ENERGY SECURITY BOARD - Reliability Standard Review March 2020 - COAG Energy Council
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ENERGY SECURITY BOARD
Reliability Standard Review
March 2020
1Contents:
Contents
Review of the reliability standard .......................................................................... 3
Next Steps ............................................................................................................. 3
1. Key findings ................................................................................................... 3
2. Approach to the reliability standard review .................................................... 8
3. Reliability measure and standard and cost benefit analysis ............................ 8
4. Options to achieve a tighter standard .......................................................... 19
5. Recommended mechanisms to deliver higher reliability................................ 21
6. Key concepts in the design of an out-of-market mechanism .......................... 23
7. Calculation of unserved energy .................................................................... 27
8. Longer term view on reliability and broader policy implications.................... 30
Attachment A: COAG EC Terms of Reference ........................................................ 33
2Review of the reliability standard
At its meeting in November 2019, the COAG Energy Council requested the ESB provide
advice on the implementation of interim measures to preserve reliability and system
security, including reviewing the reliability standard, during the transition to the post-2025
market design. The terms of reference for the advice are at Attachment A.
Following advice from the Energy Security Board the Energy Council agreed to implement
interim measures to deliver further reliability by establishing an out-of-market capacity
reserve and amending triggering arrangements for the Retailer Reliability Obligation (RRO).
Both measures will be triggered to keep unserved energy to no more than 0.0006% in any
region in any year. Ministers agreed that these were interim steps needed to improve
reliability in the immediate term while an enduring market design is developed and that
they will be reviewed as part of an expanded RRO review required by 1 July 2023.
These interim measures should not have any impact on Queensland or Tasmania who are
not shown to have any reliability issues for the years during which the measures would
apply.
This document summarises the Energy Security Board’s advice to the Energy Council.
Next Steps
The Energy Security Board will consult on draft law and rule changes as a next step.
Implementation of the Reliability Reserve
Rules to establish a reserve must developed in time to allow AEMO to procure capacity for
the reserve for the 2020/21 summer. An indicative timeline for rule changes to establish the
proposed reserve is as follows:
Late April – Consultation on draft rules (6 week consultation period)
Early June – respond to submissions, prepare final rules package for COAG EC decision
by end June.
July-August – Finalise rule changes
Changes to the Retailer Reliability Obligation
The ESB will develop and consult on a package of law and rule changes with a view to
making recommendations to Energy Council by in September 2020. Amending the RRO T-3
and T-1 instruments would require law changes, which means the earliest possible date for
making the T-1 instrument would be in 2021/22 for the following year.
1. Key findings
Reliability to be maintained during 9 out of 10 years
3COAG asked the ESB to provide advice on the NEM’s reliability standard. An acceptable level
of reliability is essential to maintaining community confidence in the NEM and will be critical
to a successful energy transition.
Statistical modelling suggests that a jurisdiction that just meets the current 0.002% standard
could expect load shedding one in every three years on average – absent an intervention
mechanism such as the RERT – due to insufficient resources to meet demand. And in the
years where load shedding occurs, the average duration of a total outage would be 6.5
hours (non-consecutive)1, recognising that load shedding would occur on a rotational basis
so that individual customers may only be affected for 30-60 minutes. If intervention
mechanisms are used and effective (as the recent use of the RERT over the summer has
proven) the likelihood of load shedding is reduced.
The challenge for the Energy Council, and for the ESB in formulating its advice, is to
determine if these outcomes meet community expectations, or if a different standard is
better suited, having assessed costs and benefits of change.
Consideration of a tighter standard
A number of different approaches were examined which would broadly achieve the
expectation in the Terms of Reference for the review that the system remains reliable in a 1-
in-10 year summer. Each approach has its own cost impacts and will produce different
reliability outcomes for consumers.
The ESB commissioned Acil Allen to advise on the net benefits and costs of moving to a
tighter standard. That work drew on the AER’s work seeking to establish the value of
customer reliability. The Acil Allen analysis found that moving to a tighter standard in the
range of 0.0010%-0.0005% expected unserved energy (USE) likely has net positive benefits
overall. The standard of 0.0006% expected USE delivers a similar outcome to the alternate
standard modelled in the 2019 ESOO – 10% probability of exceeding 0.002% expected USE –
and has been presented in terms of expected USE for ease of comparison.
Table 1 summarises the required capacity to meet the 0.001% and 0.0006% expected
unserved energy standards in each of NSW, VIC and SA based on analysis of modelling for
the 2019 ESOO. Actual numbers will differ from these based on updated information in
future ESOOs.
The associated net benefits and costs according to the base case analysed by Acil Allen are
in Table 2.
Table 1: incremental capacity (MW) required to achieve alternate standards
Year NSW SA VIC
1
Extreme, unanticipated events such as natural disasters, not associated with resource adequacy will increase
likelihood of load shedding further, but are not part of the review of the reliability standard which applies to
the availability of supply to meet demand under the normal range of contingencies.
40.002% 0.001% 0.0006% 0.002% 0.001% 0.0006% 0.002% 0.001% 0.0006%
19/20 0 0 0 0 0 0 125 430 630
20/21 0 0 0 0 0 0 0 0 95
21/22 0 0 0 0 0 0 0 0 20
22/23 0 0 0 0 0 0 0 0 0
23/24 0 255 430 0 20 115 0 0 0
24/25 0 250 470 0 24 120 0 0 0
Table 2: net benefits [Acil Allen analysis base scenario] for 2023/24
NSW SA VIC
0.002% 0.001% 0.0006% 0.002% 0.001% 0.0006% 0.002% 0.001% 0.0006%
-- $39m $45m -- $1.4m -$1.8m -- -- --
Note that Victoria already meets either alternate standard in the year modelled (2023/24)
and thus no costs or benefits are assessed.
The range in which there are net positive benefits to moving to a tighter standard are
sensitive to the assumed value of customer reliability (VCR). Acil Allen used the results of
the AER VCR survey as the basis of its analysis. The Acil Allen base case used a weighted
average of VCR results across the residential and industry sectors in the survey. To test the
sensitivity to the value of VCR, Acil Allen also conducted their analysis using only the
residential VCR data. i.e. assuming that unserved energy impacted only residential
consumers. Finally, Acil Allen conducted a further sensitivity test using only the residential
VCR data and a scenario with greater volume of available demand side response (referred to
as ‘extended RERT’) which, based on AEMO advice, is expected to be the case. Table 3
shows for NSW in 2023/24 the band of expected USE for which there are net positive
benefits under each of these scenarios and the corresponding VCR data.
Table 3: Sensitivity to VCR value and volume of RERT (NSW)
VCR up to 1 hr VCR 1-3 hr interruption Band of USE net
interruption ($/kWh) ($/kWh) positive benefit
Weighted 99.40 40.98 0.0006-0.0004%
residential and C&I
Residential only 52.33 33.98 0.0013-0.0008%
Residential only + 52.33 33.98 0.0005-0.0003%
extended RERT
Exactly how VCR was applied and the assumptions around the availability of RERT/demand
response, as well as the results for Victoria and South Australia, are explored in more detail
below and in the report by Acil Allen.
Based on this analysis, moving to either the 0.001% or 0.0005% expect USE standards would
have net positive benefits overall, however it is easier to make the case that the 0.0006%
5standard best meets the expectation that reliability be maintained through a 1-in-10 year
summer as outlined in the Terms of Reference. The 1-in-10 year benchmark has some
international precedent and is consistent with the New South Wales Energy Security Target.
As argued by AEMO in the 2019 ESOO, this standard would mean that the current (0.002%
USE) standard would be met in 9 out of 10 years on average.
Mechanisms to achieve a tighter standard
A higher reliability standard could be delivered through a range of market mechanisms or
through an out-of-market or insurance type measure. Under the current market design,
higher reliability could be delivered by adjusting the market price cap and related measures.
The ESB engaged EY to undertake modelling and asses the costs and impacts of using such a
market measure to achieve the higher standard.
The EY modelling indicated that a very significant rise to the market price cap would be
required to deliver 0.0006% USE and that the higher price cap could be expected to raise
wholesale electricity prices by 2 to 4%. The ESB has outlined a program of work to review
the market design which will take some time to design and implement. There is a need for
urgent action which then limits the options available. It is recommended then that an out of
market mechanism is used as an interim measure given it should be more cost effective and
able to be implemented sooner.
In particular, the ESB recommends that it be achieved through a combination of
mechanisms:
Amending the RRO trigger so that it is triggered off the tighter standard meaning
that it will be triggered more often in Victoria, NSW and SA; and removing the
requirement that the T-3 instrument must first be made before the T-1 instrument
can be made, both to provide greater incentives for retailers to contract.
Because the contracting obligation under the RRO will continue to be based off the
current standard, rather than a tighter standard, establish an additional out of
market reserve for capacity to meet a tighter standard
Meet emergency contingencies through the short and medium notice RERT but
replace the long notice RERT with the reserve capacity.
Market price settings (MPC, CPT, APC, price floor) should remain unchanged.
The measures outlined will achieve greater reliability without changing the current
standard, which is used to establish market price settings and for a range of other functions
in the Rules and subordinate guidelines.
The costs to consumers of procuring the reserve will be significantly offset through not
having to procure long notice RERT and reduced usage of short and medium notice RERT.
RERT would move to only being required for emergencies and rare events as was originally
intended.
Interim reliability and security measures
6These interim measures should be implemented to achieve a greater reliability (in those
regions that need it) ahead of the post-2025 market design project offering longer term, fit
for purpose options to ensure reliability and security. These interims measures would be
implemented ahead of the 2020/21 summer and designed in such a way that they leave
optionality in future market designs for alternative approaches to ensuring reliability.
Intermediate-term measures to improve reliability
The ESB recommends that these interim arrangements should be put in place until the
beginning of 2023/24.
Implementing a tighter standard as an interim measure to establish a reserve and as a
trigger for the RRO is a pragmatic measure to improve reliability in the immediate term.
However, it transfers part of the obligation to meet the reliability standard onto the market
operator and away from market participants, who may be better placed to manage the risks
associated with this obligation. An enduring market design will need to be identified to re-
establish the link between market price settings and reliability.
In the longer term the ESB, in collaboration with the market bodies and industry, is
developing more enduring approaches to ensuring reliability and security. The post-2025
market design project will make recommendations on preferred market designs through
2020 and by mid-2021.
Accordingly, the ESB recommends that the interim provisions put forward in this report
should be reviewed as part of an expanded RRO review required in 2023 following
consideration of a full range of alternatives through the post-2025 project.
Ahead markets, two-sided markets and access reform
While the proposed interim measures will improve reliability in the near-term they are
insufficient over the medium and longer term to keep the system operating in a secure
state.
The ESB considers that security constrained economic dispatch of energy-only is, by itself,
no longer sufficient to maintain system security. The ESB considers that new system services
need to be established and remunerated and an ahead market is required to ensure system
security going forward. This issue is examined in depth in separate papers.
A key recommendation to COAG EC is that it agree an ahead market (or markets) for
reliability and system security services be implemented as soon as practicable, and prior to
2025. The ESB notes that AEMO cannot keep the system reliable and secure any longer
without such a mechanism. The ESB will provide advice to COAG on a detailed market
design and timing of implementation by the end of 2020.
The ESB is also examining a transition towards a two-sided market, which offers the best
opportunity to meet the reliability requirements in an efficient manner, will contribute to
7system security and to provide economic signals that will unlock the full value of DER for
consumers.
The ESB recommends that COAG agree to transition to a two-sided market framework as
soon as practicable and that the ESB should recommend a detailed market design for the
Energy Council’s consideration by the end of 2020 .
Finally access reform pursued through the AEMC Coordination of Generation and
Transmission Investment (CoGaTI) initiative will be a key enabling reform that ensures the
NEM gets the most out of both ahead markets and two-sided markets.
These three initiatives – ahead markets, two sided markets and CoGaTI – form the basis of
the ESB’s intermediate reform agenda and will be coordinated through the post-2025
market design project.
2. Approach to the reliability standard review
The reliability standard review pursued several key streams of work in parallel:
Firstly, we explored the costs and benefits of moving to a higher reliability standard.
This included analysis to understand what the current standard delivers in terms of
avoided load shedding and system performance. Considering alternate measures of
reliability and international approaches in other power systems.
We reviewed a range of possible mechanism to achieve higher standards.
We considered the range of risks and outcomes that AEMO uses in modelling the
NEM’s likely future reliability. This task is critically important to future investment
plans and the current market and non-market mechanisms designed to ensure the
NEM meets the reliability standard. Australia’s changing generation mix and
changing environmental risks are making this task more difficult.
3. Reliability measure and standard and cost benefit analysis
Reliability Framework
Reliability Reliability Reliability
Measure Standard Response
Governance
8The reliability standard sits at the heart of the reliability framework and provides the
expression of the level of risk of load shedding that is deemed to be acceptable taking
account the fact that preventing all load shedding from occurring would be prohibitively
expensive.
Currently, the reliability standard is defined such that the expected USE in a region over a
year should remain below 0.002% of forecast demand. The impact of exceeding the
standard is to trigger a reliability response from the market in the first instance that will
remediate the gap and bring the level of USE back within the standard. In the case of the
NEM the potential responses are:
Consideration of the appropriate level of the market price settings most notably the
market price cap (MPC) and the cumulative price threshold (CPT). This is reflected in
the market by information provided to the market by AEMO about upcoming supply
and demand balance.
If the reliability gap is identified either 3 years or 1 year in advance the relevant
requirements of the Retailer Reliability Obligation (RRO) come into force.
Finally, if the reliability gap persists AEMO can uses its powers under the Long Notice
Reliability & Emergency Reserve Trader (LN RERT) to procure reserves up to one
year before the identified gap.
The Case for Change
Historically, the NEM has been oversupplied and has experienced low levels of USE.
However, in recent years following the retirement of several thermal generators (most
notably Hazelwood) the supply-demand balance has tightened considerably and AEMO has
needed to procure and use RERT for the last three summers across Victoria, South Australia
and New South Wales.
The trends driving these outcomes are explored more fully in AEMO’s submission to support
its 2018 Enhanced RERT rule change proposal2. The first is the ongoing warming trend which
not only leads to increased air-conditioning demand but also reduces supply through de-
rating of generation and transmission capability (either through temperature impacts or
bushfires). Then there is the impact of higher forced outage rates particularly amongst coal
generators. The load shedding events in Victoria in early 2019 were the result of hot
weather coinciding with multiple outages at brown coal generators.
In its 2019 ESOO forecast3 AEMO reiterates its concerns around increasing tail risk and
proposes that there needs to be a higher reliability standard. State governments have also
felt obliged to respond and have implemented their own measures to enhance reliability
with the SA government now having the ability to trigger the first stage of the RRO and the
NSW government is considering an energy security target to ensure there is enough capacity
in the electricity grid on the hottest days, even with the two largest generating units offline.
2
https://www.aemc.gov.au/sites/default/files/2018-
11/Additional%20information%20from%20AEMO%20to%20support%20its%20Enhanced%20RERT%20rule
%20change%20proposal.pdf
3
https://aemo.com.au/energy-systems/electricity/national-electricity-market-nem/nem-forecasting-and-
planning/forecasting-and-reliability/nem-electricity-statement-of-opportunities-esoov
9The Victorian government has proposed a jurisdictional rule change that would allow AEMO
to procure multi-year reserves on economic grounds.
Setting the Reliability Standard
The economically efficient level of the reliability standard is found where the cost of
preventing load shedding exceeds the benefits of avoiding load shedding.
The ESB commissioned consultants ACIL Allen to undertake a review of the efficient level of
the reliability standard using the latest available data on costs and benefits. For the benefits
component ACIL Allen were able to leverage their work on the AER’s 2019 review of the
Value of Customer Reliability (VCR)4. The VCR study provides useful data that informs the
value that different customer segments ascribe to avoiding load shedding events.
On the cost side of the equation, prevailing low capital costs reduce the cost of providing
greater reliability and there are new technologies like batteries to consider. In addition,
AEMO was able to provide ACIL Allen with anonymised RERT offer data that provides an
insight into the cost structure of demand response that has not previously been available.
The approach adopted by ACIL Allen was to utilise a full sample of USE forecast data from
the 2019 ESOO for financial year 2023-24. This year was chosen because it provides a good
range of the likely USE levels across all regions that AEMO is forecasting over the 10 year
outlook period (Queensland and Tasmania do not have any USE forecast over this period).
The USE data provides the shape and duration of potential outages that can then be used to
feed into a model that optimises the cost of reducing USE using the different technologies
available. A short outage can be prevented using technologies such as demand response
that have low fixed costs and high variable costs whereas a longer duration outage may be
best suited to resources with higher fixed costs and lower variable costs such as open cycle
gas turbines (although if there is a healthy demand response market, this could also likely
cover such outages).
ACIL Allen’s model was used to produce a table of costs for reducing the USE to different
levels. This could then be readily compared to the benefit of reducing USE as expressed by
the VCR to identify the economically efficient level of load shedding.
The VCR study contains a wide range of values so consideration was required as to which
were the most relevant for this exercise. The dimensions of the VCR include location,
duration and timing of outage and customer segment.
The approach adopted was as follows:
Timing – the USE forecast data provides the date and time of load shedding and so
this was mapped to the relevant input noting that the vast majority of USE occurs on
summer working, peak periods.
4
https://www.aer.gov.au/news-release/aer-completes-australia%E2%80%99s-largest-value-of-customer-
reliability-survey
10 Location – each state was mapped to the relevant climate zone and the CBD value
was used e.g. Climate zone 6 CBD VCR values were used for Victoria.
Duration – VCR data is available for either 1, 3, 6 or 12 hour outages. The 1 hour
outage values were chosen because they align with the way that distributors aim to
manage these types of events through using rotational load shedding lasting no
more than 1 to 2 hours.
Segment – two approaches were used – a weighted average over all segments and a
value based just on the residential segment.
ACIL Allen Results
ACIL’s results were primarily driven by 2 key inputs – the amount of DR available (because it
was the cheapest resource) and the level of the VCR.
ACIL’s approach to DR was to assume that the RERT data was the only available DR in the
region. Given the DR cost structure was also the cheapest their model allocated DR to the
USE until it was exhausted and then moved to the next cheapest resource being an OCGT.
Consequently, greater availability of DR results in lower costs of avoiding load shedding and
hence a higher (i.e. less load shedding) reliability standard can be shown to be efficient. DR
resources in a region should only be increasing given the efforts underway to establish a
demand response mechanism.
The other driver was the level of VCR. The weighted average approach for all segments
resulted in VCRs above $90,000/MWh for 1 hour outages whereas the residential only
approach resulted in much lower VCRs e.g. ~$35,000/MWh for Victoria. Clearly, a higher
VCR will result in a tighter standard whereas a lower VCR will result in a less stringent
standard.
ACIL’s ranges for the economically efficient USE standard are summarised as follows:
Table 4: Efficient USE standards
Limited DR Twice as much DR
NSW All 0.0004% to 0.0006% 0.0003% to 0.0005%
Residential 0.0008% to 0.0013% 0.0005% to 0.0010%
SA All 0.0008% to 0.0011% 0.0007% to 0.0010%
Residential 0.0009% to 0.0011% 0.0008% to 0.0010%
Vic All 0.0003% to 0.00055% 0.0001% to 0.0003%
Residential 0.0003% to 0.00055% 0.0001% to 0.0003%
Discussion
ACIL’s results indicate a higher standard is certainly justified on economic grounds. Although
the Victorian results should be read with caution because the ESOO data starts with only
limited USE (0.0006%). Consequently, there is a reduced range over which the benefit of
adding resources can be shown.
11Clearly, the amount of DR and its cost structure impacts the efficient level of the standard.
Limiting the DR to just the RERT offer quantities is certainly a conservative assumption as it
excludes some RERT data which AEMO does use (i.e. ARENA RERT and smelter RERT). These
were excluded because the data around their cost structure was not available at the time
(ARENA data) or confidential (smelter data).
Even twice the level of DR is quite conservative e.g. only provides 460 MW in NSW and
48 MW in SA. Certainly, there is a much larger pool of DR that can be accessed than this if
market structures were more supportive and reforms such as Wholesale Demand Response
and Two-Sided Markets are aimed at significantly deepening this pool of resources.
For this study the key question is around the cost structure of DR. The RERT data provides
an insight into this but it does not follow that bringing in additional DR would be at the same
cost. However, it doesn’t have to be at the same cost to produce a benefit, it just has to be
cheaper than the VCR. Any reforms that can deepen the pool of DR and have a cost less
than VCR would justify moving to a higher reliability standard.
This then brings in the question of which VCR is chosen. The choice of values is quite broad
and can be used to justify a range of efficient standards. Using a 3 hour VCR would lower the
cost of load shedding and would lead to a less stringent standard. The higher 1 hour VCR
was used by Acil Allen as this best reflects distributors approach to rotational load shedding.
Taking all this into account and focussing on the NSW and SA data a standard the range of
0.0005% to 0.0010% is reasonably robust to the variability in the input assumptions.
Form of the Reliability Standard
ACIL Allen’s analysis leads to a recommendation for the efficient level of the reliability
standard expressed in USE terms but this can be translated into a number of different forms
of the standard depending on how each of the individual characteristics of reliability are
valued.
The key aspects of reliability that could form a standard are:
Likelihood – the probability of load shedding in a region during a year.
Size – the expected (average) amount of load shedding that is forecast to occur. This
is the basis for the existing reliability standard.
Shape – the degree of skewness in the distribution of USE outcomes which highlights
the amount of tail risk.
The choice of the form of the reliability standard really comes down to a trade-off between
something that is easy to communicate and something that captures the desired features of
reliability. For example, if the desired outcome for reliability is expressed in terms of
avoiding load shedding in any year then the best form of the standard would be a Loss of
Load Probability (LOLP).
12Alternatively, if limiting the amount of load shedding in a year is the main objective of the reliability standard, then the current approach using expected (average) USE is fit for purpose. The Terms of Reference for this review suggest the standard should reflect community expectations that electricity supply will remain reliable during a “1 in 10” (POE10) year summer. One way of achieving this is to define the standard in relation to POE10 inputs such as hot weather or high demand that is only expected to occur 1 in 10 years. This could then be used in a reliability measure that is only defined over that subset of inputs. For instance, the existing 0.002% USE standard could be changed to apply to only POE10 scenarios rather than all scenarios. This would have the effect of making the USE standard roughly three times stricter. Whilst this approach certainly has merit, the ESB believes that focussing on just POE10 inputs could mean that we miss emerging risks that are associated with less extreme conditions. For instance, the January 2019 load shedding in Victoria occurred at conditions that were more likely than 1 in 10 but coincided with multiple forced coal station outages. On balance, the preferred reliability measure to reflect the expectation outlined in the review’s terms of reference is to set a stricter standard for the existing USE measure. A tighter standard would reduce the risk of load shedding and ensure the system is more reliable during a POE10 summer whilst ensuring continued vigilance around emerging risks at other times. Options for the Proposed Standard Within the range of potential efficient standards in the ACIL analysis the following standards are recommended for consideration: Expected USE
The resultant reliability gaps (expressed in MW) for each proposed standard are shown in the following table. These are calculated using the 2019 ESOO data and the gap compared to the existing reliability standard is also shown. There are no forecast gaps under any of the proposed standards for Tasmania and Queensland. Table 5: MW Reliability Gaps using 2019 ESOO data under Different Standards MW Existing Standard USE
Implications of a tighter standard
The impact of moving to a tighter standard depends on the reliability response that is
triggered by the standard.
The purpose of AEMO’s ESOO (Electricity Statement of Opportunities) is to provide
information to the market to encourage the identification of investment opportunities. A
forecast breach of the standard provides a strong signal to the market to respond.
The reinforcement of this signal through the RRO means that a forecast breach can be
expected to lead to investment and innovation that can help to remediate the reliability
gap. If there is a sufficient and timely response from the market future high prices and load
shedding will be avoided.
As described earlier the NER prescribes three responses to a higher reliability standard.
1. Review of Market Price Settings
The NER requires that the Reliability Panel conduct a review of the reliability standard and
reliability settings every four years with the next review due to be completed by April 2022
for implementation in July 2024. The review must consider a range of factors including the
impact on investment, spot prices, participants and risks in the market. Therefore, it does
not automatically translate that a higher reliability standard will lead to a change in the
market price cap, although it is likely that this is the case.
2. RRO
The impact of the higher standard is that it will trigger the RRO at T-3 and T-1 more often
than the existing standard. At T-3 the main consequence is to trigger the Market Liquidity
Obligation (MLO) which applies to up to three generating entities in the relevant region.
At T-1 the consequence is that retailers will need to ensure they have sufficient contracts in
place to meet their share of POE50 system load. The ESB recommends that the contracting
level for the purposes of compliance in the RRO remain at a POE50 level.
The direct impact of the higher standard on the RRO is confined to the way that the
Procurer of Last Resort (POLR) allocates RERT costs to non-compliant liable entities. The
POLR mechanism effectively limits the allocation of POLR costs to the amount identified in
the T-1 reliability gap. A higher standard results in a higher reliability gap than would
otherwise be identified and therefore a greater proportion of RERT costs allocated to non-
compliant entities.
Therefore, the impact of the higher standard is to change the split of RERT cost allocation
such that more costs are allocated to non-compliant entities. This seems reasonable and
should provide a greater incentive to retailers to comply with the obligation.
3. LN RERT Procurement
In the absence of a market response a higher standard would lead to AEMO procuring a
greater quantity of RERT than under a lower standard.
15However, this does not necessarily mean that AEMO will actually procure this quantity of LN
RERT as AEMO still has the option to procure RERT nearer the time through the medium and
short notice mechanisms. In fact, there have been occasions where AEMO has declined a LN
RERT offer as too expensive and then managed to contract the same resource more cheaply
through the SN RERT.
Hence, AEMO’s approach to contracting reserves would be focussed on continuing to
monitor the changing outlook using information from the MT PASA and EAAP whilst
tendering for reserves to establish price levels in the market.
The main benefit of increasing the quantity of LN RERT is that it allows for a more orderly
procurement approach and for a wider range of resource providers to participate which
should be beneficial in reducing RERT costs (although this needs to be weighed up against
the costs of incurring availability payments for resources that may not end up being used).
Quantification of Costs and Benefits of a higher level of reliability
The preceding discussion highlights that a tighter standard over the interim period doesn’t
automatically translate to more RERT and higher costs to consumers. However,
consideration should be given to the impacts – it is likely that a tighter standard, without a
corresponding change in the MPC would not necessarily deliver what it was intended to.
However, for the purposes of quantifying costs and benefits we shall assume that the
market fails to respond and AEMO is forced to procure a higher level of reserves to meet
the new standard.
It should also be clear that the costs and benefits will depend on the outlook for reliability. If
there is no identified gap there are no reserves to procure so Queensland and Tasmania will
incur no additional costs as no reserves are required.
Even in Victoria, NSW and SA there are years in the ESOO outlook with little or no gap under
each of the proposed higher USE standards.
ACIL Allen’s analysis provides the quantification of the additional costs of moving to each of
the proposed levels of standard for FY24. These are summarised below for the base case
with DR limited to the RERT volumes and the VCR based on all segments:
Table 6: Costs and Benefits of Higher Standards under ACIL Base Case in FY24
16State $ USE
AEMO’s RERT charges are passed through to retailers who then pass them onto customers
either through a line item on their C&I bill or through periodic changes to the bundled tariffs
paid by mass-market customers. The Victorian Default Offer applicable for 2020 includes an
allowance for recovery of RERT costs to the tune of $3.20/customer/year which is based on
last summer’s RERT costs in Victoria of $0.80/MWh. Over the last two summers AEMO has
spent $52m and $34.5m respectively on RERT almost all of it for Victoria. In the current
summer AEMO has indicated costs to date of $35m for the 4 days where RERT has been
required across Victoria and NSW.
The ACIL analysis suggests that the total cost of meeting each possible tighter standard in
the FY24 example is no greater than the level of costs that AEMO has incurred in each of the
past three summers.
If AEMO were to procure the entire amount of the gap then ACIL Allen have quantified the
costs in FY24. (The low range is the High RERT/Low VCR and the high range is the Low
RERT/High VCR Acil Base case).
These are for NSW $8.8m to $23.9m for the 430 MW gap which translates to $0.13/MWh to
$0.36/MWh. Or $0.65/year to $1.80/year for a customer using 5 MWh per year.
For SA it is $6.3m to $8.5m for the 115 MW gap which translates to $0.50/MWh to
$0.67/MWh. Or $2.50/year to $3.37/year for a customer using 5 MWh per year.
For comparison the Vic RERT allowance in the VDO is $3.20/yr for 2020 and it was $6/yr for
2019 – both of these were set based on the previous year’s RERT costs.
In practice, we expect that the gap in 2023/24 will likely to be significantly less than 430MW
as Liddell is extended or replaced by additional capacity within the market and VNI and QNI
are completed (both projects were excluded from the ESOO modelling as they had not
received final approval at the time). Accordingly the estimated costs to consumers should
be viewed as a conservative upper bound.
For the forthcoming years where there is less forecast USE the reserve costs will be
substantially lower e.g. the 0.0006% standard only requires a maximum of 95 MW of
reserves in Victoria.
ACIL’s analysis of costs is derived from their model which assumes perfect foresight and the
ability to optimally allocate contracts to USE taking account of the various constraints on
those contracts e.g. maximum durations. It also excludes some RERT contracts including the
smelter contracts and the ARENA RERT contracts.
Taking all things into account AEMO would be expected to incur higher costs than ACIL have
indicated given it will be making decisions in real time with imperfect information. Hence,
the level of costs that have been incurred historically provides a reasonable guide to what
would be required to meet a higher standard.
184. Options to achieve a tighter standard
The board explored several potential mechanisms to meet a higher standard – a higher
market price cap, changing aspects of the RRO and establishing a reserve.
Raising the market price cap
Under the current energy only market design, a change to the reliability standard could be
delivered by changes to the market price cap and related settings. Ernst and Young (EY) was
engaged to undertake modelling to provide indicative figures on the market price cap
required to bring on additional capacity to achieve a higher standard. The approach was to
develop a market model for the 2023-24 financial year with two capacity mixes that result
in:
the expected USE just breaching 0.002% of demand (the present reliability standard)
in SA, NSW and Victoria.
the USE being expected to be > 0.002% of demand in 1 out of 10 years (AEMO’s
proposed new standard in the ESOO) in SA, NSW and Victoria.
In each case the distribution of USE was estimated when it is close to each respective
standard; in each case the MPC/CPT settings combination was determined that would be
needed for a marginal new entrant OCGT to recover its annualised costs. The modelling took
into account the supply mix and ownership structure expected in the NEM in2023-24 and
sought to emulate real world bidding behaviour in assessing spot prices and generator
revenues.
Having determined the market price cap that met the current and alternate reliability
standard, the estimated cost to consumers of moving from one standard to the other was
determined.
The results of the EY analysis indicate that to move from the current standard to the higher
standard in each of Victoria, New South Wales and South Australia would require an
approximate trebling of the MPC. Preliminary analysis indicates that this results in a 2-4%
increase in demand weighted pool prices depending on the region. This is projected to be
significantly more expensive than the ‘out of market’ mechanism proposed (below) to meet
a higher standard.
Additionally, changing the market price cap is unlikely to have a material impact on physical
capacity ahead of next summer, or possibly the following summer as the higher potential
risks and rewards to participants flows through contracting and investment decisions. As
such it may not meet COAG EC’s requirement to have in place mechanism to meet a higher
standard by next summer.
For these reasons the ESB recommends that the market price settings not be changed as an
interim mechanism to meet a higher standard. This may have some unintended
consequences, but the ESB considers that meeting the immediate needs for reliability
outweigh these concerns.
19Increasing the required contracting level under the RRO
The view of the ESB is that changing the required contracting level under the RRO is not a
suitable mechanism to meet a higher standard. Doing this could result in higher contract
market premiums without necessarily driving additional investment in physical resources.
The current requirement for liable entities to hedge to a 1 in 2 year demand level for
compliance purposes should deliver more than a 1 in 2 year level of resources because
those using physical resources for their own liability or to sell firm products will maintain a
level of self-insurance.
Once triggered, 3 years out, the Retailer Reliability Obligation puts liable entities on notice
to cover their share of a one-in-two year peak demand at the time of the reliability gap. If
the gap remains 1 year out, liable entities are required to submit their contract positions to
the AER, adjusted for its relative ‘firmness’ based on the interim guidelines developed by
the AER. These guidelines were developed to reflect the likelihood of a qualifying contract
(including physical assets) providing cover to the liable entity during the period of the gap.
This approach to ‘firmness’ adjusting contracts and physical resources is built in large
around the practice adopted by participants when managing a portfolio and the risk of
exposure to high prices (ie participants will not typically sell or rely on all of their resources
being available at the time of high prices unless they are truly firm).
As the industry is not controlled by a single player, this process of adjusting firmness by each
participant should ensure there will be more physical resources5 to back these contracts
than needed to meet a 1 in 2 year peak. This occurs because each participant typically self-
insures against the risk of the resource not being available at the time needed; and that
there is a very low likelihood that all of these resources, being held in reserve, will be
unavailable at the same time.
One option that has been suggested to increase the reliability of the NEM is to increase the
contracting level for the Retailer Reliability Obligation from P50 to P10.
Given the current estimates of contract availability indicate that there are relatively tight
conditions for the supply of contracts across the NEM, the impact of increasing the hedging
requirement for the Retailer Reliability Obligation could be expected to increase forward
prices and contract market premiums further (potentially increasing costs to consumers). It
is important to note that most liable entities already hedge to P10, but would include
contracts in the mix that would not be considered firm (eg weather derivatives) by the AER,
triggering the RRO is expected to incentivise liable entities to seek alternative firmer ways to
manage risk (eg Demand Response)
5
One of the key assumptions in the design of the Retailer Reliability Obligation is that physical resources will follow the
financial signal – this is founded on the basis that requiring liable entities to contract sooner and to an adequate level, that the
financial market will provide enough time for a physical response. It also assumes that the non-physical players that help
support liquidity in the financial markets, such that volumes in most regions trade at a multiple of underlying demand, will
not bet against the need for additional resources or that spot prices won’t reflect the need for these resources. This latter
point in part reflects the level of confidence in the forecasts for the market as well as the level of the market price cap to
incentivise a physical response by resources to any identified gap.
20If a decision to increase the hedging requirement to the P10 level, then further
consideration is needed on whether it will:
a. drive investment in resources beyond what was needed to meet the preferred
reliability standard (and potentially impose higher costs on consumers), particularly
in the absence of any changes to the MPC or
b. increase contract market premiums to the point where non-physical players bet
against the need for additional resources, which would also raise costs to consumers
and break the implicit assumption in the Retailer Reliability Obligation that physical
resources will follow the financial signal.
5. Recommended mechanisms to deliver higher reliability
Amendments to the RRO trigger
Depending upon how a higher standard was implemented in the rules, the RRO T-3 and T-1
instruments could be triggered off the higher standard. This would result in the RRO being
activated more often – see Table 5 above – although on current projections only in NSW,
Victoria and South Australia. This may marginally increase contracting with flow on impacts
for incentives to investment in additional physical resources (subject to the caveats in noted
in the discussion around increasing the contracting obligation). To the extent that this
increases physical resources within the market it will reduce the additional capacity needed
to be procured through any out of market mechanisms.
For this reason, the ESB recommends that should a higher standard be adopted it should be
used to trigger the T-3 and T-1 instruments in the RRO.
Amending the RRO T-3 and T-1 instruments
The ESB has considered amending the RRO so that the T-1 instrument would no longer
require a T-3 instrument to be issued for the same period.
De-linking the T-3 instrument would allow AEMO to request a T-1 instrument, should AEMO
identify a material shortfall in the ESOO. It would have the effect of putting retailers in
jurisdictions that are at risk of not meeting a higher standard ‘on notice’ that their contract
positions should meet the obligations under the RRO at all times.
The principal benefit in doing so is to provide greater incentives for market participants to
make generation capacity available when it is needed most. It may also have marginal
impacts on incentives to invest in greater physical capacity. This should improve reliability
outcomes for consumers.
At present, AEMO can only request a T-1 instrument if it has first requested (and the AER
has issued) a T-3 instrument for the same period. If the T-1 instrument can be triggered
without the T-3 instrument, AEMO must only identify a forecast reliability gap one year
ahead to trigger the RRO. At a high level, the associated changes to the law and rules are
21straightforward, except for the implications a higher standard would have on the market
liquidity obligation (MLO).
The MLO requires generators with greater than 15% market share in a region to submit bid
and ask prices for baseload swaps and caps when a T-3 instrument is issued. If a T-3
instrument triggers on a higher reliability standard then it will trigger more often and
generators would be required to comply with the MLO more often. If it is triggered much
more often, it might be more value to the market and consumers for the MLO to be
converted to a tendered market making service.
The ESB notes that the changes to the RRO being considered would create more
administrative and compliance effort for AEMO, for participants, and for the AER.
Additionally, amending the T-3 and T-1 instruments would require law changes, which
means the earliest possible date for making the T-1 instrument would be in 2021/22 for the
following year – a year in which all jurisdictions are projected to remain below tighter
trigger.
On balance, the ESB recommends de-linking the T-3 instrument with consequential
amendments to the MLO to be developed in implementation. Given such a change would be
market sensitive, the ESB will consult with industry on an implementation timeline that
minimises any disruption to the forward contract market.
Out of market mechanisms
As noted above, the ESB has undertaken modelling of the impacts of achieving a higher
reliability standard through the current reliability mechanisms. The analysis showed that
the market price cap would need to approximately triple to attract the additional
investment required. This change would lead to a projected rise in the demand weighted
average price of wholesale of 2 to 4%. It would also significantly increase volatility and risk
for market participants and would need to be implemented carefully, providing time for
participants to adjust their contracting and prudential management.
The ultimate mechanism for driving reliability in the market currently under review in the
post-2025 market design, an evolved NEM, is one option. However other options are being
considered which would rely less on high energy spot prices. As the ultimate reliability
mechanism is yet to be decided, a step of this nature is not warranted now.
This then suggest the need for an ‘out of market’ mechanism to procure the additional
resources required to meet the higher standard. The design of that mechanism will be
constrained by the need for urgency and to be able to deliver additional resources for the
summer of 2020/21. Within that constraint the objective would be to:
efficiently recruit the most efficient and cost-effective resources for the defined role
minimise distortions to the primary energy market to ensure that market driven
investment to at least to the level required to meet the 0.002% USE standard
be designed in a manner which can be modified or rescinded in the transition to the
longer-term market design
22 operate in concert with the energy market, reliability and emergency reserve trader
(RERT) and the Retailer Reliability Option (RRO)
The mechanism would be designed in such a way that it preserves optionality for future
market design, but also provides can be evolved to move towards that design.
Technologies that are least cost
Modelling undertaken by AEMO gives us important information about the likelihood and
shape of the unserved energy the reliability reserve is seeking to offset. That information
includes not only the likely frequency of USE (how often it occurs) but also its scale and
duration (how long does it last in minutes/hours when it occurs). The analysis by Acil Allen
builds on that work and shows the likely optimal risk of resources
to meet this need.
An important observation from the modelling is that the resources required for the
Reliability Reserve will only be called upon sporadically and usually for a limited time period.
In some instances, additional services may be needed as infrequently as once every five
years. This suggests a very uncertain revenue stream and a product which is more akin to
insurance rather than a commodity.
The work by Acil Allen, based on experience from the RERT, suggests that demand side
response is likely to provide the least cost response. Activating flexible demand is a medium
to longer term objective as the scale of variable renewable resources continues to grow,
both at the utility scale and embedded at customers’ premises.
Acil Allen’s work suggested that some OCGT generation could be viable, particularly if the
demand side market is not sufficiently deep at this stage. An OCGT has a high proportion of
fixed costs and, subject to fuel costs, a relatively low operating cost. An OCGT would
therefore be more efficiently used in market where it could operate at a higher capacity
factor.
It is proposed that the reliability reserve be technology neutral although designed to be
attractive to demand side response as that is likely to provide least costs for the required
role.
6. Key concepts in the design of an out-of-market mechanism
How parties would participate
Parties that participate in the mechanism would have to offer resources that are not
participating in the wholesale market for the interval for which they are procured for the
mechanism. That is, they are deemed out of market.
It is important that only resources considered out of market participate in the mechanism.
Otherwise, the distortionary effects on the wholesale market would be significant –
23generators may withdraw capacity from the wholesale market in order to get payments for
the Reliability Reserve.
The new out of market provisions for the enhanced RERT offer a template to ensure
minimal distortionary impacts on the market. These provisions tightened up the out of
market provisions as far as possible, while still allowing flexibility for AEMO in terms of what
it can procure.
It is proposed that the reliability reserve be an out of market design, operating under a
framework based on the enhanced RERT provisions.
There are two broad options for procuring the resources, given they are only used rarely.
The procurement could:
have no upfront payment but a large payment when used. This is similar to the
current short term RERT; or
pay an annual fee for providing the capability to respond when needed and a
commensurate lower fee would be paid if used. This is similar to the short term RERT
and the ARENA-AEMO trial.
The first option is well suited to the role required as it only requires payment when used
and, provided its cost when used is lower than the Value of Customer Reliability (VCR),
would deliver value to customers. However, it would provide a very volatile and uncertain
return which is unlikely to attract any investment required to access new demand side
resources. It is considered important that the proposed Reliability Reserve mechanism does
not simply reassign the same demand side resources from the market or short term RERT.
The second option could attract new resources and is a reasonable way to pay for an
insurance product. The RERT mechanism provides a range of bespoke actions based on
negotiated prices. The ARENA-AEMO trial established two standardised products, each an
option for AEMO to call on a provider to lower the operational load by 1MW within a
designated time period. It is considered that defining standardised reserve products and
running a reverse auction to procure the volume required should drive competition and
innovation and lead to the lowest annual fee. The product being procured should be
defined in a technology neutral manner and by guaranteeing a minimum payment over
multiple years could encourage aggregators and retailers to invest in developing new ways
to access demand response. These resources could later shift from being out of the market
to into the market.
Resources would generally have to be physically located in the region or regions in which a
Reliability Reserve is required, consistent with current RERT arrangements. The
procurement process could optimise the volume and cost across regional boundaries but
only where they contributed to achieving the required outcome.
Where an upfront, or option fee, is paid, the requirements should ensure that the resources
procured are not involved in the market or contracted to retailers to provide a market
response. These requirements should be the same as those under the enhancement to the
24RERT process i.e. scheduled parties are deemed to be ‘in the market’ and so are not allowed
to participate in the process; non-scheduled parties are deemed to be ‘not in the market’
and so can participate in the RERT (provided they do not have a contract with their retailer
that applies to the same trading intervals). The existing obligations under the NER place civil
penalties on these parties in terms of making sure the same resource is not offered to the
market at the same time it is offered to AEMO – this is worked out contractually.
There should be flexibility in how resources to meet the Reliability Resource are procured,
but a least a portion should be procured through a reverse auction of standardised, regional
products building on experience from the ARENA-AEMO trial.
Who would procure the capacity?
The Reliability Reserve mechanism needs to be in place before the summer of 2020/21. This
is a stretching timeframe which limits the options available for immediate implementation.
AEMO should (in the first instance) be responsible for procuring the reserve capacity.
The expectation is that for the summer 2020-21, AEMO would run a reverse auction to
procure reserves. This would require urgent action to establish a framework in the Rules.
That framework would build strongly on the provisions related to long notice RERT and
would allow flexibility in procurement, potentially through guidelines. Transition measures
may be needed to cover immediate action.
Consideration was given to transition responsibility to procuring the Reliability Reserve to
retailers, potentially through a retailer-based certificate mechanism. If the Reliability
Reserve was to be maintained beyond the transition period to new market arrangements
arising from the post 2025 market design, retailers may be better placed to manage the
procurement of capacity at least cost. AEMO would still set the capacity required for the
Reliability Reserve and would allocate the procurement obligation to each retailer based on
their market share (as determined based on energy traded through the NEM in the previous
summer). Once options for post 2025 market design are more progressed, consideration
could be given as to whether it could move to a retailer based obligation sooner than 2025.
If the Reliability Reserve is to be maintained as a permanent feature of the future market
design, responsibility for its procurement should transfer to retailers.
How much would be procured?
In conceptual terms, the existing processes for forecasting USE would continue to apply. The
ESOO as the primary planning tool would identify the capacity of additional resources
required to meet the higher reliability standard proposed. That would be outlined by region
and by year. AEMO would determine the capacity to be procured, taking into account the
nature of the resources required (response time and period of use) and would include some
allowance to reflect the fact that the resources are not guaranteed to be firm (e.g. demand
response may not be there when required).
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