FEDERAL COURT OF AUSTRALIA

Australian Energy Regulator v Pelican Point Power Ltd (No 3) [2024] FCA 277

ORDERS

THE COURT DECLARES THAT:

1.    By each of its four short term PASA submissions made between 6 February 2017 at 11:00 and 7 February 2017 at 11:25 identified below for each of the future trading intervals during the 8 February 2017 trading day identified below, the respondent contravened cl 3.7.3(e)(2) of the National Electricity Rules (NER) by submitting short term PASA availability values of 220 MW that did not represent its current intentions and best estimates as to the physical plant capability of the Pelican Point Power Station that could be made available on 24 hours’ notice which was 320 MW.

2.    The respondent contravened cl 3.13.2(h) of the NER by failing to notify the Australian Energy Market Operator (AEMO) promptly on or after 3 February 2017 that the medium term PASA availability of the Pelican Point Power Station for 8 February 2017 which the respondent previously submitted to AEMO on 27 January 2017 had increased from 224 MW to 320 MW.

THE COURT ORDERS THAT:

3.    With respect to the contraventions identified in the aforesaid declarations, Pelican Point Power Ltd pay a civil penalty of $900,000.

Note:    Entry of orders is dealt with in Rule 39.32 of the Federal Court Rules 2011.

REASONS FOR JUDGMENT

BESANKO J:

INTRODUCTION

1    The Australian Energy Regulator (AER) seeks declaratory orders under s 44AAG(1) of the Competition and Consumer Act 2010 (Cth) (the CCA) to the effect that Pelican Point Power Ltd (PPPL) is in breach of a State energy law as defined in s 4 of the CCA. A State energy law includes the National Electricity Law (NEL) which has been enacted in South Australia as a Schedule to the National Electricity (South Australia) Act 1996 (SA) (s 6) and the National Electricity Rules (NER) which have the force of law by reason of s 9 of the NEL. The rules in the NER alleged by the AER to have been breached by PPPL are cll 3.7.3(e)(2), 3.7.2(d)(1) and 3.13.2(h) and each of those rules was designated a civil penalty provision at the relevant time (the NEL s 2AA; the National Electricity (South Australia) Regulations, reg 6(1) and Schedule 1). In addition to the declaratory orders, the AER seeks the imposition of civil penalties in relation to the breaches.

2    At an early stage of the proceedings, the Court made an order that liability for the alleged contraventions be heard separately from, and in advance of, the relief to be granted should the contraventions be established.

3    The trial as to liability for the alleged contraventions took place and I delivered reasons for my conclusions with respect to those matters (Australian Energy Regulator v Pelican Point Power Ltd [2023] FCA 1110 (PPPL No 1)).

4    The AER succeeded in establishing some of the allegations it made, but it did not establish all of them. It then asked the Court to make declarations reflecting the conclusions in PPPL No 1 or to make further findings before the hearing as to the civil penalties to be imposed. I declined to make declarations or make further findings at that stage because I took the view that having regard to the terms of the particular legislation, the declarations made by the Court and the civil penalties imposed must be included in the one order (Australian Energy Regulator v Pelican Point Power Ltd (No 2) [2023] FCA 1381 (PPPL No 2)).

5    The matter was then listed for hearing as to the declaratory orders to be made and the civil penalties to be imposed. By then, the AER had provided proposed declarations which differed in a number of respects from the declarations it advanced at the trial as to liability for the alleged contraventions.

6    The hearing proceeded and both sides called evidence. In the case of the AER, the further evidence it called related primarily to the loss and damage it alleges was caused by the contraventions. In the case of PPPL, the further evidence it called related to that matter and the compliance programs it had in place.

7    There was a substantial dispute between the parties about the declarations which should be made. This dispute was as to which declarations should be made and their terms. That matter was also relevant to the Court’s findings as to the number of contraventions which have been established. The number of contraventions determines the maximum penalties which is ordinarily a matter to be considered in fixing the appropriate civil penalties.

8    The dispute as to the declarations to be made involved not only a dispute about whether a particular declaration reflected the findings made in PPPL No 1, but also an objection that two of the declarations sought by the AER were outside the parameters of the case it advanced at the trial as to liability for the alleged contraventions.

9    The structure of these reasons is that I will deal first with the declarations which should be made. That will include the identification of the number of contraventions which have been established. I will then move to the factors relevant to the fixing of the appropriate civil penalty. Both parties have proceeded on the basis that a single course of conduct is involved and one civil penalty is appropriate.

THE DECLARATORY RELIEF SOUGHT BY THE AER

10    It is convenient to begin with a comparison of the declarations sought at the trial as to liability for the alleged contraventions and the declarations now sought by the AER following the findings in PPPL No 1. The declarations sought by the AER at the trial as to liability were described in the reasons in PPPL No 1 (at [2]–[4]) as follows:

… First, the AER seeks a declaration that in relation to each of its 27 short term PASA submissions submitted on or after 30 January 2017 for each trading interval during the 8 February 2017 trading day (but not including any trading interval that had concluded when the submission was made), PPPL contravened cl 3.7.3(e)(2) of the NER by failing to submit its short term PASA availability so as to reflect the true physical plant capability of the Pelican Point Power Station (Pelican Point PS) that could be made available on 24 hours’ notice and further, or in the alternative, by failing to submit its short term PASA availability to reflect its current intentions and best estimates as to the physical plant capability of the Pelican Point PS that could be made available on 24 hours’ notice …

Secondly, the AER seeks a declaration that in relation to PPPL’s medium term PASA submissions for the day 8 February 2017, PPPL contravened cl 3.7.2(d)(1) of the NER in relation to each of its 10 medium term PASA submissions made after 11 November 2016, by failing to submit medium term PASA availability so as to reflect the physical plant capability of the Pelican Point PS that could be made available on 24 hours’ notice after the gas turbine known as GT12 was brought from dry to wet storage on 11 November 2016.

Thirdly, the AER seeks further, or in the alternative to the second declaration, a declaration that PPPL contravened cl 3.13.2(h) of the NER by failing to notify AEMO promptly on or after 11 November 2016 of the increased medium term PASA availability of the Pelican Point PS after GT12 was brought from dry to wet storage on 11 November 2016. On the AER’s case, that contravention continued for a period of in the order of 86 days.

11    The declarations which the AER now seeks following the findings in PPPL No 1 are as follows:

1    By each of its 24 short term PASA submissions made after 3 February 2017 for each future or current trading interval during the 8 February 2017 trading day, the Respondent contravened cl 3.7.3(e)(2) of the National Electricity Rules (NER) by submitting short term PASA availability of values between 216 megawatts (MW) and 235 MW that did not represent its current intentions and best estimates as to the physical plant capability of the Pelican Point Power Station that could be made available on 24 hours’ notice, which was at least 320 MW.

2    The Respondent contravened cl 3.13.2(h) of the NER, by failing to notify the Australian Energy Market Operator (AEMO) promptly on or after 3 February 2017:

(a)    that the short term PASA availability of the Pelican Point Power Station for each trading interval on the 8 February 2017 trading day, which the Respondent previously submitted to AEMO on 2 February 2017 at 9:11 am, had increased from 220 MW to at least 320 MW; and

(b)    that the medium term PASA availability of the Pelican Point Power Station for 8 February 2017, which the Respondent previously submitted to AEMO on 27 January 2017, had increased from 224 MW to at least 320 MW.27

12    There are three major changes in terms of the first declaration. In addition to the change to the number of ST PASA submissions identified (reduced from 27 to 24) and the change in date from 30 January 2017 to 3 February 2017, the conduct said to be the contravention or breach is cast in positive terms in that it has been changed from “failing to submit” to submitting ST PASA availability that “did not represent”, etc.

13    The AER’s case is that if the first declaration it now seeks is made, it means that PPPL has committed 722 contraventions of cl 3.7.3(e)(2) of the NER. There were 24 ST PASA submissions made after 3 February 2017 with the first being made on 6 February 2017 at 11:00 and the last being made on 8 February 2017 at 20:51. Each submission addressed PASA availability (in addition to other matters) for a trading interval of 30 minutes with 48 trading intervals across a day commencing at 4:00 am. The AER prepared a table showing the number of contraventions it alleges and it is as follows:

14    The number of trading intervals progressively reduces after the commencement of the 8 February 2017 day because the AER accepts that there cannot be a contravention with respect to past trading intervals. For example, the number of alleged contraventions for the PASA submission made at 6:58 on 8 February 2017 is 43 because at the time of the submission, five 30-minute trading intervals had been completed.

15    Each contravention of the relevant Rules carries a maximum penalty of $100,000.

16    PPPL made a number of submissions challenging the terms of the first declaration, but did not submit that the subject matter of the declaration was not within the parameters of the case the AER advanced at trial as to liability. PPPL’s case is that the declaration does not accurately reflect the findings set out in PPPL No 1.

17    In the case of the other two declarations now sought by the AER, it relied on cl 3.13.2(h) which provides that a Scheduled Generator must notify the Australian Energy Market Operator (AEMO) of, and AEMO must publish, any changes to submitted information within the times prescribed in the timetable. The timetable at the relevant time is set out below (at [69]). It contained a provision as to “Frequency” for ST PASA and MT PASA submissions as follows: “As frequently as changes occur”.

18    No equivalent of the declaration in para 2(a) was sought at the trial as to liability. In other words, there was no claim of a contravention of cl 3.13.2(h) in relation to ST PASA submissions. The declaration now sought in para 2(b) bears some similarity to the third declaration sought at the trial as to liability in that it refers to MT PASA submissions and the contravention of cl 3.13.2(h), but the particulars of the contravention are quite different and in that sense, no equivalent of the declaration in para 2(b) was advanced by the AER at the trial as to liability.

19    The AER’s case is that the declaration in para 2(a) involves PPPL having committed 48 contraventions of cl 3.13.2(h) in relation to ST PASA submissions and that the maximum penalty for each contravention is $150,000 being $100,000 for each of the 48 contraventions and a penalty of $10,000 per day for each day the contravention continued. The explanation for this allegation is as follows. The obligation breached by PPPL was an obligation to notify AEMO on 3 February 2017 of changes to submitted information with respect to 48 trading intervals on 8 February 2017 which were continuing breaches (s 66 of the NEL) which carried a maximum penalty, in the case of a body corporate, of $10,000 for each of the five days the breaches continued (see s 2 and the definition of “civil penalty”).

20    The AER’s case is that the declaration in para 2(b) involves PPPL having committed one contravention of cl 3.13.2(h) on 3 February 2017 in relation to MT PASA submissions which continued for five days resulting in a maximum penalty of $150,000.

21    PPPL contends that neither the declaration in para 2(a) or the declaration is para (b) should be made. Its submissions may be broadly summarised as follows: (1) the declaration is outside the parameters of the case which the AER advanced at the trial as to liability; (2) the declaration is not supported by the findings in PPPL No 1; and (3) the declaration characterises matters as contraventions which, on the proper construction of the NER, are not in fact contraventions.

22    On the AER’s case, the maximum penalty for PPPL’s contravening conduct is in the order of $80 million.

23    PPPL contends that only one declaration should be made and it is in the following terms:

By its short term PASA submissions for the 8 February 2017 trading day set out in Annexure A to these orders, the Respondent contravened cl 3.7.3(e)(2) of the National Electricity Rules by submitting short term PASA availability of less than 320 MW.

I will describe the annexure referred to in this proposed declaration later in these reasons.

THE REASONS IN PPPL NO 1

24    These reasons must be read with the reasons in PPPL No 1. It is necessary to highlight some of the findings and observations in PPPL No 1 in light of the issues which must now be resolved.

25    The important provisions of the NER are set out in the reasons in PPPL No 1 (at [11]–[27]) and need not be repeated. The following provisions are also relevant.

26    The precise terms of cl 3.7.3(h) at the relevant time were as follows:

AEMO must prepare and publish the following information for each trading interval (unless otherwise specified in subparagraphs (1) to (5)) in the period covered by the short term PASA in accordance with clause 3.13.4(c):

(1)    forecasts of the most probable load (excluding the relevant aggregated MW allowance referred to in subparagraph (4B)) plus reserve requirement (as determined under clause 3.7.3(d)(2)), adjusted to make allowance for scheduled load, for each region;

(2)    forecasts of load (excluding the relevant aggregated MW allowance referred to in subparagraph (4B)) for each region with 10% and 90% probability of exceedence;

27    Clause 3.7.3(b) provided as follows:

The short term PASA covers the period of six trading days starting from the end of the trading day covered by the most recently published pre-dispatch schedule with a trading interval resolution.

28    The term “pre-dispatch schedule” was defined as meaning a schedule prepared in accordance with cl 3.8.20(a) and that clause provided as follows:

(a)    Each day, in accordance with the timetable, AEMO must prepare and publish a pre-dispatch schedule covering each trading interval of the period commencing from the next trading interval after the current trading interval up to and including the final trading interval of the last trading day for which all valid dispatch bids and dispatch offers have been received in accordance with the timetable and applied by the pre-dispatch process.

29    At the trial as to liability, the AER advanced two operating scenarios for the two generators (GT11 and GT12) as the basis of its case as to what the PASA availability at the Pelican Point PS was on 8 February 2017. They are described in PPPL No 1 as is their significance in terms of the issues in the case (at [68]–[72]). The MT PASA submissions and ST PASA submissions actually made by PPPL are also described or summarised in PPPL No 1 (at [65]–[67]).

30    The physical condition of GT12 was an issue at the trial as to liability. Mr Debasis Baksi was an employee of PPPL/ENGIE and he gave evidence relevant to this issue. Another matter which should be noted and is relevant to the performance of a generator is the minimum run-time of a generator. That means that certain circumstances relating to the operation of a generator may dictate (or strongly support) that if a generator is to be turned on, it must then be run for at least a certain period of time.

31    The evidence of Mr Baksi is summarised in PPPL No 1 (at [358]–[384]) as is the relevance of Mr Baksi’s evidence to PPPL’s case (at [374]):

374    PPPL relies on Mr Baksi’s evidence as to his concerns about the condition of GT12 because it had been run for almost 5,000 EOHs beyond the manufacturer’s specifications for a C-inspection of 24,000 EOH, it had cracks in the turbine blades and was overdue for a C-inspection and submitted that these concerns were plainly genuine and consistent with the underlying business records.

Mr Baksi also gave evidence which is now said to be significant about the minimum run-time of a gas turbine. The evidence is described in the reasons in PPPL No 1 as follows (at [375]):

375    Further, a hypothetical running time of four hours for GT12 on 8 February 2017 could only be postulated because of the coincidence of GT12 having been run for maintenance purposes on 7 February 2017. There is a need to draw a distinction between the period from which a gas turbine could ordinarily be returned to service and the minimum run-time of a gas turbine having regard to the date of its last operation. A gas turbine in wet storage may ordinarily be returned to service relatively quickly, that is to say, in approximately four hours or less. In terms of minimum run-time, a gas turbine which had been in wet storage, but not operated for approximately three weeks, would need a minimum run-time of at least eight hours. If the gas turbine had been operated more recently, then the minimum run-time would be less than eight hours.

32    I described further evidence of Mr Baksi about the minimum run-time of a generator as follows (at [380]):

380    Mr Baksi accepted that the minimum run-times he identified were not times prescribed by the manufacturer and that it was really a matter of what people on the spot determined having regard to site conditions. He also agreed that as to the minimum run-times, the management of PPPL could overrule the decision of the engineers. It is fair to say that in the course of his cross-examination on the letter from PPPL’s solicitors dated 31 January 2020, Mr Baksi quite reasonably agreed that the minimum run-times were not fixed in stone. He agreed that a run-time of less than eight hours might be possible sometimes when the other interests of PPPL “took precedence over preserving the design life of the CCGT”…

33    A number of earlier observations in the reasons in PPPL No 1 are also relevant and were as follows (at [68], [371], [372] and [373]):

68    The PASA submissions, whether they be medium term or short term, involve a forecast or prediction or prognostication, or to use one of the terms in the Rules, an estimate of physical plant capability available, or that can be made available, on 24 hours’ notice. After GT12 was brought out of dry storage, it was operated from time to time and, in fact, it was operated for a substantial period of time on 7 February 2017. It was operated in the alternative to GT11. They were not operated concurrently before 9 February 2017 when AEMO issued its direction under cl 4.8.9 of the NER.

…

371    GT12 was moved from dry storage to wet storage in November 2016 and was operated for 892 hours in November and December 2016 compared with GT11which was operated for 495 hours.

372    By mid-January 2017, GT12 had operated for approximately 29,000 EOH since its last C-inspection and PPPL had submitted a purchase order for the C-inspection of GT12 on 24 December 2016 which was subject to the successful completion of a gas tolling agreement which would provide a business case for PPPL to use GT12. Mr Baksi gave evidence that he was informed in or about the time GT12 was moved from dry storage to wet storage of the possibility of there being a C-inspection overhaul of GT12 in about April 2017.

373    In mid-January 2017, a decision was made by PPPL to operate GT11 as the primary gas turbine and GT12 as the secondary gas turbine. GT12 was not operated for a period of nearly three weeks between 18 January 2017 and 7 February 2017. It was run for approximately 16 hours on 7 February 2017 in order to maintain the appropriate water chemistry in the heat recovery steam generator. I note that in another part of his evidence, Mr Baksi said it was run for 14 hours, but I do not consider the difference to be material. The C-inspection and overall of GT12 was carried out in April 2017. It took 56 days and cost approximately $39.7 million AUD.

34    As to whether Mr Baksi was an honest witness, I made the following observations in PPPL No 1 (at [381]–[382]):

381    Mr Baksi was honest in giving his evidence. His focus was on the matter of most concern to him which was the condition of GT12 and whether there would be a backup turbine. The one matter where I had trouble accepting his evidence was his statement in para 38 of exhibit R7 that there was a medium to high risk of blade failure which would have catastrophic consequences (emphasis added). Having regard to the context of the observation and what he and PPPL did and did not do, I cannot think that this is correct, and I consider it likely, that he has confused the risk with the consequences should it materialise.

382    Mr Baksi said that he partially agreed with the suggestion that PPPL ran GT12 “harder” on 7 February 2017 than it did on 9 February 2017 and this leads back to a previous point that what made him nervous on 9 February 2017 was not the condition of GT12, but running the two together and the absence of a standby turbine.

35    In PPPL No 1, I identified what I said were the “three key issues” in determining whether the NER had been contravened as follows: (1) the availability of gas supply; (2) the availability of gas transport; and (3) the relevance (if any) of the physical plant capability of GT12 (at [496]). Those matters were to be assessed having regard to the 8 February counterfactual because I found that the other operating scenario advanced by the AER, being the basic 320 MW scenario, was unrealistic and inappropriate and that PPPL was not required to assess and determine its PASA submissions by reference to the basic 320 MW scenario (at [492]–[495]).

36    The availability of gas supply and gas transport was then addressed by reference to the amount of gas and gas transport needed to operate GT11 and GT12 in accordance with the 8 February counterfactual (as to gas supply see at [499] and [527]; as to gas transport see at [534], [617] and [653]). I found that the physical condition of GT12 was not a relevant matter pointing against the availability of GT12 on 8 February 2017 (at [670]).

37    I then turned to express my key conclusions. The key conclusion was that by the time Revision 1 of the Scheduled Quantities Report was issued on 3 February 2017 at 12:14 pm (at [631]), PPPL ought to have had a reasonable expectation of obtaining sufficient interruptible gas transport (and gas) to operate in accordance with the 8 February counterfactual. I said that subject to determining the number of contraventions, PPPL contravened cl 3.7.3(e)(2) after that date (at [680]). I had noted earlier in PPPL No 1 that there were disputes between the parties as to the number of contraventions, some of which were resolved and others which were not resolved (at [675]).

38    In my conclusion, I went on to say that PPPL did not contravene cl 3.7.2(d)(1) (MT PASA submissions) and it did not contravene cl 3.7.3(e)(2) prior to 3 February 2017 at 12:14 pm. I said that I would hear the parties on, inter alia, the effect of my conclusions on the AER’s case that PPPL contravened cl 3.13.2(h).

39    Returning briefly at this stage to the precise number of contraventions, the AER seemed to treat this issue as an issue to be determined at the penalty hearing should liability be established. The position of PPPL is less clear. It was critical in its closing written submissions of AER’s failure to be clear in its case as to the precise number of contraventions. In fairness to the AER, it did file an Amended Originating application which had the practical effect of limiting the number of contraventions. As noted in PPPL No 1 (at [675]), PPPL filed as an annexure to its closing written submissions, a helpful document addressing certain issues relating to the number of contraventions.

40    In the AER’s written outline of opening submissions at the trial as to liability, it contended that there were 10 contraventions of cl 3.7.2(d)(1) (MT PASA submissions), the first on 16 November 2016 and the last on 27 January 2017. There was one contravention of cl 3.13.2(h) which occurred on 11 November 2017 and that contravention continued for 89 days. There were 1,344 “discrete” contraventions of cl 3.7.3(e)(2) (ST PASA submissions) being 28 submissions each containing entries for 48 trading intervals.

The Declarations which will be made

41    It will assist in understanding the arguments and the reasons for their acceptance or rejection if I set out at this point the declarations which I consider should be made. They are as follows:

1.    By each of its four short term PASA submissions made between 6 February 2017 at 11:00 and 7 February 2017 at 11:25 identified below for each of the future trading intervals during the 8 February 2017 trading day identified below, the respondent contravened cl 3.7.3(e)(2) of the National Electricity Rules (NER) by submitting short term PASA availability values of 220 MW that did not represent its current intentions and best estimates as to the physical plant capability of the Pelican Point Power Station that could be made available on 24 hours’ notice which was 320 MW.

2.    The respondent contravened cl 3.13.2(h) of the NER by failing to notify the Australian Energy Market Operator (AEMO) promptly on or after 3 February 2017 that the medium term PASA availability of the Pelican Point Power Station for 8 February 2017 which the respondent previously submitted to AEMO on 27 January 2017 had increased from 224 MW to 320 MW.

The First Declaration (ST PASA submissions and contraventions of cl 3.7.3(e)(2) of the NER)

42    Annexure A to these reasons is a document prepared by PPPL which relates to the declaration it contends is appropriate in the sense that it identifies the period of contravening conduct and it shows the results of the various arguments it puts as to the number of contraventions.

43    Columns A, B and C in Annexure A identify the 24 ST PASA submissions and the date and time they were made by PPPL. Column D summarises the AER’s case as to the number of contraventions. Columns A, B, C and D contain the same information as the AER’s table which is set out above (at [13]).

44    Annexure A shows that the first ST PASA submission was made on 6 February 2017 at 11:00 and the AER contends that it gave rise to 48 contraventions. PPPL disputes this on the ground that it would not have been reasonably known to PPPL on 6 February 2017 that GT12 could have been run for approximately four hours on 8 February 2017. This is PPPL’s first argument.

45    PPPL’s second argument is that submissions 5 to 24 in the yellow box in Annexure A cannot constitute contraventions because, although they were made, they do not relate to the period covered by ST PASA submissions. This argument raises construction issues concerning certain rules in the NER.

46    PPPL’s third argument is reflected in the number of contraventions shown in Column E. It is that only those submissions made 24 hours or more before the relevant trading interval are capable of constituting contraventions. That follows, on PPPL’s argument, because of the reference in the definition of PASA availability of availability “on 24 hours’ notice”.

47    PPPL’s fourth argument is reflected in the number of contraventions shown in Column F. It is that it is only the ST PASA submissions that involve a change to PASA availability from that previously submitted that are capable of constituting contraventions. There are no contraventions, on PPPL’s argument, where there has been no change to information previously submitted. If this, and only this, argument succeeds, then there are 100 contraventions. If this argument and the first and second (or first and third) arguments succeed, then there are arguably no contraventions, although PPPL accepts that it may be appropriate to regard the second submission involving 37 contraventions as a “‘new’ (and incorrect) submission”.

48    I turn to consider each of these arguments.

(1)    Whether the ST PASA submission made by PPPL at 11:00 on 6 February 2017 gives rise to contraventions (submission 1)

49    PPPL’s ST PASA submission at 11:00 on 6 February 2017 gave a value of 220 MW for PASA availability for each of the forty eight 30-minute trading intervals for 8 February 2017 from 4:00 am on that day to 3:30 am on the following day. PPPL submits that none of these entries is a contravention of cl 3.7.3(e)(2) because at the time the ST PASA submission was made, GT12 had not been operated for the 14 to 16 hour period on 7 February 2017 and, in the circumstances as they were on that day, it would not have been known that GT12 could be operated for a mere four hours on 8 February 2017. I summarised the steps in the argument in PPPL No 2 (at [28]).

50    I have set out above the findings, descriptions and observations made in PPPL No 1 concerning the operation of GT12 and the evidence Mr Baksi (at [30]–[34]).

51    It is necessary to provide some further explanation of aspects of Mr Baksi’s evidence at the trial as to liability.

52    Mr Baksi was cross-examined about two graphs, one showing the generation dispatched by PPPL on 8 February 2017 and the other showing the generation dispatched on 9 February 2017. Mr Baksi also gave evidence about the events at the Pelican Point PS on 9 February 2017, but it is not necessary to refer to the details.

53    The evidence shows that on 9 February 2017, GT12 was operated with a running time of four hours. As I have said, it seems from Mr Baksi’s cross-examination that the minimum run-time related to the heat recovery steam generator rather than the gas turbines. Mr Baksi considered that the water quality dropped dramatically once the three week limit was exceeded. He said the following:

It’s established outcome of running at site conditions as to what’s the best possible water chemistry maintained in a wet/cold condition of the heat recovery steam generator, for how long. …

54    It was put to Mr Baksi in cross-examination that under pressure from management, GT12 was operated for four hours on 9 February 2017, but his response to this was that GT12 had already operated for almost 14 hours on 7 February 2017 and this was more than eight hours. He said that the generator was ready to get started on that “count”. The start-up on 9 February 2017 was not dictated by the chemistry, but rather it was dictated by the condition of the blade. It was also dictated by the fact that GT12 was operated in tandem with GT11 and if something went wrong with GT12, there is no backup machine available.

55    Mr Baksi’s evidence was that he made a conscious decision in mid-January 2017 to revert to using GT11 as the primary turbine and keeping GT12 in wet storage as a backup. That was for the reasons discussed earlier in his cross-examination. On 7 February 2017 three weeks after that had been done, GT12 was brought into service and operated again. Mr Baksi said it was operated because it had already remained in cold conditions for three weeks. The previous operation of GT12 was on 8 January 2017 and, therefore, “it necessitated us to run it for at least eight hours on the 7th, which was the last day of the 21-day period before maintaining it for another three weeks”. Mr Baksi agreed that PPPL decided to run GT12 on 7 February 2017 “for maintaining water chemistry”.

56    The submissions of each party with respect to this particular argument were brief.

57    The AER contends that PPPL is inviting the Court to reopen a finding the Court made at [680] of PPPL No 1 to the effect that PPPL contravened cl 3.7.3(e)(2) after Revision 1 of the Scheduled Quantities Report was issued on 3 February 2017 at 12.14 pm and that is not warranted or permissible.

58     PPPL, on the other hand, contends that the Court’s finding at [375] of PPPL No 1 to the effect that a hypothetical running time of four hours for GT12 on 8 February 2017 could only be postulated because of the coincidence of GT12 having been run for maintenance purposes on 7 February 2017 and, therefore, prior to that time, PPPL could not have known that it was reasonably possible that GT12 could have been operated for four hours on 8 February 2017, means that it could not have contravened cl 3.7.3(e)(2) of the NER by a ST PASA submission made on 6 February 2017.

59    With respect to the AER’s submission, the finding in [680] of PPPL No 1 must be read in the context of the reasons as a whole. That paragraph was addressing the point in time at which PPPL ought to have had a reasonable expectation as to the availability of gas and gas transport (in the context of the 8 February counterfactual) and the latter in particular. I identified that point in time as the point at which Revision 1 of the Scheduled Quantities Report was issued and by reference to Annexures 2 and 3 to the reasons, that was on 3 February 2017 at 12:14 pm. The first ST PASA submission made by PPPL after that time and date was made at 11:00 on 6 February 2017. The finding I made ruled out a finding that the ST PASA submissions made prior to that time and date, for example, those made on 30 January 2017 and 2 February 2017, were contraventions of cl 3.7.3(e)(2). At the same time, there could only ever be a contravention of cl 3.7.3(e)(2) by the making of a ST PASA submission and that meant, on the facts, that the next possible contravention was on 6 February 2017. Read in context, the statement in [680] upon which the AER relies is not a finding that PPPL contravened cl 3.7.3(e)(2) immediately after 3 February 2017 at 12:14 pm.

60    At the same time, with respect to PPPL’s submission, the statement in [375] in PPPL No 1 is a description of the evidence given by Mr Baksi rather than a finding.

61    Mr Baksi was cross-examined by the AER about the evidence described in [375] in PPPL No 1. He gave evidence to the effect described in [380]. That evidence is set out above (at [31]).

62    The AER referred to the letter from PPPL’s solicitors, King & Wood Mallesons, dated 31 January 2020. Mr Baksi was asked about whether he agreed with various statements in that letter concerning the minimum run-time of a generator. He agreed with a number of the statements. He was asked whether he agreed with a statement to the following effect:

Further, a run time of less than 8 hours may be possible where the interests of PPPL in preserving the design life of the CCGT in accordance with its operating practice are subordinated by some other circumstance such as when AEMO issues a direction for PPPL to run a CCGT (provided that operation would be consistent with PPPL using its reasonable endeavours).

Mr Baksi was asked whether he agreed that the paragraph correctly reflected what happened from time to time in practice, that is, a run-time of less than eight hours might be possible when other interests of PPPL took precedence over preserving the design life of the CCGT. Mr Baksi said that he considered that this particular paragraph related to what PPPL did on 9 February 2017. He said that every other circumstance is driven by preserving the design life of the HRSG (heat recovery steam generator) which is dictated by water chemistry. He said the following:

If we have the water chemistry at the right level, then, yes, we can do it. And if it has run in the last 48 hours, yes, we can do it. So firstly, it doesn’t say that blankly, you can go ahead and start this CCGT even if your water chemistry is below par. It doesn’t say that.

63    The AER’s alternative argument to the argument that I should not reopen the finding at [380] in PPPL No 1 seemed to be that Mr Baksi had qualified his evidence about the minimum run-time of GT12 and that, in effect, there was no barrier to PPPL undertaking the 8 February counterfactual on 8 February 2017, regardless of the running of GT12 on 7 February 2017.

64    I reject PPPL’s first argument on the basis that it was not clearly advanced and adequately exposed prior to and at the trial.

65    I accept immediately that there is a reference to the minimum run-time of GT12 in the Joint List of Issues and Evidence, that Mr Baksi referred to the minimum run-time of GT12 and the operation of GT12 on 7 February 2017 in his first affidavit of 12 June 2020 at para 77 and it is mentioned in PPPL’s closing submissions, although it was not given a great deal of prominence (see paras 16.3, 43.2(a), 100 and 101).

66    The argument does not appear in the Amended Response to the Concise Statement, there is a somewhat passing reference to it in PPPL’s opening submissions (paras 61 and 293) and even there, the argument is that PPPL could not have anticipated that GT12 would be operated on 7 February 2017 “months in advance”. The argument does not appear in the note as to the number of contraventions attached to PPPL’s closing submissions. That the issue was not clearly advanced and adequately exposed can be shown by the following example. On one construction of Mr Baksi’s evidence, PPPL must have known sometime well prior to 7 February 2017 that the three week period was approaching and GT12 would be run before “maintaining it for another three weeks”, to use Mr Baksi’s words. For the argument to be rejected, PPPL did not need to know or have grounds to expect that GT12 would be operated on 7 February 2017 months in advance, or well in advance, of that date; it just needed to know or reasonably expect that circumstance the day before.

67    It follows that I would not exclude the contravention constituted by the ST PASA submission made at 11:00 on 6 February 2017.

(2)    Whether the period covered by the ST PASA submissions included the ST PASA submissions after 16:00 on 7 February 2017 (i.e., submissions 5 to 24 inclusive)

68    The NER provide that ST PASA must be published at least daily by AEMO in accordance with the timetable and that ST PASA covers the period of six trading days starting from the end of the trading day covered by the most recently published pre-dispatched schedule with a trading interval resolution. Furthermore, the NER provide that AEMO may publish additional updated versions of the ST PASA in the event of changes which, in the judgment of AEMO, are materially significant (cll 3.7.3(a), (b) and (c)).

69    The section in the timetable at the relevant time in relation to both ST and MT PASA is as follows:

I refer to that part of the timetable which deals with ST PASA. The first row deals with the making of ST PASA submissions by participants and AEMO and the publication thereof by AEMO. The period covered is referred to as six trading days from end of trading day covered by most recent pre-dispatched schedule and that mirrors cl 3.7.3(b). The frequency is referred to as “As frequently as changes occur” and comments are made to the effect that the submission is in half-hourly resolution and that AEMO converts network outage information into constraints.

70    The row in the timetable which deals with the publication of ST PASA provides that it is to be done daily at 14:00. The first part of this reflects cl 3.7.3(a). Publication by AEMO is to participants and again, the period covered is referred to as six trading days from end of trading day covered by most recent pre-dispatched schedule (see cl 3.7.3(a)). As to frequency, the requirement is daily as a minimum Rule requirement and the current target system is said to be two hourly. The comments again refer to the fact that ST PASA is provided in half-hourly resolution.

71    The topic of the pre-dispatch schedule is dealt with in cl 3.8.20 of the NER and it is addressed in two rows in Section 4.3 of the timetable. This section of the timetable is as follows:

Under the heading of “day”, there is reference to “Day-1” and the time of day (EST) being as soon as possible (ASAP) after 12:30, no later than 16:00. The event is identified as the publication of the first pre-dispatch for “Day 0” by AEMO to participants and the period covered is “Day 0”. The frequency is identified as being each three hours as a minimum Rule requirement and that the current system target was half-hourly. The comments refer to the fact that the pre-dispatch schedule was provided in half-hourly resolution.

72    PPPL submits that the effect of these rules is that even if, as was the case, PPPL’s ST PASA submissions after 16:00 on 7 February 2017 included PASA availability for the 48 trading intervals on 8 February 2017, those submissions were not required by the Rules and, in those circumstances, those submissions could not constitute contraventions. If this be correct, then the ST PASA submissions from submission 5 onwards do not give rise to contraventions. This factor alone would reduce the number of contraventions alleged by the AER from 722 to 192.

73    The short point is that having regard to the terms of the NER and the timetable, the period covered by a ST PASA submission made after 16:00 on 7 February 2017 would cover six trading days from the end of the 8 February 2017 trading day (emphasis added).

74    It was not in dispute that the six trading day period was a rolling period and that that meant that at various points in time the 8 February 2017 was the sixth day in the rolling period down to the first day in the rolling period. The AER’s principal contentions against this interpretation are that such an interpretation would not further the purpose of the Rules and that such an interpretation is inconsistent with the frequency requirement for ST PASA and the requirement in cl 3.13.2(h) that AEMO be notified of changes. PPPL’s response to the AER’s contentions is that this construction of the NER and the timetable is, for good or for ill, the clear effect of the language used.

75    I am presently considering cl 3.7.3(e)(2) of the NER which requires a Scheduled Generator to submit ST PASA inputs in accordance with the timetable. I am not presently considering cl 3.13.2(h) which requires a Scheduled Generator to notify AEMO of changes to submitted information. The purposive argument advanced by the AER may have more traction in an argument about the scope of cl 3.13.2(h), but I am not presently considering that rule. In my opinion, the words of the obligation which is the civil penalty provision are clear in that they are tied to the timetable which itself reflects earlier rules (i.e., cll 3.7.3(a) and (b)). The ST PASA submissions as referred to in the NER made after 16:00 on 7 February 2017 cover the period of six trading days commencing on 9 February 2017.

76    It follows that I would exclude from the number of contraventions, ST PASA submissions 5 to 24 inclusive.

(3)    Whether submissions made within 24 hours of a relevant trading interval can constitute contraventions

77    PPPL submits that the phrase, “on 24 hours’ notice” as used in the definition of PASA availability means that a Scheduled Generator is not required to provide PASA availability with respect to a trading interval which is within 24 hours of a ST PASA submission. For the purposes of determining whether there is a contravention, a Scheduled Generator is only required to provide details of PASA availability in relation to a trading interval which is 24 hours or more from the time of the submission.

78    As can be seen from Column E of Annexure A, if this argument alone is successful, it reduces the number of contraventions from 722 to 198. There are no contraventions after submission 6. The argument, if successful, provides a basis independent of the second argument for concluding that there are no contraventions after submission 6. The argument, if successful, means that the number of contraventions is reduced from 192 (assuming the second argument is also successful) to 153 contraventions. To illustrate the argument by way of an example: the last trading interval for the 8 February 2017 gas day was the 30-minute period from 3:30 am to 4:00 am on 9 February 2017. The argument is that no ST PASA submission with respect to this period made after 3:30 am on 8 February 2017 is within the definition of PASA availability and therefore a contravention.

79    PPPL submits that the fact that PPPL actually made submissions with respect to trading intervals within 24 hours of the submission is beside the point. I note that not only did PPPL do that, but in its last submission made on 8 February 2017 at 20:51, it altered one of the PASA availability figures for the 34th trading interval. PPPL submits that it would be entirely artificial to ask a Scheduled Generator to make a prediction as to the physical plant capability it could make available on 24 hours’ notice with respect to a trading interval which was, in fact, only a couple of hours in advance of the time at which the estimation is made. Again, to illustrate the argument by way of an example: assume a Scheduled Generator is preparing a ST PASA submission at about 3:30 am for the first trading interval of the “next” day, that is, 4:00 am–4:30 am. It would be artificial to suggest that a Scheduled Generator is required to perform this exercise by considering what he or she knew approximately 24 hours earlier.

80    The AER submits that such complexities are avoided if “on 24 hours’ notice” is read to include within 24 hours.

81    I said in PPPL No 1 that the NER did not provide any indication that the postulated 24 hours’ notice was of any particular nature or given by any particular person (at [187]). Neither party suggested that that conclusion was incorrect.

82    The expression “on 24 hours’ notice” in the definition of PASA availability means that a generating unit that can be made available on say 30 hours’ notice is not PASA available for a trading interval say 24 hours from the time a submission is made.

83    As I understand PPPL’s submission, a generating unit which a Scheduled Generator discovered at the time of making a ST PASA could be made available on one hour’s notice, would not be PASA available for 23 hours (46 trading intervals) after the assumed notice was given. That seems an odd result, particularly as weather conditions, outages and other sources of supply and, therefore, generating capacity can change very rapidly (as this case illustrates) and accurate PASA availability is important. I would not reach the conclusion that PPPL’s construction is the correct one unless the words are intractable.

84    The definition of “PASA availability” was changed in 2010. The change was from “that can be made available within 24 hours” to “that can be made available … on 24 hours’ notice” (or at one point in the amendment process) “that can be made … given 24 hours’ notice”.

85    The correspondence between AEMO and the Australian Energy Market Commission (AEMC) and AEMC’s Rule Determination was put before the Court. PPPL relied on this correspondence and AEMC’s Rule Determination as supporting its construction. I reject that submission and consider that, if anything, the correspondence and AEMC’s Rule Determination supports the construction advanced by the AER.

86    It is not necessary to go through the correspondence and AEMC’s Rule Determination in detail. Three matters are important.

87    First, the amendment to the definition of PASA availability under consideration is not identified as a major change to the NER. It is identified as one of a collection of more minor changes designed to eliminate ambiguity.

88    Secondly, the mischief or ambiguity the change was designed to eliminate is stated in the material to be quite unrelated to the difference between the two constructions advanced in this case. First, it is said to be an ambiguity about “whether the 24-hour recall time applies to the period of time after or before the availability is required”. Secondly, the change was designed to avoid a situation where a participant interpreted the existing definition to mean that capability “that can be made available when, for example, only one hours’ notice is given, thereby excluding additional capability that could otherwise be made available given the full 24 hours’ notice”.

89    Thirdly, if the amendment had the effect for which PPPL contends, it is a significant change. One would expect to see in the material, a discussion of the nature of the change and the policy reasons for it. No such discussion is in the material.

90    In my opinion, the correspondence and AEMC’s Rule Determination does not support the construction advanced by PPPL.

91    In my opinion, the construction advanced by the AER can be accommodated within the words of the definition of PASA availability. It is both a sensible and practical construction and I reject PPPL’s submission to the contrary.

(4)    Whether later ST PASA submissions made by PPPL which involved no change in ST PASA availability give rise to contraventions

92    PPPL submits that there can be no contravention where the Scheduled Generator made no change to PASA availability for a particular trading interval from the previous submission made by the Scheduled Generator. That is the case having regard to the terms of the rule said to have been contravened and the fact that AEMO’s computer system which requires an entry to be made for each trading interval, means that PPPL must make entries even if they involve no change to previously submitted information.

93    In Column F of Annexure A, PPPL has provided information as to the number of entries in relation to PASA availability which are different from previous entries. If one starts with the base figure of 48 entries on 6 February 2017 at 11:00, there are 52 entries thereafter (the first of which arises from the submission made on 8 February 2017 at 11:14) where PASA availability has been changed. The AER accepts that there were changes in relation to 52 entries. On this analysis, there would be 100 contraventions.

94    If the 48 entries on 6 February 2017 at 11:00 are excluded, then 52 entries are relevant. Each of the 52 entries falls after the fourth MT PASA submission. This means that if the second argument is accepted, then none of the submissions after the fourth submission are relevant. However, as I have said, PPPL appeared to accept that this did not mean that it had not committed any contraventions. It did so on the basis that if the ST PASA submission made on 6 February 2017 at 11:00 is excluded, then “it may be appropriate” to treat the second ST PASA submission made on 7 February 2017 at 9:56 as a “new” (and incorrect) submission. PPPL submitted that on this assumption the Court might find that it committed 37 contraventions by reason of the submission made at that date and time.

95    I do not accept that only changes to PASA availability can constitute contraventions. In my opinion, every time a PASA submission was made for whatever reason, it constituted a “statement” by the Scheduled Generator of its current intentions and best estimates as to (relevantly) PASA availability. The fact that there were no changes from a previous PASA submission is relevant to the penalty to be imposed.

Other matters

96    The AER submitted that the first declaration should refer to 3 February 2017 so as to reflect my finding in PPPL No 1 (at [680]). I have already referred to the significance of that finding. I do not accept the AER’s submission. The first contravention of the rule which is the subject of the declaration (i.e., cl 3.7.3(e)(2)) occurred on 6 February 2017 and that is the first date that should be referred to in the declaration.

97    The AER submitted that the reference to 320 MW should be a reference to “at least 320 MW”. It referred to passages in the transcript where it is clear that counsel for PPPL understood that the AER’s case was “at least 320 MW”. I reject the AER’s submission. I do not consider that notice is the issue. The AER set out to prove and did prove the 8 February 2017 counterfactual and that involved 320 MW. That is what should be included in the declaration (Rural Press Ltd v Australian Competition and Consumer Commission [2003] HCA 75; (2003) 216 CLR 53 at [89]–[90]). That PPPL’s submission is correct is neatly illustrated by the fact that there was no scope for it to make a ST PASA submission to AEMO involving an “at least” figure.

98    Finally, in view of my earlier conclusions, I do not need to consider whether there can be contraventions with respect to partially completed trading intervals. It seems unlikely that that is the case in view of the words in cl 3.7.3(e)(2) “for each trading interval”, but I do not need to decide the point.

Conclusions with respect to the First Declaration

99    It is for these reasons I consider the First Declaration should be in the terms set out above (at [41]). There were 192 contraventions of cl 3.7.3(e)(2) of the NER.

The Second Declaration (Para 2(a) cl 3.13.2(h) and ST PASA submissions)

100    The AER did not apply to amend its Originating application to include a claim for this declaration or file any evidence in support of such an application.

101    PPPL submits that the declaration sought by the AER in para 2(a) (see [11] above) is not within the case the AER advanced at trial. It is not identified in any of the documents prepared prior to and for the purposes of the trial. Further, or in the alternative, PPPL submits that the factual findings made in PPPL No 1 do not support the declaration. In other words, there is not a proper basis in the findings for the declaration.

102    The AER submits that the declaration fits “conformably” within the case it advanced at trial and it is based on the findings made in PPPL No 1.

103    The first point to note, and the first point raised by PPPL, is that a claim for declaratory relief for a contravention of cl 3.13.2(h) in relation to ST PASA submissions was not made in any form by the AER at trial.

104    There was no claim by the AER for a contravention of cl 3.13.2(h) in relation to ST PASA submissions in the Originating application, Concise Statement, Joint List of Issues and Evidence and AER’s Outline of Opening Submissions and Outline of Closing Submissions. That circumstance is to be considered in a context in which there were disputes between the parties before trial about the scope of their respective cases (PPPL No 1 at [7]). Having regard to those disputes, this is not a case where one would say that the parties were not insisting on strict adherence to the case as formulated in the documents they exchanged. They were insisting on precisely that. Furthermore, I consider that it should be inferred from the fact that the AER did advance a case of a contravention of cl 3.13.2(h) in relation to MT PASA that AER considered, but rejected, advancing a case of contravention of cl 3.13.2(h) in relation to ST PASA. As I have said, the AER has provided no explanation by way of affidavit as to the reasons it now seeks a declaration in terms of para 2(a). The circumstances do not suggest an explanation other than, in view of the findings in PPPL No 1, it now seeks to raise a claim it considered and could have raised from the outset. The AER raised this claim for the first time on 27 September 2023. The case was one in which events over the whole period from 11 November 2016 to 8 February 2017 were relevant, including those circumstances affecting gas supply and gas transport, and the possibility that the Court might find that there was a contravention at some point between those dates was clearly foreseeable. It is clear that the availability of gas and gas transport were said to be relevant issues from an early stage and that can be seen from questions in the notices served by the AER on PPPL under s 28 of the NEL dated 15 June 2018 and 8 March 2019 respectively.

105    PPPL submits that the AER’s argument that its case was that the circumstances which gave rise to the changes to submitted information were the transfer of GT12 from dry to wet storage on 11 November 2016 is correct, but it does not go anywhere because there was nothing at all which prevented the AER pleading in the alternative, a case of a contravention of cl 3.13.2(h) with respect to ST PASA submissions. In my opinion, PPPL’s submission is clearly correct.

106    PPPL submits that it is relevant that even now the AER does not bring forward an application to amend the Originating application and Concise Statement and an affidavit explaining why the matter was not alleged at the outset. As I understand it, the AER’s response is that it does not need to make an application to amend because the declaration is within the findings in PPPL No 1. I do not think that that is correct. An amendment might be hard to resist because of the findings made at the trial as to liability, but that does not mean that an application to amend does not need to be made. The declarations sought in a proceeding must be in the Originating application (Federal Court Rules 2011 (Cth) r 8.03).

107    PPPL submits that in terms of the prejudice, there is at least a question that evidence about how cl 3.13.2(h) interacts with cl 3.7.3(e)(2) as distinct from cl 3.7.2(d)(1) might have been relevant bearing in mind the frequency of ST PASA submissions. That is possible, but in the absence of any details from PPPL as to the nature of this evidence and its importance, I am not inclined to place much weight on this argument.

108    Irrespective of the procedural difficulties, PPPL also raised two matters which it said are relevant to whether the declaration should be made. The first matter is that there could not be a contravention of cl 3.13.2(h) before 7 February 2017 because prior to that date, GT12 could not have been operated in a way which met the 8 February counterfactual, in other words, it could not have been run for only four hours. I have dealt with this matter elsewhere and it is rejected. The second matter is that there is a real issue as to whether the declaration sought by the AER in para 2(a) is dealing with the same conduct as the declaration in para 1. Section 67 of the NEL is relevant in this respect. Subsection (1) provides that if the conduct of a person constitutes a breach of two or more civil penalty provisions, proceedings may be instituted against the person in relation to the breach of any one or more of those provisions. Subsection (2) provides that nevertheless, the person is not liable to more than one civil penalty in respect of the same conduct. Whether this section is restricted to the civil penalty imposed and does not speak to the making of declarations was not addressed. Furthermore, this argument raises a point of some complexity, not so much for the period from 3 February 2017 to a point on 6 February 2017, but for the period from a point on 6 February 2017 to 8 February 2017.

109    There are a number of cases which have discussed the function of Concise Statements, the obligation of an applicant to identify clearly the case it advances and the fact that the Court will not take a narrow and pedantic approach to a Concise Statement or, for that matter, a Concise Response. The parties referred, in particular, to the following authorities: Australian Securities and Investments Commission v Australia and New Zealand Banking Group Ltd [2019] FCA 1284; (2019) 139 ACSR 52; Allianz Australia Insurance Ltd v Delor Vue Apartments CTS 39788 [2021] FCAFC 121; (2021) 287 FCR 388 at [149] per McKerracher and Colvin JJ; Australian Competition and Consumer Commission v Meriton Property Services Pty Ltd (No 2) [2018] FCA 1125 at [56]–[66] and [89]–[90] per Moshinsky J (involving an issue as to the number of contraventions); Australian Securities and Investments Commission v National Australia Bank Ltd (No 2) [2023] FCA 1118 at [6]–[7], [12], [18], [35], [38], [39], [43]–[48], [52], [79], [84], [86] per Derrington J (also involving an issue as to the number of contraventions). I have considered all of those authorities.

110    The essence of the AER’s submission is that the matter should be analysed in terms of whether what it now seeks falls within the temporal boundaries of its case and the legal and conceptual boundaries of its case. The AER submits that the declaration in para 2(a) falls within these boundaries. There is certainly force in the submission that the declaration in para 2(a) is within the temporal boundaries of the case. It is less clear that the declaration in para 2(a) is within the legal and conceptual boundaries of the case. In this context, I note that one of the submissions made by the AER was that it was not pressing an allegation when, in fact, it could never have succeeded on that allegation which did not in reality seem to be part of its case (see AER’s written submissions on relief at [68(b)]). The fact is that the AER was claiming relief for contraventions of cl 3.7.3(e)(2) by the making of ST PASA submissions on particular days. In any event, the reference to legal and conceptual boundaries is only one way of looking at the matter.

111    In this case, there is no application to amend and whether or not such an application is necessary or not, there is no explanation for why the declaration is now sought in circumstances in which the declaration could have been sought in the alternative from the outset. Furthermore, it is open to the Court to infer that the AER considered, but rejected, seeking such a declaration at the outset. In the circumstances, I refuse to make the declaration sought in para 2(a).

The Third Declaration (Para 2(b) cl 3.13.2(h) and MT PASA submissions)

112    The declaration sought by the AER (see [11] above) in para 2(b) identifies a contravention of cl 3.13.2(h) and not cl 3.7.2(d)(1). The contravention is identified in the declaration as having taken place on and after 3 February 2017 which was the date, on the findings in PPPL No 1, PPPL ought to have had a reasonable expectation of obtaining sufficient interruptible gas transport (and gas) to operate in accordance with the 8 February counterfactual and the declaration identifies the increase in MT PASA availability. The declaration identifies the MT PASA submission immediately prior to 3 February 2017, that is, the MT PASA submission made on 27 January 2017 (see PPPL No 1 at [65]). The declaration in para 2(b) is similar to the third declaration sought at trial, except that it relates to a shorter period of time and does not rely on the event of GT12 being brought from dry storage and placed in wet storage on 11 November 2016 as the trigger for the obligation to notify AEMO of changes to submitted information.

113    Before turning to PPPL’s submissions, there are three further matters to note.

114    The first matter to note is further aspects of the timetable. PPPL’s ongoing obligation to submit data for MT PASA to AEMO is said to be “as frequently as changes occur”, the period “covered” is 24 months from the Sunday after the day of publication. AEMO’s related obligation is to publish MT PASA to the participants each Tuesday with a “Frequency” of weekly as a minimum and “[M]ore frequently if a materially significant change exists” and with a period “covered” of 24 months from the Sunday after the day of publication.

115    The second matter to note is how the AER advanced its case at trial concerning the alleged contravention of cl 3.13.2(h). The AER addressed the issue briefly in its written outline of opening submissions (see paras 167–168, 202–205 and 280–282).

116    In its closing written submissions, the AER submitted that there were three issues in the proceedings, one in relation to each rule alleged to have been contravened. In relation to cl 3.13.2(h), the issue was identified as being whether on and from 11 November 2016, the bringing of GT12 from dry storage into wet storage and into service resulted in a change of the MT PASA availability for 8 February 2017 and whether PPPL failed to notify AEMO of that change as soon as practicable.

117    The third matter to note concerns the mental element or standard of care which must be established in order to establish a contravention of cl 3.13.2(h). I addressed the mental element or standard of care required of Scheduled Generators in relation to each of the rules in PPPL No 1 (cl 3.7.2(d)(1) at [170]; cl 3.7.3(e)(2) at [189]; and cl 3.13.2(h) at [208]).

118    PPPL advanced four reasons in support of its submission that the declaration in para 2(b) should not be made.

119    First, PPPL submits that the declaration identifies a contravention of cl 3.13.2(h) which was not part of the AER’s case at trial. The event giving rise to the “changes” to submitted information as identified in the declaration in para 2(b) when read with PPPL No 1 was the availability of gas (at [532]) and gas transport (at [617] and [680]), whereas the event identified in the third declaration sought at trial was the transfer of GT12 from dry to wet storage on 11 November 2016.

120    I do not consider this point to be fatal to the AER’s claim for the declaration because the case was run on the basis that the availability of gas and gas transport were critical issues and those issues were to be considered at various points in time from 11 November 2016 onwards. As I have previously said, the evidence was not restricted to events on 11 November 2016.

121    Secondly, PPPL submits that there are insufficient findings in PPPL No 1 to support the conclusion that there has been a contravention of cl 3.13.2(h). There are two relevant differences between the requirements for ST PASA submissions on the one hand, and MT PASA submissions and cl 3.13.2(h) (when applied to MT PASA submissions) on the other, and they are the mental element or standard of care to be applied and the fact that, in the case of MT PASA submissions, the Scheduled Generator must estimate PASA availability taking into account “the ambient weather conditions forecast at the time of the 10% probability of exceedance peak load”, whereas that is not a matter referred to in the case of ST PASA submissions.

122    In my opinion, there are sufficient findings and conclusions in PPPL No 1 to draw a conclusion as to the first matter (at [208] and [680]). The standard of care for MT PASA submissions was identified in PPPL No 1 (at [170]) as was the standard for ST PASA submissions (at [187]–[189]). There are no findings, and nor I think was there any evidence, about ambient weather conditions and percentage probabilities of exceedance peak load. As to this matter, the AER submits, correctly in my view, that no issue was raised concerning the issue at the trial as to liability.

123    The third argument advanced by PPPL is a technical one. The obligation in cl 3.13.2(h) to notify AEMO of changes is designed to ensure that submitted information (which must be published by AEMO) is as accurate as possible. As I understand PPPL’s argument, it is that there is no contravention of cl 3.13.2(h) by PPPL where the information “covering” 8 February 2017 is accurate at the time it is provided by PPPL. The MT PASA submission made by PPPL on 27 January 2017 was accurate and would have been published by AEMO on 31 January 2017 and would have covered the period of 24 months from Sunday, 5 February 2017, including Wednesday, 8 February 2017. Had PPPL notified AEMO of a change of MT PASA availability on 3 February 2017 as the AER contends, the information would have been published by AEMO the following Tuesday, 7 February 2017, and covered the period from Sunday, 12 February 2017 onwards. In other words, the MT PASA information would not have covered 8 February 2017.

124    In my opinion, the AER’s response to this argument is correct. PPPL’s submission conflates the obligation in cl 3.7.2(d)(1) to make MT PASA submissions and the obligation in cl 3.13.2(h) to notify AEMO of changes to submitted information. The latter obligation arises when there are changes to submitted information.

125    Finally, PPPL submits that there can be no contravention of cl 3.13.2(h) before 7 February 2017 when GT12 was operated for a substantial period of time. It was only that circumstance, according to the evidence of Mr Baksi, that could give rise to a reasonable expectation that the 8 February counterfactual could be implemented on 8 February 2017. I have already addressed this argument and rejected it.

Conclusions with respect to the Second Declaration

126    It was for these reasons I consider the Second Declaration set out above (at [41]) should be made. There was one contravention of cl 3.13.2(h) on 3 February 2017 which continued for five days resulting in a maximum penalty of $150,000. For the same reasons I gave in relation to the First Declaration, the Second Declaration should refer to “320 MW” and not “at least 320 MW”.

CIVIL PENALTY

General Matters

127    Section 64 of the NEL provides that the Court must have regard to all relevant matters in determining the civil penalty to be paid by a person declared to be in breach of a provision of (inter alia) the Rules, including the following matters:

(a)    the nature and extent of the breach; and

(b)    the nature and extent of any loss or damage suffered as a result of the breach; and

(c)    the circumstances in which the breach took place; and

(d)    whether the person has engaged in any similar conduct and been found to be in breach of a provision of this Law, the Rules or the Regulations in respect of that conduct; and

(e)    whether the service provider had in place a compliance program approved by the AER or required under the Rules, and if so, whether the service provider has been complying with that program.

128    The matters identified by French J (as his Honour then was) in Trade Practices Commission v CSR Limited [1990] FCA 521; (1991) ATPR 41-076 at [42] are also relevant. They correspond with, overlap or are additional to the matters identified in s 64 and are as follows:

1.    The nature and extent of the contravening conduct.

2.    The amount of loss or damage caused.

3.    The circumstances in which the conduct took place.

4.    The size of the contravening company.

5.    The degree of power it has, as evidenced by its market share and ease of entry into the market.

6.    The deliberateness of the contravention and the period over which it extended.

7.    Whether the contravention arose out of the conduct of senior management or at a lower level.

8.    Whether the company has a corporate culture conducive to compliance with the Act, as evidenced by educational programs and disciplinary or other corrective measures in response to an acknowledged contravention.

9.    Whether the company has shown a disposition to co-operate with the authorities responsible for the enforcement of the Act in relation to the contravention.

The nature and circumstances of the contravening conduct

129    Under this heading, I address the matters identified in s 64(a) and (c) and the first and third of the matters identified by French J.

130    PPPL’s contravening conduct was in underestimating and failing to update its PASA availability and, in particular, the physical plant capability at the Pelican Point PS that could be made available on 24 hours’ notice. This was in a legislative or rule based context in which AEMO has the power to direct a Scheduled Generator to bring a generator online to avoid shortages which may lead to load shedding.

131    The summer of 2016/2017 was anticipated to be one in which South Australia would face significant energy security risks that it had not faced in previous summers. Mr Foulds was an ENGIE employee and between 2012 and January 2016, he was Origination Manager and Trading Manager based in Melbourne, and from January 2016 to August 2018, he was Head of Trading and Portfolio Management. His responsibilities in those two positions are identified in PPPL No 1 (at [296]–[297]). Mr Foulds said that there were two reasons South Australia faced significant energy security risks in the summer of 2016/2017 and they were as follows: (1) the Northern Power Station was closed as was the mothballed Playford B Power Station and this was South Australia’s first summer without the Northern Power Station providing 520 MW of coal-fired baseload power; and (2) the September 2016 Black System event when a number of wind farms reduced their power output by over 450 MW in a number of seconds causing the Heywood Interconnector to trip and isolating South Australia from the National Electricity Market. GT12 was brought from dry storage to wet storage so that it would be available to be used interchangeably with GT11. GT12 was a backup turbine and according to Mr Baksi was brought into wet storage to ensure market needs were met on very extreme days and that reliability of supply was assured to the extent possible.

132    It was not in dispute that GT12 was brought from dry to wet storage so that it would be a backup to GT11 and that the turbines would be used interchangeably from time to time. Furthermore, it was not in dispute that PPPL’s intention throughout was to operate one generator and provide one generator and provide 240 MW.

133    Mr Foulds did not turn his mind to changing PPPL’s PASA submissions at the time GT12 was taken from dry to wet storage (PPPL No 1 at [329] and [342]) and insofar as he did thereafter, the commercial intention to run only one turbine and a lack of firm gas supply beyond this led to the fact that the PASA availability did not exceed approximately 240 MW (PPPL No 1 at [344] and [357]).

134    It is not in dispute that PPPL’s non-disclosure of PASA availability after 12:14 pm on 3 February 2017 was not deliberate or intentional. In other words, it did not, with a proper understanding of its obligations, decide to proceed in the way in which it did. It misunderstood its obligations focusing on its current intentions and its arrangements with respect to gas supply and gas transport.

135    The AER submitted that this could not be a mitigating factor.

136    I do not consider that a great deal is to be gained by determining what might or might not constitute a mitigating factor in the case of these contraventions. The fact is that the contraventions were not deliberate or intentional and that is a matter to be taken into account.

137    PPPL asked the Court to take into account three matters.

138     First, had GT12 been left in dry storage, there would have been no contraventions and one of the reasons it was taken from dry storage to wet storage was to “maintain system security” (PPPL No 1 at [328]). That was a responsible approach by PPPL.

139    Secondly, with respect to the AER’s submission that the contraventions arose as a result of PPPL’s misunderstanding of the NER cannot be a mitigating factor, PPPL submits that, generally speaking, that would be correct. However, PPPL referred to the observation I made in PPPL No 1 (at [184]) that the NER dealing with PASA submissions are not a model of clear and precise drafting. More significant than that observation, is that a number of important aspects of the AER’s case taken to trial did not succeed. I do not propose to set out an exhaustive list as the matters are set out in PPPL No 1, but the following are examples:

(1)    contrary to the AER’s case, the mere fact that GT12 was moved from dry to wet storage did not necessitate a change to PPPL’s PASA submissions;

(2)    the AER’s case that PPPL contravened cl 3.7.2(d) of the NER failed;

(3)    the AER’s case by reference to the 320 MW scenario, which its own expert described as “unrealistic”, failed; and

(4)    it was necessary to read a requirement of reasonableness into cl 3.7.2(d) of the NER.

140    Thirdly, it is relevant that a number of the submissions made by PPPL were resubmissions without change which came about because the AER’s system was such that all fields must be completed when entering an updated ST PASA submission.

141    I consider that the first and third matters are relevant and I take them into account. I am unable to see how the aspects in respect of which the AER failed affects the penalty for contraventions it did establish.

Whether the contraventions arose out of the conduct of senior management or at a lower level

142    The AER contended, and PPPL did not dispute, that Mr Foulds was involved in PPPL’s contraventions, albeit through management oversight rather than by direct operational involvement and that Mr Foulds was part of PPPL’s senior management.

143    Mr Foulds was not directly involved in the decisions to make the MT PASA and ST PASA submissions. He was involved in the decision to mothball half of the generation capacity of the Pelican Point PS to take effect on 1 April 2015. He gave instructions to Mr Frimston, who was the Trading Operations Manager at PPPL, or the duty trader on shift at that time, to update PPPL’s MT PASA to reflect the decision to mothball half of the generation capacity of the Pelican Point PS (PPPL No 1 at [307]).

144    Mr Foulds was also involved in the decision to bring GT12 out of dry storage in November 2016 (PPPL No 1 at [325]–[327]). At the time GT12 was returned to wet storage, Mr Foulds did not give consideration to the matter of whether PPPL should update its PASA submissions because his focus was on the intention of PPPL which was to run one gas turbine only at any particular time (at [342]). Mr Foulds was concerned to act prudently and he considered that until gas was firm, he could not make “any update “(at [344]). PPPL did not change its PASA submissions because of the absence of firm gas supply and gas transport arrangements to support the running of a second turbine (at [357]).

145    The AER submits that a misunderstanding of the requirements of the PASA regime on the part of Mr Foulds was the basis of the failure to update PASA submissions once GT12 had been taken out of dry storage and put into wet storage. I refer to the finding in PPPL No 1 as follows (at [338]):

… This evidence, together with the evidence referred to below (at [592]–[594]) and Mr Foulds’ evidence of the mothballing is the most direct evidence of the reasons PPPL made the PASA submissions it did, that is to say, it did not intend to run two turbines and its firm gas supply and gas transport were based on running one turbine at a time.

146    The AER submits that had Mr Foulds not laboured under the misunderstanding he did, he would have instructed the trading team either to revise again PPPL’s PASA availability submissions when GT12 was returned from dry to wet storage or thereafter, to consider whether any of the capacity of GT12 should be indicated as PASA available, depending on the notified spare gas transport capacity from time to time. I consider it more accurate to say Mr Foulds should have advised the trading team with respect to PASA submissions when sufficient gas and gas transport was available.

147    PPPL submits that even accepting that relatively senior management was involved in the contravening conduct, that is not a significant factor in circumstances (as here) which did not involve a conscious or reckless departure from the law. I accept this submission to a point. In this case, there was a misapprehension of a regulatory requirement formed in good faith. Mr Foulds gave evidence of the importance of not overstating the generation capacity in PASA submissions (at [308]). This is a relevant point and it is supported by a Compliance Bulletin published by the AER. The Bulletin makes the point that there are dangers in overestimating PASA availability. Planning by AEMO and market participants can be difficult where PASA availability is overestimated and then withdrawn at short notice.

The nature and extent of any loss or damage suffered as a result of the contraventions

148    It needs to be made clear at the outset that the AER does not assert that had PPPL submitted its correct PASA on and from 3 February 2017, the load shedding that occurred in South Australia between 18:00 and 19:00 on 8 February 2017 would have been avoided or reduced. Nor does the AER otherwise assert that PPPL’s contraventions had any specific impact on customers or financial losses.

149    However, the AER does assert that PPPL’s failure, through its MT PASA submissions and ST PASA submissions, to update and disclose the full PASA availability of the Pelican Point PS meant that from 3 February 2017 until late in the afternoon of 8 February 2017, AEMO was unaware that it had the ability to issue a direction to make 320 MW at Pelican Point PS available to maintain power system security. As a result, AEMO’s ability to manage power system security was materially impaired. This assertion, the AER submits, is consistent with the allegation in the Concise Statement that PPPL’s failure to submit its correct PASA availability materially impaired AEMO’s ability to manage power system security on the afternoon of 8 February 2017.

150    The AER submits that the material impairment is not merely abstract or insubstantial. The AER submits that if the material impairment is established, this means “that the absence of direct financial consequence from PPPL’s conduct should not therefore be relied on as a substantial mitigating factor”.

151    Having regard to the AER’s closing written submissions on relief, I consider the following to be particulars of the AER’s material impairment allegation:

(1)    had PPPL submitted its correct PASA availability, then AEMO would likely have first inquired about potential surplus generating capacity at the Pelican Point PS shortly after 15:17, rather than at 17:39; and

(2)    had AEMO been able to make that inquiry at the earlier time, then it would have had better prospects of being able to direct PPPL to bring at least 85 MW of additional generating capacity into service in time to either avoid or reduce the load shedding that occurred from 18:00. The likelihood of load shedding would have been reduced, albeit it is not possible to conclude, on the balance of probabilities, that the load shedding would have been avoided or reduced. AEMO’s power to issue a direction to PPPL to bring into service a generating unit is contained in cl 4.8.9(a) of the NER and s 116 of the NEL.

I have emphasised certain words so as to identify the precise nature of the argument advanced by PPPL.

152    The AER also referred to a number of cases where the contraventions were of obligations important to power system security. In addition, the cases were said to be of assistance in fixing the appropriate penalty.

153    PPPL accepts that PASA submissions form part of a regime intended to enable AEMO to manage power system security. It submits that it does not follow that any contravention in relation to PASA submissions impairs (let alone materially impacts) power system security unless that concept is used in “an abstract or theoretical way”.

154    PPPL submits that whether there was an impairment in the sense of preventing AEMO from taking steps that it would have otherwise have taken must be evaluated in light of all the circumstances established by the evidence and that when that is done, the AER has not established that there was a practical inhibition on AEMO’s ability to maintain power system security (emphasis added).

155    PPPL made two main submissions in response to the AER’s allegation that by its conduct, it materially impaired AEMO’s ability to manage power system security. Both were principally directed to negating the AER’s assertion that it was likely AEMO would have contacted PPPL approximately two hours earlier than it did on 8 February 2017 had PPPL made correct PASA submissions. First, PPPL submits that the AER’s own evidence does not support that assertion. Secondly and relatedly, PPPL submits that there is a distinct lack of direct evidence which supports the AER’s assertion that it would have been proactive in the manner stated in the particulars and that flaw in the AER’s case cannot be overcome by inferences.

156    In addition, PPPL addressed the cases referred to by the AER.

157    Before addressing the competing arguments, it is convenient to refer to one matter I raised with the parties during the course of submissions. I asked the parties whether the approach taken in Malec v JC Hutton Pty Ltd [1990] HCA 20; (1990) 169 CLR 638 at 643 per Deane, Gaudron and McHugh JJ, cited with approval in Sellars v Adelaide Petroleum NL [1994] HCA 4; (1994) 179 CLR 332 at 350, was in any way relevant to the Court’s approach to the consideration of loss or damage as a factor relevant in the determination of an appropriate civil penalty. Both parties submitted that the approach taken in those cases is not relevant. In that respect, the AER referred me to the decision of the Full Court of this Court in Australian Competition and Consumer Commission v Cement Australia Pty Ltd [2017] FCAFC 159; (2017) 258 FCR 312 (ACCC v Cement Australia) at [488]–[500], particularly at [497]–[500]. I consider that the parties are correct with respect to this matter. First, the issue in this case is whether any loss or damage was suffered as a result of the contraventions and, even under common law principles relating to the assessment of damages for breach of contract or the commission of a tort, the causation issue in terms of whether there has been any loss or damage is determined on the balance of probabilities. The second is that ACCC v Cement Australia is direct authority for the proposition that even when considering the extent of the loss or damage in a civil penalty context, one does not rely on principles relating to the assessment of damages for breach of contract or the commission of a tort.

158    A convenient starting point is the chronology of events on 8 February 2017. A chronology of events is set out in the reasons in PPPL No 1 (at [226]). That chronology was added to by both parties as a result of the further evidence that came forward on the hearing as to penalty and is now as follows:

41.    On 8 February 2017:

(a)    at 12:47, AEMO declared a forecast LOR1 condition in the South Australia region on 9 February 2017 from 16:30 to 19:00 hours (Market Notice 57268).

(b)    at 15: 18, AEMO declared a forecast LOR1 condition for the South Australia region on 8 February 2017, from 16:30 to 19:00 (Market Notice 57276). Prior to 15:00, none of AEMO’s PD PASA calculations made on a half-hourly basis from 12:00 on 7 February 2017 had forecast an LOR1 condition for 8 February 2017.

(b1)    at 15:54, the AEMO control room received a phone call from Engie, advising that the generating units at Port Lincoln had been bid out until further notice.

(b2)    at 15:58, there was a telephone call between the AEMO Senior Manager and the AEMO Shift Manager, in which the Shift Manager noted that the South Australian region was close to LOR2, and the AEMO Senior Manager enquired whether there was there any additional availability.

(b3)    at 16:00, utilising its PD PASA calculation, AEMO’s forecast was that available capacity would exceed available demand by a minimum of 226MW at 18:30 but would not result in LOR2 (because the threshold for forecasting LOR2 was when reserves were less than 200MW).

Until 16:00, wind generation matched the forecast, but after this time, wind generation declined more quickly than forecast.

(c)    at 16:13, AEMO declared an actual LOR1 condition in the South Australia region on 8 February 2017 from 16:00, forecast to exist until 19:00 (Market Notice 57277).

(c1)    at 16:30, utilising its PD PASA calculations, it remained the case that AEMO was not forecasting that there would be an LOR2 on 8 February 2017.

(d)    at 17:13, AEMO declared an actual LOR2 condition in the South Australia region on 8 February 2017 from 17:00, forecast to exist until 19:00 (Market Notice 57279). The Market Notice stated (as was the fact).

AEMO does not intend to intervene through a AEMO intervention event

(d1)    at 17:18, Origin Energy advises AEMO that Quarantine unit 4 (20MW) is not available.

(e)    at 17:25, electricity flows across the Murraylink interconnector from Victoria to South Australia increased above its limit, which resulted in the power system no longer being in a secure operating state.

(e1)    at about 17:30, Vince Duffy, Director of Energy Markers in the South Australian Government, telephoned Darren Foulds of Engie. Mr Foulds said that it looked like AEMO would need to load shed, and that he was surprised that no one from AEMO had contacted PPPL about whether PPPL could make its mothballed capacity and GT12 available or be the subject of a reserve contract or a direction.

(e2)    at 17:32, there was a telephone call between the AEMO Group Manager and an AEMO operator, in which the Group Manager suggested that the operator call Engie, to see whether “Pelican Point unit 2” was available.

(e3)    at 17:35, AEMO staff contacted AGL to enquire as to whether there was any further capacity available from Tips B1 and the status of Tips A1.

(f)    at 17:39, AEMO staff contacted Engie to enquire about the availability of the GT12 generating unit at Pelican Point PS. The transcript of that conversation includes the following statement by an Engie trader:

(f1)    AGL advises AEMO that Torrens Island A1 (120MW) will not be available until Monday and that Torrens Island B1 is operating at reduced capacity (50MW reduction) due to high ambient temperatures.

(g)    at 18:00, AEMO staff had a further telephone conversation with staff at Engie. The transcript of that conversation included the following exchange:

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.

Whether PPPL had in place, and was complying with, a compliance program

216    PPPL called Mr Jamie Lowe in respect of this matter. Mr Lowe is the Head of Regulation, Compliance and Sustainability at ENGIE Australia and New Zealand. He has worked in the energy sector in Australia since 2009 and he has been employed at ENGIE Australia and New Zealand since November 2014. He said that ENGIE was a trading name for a group of companies that includes PPPL and which are ultimately 72% owned by ENGIE SA and 28% owned by Mitsui & Co Ltd. Mr Lowe was employed as Head of Regulation from November 2014 to October 2019. On the latter date he commenced his role as Head of Regulation, Compliance and Sustainability.

217    Mr Lowe said that ENGIE’s operation of its scheduled generation assets, including the Pelican Point PS, are subject to a broad range of regulatory obligations and requirements. A substantial portion of the regulatory requirements affecting scheduled generating assets, including the Pelican Point PS, are contained in the NER, the NEL and the National Gas Rules. Mr Lowe is able to speak as to ENGIE’s approach to compliance since about 2014. He said that since that date, ENGIE has had in place systems to train its staff and to seek to ensure that they stay abreast of changes in the law (including the NER) as they are made. He described the systems as follows:

When new employees commence in roles which require them to perform tasks such as making bids under the NER, for example spot trading desk staff, those staff are provided with “onboarding” training and guidance as to the tasks that they are required to perform so as to ensure that PPPL is compliant with the NER. Examples of such tasks include the process for making bids (and rebids) and the information that spot traders need to record in PPPL’s systems when making bids (and rebids). Engie has also provided mandatory and ongoing compliance training and published compliance and procedural guidelines (including that referred to in the affidavit of Darren Foulds at paragraphs [59]-[60], to which I seek leave to refer) to ensure ongoing compliance with existing rules. Engie has also provided ad-hoc compliance training in response to the introduction of new rules or amendments to existing rules.

218    Since 2014, ENGIE’s regulation and compliance team have met bi-monthly with the ENGIE executive to report on changes and potential changes to the regulations affecting their business units (including PPPL). ENGIE’s regulation and compliance team also engaged directly with staff to provide written guidance and training when those regulatory changes take effect.

219    ENGIE has dedicated additional resources to its compliance training and its approach to compliance more generally, including in respect of the Pelican Point PS. That process has included the following: (1) employing additional staff, including a Compliance and Sustainability Manager, and two compliance officers; (2) since 2019, the regulation and compliance team has been tasked with an increased focus on all manner of day-to-day trading and market compliance, as well as staying up to date on rule changes, considering their proper allocation and delivering the training; (3) since about 2022, the regulation and compliance team have met fortnightly to discuss and action issues arising out of breaches, audits, new guidelines, rule changes (actual or proposed) and additional training requirements; (4) since about the beginning of 2023, and in relation to the bi-monthly meetings between the regulation and compliance team and ENGIE executive, the frequency of the meetings has changed in that they are held on a monthly rather than a bi-monthly basis; (5) since about July 2023, ENGIE has held a monthly Global Energy Management and Sales Compliance Committee meeting to discuss any identified compliance risks and actions associated to ensure compliance, reviews of controls in place, adoption of new policies and all other matters of a practical nature that can impact on day-to-day compliance; and (6) ENGIE has implemented a program called “Archer” which seeks to “risk assess” and then allocate every rule that applies to the operation of ENGIE’s generation assets to an employee within the business. Mr Lowe said that the program took over two years to design and implement and it came into operation in about 2023.

220    The point the AER sought to make here related to Mr Lowe’s reference to ENGIE publishing compliance and procedural guidelines and the reference by Mr Lowe to Mr Foulds’ affidavit and Mr Foulds’ reference to the ENGIE “Spot Trading Procedural Guideline”. Mr Foulds described that guideline as one of many that ENGIE developed from time to time to assist ENGIE staff to execute their roles consistently and in compliance with the relevant rules. The focus of the guideline was on ST PASA. The guideline refers specifically to and quotes from and attaches a copy of a 2010 Compliance Bulletin published by the AER. Mr Foulds also noted that the ENGIE guideline provides specific guidance depending on whether one or two GTs are operating. The point that the AER makes about the guideline is that in the context of ST PASA availability based on forecast temperature, there is a reference to maximum availability. Maximum availability was described by Mr Van Der Walt as what Scheduled Generators want to do, whereas PASA availability is what they can do. The guideline says nothing about how PASA availability is to be estimated and the AER submits that, in those circumstances, it was easy to see how ENGIE staff came to be operating under the misunderstanding that because it intended only to make a single gas turbine available at any time during the summer of 2016/2017, it was not required to indicate any additional capacity as being PASA available, even if PPPL could reasonably expect to be able to bring the second turbine into service within 24 hours or less.

221    The AER does not appear to dispute that PPPL have procedures in place for dealing with PASA availability. Those procedures and internal guidance reflected PPPL’s incorrect understanding of the NER. PPPL submitted that the fact that it had internal procedures and guidance in place is a mitigating factor. The fact that the procedures and guidance were incorrect did not take the matter further than the underlying contravening conduct.

222    I accept Mr Lowe’s evidence. At the same time, I accept the point made by the AER. I consider this factor to be relatively neutral.

The difficulty in detecting the contraventions

223    The difficulty of detecting the particular contravening conduct in issue may be relevant to the level of pecuniary penalty in order for that penalty to operate effectively by way of general deterrence. The reason is that where the contravention is not easily detected by a regulator or other person, there is an additional need to ensure that as far as practicable those subject to the obligation comply with it.

224    In AER v Hornsdale, I imposed pecuniary penalties for contraventions of obligations which were difficult to detect. I said the following (at [78]):

The sixth matter identified by the applicant is the difficulty in detecting contraventions of a capability to provide FCAS until the service is in fact required to be actively delivered during a network event, by which time it is too late for AEMO or the Market Participant to take pre-emptive action to prevent the non-compliance arising. This is an important matter and it was emphasised by the applicant in its oral submissions. As the applicant’s counsel submitted, the type of contraventions in this case only become apparent following the necessity of the services being drawn upon and being found not to be there. I accept the submission made by the applicant that because it is difficult for the market operator and the regulator to detect non-compliance before the services are actually deployed during a frequency deviation, it is important in determining the size of the pecuniary penalty to take into account the need to promote proactive compliance by providers given the difficulty of detection otherwise.

225    Insofar as PASA availability relates not to the generating unit, but rather to the gas and gas transport required to operate it, a contravention is difficult to detect because the availability of gas and gas transport is likely to be peculiarly within the knowledge of the operator. Insofar as PASA availability relates to the existence of a generating unit in wet storage, the position on the evidence as to the difficulty of detection is not so clear.

226    We do know in this case that PPPL was trying to keep AEMO informed as to the generating capacity in other locations. It contacted AEMO at 15:54 to advise it that the generating units at Port Lincoln had been bid out until further notice. Furthermore, it is clear that from 6 January 2017, AEMO in the form of Mr Van Der Walt was aware that GT12 was able to be brought back online on 48 hours’ notice (“on a 48 recall”). Finally, I agree with PPPL’s submission that the AER’s submission that in terms of detection, a telephone call from AEMO to PPPL to find out about generating capacity is an extraordinary inquiry, is not correct. It is not an extraordinary step. Nevertheless, it is not how the system is supposed to work.

227    PASA availability involves not only the availability of a generating unit, but also sufficient gas and gas transport to operate it. In combination, these matters are difficult to detect and I place some weight on this factor.

Whether PPPL has engaged in any similar contravening conduct

228    In September 2005, the National Electricity Tribunal found by consent that PPPL contravened cl 5.2.5 of the National Electricity Code when one of the gas turbines tripped in response to a network frequency disturbance when it should have responded by riding through the disturbance. NEMMCO informed the Tribunal that it was possible (but not “most likely”) that, if the gas turbine had not tripped, the extent of load shedding experienced in South Australia on that day may have been reduced. That appears to have been accepted by PPPL. The Tribunal imposed a penalty of $100,000 and suspended 80% of it for a period of 12 months.

229    I take this contravention into account, although it is not of great significance. It is, as PPPL submits, not a contravention in relation to PASA availability. At the same time, it involves, as the AER submits, an obligation related to the maintenance of power system security. By the end of the submissions, the AER had indicated that it did not place any particular weight on this factor.

The size and financial position of PPPL and of the ENGIE Group

230    There was a debate between the parties in their written submissions as to whether, for the purposes of this factor, the Court should consider ENGIE group or PPPL group. In closing oral submissions, the AER took the sensible view that the resolution of that issue was not of critical importance because on any view one was dealing with a large group. In the year ending 31 December 2017, ENGIE had a consolidated group revenue of €65 billion and an EBITDA of €9.3 billion and in the same year, PPPL had revenue of $553 million, gross profits of $151 million and net assets of A$197 million.

231    In Australian Building and Construction Commissioner v Pattinson [2022] HCA 13; (2022) 274 CLR 450, the High Court said that the circumstances of the contravenor may be more significant in terms of the extent of the necessity for deterrence than the circumstances of the contravention. The Court said (at [60]):

Indeed, in some cases, the circumstances of the contravenor may be more significant in terms of the extent of the necessity for deterrence than the circumstances of the contravention. In this regard, it is simply undeniable that, all other things being equal, a greater financial incentive will be necessary to persuade a well-resourced contravenor to abide by the law rather than to adhere to its preferred policy than will be necessary to persuade a poorly resourced contravenor that its unlawful policy preference is not sustainable. It is equally obvious that, the more determined a contravenor is to have its way in the workplace and the more deliberate its contravention is, the greater will be the financial incentive necessary to make the contravenor accept that the price of having its way is not sustainable.

(Footnote omitted.)

232    It is undoubtedly the case that ENGIE or PPPL is a well-resourced contravenor. However, it is also relevant that it is not disputed that PPPL’s contraventions were not intentional or deliberate and it would seem that it is not an accurate description to say that PPPL’s actions reflect a determination to have its way. Furthermore, the AER accepts that PPPL, by making the telephone call to AEMO at 15:54 on 8 February 2017 that it did, was appropriately endeavouring to act co-operatively with AEMO to manage the challenging circumstances on that day. At the same time, the size of the contravenor is not rendered completely irrelevant by the fact that the contraventions were not deliberate or intentional because even in the case of a mistake, the contravenor must be encouraged by the penalty to avoid similar mistakes in the future.

Whether there has been co-operation and timely disclosure by PPPL

233    In Australian Competition and Consumer Commission v Optus Internet Pty Limited [2022] FCA 1397, Moshinsky J said (at [33]):

Co-operation with authorities in the course of investigations and subsequent proceedings can properly reduce the penalty that would otherwise be imposed. The reduction reflects the fact that such co-operation: increases the likelihood of co-operation in future cases in a way that furthers the object of the legislation; frees up the regulator’s resources, thereby increasing the likelihood that other contravenors will be detected and brought to justice; and facilitates the course of justice: see, eg, Agreed Penalties Case at [46]; NW Frozen Foods Pty Ltd v Australian Competition and Consumer Commission [1996] FCA 1134; (1996) 71 FCR 285 at 293-294 …

234    In Australian Competition and Consumer Commission v Westminster Retail Pty Ltd [2005] FCA 1299; (2005) ATPR 42-084, Mansfield J said (at [31], [33]–[34]):

31    … The defence of a proceeding should not result in any additional penalty (other than by the effect of an order for costs), beyond what would otherwise be the case, but the conduct of the respondents overall is relevant to whether there should be allowed any discount for co-operation. I do not accept the implicit submission on behalf of the applicant that any lack of co-operation in the investigation of suspected contraventions of the Act, or in the conduct of proceedings under the Act, should lead to increased penalties. Consequently, I do not accept the express submission that a lack of co-operation by the respondents is an aggravating factor which can cancel the acknowledgment of liability by all respondents, so that no credit for co-operation should be given.

…

33    What is relevant to the discount, if any, on the penalties to be imposed is the extent to which the respondents have co-operated with the applicant in its investigation of the suspected offences and their conduct. Conduct before the institution of proceedings is, in my view, relevant to that assessment. It is regarded as a mitigating factor when, even at the investigation stage, there is frank and full disclosure of relevant material. The corollary should also be the case.

34    The applicant identified certain ‘aggravating factors’ related to the conduct of the respondents on the issue of their overall co-operation. For the reasons given, I shall treat the alleged ‘aggravating factors’ as matters relevant to the assessment of the extent to which the respondents did co-operate with the applicant, but I shall not do so by weighing the allegedly aggravating factors in the scale so as to possibly increase the proper penalties and then by weighing the degree of co-operation to see whether the scale tilts in favour of a discount. The alleged aggravating factors are simply matters which are part of the picture as to the extent of the respondents’ co-operation and so as to the amount, if any, of the discount for their co-operation from what would otherwise be the proper penalties.

235    In Rural Press Ltd v Australian Competition and Consumer Commission [2002] FCAFC 213; (2002) 118 FCR 236, the Full Court of this Court considered whether co-operation in the conduct of the trial could and should be taken into account in the fixing of the appropriate pecuniary penalty. The Full Court said that the conduct of the trial should not have been taken into account in fixing penalty, although it was something to which regard might have been had in relation to the appropriate orders as to costs.

236    The AER submits that the way in which PPPL conducted its defences at trial is an aggravating circumstance and that should be reflected in the pecuniary penalties which are imposed. The submission is linked to the AER’s service on PPPL before trial of notices under s 28 of the NEL seeking information from PPPL and PPPL’s responses to those notices. The AER does not complain of PPPL’s responses to the notices. It does not suggest that PPPL did not comply with the notices or that PPPL’s responses to the notices involved the provision of information which PPPL knew was false or misleading in a material particular. The AER’s submission is that PPPL’s responses to the notices were appropriate or, at least, not inappropriate in a relevant sense, whereas at trial, PPPL sought to run defences inconsistent with its responses to the s 28 Notices or to raise matters which should have been, but were not, in the responses to the notices. The differences were so marked, so the AER’s argument goes, that PPPL’s conduct at trial was an aggravating circumstance.

237    The AER submits that PPPL’s conduct was “exceptional” and that justifies an approach different from the approach ordinarily taken. As to the period before trial, co-operation with the regulatory authority is treated as a mitigating factor and a lack of co-operation is not treated as an aggravating factor. As to the trial, co-operation may be a mitigating factor, although there is authority the other way, but a lack of co-operation by way of putting the regulatory authority to proof or taking technical points without apparent merit, while potentially relevant to costs, would not be aggravating conduct. There is authority that conduct at trial may be weighed in the balance in determining the discount for other “co-operative conduct”. At all events, AER accepts that PPPL was entitled to defend itself, but submits that the circumstances in this case are exceptional.

238    Between April 2017 and June 2019, the AER made requests of ENGIE to provide, on a voluntary basis, information about the alleged contraventions to the AER. ENGIE provided various responses to the requests. The AER issued an infringement notice under s 74 of the NEL to PPPL on 6 December 2017. The AER then moved to the use of notices under s 28 of the NEL.

239    As I have said, on 6 December 2017, the AER issued an infringement notice under s 74 of the NEL to PPPL. The infringement notice alleged a contravention of cl 3.7.3(e)(2) of the NER. The particulars of the alleged contravention were as follows:

4.    PPPL’s short term PASA inputs for the 8 February 2017 trading day excluded the physical plant capability of generating unit GT12 in circumstances where the generating unit was in a wet storage state. When in a wet storage state, generating unit GT12 could physically be made available on 24 hours’ notice. PPPL had not contracted for fuel for that generating unit for that trading day. The availability of fuel is not relevant to the PASA availability input requirement pursuant to cl 3.7.3(e)(2).

5.    Accordingly, the AER alleges that by excluding the physical plant capability of generating unit GT12 from its short term PASA inputs for the 8 February 2017 trading day, PPPL breached clause 3.7.3(e)(2) of the NER in respect of PPCCGT.

240    The infringement penalty specified in the notice was an amount of $20,000. The notice made it clear that PPPL was not required to comply with the notice. The notice made it clear that if PPPL did pay the infringement penalty within the compliance period, then the AER would not institute proceedings in respect of the alleged breach unless the infringement notice was withdrawn before the end of the compliance period in accordance with s 79 of the NEL. Section 82 of the NEL provides that the payment of an infringement notice is not and must not be taken to be an admission of a breach of a civil penalty provision or admission of liability for the purpose of any proceeding instituted in respect of the breach.

241    PPPL did not pay the infringement notice. Initially, the AER placed some weight on the fact that PPPL did not pay the penalty of $20,000 and thereby avoided the expense and time associated with these proceedings. That argument was not pressed in closing oral submissions and I think rightly so. Non-payment of the infringement notice is not an aggravating factor, either alone or with other circumstances, particularly as it was the AER’s case at that point that the availability of fuel was irrelevant. By the time of the AER’s written outline of opening submissions, it was accepted by the AER that the availability of gas and gas transport was relevant to PASA availability.

242    I turn then to consider the AER’s submissions about the differences between PPPL’s responses to the notices served under s 28 and its conduct of the trial. Section 28 is in the following terms (relevantly):

(1)    If the AER has reason to believe that a person is capable of providing information or producing a document that the AER requires for the performance or exercise of a function or power conferred on it under this Law or the Rules, the AER may, by notice in writing, serve on that person a notice (a relevant notice).

(2)    A relevant notice may require the person to—

(a)    provide to the AER, by writing signed by that person or, in the case of a body corporate, by a competent officer of the body corporate, within the time and in the manner specified in the notice, any information of the kind referred to in subsection (1); or

(b)    produce to the AER, or to a person specified in the notice acting on its behalf, in accordance with the notice, any documents of the kind referred to in subsection (1).

(3)    A person on whom a relevant notice is served must comply with the relevant notice unless the person has a reasonable excuse.

Maximum penalty:

(a)    in the case of a natural person—$2 000;

(b)    in the case of a body corporate—$10 000.

(4)    A person must not, in purported compliance with a relevant notice, provide information that the person knows is false or misleading in a material particular.

Maximum penalty:

(a)    in the case of a natural person—$2 000;

(b)    in the case of a body corporate—$10 000.

…

243    On or about 15 June 2018, the AER issued its first section 28 Notice to International Power (Australia) Holdings Pty Ltd (IPAH) and PPPL responded to the notice on 16 August 2018. The AER issued its second section 28 Notice on 8 March 2019. In response to the second section 28 Notice on 29 March 2019, PPPL confirmed that the answers given by IPAH to the first section 28 Notice had been given with PPPL’s authority.

244    In the first section 28 Notice, Question 19 was in the following terms:

Between 11 November 2016 and 8 February 2017, state whether IPAH considered that it was possible to operate GT 11 and GT 12 concurrently under the existing Gas Supply Arrangements as described above in questions 15 and 17, and if so, the timeframe to bring the second gas turbine to a state of readiness to operate if required. In your response, provide the basis on which this view was based and details as to why IPAH considered that this was or was not possible.

In its response, PPPL said the following:

No, not under existing agreements for any period of length.

However, ENGIE is of the view that it was possible to operate GT11 and GT12 concurrently during the relevant period, subject to sufficient time to secure gas commodity and transportation capacity outside of those existing agreements, appropriate staffing levels at PPCCGT, and sufficient time being available, having regard to environment and safety concerns.

ENGIE did not operate the two GTs concurrently for commercial reasons. In ENGIE’s view at the relevant point in time, a 12-hour timeframe would likely be sufficient to enable it to operate the two GTs concurrently, if directed to do so. The amount of time these two plants could have run would be variable and most achievable if limited to a number of hours only.

245    Question 23 in the first section 28 Notice was in the following terms:

In addition to the Gas Supply Arrangements identified in Questions 15 and 17 above, state what sources of short term or ad hoc Gas Supply Arrangements for gas commodity or transportation including, but not limited to, the Short Term Trading Market (STTM) or Available Interruptible Capacity (AIC) were available, or may have been available, to IPAH for use at PPCCGT, including in the event of a NEL section 116 or NER 4.8.9 direction:

(a)    between 1 April 2015 and 10 November 2016; and

(b)    between 11 November 2016 and 8 February 2017?

PPPL’s response to this question included the following:

There were no material differences between the periods in terms of our ability to procure “may have been available” gas.

ENGIE suspects that in most circumstances (ignoring pipeline outage windows) PPCCGT could have procured sufficient gas supply in order to comply with a direction, assuming a direction is likely to extend for hours at a time only.

It is not practicable or possible to outline all sources as the list is limitless and every scenario is different. But between existing pipeline contracts, trading of pipeline capacity with others, overrunning pipeline contracts and buying gas from OTC markets, diverting from portfolio (including Synergen) and buying from markets (notional flows) PPPT could potentially have turned on for a unknown number of hours in most situations.

Also in the event of a direction, the participants’ ability to access short-term supplies likely increases, as demonstrated in these scenarios. ENGIE has made such support it has received from counterparties in responding to such directions clear to SA Government.

246    As the AER noted, PPPL went on in its response to outline the additional sources of potential gas supply and gas transport in its answer to Question 25.

247    Question 30 in the first section 28 Notice was as follows:

State what strategies, policies, procedures or guidelines were in effect at IPAH to secure short term or ad hoc Gas Supply Arrangements for gas commodity or transportation for PPCCGT between 11 April 2015 and 8 February 2017, either:

(a)    in response to a NEL section 116 or NER clause 4.8.9 direction from AEMO;

(b)    in response to AEMO entering into, or seeking to enter into, a RERT contract with IPAH in relation to GT 11; or

(c)    for any other reason, including commercial reasons.

PPPL’s response to this question was as follows:

Working in a dynamic commercial environment requires appropriately skilled and capable staff who are able to exercise judgement and draw on a range of personal and professional attributes to represent the company’s interests. It is not usual to expect such work to be bound by procedures.

Thus, no separate guidelines or procedures in effect would make any of these events different. What would dictate how things would work day to day would be the timing (time and day of week of request), notice period (how soon such gas is required), firmness of the request (whether it was made in a ‘just in case’ capacity or they had committed to run operation), magnitude of the request (how many hours of running was required and for how many consecutive days).

Once a need or opportunity is identified, a member of the appropriate team (spot or origination or both) would analyse the portfolio, and work out what additional sources of gas would be required and would then make the appropriate arrangements.

Both the spot and origination team are fully empowered to enter into such contracts on the companies’ behalf as outlined in the risk policy.

248    The key points to emerge from these answers are as follows:

(1)    PPPL considered between 11 November 2016 and 8 February 2017 it could have run two turbines concurrently on approximately 12 hours’ notice, but only for a limited number of hours;

(2)    PPPL suspects it could have obtained sufficient gas supply to run both generators concurrently for “hours at a time only” and the sources included diverting gas from its overall portfolio, including Synergen;

(3)    Additional gas transport may be obtained from “EPIC Synergen Service (10TJ) + Non-Firm Transport (20TJ)”;

(4)    Although there is reference in one of the questions in the notice (i.e., Question 18), to MHQ and MDQ, there is no reference to those matters presenting a barrier to PPPL operating both turbines concurrently, albeit for a limited number of hours;

(5)    PPPL had an opportunity to raise as a relevant consideration the physical condition of GT12 (see Question 20 and the response thereto), but instead said without reference to the physical condition of GT12 the following:

Given both units were not available; ENGIE had no intention to operate the units concurrently and such assessments were not made. Nevertheless, ENGIE was continuing to examine opportunities to return both units to market underpinned by longer-term arrangements. Once those arrangements were secured, both units returned to market.

249    The AER emphasised the differences between these matters and PPPL’s case in this proceeding. It referred first to para 22 of PPPL’s Amended Response to Concise Statement in which PPPL denied that it had contravened cl 3.7.3(e)(2) and alleged that in circumstances where PPPL only had gas supply and gas transport contracts with rights to operate one or other of GT11 and GT12, the portion of physical plant capability of the Pelican Point PS that was available or that “can be made available” did not exceed 239 MW in the relevant period.

250    Furthermore, the AER referred to the evidence of Mr Weatherly in his first affidavit which I summarised in PPPL No 1 (at [420]–[421]). Mr Weatherly considered that the only prudent way to run two turbines concurrently was to enter into new contracts for gas supply and gas transport and it is likely those contracts would have had to have been reasonably long term contracts.

251    AER submits that PPPL’s case was squarely rejected by the Court. With respect to the supply of gas, I found that the evidence supported a finding that prior to 8 February 2017, PPPL ought to have reasonably expected to be able to obtain sufficient additional gas to run GT11 and GT12 in accordance with the 8 February counterfactual. PPPL was obtaining relatively large quantities of non-firm gas in the ordinary course of its business and the additional amount to operate GT12 for four hours was relatively small. In addition, the thrust of the evidence of both Mr Weatherly and Mr O’Farrell was that the real problem was gas transport, rather than the gas itself, or, at least, gas transport was more of a problem (at [527]). With respect to gas transport, I found that for a period prior to 8 February 2017, PPPL ought to have reasonably expected that it could have secured the additional gas transport required to operate GT11 on 8 February 2017 and GT12 for four hours. That period commenced upon the issuing of Revision 1 of the Scheduled Quantities Report for 8 February 2017. PPPL was clearly able to secure substantial interruptible capacity on the PCA pipeline in the period leading up to 8 February 2017. PPPL’s heavy reliance on interruptible capacity in the course of its ordinary business operations reflected its confidence in its availability and relatively speaking, the amount of additional gas required was not large. The possibility of late changes under the nomination and renomination provisions under the PCA contract did not prevent a reasonable expectation arising of the additional gas transport being secured.

252    The essence of the first two matters set out above (at [248]) is the comparison with PPPL’s case at trial. PPPL advanced a substantially more pessimistic case as to the availability of gas and gas transport than it had in its response to the first section 28 Notice issued.

253    In terms of the third matter, the next alleged departure between PPPL’s response to the first section 28 Notice and the approach it advanced at trial relates to the diversion of gas from other companies in the portfolio. This is a possibility referred to in the answer to Question 23. It is also referred to in PPPL’s response to Question 25. In that response, there is a reference in the context of ad hoc gas transportation to the following:

EPIC Synergen Service (10TJ) + Non-Firm Transport (20TJ)

254    The AER contrasts this answer with the approach that PPPL took at trial. In this respect, see the evidence and argument summarised in PPPL No 1 (at [501]). Furthermore, both Mr Snow and Mr Weatherly were cross-examined on whether the intra-portfolio agreements were truly firm. The AER submits that the Court ultimately rejected the argument (at [502]–[503]) and that PPPL’s response to the first section 28 Notice was correct.

255    In terms of the fourth matter, PPPL made no reference in its response to the first section 28 Notice to the relevance of hourly (MHQ) and 12 hourly (M12HQ) constraints in the PCA contract and as noted in PPPL No 1, the hourly and 12 hourly constraints were not expressly raised by PPPL as being an issue in its Concise Response or in the Joint List of Issues and Evidence (at [622]). It was also noted that in the first round of PPPL’s evidence of which Mr O’Farrell’s first report was a part, neither Mr Foulds in his affidavit nor Mr Weatherly in his first affidavit addressed the hourly or 12 hourly constraints (at [625]). The first time that it was raised was in Mr O’Farrell’s report which was served two months prior to trial.

256    The AER’s point is that this issue was raised late and that it significantly complicated and prolonged the forensic contest at trial. It features as a central, if not the central, point of debate between the experts in conclave and reference is made to the joint report at Questions 2, 3, 4 and 5. There was extensive cross-examination of Mr Snow on the topic. PPPL served a second affidavit of Mr Weatherly on 22 July 2021 and part of that affidavit sought to explain how PPPL was able to run two turbines on 9 February 2017 consistent with the hourly and 12 hourly constraints. The AER responded with the second report of Mr Snow which identified that PPPL had, in fact, made the hourly and 12 hourly constraints on the PCA pipeline practically irrelevant by the practising of over-nominating. Mr Snow was further cross-examined on the topic. Mr O’Farrell was cross-examined extensively on the topic of hourly and 12 hourly constraints. The Court dealt with the relevance of the hourly and 12 hourly constraints and those matters occupied a substantial section in PPPL No 1 (at [618]–[653]). The Court’s conclusion was that the hourly and 12 hourly constraints were not obstacles to running GT11 and GT12 concurrently.

257    Finally, and in terms of the fifth matter, the AER submits that a major issue raised at the trial was the physical condition of GT12. The AER referred to Question 52 in the first section 28 Notice and the answer thereto:

In relation to the decision(s):

(a)    to move GT 12 from dry storage to wet storage on or around 11 November 2016, or otherwise to change the storage state of either GT 11 or GT 12 during the period 11 November 2016 to 8 February 2017; and/or

(b)    to operate either GT 11 or GT 12 individually, or both units concurrently, including but not limited to, the use of one unit as a back-up in case of any outage of the other unit, during the period 11 November 2016 to 8 February 2017.

For each such decision, state:

(i)    the nature of the decision made;

(ii)    the date of the decision;

(iii)    the person(s) at IPAH who made the decision(s) including their full name, position and roles and responsibilities; and

(iv)    the rationale, justification or reasoning for the decision.

PPPL answered this question as follows:

Wet storage is the default mode of storage, unless a unit is likely to be out of service for an extended period. A decision to place the unit in dry storage is taken by the Pelican Point O&M manager in consultation with a range of other personnel including traders, station chemist, engineers, and the asset manager.

Documents relevant to such decisions have been provided. Please see Question 10 and Question 13.

258    I agree with the submission by the AER that PPPL’s response does not engage with Question 52(b). If the physical condition of GT12 had in truth been a reason why GT12 could not be operated concurrently with GT11 on 8 February 2017, then PPPL had an opportunity to provide such explanation by reason of the question referring to “the rationale, justification, or reasoning for the decision”. The AER complains that the issue was but faintly raised in PPPL’s Amended Response to Concise Statement and the Joint List of Issues and Evidence and that it had objected to the issue being raised. At trial, the argument was rejected (at [670]–[671]). The AER submits that PPPL’s conduct squarely falls within the relevant factor of a disposition to co-operate with the AER in relation to the contravention or otherwise.

259    As I have said, the AER contends that PPPL’s conduct as outlined above was antithetical to the ethos of co-operation with regulators that the Courts have been astute to promote and that PPPL sought to “undo” the admissions and response it had previously given under compulsion to answer accurately, in a groundless attempt to escape liability for its contravening conduct. The AER submits that this conduct is an aggravating factor and justifies a higher penalty amount.

260    I do not accept the AER’s submission. Assuming there may be cases in which a respondent’s conduct in the proceeding itself may constitute an aggravating circumstance for the purpose of determining the appropriate pecuniary penalty, such a case would be rare. This is not such a case. It is necessary to maintain the principle that a respondent is entitled to defend itself and that departures from the desired approach to litigation can be dealt with in determining the issue of costs.

Conclusions with respect to the civil penalty to be imposed

261    Both parties submitted that, irrespective of the number of contraventions, one civil penalty should be imposed. In my opinion, that approach is correct for a number of reasons. First, the number of contraventions does not provide a reliable guide to the appropriate civil penalty. The maximum penalty by reference to the number of contraventions is $19,350,000. Secondly, this case involves a single course of conduct over a relatively short period of time and involved a relatively small number of changes to previous submissions. Thirdly, it is not without significance that although AEMO’s system meant that the ST PASA submissions was incorrect for each of the 48 trading intervals, on the case advanced by the AER, that is, the 8 February counterfactual, a generating capacity of 320 MW was only achievable for eight trading intervals, that is, four hours. The AER submits that a civil penalty of $3 million is appropriate, whereas PPPL submits that a civil penalty of $500,000 is appropriate.

262    I have reached the conclusion that the appropriate civil penalty is $900,000. In reaching that conclusion, I have had regard to all of the matters set out above and the need for general and specific deterrence. Nevertheless, there are some particular matters which I would emphasise.

263    First, GT12 was brought from dry storage to wet storage so that it would be available to be used interchangeably with GT11. It was a backup turbine to ensure market needs were met on very extreme days and that reliability of supply was assured to the greatest extent possible. It was not in dispute that PPPL’s intention throughout was to operate one generator and provide a generating capacity of 240 MW.

264    Secondly, the contraventions were not deliberate or intentional and they occurred because of PPPL’s misunderstanding of the requirements of the relevant rules and a focus by PPPL on its commercial intention to operate only one turbine and a lack of firm gas supply.

265    Thirdly, PPPL gained no commercial benefit from making the PASA submissions it did. This is not a case where the civil penalty needs to be of a sufficient size to ensure the contravenor does not see the penalty as the cost of doing business.

266    Fourth, PPPL’s contraventions did not lead to the load shedding which occurred on 8 February 2017 and nor would it have been reduced in duration had the contraventions not occurred. PPPL’s contraventions did not have a specific impact on customers and nor did those contraventions cause any financial losses. At the same time, it must be acknowledged and taken into account that the nature of the obligations breached are important and are intended to enable AEMO to manage the reliability of the power system.

CONCLUSIONS

267    The following declarations will be made:

(1)    By each of its four short term PASA submissions made between 6 February 2017 at 11:00 and 7 February 2017 at 11:25 identified below for each of the future trading intervals during the 8 February 2017 trading day identified below, the respondent contravened cl 3.7.3(e)(2) of the National Electricity Rules (NER) by submitting short term PASA availability values of 220 MW that did not represent its current intentions and best estimates as to the physical plant capability of the Pelican Point Power Station that could be made available on 24 hours’ notice which was 320 MW.

(2)    The respondent contravened cl 3.13.2(h) of the NER by failing to notify the Australian Energy Market Operator (AEMO) promptly on or after 3 February 2017 that the medium term PASA availability of the Pelican Point Power Station for 8 February 2017 which the respondent previously submitted to AEMO on 27 January 2017 had increased from 224 MW to 320 MW.

268    In addition, there will be an order as follows:

(3)    With respect to the contraventions identified in the aforesaid declarations, Pelican Point Power Ltd pay a civil penalty of $900,000.

269    I will hear the parties as to costs.

Associate:    

Dated:    27 March 2024

Annexure A