set of trading intervals – whether multiple trading
intervals in a day or intervals over multiple days – across the reliability gap period in a
region in which regional demand exceeded the one in two year forecast. The AER will
assess all intervals where demand exceeds the forecast threshold.
Where liable entities are under-contracted in one or more trading intervals, the AER will
calculate the shortfall across the relevant compliance period. This shortfall will be used
to determine and assign penalties for non-compliance (see below).
Liable entities will be able to adjust their contract position within the compliance year to
account for a specified material change in circumstances; such as where a retailer has
taken on additional large commercial and industrial customers that are below the 5 MW
threshold.
59
The details of the compliance framework will be further developed in consultation with
stakeholders and will provide guidance on the types of information that will need to be
reported to the regulator and the form in which that information is to be reported.
4.2.2.9 Step 8: Penalties
Penalties will be assigned to retailers that are assessed to have fallen short of their
reliability obligation. These penalties will include at least some of the cost of procuring
necessary resources via the procurer of last resort function.
A two-stage approach to compliance and assignment of penalties will be undertaken:
The first stage of the penalty framework for the reliability obligation will allocate
costs to liable entities which have failed to meet their contractual obligations. A
liable entity found to be non-compliant will be charged a predetermined
proportionate cost per MW of non-compliance to refund a proportionate cost of
the Procurer of Last Resort costs to consumers.
In the second stage, the AER will retain its ability to apply its usual suite of
enforcement options in addition to the assignment of RERT costs in stage one.
These enforcement options would likely only be used for more significant or
repeated failures to comply with the reliability obligation. They comprise
administrative undertakings, enforceable undertakings and civil proceedings,
including issue of financial penalties.
The definition of civil penalty in the NEL will be amended to provide a
meaningful upper limit on the financial penalties which can be assigned for non-
compliance under the reliability obligation. Similar to rebidding civil penalty
provisions, the ESB considers up to $1 million would be an appropriate upper
limit on first offences, with up to $10 million the upper limit on repeat offences.
The contracted load of liable entities may undergo a material change that was
reasonably beyond their control, following submission of their contract position to the
AER one year ahead of a forecast gap (e.g. taking on additional large customers that
fall below the 5 MW threshold). To accommodate such circumstances, liable entities
will be able to apply to the AER for an amendment to their contract position.
4.3 Physically Backed Contracts
The National Energy Guarantee Draft Design Consultation Paper released in February
2018 envisaged the potential for ‘physical backing’ of certain types of contracts. This
approach would involve linking contracts to the physical plant or portfolio of plants that
generate the MWh under the contract.
In relation to the reliability obligation, the link between contracts and physical backing
(to be confident that reliability would be achieved) was stressed. The Draft Design
Consultation Paper stated:
“The degree to which a contract is physically backed will provide assurance that the
reliability requirement will promote investment and provide incentives for the
60
continued operation of physical assets. There are four ways that can be
considered:
Certain types of financial contracts will be considered to be eligible contracts
Financial contracts that are ‘certified’ as being reconciled back to a physical
source
Contracts will need to demonstrate that the generation or demand response,
the subject of the contract itself, was sourced from a dispatchable generator or
user
Physical ownership of generation assets as part of an integrated retail and
generation portfolio.
..[In relation to determining the extent of physical backing] there could be a
certification of financial contracts. This would have the benefit that for compliance
purposes, the contract can uniquely be identified with a particular physical
generator i.e. there is a stronger link between the financial contract and the physical
asset … which will reduce the risk of double counting. For example, OTC contracts
specify a buyer and a seller so can be used to identify the source, but because they
are financially settled can be sold multiple times against the same physical
generator. For example, a 500 MW generator could sell 500 MW of caps to one
retailer, buy 500 MW of caps from a generator, and then sell 500 MW of caps to a
second retailer. The reliability requirement needs to avoid double counting so there
needs to be a mechanism to tie the retailer contract to the physical capacity
available.
This could be achieved through allowing financial contracts to be certified against
installed physical capacity. In this example, only 500 MW can be certified so the
two retailer contracts would need to be either scaled to match the total, or the
contracts varied so that only one retailer could certify its contract. Under this
approach, only OTC swaps, caps and PPAs would be eligible to be certified, and
may lead different classes of contract under each category. Contracts which do not
specify sources such as futures or that are contingent on exercise such as options
would not qualify for certification unless a mechanism could be established to link
futures volumes to the physical backing. This could, however, have the impact of
limiting liquidity in the financial markets which would be counter to the objectives of
the Guarantee60.”
In relation to the emissions reduction requirement, contracts would be assigned an
emissions value based on their source. This approach would effectively tie the
contracts transacted to meet the reliability requirement to the emissions obligation.
Each contract would be assigned a value based on actual intensity, or a calculated
approach, that would result in liable entities ’ emissions intensity representing the
combination of contracts in their portfolio. The Draft Consultation Paper stated:
60 Energy Security Board, National Energy Guarantee Draft Design Consultation Paper,
February 2018, pages 37 - 38
61
“Retailers would report contracts of their choosing to demonstrate compliance with
the emissions requirement. These contracts could, but need not, specify the
generation source or emissions per MWh. Broadly speaking, the following three
types of contracts could be used by retailers to achieve compliance with the
emissions requirement.
1. Contracts that specify a generation source, which allows the emissions per
MWh to be directly determined. An example of such a contract is a power-
purchase agreement sold by a wind farm (with zero emissions).
2. Contracts that specify the emissions per MWh but do not specify a generation
source. While such contracts do not currently exist, the design of the emissions
requirement needs to allow for possible innovation in contract markets. An
example of such a contract in future could be an existing exchange-traded
contract with an emissions per MWh specification.
3. Contracts that do not specify either the emissions per MWh or a generation
source. Examples include existing exchange-traded and OTC swaps and
caps61.”
In relation to contracts that specify emissions per MWh but not a generation source, the
Draft Consultation Document suggested that contracts could be developed that specify
the emissions level for each MWh of electricity but are not linked to one specific
generation source. Examples of such contracts could include those that pool together
several generators with similar emissions within a region. They could also take the form
of a ‘stapled security’, where a specified amount of emissions per MWh is ‘stapled’ to
those types of contracts currently in existence (such as OTC or Australian Securities
Exchange-traded swaps).
In relation to contracts that specify neither an emissions intensity nor a generation
source, the Draft Consultation Paper suggested that a deemed emissions level could
be assigned to particular types of contract (such as ASX-listed swaps) sold in a region.
This could be based on the average emissions intensity of generators that sold that
type of contract, or, alternatively, all types of contracts sold in a particular region could
be deemed to have the same emissions level.
From a reliability perspective the benefit of a physically-backed approach is that it
would provide more assurance that the required investment needed to cover the gap is
actually occurring. However, this approach would potentially necessitate a fundamental
change not only to the contract market, but potentially to other aspects of the current
reliability framework, imposing significant costs on participants, reducing liquidity and
the fungibility of contracts. For example, the Australian Financial Markets Association
stated:
“… [T]he consultation paper appears to suggest that the electricity derivative
financial market should move to a more physical-backed version, rather than a
primarily financial one. AFMA believes that any shift in contracting markets from
financial to physically-backed would be detrimental to financial market
61 Energy Security Board, National Energy Guarantee Draft Design Consultation Paper,
February 2018, pages 16
62
efficiency, liquidity and price transparency, as contracts would be less
homogenous, and priced on a case-by-case basis.”
A physically backed contract market also has the potential to exacerbate existing
market structure issues, and considerable concerns about the competitiveness of retail
markets.
Some stakeholders pointed out that purely financial contracts already created strong
incentives for physical output, and so should be eligible contracts in their own right. For
example, AGL argued:
“… [W]e consider that investments in capacity should be made through the
existing financial incentives that participants have in the energy market to avoid
exposure to high prices at times of tight demand. We therefore strongly support
an approach that allows purely financial caps and swaps to be considered
qualifying instruments, as well as any new contractual forms that may emerge
which can be may be physically defended or backed, as well as physical
ownership of assets and specific physically backed contracts.”
From the emissions perspective, stakeholder feedback overwhelmingly suggested that
there were serious risks to the liquidity of existing contract markets if retailers were
required to tie their financial contracts to the physical supply of electricity and the
emissions associated with that supply. For example, the Australian Financial Markets
Association suggested that:
“AFMA believes that this suggestion [of a contract that specifies the emissions
per MWh but does not specify a generation source] may be problematic, as it
may detract from liquidity in the current market. This type of contract could
introduce a bespoke condition (emission) into the contract, and would mean
that the product would be non-homogenous and illiquid. It could also be
detrimental to the overall liquidity and depth of the electricity financial markets,
to the extent that it may take away liquidity from the standard contract markets,
both exchange traded and over the counter. In addition, depending on design,
there may be difficulties in determining an appropriate reference rate for
valuation and settlement, and difficulties in contractual arrangements under
standard ISDA (International Swaps and Derivatives Association)
documentation.”
Other stakeholders questioned the ‘fit’ between financial contracts and emissions
accounting. For example, Origin argued:
“It is not appropriate to seek to ascribe some level of emissions intensity to financial contracts. These contracts were never intended to be used in this manner and it is impractical to do so.”
A further challenge in implementing ‘physical backing’ of contracts relates to the
significant layer of administration for the liable entities and the AER in tagging and
validating the linkage on all contracts that were put forward as qualifying to meet the
reliability requirement.
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Table 4.1: Differences between the Guarantee and physically backed contracts
THE GUARANTEE PHYSICALLY BACKED CONTRACTS
Emissions
contract
requirements
A liable entity can demonstrate its right
for generation to be assigned to it
based on any contractual arrangement
they have with a counter party.
The two parties must agree to the
generation assignment in the
emissions registry.
A liable entity must have a contract
with a generator, such as a power
purchase agreement or exchange
traded/over the counter swaps and
caps. Swaps and caps used for
compliance in the emissions reduction
requirement must link to physical
output and emissions.
The two parties must agree to the
generation assignment in the
emissions registry.
Reliability
contract
requirement
If the reliability requirement is
triggered, a liable entity may be
required to demonstrate future
compliance by having sufficient
qualifying contracts to cover their share
of system peak demand at the time of
the reliability gap.
Qualifying contacts (including demand
response) are contracts, such as cap
and swap contracts, with direct links to
the electricity market that expose
contract sellers to high prices . These
do not have to be linked to a specific
generator, preserving liquidity and
competitive outcomes.
If the reliability requirement is
triggered, a liable entity must enter into
sufficient contracts that are physically
linked to dispatchable generators to
cover their share of system peak
demand at the time of the reliability
gap.
Existing standardised contract
products (such as ASX futures and
$300/MWh caps) would need to be
modified to specify the generator the
contract is linked
Registry alternatives
The ESB has considered options for the Guarantee's various components.
Fundamental to a scheme such as the Guarantee is tracking how generator emissions
are allocated to market customers. In the ESB's view a registry is the only practical way
to do this. A registry simplifies functions like reallocating between parties and
distributing any unallocated generation to uncontracted load. It also makes it easy to
enforce scheme rules like market customer load must equal generation and generation
load can't be over allocated.
An alternative is a risk-based approach to compliance, as used by the CER to
administer the Commonwealth Government’s Emissions Reduction Fund. This
approach would rely on market customers stating their emissions intensity and
providing a summary of their contract positions at the time of reporting. A risk
assessment framework would be used to identify market customers most at risk of non-
compliance and these customers would be a priority for auditing. An audit (by the AER
64
or an auditor contracted by the AER) would include reviewing a market customer’s
contracts to confirm their contractual position supports their stated emissions intensity.
Only a proportion of market customers would be audited in any one year but over a
number of years all would be audited.
This approach has the potential to reduce the administrative burden for market
participants, though it would likely increase the burden for the AER. For example, a
market customer would not have to verify every reallocation they’re involved with in the
registry. However, such an approach is impractical when it is central to the scheme's
integrity that every MWh dispatched in the NEM is accounted for. Further, large market
customers may have hundreds of contracts, making an audit time consuming and
expensive and limiting the number of audits a regulator could undertake.
The ESB considers there are no viable alternatives to a registry, and so the two options
in this RIS differ only in their contract requirements.
65
5 Impact Analysis
This section considers the costs and benefits of the two options being considered.
The ESB is seeking feedback on whether interested parties agree with the impacts
described in the following impact analysis.
The estimates of BAU trends and impacts of the Guarantee are drawn from modelling
by Frontier Economics used by the ESB in its November 2017 advice to the
Commonwealth Government. This modelling is not a forecast of the future but rather an
indication of what outcomes could be expected using reasonable assumptions. It is
important to note the model's sensitivity to assumptions such as technology costs, fuel
prices and generator retirements, discussed later in this section.
5.1 Business as usual
As outlined in the problem section, a continuation of the business as usual will not
achieve the COAG Energy Council's dual objective of meeting the Commonwealth
Government's emission reduction target while maintaining the reliability of the electricity
market.
Reliability
As shown in Table 5.1, renewable generation as a proportion of total generation under
business as usual was estimated to increase from 26 per cent in 2020 to 31 per cent in
2030. Intermittent renewable generation is estimated to increase from 18 per cent of
total generation in 2020 to 24 per cent in 2030. At the same time the proportion of
dispatchable renewable energy generation is estimated to remain constant.
Table 5.1: BAU Renewable generation output (% of total): 2020, 2025 and 2030
Type of renewable generation 2020 2025 2030
All 26% 29% 31%
Intermittent renewable 18% 21% 24% Dispatchable renewable 8% 8% 8%
Source: Frontier Economics
Table 5.2: BAU Output mix (% of total generation): 2020 and 2030
Year Dispatchable generation Intermittent generation
2020 81%* 18%* 2030 77%* 24%*
* Note: Does not add to 100 per cent due to rounding. Source: Frontier Economics
Emissions target
Under the BAU, renewable generation is estimated to increase from 26 per cent of total
generation to 31 per cent between 2020 and 2030.
As shown in Figure 5.1, by the end of 2030, CO2-e emissions will be 7.6 per cent above
the assumed Paris target if there were no change to current policy settings.
66
Figure 5.1: Annual Emissions under Business as Usual compared to assumed Paris Target
Source: Frontier Economics
NEM-wide wholesale prices are currently higher than historical levels, reflecting the
absence of new investment in dispatchable generation, and the withdrawals of
Northern and Hazelwood. Wholesale prices were estimated to fall from 2018 to 2022
due to the committed entry of almost 6,000 MW of renewable capacity across the NEM.
Wholesale prices are estimated to increase in 2022 as the assumed retirement of
Liddell power station reduces supply (see Figure 5.2).
As demand rises over time and there is a greater need for new investment, the impact
of a risk premium due to policy uncertainty also contributes to higher prices under BAU.
67
Figure 5.2: Historic NEM weighted prices in comparison to BAU case
Source: Frontier Economics
Business as usual regulatory burden
The electricity sector is highly regulated and has a number of compliance requirements
that intersect with the emissions requirement and the reliability requirement. These
include:
NEM spot market participants – Market customers and generators generally
trade in the spot market 24/7. They must meet AEMO's prudential and system
requirements and manage AEMO's market settlement process.
Generator regulation – Apart from trading in the spot market, generators must
comply with various technical and reporting requirements and follow electricity
dispatch instructions from AEMO.
Retailer regulation - Apart from trading in the spot market, retailers have a
range of regulatory and reporting obligations to consumers and the AER.
NGER reporting – Each year generators/facilities must determine their
emissions according to NGER requirements and report their emissions to the
CER.
RET compliance – Retailers must meet their annual LRET and SRES
compliance targets.
These requirements would be unaffected if the Guarantee were implemented.
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5.2 National Energy Guarantee
The Guarantee is designed to incentivise retailers and large market customers, through
contracting and investment:
to support the power system's reliability
to ensure the average emissions intensity of the electricity they sell to
consumers supports Australia's international emissions reduction commitments
The impacts of the Guarantee were initially modelled by the ESB and published in
November 201762. As some elements of the Guarantee have changed slightly since
the November paper was published, the analysis might not completely represent the
Guarantee’s full impacts. However, it is presented to give stakeholders an indication of
the relative magnitude of the likely impacts and the relative performance of the
Guarantee compared with BAU. It is these relativities, rather than actual modelled
outcomes, that provide the most valuable insights.
The November modelling of the wholesale electricity market provides an indication of
how wholesale prices, retail bills, emissions levels, and generator investment,
retirement and output may change with the implementation of the Guarantee, relative
to business-as-usual (BAU).
Modelling assumptions
For the purposes of modelling, the NEM's emissions budget is assumed to be
consistent with the Commonwealth Government’s stated 2030 emissions reduction
target. The emissions budget is the maximum aggregate emissions that could come
from the NEM and meet the NEM's share of Australia's emissions reduction target. This
has been translated to 1,352Mt CO2-e of emissions for the period 2021 to 2030, as
determined by the Commonwealth Department of Environment and Energy.
In the model, the emissions requirement increases financial contracting with low-
emissions generators, providing both certainty for low-emissions generation investment
and their cash flows to make that investment viable.
The Guarantee also requires market customers to contract for a certain level of
dispatchable generation in the NEM. This can include either thermal generation, or
dispatchable renewable generation such as solar thermal with storage or hydro.
Generators typically do not commit all of their capacity under a firm contract, to account
for the physical constraints of their plant. These constraints include the potential for
outages at higher plant operating levels and fuel constraints. In addition, market
customers’ demand for contracts also influences the extent to which a generator’s
capacity is contracted.
62 Energy Security Board Advice – The National Energy Guarantee 20 November 2017 -
http://www.coagenergycouncil.gov.au/sites/prod.energycouncil/files/publications/documents/Report
%20on%20the%20National%20Energy%20Guarantee.pdf.
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If the Guarantee’s reliability requirement is triggered, market customers are required to
contract a pre-determined proportion of their forecast load, and some market
customers may consequently need to increase the extent of their contracting. To the
extent that this higher demand for contracts is met from existing capacity, this will
increase the proportion of generation capacity contracted (and reduce the proportion
uncontracted). This is likely to lead to more competitive bidding in the spot market as
generators will bid lower to increase their chances of being dispatched in order to cover
their contracted capacity. This is likely to result in lower spot prices.
Lower spot prices may be partly offset by higher contract prices due to increased
contract demand, but this may, in turn, be offset by the lower risk faced by generators
from being able to contract more of their capacity.63
If the higher demand for contracts was not able to be met by existing resources due to
their physical constraints, the demand would be met from new entrants, which
improves system reliability and reduces the likelihood of extreme spot price events (i.e.
lowers volatility).
5.2.1 Price impacts
5.2.1.1 Wholesale price impacts
The Guarantee’s impact on prices is evaluated for both wholesale and retail prices.
Wholesale prices provide an investment signal for new generation or for retirement of
existing generation, while consumer impacts are best understood through analysis of
retail bills.
Figure 5.3 reveals NEM-wide wholesale prices are currently higher than historical
levels. This reflects a policy uncertainty-induced freeze in new entrant plant, outside of
subsidised renewable generation, withdrawals of Northern and Hazelwood and
increases in coal and gas prices. The steep decline in wholesale prices under both
BAU and Guarantee from 2018 to 2022 is due to the committed entry of almost 6,000
MW of renewable capacity across the NEM.64
This generation is already planned and so is not specifically incentivised by the
Guarantee. This price decline is also reflected in the price of baseload futures
contracts.65
Initially, the introduction of the reliability requirement leads to more competitive bidding
from coal and gas, which reduces prices in the Guarantee somewhat compared with
BAU. This difference in bidding has a minimal impact on price differences in 2021-22
as the market becomes oversupplied. In an oversupplied market, higher contracting
63 Contracting reduces the volatility of generators’ revenues, which lowers generators’ financing costs
and improves their ability to obtain adequate fuel supply contracts at a lower price compared to
remaining uncontracted.
64 The amount of committed generation is based on market data and Frontier Economics own
analysis, and includes projects under construction, financially closed, or and already committed
under the Snowy Hydro expansion, RET, VRET (650MW) and QRET (400MW). Only 460MW of the
7,700MW of committed generation is not being built under one of those three schemes.
65 Price of ASX-traded calendar-year baseload futures contracts, from https://www.asxenergy.com.au
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levels and more competitive bidding has less impact on prices as an oversupplied
market is already more competitive than a market with a tight demand/supply balance.
Figure 5.3: NEM weighted-average wholesale prices (incl. RET certificate costs)
Source: Frontier Economics
Beyond 2022, the assumed retirement of Liddell power station reduces supply once
again. This results in a sharper increase in prices in the BAU case than the Guarantee,
as bidding from existing dispatchable plant is more competitive under the Guarantee.
This price jump is similar to recent price increases following the withdrawal of Northern
and Hazelwood (see Figure 5.4), which leads to a much tighter supply/demand
balance. This is less severe in the modelling which assumes perfect foresight and
immediate replacement of retiring capacity with new entrant; this result may be more
severe in reality for the BAU case if new investment involves a lag.
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Figure 5.4: Historic NEM prices in comparison to BAU and Guarantee case
Source: Frontier Economics
As demand rises over time and there is a greater need for new investment, the impact
of a risk premium due to policy uncertainty also contributes to higher prices under BAU
compared to prices under the Guarantee.
Furthermore, to the extent the demand for contracts is met by supply of contracts from
new entrants, rather than from contracting existing uncontracted capacity, this provides
an additional constraint on a generator’s ability to set higher market prices.
5.2.1.2 Retail bill impacts
Retail bill estimates under both the Guarantee and BAU were developed from the
AEMC's Residential Electricity Price Trends 2017, which estimates bills for residential
consumers from financial year 2016 to financial year 2019.
Figure 5.5 shows the modelled range of average NEM-wide residential consumers’
annual bills under the BAU and Guarantee in 2020 and 2030. This is compared to the
annual expected bill in 2017. A retail customer’s bill is comprised of network, retail and
wholesale costs and the cost of other environmental schemes. Only the wholesale
component is modelled and network charges are estimated based on the information
available at the time of modelling. The average bill saving from implementing the
Guarantee policy, compared to the do-nothing scenario, is around $120 a year (in 2017
dollars) for the 2020 to 2030 period.
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Figure 5.5: Breakdown of retail bills in 2020 and 2030, NEM
Sources: AEMC; Frontier Economics
Furthermore, annual bills are consistently lower under the Guarantee than current bills,
over the 2020 to 2030 period. For example, average bills under the Guarantee over the
2020 to 2030 period are around $400 (in 2017 dollars) a year lower than the estimated
bill for 2017.
5.2.1.3 Ability to achieve emissions reduction target
The model imposed a cumulative target for 2021 to 2030 of 1,352 Mt consistent with
the Commonwealth government’s Paris commitments and determined the trajectory
that is the least-cost way of achieving the 2030 target over the decade. This resulted in
a mostly linear trajectory (see Figure 5.6). Annual emissions produced under BAU and
the Guarantee are also shown in Figure 5.6.
Emissions in both cases are projected to fall to 2023, reflecting:
falling demand forecasts,
the entry of a large amount of committed renewable energy capacity, and
the announced closure of Liddell (i.e. exits of committed generation capacity).
The decline in emissions stalls from the early 2020s under BAU once these schemes
are met and all committed investments are deployed; the target is not met in this case.
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Figure 5.6: Emissions under the Guarantee and BAU
Source: Frontier Economics
Emissions continue to fall under the Guarantee due to the emissions requirement. The
emissions trajectory modelled for the Guarantee is the least-cost way of achieving the
emissions target under the model’s assumptions relative to BAU.
5.2.1.4 Investment and retirements
The Guarantee is expected to drive differences in the type of new generation
investment, compared to BAU. The emissions requirement is expected to incentivise a
shift towards lower emissions technologies, while the reliability requirement is expected
to incentivise a shift towards dispatchable technologies. Those generators that have
both attributes are expected to be highly valued and likely recipients of increased
investment focus.
Figure 5.7 shows the amount of committed and uncommitted generation capacity that
enters and exits the NEM under the Guarantee vs. BAU. The majority of investment
throughout the entire period, and particularly earlier in the period, is committed (almost
6,000 MW). As per the definition of ‘committed’ capacity, the amount of capacity that
enters and exits is identical under the Guarantee and BAU. In contrast, the amount of
‘uncommitted’ or additional investment that occurs and plant that exits differs between
BAU and the Guarantee, and is therefore more informative about the Guarantee’s
impact on generation investment.66
66 Committed capacity reflects entry and exit that are not an outcome of the model. Uncommitted
investment reflects outputs from the modelling.
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There is more new capacity installed under the Guarantee than under BAU. For
example, around 4,400 MW of new uncommitted capacity enters by 2030 under the
Guarantee, compared to 861 MW under BAU (bottom panel of Figure 5.7).67 Overall,
the Guarantee results in extra capacity in the system which both boosts system
reliability and lowers wholesale prices under the Guarantee vs. BAU (see Table 5.3).
The Guarantee’s dual requirements results in greater entry of those technologies that
are both low-emissions and dispatchable, compared to BAU. The least-cost mix of new
investment under the Guarantee is comprised mostly of wind, followed by large-scale
solar PV, batteries and mid-merit gas.
Figure 5.7: Entry and exit of cumulative generation capacity by technology type
and year68
Source: Frontier Economics
Table 5.3 highlights that over the 2020 to 2030 period, the Guarantee encourages
1,086 MW more dispatchable generation capacity into the system, with this extra
capacity used to ‘firm up’ intermittent renewables. This is additional to the 2,543 MW of
committed investment in dispatchable generation capacity to 2030 under both BAU and
the Guarantee, comprising 2,000 MW through Snowy 2.0, a further 338 MW of pumped
storage hydro, 198 MW in solar thermal with storage and 7 MW in gas peaking plant.
67 Figure 5.7 only includes generation investment in the wholesale market, and therefore excludes
investment in rooftop solar PV. Investment is represented as positive, exit as negative.
68 The exit of uncommitted capacity under the Guarantee relates to the mothballing of those units of
Gladstone coal power station in operation under BAU (773 MW).
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No additional dispatchable renewable capacity enters under BAU beyond the
committed generation.
Table 5.3: Investment in uncommitted plant (MW)
Coal Gas Dispatchable renewable (incl. batteries)
Intermittent renewable
BAU 0 263 0 597 Guarantee 0 251 835 3,271
Source: Frontier Economics
5.2.1.5 Generation output
In addition to showing the path of new investment in generation technologies in the
NEM, the modelling can also provide insights into what proportion of generation output
comes from different generation technologies.
Table 5.4 shows the output of different generation technologies as a percentage of total
output in 2020 and 2030. Under the Guarantee, 36 per cent of generation output in
2030 will come from renewable generation, with four-fifths of this (i.e. 28 per cent of all
output) from intermittent renewables. In contrast, under BAU, 31 per cent of output will
come from renewable generation (23 per cent from intermittent renewables) in 2030.
Table 5.4: Output mix (% of total generation) by technology: 2020 and 2030
Mechanism
Year Black Coal
Brown Coal
Hydro Gas Solar Thermal
with storage
Solar PV (incl.
rooftop)
Wind
BAU 2020 55% 16% 8% 2% 0% 7% 11% 2030 48% 16% 8% 5% 0% 12% 11%
Guarantee 2020 57% 16% 8% 2% 0% 7% 11% 2030 45% 15% 8% 4% 0% 13% 15%
Note: Some years do not add to 100 per cent due to rounding. Source: Frontier Economics
Under both BAU and the Guarantee, the penetration of renewables increases from
2020 to 2030, with this increase largely due to higher penetration of intermittent
renewables. As expected, the increase in renewables is greater under the Guarantee
due to the emissions requirement. The proportion of total generation figures include
rooftop solar generation.
If the reliability obligation is triggered under the Guarantee, liable entities will be
required to enter into sufficient qualifying contracts to cover their share of system peak
demand. This provides an incentive for liable entities to support the reliability of the
system through their contracting and investment in resources, as qualifying contracts
are typically only offered by dispatchable capacity (or demand response) that is
available to be dispatched when the system needs it.
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5.2.2 Qualitative assessment of the Guarantee
Following on from the quantitative assessment of the Guarantee in the preceding
section, this section provides a qualitative assessment of the Guarantee. Such an
assessment should be made with reference to an assessment framework, which is
provided below.
When contemplating the integration of energy and environmental policy, it is important
to design a mechanism to achieve a reliability objective and an emissions reduction
objective that are consistent with the design of the energy market. In particular, The
National Electricity Objective (NEO), as stated in the National Electricity Law, is to
promote efficient investment in, and efficient operation and use of, electricity services
for the long term interests of consumers with respect to price, quality, safety and the
reliability and security of supply. The following principles are important to consider
when designing such a mechanism:
Certainty of achieving policy objectives – for mechanisms to be sustainable
and effective, they need to be able to meet their objectives in the face of a
changing and uncertain future. Without this ability to adapt when the future does
not turn out as expected, investors may begin to expect that a mechanism may
be changed in light of the actual outcomes, for example if demand is lower than
anticipated at the outset of the policy. This can lead to investors not having the
confidence to invest in new capacity. A credible and durable compliance
framework would also provide greater certainty that both requirements can be,
and are being, met.
Technology-neutral – a mechanism that allows the greatest variety of
technology options to assist in achieving its policy objectives will help minimise
the long term costs to consumers.
Geographically-neutral – a mechanism that is indifferent to where generation
technology options are to be located, and allows the locations selected to be an
outcome of the trade-off between economic costs and benefits, is likely to
minimise costs for consumers.
Appropriateness of risk allocation – a mechanism should allocate risks to
those parties best-placed to identify and respond to risks in an efficient manner.
Contract market liquidity – a mechanism that, through its effect on the
generation mix, preserves or enhances liquidity in the market for ‘firm’
contracts, will assist participants to manage risks efficiently for the long-term
benefit of consumers. Firm contracts are backed by generators that generate
when needed by customers and so are more valuable to customers than the
‘non-firm’ contracts offered by generators with intermittent output.
Implementation flexibility – the extent to which a mechanism can be
implemented in a manner that automatically adjusts or ‘self-corrects’ in the face
of changing demand, cost or other system conditions.
Cost estimates and impacts on consumers – consumer impacts are
assessed through wholesale prices, generator investment, retirement and
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output changes. As these cost estimates and impacts are sensitive to key input
assumptions, such as demand, fuel prices and generator retirements, it is
important to compare the relative differences in outcomes between different
sets of assumptions.
Adaptability and sustainability of mechanism design – investors need a
level of confidence that policy objectives can be met and that the mechanism
for achieving these objectives is sufficiently robust to deal with changes in
energy market conditions or policy objectives without succumbing to calls for
the mechanism or the policy objectives to be altered or replaced. This requires
that the acceptability of outcomes generated by the mechanism should not be
predicated on a single view of the future, whether that is a specific demand
forecast, relative technology or fuel costs, or the policy objective itself. Rather,
investors will need to be satisfied that the mechanism can yield predictable
outcomes given different market conditions and policy objectives. Without
confidence in the resilience of the mechanism, investment will not be
forthcoming and it is likely that neither the emissions reduction nor energy
policy objectives will be met.
Minimising regulatory burden – a mechanism’s regulatory burden should be
minimised by focusing compliance on only the key information needed to
assess and demonstrate compliance with the mechanism, leveraging existing
systems and processes for reporting and data collection as far as possible. That
is, a mechanism should be designed in a way that minimises the costs of
complying with the mechanism whilst achieving the mechanism’s desired policy
objectives.
Failing to consider Australia’s energy policy objectives when designing this reliability
and emissions mechanism is likely to result in higher prices for consumers in the long-
run and a less reliable and secure power system than would otherwise be achievable.
Conversely, designing the emissions reduction mechanism in a manner that is
consistent with governments’ energy policy objectives will contribute to the resilience
and longevity of both the emissions reduction policy and its associated mechanism.
5.2.2.1 Certainty of achieving policy objectives
Both the emissions and reliability requirements embed the policy objectives of
emissions reductions and a reliable power system, respectively, into the wholesale
electricity price. This provides certainty that the policy objectives will be achieved.
The Guarantee’s reliability objective is that system reliability is consistent with the
reliability standard. A greater level of contracting will encourage generators to invest in
their plant and offer their capacity into the spot market at their marginal costs to ensure
they are dispatched to fund their contractual requirements. Furthermore, the reliability
requirement would only bind when it is expected supply won't meet demand. This
makes it cheaper than other reliability mechanisms that could be used such as a
capacity market.
The design of the Guarantee therefore enables it to meet its policy objectives at lowest
possible cost, and it has the inherent ability to adapt to changes in the target without
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having to modify the scheme. On the reliability side, market participants are able to
adjust their contract positions to account for changes in their demand forecasts, so the
cost of the reliability requirement remains reflective of the value to the system of having
that additional reliability.
While these goals may change, the mechanism to achieve them will not. This would in
turn, promote greater investor confidence to invest in new generation capacity,
facilitating the achievement of the policy objectives.
5.2.2.2 Technological and geographic neutrality
Technology neutrality is one of the principles crucial to designing effective policy
mechanisms that are integrated with the energy market. Technology neutrality means
that the widest range of technologies is available to achieve the stated policy
objectives. Policies should not favour or subsidise certain technologies over others.
The emissions requirement is technologically-neutral. This means it supports the
lowest-cost ways of meeting the emissions requirement, whether that is improving the
efficiency of coal generators, fuel switching from coal to gas and/or building renewable
energy capacity, even under different assumptions about the future (for example,
assumptions about future gas prices or technology costs). The emissions requirement
is also geographically-neutral, as the choice of locations for the new generation
capacity in the NEM is selected solely on the basis of a cost-benefit trade-off.
The reliability requirement is technology-neutral. The obligation is regionally-based
reflecting the physical needs and constraints of the system, which limits the extent of its
geographic neutrality.
5.2.2.3 Appropriateness of risk allocation
The NEM is designed so that generators make investment and retirement decisions
based on price signals in the spot and contract markets, and face the outcomes of their
decisions. If electricity demand, fuel costs, or other variables are higher or lower than
expected, the primary implications for plant profitability are borne by generators, rather
than consumers or taxpayers. This is appropriate because generation businesses have
the expertise, information and commercial incentives to manage such risks efficiently.
In this way, the risk of changes in different variables is appropriately allocated to
generators, rather than customers, which helps promote the National Electricity
Objective.
The Guarantee maintains the existing pricing and risk management mechanisms in the
NEM for signalling whether new investment is required and whether generators should
exit. It does this by maintaining the balance of incentives and risks that ordinarily
prevail in the wholesale market. Investors will continue to be responsible for managing
risks associated with demand, fuel costs and plant fixed costs diverging from forecast
levels.
5.2.2.4 Impact on contract market liquidity
Market customers manage wholesale price and volume risks as a natural part of their
business. Generators have an incentive to contract to provide more revenue certainty.
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Retailers and generators are natural counterparties in such contracts and retailers are
the more appropriate counterparty to generators than governments. Risk-sharing
amongst market participants is common practice in the NEM, through the use of
forward contracts such as swaps and caps.
Therefore, the Guarantee is likely to promote contract market liquidity by requiring
retailers to contract with generators in order to meet their emissions and reliability
requirements. As a result, the Guarantee is likely to increase the demand for contracts.
These comments are consistent with the quantitative assessment of the Guarantee’s
impacts on the generation mix.
5.2.2.5 Implementation flexibility
The Guarantee’s design allows retailers and, through their contracts, generators to
determine the least-cost generation mix to meet the reliability and emissions
requirements. Competition incentivises retailers to meet their dual requirements at the
lowest possible cost to consumers, and a credible and durable compliance framework
would ensure both requirements are met. Similarly, generator competition would
ensure the lowest cost generation mix.
5.2.2.6 Adaptability and sustainability
The inherent flexibility of the Guarantee means it is likely to meet its policy objectives if
the emissions reduction target were to change. As discussed in the Implementation
and Review section (Chapter 8), the preferred implementation option is the design
elements of the emissions reduction and reliability requirements be in the National
Electricity Law and Rules. This would mean that the mechanism need not change even
if emissions reduction policy objectives change. This would make it more sustainable
and stable, promoting investor confidence whilst allowing for changes to the
mechanism to be considered via the open, transparent and consultative process of a
rule change request.
The Guarantee can also be designed in a manner that gives it flexibility to adapt to
changing market conditions, such as lower than expected demand or lower than
expected costs for new dispatchable renewables.
5.2.3 Distributional impacts
5.2.3.1 Impacts on prices
The Guarantee provides four key ways to lower prices:
1. By providing an integrated energy and emissions reduction policy and certainty
in the mechanism to deliver the policy, the Guarantee lowers the risks on
investment in new renewable and non-renewable generation capacity.
2. The Guarantee is likely to result in an increase in the proportion of generation
capacity contracted (and therefore reduce the proportion that is uncontracted).
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This will increase supply by incentivising generators to be available at times the
system most values the generation output (i.e. when spot prices are high). This
is likely to reduce both the level and volatility of spot prices due to a
combination of more competitive spot market bidding and the risk reduction
from having more capacity contracted.
3. The Guarantee will incentivise investment in low cost dispatchable resources,
which may include intermittent renewables ‘firming up’ their capacity, for
example by investing in storage. This will enable renewable generators to
supply firm-capacity contracts such as swaps and caps and compete with
existing dispatchable capacity, increasing contract supply and liquidity and
lowering contract prices.
4. The technology-neutral nature of the Guarantee’s reliability requirement means
both demand and supply-side resources can be used. By allowing demand-side
resources to compete with the generation sector, the Guarantee ensures that
supply-demand balance is achieved efficiently.
5.2.3.2 Impacts on market customers
Market customers will be responsible for meeting the electricity emissions target.
To record the allocation of generation in the registry, it must be requested by one party,
and approved by the counterparty.69 In practice, it is likely that generators or market
customers will be able to enter an allocation by completing a form on an online registry
platform and this form will then be electronically submitted to the counterparty to
approve. The form will be designed to minimise the administrative burden of submitting
allocations to the registry. Evidence of contractual or other arrangements underpinning
the allocation will not be required due to the counterparty endorsement requirement.
Once approved by the counterparty, the allocation will be recorded in the registry.
The parties can record allocations at any time during the compliance period. They will
also have four months after the end of the compliance period to continue to adjust their
portfolios by recording reallocations. This includes three months before all data is taken
as final at 30 September, plus one further month.
The process of recording and approving allocations in the registry is likely to introduce
minimal additional administrative costs for most market customers, above business as
usual management of operations. Additional capital expenditure to do this is likely to be
limited to one-off IT system, process and education expenses. Ongoing operational
costs of inputting data to the registry should be minimal as the registry design is likely
to be kept simple.
Managing contractual or other arrangements that underpin the allocations in order to
comply with the emissions reduction requirement may introduce some additional
operational costs for market customers, such as expenses associated with legal,
financial and regulatory expertise.
69 It is not intended that output could be directly allocated between generators.
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Providing flexibility in how market customers meet the emissions reduction requirement
will minimise instances of non-compliance and reduce the costs of the mechanism to
market customers, and in turn, electricity consumers. This flexibility will allow market
customers to manage variables such as unexpected generator outages and potential
delays to the entry of new generators. Importantly, providing this flexibility will not
change the emissions outcome for the NEM. The required emissions outcome for the
NEM will still be achieved over the medium-term despite year to year fluctuations.
The high-level design set out the flexible compliance options that will be in place for the
emissions reduction requirement, including that market customers will be allowed to
carry forward a limited amount of a previous year’s over-achievement for use in a later
compliance year, and will be allowed limited deferral of compliance to future
compliance years. The proposed approach to implementing the flexible compliance
options is outlined further in the Technical Working Paper on the Emissions Registry.70
Deferred and carried-forward emissions reductions will be recorded in the registry and
it is not expected that market customers would be required to input this information.
These requirements are estimated to be a modest impost in the context of the business
as usual management of a market customer’s operations.
5.2.4.3 Impacts on Generators
To ensure the registry operates efficiently, generators will have some ongoing
administrative requirements under the emissions reduction requirement. They will be
expected to enter or confirm allocations in a timely manner to allow AEMO to provide
regular updates of the contents of the unallocated pool and its emissions intensity.
They will have an administrative requirement to allocate all generation and associated
emissions by the reporting and compliance date.
These administrative requirements of entering or confirming allocations in the registry
are estimated to be a modest impost in the context of the business as usual
management of a generator’s operations. The registry design will aim to keep the
processes simple and ensure the administrative burden is minimised for participants.
The process of entering and confirming allocations for generators is expected to be the
same as that for market customers, as outlined in Section 5.2.4.2.
Additional operational costs may be incurred by generators in order to meet the
administrative requirement to allocate all generation and associated emissions in each
compliance period. This requirement may require generators to input greater time and
resources into contracting arrangements than they would under business as usual,
however this is not expected to be a substantial impost above existing contracting
processes.
Most generators are already required to report emissions data to the NGER system
annually and, as this data will be used for the Guarantee, additional emissions
reporting is not expected to be required.
70 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports-papers.
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5.2.4.4 Impacts on large and EITE customers (sourcing electricity direct from NEM)
The Commonwealth Government intends to exempt EITE load from the emissions
reduction requirement. This means that the emissions obligation under the Guarantee
will have little effect on EITE customers.
The ESB’s proposed approach to give effect to this is that each market customer’s load
for the purposes of the emissions reduction requirement will be reduced by any EITE
load it supplies in a compliance year. Across all market customers, each MWh of non-
EITE load will then be scaled-up by a factor such that it equals the total system load for
the purposes of the emissions reduction requirement.
The scaling factor will be calculated three months after the end of the compliance
period, based on the proportion of total system load to non-EITE load for that
compliance period. To provide market customers with greater certainty, the scaling
factor will be capped at a maximum based on the prior year’s proportion of system load
to non-EITE load (or based on a best estimate of future EITE load). AEMO will
regularly publish how the scaling factor is tracking based on the year-to-date proportion
of total system load to non-EITE load.
5.2.4.5 Impacts on Residential and business customers
As outlined above, the Guarantee is estimated to deliver savings to average annual
household electricity bills in the order of $120 between 2020-2030, compared to BAU.
Likewise, business customers are expected to benefit from lower electricity costs under
the Guarantee. The extent of savings depends on the size of the business and its
electricity usage. Larger businesses can typically negotiate lower electricity rates than
average household rates. As a consequence it is difficult to estimate the average
saving to businesses, however it is reasonable to assume that percentage reductions
in electricity rates would be similar to those estimated for households between 2020-
2030.
Businesses that will benefit the most from the Guarantee are those with high electricity
inputs relative to other business inputs. To the extent that these businesses either
export goods or services, and/or compete with imported goods and services, they are
expected to experience an increase in international competitiveness.
Residential and business customers not subject to the reliability requirement will not
experience any compliance costs as a result of the introduction of the Guarantee.
The guarantee proposes the reliability requirement apply to large energy users with
peak demand above 5 MW. Without this threshold, it would make it difficult for a small
retailer to compete for reliability contracts, as the obligation would be concentrated with
a few of the largest retailers. This could manifest in increased contracts prices for
smaller retailers, with the flow costs potentially making it more difficult for them to
compete, affecting competition in the market.
5.2.4.6 Impacts on Environment
One of the main objectives of the Guarantee is to reduce emissions arising from
electricity generation by 26 per cent on 2005 levels by 2030.
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If this emissions reduction target is met by 2030, Frontier Economics estimated that a
cumulative amount of 1,352 Mt of CO2 equivalent will have been abated.
5.2.4.7 Competition Impacts
This section describes current NEM competition concerns and how competition issues
have been considered in the Guarantee’s design.
NEM competition issues
In 2017, the Finkel Review highlighted concerns about wholesale market competition
and increased retail and wholesale market concentration, and the implications for price
and service outcomes.71 The ACCC is considering these issues of market
concentration as part of its Retail Electricity Pricing Inquiry.
The majority of stakeholder submissions to the ESB's discussion paper mention
various competition issues. In particular, the design must not undermine competition,
for example by inadvertently creating barriers to entry for new retailers or entrenching
the market power of vertically integrated retailers. Some submissions said the
Guarantee should be used to improve retail and wholesale market competition through
increased liquidity and transparency.72
Market share is one indicator, amongst many, of the potential existence of market
power. This section presents some standard market share-based indicators, for
generation and retail sectors and draws on the evidence presented in the ESB’s
November 2017 advice.73
Competition in the generation sector
Figure 5.8 shows market shares by generation capacity installed.74 In each NEM
region the combined market shares of the two or three most significant generators
exceeds 70 per cent on both capacity and dispatched energy measures. Tasmania-
excluded,75 South Australia’s generation sector has the highest degree of
71 Commonwealth of Australia, Independent Review into the Future Security of the National Electricity
Market (Finkel Review), June 2017, p.138 https://www.energy.gov.au/publications/independent-
review-future-security-national-electricity-market-blueprint-future.
72 Various stakeholder submissions, Energy Security Board National Energy Guarantee - Consultation
Paper, http://coagenergycouncil.gov.au/publications/energy-security-board-national-energy-
guarantee-consultation-paper.
73 See Chapter 6 of Energy Security Board, The National Energy Guarantee, Advice to the
Commonwealth Government, 20 November 2017.
74 Figure is based on capacity rather than output, it is likely to overstate the market share of
businesses that have mostly peaking generators (such as Origin in Queensland and Victoria), or
fuel-constrained hydro plants (such as Snowy Hydro), who may have a lot of generation capacity
but typically only run it for short bursts at peak times.
75 In Tasmania, Hydro Tasmania is effectively the only generator, but Tasmania has access to
mainland generation through the Basslink interconnector.
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concentration, with the largest generation business (AGL Energy) having a larger
market share (42 per cent) than the largest generator in any other NEM region.
Figure 5.8: Market shares in generation capacity, 201776
Source: AER, State of the energy market 2017, May 2017
As noted by the ACCC, generation sector concentration has increased over time.77 For
example, in 2011–12 Queensland consolidated some of its state-owned generation and
in 2012 AGL acquired full ownership of Loy Yang A in Victoria. More recently,
concentration has been exacerbated by the closure of a number of key facilities. In
particular, in 2015-16 Alinta exited SA when it retired its coal-fired power stations and
Engie’s share of the Victorian market was significantly reduced in 2016-17 when it
closed its Hazelwood power station.
In some NEM regions, a single generation business accounted for more than 30 or 40
per cent of dispatched energy in 2016-17. AGL, in particular, accounted for over 40 per
cent in each of NSW and SA, and over 30 per cent in Victoria. In Queensland, the
76 Note: Capacity is based on summer availability for January 2017, except wind, which is adjusted for
an average contribution factor. Interconnector capacity is based on observed flows when the price
differential between regions exceeds $10 per MWh in favour of the importing region; the data
excludes trading intervals in which counter flows were observed (that is, when electricity was
imported from a high priced region into a lower priced region). Capacity that is subject to power
purchase agreements is attributed to the party with control over output.
77 See Chapter 3 of Australian Competition and Consumer Commission, Retail Electricity Pricing
Inquiry, Preliminary report, 22 September 201
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state-owned CS Energy and Stanwell Corporation facilities each account for over 30
per cent of electricity generated.
Guarantee competition considerations
In general, the greater the extent of competition amongst market participants, the lower
the likely costs to consumers of achieving the Guarantee’s policy objectives.
Competition in the generation sector influences contract prices and therefore affects
the cost to retailers of meeting their requirements under the Guarantee. The greater the
effectiveness of this competition, the lower the cost to retailers. In addition, competition
in the retail sector influences the cost of the Guarantee to end-consumers. Retail sector
competition influences the extent to which the savings to retailers, from competition in
generation sector, are passed through to consumers.
The design of the emissions reduction and reliability requirements will support the
liquidity, transparency and competitiveness of the NEM in the following key ways:
Compliance with the emissions reduction requirement will be facilitated by the
allocation of generator output via an emissions registry. This will address the
key concern of many stakeholders that the emissions reduction requirement
would require the physical linking of contracts to their emissions source, making
contracts more bespoke and reducing contract market liquidity.
Market customers will continue to enter into financial contracts to hedge their
position in the spot market as per their usual business practices, and to manage
any obligations they may have under the reliability requirement of the
Guarantee. They will then be able to use their existing contracts, or enter into
new ones, to obtain the right to assign physical generation and emissions for
the purpose of the emissions reduction requirement. This can be done in any
way the market customer deems appropriate, based on its current contract
arrangements.
Limits will be applied to the carry forward of over-achievement under the
emissions reduction requirement to ensure that there is sufficient opportunity for
all market customers to secure adequate contracts to meet the electricity
emissions targets for their load. Unlimited carry forward of over-achievement
could present a significant risk to effective competition. The limit imposed will
ensure that market customers do not unreasonably withhold over-achievement
from the market.
A limited allowance for under-achievement in a particular year under the
emissions reduction requirement will also help ensure that market customers
are not forced into non-compliance by a temporary shortage.
As an additional measure to support retail market competition, the first 50,000
MWh of any market customer’s load will be exempt from the emissions
reduction requirement, and instead spread over other market customer load.
This level has been set such that small market customers will be exempt for
some or all of their load. As a market customer’s load increases above
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50,000 MWh, their exempt proportion decreases. This measure will help smaller
market customers meet the emissions reduction requirement, while not having
a material impact on overall coverage.
If the reliability obligation is triggered, transparency, liquidity and competition
issues would be addressed through a Market Liquidity Obligation and a trade
repository and reporting approach. The Market Liquidity Obligation could be
imposed on vertically integrated retailers with generation shares in gap regions
over a certain threshold. These participants will be required to post bid and offer
spreads for swaps in the region to cover the period of the forecast gap. These
bids and offers will be provided through a centrally cleared platform and provide
access to qualifying contracts. This will enhance competition through access to
tradeable contracts. A trade repository and reporting approach would seek to
capture additional transparency in areas of wholesale contracting that are
currently opaque.
A voluntary AEMO book-build could enhance wholesale market competition by
allowing smaller retailers to band together and bring new resources to market to
back qualifying contracts such as swaps and caps.
Liable entities under the reliability requirement will be retailers and large
customers. Retailers are well positioned to support the reliability of the power
system through their contracting as they are already incentivised to contract to
cover their mass market loads. However, it is difficult for retailers to accurately
forecast the potential demand from large customers as their contracts expire.
Large customers often change retailers frequently. Retailers would need to
impose additional costs on customers to manage the obligation without knowing
whether they were ultimately responsible for the load associated with a large
customer. Therefore, large customers will have the choice to either contribute
directly to the reliability of the power system, or alternatively, enter into a
commercial arrangement to have a retailer manage its obligation on their
behalf. This should see the reliability requirement managed at least cost while
providing retailers (large and small) the opportunity to compete to manage the
reliability requirement on behalf of large customers.
5.2.4.8 Regulatory Burden
Emissions Requirement
The emissions reduction requirement is an annual obligation on market customers to
ensure the average emissions intensity of generation allocated against their load is at
or below the prescribed electricity emissions target for a given compliance period.
The registry provides the necessary infrastructure to facilitate efficient compliance with
the emissions reduction requirement. It allows market customers to be allocated a
share of a generator’s output and associated emissions, for which they have obtained
the rights. This can be based on any contractual arrangement held with a counterparty
outside the registry, as long as both parties verify the agreement in the registry. Market
customers can choose to enter into contracts to allocate generation in the registry with
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the same generators that they enter into hedging contracts with, but there is no
requirement for these parties to be the same.
Fundamental to the operation of the emissions registry is the capacity to ‘allocate’
generation from a generator to a market customer (and subsequently reallocate
between market customers).
When a market customer allocates generation to their load in the registry, the allocation
must be underpinned by evidence that the counterparty has approved it. This
requirement will reduce the risk of generation being inaccurately allocated or the same
generation being allocated to multiple market customers. Non-compliance with this
requirement will be automatically identified in the Registry and non-compliant entities
may be subject to enforcement action.78
Market customers can use information recorded in the registry over a compliance year
to monitor their compliance position. At the end of the compliance period, and following
a four month reporting and revision window, the AER will assess the compliance of
each market customer based on final information in the registry. There will be a robust
framework for the AER to monitor and enforce compliance.
Generators will be required to enter or confirm allocations in a timely manner to allow
AEMO to provide regular updates of the contents of the unallocated pool and its
emissions intensity. They will also have an administrative requirement to allocate all
generation and associated emissions by the reporting and compliance date.
There are approximately 75 market customers and 150 registered participant
generators that will need to be involved in all allocations.
The proposed compliance framework has been designed to minimise the reporting
burden on generators and market customers. Where possible, the reporting required to
assess compliance with the emissions reduction requirement will build on existing
information sources. For the data being sourced from existing information sources, the
existing frameworks for monitoring and enforcing reporting requirements will continue
to apply.
Existing data sources that will be drawn on to assess compliance are likely to include:
Emissions intensity data: Emissions for each generator will be primarily sourced
from NGER reporting. Monitoring and enforcing compliance with data reporting
requirements and record keeping requirements will continue to be the
responsibility of the Clean Energy Regulator. These requirements fall under the
National Greenhouse and Energy Reporting Act 2007. For the purposes of
calculating a generator’s emissions intensity, emissions data will be combined
with generation data that matches the year of the emissions data and scaled
according to the marginal loss factors applying in the compliance year (both
generation and market customer purchases will be calculated at the node). For
further details, see the Technical Working Paper on Market Customer Load.79
79 Energy Security Board, Technical Working Paper, see
http://www.coagenergycouncil.gov.au/reports -papers.
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Generation data: Output data for each market generator will be sourced from
AEMO’s settlement systems. This data will show actual volume of generation
from each generator in the NEM over the compliance period. The compliance
with data reporting requirements will continue to be the responsibility of the
AEMO.
Pool purchases: Pool purchases for each market customer will be sourced from
AEMO’s settlement systems. This data is settled in weekly batches, and each
week’s data first becomes available four weeks in arrears. The compliance with
data reporting requirements will continue to be the responsibility of the AEMO.
Where existing data sources are used to assess compliance, there is no additional
burden on market customers, compared to business as usual. The existing frameworks
for monitoring and enforcing reporting requirements will continue to apply.
Where new information is required to assess compliance with the emissions reduction
requirement, such as emissions data for generation not currently captured in NGER
reporting, additional reporting requirements will be introduced (largely under NGER
legislation).
For most generators and market customers, the significant additional reporting
requirements above business as usual are likely to be the requirements to report on
and confirm allocations of generation to load in the emissions registry. As outlined in
Section 5.2.4.2 and Section 5.2.4.3, undertaking this additional reporting (inputting and
approving allocations in the online registry platform) will incur costs. Capital costs are
likely to be incurred in order to establish IT systems, processes and education to
enable participation in the allocation process in the registry. These costs are likely to be
minimal for smaller entities and increasing with size and complexity of the entity.
Ongoing operational cost may include human resources and potentially the
procurement of legal, regulatory and financial expertise to manage contractual or other
arrangements that underpin the allocations in the registry. The ongoing operational
costs are expected to be higher than the capital expenditure and will similarly be
smaller for smaller and less complex entities. The expense is likely to be very
dependent on each entity’s existing resourcing and capacity.
The costs of securing contractual or other arrangements to underpin allocations of
generation and associated emissions in the registry will be subject to the electricity
emissions target and the shape of the trajectory to reach that target.
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Reliability requirement
If the reliability obligation is triggered (at T-3), then the liable entities will have 2 years
to ensure that they have qualifying contracts in place to cover their electricity demand
for the 1 in 2 year regional peak demand forecast for the compliance year (T).
A liable large customer will be able to meet their obligation by contracting with an
electricity retailer, arranging their own qualifying contracts for supply, use of their own
demand response capability, or through a mix of these approaches.
The reliability obligation provides a safe harbour that scales down actual measured
demand when it is above the 1 in 2 year peak demand forecast to a share of the 1 in 2
year forecast. A liable large customer can be confident that if they contract for their
expected peak load they will meet or exceed their reliability obligation.
New entrants – for example, entities above the demand threshold commencing
operations during the compliance year – will be required to take steps to secure
contracts or enter an agreement with a retailer to manage their obligation for contracts
over the forecast gap period. New entrants would demonstrate their compliance with
the reliability requirement in the same way as all liable entities. The difference is that
the new entrant would only need to demonstrate they met the contracting requirement
at the time they entered the market, rather than at the commencement of the
compliance year (T-1).
The existing contracts of liable entities that are large customers, will be considered
qualifying contracts (up to the load covered by the contracts in place). This is a
transitional concession that deems existing contracts to be eligible contracts to reduce
regulatory burden and avoid impacting pre-existing contracts entered in good faith
before the Guarantee design was released.
If the reliability obligation is triggered (at T-3), then all liable entities, excluding those
that have transferred their obligation to a retailer, will need to assess their likely share
of regional peak demand and secure sufficient qualifying contracts to cover this.
If the gap persists in one or more NEM regions one year out, liable entities in the
affected regions will be required to submit their net contract position to the AER to
demonstrate they have sufficient enduring qualifying contracts over the gap period.
A liable entity’s reported contract position at T-1 will be the primary information source
for the AER to assess compliance should a compliance assessment arise. The
information contained in the report must therefore be sufficiently detailed to enable the
AER to make this assessment.
A liable entity will need to have appropriate systems and processes in place to record
the contracts they have procured at T-1. These contracts will also then need to be
accessible for an external auditor to assess the ‘firmness’ of the contracts for time T. A
record of the eligible contracts will also need to be retained by the liable entity in the
event that the AER needs to make further compliance enquiries or information
requests.
An external audit of the contract position at time T-1 for time T will have varying
resource costs depending on the nature of the contracts under assessment and the
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AER’s reporting requirements. In circumstances in which the eligible contracts are firm
(such as exchange traded caps and swaps) the audit cost should be minimal. A liable
entity with more complex risk management arrangements, will likely already have a
similar internal (or external) auditing process to monitor risk. In this case, the cost of
auditing the contract position may be more resource intensive but would likely utilize
existing processes of assessing the effectiveness of contract positions for risk
management.
5.3 Physically Backed Contracts
Physically backed contracts (described in section 4.3) were a key element of one of the
ESB's original options. This approach requires contracts used to meet the emissions
requirement and the reliability requirement to be linked to a specific generator. This
option was developed from the ESB's observation that the NEM's spot market, together
with the contracts between generators and retailers to manage price volatility, promote
competition and support the power system. Therefore any mechanism to maintain
reliability and reduce emissions must be able to operate with these contracts.
All other components of physically backed contracts are the same as the Guarantee
including the emissions and reliability requirements, the market customers and liable
entities to whom these requirements apply, the treatment of EITEs exemptions and
offsets.
5.3.1 Price impacts
The ESB's modelling projects the Guarantee will reduce wholesale prices by 30 per
cent by 2030 compared to BAU, while retail bills will be an average of around $120 per
year lower over the 2020 to 2030 period. The ESB considers the wholesale modelling
could be considered applicable to the Guarantee and physically backed contracts, as
the two options are similar. However, linking contracts in the wholesale market to
generation will likely decrease liquidity and competition driving up wholesale prices as
a result. This would also likely reduce a retailer's ability to manage price risk, which
could lead to higher prices for consumers, compared to the guarantee, and it would
have high regulation costs (discussed below).
As previously discussed, the modelling doesn't include the exemption of EITE load for
the emissions requirement. However, changing this assumption would not have had a
material impact on the model's results because the key drivers of electricity price
reductions under the Guarantee are not affected by whether EITEs receive an
exemption.
5.3.2 Financial market impacts
Stakeholder submissions to the ESB's Draft Design Consultation Paper were almost
universal in warning of the risk to the financial derivatives/contracts market if contracts
were required to be physically backed by generators.
It should be noted these contracts do affect the physical market. For example, as
discussed previously, when a retailer and a generator enter into a swap the generator
pays the retailer when the spot price is above the strike price and vice versa when it is
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below the strike price. In this contract the generator has the incentive to generate when
prices are high to help lower prices with more supply and reduce its liability to the
retailer.
Physically backed contracts could provide greater certainty for the reliability
requirement being met. At a time of peak demand and limited generation reserves, a
contract with a specific generator would be more likely to result in the necessary
generation than a financial contract, though for the reasons above, the financial
contract could be expected to have a fair degree of certainty of providing generation at
the required time.
However, use of physically backed contracts would significantly increase costs, partly
as a result of the impact on liquidity and competition, but also in relation to the
complexity and costs that would be associated with transitioning the existing financial
derivatives market to physical products.
Stakeholder concerns with physically backed contracts included that existing financial
contracts would have to be revised to be used for the emissions and/or reliability
requirement, increasing complexity and costs. Physically backed contracts would result
in a move away from standard exchange traded and over the counter contracts to less
fungible bespoke contracts. This would fragment the financial derivatives/contracts
market and reduce the market's liquidity and transparency. Another concern was
physically backed contracts would limit the ability of market participants to innovate and
develop flexible new products to support the introduction of new technology, thus
increasing the financial risks associated with investment.
5.3.3 Competition impacts
Requiring a link to generation in contracts would increase the market power of vertically
integrated retailers.
Liable entities would be required to source physical contracts, limiting their ability to
manage financial risks ordinarily dealt with through existing financial products in both
the ASX and OTC products.
This could lead to increased premiums for investment in new sources of dispatchable
generation.
5.3.4 Emissions impacts
The ESB considers the outcomes of its modelling are applicable to both the Guarantee
and physically backed contracts. The model's assumptions are common to both options
with the exception of the exemption of EITE customer load from the emissions
requirement. The ESB considers the impact of the EITE customer exemption not to be
material to the model's projections.
5.3.5 Regulatory burden
Physically backed contracts will have a greater regulatory burden than the Guarantee.
The compliance and regulatory processes for physically backed contracts are expected
to cover all those for the Guarantee, and with the same amount of burden. However,
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physically backed contracts would have additional costs from its additional compliance
and administration requirements.
Emissions requirement
In addition to the Guarantee's regulatory requirements, under this option, physically
backed contracts would require a market customer to confirm their contracts are
physically backed. This may be as simple as the market customer ticking a box in the
registry.
The approach for checking compliance would be for the AER to decide. The following
is one possible approach for the purposes of this RIS.
The AER could take a risk and audit based approach to check compliance. It would
develop a risk assessment framework against which each market customer would be
tested for their risk of non-compliance.
Audits would be conducted by AER staff and/or contractors. The AER would audit a
certain number of market customers each year, some selected from the AER's risk
assessment, some chosen at random. All market customers would eventually be
audited.
The AER would develop an audit framework for its auditors and market customers,
describing the roles and requirements of both. The audit may look at all of a market
customer's contracts or a portion of them, depending on the number. An audit could
take a day or more, depending on the number of contracts being audited and their
complexity. Audits would be conducted through the year and could be for any year for
which the market customer has participated in the Guarantee.
Reliability requirement
If the reliability requirement were triggered, the AER would check a liable entity's
contracts are physically backed as part of its review of contracts to confirm the entity
met its obligation. As a result, physically backed contracts are expected to have
minimal additional regulatory burden for the reliability requirement compared to the
Guarantee.
5.4 Summary
Requiring physically backed contracts in the wholesale market will likely decrease
liquidity and competition driving up wholesale prices as a result. This would also likely
reduce a retailer's ability to manage price risk, which could lead to higher prices for
consumers, compared to the guarantee, and it would have high regulation costs. As a
result, the net benefit to the community of the Guarantee compared to BAU will be
higher than the net benefit of physically backed contracts.
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6 Consultation
The following is the timeline for ESB's consultation so far.
October 2017 – The ESB advised the COAG Energy Council on proposed
changes to the National Electricity Market and associated legislation to implement
the Guarantee. The Commonwealth Government asked the ESB to provide a
report and modelling on the operation of the Guarantee and its impacts on the
NEM.
10 November – The ESB held a public webinar on the Guarantee and posted
answers to questions that weren't answered in the webinar.
24 November – The ESB released its report and modelling on the Guarantee's
operation and impacts on the NEM. The COAG Energy Council agreed the ESB
should provide further advice.
15 February 2018 – The ESB's first consultation paper was released.
Submissions closed 8 March and over 150 were received.
26 February – The ESB held a stakeholder forum and webinar in Sydney.
20 April – The ESB released its high level design paper. The Commonwealth
Government released a paper for its design elements: the emissions trajectory,
emissions-intensive trade-exposed (EITE) industry exemptions and the use of
offsets. The COAG Energy Council agreed the ESB develop the Guarantee's
detailed design.
22 May – The ESB released 14 issues papers for discussion with jurisdictions and
technical working groups.
21 – 25 May and 4 – 8 June – Technical working group meetings were held. The
groups had government, industry and energy market body representatives.
15 June – The ESB and the Commonwealth released their high level design
documents. Submissions on the Commonwealth consultation close Friday 6 July.
Submissions on the ESB consultation close Friday 13 July.
22 June – The ESB released technical working papers. Submissions close Friday
13 July.
29 June – The ESB released the Consultation RIS. Submissions close Friday
20 July.
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6.1 Consultation for the detailed design papers and consultation Regulation Impact Statement
Submissions to the COAG Consultation RIS
The ESB is seeking input from interested parties on the proposed Guarantee and
physically backed contracts for addressing the policy problem as described in this
Consultation RIS by 20 July 2018. All submissions will be published on the COAG
Energy Council’s website, subject to any claims of confidentiality. All submissions
should be sent to [email protected].
This RIS should be read in conjunction with the ESB Draft Detailed Design
Consultation Document (and its Technical Working Papers)80 and the Commonwealth
Government's Draft Detailed Design for Consultation - Commonwealth Elements
paper81, both released on 15 June 2018. Submissions on the Commonwealth elements
paper are due 6 July 2018. Submissions on the Draft Detailed Design for Consultation
are due 13 July 2018.
The ESB intends to consult broadly in finalising the design of the Guarantee.
Stakeholders have a range of opportunities to be involved, as detailed below.
Public forum and webinar
A public forum and live webcast will be held Monday 2 July 2018. Further information
about how to participate is published on the COAG Energy Council website.
Next steps
Following the consultation process, the detailed design of the Guarantee will be
finalised and a COAG Decision RIS will be prepared. The detailed design and Decision
RIS will be presented to the COAG Energy Council for decision at its August 2018
meeting.
If the COAG Energy Council approves the final design of the Guarantee at its August
2018 meeting, it is expected that the draft legislation will be finalised for introduction to
the South Australian and Federal parliaments by the end of 2018.
80 Energy Security Board, Draft Detailed Design Consultation Paper,
http://www.coagenergycouncil.gov.au/publications/energy-security-board-%E2%80%93-draft-
detailed-design-national-energy-guarantee-consultation, accessed 18 June 2018 81 Department of the Environment and Energy, Draft Detailed Design for Consultation Commonwealth
Elements, http://www.coagenergycouncil.gov.au/publications/national-energy-guarantee-draft-
detailed-design-commonwealth-elements, accessed 18 June 2018
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7 Conclusion
The ESB's preliminary view is the Guarantee is the preferred option. The Guarantee
will achieve the COAG Energy Council's objectives to maintain the NEM's reliability and
meet the electricity sector’s share of the Commonwealth Government's international
emissions reduction commitment. It will do this at the lowest cost and with a larger net
benefit to the community than physically backed contracts.
The ESB's modelling shows the Guarantee and physically backed contracts can both
reduce the electricity sector's emissions to 26 per cent below 2005 levels by 2030 and
provide more dispatchable generation to ensure reliability. BAU will not meet either of
these objectives.
The ESB's modelling projects the Guarantee will reduce wholesale prices by 30 per
cent by 2030 compared to BAU, while retail bills will be an average of around $120 per
year lower over the 2020 to 2030 period. The modelling doesn't include the exemption
of EITE load for the emissions requirement, but the ESB considers this would not
materially impact prices. The impact analysis suggests the physically backed option
would have higher compliance costs.
Physically backed contracts would see the market use more bespoke contracts and
limit options to meet the emissions and reliability requirements. This in turn would
increase compliance and transaction costs, fragment the financial derivatives/contracts
market and reduce the market's liquidity.
The ESB will publish its final position in a Decision RIS, after it has considered
stakeholder submissions and refined its impact analysis. The Decision RIS is expected
to be published following the COAG Energy Council's meeting in early August 2018.
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8 Implementation/Review
8.1 Implementation and governance
Based on the preliminary analysis in this Consultation RIS, the Guarantee is the
preferred option for addressing the emissions and reliability objectives. The following
outlines the implementation and governance arrangements for the Guarantee.
Stable and effective implementation of the Guarantee will provide certainty for market
participants about the market's operation and allow for long-term investment decisions
to be made in the electricity sector.
The ESB’s preferred option is for COAG Energy Council agreement with
implementation through existing governance arrangements for the NEM. The majority
of the Guarantee would be implemented through amendments to the Australian Energy
Market Agreement (AEMA), the NEL and the Rules.
Embedding the Guarantee into the broader energy governance framework would allow
the mechanism to be fully integrated with the broader energy Rules. This would
maximise consistency between the reliability and emissions reduction requirements,
reducing complexity and compliance costs for market participants.
8.1.1 Implementation through NEM governance arrangements
Amendments to the NEL, after being agreed by the COAG Energy Council in
accordance with the AEMA, would be implemented by South Australia and
automatically applied in each of the other jurisdictions.
The necessary changes to the Rules would be made by the South Australian Energy
Minister.
The NEL and Rules would be amended to:
translate the emissions target and reliability requirement into retailer obligations,
and
establish the compliance and enforcement framework.
After the initial package of changes to the Rules are made, the AEMC would be the
rule-maker in accordance with its current functions. It would be able to accept and
assess rule change requests from any entity relating to the portion of the Guarantee
mechanism that is contained in the Rules, following the well-understood rule making
processes set out in the NEL. This will give participants clarity in relation to how and
when revisions to the mechanisms will occur, recognising that the design of the
Guarantee is already flexible to changing market dynamics. Certainty that the policy will
last, along with a mechanistic and known approach to any updates, would increase the
investor confidence and certainty needed in the electricity sector where the assets are
long-lived, and the planning horizons are lengthy.
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8.1.2 Relevant Commonwealth legislation
As discussed above, the Guarantee would be implemented primarily through
amendments to the NEL after agreement by the COAG Energy Council.
The Commonwealth Government would set the electricity emissions target as
discussed in Chapter 4. Some amendments to existing Commonwealth legislation may
also be required. These changes would relate primarily to the setting the emissions
targets, provisions relating to EITE businesses, possibly the use of offsets, and
emissions reporting and information gathering powers.
8.1.3 Advice on including Western Australia in the emissions reduction requirement
At the last COAG Energy Council meeting in April 2018, Western Australia requested
that the ESB provide advice on how Western Australia might be able to participate in
the emissions reduction requirement of the Guarantee. Preliminary advice on this
matter will be provided to the COAG Energy Council at its August 2018 meeting.
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8.1.5 Summary of key steps and issues
An outline of the key steps and considerations involved in implementing this approach
is provided below.
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8.2 Reviews
The National Energy Guarantee may evolve over time through the existing AEMC rule
making processes under the National Electricity Law. Stakeholders can shape the
design and regulation of the Guarantee through participation in the rule change
process, including by submitting rule change requests.
An important aspect of the National Electricity Rules is that any party, except the
AEMC, can propose a change to the rules. Rule changes that are recommended as
part of an AEMC review can also be requested by any party.
Engagement with stakeholders is conducted during the rule making process through a
number of mediums such as seeking written submissions and participation in meetings,
workshops and forums.
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Abbreviations and defined terms
ACCC Australian Competition and Consumer Commission
ACT Australian Capital Territory
AEMA Australian Energy Market Agreement
AEMC or Commission Australian Energy Market Commission
AEMO Australian Energy Market Operator
AER Australian Energy Regulator
ANREU Australian National Registry of Emiss ions Units
ARENA Australian Renewable Energy Agency
ASX Australian Stock Exchange
CER Clean Energy Regulator
COAG Council of Australian Governments
ESOO Electricity Statement of Opportunities
EITE Emissions-intensive trade-exposed
ESB Energy Security Board
Guarantee National Energy Guarantee
LRET
MW
Large-scale Renewable Energy Target
Megawatt
MWh Megawatt-hour
NEL National Electricity Law
NEM National Electricity Market
NEO
NER
National Electricity Objective
National Electricity Rules
NGER National Greenhouse and Energy Reporting scheme
OTC Over the counter
PPA Power purchasing agreement
RERT Reliability and Emergency Reserve Trader
RET Renewable Energy Target
Rules
SRES
National Electricity Rules
Small-scale Renewable Energy Scheme
tCO2-e Metric tonnes of carbon dioxide equivalent
USE Unserved energy
