Alex Driscoll (Chair) welcomed participants to the October NEMW-CF and the agenda was confirmed.
Minutes of previous meeting / Actions
The NEMW-CF noted and accepted the minutes from the previous meeting held on 8 August 2017. Updates to the action items are includes in these meeting minutes.
Understanding Reliability and Emergency Reserve Trader (RERT) dispatch triggers
Tjaart Van Der Walt (AEMO) referred to the presentation provided in the meeting pack explaining how the RERT process works from an operations point of view. In the event where a reserve condition is identified, AEMO has the below options as per SO_OP_3715:
To exhaust all market possibilities (constraints)
Rearrange the operating nature of the network in conjunction with TNSPs
Market intervention and declare an LOR 2 or LOR 3 condition
The notification time that participants require varies per participant, due to different contracts that may be in place.
Three types of RERT are used - Long Notice RERT, Medium Notice RERT and Short Notice RERT. These all have different contracting protocols and may be contracted if the specific trigger point is reached for each different type.
AEMO uses the lowest cost option available, given possible timeframes.
Matt Grover (EnerNOC) queried what the relevant intervention pricing intervals are, in a 24 hours’ notice situation. Tjaart clarified that although a pricing event is advised from the time the activation signal is given the intervention pricing kicks in once the actual MW change in power system occurs.
Chris Murphy (Meridian/Telstra/Powershop) asked whether AEMO takes into account the least cost for consumers when activating RERT, noting that AEMO may activate RERT with 24 hours’ notice without knowing whether the RERT will definitely be needed. AEMO clarified that any known or perceived risks will be taken into consideration (based on information provided by generators or TNSPs and weather conditions) and AEMO will then determine which RERT to activate, selecting the cheapest option where possible.
Jennifer Brownie (QEUN) questioned how much RERT is contracted for Short Notice RERT and once it is contracted, how often is it actually available when AEMO contacts providers in a situation. James Lindley (AEMO) pointed out that at the moment, RERT is still in the process of being contracted. In an occasion where we believe it may be required, AEMO will contact RERT providers who have strict availability terms they must meet. The MW contracted for RERT will not be available to the market.
Ron Logan (ERM Power) raised concerns with the accuracy of AEMO’s forecasts, specifically relating to the RERT process. Damien noted that AEMO is working very closely with the Bureau of Meteorology (BOM) to resolve this issue. It was suggested that a discussion concerning AEMO’s forecasting accuracy be arranged for the next NEMW-CF. Damien raised that it would be helpful to hear from retailers and generators to see if AEMO can apply anything similar to what they utilise for forecasting extreme weather days. Action item 28.3.1
Restructuring of Lack of Reserve (LOR) criteria
Ben Skinner (AEMO) informed participants that AEMO is restructuring the LOR criteria as a result of reviews into the forecasting performances of last summer, in line with Finkel Report Recommendation 1.
Currently three types of conditions exist with regards to load shedding in the short-term (up to 7 days ahead); these are LOR1, LOR2 and LOR3. The first two are currently determined purely on the basis of a number of considered contingencies; principally the loss of the largest conventional generating unit in each region.
AEMO is proposing to retain the contingency risk, but also include a probability of the forecast variables moving unfavourably. AEMO is using a Bayesian Belief Network to analyse the historical predictability of these variables:
Aggregate of generator availability bids
From this a distribution of the predictability of these variables can be formed, consistent with current conditions. Where there is a material risk that an unfavourable movement in them would lead to load shedding, LOR2 will be declared. AEMO is proposing to use a 97% confidence interval, and backcasting suggests this will moderately increase the incidence of declarations of events 6 hours ahead.
Ben advised that AEMO will publish draft guidelines on the new approach on 17 October and submissions are welcome by 14 November. This is occurring in parallel with an AEMC rule change that empowers these guidelines. The aim is to have this project in place by early January 2018.
Tom Butler (CEC) asked whether AEMO had considered moving away from the LOR framework entirely given the high level of uncertainty in renewables’ forecasts. Ben said that the improvements had been built on the existing framework and infrastructure in order to be in place quickly, however an entirely different approach could be looked into in the future.
Angus Holcombe (Meridian Energy) asked whether the wind forecast comes from AWEFS. Ben advised that this is correct, and ASEFS for large-scale solar forecasts.
Jennifer Brownie queried what the cost to a consumer is if they do not have electricity. Ben noted that an AEMO-led exercise was completed a couple of years ago titled the ‘Value of Customer Reliability’ and this can be found here.
Chris Murphy queried whether AEMO would be able to publish the FUM and LCR figures rather than just the greater of as presented in the proposed design, to enable participants to better understand the situation. Ben encouraged Chris Murphy to submit this suggestion in their submission to the guidelines.
Ron Logan asked whether it would be possible to get backcasting information on the impact if activating 24 hours in advance. This suggestion will be passed on to the project team.
Phil Pollard (QEUN) asked whether AEMO looks at states individually or whether it is done for the overall NEM. Ben advised that the ST-PASA shares reserves between the regions and assesses reserves available to each regional reference node subject to intra and inter-regional constraints.
Any further questions on this topic are welcomed to firstname.lastname@example.org. Comments on the Guidelines can be sent to LOR2017@aemo.com.au.
Amendments to Constraint Violation Penalties (CVPs) during Operational Events
Ken Harper (AEMO) referred to the paper provided in the meeting pack noting that AEMO is consulting with market participants on a change to the Constraint Relaxation Procedure and the Schedule of CVP factors. AEMO will be able to modify the CVP factors for constraint equations to achieve reasonable dispatch outcomes. AEMO noted that the relevant CVP factors in relation to RERT are being reviewed and may also need to be modified.
All submissions or comments relating to the proposal should be sent to email@example.com by 27 October 2017. AEMO will then consider the submissions and aim to finalise the CVP procedure and schedule of CVP factors by 17 November 2017.
Review of Intervention Pricing
Abraham Yohannan (AEMO) provided an outline of the presentation provided in the meeting pack noting that this is a follow up discussion from the 29 March 2017 NEMW-CF. An action item from the 29 March NEMW-CF involved AEMO undertaking a review of the Intervention pricing and Directions process. This review has been completed by Endgame Economics and Stephen Wallace Advisory. Oliver Nunn (Endgame Economics) and Stephen Wallace provided an assessment of the Directions process and outlined options and recommendations for improving the Intervention pricing process.
The presentation explains the assessment as well as the options and recommendations.
Four options have been identified, and the consultants have recommended options 1 and 3:
Reduce the use of intervention pricing.
Adopt an improved intervention pricing rerun methodology.
Abandon the rerun approach and directly price scarcity.
Cease the practice of intervention pricing.
AEMO has updated its procedures to invoke system security constraints to manage shortage of FCAS services and power system security issues. If system security constraints are ineffective, directions will be issued to generators. AEMO has also advised ElectraNet of the Network Support and Control Ancillary Services (NSCAS) gap in South Australia, they are now considering options to remedy the issue.
AEMO is establishing an intervention pricing working group. If participants are interested in joining this group please email firstname.lastname@example.org before the end of October.
Jennifer Tarr (Stanwell) asked whether there is going to be a review of directions. It was commented that the direction process was slightly touched on as part of this review. Compensation and timetable issues relating to Directions have also been identified by AEMO as potential areas to look into.
Jennifer Brownie queried that if intervention pricing is not applied for unpriced services such as inertia, how would the cost for those unpriced services be picked up? Where is it transparent as to how much intervention pricing is costing the consumer? Paul Austin (AEMO) advised that the approach would be to put this inertia requirement into the network support agreement. This will mean that the TNSPs procure this service and a mechanism will be implemented to recover this cost via TuOS payments. In the interim there is the normal compensation and direction calculation process.
Jennifer also sought clarification as to whether the average prices for each jurisdiction on the data dashboard include intervention pricing. AEMO advised that this is currently the case.
System Restart Ancillary Services (SRAS) Guidelines Consultation – Final Summary
Glenn Gillin (AEMO) provided an update on the System Restart Ancillary Services (SRAS) Guidelines Consultation. Glenn advised that for stage two, six submissions were received which primarily address the location of system restarts sources and testing costs. AEMO is aiming to publish a final report and the final SRAS guidelines by 7 November 2017. The intention is to have SRAS contracts signed and in place by 30 June 2018. There are currently 10 SRAS services across all five regions in the NEM.
Norman Jip (Energy Networks Australia) asked whether the stage 2 submissions are going to be published on the AEMO website and Glenn confirmed that they will be published shortly.
Chris Murphy asked whether the issues discussed at the consultation forums were different to the issues that were raised when the reliability panel made changes to the System Restart Standard (SRS). Glenn advised that similar (but more detailed) issues have been raised through this process.
Electricity Statement of Opportunities (ESOO) – Key Findings
Matthew Marston (AEMO) advised that AEMO’s 2017 Electricity Statement of Opportunities (ESOO) was published in September. The ESOO is an annual planning document looking at the committed electricity supply information provided by industry participants with operational consumption and maximum demand forecasts to identify any Unserved Energy (USE) over the next ten years. This version of the ESOO highlights heightened risks of USE in 2017-18, in South Australia and Victoria with an increased potential for not meeting the reliability standard. The risk is forecast to reduce after 2018. Long term, the closure of the Liddell power station (announced as 2022) significantly increases the risk of USE in NSW and VIC.
James Googan (Origin Energy) asked how the SA Energy plan will influence the ESOO. Matthew Marston advised that the ESOO included the market operated components of the SA Energy plan, being 120 MWh of the 129 MWh battery. The ESOO did not include the non-market operated components of the SA Energy plan, being the extra capacity in the battery and the diesel generation. These would reduce the risk of USE.
Jennifer Brownie asked whether the graph used on slide three in relation to the base range, is the same graph that was used in the June Energy Supply Outlook. If so, eight solar projects in QLD haven’t been accounted for. Paul Austin (AEMO) advised that the report does consider the increase in renewables/solar.
Jennifer also sought clarification whether the USE that is being discussed, is USE in total or at a period of peak demand. Matthew confirmed that it is USE in total.
Ron Logan (ERM Power) asked whether there can be a presentation on how last year’s ESOO numbers compared to actuals. Alex has taken an action to try to arrange this. Action item 28.8.1.
Causer Pays – Technical Overview (part one)
In the interest of time the Causer Pays technical overview will be delivered at the 29 November NEMW-CF. Action item 28.9.1.
Chris Muffett (AEMO) provided an update on the Causer Pays Procedure (CPP) review noting that progress on the review has been delayed while AEMO considered the implications of causer pays on frequency control. Following completion of the work by DigSILENT, AEMO is proposing to continue with the review - the intention is to publish a draft determination in the next three to four weeks. Based on findings from the frequency control work, AEMO’s proposed approach is to prioritise a tactical change to the CPP, to address concerns raised that causer pays may be a contributing factor for participants in the provision of primary frequency control. To discuss this in further detail please contact Chris Muffett on +61 2 8884 5317 or email@example.com.
Angus Holcombe asked whether this will impact the Ancillary Services Technical Advisory Group (AS-TAG) and Alex advised that this is still continuing. Angus also asked whether the 30MW local FCAS requirement in SA would be reviewed. Tjaart advised this was currently under review with the results still to be published.
Chris Murphy asked whether AEMO can make the information developed with regards to DigSILENT and primary frequency control available to the Reliability Panel. Chris Muffett advised that this work has not yet been published, and it will be published in the next few weeks.
Summer Readiness Update
Stephen Clark (AEMO) provided a verbal update on the work AEMO has been undertaking to prepare for summer 2017-18. AEMO has a six-point plan which includes Supply availability, Fuel availability, Network availability, Peak demand response, Resilience and recovery and Operational changes.
Stephen noted that all regions are forecast to be within the NEM reliability standard of 0.002% USE. Victoria has an approximate 40% likelihood, and South Australia 30% likelihood of capacity shortfall this summer. AEMO is working with TNSPs to ensure there will be no planned major outages over summer and that planned interconnector upgrades are completed before the high risk period. The demand response programs have procured ~900MW across Victoria and SA, as well as temporary diesel generators which will contribute 170 – 225MW in SA. The expected gas shortfall is 54 PJ but this could be has high as 107 PJ under a range of credible scenarios, this risk has now been addressed by the Commonwealth Government through their heads of agreement with east coast LNG exporters. Generator risk profiling has been undertaken to better understand the risk of unexpected reductions in the availability of scheduled generating units on days of extreme heat. Out of the System Black recommendations 13 have been completed and four are underway.
Stephen advised that a joint Gas and Electricity emergency exercise was held in September 2017.
An industry wide Summer Readiness briefing is being planned for 1 December. Contact firstname.lastname@example.org if you have not received the invitation.
James Googan queried whether the 900MW of additional demand response in VIC and SA is part of the RERT scheme and whether it can be broken down by region. Stephen advised that more than the 760MW of RERT in Victoria has been procured and AEMO is currently working on the required RERT for SA. Stephen also noted that there has been some operational restrictions on some of these RERT products and therefore AEMO is looking for additional opportunities.
Lachlan Simpson (Meridian Energy) asked for the ratio of capacity from short and long notice RERT in Victoria. This question was taken on notice. Action item 28.10.1
Jennifer Brownie commented that within the demand response ARENA/AEMO contracts, there seems to be a heavy reliance on load curtailment contracts with commercial and industrial projects. Jennifer asked whether weight was given to curtailment of residential over industrial and commercial loads. This question was also taken on notice. Action item 28.10.2
Phil Pollard asked whether AEMO has given any planning or consideration to the recovery of renewables post natural disasters, using the Puerto Rico situation as an example. Stephen advised that worst-case-scenarios are considered in AEMO planning exercises but not as extreme as the Puerto Rico situation.
Market Audit 2016-2017
Rachel Rundle (AEMO) introduced Nick Burjorjee and Lincoln Chun from Price Waterhouse Coopers to present the results from the 2016-17 NEM audit findings and commence discussions on next year’s audit. PWC has reviewed the AEMO internal control procedures in relation to compliance with the National Electricity Rules (NER) for the financial year.
Nick advised that within FY17 no qualifications were reported in the NEM, and explained that this refers to any non-compliances considered material to market participants.
19 new findings were identified in FY17 and most of these are through management’s self-assessment process, this is a reduction from the previous year (24 findings in FY16).
Lincoln noted that the scope for FY18 is similar to that for previous years, including a review of any changes associated with Power of Choice changes and any other market system changes. Settlements Residue Action (SRA) will also be included in the next audit.
Contact details for Nick and Lincoln are included in the appendix page of presentation 6.
Market and System Update
Jonathan Jorgensen (AEMO) provided the below market update and also advised that a presentation was provided in the meeting pack explaining the reason for the FCAS price increases.
The electricity market saw a return to more connected price outcomes for August and September, contrasting with our last reporting period in June and July, which experienced significant price separation between the northern and southern regions. This separation was driven by constraints on the ability of the network to transfer lower-priced generation from Queensland and New South Wales into Victoria. This was particularly the case for September, which recorded only a ~$17/MWh average spread across the NEM.
Electricity prices remained high during August, with average prices between $82/MWh and $105/MWh across NEM regions. In New South Wales, prices increased to $102/MWh (+$11/MWh) due to reduced output from black coal generators resulting from outages and higher-priced offers. Prices in the southern regions were $8-18/MWh lower than in July, influenced by brown coal generators returning from outages and increased hydro output in Tasmania.
September registered warmer maximum temperatures than the long-term average in Brisbane and Sydney (~1.5 to 2 degrees) and colder than average maximum temperatures in Adelaide and Melbourne, with the latter experiencing its coldest start to spring since 2004.
Electricity prices were lower in September than in August, with average prices between $73/MWh and $87/MWh. The highest decreases month-on-month were experienced in South Australia (~$30/MWh below August) Tasmania (down $23/MWh) and Victoria (down $23/MWh). These price reductions were primarily driven by very high wind (2,030 MW on average, the highest month on record) and lower demand (-351 MW in Victoria), resulting in lower output from gas-powered and hydro generation (-509 MW in South Australia and Victoria). The record wind output also contributed to increased flows from South Australia into Victoria (+76 MW) and from Victoria into New South Wales (+258 MW). In addition, the high wind output led to five unit directions and curtailment of 28 GWh of wind in South Australia as part of AEMO’s system security measures. In New South Wales, black coal generation dropped by more than 1,000 MW, influenced by lower demand, higher imports from Victoria, a long outage at Mt Piper which coincided with coal supply concerns in the media for the generator.
In South Australia, generators were directed on several occasions to provide system strength. SA also recorded its lowest average September operational demand on record and a minimum demand of 793 MW on the 30th of September - the second lowest ever recorded in the state (excluding the South Australian System-Black event in late 2016). This follows a trend of low demand records contributed by high penetration of rooftop solar PV in South Australia. The minimum demand on the 30th of September coincided with record high September roof-top PV generation (165 MW) and lower than usual demand due to the AFL grand-final that featured the Adelaide Crows
August 2017 FCAS costs were the highest month on record. NEM wide FCAS costs were $28 million, which is $12 million (+83%) higher than the monthly average over the last 12 months (a period marked by high FCAS costs).
The increase in Regulation FCAS costs was largely driven by very high prices in South Australia on a single day. A planned outage of the Moorabool-Mortlake PS 500 kV line on the 28th of August led to the Heywood interconnector being constrained and application of the 35 MW local procurement constraint. Due to the limited suppliers of FCAS in the region, the price of Lower Regulation and Raise Regulation FCAS services increased to about $10,000/MWh for 10 hours, resulting in a cost of about $6 million in FCAS services for the day.
Southern states were largely flat for Cal18, relatively unchanged from the prices at the end of July.
NSW Cal18 rallied in price starting from $89.18 on the 1st of August, before hitting a high of $99 on the 20th of September. The price cooled somewhat from there, finishing the month at $94.41 and continued to reduce somewhat in October. QLD, too, saw fluctuating increases from ~$77 at the start of August to finish the month of September at ~$80. Though hard to directly correlate with price action, there are some potential market concerns which could be driving some of the outcomes, and include:
Increased focus on black coal in the media, with specific focus on Liddell
General coal issues, including environmental concerns of certain mines, stock levels etc.
Increase in international coal prices, with Chinese demand driving thermal exports. From June to September, the USD Newcastle FOB has gone from ~$81 to ~$97. This time a year was priced at $73, representing a 33% change in price.
One participant questioned, with regard to the minimum of 35MW Regulation FCAS enablement in SA during times when it is a credible risk of separation, whether there is a plan to review or test that in the future. Tjaart advised that this is currently under review. The timings and outcomes of this review were requested and this was taken on notice. Action item 28.12.1
Tom Butler asked whether AEMO is planning to release an updated version of the FCAS compliance report. This question was also taken on notice. Action item 28.12.2
Steve Johnston (AER) queried whether the high contingency prices are global or whether they are local to a couple of areas. Jonathan took an action to confirm that offline. Action item 28.12.3.
Ron Logan questioned if AEMO has done any work to look at the percentage of FCAS over the entire NEM settlement and whether that has increased. Ken Harper advised that this has not yet been looked into, however the team will investigate and present this at the next NEMW-CF. Action item 28.12.4.
Boris Basich (AGL) asked whether AEMO has a feel of how much energy prices are being reduced by the FCAS energy trade-off. Jonathan advised that it appeared to AEMO from observation, that the FCAS markets are markets in and of themselves. A reduction in energy, as a result of an increase in FCAS, has not been observed.
Tjaart Van Der Walt provided a system update noting that no major incidents have been noted in the past couple of months. Some directions were issued in SA for system security, specifically with regards to system strength. On 11 October 2017 AEMO experienced the failure of the main and back up NEM system for a short period of time.
Ron Logan (ERM Power) asked whether the IT failure only affected the bidding system or whether updated dispatch targets were affected. Tjaart advised that the EMS system in Brisbane was affected and the AGC was running in Brisbane. The AGC system was then successfully redirected to NSW, however, it affected dispatch targets for a short period of time. Tjaart noted that a report will be prepared for this event.
No other business was raised by the group.
Alex Driscoll notified participants that a quick survey will be distributed to participants shortly to obtain feedback on the forum.
Jennifer Tarr put forward the below suggestions for the next NEMW-CF:
The AEMC rule change report by the University of Wollongong, to critique the dispatch forecasting system. Action item 28.13.1
More information on the AGC system. Action item 28.13.2
Next Meeting Date
The next NEMW-CF meeting is scheduled for Wednesday 29 November 2017.
Coordinate a discussion regarding forecasting extreme weather days for the next NEMW-CF (Hear from retailers or generators)
Alex Driscoll/ Duncan MacKinnon
29 Nov 2017
ESOO Key Findings
Arrange for a presentation on last year’s ESOO numbers compared to actuals.
Post meeting note: The Electricity Statement of Opportunities (ESOO) evaluates and compares committed electricity supply information provided by industry with operational consumption and maximum demand forecasts, to identify potential unserved energy (USE) in excess of the reliability standard over a 10-year outlook period. AEMO performs this evaluation under a range of demand scenarios. The purpose of this study is to provide information to market participants to help them make informed decisions concerning investment potential in the National Electricity Market (NEM).
The ESOO does provide an analysis of the changes to the market since the previous year. Chapter 2 outlines changes to supply since the 2016 ESOO, while Chapter 3 outlines the changes to demand since the 2016 ESOO. Due to the volume of changes, the ESOO does not provide explicit comparison of the 2016 versus 2017 reliability outcomes.
Alex Driscoll (AEMO)
29 Nov 2017
Arrange an additional session at the end of the next NEMW-CF regarding Causer Pays.
Chris Muffett (AEMO)
29 Nov 2017
Confirm the ratio of capacity from short and long notice RERT in Victoria.
Stephen Clark (AEMO)
29 Nov 2017
Advise whether weight was given to curtailment of residential over industrial and commercial loads, when considering demand response ARENA contracts.
Violette Mouchaileh (AEMO)
29 Nov 2017
Market and System Update
Confirm the timings and outcomes of the review on the minimum of 35MW Regulation FCAS enablement in SA.
Post meeting note: There was a paper sent to the TARC indicating the completion date for these will be January 2018.
Tjaart Van Der Walt (AEMO)
29 Nov 2017
Market and System Update
Confirm whether AEMO is planning to release an updated version of the FCAS compliance report.
Post meeting note: Last updated in August 2017 and can be found here: http://www.aemo.com.au/Electricity/National-Electricity-Market-NEM/Security-and-reliability/Ancillary-services/Frequency-and-time-error-monitoring
Jonathan Jorgensen (AEMO)
29 Nov 2017
Market and System Update
Confirm whether the high contingency prices are global or whether they are local to a couple of areas.
To be provided during agenda item – Market System Update
29 Nov 2017
Market and System Update
Look into the percentage of FCAS over the entire NEM settlement and whether that has increased.
Ken Harper (AEMO)
29 Nov 2017
Look into whether anyone can present at a future meeting on AEMO’s response to the AEMC rule change report by the University of Wollongong, to critique the dispatch forecasting system.
29 Nov 2017
Arrange for the AGC system to be discussed at a future NEMW-CF.
29 Nov 2017
Items raised at previous meetings
Clarify why SA does not support Victoria, and whether the modelling could be overstating the number of days Victoria could be subject to limitations.
Mark Stedwell (AEMO)
Have a discussion with Chris Murphy and separately look into how to better engage distributors in this forum.
Mark Stedwell (AEMO)
Ancillary Services Unbundling
Discuss dispatch load data for generation units and share any actions/outcomes with the NEMW-CF.