The estimate of one hour was understood by Mr Van Der Walt to mean an hour from directing to synchronising, after which a further period of time would be required to reach the desired generation level and PPPL's evidence confirms this.
(h) at 18:03, AEMO issued a direction to Electra Net, requiring it to shed 100 MW of electrical load (Participant Notice 57283). At Tab 15 of Exhibit TNV-01 is an extract from the AEMO Control Room Log.
(i) at 18:11, AEMO declared an actual LOR3 condition in the South Australia region from 18:03, forecast to exist until 19:30 (Market Notice 57282). The Notice stated 'AEMO considers that Customer load is actually being interrupted in order to maintain or restore the security of the power system in South Australia Region. … The maximum load is being interrupted is 100 MW at 1803 hrs Wednesday, 8 February 2017.'
(i1) at 18:20, there was a telephone call between the AEMO Senior Manager and an AEMO Shift Manager, in which the Senior Manager said that the Pelican Point PS had a "one hour call up time", and they both agreed that it would be "too late for them". At some time prior to this conversation Mr Van Der Walt was likely told this by another AEMO employee.
(j) at 19:08, AEMO issued a notice that the actual LOR3 condition was cancelled at 19:00 (Market Notice 57284 ).
(k) at 19:21, Engie called AEMO for an update.
(l) at 20:01, AEMO issued a notice that an actual LOR2 condition had been declared for the South Australia region from 19:00 on 8 February 2017, forecast to exist until 20:00 (Market Notice 57286).
(m) at 20:10, AEMO called Engie to make further queries regarding the availability of GT12.
(n) at 20:18, AEMO issued a notice that an actual LOR1 condition had been declared for the South Australia region from 20:00 to 21:00 (Market Notice 57287).
(o) at 21:21, AEMO issued a notice that the actual LOR1 condition was cancelled from 21:00 (Market Notice 57289).
(p) at 21:34, AEMO declared a forecast LOR2 condition for the South Australia region on 9 February 2017 from 17:00 to 18:30, and stated that it was 'seeking a market response' (Market Notice 57290).
(q) at 21:40, AEMO declared a forecast LOR1 condition for the South Australia region on 9 February 2017 from 15:30 to 17:00 and from 18:30 to 19:30 (Market Notice 57291).
(r) at 22:25 and again at 23:47, AEMO called Engie with further queries about the availability of GT12.
(s) at 23:55, Engie called AEMO with further information regarding the availability of GT12.
159 As I have said, the AER relied heavily on the evidence of Mr Van Der Walt who gave evidence at the trial as to liability (PPPL No 1 at [210]-[236]) and the hearing as to penalty. PPPL made it clear that it did not challenge Mr Van Der Walt's credit.
160 In his evidence-in-chief at the hearing as to penalty, which was given by way of affidavit, Mr Van Der Walt referred to a number of paragraphs in his first affidavit which was read at the trial as to liability. After doing that, Mr Van Der Walt deposed to AEMO's usual practice as at 8 February 2017 when lack of reserve conditions are declared, the relevant events that occurred on 8 February 2017 and AEMO's current practice when lack of reserve conditions are declared.
161 Before describing the detail of Mr Van Der Walt's evidence, it is necessary to set out the rule which defined the various lack of reserve conditions as at 8 February 2017. Clause 4.8.4 provided as follows:
4.8.4 Declaration of conditions
AEMO may declare the following conditions in relation to a period of time, either present or future:
(a) Low reserve condition - when AEMO considers that the balance of generation capacity and demand for the period being assessed does not meet the reliability standard as assessed in accordance with the reliability standard implementation guidelines.
(b) Lack of reserve level 1 (LOR1) - when AEMO considers that there is insufficient capacity reserves available in an operational forecasting timeframe to provide complete replacement of the contingency capacity reserve on the occurrence of the credible contingency event which has the potential for the most significant impact on the power system for the period nominated. This would generally be the instantaneous loss of the largest generating unit on the power system. Alternatively, it might be the loss of any interconnection under abnormal conditions.
(c) Lack of reserve level 2 (LOR2) - when AEMO considers that the occurrence of the credible contingency event which has the potential for the most significant impact on the power system is likely to require involuntary load shedding. This would generally be the instantaneous loss of the largest generating unit on the power system. Alternatively, it might be the loss of any interconnection under abnormal conditions.
(d) Lack of reserve level 3 (LOR3) - when AEMO considers that Customer load (other than ancillary services or contracted interruptible loads) would be, or is actually being, interrupted automatically or manually in order to maintain or restore the security of the power system.
162 Mr Van Der Walt said that when AEMO declares a forecast or actual LOR1 condition indicating that reserve capacity is low for a given time interval, its practice was, and is, to continually assess how close that situation is to becoming an LOR2 or LOR3 condition and the options that may be available to AEMO to make an intervention in the market in the event that an LOR2 or LOR3 condition is declared. He said that during an LOR1 condition which AEMO considers has the danger of becoming an LOR2 or LOR3, AEMO's practice was and is to consider the availability and cost of all of the intervention options which may be available in order to determine how it may be best able to intervene if an LOR 2 or LOR3 is declared. He said that the processes he describes are conducted continually and simultaneously with new information continually incorporated into AEMO's analysis of intervention options. AEMO's assessment and declaration of lack of reserve conditions are based on the "available capacity" inputs that Scheduled Generators notify through their ST PASA inputs, that is, the MW capacity that they intend to bid as available for dispatch.
163 AEMO's practice was, and is, in considering whether there is any additional capacity available on a generating unit to assess, based on the difference between the "PASA availability" and the "available capacity" submitted by each Scheduled Generator, how much additional generation capacity each Scheduled Generator may be capable of providing in response to a direction. Based on that information, AEMO's practice prior to and on 8 February 2017 was then to contact each Scheduled Generator whose PASA availability was greater than its available capacity, usually by telephone, and ask about the following matters: (1) whether it could make the additional generating capacity available by the time of the forecast lack of reserve, particularly if the shortfall is due to occur in less than 24 hours' time; (2) how far in advance the Scheduled Generator would require a direction to be given in order for it to be able to make that additional capacity available in time to meet the shortfall; (3) what MW quantity of additional generation the Scheduled Generator expects to be able to provide and for how long; and (4) the expected costs of responding to a direction.
164 Mr Van Der Walt said that AEMO is continually assessing events and based on information received from Scheduled Generators it identifies the latest time at which it would need to intervene for each relevant generating unit in order to maximise its ability to issue an effective direction to that Scheduled Generator and to evaluate whether a direction to that Scheduled Generator is a suitable market intervention or if another option or options may be required, either separately from or together with a direction. If AEMO was considering whether to make a direction or take other action, its practice was, and is, to take into account whether additional reserves by way of RERT (Reliability and Emergency Reserve Trader) capacity may be available from participants under the RERT scheme and any other known constraints on the relevant generating unit, such as ramp times, fuel limitations and minimum run-times and safety, equipment and legal (e.g., environmental restrictions) considerations. As at 8 February 2017, the NER required AEMO to use RERT capacity (if available) before issuing a direction under cl 4.8.9.
165 If an LOR2 or LOR3 condition was declared, then depending on an assessment of the factors previously identified, AEMO's usual practice was, and is, to consider whether any RERT capacity was available and if a direction was required. If AEMO decided that one or more directions were required, then its usual practice was to issue the direction(s) to scheduled generating units that it had identified as having capacity available for direction to provide additional supply. When doing so, AEMO's practice was generally to issue first a direction to the scheduled generating unit which required the longest lead time before making that capacity available.
166 Mr Van Der Walt said that even if AEMO did not expect that it would be able to dispatch or activate RERT capacity and issue directions to make sufficient capacity available in time to avert potential load shedding, nevertheless its practice was, and is, generally to dispatch, activate and direct all potentially available capacity to be brought online. He said that even if the risk of load shedding could not be avoided entirely, then such additional capacity as AEMO is able to procure may nevertheless reduce the length and/or depth of any LOR3 condition and thereby reduce the duration of, and/or the number of customers affected by, any load shedding.
167 Mr Van Der Walt said that in the case of AEMO declaring an actual or forecast LOR1 condition before a day of forecast very high temperatures, AEMO may take a number of actions, including the following: (a) issuing a high temperature Market Notice to request generators to review their plant capacities in line with the forecast temperatures; (b) reviewing demand forecasts; (c) assessing, similar to the processes previously described, whether there would be any additional capacity available on the day in question based on the difference between the "PASA availability" and the "available capacity" submitted by each generator; and (d) making inquiries with the generators who had surplus PASA availability as to when that capacity could be made available.
168 Mr Van Der Walt then turned to the events on 8 February 2017. The chronology is set out above.
169 Mr Van Der Walt said that after AEMO had at 15:18 declared a forecast LOR1 condition for the South Australia region on 8 February 2017 from 16:30 to 19:00, and given all of the factors, including generation availability, the forecast temperatures and demand forecast on that day, AEMO's usual practice as set out in his affidavit would have been to consider what options were available to intervene in the market if required to procure additional reserve capacity. However, the problem on 8 February 2017 was that there was no RERT capacity available and furthermore, AEMO was not aware of any surplus PASA availability more generally. AEMO did not contact any generators to inquire about their additional capacity, either on 7 February 2017 ahead of the high temperatures on 8 February 2017 more generally, or immediately after 15:18 on 8 February 2017 when it forecast LOR1 conditions from 16:30 onwards. Mr Van Der Walt said that this was his recollection which he has also confirmed by reviewing AEMO's operator logs and its subsequent reports on the events of 8 February 2017.
170 Mr Van Der Walt expanded on the telephone conversation between the AEMO control room and ENGIE at 15:54 where ENGIE advised AEMO that the generating units at Port Lincoln had been bid out until further notice. Mr Van Der Walt notes that by the time of this telephone conversation at 15:54, AEMO had declared a forecast LOR1 condition at 15:18 for the period 16:30 to 19:00 and that it was approximately one and three quarter hours before AEMO called ENGIE at 17:39 to first inquire whether any generating capacity could be made available from GT12 and more than two hours before AEMO was first advised by ENGIE at 18:00 that GT12 was available to be brought online and could be brought online within one hour.
171 Mr Van Der Walt said that the Pelican Point PS was the second largest power station in South Australia. Mr Van Der Walt expressed the view in his evidence that based on AEMO's usual practice and his experience of managing real time operations of the National Electricity Market in lack of reserve conditions, had AEMO known by 3 February 2017 that PPPL had a PASA availability of 320 MW for 8 February 2017, which had not been offered as "available capacity", it is likely that AEMO would also have been prompted to make inquires with ENGIE about making that capacity available, including further or more detailed inquires if they were necessary, shortly after 15:18 when it first declared forecast LOR1 conditions on 8 February 2017. Mr Van Der Walt goes on to say that had AEMO known from 3 February 2017 that PPPL had PASA availability of 320 MW for 8 February 2017, he does not know whether that would have reduced, by duration or amount, the load shedding that in fact occurred between 18:00 and 19:00 that evening. He states that he would only be speculating about that matter because, in part at least, of the dynamic nature of power system events, generating unit performance, power system conditions, and demand variability, and his expectation that ENGIE's own assessment of the time required to obtain sufficient gas or gas transport to bring GT12 into service would also likely have been "somewhat fluid" having regard to the market conditions on that day. In that regard, he notes that when AEMO made its first inquiry of ENGIE at 17:39, the ENGIE staff member initially advised that a minimum run-up time of four hours might be required, if gas could be sourced. However, Mr Van Der Walt states that AEMO could have made inquiries with ENGIE in accordance with its usual practices as described above as to the potential availability of GT12 on 8 February 2017 at an earlier time than its telephone call at 17:39 on that day. These matters are the critical matters in Mr Van Der Walt's evidence in terms of the submission made by the AER.
172 Mr Van Der Walt gave evidence that at the time of his telephone conversation with the acting shift manager on 8 February 2017, that is, 15:58:36, had he known that there was additional PASA availability at the Pelican Point PS, he would have told the acting shift manager to call PPPL and find out "what their latest time to intervene is, and what that is, is how much time do they need for us to notify them that they can give us that additional generation".
173 Mr Van Der Walt also gave evidence of AEMO's current practices where a lack of reserve condition is forecast or declared. He said that AEMO now calculates a forecast uncertainty measure which translates a probability of forecast error into a MW value. This forecast uncertainty measure can result in earlier LOR2 declarations and enable AEMO to utilise intervention options earlier to manage those conditions. Furthermore, as a result of the load shedding in February 2017, it is now AEMO's practice to contact all Scheduled Generators in the affected region in order to ascertain whether there is additional generation capacity which can be made available under a direction, rather than contacting only Scheduled Generators which have reported a PASA availability which exceeds their reported or commercially available maximum availability. The revised practice involves additional time and attention by the AEMO control room staff at periods of critical and intense activity for the AEMO control room and may cause delays in AEMO responding to conditions on the power system.
174 The NER no longer require the use of RERT capacity prior to the making of a direction. Mr Van Der Walt's experience is that providing additional reserve capacity through the RERT scheme was typically more expensive for AEMO than issuing a direction. The relative cost is affected by the terms of the reserve contracts with RERT providers and by terms that require AEMO to procure RERT capacity in specified MW quantities or for specified durations that may exceed the quantities and durations needed to respond to a given potential reserve shortfall. In order to minimise costs for consumers in accordance with cl 3.8.14, if AEMO can issue a direction to make additional generating capacity available at short notice, its practice is generally to do so in priority to accessing RERT capacity. This then is the evidence of Mr Van Der Walt.
175 PPPL adduced further evidence from Mr Baksi about the likelihood of PPPL being able to provide additional generating capacity had it been contacted by AEMO earlier than it was contacted. His evidence was directed to the steps and the timing associated with those steps in preparing the Pelican Point PS to make 320 MW available for a period of four hours on the afternoon of 8 February 2017 at a time when PPPL was actually dispatching approximately 214 MW.
176 Mr Baksi's evidence at the trial as to liability is described in the reasons in PPPL No 1 (at [358]-[383]). Mr Baksi reiterated certain matters in his evidence at the hearing as to penalty. He went on to say that on 8 February 2017, GT12 was only able to be returned from wet storage to operation in less than four hours by reason of it having been run on 7 February 2017 for the purpose of wet preservation. This is because the particularly time-intensive activities associated with achieving the required water quality that can take up to four hours had been undertaken prior to the operation of GT12 on 7 February 2017 and did not need to be repeated in order for GT12 to be operated on 8 February 2017. Mr Baksi said that as GT12 commenced operating at 6:34 hours on 7 February 2017, he can recall that the operations team had commenced preparing GT12 for that run at about midnight. That came about because the operations team ordinarily commenced pre-start checks well in advance of the relevant turbine operating time so they have sufficient time to deal with any issues that arise during that procedure.
177 Mr Baksi described the steps which PPPL would have been required to undertake had he received a direction from the PPPL trading room (for example, in response to a direction from AEMO) to return GT12 from wet storage so that the Pelican Point PS could operate at 320 MW. He described the four steps as staffing, pre-start checks, start-up and generation, and he estimated a time for the completion of those steps as a minimum of 35 minutes for staffing, at least 45 minutes for pre-start checks, at least 25 minutes and as long as 45 minutes for start-up, and between 15 minutes and 45 minutes for generation. He explains the basis for these estimates in his evidence. The minimum time to carry out those steps is two hours.
178 Mr Baksi summarised his evidence as follows. Had PPPL received a direction at 5:13 pm on 8 February 2017 to make available 320 MW for a period of four hours, having regard to the matters set out in his affidavit, his opinion is that the earliest that PPPL could have made that generation capacity available by bringing GT12 from wet storage to operation and up to that dispatch target would have been by 7:13 pm.
179 The AER contended that in cross-examination, Mr Baksi accepted that the time required between the direction given by AEMO on 9 February 2017 and the Pelican Point PS reaching 320 MW output was approximately 71 minutes.
180 PPPL submitted that other evidence of events on 8 February 2017 and 9 February 2017 is relevant to what may have occurred on 8 February 2017 had PPPL made correct PASA submissions. That evidence was not in dispute and I turn to describe it.
181 A number of reports were prepared which address the events on 8 February 2017 and 9 February 2017 and the causes of those events.
182 AEMO prepared and published a report on 15 February 2017 titled "System Event Report. South Australia, 8 February 2017". This report was prepared in accordance with cl 4.8.15(c) of the NER. The report makes it clear that the analysis and conclusion are preliminary in nature.
183 AEMO also prepared a report which was published in July 2017 and which is titled "NEM Event - Direction to South Australia Generator - 9 February 2017". This report was prepared in accordance with cl 3.13.6A(a) of the NER using information available as at 30 June 2017.
184 The AER prepared a report which was published on 27 April 2017 titled "Electricity Spot Prices above $5000/MWh South Australia 8 February 2017".
185 Each of these reports addresses to a greater or lesser extent, the events on 8 February 2017 and the possible causes for those events, including the load shedding which took place at approximately 6:00 pm. Mr Van Der Walt was asked about these reports in cross-examination.
186 The AER submits that the reports and the evidence in relation to them is beside the point because it is not alleging that PPPL's contraventions were such that had they not occurred, the load shedding which occurred on 8 February 2017 would have been avoided, or would have been reduced in duration.
187 The AER report indicates that the temperature was very high on 8 February 2017, the forecast demand was considerably lower than the demand in fact and the forecast of the contribution from wind generation was higher than in fact occurred. The AER report contains the following statement:
Around 6 pm, without other alternatives, AEMO issued a direction to the South Australia transmission network service provider (ElectraNet) to shed 100 MW of load. ElectraNet in turn instructed the distribution network service provider SA Power Networks (SAPN), to shed 100 MW of customer load, based on established load shedding priorities. SAPN inadvertently shed around 300 MW of customer load for about 40 minutes as a result of an error in its load shedding systems. …
188 AEMO's report dated 15 February 2017 states, with respect to conditions in South Australia on 8 February 2017, that demand and supply from renewable and thermal generation were changing rapidly in the period just prior to the loss of system security and that at the peak, demand was higher than forecast, wind generation was lower than forecast and thermal generation capacity was reduced due to forced outages. The report also contains a summary of the sequence of events. Mr Van Der Walt agreed that events on the afternoon of 8 February 2017 unfolded "quite rapidly and unexpectedly". The pre-dispatch PASA calculations did not indicate the prospect of the LOR2 in a way that perhaps was unexpected. A forecast LOR3 condition was not issued. Mr Van Der Walt agreed that the AEMO report dated 15 February 2017 states that in terms of South Australia demand forecasting, AEMO uses an equal weighted average of hourly weather forecasts provided by WeatherZone and Telvent based on measurements taken at Bureau of Meteorology weather stations at the Adelaide Airport and Adelaide. Mr Van Der Walt agreed that the actual temperature during 8 February 2017 was materially above that which had been forecast and that that would impact on demand. Mr Van Der Walt agreed that the instruction to shed load that was given related to 100 MW, but 300 MW was shed due to a software error in the SA Power Network's system. One other matter noted in the AEMO report dated 15 February 2017 is the statement that from 16:00 hours onwards, actual wind generation declined more rapidly than forecast as a result of a sharp drop in wind speed between 16:00 hours and 18:00 hours. The forecast issued at 14:00 hours was for about 175 MW of wind generation for the trading interval ending 18:30 hours. The forecast issued at 16:00 hours was for about 200 MW of wind generation for the same trading interval. At 18:00 hours, the actual wind generation was about 100 MW and falling. In addition to these matters, there were a number of forced outages, including an outage at Port Lincoln at 16:07 and an outage of Quarantine 4 at 17:18.
189 The AEMO report published in July 2017 states that the pre-dispatched PASA runs from 23:30 on 8 February 2017 until the direction at 15:05 hours on 9 February 2017 forecast LOR2 conditions in South Australia between 17:00 and 18:30 hours on 9 February 2017. This was in circumstances in which the temperature in Adelaide on 9 February 2017 reached a peak of 39.4oC at 17:00 hours. The report refers to the processes undertaken by AEMO to issue a direction.
190 Mr Van Der Walt accepted that the following conclusions in the report were accurate:
AEMO has reviewed the Direction issued to ENGIE in relation to GT12 of Pelican Point power station on 9 February 2017 and the circumstances surrounding this Direction, as set out in this report.
AEMO assessed its compliance with the applicable procedures and processes for determining to issue the Direction, notification, and the application of intervention pricing, and is satisfied these requirements were met.
191 As I understand it, PPPL does not contend that Mr Van Der Walt does not hold the belief that had PPPL made the correct PASA submissions, then it is likely AEMO would have contacted PPPL shortly after 15:18 to inquire about PPPL making the additional generating capacity available. PPPL does contend that there is a strong body of evidence that means that Mr Van Der Walt's evidence as to what was likely, or indeed a reasonable possibility, should be rejected. It is important to bear in mind that AER's particulars are that an inquiry by AEMO of PPPL would have been followed by a direction by AEMO to PPPL to bring at least 85 MW of additional generating capacity into service.
192 PPPL submitted that Mr Van Der Walt's evidence about AEMO's practice after it declares a forecast or actual LOR1 condition of considering the availability and cost of all of the intervention options which may be available in order to determine how it may be best able to intervene if an LOR2 or LOR3 condition is declared is premised on AEMO forming the view that there is a danger of an LOR1 condition becoming an LOR2 or LOR3 condition and that there is no evidence that AEMO formed that opinion shortly after 15:18. In fact, whilst a forecast LOR1 condition was declared at 15:18, an actual LOR condition was not declared by AEMO until 16:13.
193 There was no declaration by AEMO of a forecast LOR2 condition on 8 February 2017. An actual LOR2 condition was declared by AEMO at 17:13 and the provisions of cl 4.8.9 of the NER are such that the power to issue a direction only arose on the declaration of an LOR2 or LOR3 condition. Even then when AEMO declared an LOR2 condition, AEMO's Market Notice indicated that it was seeking a market response and did not intend to intervene through "a AEMO intervention event". It follows that even at 17:13, AEMO was not foreshadowing intervention and, according to PPPL, "was content to let the market provide a response". A curiosity in the evidence not explained is that Mr Van Der Walt said that AEMO was not aware of any surplus PASA availability more generally and yet it issued a Market Notice at 17:13 saying that it was looking at a market response.
194 AEMO did not declare a forecast LOR3 condition on 8 February 2017. It declared an actual LOR3 condition at 18:11 and that condition was effectively cancelled at 19:00. The evidence establishes that at 18:30, AEMO directed ElectraNet to restore all load as by that time, spare capacity was available on generating units in South Australia and on the Heywood interconnector. PPPL could not have brought GT12 online so as to avoid or reduce the load shedding had it been directed to do so at 18:11 in circumstances in which there was less than one hour between the LOR3 condition being declared and cancelled and 19 minutes between the declaration by AEMO of the LOR3 condition and AEMO's direction to ElectraNet to restore all load.
195 PPPL also emphasised that the conditions on 8 February 2017 were not stable and the only question is whether AEMO would have made a telephone call earlier than it did. Conditions were changing rapidly. The reports previously referred to indicate that demand and the temperature were higher than forecast and supply was expectedly limited by the bidding out of the generating units at Port Lincoln and Quarantine 4, the electricity flow across the Murraylink interconnector increasing above its limit and that there was a sharp drop in wind speed affecting wind generation significantly. As Mr Van Der Walt agreed, circumstances were changing during the afternoon of 8 February 2017 "quite rapidly and unexpectedly". He also agreed that events on the day were "complex". The factors I have identified in this paragraph seem to be the reasons for the load shedding on 8 February 2017.
196 PPPL also points out that although Mr Van Der Walt said that there was a practice by AEMO of considering whether there were reserves available under the RERT scheme of which PPPL was a part, there is no evidence of AEMO taking any steps to contact any members of the RERT panel. As I have said, the NER at the time required AEMO to use available RERT capacity before issuing a direction under cl 4.8.9.
197 PPPL also points to AEMO's knowledge of a second gas turbine at the Pelican Point PS.
198 Mr Van Der Walt was the "Final Approver" of a Reserve Management Guide dated 6 January 2017 which contained the following:
10.3.2 Dynamic LOR for South Australia region
NEM RTO and Operations Planning decided to enable dynamic LOR in South Australia region for the following reasons:
• Pelican Point has offered a MTPASA availability to a of maximum 237 MW. This equates to 1 GT + ½ ST. However, AEMO's Generation Information website indicates that Pelican Point unit 2 can be available on a 48 hour recall.
° Actual credible contingency when Pelican Point bids 480 MW is only 240 MW (1 GT + ½ ST)
° The maximum error in LOR1 would be 40 MW (assuming that any 200 MW TIPS is in service).
199 In view of the AER's argument, it is not clear to me that knowledge that GT12 was available on a 48 hour recall advances PPPL's response to the argument.
200 Furthermore, just before PPPL was contacted by AEMO at 17:39 on 8 February 2017, the following conversation took place between an AEMO group manager and an AEMO operator, neither of whom were identified or called as witnesses:
[AEMO group manager]: Yeah, and Pelican Unit 2.
[AEMO operator]: Pelican Unit 2, that's the reserve one, isn't it?
[AEMO group manager]: Yeah, it's not available? Have we spoken with ENGIE?
[AEMO operator]: No, we haven't spoken to them. Isn't there a, isn't that a reserve thing we've got to notify them?
[AEMO group manager]: Well, I'd just ring them, see if it's available for the market.
[AEMO operator]: Yeah, yeah. No, we'll do that. [redacted] was talking to - or [redacted] was talking to them earlier about something but yes. And there's a Quarantine, one of the GTs, 20 megawatt GTs came on and then failed, so it's off at the moment too.
[AEMO group manager]: Okay, yeah.
[AEMO operator]: But we'll talk to Pelican.
[AEMO group manager]: Yeah, just check with ENGIE whether or not that's available. You know, it might - it's probably not going to save you before 1900 when your LOR 2 runs to anyhow. My concern is your solar starts to run off and we don't get any load reduction.
201 An employee of AEMO contacted ENGIE at 17:39 to inquire about the availability of GT12 at the Pelican Point PS. No evidence was adduced by AEMO about his or her knowledge of the availability of GT12. It is submitted by PPPL that, in the circumstances, it should be inferred that AEMO was aware of the fact that GT12 was out of dry storage and capable of being run subject to sufficient gas and gas transport being available. The argument is that AEMO are not able to negate the evidence that it was aware on 8 February 2017 that GT12 was in wet storage and available on 48 hours' recall and yet did not contact PPPL until 17:39 and that makes it implausible that it would have contacted PPPL approximately two hours earlier had PPPL made correct PASA submissions.
202 With respect to Mr Van Der Walt's evidence that if AEMO declares actual or forecast LOR1 before a day of forecast very high temperatures, AEMO may, inter alia, make inquiries with the generators who had surplus PASA availability, as to when that capacity could be made available, it should be noted, as PPPL pointed out, that AEMO did not declare an actual or forecast LOR1 before 8 February 2017.
203 I have considered the evidence carefully. In light of the fast moving and complex events of the day and the other matters to which I have referred to, I am not satisfied on the balance of probabilities that AEMO would have contacted ENGIE shortly after 15:18 on 8 February 2017 had it known by 3 February 2017 that PPPL had a PASA availability of 320 MW for 8 February 2017. It may well be that AEMO would have contacted PPPL earlier than it did at 17:39, but as I cannot on the evidence make a firm finding as to when this would have been done, I am not able to find that "the likelihood of load shedding would have been reduced" as alleged by the AER (see [151] above).
204 None of this is to deny that the obligation to make correct PASA submissions is an important obligation which is part of a regime intended to enable AEMO to manage power system security. That is a matter to be taken into account.
205 As I have said, the parties referred to various authorities and I turn now to consider those authorities.
206 In Australian Energy Regulator v AGL HP1 Pty Ltd [2022] FCA 737 (AER v AGL HP1), the issue was the relief to be granted with respect to contraventions of cl 4.4.3 and S5.2.2 of the NER by members of a partnership known as the AGL Hydro Partnership by operating generating units of the Hallett 1, 2, 4 and 5 wind farms and allowing those generating units to supply electricity to the power system when the settings for the repeat low voltage ride-through (LVRT) protection system applied to them had not been approved in writing by the network service provider or AEMO. I made a declaration, orders for the appointment of a compliance expert, orders for the payment of a pecuniary penalty of $1.16 million approximately in respect of the contravention of cl 4.4.3 of the NER and orders for the payment of costs. The matter proceeded by way of agreement in that the parties placed before the Court a Statement of Agreed Facts, a Further Statement of Agreed Facts and joint submissions. The relevant period in that case was from 6 August 2013 to 23 December 2016. The maximum civil penalty was an amount of $12.45 million. The parties agreed that by reason of the LVRT protection system settings not having been disclosed in the generator performance standards of any of the Hallett wind farms and not otherwise having been approved by ElectraNet and AEMO, AEMO's ability to maintain the secure operation of the power system during the relevant period was compromised (see at [25]). At the same time, I recorded in the reasons that certain allegations were no longer pursued by the AER and that included an allegation that the activation of the repeat LVRT protection system which caused the generating units at the Hallett 2, 4 and 5 wind farms to cease generating active power was a contributing cause of the black system event and blackout throughout the South Australian region of the National Electricity Market that occurred on 28 September 2016.
207 In Australian Energy Regulator v AGL Loy Yang Marketing Pty Ltd [2023] FCA 1299, Button J found contraventions of cl 4.9.8(a) of the NER in relation to 91,990 dispatch instructions given by AEMO during the period 23 December 2019 to 22 May 2020 because AGL Loy Yang Marketing Pty Ltd did not operate its equipment to ensure that it could provide contingency Frequency Control Ancillary Services (FCAS) which complied with the dispatch instructions received from AEMO and so did not comply with the dispatch instructions as required by cl 4.9.8(a) of the NER. Her Honour also found that AGL Loy Yang Marketing Pty Ltd had contravened cl 4.9.8(d). Her Honour imposed a pecuniary penalty of $2.8 million. In the related proceeding involving AGL Macquarie Pty Ltd, there were 142,522 dispatch instructions during the period from 4 September 2018 to 25 August 2020 and a pecuniary penalty of $3.2 million was imposed. Her Honour referred to the difficulty of detecting the contravention (at [29] and [59]). The facts in that case were such that the contraventions had not caused any actual loss or damage to end users. However, as her Honour noted (at [88]):
… the contraventions did result in there being less contingency FCAS available to respond to any significant frequency deviations and so raised the risk that power system security would be compromised in the event of a frequency disturbance. This factor heightens the need for deterrence in respect of the respondents' conduct. It is, of course, vitally important that power generators in fact be able to provide the contingency to which they commit.
208 Her Honour found that the contraventions were the result of insufficient processes and practices and inadvertence (at [89]). It is relevant to note that her Honour considered that the size and financial position of the respondents were relevant both because the head company bore some responsibility for its subsidiary's conduct and because the group's financial position bore upon the subsidiary's ability to meet substantial pecuniary penalties and the level of penalty required to have a deterrent effect (at [92]).
209 The AER placed significant weight on this decision and there are some similarities in terms of knowledge of the contravention, the size and financial position of the contravenor and difficulty of detection. However, there are some important differences, including the relatively short period over which the contraventions extended, the fact that the number of changes to previous submissions was relatively small and despite the number of entries, the finding was that GT12 could have been operated for approximately four hours.
210 In Australian Energy Regulator v Hornsdale Power Reserve Pty Ltd [2022] FCA 738 (AER v Hornsdale) (a decision handed down on the same day as AER v AGL HP1), I made declarations of contraventions of cll 3.8.7A(1), 4.9.8(a), 4.9.8(d) of the NER during the period from 23 July 2019 to 14 November 2019. The declaration concerned 690 market ancillary service offers to AEMO, 185,738 dispatch instructions given by AEMO and 32,602 trading intervals. I imposed a penalty of $900,000. The parties agreed to a resolution of the proceeding and the matter proceeded by reference to a Statement of Agreed Facts and joint submissions. I referred to FCAS and, in particular, contingency FCAS and the fact that because they were generally (but not only) used when a contingency event occurred which triggered a significant frequency deviation, this made it difficult to detect when a FCAS provider was not complying with its offers or dispatch instructions (see also [78]). One of the matters said to be important in terms of the seriousness and significance of the contraventions was the importance of FCAS to power system security and the harm that could potentially flow to end users of electricity if power system security is compromised.
211 In Australian Energy Regulator v HWF 1 Pty Ltd [2021] FCA 732 (AGL v HWF1), White J made declarations of contraventions of r 4.4.3 and cl S5.2.2 of the NER between 2 June 2016 and 10 October 2016 by operating the generating units of the Hornsdale Wind Farm and allowing those generating units to supply electricity to the power system when the settings for the Repeat LVRT Protection System applied to them had not been approved in writing by the network service provider or AEMO. His Honour made various orders, including an order that HWF 1 Pty Ltd (HWF1) pay a pecuniary penalty of $555,000. This matter proceeded by reference to a Statement of Agreed Facts, agreed minutes of order and joint submissions. His Honour noted in his reasons that the AER did not press allegations in its Amended Concise Statement that by ceasing to supply active power as a result of the activation of the Repeat LVRT Protection Systems, the generating units did not meet or exceed, and were not operated to comply with, the NER or relevant performance standards and the activation of the Repeat LVRT Protection Systems which caused the generating units to cease generating active power was a contributing cause of the widespread electricity blackout which occurred in South Australia on 28 September 2016 (at [21]).
212 His Honour did note, however, that the seriousness of HWF1's contraventions in applying non-approved settings was underlined by its potential consequences. In that context, his Honour said the following (at [70]):
… As noted earlier in these reasons, AEMO's ability to achieve and maintain security in the power system depended, amongst other things, on Generators such as HWF1 providing, both at the time of the connection and subsequently, accurate and complete information concerning their ability to operate in accordance with the agreed performance standards. The rigorous regime summarised earlier and in particular cl S5.2.2, is directed, amongst other things, to the achievement and maintenance of power system security, this being an important public purpose. HWF1's use of non-approved settings in the present case compromised AEMO's ability to discharge its responsibility because it meant that it was making important decisions concerning the secure operating limits of the power system on the basis of incomplete information. As the events of 28 September 2016 indicate, a compromise of the security of the power system can have extensive and serious consequences.
His Honour also said that he regarded the contravention as serious because it had the potential to result in drastic consequences, even if those consequences were not realised on 28 September 2016.
213 The decision in Australian Energy Regulator v Pacific Hydro Clements Gap Pty Ltd [2021] FCA 733 (AER v Pacific Hydro) was delivered by White J on the same day. It involved the same contraventions, albeit over a longer period of time between 6 August 2013 and 3 October 2016. His Honour imposed a pecuniary penalty of $1.1 million. Again, the matter proceeded by way of a Statement of Agreed Facts, agreed minutes of order and joint submissions. Again, the AER in that case did not press allegations of a similar nature to those made in AER v HWF1 (see [23]) and his Honour made similar comments about the seriousness of the contraventions (at [74]).
214 The decision in Australian Energy Regulator v Snowtown Wind Farm Stage 2 Pty Ltd [2020] FCA 1845 was delivered approximately six months before the respective decisions in AER v HWF1 and AER v Pacific Hydro. It involved a similar contravention over a period between 10 September 2013 and 10 October 2016. The contravention was admitted and White J imposed a pecuniary penalty of $1 million. There was no admission that the contravention caused the blackout on 28 September 2016 (see at [41]). Justice White considered that the contravention was serious because AEMO's ability to achieve security in the power system depended upon, among other things, generators such as SWF2 providing, both at the time of connection and subsequently, accurate and complete information concerning their ability to operate in accordance with the agreed performance standards. SWF2's use of non-approved settings in that case comprised AEMO's ability to discharge its responsibility. His Honour said that the events of 28 September 2016 indicate that a comprise of the security of the power system can have extensive and serious consequences.
215 These cases provide some general guidance as to the appropriate penalty. However, that is as far as it goes because the facts in this case are different from the facts in the cases to which I have referred.