Technical material on the risk violation curve design
2 Apr 2019
In support of the consultation on the remaining-elements of real-time pricing – 29 March 2019 we have published this technical material on the 'risk-violation curve' design element, as a zip archived file. This material includes full modelling results, summary charts, and further technical explanations.
Real-time pricing frequently asked questions
12 Sep 2017
These are distinct projects and do not depend on each other.
Any party seeking to influence market outcomes by biasing their PRSS inputs in the lead-up to a planned market system outage would likely attract attention from a compliance perspective.
Based on current information, the Authority has no reason to expect any significant change in the number of pricing error claims.
Incorrect inputs are relatively rare—12 instances were identified in the past three years. Although these involved errors in inputs to dispatch schedules, they might not have triggered price error correction processes had RTP been in operation. This is because, under RTP, schedules will only create dispatch prices if dispatch instructions are issued. In addition, a materiality threshold is proposed before the error correction process is triggered. This threshold reflects the proposed emphasis on providing actionable real-time information, and the proposal to only re-open prices if a manifest error has occurred.
Under RTP, the dispatch price would be based on a default scarcity price value, since this is higher than the IR CVP. This type of situation would imply reserve cover is being relaxed to provide energy, but could not provide enough resource to meet demand. Some emergency load shedding would therefore be needed in real-time, and as a result a default scarcity value would set the dispatch price.
Yes. This recognises it can be more efficient to shed load than to use all offered resources at costs greater than scarcity pricing values.
Yes, that is the proposal. The Authority welcomes any specific views from submitters on how to set CVPs for fast and sustained IR to best ensure the value of reliability (including reserves) is signalled in spot prices.
No change is proposed to the current operational practice. This seeks to minimise the amount of reserve requirement that is relaxed, as part of the normal dispatch optimisation process.
Yes, and yes.
There is no reason to compel any consumers to use the DD product, and the Authority is not proposing to do so.
If consumers use DD (classic or lite), their intended degree of price-responsiveness will be reflected in dispatch prices. If they choose not to use DD, their prevailing level of demand (recorded by ION meters) will be assumed to continue.
Clause 13.5A of the Code requires generators and ancillary service agents to meet a high standard of trading conduct in relation to their offers. There is currently no similar provision in relation to dispatchable demand bids.
However, the Authority has a review of spot market trading conduct provisions on its 2017/18 work programme, and this is expected to be completed before RTP goes live in 2021.
This appears unlikely, as offers would remain subject to the one-hour gate closure rule. The Australian market has no gate closure period. Revisions within a trading period would only be allowed in response to grid emergency notices (where offer volumes can be increased) or for a bona fide physical reason. Revisions would continue to be subject to the compliance provisions of the Code.
In the first instance, it is important to make sure participants understand the importance of submitting robust information about their intentions, in the form of offers and bids (ie, education is important).
Ultimately, if a party persistently made bids (or offers) that were unrealistic, it could face scrutiny from a compliance perspective.
The future is inherently uncertain, so it is not possible to say whether the past is representative.
The Authority is not aware of any reason to expect RTP will alter the level of volatility in dispatch prices or final prices.
At present, ‘five-minute prices’ are published based on conditions in the preceding five-minutes. Although they are sometimes referred to as real-time prices, these prices are only indicative and can vary widely from final prices. For example, five-minute prices have sometimes reached $100,000/MWh or more (due to infeasibilities), much higher than the level of final prices. Five-minute prices are not used for settlement, and the Code only requires the system operator to use reasonable endeavours to calculate them.
The incentive to “turn off” comes from:
- Consumers who pay the spot price will save money by reducing usage, when the price is above their willingness to pay.
- Consumers with hedge contracts will receive money from their counterparties when the spot price is above the contract strike price. Consumers will be able a retain more of these contract payments by reducing their usage in high price periods.
- Some consumers have contracts with their retailers that reward them for reducing usage when spot prices are high.
It is not practical to have a full parallel run because RTP would change some inputs to current dispatch schedules. For example, the constraint violation penalties for energy deficits that apply in current schedules would be replaced by default scarcity bid values, and this could alter dispatch instructions.
While a full parallel run is not feasible, it may be possible to publish notional ‘real-time’ prices with a short lag. These prices would largely simulate the effect on final prices if RTP had been in operation. This will be considered further if consultation submissions support this approach.
The Authority welcomes views on when to gazette the Code amendments, noting that early publication can provide more notice, but may need to be amended if any issues are identified in the implementation phase.
We are seeking parties’ views on whether to retain a process for identifying and addressing any material pricing errors, and, if so, how these should be handled. Please see sections 3.96-3.105 of the Consultation Paper for more information.
It is not proposed that scarcity pricing would be triggered by a planned transmission outage itself, as these are typically managed without emergency load shedding being required. However, if an unexpected event (e.g. loss of generation) were to occur during a planned transmission outage, and this led to scarcity default values in dispatch schedules, this would trigger scarcity pricing in the affected area if the schedule was used to issue dispatch instructions to any party.
It is not proposed that scarcity pricing would be triggered by an unplanned transmission outage itself (ie, the capacity now removed from service). However, scarcity pricing would apply if the unexpected loss of transmission capacity triggered default scarcity values in a subsequent dispatch schedule, and that was used to issue dispatch instructions.
It is not proposed that an AUFLS event would trigger scarcity pricing because it is not based on dispatch schedule instructions. This reflects the same approach as at present.
No. Rolling outages can only occur with prior notice to consumers, and would not trigger scarcity pricing under RTP. This is consistent with current arrangements.
The current market design does not include a spot price cap and it is proposed that this will not change.
Generators or dispatchable demand participants will be able to set offers or bids at levels above the default scarcity values if they wish. Of course, the likelihood of resource providers being called upon is reduced if they choose to make a bid/offer higher than default scarcity values. However, they might still be called upon in some situations.
Over time, the volume of load assigned default scarcity prices could shrink to a level where it is insignificant, as more purchasers choose to bid their demand explicitly. In this way, prices could rise above default scarcity price values if purchasers reveal they are willing to pay more for supply.
Yes. Clause 13.70(a) of the Code provides the system operator with discretion to depart from a dispatch schedule if it believes this will better meet the dispatch objective in the Code. No change to this discretion is proposed under RTP.
Furthermore, it is proposed that under RTP, default scarcity values would only set a dispatch price if the associated schedule has been used to issue dispatch instructions to any party. That may not necessarily occur if a decision is made to (say) temporarily overload a circuit rather than invoke emergency load shedding.
Under the RTP proposal it is technically possible that dispatch prices at scarcity values could be produced even though emergency load shedding is not being applied in practice. For example, instructions to shed load might have been issued by the system operator, but not yet acted upon. It would be impractical to test for this condition while still providing an actionable price signal in real-time. See sections 3.29-3.36 of the Consultation Paper for more information.
It is important to recognise, that under the RTP proposal, it is proposed that default scarcity price values will only produce dispatch prices if the associated schedule has been used to issue dispatch instructions to any party.
Not at present, but this idea has merit and the system operator will look at whether this could be done in future.
The Authority is open to proposals from submitters on how best to ensure that the value of reliability (including reserves) is signalled in spot prices.
The Authority noted in 2011 that the choice of a minimum geographic threshold for applying scarcity pricing was a matter of judgement. It chose an island-level approach as the initial step because of concerns about locational price risk at the time, and because that approach was scalable.
Since 2011, significant grid investments have been commissioned which have acted to reduce the incidence of large locational price differences, and new locational risk management products have been introduced. In addition, an island-level approach would be practically difficult with RTP and could undermine efficient incentives at the local level. For example, batteries or local demand response could provide the least cost option to address some local security issues, but would not be rewarded if an island-wide shortage is required to trigger scarcity pricing.
In essence, the current HSWPS process provides a ‘tyre-kick’ safety check. It slightly relaxes the binding transmission constraint(s) to reflect the degree of uncertainty that can apply to input parameters in the dispatch schedule. This relaxation is intended to mitigate the price effects if the constraint(s) are only just binding. However, if the constraints continue to bind post the relaxation process, spot prices at affected nodes could very high—potentially $100,000/MWh or more. The current HSWPS process therefore has unpredictable effects on prices.
Under the RTP proposal, a HSWPS could trigger default scarcity prices (most likely at the lowest default value of $10,000/MWh). This makes the effect of a high spring washer more predictable, and should encourage the emergence of alternative physical solutions in areas where HSWPS are expected to occur.
It is proposed that dispatchable demand will remain voluntary, and only apply to those consumers that wish to use it.
Under the RTP proposal the benefit for individual customers is that they would receive a dispatch instruction or notification if the spot price for the forthcoming dispatch interval exceeds their willingness to pay. This means purchasers would not need to constantly monitor dispatch prices. Furthermore, in the case of DD-classic, customers would qualify for constrained-on and constrained-off compensation.
More generally, under the proposal, if price-responsive customers opt into DD-classic or DD-lite, that will make dispatch prices more accurate, because real-time schedules will better reflect the price response intentions of DD participants.
Some customers may wish to be told when dispatch prices reach a pre-defined response level, but are unable to satisfy the stricter compliance requirements of DD-classic. Under the RTP proposal, DD-lite provides these customers with an option that may be beneficial to them. Participation in DD-lite will also make dispatch prices more accurate, because real-time schedules will better reflect the degree of price response intentions of DD participants.
Under the RTP proposal discrete loads can be bid, provided the individual loads meet the normal DD-lite criteria.
This is possible if a DD participant is ‘on the margin’. The Authority welcomes views on the extent to which this is practical concern, or whether customers could mitigate it via the structure of their bids (as generators are required do if they do not want to be marginal). The Authority and system operator also welcome views on possible mitigants such as including ramp rates or minimum cycle times (see section 3.75 of Consultation Paper.)
Customer bids show the price points where a customer prefers to alter its level of demand. This is simply the mirror image of generation offers. That is, the price in a bid indicates the maximum the purchaser is willing to pay for the associated quantity.
Under the RTP proposal, DD-lite notifications would be produced by the dispatch software, in the same way as dispatch instructions for DD-classic.
It is proposed that any change to rebid/reoffer provisions within a trading period would only be allowed in limited circumstances, such as a grid emergency or bona fide physical reason – as at present. Given these limitations, the proposed change is not expected to increase any potential for gaming. The Authority compliance team will monitor these events.
It is proposed that dispatch schedules will be recalculated every five minutes (approximately). Given their short time horizon, the best baseline value is the current level of demand. This would be measured from ION meters as the primary data source.
The only demand input which it is proposed would not be based on measured data, would be load for dispatchable demand customers. For these customers, the demand input is the quantities specified in their bids.
The Authority and system operator are considering options to improve the medium-term load forecast (MTLF) which covers the period from 30-minutes to 14 days ahead.
The MTLF data is not used in dispatch schedules, as they consider the next five-minutes. RTP is therefore not dependent upon changes to the MTLF.
Yes. This could be from consumers reacting to clearer real-time price signals, or dispatchable demand participants reacting to dispatch instructions/notifications. No specific assumption is made about the relative contribution from these different sources
Other benefits are also expected to flow from RTP, such as more efficient generation scheduling, and risk management, but most of these benefits have not been quantified. Please refer to Appendix E of the RTP consultation paper for more information.
RTP is expected to cost around $8 million to implement the necessary system changes.
Improved demand response would reduce the investment required in new generation and network infrastructure. To recoup the implementation cost of $8 million would only require a very small reduction in peak demand (around 10MW or ~0.1% of peak demand).
Please see the real-time pricing cost benefit analysis model below for more information on key assumptions in the cost-benefit analysis.
The proposed dispatch-lite product would provide an option for customers – which could be valuable to them. Even if it is not widely utilised at the outset, it may become more valuable over time as technology improves and it becomes easier for customers to alter their demand via smart controllers, or use of batteries etc. Given that DD-lite does not add any material cost, it appears to be a worthwhile option to provide, based on current information.
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