FEDERAL COURT OF AUSTRALIA

Australian Energy Regulator v Pelican Point Power Ltd [2023] FCA 1110

ORDERS

THE COURT ORDERS THAT:

1.    The applicant prepare draft minutes of order reflecting the conclusions in these reasons and/or the orders sought as to the future progress of this proceeding and serve on the respondent and lodge with the Court such draft minutes of order within seven days.

2.    The proceeding be adjourned to a date to be fixed after consultation with the parties.

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

REASONS FOR JUDGMENT

BESANKO J:

INTRODUCTION

1    This is an application by the Australian Energy Regulator (the AER) for declaratory relief 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.

2    The AER seeks three declarations. 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. PASA is an acronym for Projected Assessment of System Adequacy. It is described in cl 3.7.1 of the NER as involving processes that are administered by the Australian Energy Market Operator (AEMO). Further details of the concept and the relevant Rules are set out below.

3    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.

4    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.

5    The AER also seeks the imposition of civil penalties on PPPL in respect of the contraventions. The relevant Rules referred to in the declarations (i.e., cll 3.7.2(d)(1), 3.7.3(e)(2) and 3.13.2(h) of the NER) are each designated as a civil penalty provision: the NEL s 2AA; the National Electricity (South Australia) Regulations, reg 6(1) and Schedule 1.

6    At an early stage in these proceedings, the Court made an order that the issue of whether PPPL contravened the NER be tried separately from, and in advance of, the determination of what relief (including civil penalty) should be granted.

7    In the course of the proceeding, two major procedural issues arose. The case proceeded by way of a Concise Statement and a Concise Response. The proceedings were fixed for trial and before the trial, the parties filed and served lengthy and detailed opening submissions. As a result of that process, an issue arose between the parties about the scope of their respective cases. That led to an Interlocutory application by the AER and an issue as to whether each party proposed to run a case that went beyond the scope of its “pleadings”. I rejected PPPL’s submission that the AER proposed to run a case beyond the scope of its pleaded case and I refused PPPL’s subsequent application for an adjournment of the trial. At a later point in the trial, I rejected the AER’s objection to evidence about the physical condition of one of the gas turbines as being beyond the scope of PPPL’s pleaded case. The AER did not seek an adjournment following this ruling.

8    The trial commenced and proceeded for a number of days before it had to be adjourned for a number of months because the time allocated for the trial (based on the parties’ estimates) proved to be insufficient. Before the resumption, PPPL issued an Interlocutory application seeking leave to rely on a further report from its expert (Mr Andrew O’Farrell) and a further affidavit from one of its proposed witnesses (Mr Michael Weatherly). Leave was required because an order had been made for each party to file and serve its evidence in written form prior to the commencement of the trial. I granted that leave subject to conditions that would enable the AER to file responding evidence which it subsequently did.

9    Complaints by PPPL about the scope of the AER’s case and the notice it was given of the case lingered until the end of the trial. It is convenient for me to describe briefly how the case was pleaded and the issues identified.

THE CASE AS PLEADED

10    The AER issued a Concise Statement in support of its Originating application and an order was made that PPPL file and serve a Concise Response.

11    The AER’s case as pleaded was that PPPL was the operator of the Pelican Point PS and contravened cll 3.7.2(d), 3.7.3(e) and 3.13.2(h) of the NER by failing to disclose to AEMO all of the physical plant capability that could be made available on 24 hours’ notice for 8 February 2017 by the Pelican Point PS, as part of its PASA availability for that day.

12    The relevant version of the NER is version 88 and the directly relevant rules are as follows:

3.7.2    Medium term PASA

(d)    The following medium term PASA inputs must be submitted by each relevant Scheduled Generator or Market Participant in accordance with the timetable:

(1)    PASA availability of each scheduled generating unit, scheduled load or scheduled network service for each day taking into account the ambient weather conditions forecast at the time of the 10% probability of exceedence peak load (in the manner described in the procedure prepared under paragraph (g)); and

(2)    weekly energy constraints applying to each scheduled generating unit or scheduled load.

Note

This clause is classified as a civil penalty provision under the National Electricity (South Australia) Regulations. (See clause 6(1) and Schedule 1 of the National Electricity (South Australia) Regulations.)

3.7.3    Short term PASA

(e)    The following short term PASA inputs must be submitted by each relevant Scheduled Generator and Market Participant in accordance with the timetable and must represent the Scheduled Generator’s or Market Participant’s current intentions and best estimates:

(1)    available capacity of each scheduled generating unit, scheduled load or scheduled network service for each trading interval under expected market conditions;

(2)    PASA availability of each scheduled generating unit, scheduled load or scheduled network service for each trading interval; and

(3)    [Deleted]

(4)    projected daily energy availability for energy constrained scheduled generating units and energy constrained scheduled loads.

Note

This clause is classified as a civil penalty provision under the National Electricity (South Australia) Regulations. (See clause 6(1) and Schedule 1 of the National Electricity (South Australia) Regulations.)

3.13.2    Systems and procedures

(h)    A Scheduled Generator, Semi-Scheduled Generator or Market Participant must notify AEMO of, and AEMO must publish, any changes to submitted information within the times prescribed in the timetable.

Note

This clause is classified as a civil penalty provision under the National Electricity (South Australia) Regulations. (See clause 6(1) and Schedule 1 of the National Electricity (South Australia) Regulations.)

13    Chapter 10 of the NER contains a glossary of terms.

Available capacity is defined as follows:

The total MW capacity available for dispatch by a scheduled generating unit, semi-scheduled generating unit or scheduled load (i.e. maximum plant availability) or, in relation to a specified price band, the MW capacity within that price band available for dispatch (i.e. availability at each price band).

Physical plant capability is defined as follows:

The maximum MW output or consumption which an item of electrical equipment is capable of achieving for a given period.

PASA availability is defined as follows:

The physical plant capability (taking ambient weather conditions into account in the manner described in the procedure prepared under clause 3.7.2(g)) of a scheduled generating unit, scheduled load or scheduled network service available in a particular period, including any physical plant capability that can be made available during that period, on 24 hours’ notice.

A scheduled generating unit is defined as follows:

(a)    A generating unit so classified in accordance with Chapter 2.

(b)    For the purposes of Chapter 3 (except clause 3.8.3A(b)(1)(iv)) and rule 4.9, two or more generating units referred to in paragraph (a) that have been aggregated in accordance with clause 3.8.3.

A generating unit is defined as follows:

The plant used in the production of electricity and all related equipment essential to its functioning as a single entity.

The word change is defined as follows:

Includes amendment, alteration, addition or deletion.

14    The definition of PASA availability is of central importance in this case and particularly that part of the definition that refers to “any physical plant capability that can be made available [during a particular period] on 24 hours’ notice”.

15    The AER alleges in its Concise Statement that the Pelican Point PS is an aggregated scheduled generating unit with a registered capacity of 478 megawatts (MW). It consists of two 160 MW gas turbines (designated GT11 and GT12 respectively) and a 158 MW steam turbine. The steam turbine is required to operate in conjunction with one or both gas turbines so that the Pelican Point PS can operate with a maximum capacity of 239 MW if only one gas turbine is operated, and a maximum capacity of 478 MW if both gas turbines are operated.

16    In its Concise Response, PPPL admits the description of the gas and steam turbines and the nameplate capacity of the Pelican Point PS.

17    The AER alleges and PPPL admits, subject to some qualifications which I will identify, that when the gas turbines are not operating, they are either in wet storage, from which they can be returned to operation relatively quickly, that is to say, in approximately four hours or less, or they are in dry storage from which they can be returned to operation in approximately four days. On 11 November 2016, GT12 was moved from dry to wet storage and that meant that from that date to at least 8 February 2017, GT11 and GT12 were in either operation or in wet storage, and were used interchangeably as the operational gas turbine at the Pelican Point PS and, to the extent that one of those gas turbines was not already in service, it could have been returned to operation in approximately four hours or less.

18    PPPL’s admissions as to these matters are qualified to the following extent. The first qualification is that the ability to return a gas turbine to operation is subject to PPPL having rights to gas supply and transport to operate one or both of those gas turbines. The second qualification is that the ability to return a gas turbine to operation is subject to contingencies, namely, GT11 remaining in operation and not having been removed from operation for repair or being in intermittent dry storage and GT12 being able to be used in a continuous manner in circumstances where (on PPPL’s case) it required significant overhaul works. Those qualifications are set out in PPPL’s Concise Response.

19    The AER’s case as to the nature of the PASA Disclosure Regime and the requirements of the regime is as follows. PPPL is a Scheduled Generator (a generator in respect of which a generating unit is classified as a scheduled generating unit in accordance with Chapter 2 of the NER) and is required to submit medium term PASA (MT PASA) inputs to AEMO under cl 3.7.2(d), and short term PASA (ST PASA) inputs under cl 3.7.3(e).

20    MT PASA inputs are defined as the inputs to be prepared in accordance with cll 3.7.2(c) and (d) and ST PASA inputs are defined as the inputs to be prepared in accordance with cll 3.7.3(d) and (e).

21    The AER alleges and PPPL admits that these inputs are important to AEMO’s ability to maintain power system security which is a defined term in the NER as follows:

The safe scheduling, operation and control of the power system on a continuous basis in accordance with the principles set out in clause 4.2.6.

22    Power system is defined in the NER as follows:

The electricity power system of the national grid including associated generation and transmission and distribution networks for the supply of electricity, operated as an integrated arrangement.

23    MT PASA inputs must be submitted to AEMO for each day over a 24 month forecast period, in accordance with the timetable published by AEMO, at least weekly or as changes occur. These inputs include the PASA availability of each scheduled generating unit for each day (MT PASA availability) (cl 3.7.2(d)(1)).

24    Timetable is defined in the NER as follows:

The timetable published by AEMO under clause 3.4.3 for the operation of the spot market and the provision of market information.

25    ST PASA inputs must be submitted to AEMO for each 30 minute trading interval over a forecast period of six trading days, in accordance with the timetable published by AEMO, at least daily or as changes occur. Unlike the clause dealing with MT PASA which contains no express statement as to what they must represent, the clause dealing with ST PASA inputs provides that they must represent the Scheduled Generator’s current intentions and best estimates. These inputs include the PASA availability of each scheduled generating unit for each trading interval (ST PASA availability) (cl 3.7.3(e)(2)).

26    Trading interval is defined in the NER as follows:

A 30 minute period ending on the hour (EST) or on the half hour and, where identified by a time, means the 30 minute period ending at that time.

Trading day is defined in the NER as follows:

The 24 hour period commencing at 4.00 am and finishing at 4.00 am on the following day.

27    A Scheduled Generator must notify AEMO of any changes to submitted information as changes occur (cl 3.13.2(h) and the timetable).

28    Subject to a number of significant differences about what the PASA Disclosure Regime requires in particular circumstances and the raising of some additional matters, PPPL in its Concise Response largely admitted with what is set out above.

29    The additional matters alleged by PPPL in its Concise Response are as follows. PPPL alleges that the Pelican Point PS is a “mid-merit” power station, that is to say, that it does not produce “base-load” power. PPPL alleges that in June 2014, it made a commercial and operational decision to “mothball” (i.e., retire or withdraw or place in reserve) half of Pelican Point PS’s generating capacity indefinitely for the following reasons. First, PPPL made this decision because it had incurred financial losses in the period leading up to the decision because of sustained periods of unfavourable market conditions and a view which it held that these conditions would continue indefinitely. Secondly, PPPL made this decision because of the physical condition of GT12 which it alleges required significant overhaul works and a capital commitment in order to be used in a continuous manner.

30    PPPL implemented its decision on 1 April 2015. PPPL alleges in its Concise Response that from that time to at least 8 February 2017, its rights under its gas supply and transport contracts only provided enough gas to make available a maximum of 239 MW, rather than the registered total capacity of the Pelican Point PS of 478 MW. It further alleges that it revised its MT PASA and ST PASA inputs “to reflect the portion of the Physical Plant Capability of Pelican Point PS that was available (including that portion of the Physical Plant Capability that ‘can be made available’) in the relevant period”.

31    PPPL alleges in its Concise Response that Mr Darren Foulds is the Origination Manager at International Power (Australia) Pty Ltd trading as ENGIE which is the owner of PPPL. ENGIE trades in the energy generated by those assets in the National Electricity Market (NEM). Mr Peter Adams is the General Manager of Wholesale Markets at AEMO and Mr Joe Spurio is the Acting Chief Operating Officer at AEMO. PPPL alleges that in a conversation with Mr Adams in June 2014 and in a subsequent email to Mr Spurio on 27 June 2014, Mr Foulds communicated to AEMO that PPPL intended to mothball half of its generation capacity at the Pelican Point PS from 1 April 2015 and its intention to revise its MT PASA inputs to reflect the reduction in its gas supply and transport contracts and the consequential reduction of generation capacity.

32    PPPL alleges that from 1 April 2015 to at least 8 February 2017, its MT PASA inputs and its ST PASA inputs for the Pelican Point PS had halved to a maximum of 239 MW reflecting the portion of the physical plant capability of the Pelican Point PS that was available in the relevant periods. PPPL asserts that neither AEMO nor the AER took issue with PPPL’s approach.

33    PPPL alleges that from 1 April 2015 to at least 8 February 2017, it operated its gas turbines in the following way. At certain times, PPPL moved its two gas turbines at the Pelican Point PS into dry storage (generally during the winter months) and into wet storage (generally during the summer months). The physical condition of GT12 meant that it was operated as a “back-up” unit and was moved into wet storage at certain times so that if GT11 failed or needed maintenance, the period during which the Pelican Point PS may have been off-line altogether was minimised or avoided. The operation was conducted in this way to ensure PPPL could continue to make available that portion of the physical plant capability notified in its PASA submissions. In the period from 1 April 2015 to at least 8 February 2017, and despite the fact that GT12 was moved into wet storage on occasions, PPPL did not amend its current gas supply and transport contracts or enter into new contracts so as to enable the Pelican Point PS to make available generation capacity in excess of a maximum of 239 MW and nor, on its case, did it estimate or intend that the Pelican Point PS would make available generation capacity in excess of a maximum of 239 MW.

34    A key issue in this case concerns the precise nature of the requirements of the PASA Disclosure Regime. I have already referred to the importance of the definition of PASA availability.

35    An important aspect of PPPL’s case as set out in its Concise Response and relevant to that issue is its allegation the PASA Disclosure Regime did not require disclosure of a portion of the physical plant capability of the Pelican Point PS that is not available and is not estimated or intended by the operator to be made available in the relevant period and could be said to be no more than theoretically available after a period of ramp up and subject to contingencies, including the following contingencies: (1) GT11 remaining in operation and not having been removed from operation for repair or being in intermittent dry storage; (2) GT12 being able to be used in a continuous manner in circumstances where it required significant overhaul works; and (3) the availability of gas supply and transport to enable the Pelican Point PS to make available generation capacity in excess of a maximum of 239 MW.

36    PPPL further alleges that the moving of GT12 from dry storage to wet storage, or from wet storage to dry storage, did not result in a change in the portion of physical plant capability of the Pelican Point PS for the purposes of cll 3.7.3(e)(2), 3.7.2(d)(1) or 3.13.2(h) of the NER and there was no requirement for PPPL to notify AEMO of any change to its PASA inputs.

37    As I will explain, the AER disputes these propositions or, at least, disputes them to the extent that it is said they provide the answers to the issues in this case.

38    The AER alleges and PPPL admits that on 9 February 2015, PPPL first submitted to AEMO that its MT PASA availability for 8 February 2017 was 224 MW and that between 9 February 2015 and 8 February 2017, PPPL submitted to AEMO on numerous further occasions, including on 10 occasions from 11 November 2016, that its MT PASA availability for 8 February 2017 was 224 MW (MT PASA submissions). The AER contends that PPPL was under an obligation which it did not discharge, to notify AEMO of the change to its MT PASA submissions after 11 November 2016 to reflect the fact that GT12 had been brought from dry storage to wet storage and nor did its subsequent MT PASA submissions reflect the fact that GT12 had been brought into wet storage. PPPL admits the absence of notification to AEMO, but denies that the NER required it to provide notification.

39    The AER alleges and PPPL admits that PPPL first submitted ST PASA availability for each trading interval in the 8 February 2017 trading day on 15 January 2017, and subsequently submitted its ST PASA availability for trading intervals in the 8 February 2017 trading day on 27 further occasions (ST PASA submissions). The highest ST PASA availability value that PPPL submitted for any of the trading intervals for the 8 February 2017 trading day was 235 MW. The submissions did not reflect the fact that GT12 had been brought from dry to wet storage. PPPL contends that it was not required to notify any greater PASA availability and that to have done so “would have been inaccurate and misleading to AEMO and to participants in the energy trading, derivatives and financial markets generally”.

40    I come then to the AER’s case as to events on 8 February 2017 as set out in its Concise Statement. The AER alleges that it was on that day at 17.39 that AEMO first became aware that GT12 was potentially available to return to operation within 24 hours’ notice. On that day, Adelaide recorded a maximum temperature of 42.4oC. During the afternoon, AEMO notified the market of forecast lack of reserve (LOR) with a forecast LOR1 issued at 15.18.

41    A lack of reserve level 1 (LOR1) is defined in cl 4.8.4 of the NER as follows:

(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.

42    An actual LOR1 was issued at 16.31. At 17.13 an actual LOR2 was issued. A lack of reserve level 2 (LOR2) is defined in cl 4.8.4 of the NER as follows:

(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.

43    At 17.25, electricity import flows across the Murraylink interconnector between South Australia and Victoria increased above its import limit, which resulted in the power system no longer being in a secure operating state in the South Australian region. As a consequence, AEMO was obliged under cll 4.2.6(b)(1) and 4.8.7 to take all reasonable steps to return the power system to a secure operating state, including by issuing directions, including, as a last resort, a direction to initiate load shedding. Load shedding is reducing or disconnecting from the power system and, speaking broadly, load is the electrical power at a connection point.

44    At 17.39, while the power system was not in a secure operating state, AEMO contacted PPPL to enquire whether GT12 was available to respond to a direction. PPPL responded that it did not have gas available to run GT12, but that if gas was available, GT12 could be made available on a minimum lead time of four hours. The AER alleges that this was the first time that AEMO was made aware that GT12 was potentially available to return to operation within 24 hours’ notice.

45    At 18.01, PPPL advised AEMO that GT12 could be made available, if necessary, within one hour.

46    At 18.03, AEMO issued a direction to ElectraNet (the operator of the transmission network in South Australia) to shed 100 MW of electrical load. This caused localised load shedding, that is, a loss of supply of electricity to customers in affected localities in South Australia. However, it also resulted in the power system being returned to a secure operating state.

47    PPPL’s response to these allegations by the AER about events on 8 February 2017 is an admission that it advised AEMO at about 17.39 (ACDT) that it did not have gas available to run GT12 concurrently with GT11 and an allegation by PPPL that the fact that GT12 was in wet storage and able to be returned to operation in four hours or less, subject to the availability of, and PPPL being able to negotiate contracts for, gas supply and transport during or at the end of that period, is irrelevant to the ST PASA availability of the Pelican Point PS in circumstances where PPPL did not have arrangements in place for gas supply or transport to run GT12 concurrently with GT11. PPPL further alleges that as at 17.39 on 8 February 2017, the ST PASA availability of Pelican Point PS still did not exceed 239 MW.

48    I have referred to conversations between representatives of AEMO and representatives of PPPL on 8 February 2017. Those conversations were recorded and aspects of the conversations are relied on by each party.

49    The AER alleges in its Concise Statement that events on 9 February 2017 are relevant to the MT PASA and ST PASA submissions that PPPL should have made for 8 February 2017. The AER’s case as to relevant events on 9 February 2017 is as follows. The forecast weather conditions for 9 February 2017 in South Australia were to the effect that heatwave conditions and high electricity demand would continue. Prior to 8 February 2017, PPPL had submitted that its MT PASA availability was 224 MW for each day in the week of 5 to 11 February 2017. By reason of AEMO becoming aware on 8 February 2017 that GT12 was capable of being returned to operation within one hour, AEMO was able to issue a direction to PPPL on 9 February 2017 to synchronise and dispatch GT12 in response to further forecast LOR2 conditions that afternoon. PPPL complied with that direction and that enabled AEMO to maintain power system security on 9 February 2017 without the need for load shedding.

50    PPPL alleges that its MT PASA availability was 224 MW for each day in the week of 5 to 11 February 2017. It admits that it was able to comply with the direction given by AEMO on 9 February 2017 to synchronise and dispatch GT12. It alleges that it was able to do that because after 17.39 on 8 February 2017, it had been able to arrange for gas supply and transport over and above its existing contractual rights. It alleges that the additional gas supply and transport that it arranged only in response to AEMO’s direction and the availability of both GT11 and GT12 on 8 February 2017 are, for reasons in its Concise Response, not relevant to the MT PASA and ST PASA submissions it made.

51    The way in which the AER put its case in its Concise Statement as to PPPL’s obligations with respect to ST PASA availability, MT PASA availability and the obligation in cl 3.13.2(h) may be summarised as follows.

52    PPPL, in relation to its 28 (amended now to 27) ST PASA submissions for each trading interval during the 8 February 2017 trading day, had an obligation (which it failed to discharge) to submit its ST PASA availability so as to reflect the true physical plant capability of the Pelican Point PS that could be made available on 24 hours’ notice. In addition, or in the alternative, PPPL, in relation to each of its 27 ST PASA submissions for each trading interval during the 8 February 2017 trading day, had an obligation (which it failed to discharge) to submit its ST PASA availability so as 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. PPPL denied these allegations for reasons previously given, including that it had gas and gas transport rights to generate no more than 239 MW in the relevant period.

53    By amendment to its Concise Response, PPPL introduced the following further response to the AER’s plea in relation to ST PASA submissions:

22A.    In further answer to paragraph 16 of the CS, PPPL says that:

(a)    clause 3.7.3(2)(e):

(i)    only required that PPPL make PASA availability submissions in respect of a trading interval where that interval was during the 6 trading days from the end of the trading day covered by the most recent pre-dispatch schedule issued by AEMO; and

(ii)    further, and in any event, did not require that PPPL make PASA availability submissions in respect of a trading interval that had already passed;

(b)    PPPL could not and did not contravene clause 3.7.3(2)(e) by reason of PASA availability submissions not required to be made in respect of the trading interval; and

(c)    PPPL could not and did not contravene clause 3.7.3(2)(e) in so far as any PASA availability submission related to a trading interval that had passed at the time of the submission to AEMO.

54    The AER alleges that PPPL had an obligation (which it failed to discharge) in relation to its MT PASA submissions for 8 February 2017 and in relation to each of its 10 MT PASA submissions made after 11 November 2016 to submit MT 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 GT12 was brought from dry to wet storage. PPPL, in relation to its MT PASA submissions for 11 February 2017, had an obligation (which it failed to discharge) to notify AEMO promptly on or after 11 November 2016 of the increased MT PASA availability of the Pelican Point PS after GT12 was brought from dry to wet storage on 11 November 2016.

FACTS WHICH ARE NOT IN DISPUTE

55    The following facts are taken from the Statement of Agreed Facts signed by both parties.

56    The AER is a body corporate established pursuant to s 44E of the CCA, and has the functions and powers referred to in s 15 of the NEL. PPPL is a company incorporated in England and Wales and is registered in Australia as a foreign company under s 601CE of the Corporations Act 2001 (Cth). It is wholly owned by International Power (Australia) Pty Ltd trading as ENGIE and previously known as GDF Suez. PPPL is the operator of the Pelican Point PS and is a Registered Participant and a Scheduled Generator within the NER.

57    Pelican Point PS is and was at all material times an aggregated scheduled generating unit under cl 3.8.3 of the NER comprising two gas turbines with designated identifiers GT11 and GT12 and one steam turbine, and scheduled plant within the NER to which AEMO may issue a direction to PPPL under cl 4.8.9(a) and (a1)(1). At all relevant times, Pelican Point PS had a registered capacity of 478 MW. The ability of PPPL to operate the Pelican Point PS at its registered capacity is directly affected by certain operating conditions, including but not limited to, the ambient air temperature, the physical condition of the gas turbines and the steam turbine, the availability of gas supply and the availability of gas transport (operating conditions). Subject to the operating conditions, at all relevant times each gas turbine was capable of generating up to approximately 160 MW. Subject to the operating conditions and subject to one or both of the gas turbines operating, at all relevant times the steam turbine was capable of being operated in conjunction with one or both of the gas turbines to generate up to approximately 79 MW, if only one of the gas turbines was in operation, and up to approximately 158 MW if both of the gas turbines were in operation. Again, subject to the operating conditions, at all relevant times, Pelican Point PS was capable of generating up to approximately 478 MW, if both of the gas turbines were operating in combination with the steam turbine, or up to approximately 239 MW, if only one of the gas turbines was operating in conjunction with the steam turbine. Again, subject to the operating conditions, at all relevant times, Pelican Point PS was capable of a minimum generating capacity of approximately 160–170 MW, if only one gas turbine was operating in conjunction with the steam turbine, or approximately 320–335 MW, if both gas turbines were operating in conjunction with the steam turbine. PPPL does not agree that minimum generating capacity is relevant to whether it has breached any of cl 3.7.2(d)(1), cl 3.7.3(e)(2) and/or cl 3.13.2(h). As I will explain, the 320 MW minimum generating capacity is significant because it is this figure which is relevant to “the basic 320 MW scenario” or, as PPPL referred to it, “the 320 MW, 4 hour ‘benchmark scenario’”.

58    Each of the gas turbines when not actively generating was kept in either wet storage or dry storage. In each case, assuming sufficient availability of gas supply, availability of gas transport and operational staff on duty to operate the turbine (among other matters), the parties agree that wet storage is the state from which the gas turbine could ordinarily be returned to service relatively quickly, that is to say, in approximately four hours or less. Dry storage is a state from which the gas turbine could be returned to service in up to four days, if the entire power station is in dry storage, or in 60 hours or less, if only one gas turbine and the associated steam turbine is in dry storage.

59    The parties agree that on 8 February 2017, the net (sent-out) Heat Rate for Pelican Point PS was 8.31GJ/MWh. The volume of gas required to operate either of the gas turbines at a given level of active power output is calculated by using the following formula: Gas Requirement (TJ) = run-time (hrs) x power output (MW) x Heat rate (GJ/MWh)/1000.

60    During the relevant period between 11 November 2016 and 9 February 2017, the relevant timetable was version 1.3 of the AEMO Spot Market Operations Timetable published on 28 October 2016. During the relevant period, for the purposes of cl 3.7.2(d)(a) and AEMO’s Medium Term PASA Process Description, the reference temperature published by AEMO as reflecting a 10% probability of exceedance peak load in South Australia was 43oC (as published in AEMO’s Generation information data for South Australia, the relevant versions of which were published on 11 August 2016 and 18 November 2016).

61    The parties agree that on about 25 June 2014, in the course of a meeting between Mr Foulds and Mr Stephen Orr of GDZ Suez and Mr Spurio of AEMO (which was followed up by an email from Mr Foulds to Mr Spurio sent on 27 June 2014 confirming the same), PPPL’s parent company, GDF Suez, notified AEMO of the following: (1) that from 1 April 2015, PPPL would have firm gas arrangements to support the operation of only half of the Pelican Point PS (240 MW); (2) PPPL had updated its MT PASA inputs to reduce the capacity of Pelican Point PS to 240 MW from that date; and (3) Pelican Point PS “poses no ability to deliver generation on the remaining capacity”.

62    On 9 February 2015, PPPL first submitted its MT PASA inputs for 8 February 2017. In each submission of its MT PASA inputs between 9 February 2015 and 11 November 2016, PPPL submitted that its PASA availability for Pelican Point PS on 8 February 2017 was 224 MW.

63    The parties agree that from 1 April 2015 until 11 November 2016, both of the gas turbines GT11 and GT12 were kept in dry storage substantially throughout the period from 1 April 2015 until 2 October 2015; GT11 was brought into wet storage from 2 October 2015 until 28 April 2016 when it was returned to dry storage; GT12 was brought into wet storage from 26 November 2015 until 22 January 2016 when it was returned to dry storage; both GT11 and GT12 were kept in dry storage from 18 April 2016 to 13 July 2016; and GT11 was brought from dry storage to wet storage on 14 July 2016, and PPPL thereafter operated GT11 (in conjunction with the steam turbine) from time to time to supply power in the NEM.

64    The parties agree that on 11 November 2016, PPPL brought GT12 from dry storage to wet storage. At all relevant times from 11 November 2016 until at least 8 February 2017, each of GT11 and GT12 was either in operation or in wet storage; and only one or the other of them was used as the operational gas turbine at any time. At all relevant times from 11 November 2016 until 8 February 2017, to the extent that one of those gas turbines was not already in operation, and subject to it not having been removed from operation for repair, it could have been returned to operation in approximately four hours or less if PPPL had access to, or could procure, sufficient gas supply and transportation to operate the gas turbine.

65    The parties agree that between 7 November 2016 and 8 February 2017, PPPL submitted its MT PASA inputs to AEMO on 11 occasions, in each case submitting that the PASA availability for Pelican Point PS on 8 February 2017 was 224 MW, with a value of 999999 for its weekly energy constraints, as set out in the following table:

66    PPPL did not change its MT PASA inputs at or around 11 November 2016, or at any time between 11 November 2016 and 8 February 2017.

67    The parties agree that on 15 January 2017, PPPL submitted its first ST PASA inputs for the 8 February 2017 trading day. The dates of PPPL’s submissions to AEMO of its ST PASA inputs for Pelican Point PS for the 8 February 2017 trading day, and the values submitted for available capacity, PASA availability and projected daily energy availability, in respect of each trading interval are set out in an exhibit before the Court. It is sufficient at this point to say that in each of those submissions, PPPL’s ST PASA inputs for Pelican Point PS for each trading interval for the 8 February 2017 trading day, the highest value of PASA availability submitted by PPPL was 235 MW.

OPERATING SCENARIOS

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.

69    In order to run a second turbine, there is a need for a supply of gas and gas transport. There is no dispute that to be able to be made available for the purposes of the definition of PASA availability means not just in wet storage, but there and able to be turned on and run for a period of time and thereby generate a maximum MW output. That assumes a quantity of gas and a quantity of gas transport. None of the definitions specify a particular time the turbine must run for the purposes of assessing availability. In other words, it is not to be assumed that an item of physical plant only meets the description of “can be made available” if it can be operated for the full day. There is nothing in the definitions to that effect. On the other hand, a certain amount of gas and gas transport must form an assessment of whether physical plant can be made available.

70    In order to prove its case, the AER needed to establish that the PASA submissions were too low and that PPPL should have reasonably expected (and I will come to address the precise formulation of the relevant standard) that it could have, on 24 hours’ notice, made GT12 available by switching it on and running it with GT11 to produce a greater amount of megawatts than those set out in the PASA submissions. The AER put forward two operating scenarios which it contends a reasonable generator would have had in mind when making PASA submissions.

71    The first operating scenario is what the AER referred to as the basic 320 MW scenario. This scenario involved both GT11 and GT12 operating for four hours concurrently and producing 320 MW. The second operating scenario is what the AER referred to as the 8 February counterfactual. This scenario involved GT11 operating on 8 February 2017 as it in fact did and GT12 operating on 8 February 2017 as it in fact operated on 9 February 2017. On 8 February 2017, GT11 operated for most of the day, but not always at the maximum amount specified in its PASA submissions. On 9 February 2017, GT12 was run concurrently with GT11 for about four hours.

72    Both these operating scenarios are, of course, hypothetical. However, they frame the issues concerning reasonable expectations as to the availability of gas supply and gas transport. No other operating scenarios were advanced by the AER.

THE EVIDENCE

73    The AER called four witnesses as follows:

(1)    Mr Tjaart Nicolaas Van Der Walt who is employed by AEMO as Group Manager, NEM Real Time Operations;

(2)    Ms Philippa Jean Eastgate who is employed by the AER as Assistant Director in its Compliance and Enforcement Branch;

(3)    Mr Michael Nicholas Sanders who is employed by AEMO as Principal Analyst, Electricity Market Monitoring; and

(4)    Mr James Arthur Snow, an expert who has extensive experience in the energy industry, including gas with both practical experience and experience as an adviser, reviewer and consultant.

74    PPPL called four witnesses as follows:

(1)    Mr Darren Foulds who is employed by ENGIE as Head of Trading and Portfolio Management;

(2)    Mr Debasis Baksi who was employed by ENGIE and was General Manager – South Australian Assets between 2012 to 2020;

(3)    Mr Michael Weatherly who was employed by ENGIE (International Power), and was Origination Manager between 2015 and 2018; and

(4)    Mr Andrew O’Farrell, an expert who has spent many years in the energy industry and between 2011 and 2018 was Gas Portfolio Manager for Origin Energy.

75    Each party also tendered a number of documents in support of its case. Without being exhaustive at this stage, the AER placed reliance on the transcripts of conversations between representatives of PPPL and representatives of AEMO on 8 and again on 9 February 2017, the events of 9 February 2017 and, in particular, the fact that PPPL was able to operate the two gas turbines concurrently on that day for about four hours and certain answers International Power (Australia) Holdings Pty Ltd (ENGIE) gave to a notice issued by the AER under s 28(2)(a) and (b) of the NEL and dated 15 June 2018. I will refer to this as the Section 28 Notice.

76    For its part, and again without being exhaustive, PPPL took the Court to a complex and detailed array of provisions in various gas supply and gas transport agreements and submitted that the uncertainties attending the market for gas and gas transport were such that its approach to the PASA submissions was appropriate and not in contravention of the NER. A further matter which was the subject of evidence and relied on by PPPL was the physical condition of GT12 and PPPL submitted that that was relevant to the issue of whether the PASA submissions complied with the NER.

77    Before addressing the evidence and the factual issues, it is necessary to address a number of construction issues concerning the relevant Rules. The parties made extensive and detailed submissions about these issues.

CONSTRUCTION ISSUES

The issues identified

78    The AER put forward a list of what it contended were the construction issues as follows:

(1)    What is the proper construction of the defined term “PASA availability” in cll 3.7.2(d)(1) and 3.7.3(e)(2) when read in context and having regard to the meaning of the defined terms “physical plant capability” and “available capacity”?

(2)    Is the commercial intention of a Scheduled Generator as to the amount it proposes to generate relevant to the submission it makes as to that aspect of PASA inputs which is PASA availability?

(3)    In determining the availability of a scheduled generating unit within the definition of PASA availability, which includes a scheduled generating unit that can be made available on 24 hours’ notice, is the generator in making its PASA submissions limited to firm sources of gas and gas transport, or must it also take into account gas and gas transfers it ought reasonably expect that it would practically be able to procure on 24 hours’ notice if required to do so? “Firm” in this context refers to a term which is well understood in the gas industry in connection with the supply of gas and gas transport. It means contractually obliged to supply with a failure to do so attended by penalties and other contractual remedies. There is no binding obligation in the case of non-firm or “as available” gas or gas transport, although a firm obligation will arise on the execution of a Formal Transaction Notice or Confirmation. This was the evidence of Mr Snow which was not disputed and which I accept.

(4)    What is the nature and extent of the generator’s obligation to submit estimates or forecasts of MT PASA and ST PASA?

(5)    How is PASA availability for MT PASA affected by a practical limit on how long a generating unit can run for within a day?

(6)    How is PASA availability for ST PASA affected by how long a generating unit can run for within a day?

79    The AER’s list of issues is a convenient way of identifying areas of dispute between the parties. I will deal with them in a different order and, as will become clear, there is a substantial overlap between a number of the issues.

General principles of statutory construction including the use of extrinsic material

80    In the section which follows, I do not intend to cover the whole field, but only those areas which are relevant having regard to the submissions of one or both of the parties.

81    The general principles of statutory construction, including the importance of text, context and the general purpose and policy of a provision, including the mischief sought to be remedied are well known and, with respect, are conveniently summarised by French CJ and Hayne J in Certain Lloyd’s Underwriters v Cross [2012] HCA 56; (2012) 248 CLR 378 at [23]–[26].

82    Section 8(2) of the National Electricity (South Australia) Act 1996 provides that the Acts Interpretation Act 1915 (SA) does not apply to the National Electricity Law (South Australia) or the National Electricity (South Australia) Regulations.

83    Section 3 of the NEL provides that Schedule 2 to the NEL (Miscellaneous provisions relating to interpretation) applies to the Law, the Regulations and the Rules.

84    Section 7 of the NEL provides that the objective of the Law is to promote efficient investment in, and efficient operation and use of, electricity services for the long-term interests of consumers of electricity with respect to:

(a)    price, quality, safety, reliability and security of supply of electricity; and

(b)    the reliability, safety and security of the national electricity system.

85    Clause 7 in Schedule 2 is equivalent to s 15AA of the Acts Interpretation Act 1901 (Cth) and it provides that in the interpretation of a provision of the NEL, the interpretation that will best achieve the purpose or object of the Law is to be preferred to any other interpretation and that is the case whether or not the purpose is expressly stated in the Law.

86    Clause 41 of Schedule 2 provides that the Schedule applies to the Rules notwithstanding that the provision refers to this Law.

87    In its submissions, the AER pointed out that at common law, there may be reasons to adopt what in one respect may be a different approach to the interpretation of subordinate legislation than that adopted in the case of Acts of Parliament. It referred to the following observations of Lord Reid in Gill v Donald Humberstone & Co Ltd [1963] 1 WLR 929 at 933–934, a case concerning regulations made under the Factories Act 1937 (UK) relating to the use of scaffolding, ladders, etc. Lord Reid said the following:

… I find it necessary to make some general observations about the interpretation of regulations of this kind. They are addressed to practical people skilled in the particular trade or industry, and their primary purpose is to prevent accidents by prescribing appropriate precautions … They have often evolved by stages as in the present case, and as a result they often exhibit minor inconsistencies, overlapping and gaps. So they ought to be construed in light of practical considerations, rather than by a meticulous comparison of the language of their various provisions, such as might be appropriate in construing sections of an Act of Parliament … difficulties cannot always be foreseen and it may happen that in a particular case the requirements of a regulation are unreasonable or impracticable. But if the language is capable of more than one interpretation, we ought to discard the more natural meaning if it leads to an unreasonable result, and adopt that interpretation which leads to a reasonably practicable result.

This decision was followed by the Full Court of this Court in Melbourne City Council v Telstra Corporation Limited [2020] FCAFC 200; (2020) 281 FCR 379 at [154] per O’Bryan J (with whom Gleeson J agreed). That case concerned the Telecommunications Act 1997 (Cth) and the Telecommunications (Low-Impact Facilities) Determination 2018 (Cth). The Court held that the Determination in issue was directed to practical people with particular skills and ought to be construed having regard to practical considerations. This case, it seems to me, calls for the same approach, but subject, of course, to the provisions of Schedule 2.

88    The AER seeks to rely on extrinsic material in support of its interpretation of the Rules.

89    Schedule 2 of the NEL addresses the use of extrinsic material in the interpretation of the Law and the Rules. In cl 8, two categories of extrinsic material are identified, namely Law extrinsic material and Rule extrinsic material.

90    The term “Rule extrinsic material” is defined in cl 8 to mean any of the following:

(a)    a draft Rule determination; or

(b)    a final Rule determination; or

(c)    any document (however described)—

(i)    relied on by the AEMC in making a draft Rule determination or final Rule determination; or

(ii)    adopted by the AEMC in making a draft Rule determination or final Rule determination.

91    The AEMC is defined in s 2 of the NEL as the Australian Energy Market Commission established by s 5 of the Australian Energy Market Commission Establishment Act 2004 of South Australia.

92    Clause 8(2), (2a) and (3) in Schedule 2 provide for the circumstances in which Law extrinsic material or Rule extrinsic material may be taken into consideration in interpreting a provision of the Law or the Rules. Clause 8(2a) and (3) are relevant as far as the interpretation of a provision of the Rules is concerned and they are as follows:

(2a)    Subject to subclause (3), in the interpretation of a provision of the Rules, consideration may be given to Law extrinsic material or Rules extrinsic material capable of assisting in the interpretation—

(a)    if the provision is ambiguous or obscure, to provide an interpretation of it; or

(b)    if the ordinary meaning of the provision leads to a result that is manifestly absurd or is unreasonable, to provide an interpretation that avoids such a result; or

(c)    in any other case, to confirm the interpretation conveyed by the ordinary meaning of the provision.

(3)    In determining whether consideration should be given to Law extrinsic material or Rule extrinsic material, and in determining the weight to be given to Law extrinsic material or Rule extrinsic material, regard is to be had to—

(a)    the desirability of a provision being interpreted as having its ordinary meaning; and

(b)    the undesirability of prolonging proceedings without compensating advantage; and

(c)    other relevant matters.

93    For the purposes of cl 8, “ordinary meaning” is defined as the ordinary meaning conveyed by a provision having regard to its context in this Law and to the purpose of this Law.

94    PPPL contended that these sections worked a designedly limited variation to the ordinary modern rules of construction to the effect that a legislative instrument which is amended and the amending legislative instrument are to be read together as a combined statement of the will of the legislature with the consequence that the effect of the amending legislative instrument may be to alter the meaning which remaining provisions of the amended legislative provision bore before the amendment (Commissioner of Stamps (SA) v Telegraph Investment Co Pty Ltd [1995] HCA 44; (1995) 184 CLR 453 at 463 per Brennan CJ, Dawson and Toohey JJ and at 479 per McHugh and Gummow JJ; see also, by way of example, s 11 of the Acts Interpretation Act 1901). That may be accepted, but it is what follows which is significant.

95    In this respect, PPPL sought to rely on the unfairness of using Rule extrinsic material to interpret provisions that are civil penalty provisions. I will deal later with the significance of these provisions being civil penalty provisions. As far as the unfairness argument is concerned, this case is different from the case PPPL relied on — Australian Energy Regulator v Stanwell Corporation Ltd [2011] FCA 991; (2011) 197 FCR 429 at [325]–[331] — because in this case, the extrinsic material supports the ordinary meaning.

96    Before leaving the principles relevant to the use of extrinsic material, I note that one item of extrinsic material in this case is not Rule extrinsic material for reasons I will explain. That does not necessarily prevent me from considering it.

97    In CIC Insurance Ltd v Bankstown Football Club Ltd [1997] HCA 2; (1997) 187 CLR 384, Brennan CJ, Dawson, Toohey and Gummow JJ said (at 408):

It is well settled that at common law, apart from any reliance upon s 15AB of the Acts Interpretation Act 1901 (Cth), the court may have regard to reports of law reform bodies to ascertain the mischief which a statute is intended to cure. Moreover, the modern approach to statutory interpretation (a) insists that the context be considered in the first instance, not merely at some later stage when ambiguity might be thought to arise, and (b) uses “context” in its widest sense to include such things as the existing state of the law and the mischief which, by legitimate means such as those just mentioned, one may discern the statute was intended to remedy.

(Footnote references omitted.)

98    The AER submitted that the proper construction of the PASA obligations is informed by the legislative history of modifications which were made to the MT PASA and ST PASA inputs with a view to clarifying their content. The AER referred to two amendments being first, what it referred to as the 2001 Code change and secondly, the 2010 Rule change.

99    The National Electricity Code (the Code or NEC) commenced operation in December 1998 and preceded the NER. Both legislative instruments contained requirements for generators and other Market Participants to submit information to AEMO, which prior to 1 July 2009 was known as NEMMCO, and for AEMO to prepare and publish outputs of MT PASA and ST PASA.

100    Prior to certain amendments to the Code in 2001, cll 3.7.2 and 3.7.3 only called for generators to provide forecasts of “availability” and for NEMMCO to publish information as to aggregate generating unit “availability” for the purposes of both MT PASA and ST PASA. The 2001 amendments did the following. With respect to MT PASA, the changes in 2001 substituted “PASA availability” for “availability” in cll 3.7.2(d)(1) and 3.7.2(f)(3). With respect to ST PASA, they inserted an additional requirement that Market Participants submit “PASA availability” and for NEMMCO to publish aggregate information about “aggregate generating unit PASA availability” for each region in cll 3.7.3(e)(1A) and 3.7.3(h)(4A). The amendments also made it clear that the availability input was, in the case of ST PASA, to be that “under expected market conditions” (cl 3.7.3(e)(1)). The amendments included a definition of “PASA availability” as follows:

The physical plant capability of a Scheduled Generator, scheduled load or scheduled network service, including any capability that can be made available within 24 hours.

101    The Code Change Panel prepared a report titled “Improvements to the projected assessment of system adequacy” in November 2000 which preceded the amendments and identified the mischief to which they were directed. The AER relies on the following passages in the report of the Code Change Panel:

The projected assessment of system adequacy (PASA) arrangements within the market are intended to provide short (up to a week ahead) and medium-term (up to two years ahead) forecasts of energy and reserve availability which also take account of planned transmission network outages. Such forecasts are essential to a properly functioning market, including to the ability of the demand side to participate fully and actively in the market. The existing PASA arrangements generally work well but there is scope to improve their operation overall by:

    Clarifying and enhancing the information generators provide to NEMMCO by removing the existing ambiguity in the Code and drawing a distinction between the capacity they intend to make available and the capacity they could make available in extreme conditions. This is the purpose of these proposed Code changes;

…

The Code requires market participants to provide medium-term forecasts of the expected availability of each scheduled generating unit. Expected availability is, however, not defined and is ambiguous. It could be interpreted as the capacity generators intend to bid into the market based on their commercial decisions or the capacity which could physically be made available. As a result, at times the medium-term PASA forecast therefore provides an optimistic view of available capacity, ie that more capacity is available than will in fact be presented. At other times, there is more capacity available than the forecast suggests. It is not clear to the market whether the inaccuracy of the forecast is due to a change in the physical capability of the plant or a legitimate commercial decision to present less capacity. NEMMCO can, and does, seek informal advice to clarify its understanding but this is neither transparent nor available to the market.

The primary role of the medium-term PASA is to provide transparent reserve forecasts so that market participants can plan and adjust their operations, particularly plant outages, to maximise the value of market trading. The information also assists NEMMCO in its reserve trader contracting and to determine the need for directions. For these purposes, the relevant definition of available capacity in the medium term is that which could be presented at short notice under worst case conditions. The actual capacity presented to the market will normally be less than the maximum potentially available due to conditions at the time and commercial decisions about commitment. Timing is crucial to whether capacity can be made available in extreme conditions since planned maintenance outages can be deferred if sufficient notice is available, but closer to the event they are usually beyond practical recall. The current provisions do not recognise this.

The Panel published a consultation paper on 21 September on draft changes to the Code to remove the ambiguity surrounding the definition of expected availability and acknowledge the crucial role of timing in relation to commitment decisions. The changes would require scheduled generators to provide information, within both the short and medium-term PASA timeframes, about the capacity that could be made physically available at twenty four hours’ notice in response to extreme conditions. This new information is defined as PASA availability. In the short term, however, reliability will also depend on participants’ discretionary decisions. The proposed changes would also therefore require scheduled generators to provide a forecast of market availability, which is defined as the capability they intend to make available under normal anticipated market conditions, within the short-term PASA timeframe.

…

The Panel recommends that the Code changes, as amended, be forwarded to the Australian Competition and Consumer Commission for authorisation.

102    In its submissions, the AER emphasised the change to cl 3.7.2(d)(1) from “expected availability” to “PASA availability” and the reference in the report of the Code Change Panel to the need to draw a distinction between the capacity which generators intend to make available and the capacity which they could make available in extreme conditions and the ambiguity surrounding the use of the expression, “expected availability”. The AER also referred to the “relevant definition” of available capacity in the medium term as that which could be presented at short notice under worst case conditions. The AER also referred to the amendment to cl 3.7.3(e) dealing with ST PASA to add to the element of the Market Participant’s current intentions and best estimates of availability under expected market conditions, the element of PASA availability for each trading interval and the statement that the changes would require Scheduled Generators to provide information within both the ST and MT PASA timeframes about the capacity that could be made physically available at 24 hours’ notice in response to extreme conditions and the statement in the report that as availability in the short term will also depend on participants discretionary decisions, Scheduled Generators would be required, in the case of ST PASA, to provide a forecast of market availability defined as the capability they intend to make available under normal anticipated market conditions.

103    What emerges from the passage from the report of the Code Change Panel set out above is clear recognition of the distinction between capacity a generator intends to make available and the capacity that could be made available under extreme conditions, that is, that could be made physically available at 24 hours’ notice in extreme conditions. There is, or can be, a difference between the capacity generators intend to bid into the market based on their commercial decisions and the capacity which could physically be made available. There is reason to require the latter in the case of MT PASA and to require both in the case of ST PASA. That is how the amendments to the NEC are framed.

104    The Code Change Panel said in response to a concern raised by a Market Participant that it was satisfied that the draft changes would not be construed as creating a legally binding commitment to deliver capacity. The AER submitted that the report of the Code Change Panel is not consistent with a construction of PASA availability based on an approach of business as usual in the sense of no special measures on 24 hours’ notice.

105    The definition of Rule extrinsic material includes determinations made by the AEMC. There appears to be a lacuna in the legislation because when the National Electricity Rules were initially made in 2005, what they did was to enact the former provisions of the NEC in statutory form under s 9 of the National Electricity Law. The AEM was established in 2004 and it did not have the function of making or recommending changes to the National Electricity Code. The AER submitted that on a “strict reading” of the definition of Rule extrinsic material, the report of the Code Change Panel is not within the definition because it was not material that was relied upon by the AEMC which was not in existence in 2000/2001. The AER submitted that this leaves a gap in how the Court may determine the purpose or objects of the Rules which were originally made as provisions of the Code and, therefore, were not made by the AEMC. The AER submitted that the provisions of cl 8 of Schedule 2 should not be read as a comprehensive code so that it excludes extrinsic material that is relevant to the meaning of its provisions when they were part of the National Electricity Code. It submitted that that could not have been the intention of cl 8 of Schedule 2 because that would mean that all of the extrinsic material that shed light on the proper interpretation of the provisions of the Code became redundant in 2005 notwithstanding their obvious relevance to interpreting the provisions of the NER when they were then enacted. Such an approach would not be consistent with s 7 of the NEL which sets out the objective of the Law. In summary, the AER submitted that in the particular setting involving the National Electricity Code being enacted in statutory form as the NER in 2005, the Court should have regard to “pertinent extrinsic material” associated with the 2001 Code change in the same way as the Court would, at common law, determine the mischief for a legislative change, in this case the insertion of the definition of “PASA availability”.

106    For the reasons given by the AER, I consider that I may have regard to this material. However, I would note that I would reach the same conclusion as to the proper construction of the relevant rules even if I exclude consideration of the extrinsic material.

107    The AER also referred to, and relied upon, statements made in the Australian Competition and Consumer Commission’s determination on an application for authorisation of the amendments to the National Electricity Code. The particular statements relied upon were the record of the submission made to the ACCC by NEMMCO as follows:

The Commission received one submission. The submission, from NEMMCO, states that it supports the proposed Code changes in principle, since they increase the clarity of participant obligations and provides additional resolution and transparency of the information used to forecast reserve levels.

The submission by NEMMCO was as follows:

These Code changes will now require Market Participants to advise NEMMCO of two different availability levels for scheduled plant in short term time frame. In addition NEMMCO will be required to report on two different levels of availability in the short term time frame. NEMMCO supports these proposed Code changes in principle, as they provide some increase in clarity of participant obligations, and additional resolution and transparency of the information used to manage forecast reserve levels.

108    In 2010, AEMO proposed a suite of amendments to the PASA provisions. A number of amendments to the Rules were made. The primary purpose of the amendments was, according to the AER, to “loosen the former requirement that AEMO should calculate a separate reserve requirement for each region, by allowing AEMO instead to calculate ‘dynamic joint regional reserve requirements’”. A number of other amendments were made at the same time which, according to the AER, were designed “to improve clarity of the PASA rules and to address various minor issues identified through a review of the PASA processes that had been undertaken in 2009”.

109    The AER submitted that for present purposes, the most important amendment was that made to the description of “availability” in the case of ST PASA. In place of the undefined word “availability” in cl 3.7.3(e)(1), the defined term “available capacity” was substituted. The substitution of “available capacity” in place of “availability” was recommended by AEMO because it considered that:

“availability” in amended clause 3.7.3(e)(1) is equivalent to the existing glossary definition “available capacity” and the clause should instead refer to the existing definition.

110    The AEMC agreed with the position advanced by AEMO “in order to improve clarity of the Rules”. The amendments in 2010 also included amendments to change the existing definition of “PASA availability” (see [100] above) to the following:

The physical plant capability of a scheduled generating unit, scheduled load or scheduled network service available in a particular period, including any physical plant capability that can be made available in that period given 24 hours’ notice of a requirement that the relevant scheduled generating unit, scheduled load or scheduled network service be made available.

111    The amendment actually made was to change the definition of “PASA availability” so that it read as follows:

The physical plant capability (taking ambient weather conditions into account in the manner described in the procedure prepared under clause 3.7.2(g)) of a scheduled generating unit, scheduled load or scheduled network service available in a particular period, including any capability that can be made available during that period, on 24 hours’ notice.

112    PPPL submitted that the relevant rules are civil penalty provisions and that any doubt or ambiguity about meaning should be resolved in its favour. It referred to the observations of Franki J in Trade Practices Commission v TNT Management Pty Ltd (1985) 6 FCR 1 (at 47–48):

It is, in my opinion, now necessary to look at certain aspects of the correct approach to be adopted in the construction of a statute such as Pt IV of the Act. It is clear that, although the criminal onus of proof does not have to be satisfied, it is necessary to have regard to the penal nature of the contravention alleged and the extent of the penalty, both financial and probably to trade reputation, which is involved in a finding of contravention. I have in mind that the legislation is of a highly penal nature and in TPC v Legion Cabs (Trading) Co-operative Society Ltd (1978) 35 FLR 372 at 382 … I said in relation to s 47 of the Act:

I consider that such a section should be construed in a similar way to a section imposing a criminal liability. As to the interpretation of statutes creating offences, see Beckwith v The Queen (1976) 135 CLR 569 per Gibbs J at 576.

The passage of Gibbs J, as he then was, to which I referred reads:

The rule formerly accepted, that statutes creating offences are to be strictly construed, has lost much of its importance in modern times. In determining the meaning of a penal statute the ordinary rules of construction must be applied, but if the language of the statute remains ambiguous or doubtful the ambiguity or doubt may be resolved in favour of the subject by refusing to extend the category of criminal offences: see R v Adams (1935) 53 CLR 563 at 567-568; Craies on Statute Law (7th ed, 1971), pp 529-534. The rule is perhaps one of last resort.

… In my opinion, if the language of the Act after the ordinary rules of construction have been applied remains ambiguous or doubtful, it is appropriate to remove or resolve that ambiguity or doubt in favour of a defendant, at least, where the proceedings are for a penalty.

113    The rules of construction in relation to civil penalty provisions are similar to those that apply in the case of criminal offences (Australian Competition and Consumer Commission v Yazaki Corporation [2018] FCAFC 73; (2018) 262 FCR 243 at [68]).

114    In R v A2 [2019] HCA 35; (2019) 269 CLR 507, Kiefel CJ and Keane J said (at [52]):

A statutory offence provision is to be construed by reference to the ordinary rules of construction. The old rule, that statutes creating offences should be strictly construed, has lost much of its importance. It is nevertheless accepted that offence provisions may have serious consequences. This suggests the need for caution in accepting any “loose” construction of an offence provision. The language of a penal provision should not be unduly stretched or extended. Any real ambiguity as to meaning is to be resolved in favour of an accused. An ambiguity which calls for such resolution is, however, one which persists after the application of the ordinary rules of construction.

(Footnotes omitted.)

115    I also refer to the following observations of Leeming JA in Grajewski v Director of Public Prosecutions (NSW) [2017] NSWCCA 251; (2017) 270 A Crim R 33 at [55]):

Although it was at the forefront of his written submissions, the principle invoked by Mr Grajewski does not exclude the ordinary rules of construction: Waugh v Kippen (1986) 160 CLR 156 at 164; [1986] HCA 12. Indeed, Gibbs J’s qualified observation in Beckwith v The Queen (1976) 135 CLR 569 at 576 that the “rule is perhaps one of last resort” has much more recently been reiterated in unequivocal terms: by Nettle and Gordon JJ in Re Day [No 2] [2017] HCA 14; 91 ALJR 518 at [276] and in the joint judgment in Aubrey v The Queen [2017] HCA 18; 91 ALJR 601 at [39]. I do not for a moment understand the High Court, by referring to “rules” and “last resort”, to be implying that the task of ascertaining the legal meaning of a statute is mechanistic, to be determined by the application of rules, amongst which the penal character of the statute is the last to be invoked. The process is considerably more nuanced, reflecting as it does the constitutional relationship between the various arms of government: Zheng v Cai (2009) 239 CLR 446; [2009] HCA 52 at [28]. As was express in the passage from Stevens v Kabushiki Kaisha Sony Computer Entertainment reproduced above – a statute’s penal character is to be regarded as a very minor consideration to be taken into account in ascertaining its legal meaning in light of its text, context and purpose.

116    Finally, it is relevant to note the principles relevant to when a word or words may be read into a legislative provision. A prior question is whether that exercise is necessary. For example, in Construction, Forestry, Maritime, Mining and Energy Union v Australian Building and Construction Commissioner (Bay Street Appeal) [2020] FCAFC 192; (2020) 282 FCR 1 (the Bay Street Appeal case), Flick J discussed the difference between reading words into a legislative provisions and, to use the words of his Honour (at [62]), “to construe a legislative phrase by reference to the context in which the phrase appears and to read that phrase in a matter which gives effect to its presumed legislative object and purpose”.

117    Assuming it is a true case of reading words into the legislative provision, then the relevant principles are as follows.

118    In Wentworth Securities Ltd v Jones [1980] AC 74 at 105–106, Lord Diplock identified three conditions which must be satisfied before words are read into a statutory provision or the Court reads a provision in a way which modifies the words of an Act. His Lordship said:

First, the court must know the mischief with which the Act was dealing. Secondly, the court must be satisfied that by inadvertence Parliament has overlooked an eventuality which must be dealt with if the purpose of the Act is to be achieved. Thirdly, the court must be able to state with certainty what words Parliament would have used to overcome the omission if its attention had been drawn to the defect.

119    The High Court addressed this issue in Taylor v Owners – Strata Plan No 11564 [2014] HCA 9; (2014) 253 CLR 531. French CJ, Crennan and Bell JJ said the following (at [37]–[39]):

37    Consistently with this Court’s rejection of the adoption of rigid rules in statutory construction, it should not be accepted that purposive construction may never allow of reading a provision as if it contained additional words (or omitted words) with the effect of expanding its field of operation. As the review of the authorities in Leys demonstrates, it is possible to point to decisions in which courts have adopted a purposive construction having that effect …

38    The question whether the court is justified in reading a statutory provision as if it contained additional words or omitted words involves a judgment of matters of degree …

39    Lord Diplock’s three conditions (as reformulated in Inco Europe) accord with the statements of principle in Cooper Brookes and McColl JA was right to consider that satisfaction of each could be treated as a prerequisite to reading s 12(2) as if it contained additional words before her Honour required satisfaction of a fourth condition of consistency with the wording of the provision. However, it is unnecessary to decide whether Lord Diplock’s three conditions are always, or even usually, necessary and sufficient. This is because the task remains the construction of the words the legislature has enacted. In this respect it may not be sufficient that “the modified construction is reasonably open having regard to the statutory scheme” because any modified meaning must be consistent with the language in fact used by the legislature …

(Footnote references omitted.)

120    Their Honours also made the point (at [40]) that the Court may be prohibited from giving effect to a purposive construction because to do so would involve an alteration to the language which was “too far-reaching” and the issue itself may have an added dimension in the Australian context because it may violate the separation of powers in the Constitution.

121    Justices Gageler and Keane dissented in the result. However, as to the relevant principles of statutory construction, their Honours said the following (at [65] and [66]):

65    Statutory construction involves attribution of legal meaning to statutory text, read in context. “Ordinarily, that meaning (the legal meaning) will correspond with the grammatical meaning … But not always”. Context sometimes favours an ungrammatical legal meaning. Ungrammatical legal meaning sometimes involves reading statutory text as containing implicit words. Implicit words are sometimes words of limitation. They are sometimes words of extension. But they are always words of explanation. The constructional task remains throughout to expound the meaning of the statutory text, not to divine unexpressed legislative intention or to remedy perceived legislative inattention. Construction is not speculation, and it is not repair.

66    Context more often reveals statutory text to be capable of a range of potential meanings, some of which may be less immediately obvious or more awkward than others, but none of which is wholly ungrammatical or unnatural. The choice between alternative meanings then turns less on linguistic fit than on evaluation of the relative coherence of the alternatives with identified statutory objects or policies.

(Footnotes omitted.)

122    In HFM043 v Republic of Nauru [2018] HCA 37; (2018) 359 ALR 176, Kiefel CJ, Gageler and Nettle JJ said (at [24]):

The task of construction of a statute is of the words which the legislature has enacted. Any modified meaning must be consistent with the language in fact used by the legislature. Words may be implied to explain the meaning of its text. The constructional task remains throughout to expound the meaning of the statutory text, not to remedy gaps disclosed in it or repair it. On any view, as was conceded, to construe s 31(5) in the manner contended for the respondent would go far beyond any implication of legislative intention that may be ascertained from the provisions of the statute, including the policy discernible from those provisions. The respondent’s construction cannot be accepted.

(Footnotes omitted.)

123    PPPL submitted that in Mills v Meeking [1990] HCA 6; (1990) 169 CLR 214 at 235, Dawson J suggested a fourth requirement before the literal meaning of a statutory provision is modified and that is that the modification must be consistent with the “wording otherwise adopted by the draftsman”.

Some general matters relevant to construction

124    Clauses 3.7.2(d), 3.7.3(e) and 3.13.2(h) are set out above.

125    MT PASA covers the 24 month period commencing from the Sunday after the day of publication with a daily resolution, whereas ST 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.

126    There are two differences in the text between the rule dealing with MT PASA inputs on the one hand, and the rule dealing with ST PASA inputs on the other, which should be noted.

127    First, MT PASA inputs to be submitted by, among others, a Scheduled Generator, consist of the PASA availability of each scheduled generating unit, scheduled load or scheduled network service for each day and weekly energy constraints applying to each scheduled generating unit or scheduled load. The term “energy constraint” was defined in the glossary at the relevant time as follows:

A limitation on the ability of a generating unit or group of generating units to generate active power due to the restrictions in the availability of fuel or other necessary expendable resources such as, but not limited to, gas, coal, or water for operating turbines or cooling.

128    By contrast, ST PASA inputs consist of the available capacity of each scheduled generating unit, scheduled load or scheduled network service for each trading interval under expected market conditions and PASA availability of each scheduled generating unit, scheduled load or scheduled network service for each trading interval, and projected daily energy availability for each energy constrained scheduled generating units and energy constrained scheduled loads.

129    The definition of “available capacity” is also set out above (at [13]). Clearly, it is different from PASA availability. The AER submitted (correctly) that it consists of two limbs and can refer to either the total MW capacity available for dispatch by a scheduled generating unit, semi-scheduled generating unit or scheduled load, or in relation to a specified price band, the MW capacity within that price band available for dispatch. In other words, the AER submitted (again correctly) that available capacity can refer to either the total MW capacity that a generator offers to supply for dispatch across all price bands or the MW capacity that a generator offers to supply for dispatch at a particular price band. An energy constrained scheduled generating unit is defined in the glossary as follows:

A scheduled generating unit in respect of which the amount of electricity it is capable of supplying on a trading day is less than the amount of electricity it would supply on that trading day if it were dispatched to its full nominated availability for the whole trading day.

130    Secondly, in the case of ST PASA inputs, such inputs must represent the Scheduled Generator’s (or Market Participant’s) current intentions and best estimates as to the matters identified in points (1), (2) and (4) ((3) is deleted), whereas there is no such requirement or qualification expressed in the case of MT PASA inputs.

131    Both rules dealing with the MT PASA and ST PASA submissions which a Scheduled Generator must make appear in a collection of rules which in each case require AEMO to prepare PASA inputs and AEMO to subsequently prepare and publish defined information for the benefit of the market.

132    A contextual matter relevant to the PASA provisions which are related to power system security and reliability of supply prospects is AEMO’s power to issue directions in relation to the power system and whether it is in a secure operating state, a satisfactory operating state or a reliable operating state.

133    The following rules deal with AEMO’s power to issue directions and to use its reasonable endeavours to minimise costs and compensation and a Registered Participant’s obligation to comply with a direction:

4.8.9    Power to issue directions and clause 4.8.9 instructions

(a)    Notwithstanding any other provision of rule 4.8:

(1)    AEMO may require a Registered Participant to do any act or thing if AEMO is satisfied that it is necessary to do so to maintain or re-establish the power system to a secure operating state, a satisfactory operating state, or a reliable operating state; and

(2)    …

(b)    AEMO must develop, and may amend from time to time, in accordance with the Rules consultation procedures, procedures for the issuance of directions. Such procedures must reflect the following principles:

(1)    AEMO must use its reasonable endeavours to minimise any cost related to directions and compensation to Affected Participants and Market Customers pursuant to clause 3.12.2 and compensation to Directed Participants pursuant to clauses 3.15.7 and 3.15.7A;

(2)    …

(c)    A Registered Participant must use its reasonable endeavours to comply with a direction or clause 4.8.9 instruction unless to do so would, in the Registered Participant’s reasonable opinion, be a hazard to public safety, or materially risk damaging equipment, or contravene any other law.

134    There is provision for AEMO to pay compensation to Directed Participants under cl 3.15.7.

135    With respect to purpose and policy, including mischief, I have already referred to the National Electricity Objective in s 7 of the NEL. I add the following. The rules dealing with PASA submissions appear in Chapter 3 of the NER titled “3. Market Rules”. The purpose of the Chapter is stated in cl 3.1.1 as follows:

This Chapter sets out the procedures which govern the operation of the market relating to the wholesale trading of electricity and the provision of ancillary services and includes provisions relating to:

(a)    prudential requirements to be met for participation in the market;

(b)    the operation of the spot market;

(c)    bidding and dispatch;

(d)    spot price determination;

(d1)    the determination of ancillary service prices;

(e)    AEMO clearing house and trading functions;

(f)    market information requirements and obligations;

(g)    the conditions and procedures for market suspension; and

(h)    settlements.

136    Finally, there are relevant statements in cl 3.7.1 as to what PASA is and AEMO’s role in the administration of PASA.

(a)    AEMO must administer medium term and short term projected assessment of system adequacy processes to be known as PASA.

(b)    The PASA is a comprehensive program of information collection, analysis, and disclosure of medium term and short term power system security and reliability of supply prospects so that Registered Participants are properly informed to enable them to make decisions about supply, demand and outages of transmission networks in respect of periods up to 2 years in advance.

(c)    On a weekly basis AEMO must:

(1)    collect and analyse information from all Scheduled Generators, Market Customers, Transmission Network Service Providers and Market Network Service Providers about their intentions for:

(i)    generation, transmission and market network service maintenance scheduling;

(ii)    intended plant availabilities;

(iii)    energy constraints;

(iv)    other plant conditions which could materially impact upon power system security and reliability of supply; and

(v)    significant changes to load forecasts previously notified to AEMO,

for the following 24 months;

(2)    prepare the unconstrained intermittent generation forecasts for the following 24 months; and

(3)    following analysis and assessment of the information referred to in subparagraphs (1) and (2), publish information that will inform the market regarding forecasts of supply and demand.

(d)    AEMO must use its reasonable endeavours to ensure that it publishes sufficient information to allow the market to operate effectively with a minimal amount of intervention by AEMO.

PASA availability

137    The AER submitted that the “central construction issue” is the meaning of “PASA availability” when read in context and with the definition and use of the expressions “physical plant capability” and “available capacity”. The definition of PASA availability is set out above (at [13]). Although the expression, “physical plant capability”, was in the Rules before the expression “PASA availability”, its only remaining role is as an element of the definition of PASA availability. The definition of physical plant capability is also set out above (at [13]). It is an objective and technical parameter, whereas PASA availability raises more operational matters, being the physical plant capability that is available, or can be made available, on 24 hours’ notice or less.

138    The Rules address the bidding and dispatch in the wholesale market of available capacity and, in particular, reference may be made to cll 3.8.4(a) and 3.8.22(b) of the NER. The AER submitted, correctly in my view, that as it is used as a ST PASA input in cl 3.7.3(e)(1), available capacity is directed to the aggregate MW capacity that a Scheduled Generator proposed to bid as available for dispatch under expected market conditions in each 30 minute trading interval over the ST PASA forecast period and that meaning engages the first, rather than the second, limb of the definition of available capacity. The available capacity of, for example, a scheduled generating unit may be limited by operational constraints, such as the availability of fuel, in common with constraints relevant to PASA availability, but it will be further constrained by matters that are relevant only to the generator’s commercial intentions, “under expected market conditions”. There is a clear difference between available capacity for ST PASA purposes and the generator’s best estimate of PASA availability. In the former case, the generator can exclude from its forecast the extent of any physical plant capability of its generating unit that it intends not to offer into the market on a particular day, or at a particular time of day, because it considers that expected market conditions, including expected spot prices, are not likely to justify incurring the running costs for that generating unit. On the other hand, in the latter case of PASA availability, physical plant capability that can be made available on 24 hours’ notice must be included.

139    This conclusion seems to me to follow from the definitions themselves and the differences between them. The conclusion is supported by the statements in the report of the Code Change Panel to which I have previously referred.

140    The AER submitted that as a MT PASA input, the “weekly energy constraint” is intended to refer to a limitation on the generating unit’s ability to generate power for a whole week at its specified availability level. That does seem clear having regard to cl 3.7.2(f)(5B) which requires AEMO to publish, as one of the MT PASA inputs, the aggregate capacity “that cannot be generated continuously at the PASA availability of the scheduled generating units … due to specified weekly energy constraints”.

141    With respect to ST PASA, a generator who operates an energy constrained scheduled generating unit is required to notify AEMO of projected daily energy availability (cl 3.7.3(e)(4)). The term “daily energy” is not defined. The AER submitted that “some context” is provided by the definition of an energy constrained scheduled generating unit. That definition is set out above (at [129]). The AER submitted that considered in its context, cl 3.7.3(e)(4) is intended to provide AEMO with information about the extent to which a scheduled generating unit may be unable to generate continuously for 24 hours at its specified available capacity due to energy constraints within the definition of energy constrained scheduled generating unit. In my opinion, that construction is supported by cl 3.7.3(h)(4AB) which requires AEMO to calculate the “aggregate capacity … that cannot be generated continuously at the available capacity due to specified daily energy constraints”.

142    I accept that like the concept of PASA availability, the concepts of “weekly energy constraint” and “daily energy availability” involve objective parameters that refer to any limitations on PASA availability or available capacity for MT PASA and ST PASA respectively that are “due to the restrictions in the availability of fuel or other necessary expendable resources”, picking up the definition of “energy constraints”, an expression used in cl 3.7.2(d)(2) and set out above (at [127]).

143    With respect to the definition of PASA availability, the AER submitted that the reference to “can be made available” in the definition makes it clear that what is required is an estimate or forecast as to a future event. The AER accepted that by its nature, a forecast involves an element of uncertainty and that is why, in the case of ST PASA, only an estimate is required. There is inevitably an element of uncertainty. For example, in the case of MT PASA, the forecast may relate to a period which is 24 months into the future. Contracts for firm fuel or transport may expire within that 24 month period. Nevertheless, a forecast must be given. The AER submitted that in the case of ST PASA, for example, it would not make sense to restrict that to the Scheduled Generator’s current intentions having regard to the reference in PASA availability to physical plant capability that can be made available during a period on 24 hours’ notice. The AER submitted that the reference to the physical plant capability that can be made available during the period on 24 hours’ notice is entirely inconsistent with the notion that PASA availability does not go outside the steps which would be taken by a Scheduled Generator in the ordinary course of the business of that Scheduled Generator. Put another way, there is no notion in the definition to the effect that the Scheduled Generator is not required to take steps outside its ordinary course of business or its established business plans. The AER’s submission is that once it is recognised that PPPL had sufficient gas and gas transport to operate a single turbine for the day, or most of the day, on 8 February 2017, then the question of PASA availability is answered. Whilst the AER accepted that running two turbines for part of the day may not have been commercially desirable or profit maximising, it submitted that that is not the relevant question.

144    The AER submitted that for MT PASA if it would be practically and physically possible on 24 hours’ notice for both of the Pelican Point PS gas turbines to run concurrently in any trading interval on a particular day, and a Scheduled Generator in PPPL’s position would reasonably expect to obtain sufficient gas and gas transport in order for this to occur, then the PASA availability for that trading interval would reflect the physical plant capability of both units and the weekly energy constraints should reflect a reasonable estimate of the limitation on Pelican Point PS’s ability to generate at the PASA availability level continuously over a week due to restrictions in the availability of gas and gas transport.

145    The AER submitted that for ST PASA, if it would be practically and physically possible, on 24 hours’ notice, for both of the Pelican Point PS’s gas turbines to run concurrently in a particular trading interval, and the best estimate of a reasonable generator in PPPL’s position was that sufficient gas and gas transport could be obtained in order for this to occur, then the PASA availability for that trading interval should reflect the physical plant capability of both units and the available capacity should reflect only the capacity that PPPL subjectively intends to make available in the market through its dispatch offers for that trading interval and the projected daily energy availability should reflect PPPL’s best estimate of the amount of energy that can be generated on a particular day, in light of any gas supply or gas transport constraints.

146    PPPL submitted that available capacity addresses what the generator intends to do. The concept of PASA availability starts from the premise of what the generator intends to do. The definition of PASA availability and the reference to “including” focuses on what in addition to that the generator intends to do, it can do on 24 hours’ notice. PPPL submitted that the word “can” denotes the ability, power, right, qualifications or means to do something. Although PPPL does not go so far as to submit that the test is 100% certainty, it does submit that the sense of the concept is not directed towards predicting in respect of each and every period the capacity which, on the bare balance of probabilities, is predicted to be more likely than not available.

147    PPPL referred to cl 3.7.1(b). It pointed out that on the face of it, it is not concerned with identifying extreme events and nor is it premised on a direction being given by AEMO. Furthermore, cl 3.7.1(c)(1) refers to AEMO’s collection and analysing of information from all Scheduled Generators (among others) about their intentions with respect to certain matters.

148    With respect to cl 3.7.2(d)(1), PPPL submitted that the gas turbines and steam turbine at Pelican Point PS are aggregated under cl 3.8.3 so that there is one unit for dispatch. AEMO has an obligation to publish information under cl 3.7.2(f). PPPL submitted that these rules are directed at real circumstances and the practical realities of what Scheduled Generators intend to do and what the aggregate generating unit PASA availability for each region will be. PPPL submitted that to publish PASA availability based on an unreal hypothetical and one in which actual business plans were ignored, would be contrary to the whole purpose of the regime established with respect to PASA.

149    PPPL then moved to cl 3.7.3(e) and ST PASA. PPPL referred to cl 3.7.3(h) which identifies the information for each trading interval that AEMO must prepare and publish. PPPL referred to paras (4AA), (4AB) and (4A) and submitted that they were part of the information to be published and self-evidently, this was to inform Market Participants of “what’s out there”. PPPL submitted that if all Scheduled Generators were required to approach PASA availability on a hypothetical basis, then that would result in meaningless information in circumstances where they were all competing for non-firm gas supply and gas transport. Each Scheduled Generator would be considering whether it might be able to obtain non-firm gas transport or non-firm interruptible gas transport. PPPL referred to the definition of “available capacity” and “PASA availability”. In connection with the definition of PASA availability, PPPL submitted that a total hypothetical is not envisaged by the definition. The definition refers to what is available. That refers to the Scheduled Generator’s intentions and plans (and in this case, that included operating one generator). The definition goes on to refer to what can be made available on 24 hours’ notice. PPPL at one point referred to this second aspect of the definition as the “fall back”. PPPL’s submission is that, properly construed, the definition refers to what the Scheduled Generator is intending to do and then the physical plant capability that can be made available in addition. PPPL submitted that one does not ignore the starting point of what the Scheduled Generator intends to make available and, in effect, proceed by reference to what is a truly hypothetical scenario. PPPL submitted that there is a subjective element and an objective element in the chapeau. The information is designed to properly inform Market Participants and if it is done on a wholly theoretical basis, then it will provide information opposite to that which the NER envisage.

150    PPPL accepted that the word “can” in the definition of PASA availability requires the person applying the Rules to consider whether there was a reasonable basis for a Scheduled Generator to reach the view that there is physical plant capability that can be made available on 24 hours’ notice. PPPL submitted in this context that “reasonable” means not arbitrary or capricious. In other words, if the Scheduled Generator can show that its decision was not arbitrary or capricious, then it satisfies the reasonableness test. The standard was, PPPL submitted, similar to the public law standard of legal reasonableness (Minister for Immigration and Citizenship v Li [2013] HCA 18; (2013) 249 CLR 332 at [72] per Hayne J, Kiefel J (as her Honour then was) and Bell J; Minister for Immigration and Border Protection v SZVFW [2018] HCA 30; (2018) 264 CLR 541). The AER submitted that it has never contended that the test is similar to the public law standard of legal reasonableness.

151    PPPL directed the Court’s attention to various statements made by the AER as to the standard under the NER. It is true that the AER has said that it does not submit that the relevant test is what a prudent or diligent Scheduled Generator would submit. On other occasions, the AER has submitted that the test is whether the PASA availability was the best estimate of a competent and diligent generator in PPPL’s position or a reasonable estimate. On other occasions, the AER has said that the relevant test is reasonableness and that meant that the Scheduled Generator could not be capricious or provide an estimate that was purely arbitrary.

152    PPPL submitted that if this last submission is accepted, then there is not a great deal of difference between the AER’s test and its test. PPPL’s test is that the Scheduled Generator’s assessment of PASA availability must be bona fide and genuine. There is not a great deal of difference between this test and the test of reasonableness in the sense of the estimate must not be arbitrary or capricious.

153    It is true that at various points when attempting to explain the concept of reasonableness, counsel for the AER referred to not arbitrary or not capricious. I do not consider that to be material. First, the AER has clearly articulated a case that the forecast must be reasonable (sometimes expressed in terms of what it ought reasonably to have expected) and not limited to not arbitrary or capricious and that can be seen in its submissions and the questions asked of the experts. Secondly, the issue is one of the correct construction of subordinate legislation and the Court cannot be bound by a concession made by one of the parties.

154    PPPL complained that the AER was now expounding yet a different case by reference to its definition of “best estimate”. The AER’s counsel said in closing submissions that a best estimate requires the task to be approached in the most comprehensive way possible and that the notion of a best estimate presupposes that all inquiries and all analysis that can be undertaken will be undertaken.

155    In essence, PPPL’s submission is that the reference in the definition of PASA availability to including any plant capability that can be made available during that period on 24 hours’ notice is a reference to, in effect, what else the Scheduled Generator can do, or what more can the Scheduled Generator do. PPPL submitted that that reflects a “real world approach” and conforms with the purpose of the Rules. PPPL went so far as to submit that a complete change of business plans is really inconsistent with the notion of what else can be made available on 24 hours’ notice.

156    PASA availability is a forecast and it would be a forecast even if restricted to availability. It goes beyond current intentions and includes what can be made available on 24 hours’ notice. The circumstances facing a Scheduled Generator preparing a PASA submission for a date two years in advance down to say, a couple of days in advance, may be many and varied, but what is required is a forecast or prediction, not just of its proposed business plans (which will no doubt be relevant to the whole issue), but of what it can make available on 24 hours’ notice. PASA availability may be changed if circumstances change and, in fact, there is an obligation on Scheduled Generators to advise of changes to submitted information. The “can be made available” aspect of PASA availability is not a promise or representation to the market that that physical plant capability will be made available or that it is the Scheduled Generator’s intention to make it available.

The nature and extent of the generator’s obligations in submitting estimates or forecasts of MT PASA and ST PASA

157    As previously stated, the MT PASA rule, cl 3.7.2(d), does not indicate what the MT PASA input of PASA availability must represent on the part of the Scheduled Generator, whereas the ST PASA rule, cl 3.7.3(e), states that the ST PASA input of PASA availability must represent the Scheduled Generator’s current intentions and best estimates of PASA availability.

158    I start with MT PASA.

159    The AER’s case is that the MT PASA input of PASA availability must be a reasonable estimate by the Scheduled Generator of PASA availability. That is how it formulated the obligation in its submissions.

160    The AER submitted that although a literal interpretation of the text of cl 3.7.2(d) might suggest that a Scheduled Generator’s only obligation was to submit a value for PASA availability and weekly energy constraints in accordance with the timetable, such an interpretation needs only to be stated to be dismissed as absurd and unsustainable. The AER’s contention that the Scheduled Generator’s obligation is to submit a reasonable estimate of each of its PASA availability and weekly energy constraints, based on the information available to the Scheduled Generator at the time it submits its MT PASA inputs, is said to be supported by the following matters.

161    First, the interpretation to be preferred is the interpretation which will best achieve the purpose or object of the Law (National Electricity (South Australia) Act 1996 Schedule 2, s 7; NEL s 3). Clause 3.7.1(b) describes the PASA regime or program and its purpose. The latter is to ensure that Registered Participants are properly informed to enable them to make decisions about supply, demand and outages of transmission networks in respect of periods of up to two years in advance. Furthermore, if there is no requirement of a “reasonable estimate”, AEMO’s ability to use the outputs of the MT PASA process to identify and notify the market of low reserve conditions over the two year MT PASA outlook period in an accurate fashion would be undermined. Under the modern approach, the fact that the provision is a civil penalty provision does not constitute a hurdle.

162    Secondly, the AER pointed to the fact that cl 3.7.2(d) provides that the MT PASA inputs must be submitted in accordance with the timetable. This indicates a link with the requirement in cl 3.13.2(h) that a Scheduled Generator (among others) must notify AEMO of, and AEMO must publish, any changes to submitted information within the limits prescribed in the timetable. The AER submitted that this provision reinforces the purpose of the scheme and that is to ensure that Registered Participants are “properly informed”. The Scheduled Generator must act according to the information available at the time. If there was no requirement on the Scheduled Generator to make a reasonable estimate, then there would be no need for a provision such as cl 3.13.2(h).

163    Thirdly, the AER submitted that the absence of a requirement that the Scheduled Generator’s MT PASA inputs must reflect a reasonable estimate would risk undermining the efficacy of the standing data mechanisms provided for in cl 3.13.3(b).

164    The AER submitted that having regard to these matters, the Court should construe cl 3.7.2(d) as including an “implied requirement” that MT PASA inputs should reflect a Scheduled Generator’s reasonable estimate based on the information available to it at the time it submits the MT PASA inputs. The AER’s submission included a submission that a strictly literal interpretation of cl 3.7.2 would produce a perverse and counter-productive result. Further, it submitted that the standard of a reasonable estimate is readily understood and applied (Healthcare at Home Ltd v Common Services Agency [2014] UKSC 49 (Healthcare v Common Services Agency)) and is “appropriately calibrated at a lower standard of stringency than the ‘current intentions and best estimates’ requirement for short-term PASA inputs”.

165    Each of the AER’s reasons for reading cl 3.7.2(d) as if it contained a reference to the forecast or estimate being reasonable have considerable force and reasonableness is both well understood and accepted in the law. However, the words are not in the clause.

166    The AER sought to overcome this difficulty by relying on two arguments. The first did not involve reading words into the clause. I was invited simply to construe the clause as containing an implied obligation of a reasonable estimate and I was referred to the Bay Street Appeal case. I do not think that case, where there was a phrase to be construed narrowly or broadly as the case may be, is of assistance. The AER did not identify a phrase in cl 3.7.2(d) that was to be construed in this case.

167    The alternative approach advanced by the AER was to invite the Court to read words into the clause along the lines of the inputs must represent the Scheduled Generator’s reasonable estimate of each matter. PPPL submitted that the implications suggested by the AER do not satisfy the four conditions identified in the authorities. PPPL submitted that there is also an additional consideration which operates and that is the provisions in question are civil penalty provisions and the construction suggested by the AER would mean that there would be an expansion of the circumstances in which a person will be exposed to liability.

168    PPPL acknowledged in its submissions that the NER were directed to industry participants and that where language is capable of more than one interpretation, the Court may strain against a meaning that would lead to an unreasonable or impractical result. However, it submitted that the AER’s approach to the obligations in Part 3.7 of the NER would result in an onerous and impractical outcome. On the AER’s construction, a Scheduled Generator in the position of PPPL would be required to make constant prognostications as to what might be achievable in respect of isolated periods of time in hypothetical circumstances divorced from the commercial arrangements reflecting the operator’s actual supply intentions and consequential firm gas arrangements, but it would be at risk of penalty if the estimates do not conform to the standard the AER submitted should be read into the obligations in Part 3.7 of the NER, that is to say, the standard of a reasonable and diligent operator considering the same hypothetical set of circumstances.

169    I accept that there appears to be an omission in the rule and it would seem that the objects of the PASA regime would be better served by a standard or requirement a MT PASA submission must attain and, of course, the reasonableness standard is ubiquitous in the law. The submission is that the Court should read into the chapeau of cl 3.7.2(d) words to the effect that PASA availability submissions should represent the Scheduled Generator’s reasonable estimate based on the information available to it. The matter which has caused me most concern is that of being able to state with certainty what words the rule-making authority would have used to overcome the omission if its attention had been drawn to the defect. I note that, albeit in relation to a different time period, in the case of ST PASA submissions, the standard specified is “current intentions and best estimates”.

170    I have given the matter anxious consideration. I consider a requirement that the forecast or estimate be reasonable should be read into cl 3.7.2(d). A requirement of good faith may mean no more than that there must be no knowing misrepresentation and a requirement of genuine forecast or estimate could be a very “thin” obligation, indeed perhaps, no more than that it be PPPL’s submission. Obviously, it was contemplated that the PASA scheme which addresses the important issues of how power system security and reliability of supply prospects, would work. The Rules are addressed to practical people in a specialised industry who would understand the need for forecasts to be reasonably based.

171    With respect to ST PASA, three ST PASA inputs are required, being available capacity, PASA availability and projected daily energy availability. The timetable provides that updates to a Scheduled Generator’s ST PASA inputs must be made on a daily basis for each day over a forecast window of six days. The ST PASA submission must be for each trading interval in a day which is a half hour period. With respect to the obligation on a Scheduled Generator to publish any changes to submitted information within the times prescribed in the timetable, the timetables provides that updates must be made as frequently as changes occur.

172    With respect to ST PASA, the standard is expressed and embodied in the words “current intentions and best estimates”. An issue arises as to whether those words apply to each of the three ST PASA inputs identified in cl 3.7.3(e). The AER accepts that the words of the clause are such that there is no room for the application of the maxim which would enable the clause to be read distributively, reddendo singula singulis (Canadian Pacific Tobacco Co Ltd v Stapleton [1952] HCA 32; (1952) 86 CLR 1 at 6 per Dixon CJ; Commonwealth v Sterling Nicholas Duty Free Pty Ltd (1972) 126 CLR 297 at 313–314 per Windeyer J).

173    The first of AER’s arguments was that “current intentions” attaches to the Scheduled Generator’s own actions and “best estimates” attaches to forecasts beyond the control of the Scheduled Generator and are forecasts that would be made by a diligent and competent generator in the position of the Scheduled Generator. The AER’s submission is that current intentions attaches to the ST PASA input involving available capacity (i.e., cl 3.7.3(e)(1)), but that the concept of best estimates also has a role to play in this respect because it is available capacity under “expected market conditions”.

174    By contrast, the other two ST PASA inputs, that is to say, PASA availability and projected daily energy availability, are objective matters and the notion of best estimates attaches to those matters because a generator is capable of answering the questions they raise by drawing on its own knowledge of the technical and physical capabilities of its plant and, for an energy constrained scheduled generating unit, its knowledge and experience of the fuel supply arrangements that it continually manages in its day-to-day operation of the generation unit. PASA availability has nothing to do with the Scheduled Generator’s current intentions. The AER submitted that that must be so because were it otherwise, the first ST PASA input i.e., available capacity would overlap with the second ST PASA input i.e., PASA availability. Furthermore, it would give a different meaning to PASA availability in the case of ST PASA compared with MT PASA because in the latter case, I should accept the AER’s submission that the Scheduled Generator’s current intentions are not relevant to MT PASA.

175    The AER’s alternative argument which is reflected in the alternative formulation of the declaration it seeks (see [2] above) was that the concept of “current intentions” has the most work to do in terms of the ST PASA input of available capacity. It submitted in the alternative that it also has work to do in relation to PASA availability and that PPPL’s contention to the effect that the AER submitted otherwise is incorrect. The AER submitted that the intention of the Scheduled Generator is relevant to the extent it has a bearing upon the generating capacity and the extent to which it is possible to make it available. The AER proffered an example of an immediate intention by a Scheduled Generator to decommission a turbine or to place it in dry storage and that intention has the consequence that it is not possible to make that turbine available on a particular date on 24 hours’ notice. The AER submitted that, on the other hand, the reference to current intentions does not have the effect that PASA availability “as a whole” is to be determined by whether or not the Scheduled Generator wishes to make the generating capacity available. The AER’s alternative construction (it submitted) gives the expression “current intentions and best estimates” work to do which is consonant with the definition of PASA availability and the purpose of the Rules.

176    The remaining question is what an obligation to provide best estimates precisely means in terms of the standard of care required of a Scheduled Generator. The AER submitted that this is a higher standard than that attaching to the estimate of PASA availability for MT PASA. The AER submitted that this is “entirely understandable, in circumstances where the relevant outlook timeframe is no more than 7 days ahead, rather than 2 years”. That is because a forecast for a seven day period can be expected to have a much firmer base in terms of likely fuel supply and transport conditions than a forecast for a period of two years. Furthermore, there will be a more reliable weather forecast in the case of ST PASA.

177    With respect to ST PASA and cl 3.7.3(e), the AER submitted that there is an objective element in the obligation identified as representing the Scheduled Generator’s current intentions and best estimates. It submitted that the concept of best estimate “connotes diligence by the scheduled generator in making all possible inquiries about information that would bear upon the estimate”. An estimate would not be a best estimate if, for example, it was premised solely upon information that was within the knowledge of the Scheduled Generator and the notion of a best estimate must at least involve an obligation to make inquiries. The AER does not advance the concept of a “hypothetical reasonable diligent and prudent generator” as the words to be read into the provision. That concept simply represents the identification of a legal standard by reference to a hypothetical person (Healthcare v Common Services Agency). The AER submitted, correctly in my view, that evidence from a reasonable Scheduled Generator is not required because the reference to this concept is, as the AER put it, a “focusing lens” and it does not stand in substitution for the words of the provisions themselves.

178    The AER submitted that the forecast which is to involve the Scheduled Generator’s best estimate remains just that and that it is not a binding promise. The AER submitted that that is made clear when regard is had to Chapter 4 and that part of Chapter 4 which empowers AEMO to issue directions to a Registered Participant and the fact that the Registered Participant’s obligation with respect to the direction is to use reasonable endeavours to comply with it “unless to do so would, in the Registered Participant’s reasonable opinion, be a hazard to public safety, or materially risk damaging equipment, or contravene any other law” (cl 4.8.9(c)). Furthermore, the fact that the Scheduled Generator’s best estimate is not a binding promise is also made clear by cl 3.13.2(h) and the obligation on the Scheduled Generator to notify AEMO of any changes to submitted information within the times prescribed in the timetable.

179    PPPL emphasised the fact that the primary focus of the PASA processes is the collection of information which will best assist the market to understand the supply intentions of other participants so that the market makes sufficient decisions “thus obviating the need for market intervention is prioritised over a process or system designed to facilitate market intervention”. PPPL submitted that conversely, to make a PASA availability submission which suggests the availability of items of plant for which no firm gas supply or transport rights are, or are intended to be, in place and which for operational reasons are being run on a restricted basis, would be damaging to the objective of facilitating efficient decision-making by the market and minimising the need for market intervention. PPPL submitted that if PASA availability is required to be assessed and submitted in the manner contended for by the AER, it is difficult to see how AEMO could ascertain, as cl 3.7.1(c) requires it to over a 24 month period, the intended plant availabilities consistent with the intentions of Scheduled Generators. PPPL submitted that the obligations imposed by cll 3.7.2(d) and 3.7.3(e) are obligations to submit PASA inputs, in the latter case in accordance with the Scheduled Generator’s current intentions and best estimates. The Court should hesitate (so the submission goes) to read words into those provisions which impose additional and different obligations, and thereby expand the scope of a civil penalty provision, particularly where it cannot safely conclude that to do so is necessary to advance the National Electricity Objective and the purpose of the PASA regime.

180    PPPL submitted that there had been an impermissible shift in the AER’s case concerning the standard required by the NER. This shift is best illustrated by a comparison of the AER’s opening submissions and its closing submissions.

181    In its opening submissions, the AER submitted that having determined the meaning of “PASA availability”, the following issue arises. PASA availability is intended to be a measure of what a generator is practically capable of doing either if it were to decide to offer additional capacity as available for dispatch in the wholesale market or if it were directed by AEMO to bring additional generating capacity into service. It is not concerned with the generator’s commercial intention as to how much electricity it proposed to bid into the NEM. PASA availability is directed to the capacity that a Scheduled Generator would reasonably and practically expect to be able to supply having regard to fuel supply and other operational arrangements in their day-to-day operational context. The NER are directed to practical people skilled in the operation of scheduled generating units and ought to be construed to take account of practical and commercial considerations, including how much fuel the generator is able to obtain through typical commercial arrangements. The word “availability” in the definition of PASA availability should be construed in a practical and operationally-orientated way so as to require the generator of a gas-fired scheduled generating unit not only to take account of its existing firm contractual rights to gas and gas transport, but also any additional fuel that it would ordinarily have a reasonable expectation of obtaining if necessary on 24 hours’ notice. PASA availability (and projected daily energy availability) are objective estimates that a generator is capable of answering drawing on its own knowledge of the technical and physical capabilities of its plant and for an energy constrained scheduled generating unit, its knowledge and evidence of the fuel supply arrangements that it continually manages in its day-to-day operation of the generating unit. The Scheduled Generator is required to supply its best estimate.

182    In its closing written submissions, the AER submitted that the questions in issue in this proceeding concerned the maximum generating capacity that was possible for PPPL to make available on 24 hours’ notice for any part of the day on 8 February 2017 and it is not whether PPPL should have estimated that it would be able to obtain enough gas and transport on 24 hours’ notice to enable a second turbine to run in addition to whatever amounts of gas and transport PPPL might require to operate its first turbine however it pleases and, for example, at up to 240 MW for 24 hours continuously. The AER submitted that if AEMO had issued a direction requiring PPPL to generate at 320 MW in 24 hours’ time, that would have allowed PPPL more than sufficient time to change its intended running of the Pelican Point PS by reallocating the gas that it was otherwise intending to use to operate a single turbine to instead operate two turbines for at least some part of the day. The AER submitted that the issues in the proceeding do not require the Court to consider whether PPPL should have estimated that it would be able to obtain gas supply and transport on 24 hours’ notice in addition to the gas supply and transport PPPL required to run a single turbine in whatever manner PPPL wished. The AER submitted the following:

The question is whether PPPL should have estimated that, on 24 hours’ notice, it could be rearranged its existing business plans so that it could run two turbines concurrently to generate 320 MW for any part of 8 February 2017.

183    In oral submissions, the AER submitted that a best estimate required the task to be approached in the most comprehensive way possible and that the notion of a best estimate presupposes that all inquiries and all analysis that can be undertaken will be undertaken.

184    The Rules dealing with PASA submissions are not a model of clear and precise drafting. Although I have attempted to summarise the parties’ submissions, it was not always clear which arguments were their primary arguments and which were their secondary arguments. At times, the parties did not seem far apart on the construction issues and at other times, their submissions were at opposite ends of the spectrum.

185    The starting point is that I agree with the AER’s acceptance of the proposition that the construction issue as whether the requirement of “current intentions” attaches to all three ST PASA inputs or only the first is not solved by the syntactical presumption reflected in the maxim, reddendo singula singulis (render each to each or read the phrases distributively) which means each object is linked to its appropriate subject. In this regard, I refer to the discussion in Bailey D and Norbury L, Bennion, Bailey and Norbury on Statutory interpretation (8th ed, LexisNexis, Butterworths, 2020) and it is correct that it is not applicable. The reason the syntactical presumption does not apply is that here there are two objects and three subjects (or three objects and two subjects).

186    The next argument is that even though the presumption does not apply, as a matter of construction current intentions is linked to available capacity and best estimates is linked to PASA availability. There are two difficulties with that submission. First, it is not how the rule is structured. On the face of it, the description “current intentions and best estimates” applies to each of the three ST PASA inputs. Secondly, it is clear when one goes to the definition of the concepts that both current intentions and best estimates could be relevant in the case of each of them. In the case of available capacity, a Scheduled Generator’s best estimate may be required because of the reference to “expected market conditions”. Further, current intentions may be relevant to PASA availability as the AER recognised in their alternative argument. As it submitted, a current intention to decommission a turbine may well be relevant to what will be available and what can be made available. As to the third ST PASA input, that is, the projected daily energy availability for energy constrained scheduled generating units and energy constrained scheduled loads, this is a reference to the energy a generating unit is to produce less than its full nominated availability for the whole of the trading day. With respect to this type of information, both concepts of current intentions and best estimates may be relevant because the projected daily energy availability for energy constrained scheduled generating units and energy constrained scheduled loads may be affected by arrangements and intentions as to gas supply and gas transport.

187    In my opinion, the two concepts of current intentions and best estimates are linked and both apply to PASA availability. The concept of current intentions is relevant to the availability of the physical plant capability of a scheduled generating unit and the concept of best estimates is relevant to what can be made available on 24 hours’ notice and perhaps the overall assessment of the “maximum MW output”. I reject, insofar as it was put by PPPL, the submission that the only relevant factor was its business plans. That would be to ignore the words. “that can be made available … on 24 hours’ notice” which refers to physical plant capability where there is no present intention to use it or, at least, the Scheduled Generator is undecided. At the same time, I do not consider that current intention is irrelevant to PASA availability. It seems to me that the most sensible reading of cl 3.7.3(e) and the definitions of PASA availability and physical plant capability is that it refers to what the Scheduled Generator intends and what it could do on 24 hours’ notice. I am not convinced that the reference to notice is a reference to notice by any particular person or entity, for example, AEMO. It is a reference to an event for the purposes of fixing a time period for assessing availability.

188    I do not consider that a hypothetical operating scenario which is completely divorced from a Scheduled Generator’s actual intentions is within the scope of the rule and definitions. I consider the AER’s basic 320 MW scenario meets this description. There are other reasons I do not think it an appropriate scenario by which to judge PPPL’s compliance with the Rules and I will set these out later in these reasons (at [492]–[495]). The AER does not dispute that at all times prior to 9 February 2017, PPPL intended to run only one turbine and had no intention of operating both turbines concurrently. The starting point then is the running of one turbine for a substantial part of the day on 8 February 2017.

189    The next question then is what precisely is required of a Scheduled Generator who is required to give its best estimate of the physical plant capability that can be made available on 24 hours’ notice? The term “best estimates” is not defined in the Rules. It is to be given its ordinary meaning. The Macquarie Dictionary (6th ed) definitions of the word “estimate” highlight the approximate nature of the result and the extent to which it involves an opinion or judgment. The word “best” is an ordinary English word and the most apposite meaning in the term best judgment is a judgment of the “highest quality, excellence or standing” (Macquarie Dictionary (6th ed). In my opinion, a Scheduled Generator must form a judgment as to the physical plant capability that can be made available on 24 hours’ notice, that is, the best judgment it can reasonably form on the information known to it, including information it can reasonably be expected to obtain in the circumstances.

The relevance of the Scheduled Generator’s commercial intention

190    The commercial intention of the Scheduled Generator will be relevant to the available capacity referred to in cl 3.7.3(e)(1) and it will be relevant to that part of the definition of PASA availability which relates to the physical plant capability of a scheduled generating unit which is available. It is not directly relevant to that part of PASA availability which relates to the physical plant capability of a scheduled generating unit which can be made available on 24 hours’ notice which assumes it is not otherwise the Scheduled Generator’s intention to make it available. As I have said, that is not to say that the Scheduled Generator’s commercial intentions may not give rise to circumstances that bear on whether the physical plant capability of a scheduled generating unit can be made available on 24 hours’ notice.

Is the Scheduled Generator limited to taking into account only firm sources of gas and gas transport?

191    The AER submitted that a fundamental difference between it and PPPL concerned whether, in ascertaining the physical plant capability that is, or can be made, available on 24 hours’ notice, it is relevant to take into account only gas supply and gas transportation to which a Scheduled Generator has firm rights (PPPL’s contention) or whether in addition, it is relevant to take into account any other gas supply and gas transportation the Scheduled Generator ought reasonably expect that it would practically be able to procure on 24 hours’ notice if required to do so, including gas supply and gas transportation to which a Scheduled Generator has non-firm rights, and other gas that may be available in short term trading markets and for which that Scheduled Generator may be able to arrange transportation rights (AER’s contention). This does appear to be an issue, although in parts of his evidence PPPL’s expert, Mr O’Farrell, seemed to accept that non-firm gas and gas transport might be relevant where securing it was highly probable or likely.

192    The AER submitted that as a matter of construction, this issue appeared to revolve around the meaning of the word “available”, as it appears twice in the definition of PASA availability.

193    The AER’s primary submission was that the concept of PASA availability speaks generally to the capacity that a Scheduled Generator would reasonably and practically expect to be able to supply having regard to fuel supply and other operational arrangements in their day-to-day operational context. The PASA rules are addressed to practical people skilled in the operation of scheduled generating units, and so ought to be construed to take account of practical and commercial considerations (including how much fuel the generator can obtain through typical commercial arrangements), rather than “by minute contractual parsing of gas supply and transport agreements”.

194    The AER submitted that its interpretation was supported by the following matters.

195    First, the statement in the report of the Code Change Panel to the effect that a distinction is to be drawn between the capacity generators intend to make available and the capacity they could make available in extreme conditions. Furthermore, the point is underscored by the fact that AEMO is to be notified of energy constraints and is required to take into account any energy constraints that will impose a practical constraint on a generating unit’s ability to generate continuously at the level of PASA availability or the available capacity indicated.

196    Secondly, the word “available” does not have a settled or consistent technical meaning when used more generally in the NER. It is not defined in the NER. It is used in Chapters 3 and 4 of the NER in a general way “to refer variously to a plant’s ability to operate or respond in a given set of power system and/or market conditions, and to the generation capacity that a generator has bid for dispatch in the wholesale market”. The AER referred to the notion of “available capacity” and its connection with the bidding and dispatch provisions of the NER and, in particular, it referred to the fact that “available” is used in the definition in “available capacity” and in cl 3.8.4(a) as part of the expression “available capacity” (in unitalicised form).

197    The AER referred to other uses of “available” or “availability” in Chapters 3 and 4, including in cll 3.8.1(b)(2)(i), 3.9.7(a), 3.13.4(f)(4), 3.13.7(d)(1), 4.9.2(d), 4.9.9, 4.9.9A and 4.9.9B. The AER submitted that an examination of these clauses reveals that where used across Chapters 3 and 4 of the NER the undefined word “availability” does not have a consistent or technical meaning that necessarily fixes the meaning of the word “availability” as it appears in the definition of PASA availability.

198    The AER submitted that in the absence of any settled technical meaning, it may then be appropriate for the Court to have regard to the natural and ordinary meaning of “available”. The AER submitted (correctly) that the primary meanings of “available” given by the Oxford and Macquarie Dictionaries are as follows:

(1)    able to be used or obtained; at someone’s disposal (Australian Oxford Dictionary); and

(2)    suitable or ready for use; at hand; of use or service (Macquarie Dictionary).

199    The AER submitted that those meanings emphasise a thing’s ability or suitability for use and do not imply the need for any contractual or other legal right in relation to the product or service. The word “availability” should be interpreted in a practical and operationally-oriented way so as to require the generator of a gas-fired scheduled generating unit not only to take account of its existing firm contractual rights to gas and gas transport, but also any additional fuel that it would ordinarily have a reasonable expectation of obtaining, if necessary, on 24 hours’ notice. The AER’s submission is that there is nothing in the definition or in any of the relevant extrinsic materials for the 2001 Code change to indicate that PASA availability should take account of only that physical plant capability for which a Scheduled Generator has firm contractual rights to any necessary fuel supply. If the Code Change Panel and/or the National Electricity Code Administrator had wished to restrict the meaning in that way, they could readily have drafted the definition in a way that made that intention clear.

200    In my opinion, even leaving aside the extrinsic material, the AER’s submissions are correct. If the test in the case of MT PASA is one of a reasonable estimate, including a reasonable expectation of gas supply and gas transport, and in the case of ST PASA, one of a best estimate, including a reasonable expectation of gas supply and gas transport, there is no reason to draw a distinction between firm gas supply and non-firm gas supply and transport. The question is one of fact and whilst the matter is relevant and may well be significant in many cases, the ultimate question is whether the circumstances meet or do not meet the relevant test.

Running time considerations

201    It is convenient to deal with the final two issues identified by the AER together.

202    The AER referred to these issues as the “running time considerations”, that is to say, the running time of the gas turbines. The Pelican Point PS is a “mid-merit” power station and typically, it fills the gap between “base load” power stations which are power stations which are low cost and constantly operating, and “peaking” power stations which are power stations which are high cost and operate only at peak times. The AER submitted that the gas turbines at the Pelican Point PS are operated flexibly to respond to periods of high energy demand, from periods as short as four hours up to periods of days or weeks continuously, but at varying levels of output. Mr Foulds gave evidence that he had been informed by PPPL’s engineers that the prudent minimum run-time to avoid additional wear and tear on the gas turbines is eight hours and that, in certain circumstances, where the gas turbine has recently, that is to say, in the last few days been in service, it may be possible to operate the turbine for a period shorter than eight hours and for as little as four hours.

203    It will be recalled that the MT PASA framework requires PASA availability to be forecast on a daily basis, whereas the ST PASA framework requires PASA availability to be forecast on a 30 minute trading interval basis.

204    The AER submitted that PASA availability does not relate to a Scheduled Generator’s intention to offer its generating capacity into the wholesale market, but rather, PASA availability is an estimate of the physical plant capability that is potentially available if the generator were to bid in the wholesale market to generate up to that output level, or if it were given a direction to do so by AEMO. The AER submitted that the submission of PASA availability by a Scheduled Generator to AEMO for a given day or trading interval contains no representation that a generator intends to operate its generating unit at the PASA available output level for all or any part of a day in the MT PASA framework, or in any trading interval or any number of consecutive trading intervals in the ST PASA framework. The AER submitted that this proposition is important in three respects. First, contrary to PPPL’s response, PASA availability does not imply that a generating unit can be run for any extended period of time. Secondly, PASA availability is not capable of misleading the energy trading and derivatives markets about the generator’s intention as to its planned bidding and running of the generating unit. Thirdly, PASA availability is relevant to issues of fuel supply. In particular, to indicate that a generating unit is PASA available on a particular day does not imply that the generator must reasonably expect that it will be able to obtain sufficient fuel to run the generating unit at the PASA available output level for 24 hours continuously.

205    The AER addressed the issue of how PASA availability for MT PASA is affected by a practical limit on how long a generating unit can run within a day. The AER submitted that if a generator would reasonably expect that the physical plant capability of its generating unit could be made available for only part of a day, including because of any reasonably expected fuel constraints, then its obligation is to indicate the maximum amount of its physical plant capability that can be made available for any part of that day. The AER submitted that this conclusion follows from the text of the definition of PASA availability and, in particular, “available in a particular period, including any physical plant capability that can be made available during that period, on 24 hours’ notice”. The effect of these words is not to require that the physical plant capability be available to be operated for the whole of a day. Further support for that conclusion follows from the fact that if the generating unit is unable to run continuously throughout the day because of fuel constraints, then there is an obligation on the generator to inform AEMO of that through the weekly energy constraints parameter (cl 3.7.2(d)(2)). The AER submitted that this conclusion is also supported by reference to cl 3.7.2(f)(5)(5A) and (5B). An interpretation which would mean that PASA availability was limited to generating units which could supply continuously over a whole day would mean that the reserve capacity supplied by “peaking” gas-fired generating units would go wholly unrecognised by the MT PASA process.

206    The AER addressed whether PASA availability for ST PASA is affected for how long a generating unit can run for within a day. This question is answered by the fact that forecasts of PASA availability for ST PASA are required to be made separately for each half hour trading interval. The AER submitted that it follows from the fact that PASA availability does not relate to a Scheduled Generator’s intention to offer its generating capacity into the wholesale market, that the physical plant capability of the generating unit should be designated as PASA available for each of the 48 trading intervals throughout the trading day. To do so does not represent or imply that the generator will bid that generating unit to operate at that output level (or at all) continuously throughout the day, or that the generator’s best estimate is that it would be able to obtain sufficient fuel to run the generating unit for 24 hours continuously. The AER said that as noted above in relation to PASA availability in the context of MT PASA, if the reason for a generating unit’s inability to run continuously throughout a day is a lack of reasonably expected fuel supply, then the generating unit is an energy constrained scheduled generating unit and the generator is required to notify AEMO of its projected daily energy availability (see cl 3.7.3(e)(4)).

207    I agree with the AER’s submissions. PPPL’s PASA submissions were based on one gas turbine operating with the steam turbine and one figure was given for the relevant periods, even though at least in the case of the ST PASA submissions, the gas turbine was not operating at that figure throughout the relevant period. The AER’s submissions do not mean that the starting point is not what the Scheduled Generator intends to make available and then it must consider what physical plant capability can be made available on 24 hours’ notice. The AER’s 8 February counterfactual is that GT11 runs as it did on 8 February 2017 and GT12 is run for approximately four hours. This operating scenario is within the definition of PASA availability which refers to available “in a particular period” and to any physical plant capability that can be made available “during that period”.

208    The parties did not identify any construction issues in relation to cl 3.13.2(h). The AER’s submissions with respect to this clause are correct. With respect to cl 3.13.2(h), the AER submitted that the reference to changes to submitted information should be construed to mean a change in the reasonable estimate of PASA availability and that ordinarily, it is expected that a change to the reasonable estimate of PASA availability would occur as a result of some change affecting the physical plant capability of a generating unit, or affecting the generator’s ability to make some or all of that physical plant capability available on 24 hours’ notice. The timetable requires a Scheduled Generator to notify AEMO of its MT PASA inputs as frequently as changes occur and for the purposes of applying 3.13.2(h), the AER submitted that this should be interpreted as requiring a Scheduled Generator to notify AEMO of any changes to previously submitted MT PASA inputs as soon as practicable. At all times prior to 11 November 2016, the PASA availability that PPPL submitted for the MT PASA for 8 February 2017 was 224 MW. It follows, that PPPL will have contravened cl 3.13.2(h) after 11 November 2016 if 224 MW was no longer a reasonable estimate of PASA availability for 8 February 2017 and PPPL failed to notify AEMO of that change as soon as practicable.

WITNESSES

209    There are three important matters to be mentioned at the outset. First, in the section which follows, I will examine the evidence of each witness. In some cases, there was barely a challenge to their evidence and their evidence may be accepted. In other cases, such as in the case of the experts (Messrs Snow and O’Farrell) and Mr Weatherly, I will need to come back to their evidence when I deal in detail with the availability of gas and of gas transport. Secondly, in making findings I bear in mind s 140 of the Evidence Act 1995 (Cth) and that the contraventions alleged involve civil penalty provisions (Briginshaw v Briginshaw [1938] HCA 34; (1938) 60 CLR 336 at 361–362; Neat Holdings Pty Ltd v Karajan Holdings Pty Ltd [1992] HCA 66; (1992) 110 ALR 449; (1992) 67 ALJR 170 at 170–171 per Mason CJ, Brennan, Deane and Gaudron JJ; Setka v Gregor (No 2) [2011] FCAFC 90; (2011) 195 FCR 203 at [24]–[26] per Lander, Tracey and Yates JJ; Morley v Australian Securities and Investments Commission [2010] NSWCA 331; (2010) 247 FLR 140 at [742]–745]). Thirdly, I did not draw any adverse inferences by reason of demeanour in relation to any of the witnesses. That, of course, does not mean that I accept all of the evidence of a particular witness. As will be seen, I do not. In a number of areas I have drawn a different inference from that drawn by the witness or characterised a set of circumstances in a different way from the way the witness has characterised those circumstances. I have done so by reference to “contemporary materials, objectively established facts and the apparent logic of events” (Fox v Percy [2003] HCA 22; (2003) 214 CLR 118 at [30]–[31] per Gleeson CJ, Gummow and Kirby JJ).

The AER’s witnesses

Mr Van Der Walt

210    As I have said, Mr Van Der Walt is employed by AEMO as Group Manager, NEM Real Time Operations. In opening, counsel for the AER described Mr Van Der Walt’s evidence as providing a general overview of the PASA regime and evidence sourced from AEMO’s data base of a technical nature. In its closing written submissions, PPPL said that there was no issue of credit and the Court can accept Mr Van Der Walt’s evidence. I agree that there is no issue as to credit and I accept Mr Van Der Walt’s evidence.

211    The principal matters to emerge from Mr Van Der Walt’s evidence are his description of AEMO’s role, the operation of the PASA system, AEMO’s power to issue directions to Registered Participants and the events on 8 February 2017 and 9 February 2017 from AEMO’s point of view.

212    Mr Van Der Walt described AEMO as the independent market and system operator for the NEM. He described the NEM as the interconnected power system in Australia’s eastern and south-eastern seaboard and Tasmania, and a wholesale exchange for the buying and selling of electricity. He described AEMO’s statutory functions as laid down in the NEL and the NER as operating and administering the wholesale exchange and collecting, analysing and publishing information in relation to the Projected Assessment of System Adequacy (PASA) and monitoring and maintaining power system security.

213    Mr Van Der Walt’s present role is as the manager with overall responsibility for AEMO’s real-time electricity system operations in the NEM, including the maintenance of security and reliability of electricity supply for the interconnected power system for the NEM and scheduling and real-time dispatch of energy services for the NEM.

214    Mr Van Der Walt was employed by AEMO’s predecessor organisation, NEMMCO. Between March 2016 and October 2017, he held the position of Senior Manager, NEM Real Time Operations.

215    Mr Van Der Walt said that a key aspect of AEMO’s function of monitoring and maintaining power system security is to ensure that there is sufficient power supply to meet forecast demand. He said that this includes ensuring that there are sufficient capacity reserves in the event that certain types of event occur which impact on the supply of power.

216    Mr Van Der Walt identified AEMO’s power system security responsibilities and obligations as set out in cl 4.3.1 of the NER. He also referred to the obligation of generators to submit MT PASA inputs and ST PASA inputs. A Scheduled Generator must submit its MT PASA inputs on a weekly basis, or more frequently if a materially significant change exists, covering a 24 month period with a daily resolution. A Scheduled Generator must submit its ST PASA inputs on at least a daily basis, and as frequently as changes to the previously submitted values occur, covering a rolling period of six trading days, with a 30 minute resolution.

217    Mr Van Der Walt referred to the definitions of “available capacity” and “PASA availability” and said that AEMO uses the information submitted by reference to those matters by scheduled generating units, forecasts of semi-scheduled generation and “available capacity” of scheduled loads to determine the forecast level of capacity reserves and whether there is a forecast reserve shortfall in each NEM region. Mr Van Der Walt said that AEMO publishes capacity reserves for NEM regions and regionally aggregated short term “PASA availability” of generation. This aggregated “PASA availability” information is used to inform AEMO and the market as to whether there is additional capacity available for recall within 24 hours to address any forecast reserve shortfall. He said that AEMO also uses the short term “PASA availability” as submitted for individual generating units to determine which generating units may be available for direction, if required in order to maintain or restore power system security and reliability.

218    Mr Van Der Walt referred to Chapter 4 of the NER which addresses power system security and, in particular, he referred to cl 4.8.4 which empowers AEMO to declare various conditions in relation to the power system. He also referred to s 116 of the NEL and cl 4.8.9 of the NER which give AEMO the power to intervene in the market in certain circumstances. Mr Van Der Walt made the point that in circumstances of supply scarcity, AEMO uses its reasonable endeavours to issue a direction only if, by the latest time to intervene, the requirement still exists and is not expected to be fully met by a market response or by action taken under any available reserve contract. He said that in determining whether, when and to which Registered Participants AEMO may need to issue a direction or instruction, AEMO relies primarily on the information provided by Registered Participants in the PASA process. AEMO may also contact Registered Participants directly to request additional information, or to confirm information that has already been provided. A Registered Participant which has been issued with a direction by AEMO must use its reasonable endeavours to comply with that direction.

219    PPPL is the registered generator in respect of the Pelican Point PS. The Pelican Point PS is the second largest power station in South Australia. PPPL’s parent company is ENGIE, previously known as GDF Suez, which is a global energy company. The Pelican Point PS has three aggregated turbines with an aggregated registered capacity of 478 MW. The three turbines are registered as an aggregated generator with a single dispatchable unit identifier of “PPCCGT”. The three turbines at the Pelican Point PS comprise two 160 MW gas turbines and one 158 MW steam turbine. The steam turbine may only be operated in conjunction with one or both of the gas turbines, for a registered capacity of 478 MW if both gas turbines are operated and approximately half of that capacity if only one of the gas turbines is operated.

220    Mr Van Der Walt produced correspondence from GDF Suez to AEMO in June 2014 advising of a reduction of station capacity of the Pelican Point PS to half (240 MW) from 1 April 2015.

221    AEMO maintains a database known as the “WARE” database. That database includes all market data associated with the NEM, including the PASA submissions by generators and the power generation output of generators. Mr Van Der Walt said that the database receives data from various sources, including a continuous live feed of SCADA data from transmission network service providers. In South Australia, the transmission network service provider is ElectraNet and it provides data which includes, among other things, power generation output data relating to the Pelican Point PS.

222    Between 9 February 2015 and 8 February 2017, PPPL’s submissions to AEMO of its MT PASA availability for the Pelican Point PS for 8 February 2017 reflected a value of 224 MW. Between 15 January 2017 and 8 February 2017, PPPL’s submissions to AEMO of its ST PASA availability for the Pelican Point PS for the 8 February 2017 trading day did not exceed 235 MW.

223    The function of Market Notices includes a function of informing the market of AEMO’s intention to intervene in the market. Participant Notices are directed at particular participants and, for example, may be to confirm a direction AEMO has issued to that participant. Market Notices and Participant Notices are stored on AEMO’s website. Mr Van Der Walt said that when AEMO issues a direction, it takes effect from the time that it is issued verbally by AEMO’s control room staff to the participant.

224    On 31 January 2017 at 15.27, AEMO issued a Market Notice advising of low reserve conditions in South Australia for February and March 2017, summer 2017/2018 and summer 2018/2019.

225    On 8 February 2017, the recorded maximum temperature in Adelaide was 42.4oC and on 9 February 2017, the recorded maximum temperature was 41oC.

226    Certain events occurred on 8 February 2017 involving action taken by AEMO and ENGIE. Rather than attempt to summarise the evidence of Mr Van Der Walt, it is convenient to set it out. The times set out in what follows are Australian Eastern Standard Time:

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).

(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).

(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).

(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.

(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:

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

(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.’

(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.

227    Mr Van Der Walt states that prior to the telephone conversation between staff of AEMO and ENGIE at 18.00 on 8 February 2017, to the best of his knowledge, AEMO had not been informed by PPPL (or ENGIE on its behalf) that GT12 could be made available on 8 and 9 February 2017 within 24 hours’ notice.

228    Certain events occurred on 9 February 2017 involving AEMO and ENGIE. Again, rather than attempt to summarise the evidence of Mr Van Der Walt, it is convenient to set it out:

43.    On 9 February 2017:

(a)    at 3:28, AEMO declared a forecast LOR2 condition for the South Australia region on 9 February 2017 from 16:30 to 18:00, and stated that it was ‘seeking a market response’ (Market Notice 57295).

(b)    at 6:10, AEMO called Engie with further queries about the availability of GT12.

(c)    at 6:33, Engie called AEMO to provide it with an update.

(d)    at 6:36, AEMO called Engie with a further query.

(e)    at 10:49, AEMO declared a forecast LOR2 condition for the South Australia region on 9 February 2017 from 15:30 to 18:00, and stated that it was ‘seeking a market response’ (Market Notice 57307).

(f)    at 10:51, AEMO declared a forecast LOR1 condition for the South Australia region on 9 February 2017 from 13:30 to 15:30 and from 18:00 to 19:00 (Market Notice 57308).

(g)    at 13:20, AEMO declared a forecast LOR2 condition for the South Australia region on 9 February 2017 from 15:30 to 18:00, and stated that it was ‘seeking a market response’ (Market Notice 57313).

(h)    at 14:49, AEMO declared a forecast LOR2 condition for the South Australia region on 9 February 2017 from 16:00 to 18:00, and stated that it was ‘seeking a market response’ (Market Notice 57319). The Notice also stated that ‘AEMO intends to intervene through an AEMO intervention event at 1500 hrs if a sufficient market response is not achieved.’

(i)    at 15:05, AEMO issued a direction to PPPL, to synchronise and dispatch generating unit GT12 to its minimum load (Participant Notice 57310). At Tab 16 of Exhibit TNV-01 is an extract from the AEMO Control Room Log. This was announced by a further Market Notice at 15: 17 (Market Notice 57312).

(j)    in response to AEMO’s direction, PPPL made additional generation available to the market, effective at 15:30, which resulted in output from the Pelican Point Power Station increasing from approximately 215MW at 16:00 to approximately 320MW at 17:00. At Tab 17 of Exhibit TNV-01 is a table stating the output of Pelican Point PS on 8 and 9 February 2017. The data in that table is extracted from AEMO’s “WARE” database.

(k)    at 19:09, AEMO issued a notice cancelling its previous direction to PPPL from 19:00 (Market Notice 57347). The output from Pelican Point PS thereafter decreased from 320MW at 19:00 to 214MW at 20:00.

(l)    at 19:20, AEMO declared an actual LOR1 condition in the South Australia region on 9 February 2017 from 19:00 to 20:00 (Market Notice 57349).

(m)    at 20:07, AEMO issued a notice that the actual LOR1 condition in the South Australia region on 9 February 2017 was cancelled at 20:00 (Market Notice 57350).

229    On 8 February 2017, the power system was not in a secure operating state for more than 30 minutes and AEMO issued an instruction under cl 4.8.9 of the NER for load shedding. AEMO subsequently conducted a review and prepared a report in accordance with cl 4.8.15(c) of the NER titled “System Event Report. South Australia, 8 February 2017” dated 15 February 2017.

230    Following AEMO’s issue of a direction to PPPL on 9 February 2017, AEMO prepared a report under cl 3.13.6A(a) of the NER titled “NEM Event – Direction to South Australia Generator – 9 February 2017” dated July 2017.

231    Mr Van Der Walt produced a spreadsheet of PPPL’s MT PASA availability submissions from 11 November 2016 to 8 February 2017 and a spreadsheet of PPPL’s ST PASA availability submissions from 4 February 2017 to 12 February 2017.

232    In cross-examination, Mr Van Der Walt agreed that the SCADA data fed into AEMO’s WARE database contained information as to precisely which generating unit at the Pelican Point PS was operating on an hourly basis. He said that AEMO does not use the SCADA data to establish which unit is generating. It uses the DUID, the unit identifier, for that information in the system.

233    Mr Van Der Walt was taken to the SCADA data or real-time information provided to AEMO in respect of the generating units at the Pelican Point PS. The data is available to persons such as Mr Van Der Walt if they look for it. Mr Van Der Walt said that in Pelican Point PS’s case, the two gas turbines and the steam turbine are aggregated. Mr Van Der Walt said that in addition to action taken in managing a situation, AEMO may speak to governments to see if they can do anything reliability wise, such as switching off their buildings.

234    Mr Van Der Walt said that “RERT” stands for Reliability and Emergency Reserve Trader and is a process made available to AEMO to manage the reliability issues when there is not enough scheduled generation. If a person is in the market, then he or she are not allowed to be on the RERT panel. Mr Van Der Walt gave an example of a smelter and contact being made because under a contract they can be asked to reduce their demand. PPPL was one of the RERT panel members and the arrangement involved the entry into agreements with panel participants. The RERT Panel Agreement between AEMO and PPPL was dated 9 February 2016. Mr Van Der Walt did not have a role in connection with this RERT panel. The RERT Panel Agreement did not feature in either party’s closing submissions.

235    Mr Van Der Walt was asked to identify the first day prior to 8 February 2017 that PPPL was required to submit ST PASA for that day. Mr Van Der Walt agreed that the seven day window commenced on 2 February 2017 and that they were required through until 8 February 2017. Furthermore, a number of ST PASA submissions were submitted across the day on 8 February 2017. The ST PASA submissions were provided at different times during the day. The ST PASA submissions are upgraded to take into account, for example, temperature changes which may affect the generating capacity of the Scheduled Generator. ST PASA submissions were lodged at 16.42 and it appears, although it is not entirely clear, that the ST PASA was providing a “look-forward” for the balance of the day which was the requirement of the ST PASA regime. That cross-examination, or at least the latter part of it, seems to have been directed to an issue (still outstanding) as to the number of contraventions if liability is established.

236    In re-examination, Mr Van Der Walt said that there was nothing which would prompt him to look for the SCADA data on the WARE database. He said that there was no reason for those at AEMO to dig in that deep if there is no actual event happening at the station. Mr Van Der Walt said that AEMO does not use the SCADA data to ascertain the maximum generating capacity of the plant.

Ms Eastgate

237    As I have said, Ms Eastgate is employed by the AER as an Assistant Director in its Compliance and Enforcement Branch. She assists in the investigation of matters to be reported to the AER Board. She has been involved in the investigation of the conduct which is the subject of these proceedings since June 2017.

238    In his opening, counsel for the AER described Ms Eastgate’s evidence as evidence of a technical nature. In its closing written submissions, PPPL said there was no issue of credit and the Court can accept Ms Eastgate’s evidence. I agree that there is no issue as to credit and I accept Ms Eastgate’s evidence.

239    Ms Eastgate states that the AER uses a software package called “NEO” to manage and display data relating to the NEM. The AER has an SQL server that links directly to AEMO’s systems to retrieve and store NEM data. When an AER staff member runs a report in NEO, the NEO replicates the data held in the AER’s SQL server.

240    On 29 July 2019, Ms Eastgate extracted from NEO 30 minute generation and dispatch target data for the Pelican Point PS with the DUID, PPCCGT, for 8 and 9 February 2017 trading days. She states that the report she ran was called “Generation vs Target” which is accessed in the NEO. The report provides for each 30 minute trading interval, two data outputs, namely, the generation unit of the Pelican Point PS and the dispatch data issued to the Pelican Point PS. Ms Eastgate ran the report twice, once for each of 8 and 9 February 2017 trading days. Ms Eastgate described how she prepared that information so that it was provided to the Court. On 26 February 2020, Ms Eastgate extracted from NEO, 5-minute generation and dispatch target data for the Pelican Point PS with DUID PPCCGT for 1 January 2012 to 7 February 2017 trading days. Ms Eastgate ran a report called “Generation vs Target_5min”. This report provided for each 5-minute dispatch interval, two data outputs, being the generation output of the Pelican Point PS and the dispatch target issued to the Pelican Point PS. Ms Eastgate described how she went about preparing that data so that it could be provided to the Court in the form of a USB.

241    Ms Eastgate also created other documents from the records of AEMO. This included PPPL’s output and gas usage and, in this respect, she created the following: (1) a new worksheet entitled “Est. gas usage calc” (Estimated gas usage calculation); (2) a chart of the daily energy output and estimated gas usage of the Pelican Point PS for each day from 1 January 2017 to 9 February 2017; (3) charts of the generation of the Pelican Point PS for each week from 1 January 2017 to 9 February 2017; and (4) a chart of the generation of the Pelican Point PS for 30 January 2017 to 6 February 2017 trading days. Ms Eastgate also created an Excel file which is in USB form and which contains data relating to the PPPL’s ST PASA submissions and PPPL’s MT PASA submissions.

242    It seems that Ms Eastgate based her calculations on NEO which is AER data, not AEMO data. Further, one of the points which the AER seeks to make based on Ms Eastgate’s evidence is that the Pelican Point PS was regularly dispatched to generate at an output rate of 320 MW which is the combined output of GT11 and GT12 run together.

Mr Sanders

243    As I have said, Mr Sanders is employed by AEMO as a Principal Analyst, Electricity Market Monitoring. In its closing written submissions, PPPL said that there was no issue of credit and the Court can accept the evidence of Mr Sanders. I agree that there is no issue as to credit and I accept Mr Sanders’ evidence.

244    Mr Sanders’ expertise centres on bidding, dispatch and pricing in the NEM. This means that he is required to have an understanding of all components of the dispatch model, the operation of the optimisation techniques used in dispatch and the way in which various elements of a bid might be used in the pricing and dispatch process. He has been employed in his present role, or equivalent roles, at AEMO since August 2011. AEMO succeeded NEMMCO as the operator of the NEM and before commencing his employment with AEMO, Mr Sanders spent six years working for NEMNCO as a Specialist, Market Design, analysing and advising on the ways in which the NEM might be improved. Mr Sanders holds a Bachelor of Science with First Class Honours from the University of Otago in Dunedin, New Zealand and a Post Graduate Diploma in Applied Nuclear Physics from Sydney University.

245    Mr Sanders was not on the AER’s original witness list. The substance of Mr Sanders’ evidence is the AER’s response to certain aspects of Mr O’Farrell’s evidence in his second report which I gave PPPL leave to adduce.

246    Before he addressed those matters, Mr Sanders addressed a number of general matters. He began by addressing the ST PASA process referred to in cl 3.7.3 of the NER. He produced the Spot Market Operations Timetable published by AEMO in October 2016 pursuant to cl 3.4.3 of the NER. He summarised one of a Scheduled Generator’s obligations as specified in the timetable as a requirement to submit and update ST PASA inputs for a trading day to AEMO during the period between two and seven days in advance of the trading day in question.

247    Mr Sanders described how AEMO uses the ST PASA inputs supplied by Scheduled Generators. He said in broad terms, AEMO uses the information along with other information regarding forecast demand and forecast network constraints to forecast the quantity of capacity reserves that will be available in each region in each trading interval across the ST PASA forecast period.

248    Mr Sanders also produced the Reliability Standard Implementation Guidelines published by AEMO in October 2016. That document summarises how AEMO uses the ST PASA framework to forecast capacity reserves over the ST PASA timeframe.

249    Aside from the Scheduled Generator’s obligations with respect to ST PASA, the Scheduled Generator has obligations under cl 3.8.4 to notify AEMO of available capacity and daily energy availability two days in advance of each trading day. AEMO uses this information and information about dispatch offers and bids, forecast demand and forecast spot pricing for each trading interval in preparing and publishing its pre-dispatch schedules. AEMO’s obligation to prepare, publish and update a pre-dispatch schedule for each trading day is governed by cl 3.8.20 of the NER. Mr Sanders gives his opinion as to a key purpose of the pre-dispatch schedule. It is to provide Market Participants (including generators) with sufficient information about forecast supply, demand and prices to enable them to make informed decisions about how to operate their generating units during each trading day. The information published and regularly updated in the pre-dispatch schedule enables generators to submit rebids in order to increase or decrease the amount of generating capacity that they wish to offer for dispatch in each price band during each trading interval throughout the trading day. Mr Sanders said that AEMO uses the daily energy availability information submitted by generators under cl 3.8.4 in preparing the pre-dispatch schedule. Mr Sanders provided a copy of the pre-dispatch process description prepared by AEMO with an effective date from 1 July 2010.

250    Mr Sanders addressed the issue of dispatch. He said that, in broad terms, in co-ordinating the dispatch of generating units every 5-minutes in real-time, AEMO’s dispatch algorithm seeks to achieve a lowest-price solution that balances aggregate supply and aggregate demand, while taking account of other physical or electrical constraints, including constraints on transmission lines, the rate at which individual generating units are able to ramp up or ramp down their output, and other constraints that may be necessary to maintain power system security from time to time. AEMO’s real-time dispatch process is principally governed by cl 3.8.1 of the NER. Mr Sanders explained that AEMO’s bidding and dispatch framework enables the generator of an energy-constrained generating unit to make its limited generating capacity available during times of the day when spot prices are forecast to be highest, including by rebidding at any time up to the start of a 5-minute dispatch interval.

251    Mr Sanders addressed the situation of a generator of an energy-constrained generating unit notifying a daily energy availability to AEMO under cl 3.8.4 (or if it has submitted a “projected daily energy availability” in ST PASA), and expressed the following conclusions: (1) the generator is not constrained by that estimate in submitting dispatch offers for any trading interval in that trading day; and (2) AEMO’s dispatch algorithm does not take account of whether a generating unit has exceeded its “Daily Energy Availability” (or its “projected daily energy availability”) for the trading day in computing and co-ordinating real-time dispatch for any 5-minute dispatch interval during the trading day. Mr Sanders gave the following example: a generator has notified AEMO that its generating unit has a “Daily Energy Availability” of 2,000 MWh for a trading day, and the generating unit has in fact been dispatched to supply 2,000 MWh before the end of a trading day. In those circumstances, the generator is not prohibited from continuing to offer generating capacity during remaining trading intervals and nor will AEMO’s dispatch algorithm prevent that generating unit from continuing to be dispatched to supply power during the remaining trading intervals of that trading day. Mr Sanders referred to the Pre-Dispatch Process Description and noted the following passage:

6.4.3    Unit Daily Energy constraint

Unit Daily Energy Limits are used by market participants in Pre-dispatch to limit the total amount of energy (energy generated for a generating unit or energy consumed by a load) that can be scheduled on their energy­constrained units from the start of the trading day onwards. Note that energy-constrained units are not subject to this limit in On-line Dispatch.

252    I turn now to Mr Sanders’ review of two aspects of Mr O’Farrell’s second report.

253    In the case of the basic 320 MW scenario advanced by the AER where PPPL generated 320 MW for a four hour period, a question arises as to whether PPPL would be obliged to identify a particular four hour period. Mr O’Farrell expressed the view in his second report that if, by contrast, PPPL submitted 320 MW for each trading interval for ST PASA, then that entailed committing to significantly greater output than generating at 320 MW for only four hours and, therefore, obtaining significantly more non-firm gas, interruptible transport and a user of surplus gas during periods in which that level of output was not being generated over a 24 hour period. Mr O’Farrell’s opinion was that if it was necessary for PPPL to submit ST PASA of 320 MW for all trading intervals in a day, in his view a prudent and diligent operator would have needed to be in a gas supply and transport position that was sufficient to operate at that output across each and every one of those intervals for the day, not merely for part of the day. In Mr O’Farrell’s opinion, the submission of an energy constraint for the trading day equal to a maximum output of 320 MW multiplied by four hours would not solve the problem. Mr Sanders addressed Mr O’Farrell’s two reasons for expressing that opinion.

254    Mr O’Farrell said the following:

Even if PPPL had submitted a PASA of 320 MW or more for every trading interval in a trading day, and simultaneously submitted an energy constraint for that trading day equal to a maximum output of 320 MW multiplied by 4 hours … I do not consider that it could have submitted an energy constraint to accurately reflect its generating capacity for that trading day in any event. … The use of an energy constraint would have had the effect of putting a limit on the amount of power that the power station could generate for the day, with that limit set by reference to the maximum output (320 MW) multiplied by the number of hours for which that output could be achieved (4 hours). Once that total amount of energy (1,280 MW) had been generated, the AEMO dispatch system would automatically prevent the Pelican Point Power Station from dispatching power to the grid, notwithstanding that it might be physically capable of generating for a further period of time at 240 MW (or some other, lower, amount).

255    Mr Sanders interpreted the example put forward by Mr O’Farrell as involving a hypothetical scenario in which PPPL had submitted a “projected daily energy availability” amount of 1,280 MWh in its ST PASA submission for a particular trading day. The conclusion that Mr O’Farrell has expressed is wrong for two reasons. First, the projected daily energy availability amount (if any) that a Scheduled Generator submits in its ST PASA submissions under cl 3.7.3(e)(4) is used by AEMO for the purpose of forecasting capacity reserves over the ST PASA forecast period. It is not used by AEMO either in calculating pre-dispatch schedules for, or in dispatching generation from the Pelican Point PS in real-time during that trading day. Secondly, even if PPPL had notified AEMO of a Daily Energy Availability of 1,280 MWh under cl 3.8.4 rather than in its ST PASA submissions, that quantity would only have been used by AEMO as a modelling constraint in preparing its pre-dispatch schedules for that trading day. If the Pelican Point PS had already dispatched to supply 1,280 MWh during that trading day, the AEMO dispatch system would not automatically prevent the Pelican Point PS from being dispatched to continue to supply power during the remaining trading intervals in that trading day if PPPL had submitted dispatch offers for the Pelican Point PS to supply power during those remaining trading intervals.

256    The second matter referred to by Mr O’Farrell was as follows:

In my opinion, if PPPL could have generated at 320 MW/hr for 4 hours and 240 MW/hr for the rest of the day (20 hours), it could not have made a PASA submission in which it nominated PASA availability of 320 MW in every trading interval with an energy constraint reflecting the total energy that it would generate for the day if it generated at 320 MW/hr for 4 hours and 240 MW/hr for 20 hours. I am aware from my roles with AEMO and Origin that, in about 2017, energy constraints were entered into the AEMO system as a total daily output cap (in MW). The total output for this generating scenario is calculated as follows (320 MW x 4 hrs) + (240 MW x 20 hours) = 6080 MW. If 320 MW was nominated for every trading interval in PPPL’s PASA submission with a daily energy constraint of 6080 MW, the AEMO dispatch engine would interpret that as meaning that PPPL could generate at 320 MW/hr for 19 hours (6080 MW/320 MW = 19), which was not possible with the available gas supply and transport at the time, particularly having regard to the M12HQ constraint under the SEAGas PCA contract. That is, the AEMO dispatch system would have assumed that the power station would have generated at its nominated PASA availability (320 MW) until it reached its daily energy constraint (6080 MW). After PPPL generated 6080 MW, the AEMO system would have prevented it feeding power into the grid.

257    Mr Sanders said that there are a number of errors in this analysis. First, the “PASA availability” that a Scheduled Generator submits in ST PASA is not taken into account at all either by AEMO’s pre-dispatch or dispatch algorithms. AEMO uses that information to forecast capacity reserves in each region over the ST PASA forecast period. Secondly, AEMO’s dispatch algorithm also does not take account of either the “projected daily energy availability” submitted in ST PASA, or the Daily Energy Availability submitted under cl 3.8.4, in co-ordinating dispatch outcomes or in giving dispatch instructions to the Pelican Point PS.

258    Mr Sanders expressed the view that it followed that each of Mr O’Farrell’s assertions regarding the AEMO dispatch engine were incorrect, particularly insofar as it is understood as referring to real-time dispatch.

259    Mr Sanders was briefly cross-examined. He did give evidence about one matter which may go to the number of contraventions if liability is established. He gave evidence that AEMO’s system was such that where there was a change to PASA, for example, by reason of temperature, it was necessary to fill in all the fields when submitting an updated ST PASA. I note that matter, but otherwise there is nothing to throw any doubt on the evidence-in-chief of Mr Sanders which I accept. A related point raised by PPPL was that the AER had submitted that the 320 MW maximum generating capacity should have been indicated over the whole 24 hour period when, in fact, under the 8 February counterfactual it is the maximum generating capacity for only four hours. The answer to PPPL’s point is that the issue is not what will be made available, but what can be made available on 24 hours’ notice. In the alternative, the issue can be dealt with under the item, projected daily energy availability for energy constrained scheduled generating units.

Mr Snow

260    Mr Snow prepared two reports which were tendered in evidence and he attended a conference of experts with Mr O’Farrell. The conference led to the preparation of a joint experts’ report which set out at least some of the key differences between the experts. The experts addressed a number of agreed questions. In addition, there were some questions proposed by one party, but not agreed to by the other.

261    The background to Mr Snow’s first report is that he was sent two letters of instructions by the AER, one on 20 May 2020 and the other on 12 November 2020, and he addresses the questions raised in those letters in his report.

262    In the first letter of instructions, Mr Snow was asked to identify the actual quantity of gas that PPPL obtained for use at the Pelican Point PS on 8 February 2017 and the source for that gas and the means by which that gas was transported to the Pelican Point PS. Mr Snow states that PPPL took delivery and used 57.495TJ of gas on 8 February 2017 of which 40TJ was firm gas (35TJ approximately from BHP Billiton Petroleum (Victoria) Pty Ltd (BHP) and 5TJ from Origin Energy Retail Limited (Origin Energy)) and the balance was non-firm (7TJ from Santos Direct Pty Ltd (Santos) under a separate swap agreement from the Otway Gas Plant) and linepack (9.897TJ from the Moomba to Adelaide pipeline (MAPS) PPPL linepack account). A swap agreement between two parties involves two transactions for the same amount of gas where each party is both a buyer and seller and each party gains the advantage of relocating the source or delivery point of the gas. Linepack is a well understood term in the gas industry in relation to being able to effectively store gas within the transmission gas pipelines. Gas can be compressed in a gas transmission pipeline to very high pressures and this increases the volume of gas on the pipeline. An imbalance arises if more gas is withdrawn than injected and this impacts gas flow in the pipeline and withdrawals. Pipelines which use close to their maximum throughput levels have very little linepack, whereas those that are under-utilised often have significant linepack available. Mr Snow described linepack as a term describing a level of workable gas storage. It has a commercial value and is sold as a gas storage product. I accept that evidence.

263    A total of 38.876TJ was used at the Pelican Point PS and the balance was used at the Mintaro Power Station (8.329TJ), the Dry Creek Power Station (9.871TJ) and in SUG (PPPL) (0.419TJ). Mr Snow was also asked to address, assuming 24 hours’ notice, what quantity of additional gas PPPL could have obtained on 8 February 2017 based on existing firm gas supply and transportation rights. Mr Snow said that PPPL had no additional gas available to it in terms of quantities of other firm gas supply.

264    In the second letter of instructions, Mr Snow was asked what non-firm source of gas and gas transport were available to PPPL for use at the Pelican Point PS on 8 February 2017. He was then asked to express an opinion on the question of, assuming 24 hours’ notice, how much additional gas could PPPL have reasonably expected that it would practically be able to obtain on 8 February 2017 for use at the Pelican Point PS, in addition to the firm sources he identified in answer to one of the questions in the first letter of instructions (question 3). The answer Mr Snow gives in numerical terms is 55.5TJ from four sources which he identifies. He then asks himself what gas transport would have been available for “additional non-firm gas reasonably expected to be available”. Mr Snow concludes that the Port Campbell to Adelaide (PCA) pipeline would have been required to transport 22.902TJ more gas than was actually transported on PPPL’s account on 8 February 2017 and that PPPL could have reasonably expected that this capacity was available.

265    The next question Mr Snow was asked to address was whether PPPL should have reasonably expected throughout the entire period from 11 November 2016 to 8 February 2017 that it would practically be able to obtain, on 24 hours’ notice, for 8 February 2017 the gas supply and gas transportation he had identified in his answers to previous questions. He expressed an affirmative answer to that question saying that “all relevant agreements for supply and transport were in place for that period”.

266    The final question Mr Snow was asked to address sought to link the previous opinions Mr Snow had expressed to the running of GT12 concurrently with GT11. The question was whether, having regard to his previous opinion about PPPL’s reasonable expectation of gas supply and gas transport for 8 February 2017 for the period from 11 November 2016 to 8 February 2017, PPPL should have reasonably expected that it would practically be able to obtain sufficient gas supply and gas transport on 24 hours’ notice in order to operate GT12 concurrently with GT11 on 8 February 2017 for at least GT12’s minimum run-time. Mr Snow was asked to assume for the purposes of answering this question a minimum run-time of four hours, a net (sent-out) Heat Rate of 8.31GJ/MWh and that the combined output of GT11 and GT12 would be 320 MW. Mr Snow’s answer to this question was clearly yes. Mr Snow also identified another operating scenario and answered yes to the question as applied to that scenario. That scenario involved GT11 operating as it in fact did on 8 February 2017 and GT12 operating on 8 February 2017 as it in fact did on 9 February 2017 (i.e., from 4.30 pm for approximately four hours). Mr Snow said that that scenario would have required additional gas of 3.23TJ which PPPL could have taken from the amount it in fact supplied to the Mintaro Power Station leaving that power station to take more linepack from the Moomba to Adelaide Pipeline System (MAPS). Furthermore, gas transport would have been available.

267    Mr Snow’s second report followed the provision of Mr Weatherly’s second affidavit and Mr O’Farrell’s second report and was largely responsive to the statements and opinions in those documents.

268    Mr Snow was first asked whether Mr Weatherly’s evidence in his second affidavit as to the following matters: (1) quantities of gas in fact supplied by PPPL to Synergen Power and Simply Energy on 8 February 2017; and (2) how PPPL obtained sufficient gas transport to operate a second gas turbine on 9 February 2017, caused him to alter any of the views he had previously expressed in his reports or evidence. Mr Snow said that Mr Weatherly’s evidence did not lead him to alter his conclusions, although it “marginally” changed some of his analysis. The matters Mr Snow addressed were as follows: (1) an additional source of non-firm gas supply through Santos/Simply Energy Gas Supply Agreement at Minerva East; (2) an assumption that he had previously made about a source of gas from Minerva was incorrect; (3) he revised his figure for PPPL’s reasonable expectation of non-firm gas to 45.3TJ; (4) he noted that PPPL had not in fact interrupted Santos Interruptible Firm Haulage Capacity on the PCA pipeline on 8 February 2017; and (5) he noted that PPPL was using the over-nomination of scheduled gas flows on the PCA pipeline to manage Maximum 12 Hourly Quantity constraints, which also meant that there was no correlation between PPPL’s actual flows and scheduled capacity on the PCA pipeline, nor any basis for the requirement asserted by Mr O’Farrell to have smoothed hourly flow rates leading to high levels of excess gas if GT12 was run for four hours.

269    Mr Snow was next asked to address whether Mr O’Farrell’s second report caused him to change any views he had previously expressed in his reports or evidence. Mr O’Farrell was asked to address in his second report whether any MT or ST PASA submissions for 8 February 2017 which were less than 320 MW were not a “reasonable estimate” in the sense of an estimate which was rational and based on proper grounds and not arbitrary or capricious and in the sense of an estimate which involves gas “Pelican Point reasonably expects it would practically be able to procure on 24 hours’ notice, if required to do so – including gas from non-firm gas supply and gas transportation rights”. Mr Snow said that he was not an expert on the MT or ST PASA matters and has only considered Mr O’Farrell’s second report in terms of the gas supply and haulage comments. Mr Snow said that nothing in Mr O’Farrell’s second report caused him to change his opinions.

270    This is a summary of Mr Snow’s reports. As I have said, I will need to come back to certain details of his evidence (and the opinions he expresses in the joint experts’ report) when I consider the specific topics of gas supply and gas transport. I do note at this point that most of Mr Snow’s figures were not challenged by Mr O’Farrell. PPPL’s challenge to Mr Snow’s evidence was to his approach to the questions and the adequacy of the material he relied on for his opinions.

271    Some key matters raised in the cross-examination of Mr Snow should be identified now.

272    PPPL submitted that Mr Snow’s opinions were based on historical evidence and hindsight reasoning. The question was what an entity could reasonably expect as to future matters, that is, circumstances on a future date and not what could have been reasonably expected having regard to information relating to events after it was necessary for the forecast or estimate to be formed.

273    In support of this submission, PPPL relied on a number of answers Mr Snow gave in cross-examination.

274    First, Mr Snow agreed in cross-examination that he did not put himself in the shoes of the hypothetical, competent, reasonable, diligent generator in November 2016 looking forward to 8 February 2017. It is true that Mr Snow did agree with this proposition, although it is not clear whether he agreed he had not done what was suggested because he had not done all the elements in the proposition or only one of them.

275    Secondly, in the context of questions about the availability of interruptible transport, Mr Snow was asked on which day it became apparent to him from his review of the “source” business records that there would be available on 8 February 2017 some interruptible transport that PPPL might have been able to avail itself of. He said in response to that question that he did not think that he undertook that form of analysis. He had looked at what had been available and he had carried out an “ex post” review. He said that he did not “look at it as a forward look”.

276    Relatedly, Mr Snow was cross-examined about whether one of the Foundation Shippers with a right to interrupt the interruptible service had exercised that right. He said that he did not analyse that and his evidence continued as follows:

… I only took the data ex post to see what was available - - -

Yes? --- - - - and to look at the build-up by – the forecast, really, of the PCA itself - - -

Thank you? --- - - - as to what was available ….. that’s all I did.

Thank you. So you didn’t look at it from, say, November 2016, did you?---We went back to January 2017.

Yes?---There was various reasons for that.

Yes?---I didn’t go back to November 2016 - - -

Thank you?--- - - -to have a look at ….. PCA.

277    Thirdly, in the context of his opinion as to a reasonable expectation on the part of PPPL of an additional 45.3TJ of non-firm gas supply on 8 February 2017, Mr Snow expressed the view that he had regard to what in fact occurred on 8 February 2017, adopting the “look back” process he had described. He then said that insofar as his work was undertaken as at 2 February 2017, he did not form a view in the second report as to whether or not there would be 45.3TJ of non-firm gas available to PPPL.

278    Fourthly, in the joint experts’ report and in the context of a question as to the significance of events on 9 February 2017 to his opinion as to the reasonable expectation of gas transport on 24 hours’ notice on 8 February 2017, Mr Snow said that the events on 9 February 2017 were fundamental to his opinion and “that they must have had a reasonable expectation that they could do this”.

279    PPPL also submitted that Mr Snow was given limited instructions and that this is relevant to the weight that can be placed on his opinions. Mr Snow said that he did not receive any instructions from the AER about timelines for the provision of information to AEMO under the NER. He was given no instructions as to the time of the provision of MT PASA or ST PASA and he did not recall the 320 MW basic scenario being referred to as the “benchmark” scenario. He was given no instructions about the weather or the circumstance that GT12 had been run on 7 February 2017 such that it was possible to run it for four, not eight hours on 8 February 2017. He had no instructions as to which other shippers on the PCA pipeline were not using the pipeline and he was given no instructions about the Torrens Island A generator failing for mechanical reasons. Nor was he given any instructions about the operation of Quarantine 4 on 8 February 2017. He was given no instructions, nor did he make any assumptions, about the capacity that Origin Energy and AGL were proposing to use on the PCA pipeline and at what times.

280    In response to this challenge to Mr Snow’s approach, the AER referred to the question 3 in the second letter of instructions and Mr Snow’s response as follows:

3.    Should PPPL have reasonably expected throughout the entire period from 11 November 2016 to 8 February 2017, that it would practically be able to obtain on 24 hours’ notice for 8 February 2017:

a.    the gas supply and transportation referred to in your answer to question 3 from the First Letter of instruction; and

b.    the gas supply and transportation referred to in your answer to 2 above?

    Answer:

I consider that the answer to both of these sub-questions is yes as all relevant agreements for supply and transport were in place for that period.

281    The AER submitted that it was not put to Mr Snow that he had not addressed the questions he was asked and it was not put to him that because his analysis of non-firm gas supplies related to dates after 11 November 2016, the analysis could not be probative as to what PPPL’s expectations should have been throughout the entire period from 11 November 2016 to 8 February 2017 when all of the PASA submissions had been made. That is correct and those matters were not put to him.

282    The AER acknowledged that Mr Snow gave the following evidence:

I think in your report you say that the contractual arrangements that you’ve observed were in place as at 11 November 2016?---Except for – I think the BHP contract rolled over in that period after that, but there was no major change I can see to that contract, yes.

Of course, you accept, don’t you, that under those contracts what may or may not have been the position on a particular day turned on what steps had been taken to exercise rights under them, by that I mean a concept known as nominations?---Correct, yes.

And for the purposes of expressing your opinions, I don’t think you did a detailed analysis of just what nominations, if any, had been made on 11 November 2016?---November 2016?

Yes?---No, we didn’t look at 11 November 2016 specifically, no.

No. And putting yourself in the – did you put yourself in the shoes of the hypothetical competent, reasonable, diligent generator in November 2016 looking forward to 8 February 2017?---No.

283    However, the AER submitted that it was not put to Mr Snow that he had not drawn any conclusions as to what PPPL’s reasonable expectations were from 11 November 2016 on a forward looking basis. The AER submitted that if such a case was to be made, then it needed to be put to Mr Snow. In particular, it was not put to Mr Snow that insofar as his analysis was based on PPPL’s historical ability to obtain gas, that was unlikely to be relevant to its future ability to obtain gas. It was not put to Mr Snow that PPPL’s historical ability to obtain gas was unusual or dependent on circumstances that could not be predicted on a forward looking basis. All of these matters are correct.

284    I do not consider that Mr Snow’s approach means that his evidence is of no or little weight. It is one approach. It is a matter of judgment as to what level and when historical information can form the basis of an opinion as to what reasonable estimate should have been made and, of course, one must be alive to any special circumstances which have influenced past events or which may influence future events. As to the “lack of instructions”, where that is relevant I will deal with it.

285    As I have said, much of Mr Snow’s data was not challenged by PPPL. Mr O’Farrell acknowledged in cross-examination that Mr Snow was excellent “when it comes to historical fact”. Mr Snow’s report indicates that PPPL had the ability to obtain non-firm gas supply and gas transport on a regular basis throughout January and February 2017. As counsel for the AER pointed out, Mr Snow’s data on non-firm gas supply which PPPL obtained from Santos and BHP from 15 January 2017 (Figures 1 and 2 of his first report) was not challenged and PPPL’s MAPS linepack balance trends and PCA linepack use by PPPL (Figures 3 and 4) were not challenged. The data as to how frequently and by how much PPPL was able to output more electricity than it did on 8 February 2017 (Table 6) was not challenged and the spare capacity on the PCA pipeline (Figure 5 of his first report and Figure 5 of his second report) was not challenged.

286    The AER submitted that, in the circumstances, the Court should infer that in advance of 8 February 2017 and “certainly in the six day trading window before 8 February, when the short term PASA submissions had to be made”, PPPL would have known that it could have obtained substantial quantities of non-firm gas and supply on 8 February 2017. In his second report in section 2.1.4, Mr Snow revised his figures having regard to IA-011, but his revision was conservative in view of the fact that PPPL was able to take 7TJ on 9 February 2017.

287    Counsel for PPPL agreed that there had been no challenge to the data assembled by Mr Snow. He submitted, referring to Figure 1 and Figure 2 in Mr Snow’s first report dealing with the Santos swaps and BHP deliveries, that the data did not make good Mr Snow’s propositions. Mr Snow agreed that he did not consider things from 11 November 2016. Save and except for MAPS, Mr Snow addressed the matter from 15 January 2017. That can be seen from his Figure 1. PPPL prepared and handed up a schedule summarising non-firm supply by BHP and Santos. The short point that PPPL made was that one cannot just add up the 15TJ and the 7TJ or thereabouts as Mr Snow does from the Santos swaps and the BHP excess and come up with the 23TJ that he opines because the charts do not make good that proposition. With respect to MAPS linepack (Figure 3), PPPL submitted that the data did not support the assertion that there was consistently 40 to 48TJ of linepack gas on the MAPS. There was significantly less than 47TJ and, in fact, less than 30TJ on 3 February 2017.

288    PPPL also referred to Mr Snow’s evidence as set out in the joint experts’ report to the effect that determining how much non-firm gas supply and transport PPPL had available to it to supply the Pelican Point PS on 8 February 2017 on 24 hours’ notice was “too speculative to answer categorically”. In addition, Mr Snow noted that PPPL went out and looked for gas and they found it. This is non-firm gas supply. He said that it was reasonable to not make firm commitments on additional generation until supply of non-firm gas that may be required is confirmed. The question is a different one when non-firm is turned into firm. Mr O’Farrell agreed. PPPL made much of the fact that this was the AER’s own expert and the “fundamental problem” for the AER’s case is that those events occurred well inside the 24 hour window required by the PASA regime.

289    Mr Snow drew a number of conclusions from the evidence in Mr Weatherly’s second affidavit. He said that it confirmed to him what he described as the tight knit communication arrangements between participants on the PCA pipeline for gas supply in terms of sourcing gas and haulage arrangements through the direct relationships between traders. He said he was not surprised by this as he would have expected to see informal access to discuss supply issues between professional gas originators and traders before moving to confirm trades and arrangements more formally. The best example was the conversation between Mr Weatherly and his counterpart at Santos referred to below (at [435]). Mr Snow expressed the opinion that the level of access he identified was certainly not available outside the operational group of gas originators and traders using the PCA pipeline and reflected the nature of the working relationships of those participants in terms of managing their gas needs as co-operatively as possible given contractual constraints.

290    The findings which the AER seeks are as follows. Having regard to Mr Snow’s evidence, PPPL could reasonably expect to have 40TJ of firm gas and an additional 45.3TJ of non-firm gas. If one subtracts the 25TJ that PPPL could extract from the MAPS linepack, then the result is a reasonable expectation of 20TJ of non-firm gas comprised of gas obtained from BHP Santos swaps and sales of gas by Santos to Simply Energy which gas is then on-sold to PPPL. The AER submitted that the effect of this evidence is that it is common ground that PPPL’s business operations depended on being able to obtain access to firm and non-firm gas sources. There may be disputes “at the margins”, but the evidence is clear that it is or was, at least, likely that some non-firm gas could be obtained from all of those sources on any given day.

PPPL’s witnesses

291    Messrs Foulds, Baksi and Weatherly are or were employed by ENGIE at the relevant time and Mr O’Farrell was PPPL’s expert. The evidence of Messrs Foulds, Baksi and Weatherly related to the major aspects of PPPL’s case, namely, the availability of gas supply, the availability of gas transport, the condition of GT12 and what reasonable expectations were held as to the availability of gas supply and of gas transport and, in the case of Messrs Foulds and Weatherly, they also sought to explain certain matters relied on by the AER.

Mr Foulds

292    Mr Foulds has worked in the energy sector in Australia and the United Kingdom for more than 25 years. He commenced working in the energy sector in 1994 after graduating from the University of Manchester with a Bachelor of Arts with Honours.

293    In 2002, Mr Foulds began working for International Power (formerly trading as GDF Suez and now trading as ENGIE) in the United Kingdom as an Energy Trader. He described his responsibilities in this role as follows: (1) trading in the short term over-the-counter (OTC) and power exchange markets to deliver optimum contract positions across the power and gas markets; (2) self-dispatch of the group’s assets, comprising 1,500 MW of coal and CCGTs; and (3) nomination of upstream gas contracts, OTC and gas transport arrangements. Prior to this role, Mr Foulds worked in different organisations in various positions, including in the positions of Tenders Manager, Commercial Manager and Electricity Trader.

294    In 2004, Mr Foulds became the Manager of Trading Operations at International Power in Melbourne after he had emigrated to Australia. From this point in time until August 2018, save and except for 2011 and 2012, Mr Foulds was involved in the commercial operation and trading activities of PPPL. He held the position of Manager, Trading Operations until 2011 and he described his responsibilities as follows: (1) managing spot market and short-term activities of International Power’s electricity and gas portfolio consisting of 3,700 MW and 40PJ/year; (2) commercial optimisation across both electricity and gas spot markets in wholesale and retail environments; and (3) developing operating plans that aligned with Portfolio Management and Risk objectives requiring him to take into account the contract portfolio at the time, variable market conditions, participant behaviour, cross commodity synergies and the potential longer-term impact of short-term behaviour.

295    From 2011 to 2012, Mr Foulds was employed as the Spot Energy Market Manager at Alinta Energy in Sydney. He described his key responsibilities in this role as including liaison with both power stations in the Alinta portfolio and market operator in line with the NER to ensure the co-ordinated dispatch of the businesses’ power stations. His responsibilities included managing the associated gas nominations and co-ordination with upstream gas counterparties.

296    From 2012 until January 2016, Mr Foulds was the Origination Manager and Trading Manager at ENGIE in Melbourne and he was responsible for managing and securing ENGIE’s longer term portfolio position, to leverage and add value across all ENGIE’s commodities, including power, gas and renewables with a view to delivering optimum long-term value in both structured and derivative transactions. In this particular role, Mr Foulds said that he had a substantial involvement in the decision to mothball half of the generation capacity of the Pelican Point PS, including the consideration of how that decision would impact on ENGIE’s portfolio.

297    From January 2016 until August 2018, Mr Foulds was Head of Trading and Portfolio Management at ENGIE, Melbourne. He reported to the Chief Executive Officer and he was the head of ENGIE’s wholesale trading function and had responsibility for overseeing the activities of the derivative and structured transactions, market operations, analytics and retail pricing functions. He had responsibility for the commercial and trading activities of the companies’ wholesale power and gas portfolio, including the Pelican Point PS. He had direct involvement in the events that unfolded in the South Australian region in the summer of 2016/2017. Although he was based in Melbourne, he visited the South Australian assets regularly.

298    Mr Foulds gave a very good description of the Pelican Point PS and how it operates. It is located at Outer Harbour which is approximately 20 kilometres north of the Adelaide CBD. PPPL operates, and only operates, the Pelican Point PS. International Power (Australia) Pty Ltd owns PPPL. It formerly traded as GDF Suez and now trades as ENGIE. The Pelican Point PS requires about 20 and 40 employees to operate, depending on seasonal operational requirements. The functions those employees perform are trading, control room and engineering duties at Pelican Point PS, including on a 24 hour basis.

299    The Pelican Point PS is a combined cycle gas turbine power station comprising two Alstom GT13E2 gas turbines and a steam turbine. The gas turbines generate electricity by burning gas and the steam waste from that process provides the power for the steam turbine. The Pelican Point PS is a “mid-merit” power station and this means that it is operated seasonally to meet higher energy demands, that is, demands that cannot be satisfied by base load (permanent) generation and arise, for example, over the summer months in South Australia. A mid-merit unit is a “load-following” unit that adjusts output as demand fluctuates during a typical day. Mr Foulds said that the Pelican Point PS’s gas turbines are designed to be run in a flexible manner for medium, that is, from about eight hours to several days, to long, that is, for up to several weeks, periods of time at varying levels of output. In operating the gas turbines in this manner, it is necessary to turn them off and restart them at periodic intervals and this pattern of operation results in significant annual operation and maintenance costs. The gas turbines are fuelled by gas that is predominantly secured under long-term “take or pay” gas supply and gas transport contracts of at least multiple years in duration. The long-term contracts are entered into to secure gas supply and transport at rates that make it possible for the Pelican Point PS to operate commercially and cover its operation and maintenance costs. The long-term contracts represent significant fixed costs for the operation of the Pelican Point PS.

300    Mr Foulds described the difference between a mid-merit power station on the one hand, and “base load” power stations and “peaking” power stations on the other. The Northern Power Station was closed in 2016. Before that, it was a base load power station. Typically, such power stations have low marginal costs and are run on a permanent basis. Generally, the fuel for the power station is coal and a large number of staff are required to operate the power station. Peaking power stations generally feature open cycle gas turbines which are able to be synchronised quickly in order to generate electricity. Mr Foulds said that start-up times in the case of such turbines of 10 minutes are common. Peaking power stations are run over limited, short term periods during any given year in order to meet residual demand, often when the base load and mid-merit power stations are already running at full available capacity. Generally, the fuel used in peaking power stations is gas. Synergen Power is a subsidiary of ENGIE. It operates peaking power stations at Dry Creek, Mintaro and Snuggery Point and a diesel fuelled peaking power station at Port Lincoln.

301    Mr Foulds then addressed the market conditions in or around 2012 and 2013 and the decision by PPPL to mothball generating capacity at the Pelican Point PS. I have referred above to Mr Foulds’ position and responsibilities in 2012 and 2013. Electricity prices in South Australia in the 12 months or so prior to 2013 were volatile in the sense that they moved “from highly negative to highly positive and featuring low spot prices”. There was a high degree of uncertainty about future electricity prices and Mr Foulds described the factors contributing to this uncertainty. I need not set out these factors. In the course of 2013, GDF Suez undertook a review of the commercial position of PPPL in the South Australian electricity region and of its other major South Australian generation asset, being Synergen Power. The review was given the name “Project Phoenix”. Mr Foulds was one of the two project managers and he was heavily involved in the project. He prepared and delivered presentations about the project to various project groups. Mr Foulds and others involved in the project formed the view that it was not commercial to operate both of the gas turbines at the Pelican Points PS. Heavy financial losses were forecast and, in those circumstances, Mr Foulds recommended that the Pelican Point PS operate with only one gas turbine and “mothball” half of its generation capacity.

302    Mr Foulds described aspects of the decision-making process in Project Phoenix. The ultimate decision was that the Pelican Point PS would mothball 240 MW of its 480 MW of generation capacity and continue to operate a single gas turbine with the steam turbine because this was the most economically viable option. The review included forecasts which involved the on-sale of gas transportation rights on the PCA pipeline and the deferral of certain material operational and maintenance costs.

303    Gas transportation rights and gas supply rights represented high fixed costs for PPPL. They were fixed costs because the agreements were made on a “take or pay” basis, meaning that PPPL was required to pay for the rights regardless of whether, and the extent to which, it exercised those rights. The market for the on-sale of gas transportation rights is smaller than the market for the on-sale of gas supply rights because gas transportation rights are specific to a particular pipeline.

304    With respect to operational and maintenance costs, Mr Foulds said that as at November 2013, GT11 was in good condition and was planned to require a C-inspection in 2017, whereas GT12 was in poor condition, including because it had a cracked turbine blade which had just been identified, had exceeded the recommended C-inspection “Equivalent Operating Hours” (EOH) and was scheduled to require a C-inspection in 2014. These concepts are described in my examination of Mr Baksi’s evidence. In the modelling which was performed as part of the review, GT11 was identified as the lead gas turbine for the purpose of generation. This approach as to the use of GT11 would defer the significant capital costs associated with the C-inspection of GT12.

305    The decision to mothball half of the generation capacity of the Pelican Point PS was taken and it was put into effect on 1 April 2015.

306    I refer to [61] above. Mr Foulds provided further details of the advice and information PPPL gave to AEMO about its decision. He met with Mr Spurio at AEMO in June 2014. Mr Spurio was Acting Chief Operating Officer of AEMO. Mr Steven Orr, who was the Head of Regulatory at GDF Suez at the time, was also present. Mr Foulds explained to Mr Spurio that conditions impacting the wholesale energy market were such that PPPL had been losing money for a number of years and that that was forecast to continue. He said that there were a number of options available to PPPL to seek to reduce those losses and one of those options was mothballing half of the generation capacity of the Pelican Point PS. GDF Suez had approved a recommendation to mothball half of the generation capacity and this would take effect from 1 April 2015. From 1 April 2015, PPPL would only have firm gas supply and transport arrangements to operate one of its gas turbines and for it to generate only 240 MW of its registered capacity of 480 MW. Mr Foulds advised Mr Spurio that PPPL would update its MT PASA submission from a maximum of 480 MW to a maximum of 240 MW to reflect that decision. Mr Spurio told Mr Foulds and Mr Orr that he was grateful for the advice. He did not indicate that he had any concern with PPPL’s decision or any issue which related to how PPPL would respond to a direction if AEMO directed it to run a second gas turbine.

307    Following the meeting, on 27 June 2014 Mr Foulds instructed either Mr Stephen 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 which would take effect on 1 April 2015. Later on 27 June 2014, Mr Foulds sent Mr Spurio an email as a follow up to their meeting. He did not receive a response to his email and nor does he recall any representative of AEMO querying PPPL’s PASA submissions at any time between that day and 8 February 2017.

308    Mr Foulds gave evidence of his understanding of PASA submissions and advice as to generation capacity. Mr Foulds’ knowledge and understanding of the clauses in the NER which deal with PASA submissions was that it was important to AEMO that PPPL provide accurate information in relation to the generation capacity that it intended to make available and that it did not overstate that generation capacity as this would mislead AEMO into thinking that there would be a greater volume of physical plant capability available on the relevant day than PPPL could make available and could have a direct impact on AEMO’s ability to maintain system security, for example, if it issued a direction in relation to generation capacity which PPPL had declared available in its PASA submissions. As I have said, Mr Foulds directed either Mr Frimston or the duty trader to update PPPL’s MT PASA submission from 1 April 2015 onward to reflect the ability of the Pelican Point PS to make available a maximum of 240 MW of electricity based primarily on the firm gas supply and transport contracts that would be in place at that time that reflected PPPL’s commercial decision to mothball.

309    In the period leading up to the mothballing of generation capacity, PPPL had in place a number of contracts for the supply of gas and for the supply of gas transport. I turn to those arrangements and how, between 25 June 2014 and 15 April 2015, they were affected by PPPL’s decision to mothball half of its generation capacity.

310    Mr Foulds said that in normal operations, it is unusual for a gas turbine to be operating at its maximum generation for a full day. In normal operations, and even when demand is relatively high, each gas turbine required approximately 35 to 45TJ/d of gas supply and transport in order to generate 240 MW from one gas turbine and the steam turbine throughout most of the day. Mr Foulds said that this came about because of the non-linear nature of South Australia’s energy demands and energy supply and that there were and are substantial periods of the day when South Australia’s energy demands are such that it is not commercial or necessary for the Pelican Point PS to operate. He said that this is consistent with the Pelican Point PS being a mid-merit power station. Mr Foulds noted correctly that even on 8 February 2017, PPPL did not operate at full load for the entire day.

311    The measures which PPPL undertook to implement the decision to mothball half of the generation capacity of the Pelican Point PS insofar as they relate to gas transport and gas supply are important.

312    With respect to gas transport, Mr Foulds said, and I accept at a general level, that in 2014 the market to on-sell gas transport rights was small and non-liquid. PPPL had two gas transportation agreements in place.

313    The first was a gas transportation agreement between South East Australia Gas Pty Ltd (SEAGas) and PPPL for the transportation of gas on the pipeline from Port Campbell to Adelaide (PCA pipeline) for the period from April 2003 to December 2018 (PCA Contract). The amount involved was approximately 88TJ/d. PPPL was one of three Foundation Shippers on the PCA pipeline and the volume was fixed and non-seasonal.

314    PPPL also had a gas transportation agreement with Epic Energy South Australia Pty Ltd (Epic) for the transportation of gas on the Moomba-Adelaide Pipeline System (MAPS) for the period from March 2007 to December 2019 (MAPS Contract). Mr Foulds asserted that, although PPPL held the rights under the MAPS Contract, those rights had been largely on-sold on an arm’s length basis by PPPL to companies within the ENGIE group, including Synergen Power and, at other times, Simply Energy. Mr Foulds said that as a result, whilst at various times PPPL may have had transport rights available to it under the MAPS Contract, the predominant source of gas to operate the Pelican Point PS was transported on the PCA pipeline.

315    The decision to mothball half the generation capacity of the Pelican Point PS suggested that some of the transport rights held by PPPL should be on-sold to avoid ongoing costs. On the other hand, Mr Foulds said that should a time come when PPPL could have operated both gas turbines commercially, then PPPL may have difficulty buying back or buying additional transport rights. The matter was considered in detail within GDF Suez and PPPL entered into two agreements in relation to the transportation rights that it held with respect to the PCA pipeline.

316    The first agreement was a Gas Haulage Capacity Sale Agreement between PPPL on the one hand, and Santos Direct Pty Ltd and Santos Limited on the other (collectively Santos). The agreement was executed on 2 June 2014 and applied during the period from 1 April 2015 to 1 January 2019. Under the agreement, PPPL agreed to provide Santos with at least 20TJ/d of firm transport rights in the summer months (October–April) and at least 50TJ/d of firm transport rights in the winter months (May–September). PPPL also agreed to provide Santos interruptible firm haulage capacity of 30TJ/d. I will refer to this agreement as the Santos GHCSA.

317    The second agreement was a SEAGas PCA – MDQ Trading Agreement between PPPL and Origin Energy Retail Limited (Origin Energy) executed on 30 November 2015 and relating to the period from 1 January 2016 to 1 January 2019 and under which PPPL agreed to provide Origin Energy with 30TJ/d of firm transport rights from 1 April 2016 onwards. I will refer to this as the Origin Energy MDQ Trading Agreement.

318    In the circumstances, assuming a starting quantity of 88TJ/d on the PCA pipeline, PPPL was left with gas transportation rights in summer of up to 38TJ/d of firm transport on the PCA pipeline.

319    Mr Foulds said that, in addition, in relation to its gas transportation rights on the MAPS, PPPL entered into further arm’s length agreements with Synergen Power and Simply Energy so that it held either little or no gas transportation rights on the MAPS. I will come back to these agreements.

320    Mr Foulds said, and I accept at a general level, that with respect to the supply of gas, there is a more liquid market for the trading of gas supply.

321    In 2014, PPPL’s gas supply agreements were with BHP under a long term gas supply agreement running through to about October 2016. This gas supply agreement related to the supply of gas from BHP’s Minerva gas field. Mr Foulds described the background and early relationship between PPPL and BHP. He said that after the decision to mothball half of the generation capacity of the Pelican Point PS and with respect to the period from October 2016 onwards when the underlying gas supply agreement with BHP expired, PPPL executed in stages two agreements with BHP. These agreements are described in detail by Mr Weatherly (at [391]). I will refer to these agreements as the BHP Gas Supply Agreements.

322    There is a second gas supply agreement which is relevant. It is an agreement between PPPL and Origin Energy for the supply by Origin Energy of 5TJ/d of gas for the period from 1 January 2017 to 31 December 2017. Further details of this agreement, which I will refer to as the Origin Energy Gas Supply Agreement, are set out in the evidence of Mr Weatherly (at [392]).

323    The respective agreements with BHP and Origin Energy meant that in relation to the summer of 2016/2017, PPPL had available to it 35TJ/d of gas supply prior to 1 January 2017 and 40TJ/d of gas supply from 1 January 2017 onwards. Mr Foulds’ understanding was that this volume was subject to certain on-selling arrangements that provided rights to Synergen Power and Simply Energy.

324    Mr Foulds gave evidence of significant changes and events in the market in the South Australian region following PPPL’s mothballing announcement and they included the Heywood Interconnector failure, developments at the Torrens Island Power Station, developments at the Northern Power Station, developments at the Playford B Power Station and the selection of PPPL to be a reserve provider on the Reliability and Emergency Reserve Trader or RERT panel. I do not need to describe these matters at this point and it is convenient to turn now to the decision by PPPL to bring GT12 out of dry storage in November 2016.

325    Mr Foulds said that the decision to bring GT12 out of dry storage in November 2016 was made because ENGIE had a desire that its South Australian generators assist to ensure reliability of supply of electricity in South Australia. Nevertheless, the intention was to deliver 240 MW approximately and, as he put it, at the end of the day, they were maintaining 240 MW of capacity.

326    Mr Foulds identified a number of factors which meant that South Australia was facing what he referred to as significant energy security risks that it had not faced in previous summers. He referred to the political focus on PPPL at the time. Mr Foulds gave evidence of the two events which occurred in the lead up to the 2016/2017 summer and which led him to believe that the South Australian region was facing significant energy security risks. The first event was the closure of the Northern Power Station and the closure “finally” of the mothballed Playford B Power Station. It was the first summer without the Northern Power Station providing 520 MW of coal-fired baseload power. The second event was the September 2016 Black System event. A number of windfarms 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 NEM.

327    Mr Foulds was of the view that the Pelican Point PS would be running its primary gas turbine for significant periods of time during the summer of 2016/2017. The discussions within PPPL (and which included Mr Foulds) included the prospect of returning GT12 to service for the summer prior to its major C-inspection overhaul so that the Pelican Point PS could best position itself to maintain available capacity of 240 MW at all times during the summer by using both GT11 and GT12 interchangeably.

328    Mr Foulds said that ultimately, the decision was made by the Head of Generation of GDF Suez (Mr Luc Dietvorst) that GT12 would be returned from dry storage to wet storage and available to be used interchangeably with GT11, subject to management of the operational risks relating to GT12 throughout the summer. Mr Foulds said that this decision was made with the knowledge that at any time the physical condition of GT12 was such that it might be withdrawn from service indefinitely until it could be overhauled during a C-inspection which was then scheduled to take place from about April to May 2017. The C-inspection of GT12 was the subject of a purchase order issued late in December 2016. Mr Foulds said that these discussions sought to balance both the commercial interests of PPPL and its desire to remain a source of reliable electricity generation throughout a summer in which it was considered that the South Australian region was likely to experience reserve shortfalls. Mr Foulds said that the “main driver” of returning GT12 from dry storage to be used as a backup gas turbine was for “PPPL to act as a good corporate citizen and to ensure it could make half of its capacity available to be called upon if AEMO required it, in order to maintain system security”. It did not mean that PPPL’s position that it would make only half of the generation capacity of the Pelican Point PS available had changed. PPPL’s position remained as it was and that was because PPPL only had gas supply and transport arrangements to support the generation of up to 240 MW and the condition of GT12 was such that PPPL’s view was that it could not be relied on to be used in a continuous manner. Mr Foulds added that this position was reinforced by the uncertainty around the extent to which the sources of renewable energy would be able to support the State’s energy demands, the extent to which gas-fired power stations, both peaking and mid-merit, would be called upon to support the State’s energy demands, and the impact of that dynamic on the market for spot gas which would be in high demand if market conditions were such that the operators of the peaking gas plants sought to generate and bid into the market.

329    Mr Foulds said in his evidence that he did not specifically turn his mind to whether PPPL should update its PASA submissions after GT12 was returned to wet storage. He said that this was principally because PPPL only had gas supply and transport arrangements to support the generation of up to 240 MW and the condition of GT12 was such that PPPL’s view was that it could not be relied on to be used in a continuous manner. Furthermore, Mr Foulds considered that had PPPL’s ST or MT PASA submissions for 8 February 2017 been about 440 to 470 MW, it would be said that it had no reasonable basis to make such a submission having regard to its gas arrangements, its commercial intention at the time and the condition of GT12.

330    On or about 11 November 2016, GT12 was moved from dry to wet storage and thereafter in November and December 2016 was used interchangeably as the primary gas turbine. In November and December 2016, GT12 logged about 900 EOH, taking it further beyond the recommended EOH for the C-inspection to over 4,600 EOH beyond that interval and, according to Mr Foulds, further increasing the risk of failure of that gas turbine. In January 2017, GT11 was used as the primary gas turbine logging 604 EOH for January compared to 228 EOH for GT12 for the same period. From about mid-January 2017 to 7 February 2017, GT12 was not operated other than for brief periods so that it could continue to be kept in wet storage. It was kept in wet storage so that it could return to service in order to ensure that PPPL could continue to generate up to 240 MW in accordance with its PASA submissions and any reserve contract made under the RERT panel agreement. Mr Foulds said that these operational decisions were made primarily by Mr Dietvorst.

331    Mr Foulds said that for normal operations over the summer of 2016/2017, the operation of a primary gas turbine was sufficient to meet energy demands. As previously noted, there were substantial periods where South Australia’s energy demands were such that it was not commercial or necessary for PPPL to operate. At the same time, there was a number of days that summer where South Australia’s energy demands were such that PPPL sought more gas from the spot market to run the primary gas turbine for longer periods at its full load.

332    I turn now to Mr Foulds’ evidence about events on 8 February 2017.

333    Mr Foulds said that on 8 February 2017, he spoke to Mr Vince Duffy who was the Executive Director of Energy Markets in the South Australian Government. He had a working relationship with Mr Duffy and he previously made him aware of the details of the mothballing of capacity at the Pelican Point PS and the financial strain that PPPL had been under. Mr Foulds and Mr Duffy had a discussion concerning the diesel fuelled Port Lincoln power plant. Mr Foulds told Mr Duffy that, in his view, it was likely that AEMO would be required to load shed to maintain system security. He said to Mr Duffy that he was surprised that no one from AEMO had contacted PPPL about whether the Pelican Point PS could make its mothballed capacity and GT12 available or be the subject of a reserve contract or a direction.

334    Mr Foulds gave evidence of his understanding of various telephone conversations between representatives of PPPL and representatives of AEMO on 8 February 2017. He referred to the telephone conversation between a representative of AEMO and Mr Andrew Godfrey, a PPPL trader, at 17.39. He said that Mr Godfrey’s statement that at the time of the telephone conversation, GT12 was technically available, but PPPL did not have the gas to run the unit was correct. PPPL only had sufficient gas supply and transport to generate a maximum of 240 MW (subject to weather conditions) for substantial periods during the day and did not have any other firm rights to gas supply and transport.

335    Mr Foulds also addressed the telephone conversation between an AEMO representative and Mr Godfrey at 18.00. In this conversation, Mr Godfrey said that, in regards to gas, PPPL could probably run GT12 for about four to eight hours. Mr Foulds said, to the extent that the conversation suggests that PPPL had gas supply and transport to operate GT12 in conjunction with GT11, this was incorrect, as at that time, PPPL only had firm gas supply and transport to operate GT11. He said that an agreement for gas supply and transport to operate GT12 was not reached until later on 9 February 2017 in response to a direction by AEMO under cl 4.8.9 of the NER. Mr Foulds said that this position was conveyed by PPPL in its subsequent telephone calls with AEMO, including a call between an AEMO representative and Mr Godfrey at 20.10 and a call between an AEMO representative and Mr Godfrey at 22.25. That was also conveyed during a telephone call at 23.55 on 8 February 2017. Mr Foulds said that the reference by Mr Godfrey during the call at 18.00 to running GT12 for about four to eight hours was a reference to the minimum run-time of the gas turbines and not to any firm additional gas supply and transport which was available to operate GT12 at that time.

336    PPPL submitted that I should accept Mr Foulds’ evidence about the characterisation and significance of the conversations between Mr Godfrey of PPPL and the representative of AEMO. Mr Godfrey did not give evidence. The subsequent conversations suggest that he was not saying that PPPL had secured rights to gas to run GT12 for about four to eight hours and to that extent, I accept Mr Foulds’ evidence. However, having regard to the context, I have difficulty accepting that Mr Godfrey was not expressing a degree of confidence about securing sufficient gas to run GT12 for about four to eight hours.

337    At 18.03 on 8 February 2017, AEMO issued a direction to shed 100 MW of electrical load. This was what he described as a relatively significant event as it meant that thousands of end-users were subject to a blackout.

338    Late in the evening of 8 February 2017, or early in the morning of 9 February 2017, Mr Godfrey telephoned Mr Foulds and told him that he had received and made several calls to and from AEMO and on those calls AEMO had asked him to make preliminary inquiries as to the availability of gas supply and transport to operate GT12. Mr Godfrey had made those inquiries. He told Mr Foulds that he advised AEMO that those inquiries indicated that there was likely to be gas supply and transport available from the spot market on 9 February 2017. Mr Godfrey advised AEMO that, notwithstanding those indications, that availability was subject to making further inquiries after PPPL received a direction from AEMO and when PPPL was in a position to actually enter into an agreement for that supply and transport. Mr Godfrey also told Mr Foulds that on one of those calls, AEMO had asked PPPL to update its ST PASA to reflect any additional capacity that PPPL could make available to the market if AEMO directed it to operate its second gas turbine. Mr Foulds told Mr Godfrey that PPPL would not update its ST PASA and that its ST PASA reflected its firm gas supply and transport arrangements for 8 and 9 February 2017 which reflected the generation capacity that PPPL intended and estimated it would make available on the market. Mr Foulds told Mr Godfrey that if AEMO wanted to give PPPL a direction, that that had nothing to do with PPPL’s PASA submissions and that PPPL would “just use its best endeavours to comply with that direction”. Mr Godfrey agreed with Mr Foulds and said that he would get back to AEMO. 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.

339    Mr Foulds next addressed the extent to which PPPL reasonably expected that it would practically be able to procure gas supply and transport to fuel the second gas turbine to operate concurrently with the primary gas turbine at the Pelican Point PS for 8 February 2017 on 24 hours’ notice. Mr Foulds said that in advance of 8 February 2017, he did not at a general level have any expectation of being able to obtain gas supply and transport to provide fuel and transport for a second gas turbine on that day. He identified difficulties with the generality of the question he had been asked and he also referred to the fact that a review of gas strategy was undertaken by ENGIE and that had referred to the tightening east coast energy market driven by the ramp up of LNG exports from Queensland and the declining nature of BHP’s Minerva gas field. Mr Foulds said that, given the uncertainties in the market that summer, he did not have any particular expectation of obtaining gas until he had a firm contract for short term supply and transport. The fact that PPPL was ultimately able to obtain gas and transport on 9 February 2017, did not alter any expectation that Mr Foulds had prior to that time, or in relation specifically to 8 February 2017. He said he could not recall the “specifics” when it was suggested to him that at no time between 11 November 2016 and 8 February 2017, to his knowledge, did PPPL seek or obtain gas supply and transport rights that would permit it to make available more than 240 MW of generating capacity. Mr Foulds maintained that the moving of GT12 from dry storage did not change PPPL’s intention to make 240 MW available. As I have said, Mr Foulds’ evidence was that following the decision to mothball half the generation capacity of the Pelican Point PS, he directed Mr Frimston, or the duty trader on shift at that time, to update PPPL’s MT PASA from 1 April 2015 onwards to reflect the ability of the Pelican Point PS to make available a maximum of 240 MW of electricity “based (primarily) on the firm gas supply and transport contracts that would be in place at that time, which reflected PPPL’s commercial decision to mothball”.

340    Mr Foulds identified the person who had the responsibility for submitting PPPL’s MT PASA submission at that time on a week to week basis as the duty trader who he said would have followed a procedure which was driven by the requirements of the NER and was a rigorous process. Mr Foulds said that it was “driven off generic information that flowed through into the, onto the operations desk” and that in 2014, the MT PASA submission each week was a culmination of many processes that would all filter through onto the operations desk. Mr Foulds did not personally enter any PASA submissions in respect of the Pelican Point PS between 11 November 2016 and 8 February 2017 and he said that that was an “operational desk responsibility” and “typically the responsibility of the duty traders”.

341    Mr Foulds said, and I accept, that at the time of the C-inspection of GT12, PPPL spent approximately $40 million replacing the blades in the turbine.

342    Mr Foulds was cross-examined about his evidence that after GT12 was returned to wet storage, he did not specifically turn his mind to whether PPPL should update its PASA submissions. In cross-examination, Mr Foulds appeared to say that it was not correct to say that he did not specifically think about whether PPPL should update its PASA availability submissions. He said that that evidence must be read in the context of the reasons PPPL had decided to make only half of its generation capacity available. PPPL asked the Court to characterise what Mr Foulds was saying as being that the view he had earlier formed about the PASA availability of the Pelican Point PS was not altered by the return from dry to wet storage of GT12 because of the limited gas supply and transport arrangements and the condition of GT12. I do not think that he did give consideration to the matter. His focus was on the intention of PPPL which was to run one gas turbine only at any particular time.

343    Mr Foulds said in re-examination and in the context of a suggestion made by the AER that no inquiries were made by ENGIE or entities in the ENGIE group to procure additional gas supply that in 2016 there were numerous discussions between PPPL and Origin Energy about the possibility of a “tolling agreement”. Mr Foulds was involved in that and an agreement was concluded in 2017.

344    Before referring to the submissions of the parties with respect to Mr Foulds, I make the following observations. First, Mr Foulds occupied a relatively high level position in the management structure of PPPL. He was involved in the major decisions and the relevant major decision was the decision to mothball half the generation capacity of the Pelican Point PS, but it was others down the line who were aware of the particular details of specific circumstances and events. Secondly and relatedly, Mr Foulds’ inability during the course of his evidence to provide particular details of events and circumstances reflects his position within PPPL rather than any failure of his memory or unwillingness to be forthcoming. Thirdly, as far as Mr Foulds was concerned, the key was to proceed prudently. PPPL could make 240 MW available, but beyond that, the market was difficult and it was only non-firm gas that would be available and, as Mr Foulds put it: “Until it’s made firm, I can’t with certainty make any — any update”. Finally, Mr Foulds’ evidence clearly established PPPL’s “current intentions” which was to operate one gas turbine at Pelican Point PS and, subject to any matters arising from the condition of GT12, to operate GT11 and GT12 interchangeably.

345    PPPL submitted that the evidence of Mr Foulds is significant because he was the supervisor of the traders and his beliefs and expectations were inconsistent with the capacity of two turbines being relevantly available on 24 hours’ notice. PPPL relies on his evidence of its intentions and expectations.

346    In response to question 23 in the notice served by the AER, ENGIE said the following:

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?

Answer

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.

347    PPPL pointed to the fact that Mr Foulds said in the course of his evidence that there were discussions talking through the risks of operating GT12, pursuant to an AEMO direction, in conjunction with GT11 and where PPPL would not have a backup during an extreme weather event. Mr Foulds said that despite these risks, and in the context of AEMO likely directing PPPL to operate GT12 on 9 February 2017, the common view reached in the course of those discussions was that PPPL would do all that it could to assist AEMO, subject to being able to secure gas to operate GT12 in conjunction with GT11.

348    PPPL relied on Mr Foulds’ evidence that he did not have any expectation of being able to obtain gas supply and transport to fuel a second gas turbine on 8 February 2017 and the fact that PPPL was ultimately able to obtain gas supply and transport on 9 February 2017, did not alter any expectation that he had prior to that time or in relation specifically to 8 February 2017. Mr Foulds referred to the fact that he had taken into account the availability of spot gas, the ENGIE portfolio, the MAPS and PCA pipeline, and linepack informing the conclusion that he did not have any actual expectation that PPPL would be able to procure additional gas supply and transport to fuel GT12 on 8 February 2017 on 24 hours’ notice. In addition, if PPPL was able to make arrangements with counterparties for additional gas supply and transport for that day, there would have been a risk that it would not be delivered when PPPL required it. I accept that that was Mr Foulds’ opinion, but at the same time, I infer that he would not have had the knowledge of the market for gas and gas transport that Mr Frimston or the duty traders had.

349    The AER challenged aspects of Mr Foulds’ evidence.

350    First, the AER submitted that Mr Foulds’ affidavit and oral evidence was marked by strained attempts to maintain that PPPL did not mothball a gas turbine, but had instead mothballed 239 MW of generating capacity. The AER referred to a number of statements in Mr Foulds’ affidavit to the effect that the decision was made to mothball half of the generation capacity of the Pelican Point PS. In the course of his evidence, Mr Foulds said that the term “mothball” did not have a statutory definition, but was commonly understood by the electricity industry to mean the mid to long term removal of a portion or the entirety of the generation capacity of a power station. He referred to the glossary of the NEM Electricity Statement of Opportunities (ESOO) published annually by AEMO. In that document, “mothballed” is defined as “a generation unit that has been withdrawn from operation but may return to service at some point in the future”. He referred to mothballing generation capacity in a number of paragraphs in his affidavit and in his oral evidence. The point is illustrated by the following question and answer in cross-examination:

Yes. Thank you. And so what I want to suggest to you, Mr Foulds, is that unlike the meetings and the emails that you had with AEMO in July 2014 to inform them about that that capacity would be put into mothballs, from 11 November 2016, ENGIE did 10 not take steps to inform AEMO with absolute clarity about the recall time of that mothballed capacity. What do you say to that?---Well, the capacity remained the same. There was no, there was an ability to dispatch 240 megawatts and at times there was, you know, to manage the risk of not being able to deliver 240 megawatts, you know, at times, you know, actions were taken. But there was never any variation for the ability for Pelican Point to dispatch more than 240 megawatts of capacity ...

351    Mr Foulds gave evidence that he communicated PPPL’s decision in 2014 to mothball half of its generation capacity at the Pelican Point PS to AEMO with absolute clarity. The AER pointed to Mr Foulds’ evidence that he could not testify to ENGIE having informed AEMO at any time after 11 November 2016 that, as a result of GT12 having been returned from dry storage to wet storage, it could now be brought online within approximately four hours, subject to gas supply, gas transport and staffing. The AER’s submission, insofar as it identified the evidence Mr Foulds gave, is correct. However, I do not consider that there was any sinister reason behind Mr Foulds’ characterisation of a mothballing of generation capacity as distinct from the mothballing of GT12. That simply reflects how PPPL saw the matter.

352    Secondly, the AER submitted that the most significant point to emerge from Mr Foulds’ evidence was that it was not part of his responsibilities to submit PASA inputs on behalf of PPPL. The persons authorised to do so were Mr Frimston, who was the Trading Operations Manager, and the trading team that he supervised. Mr Foulds agreed with the proposition put to him in cross-examination that it was Mr Frimston’s responsibility to either ensure that or to supervise the traders in their duties generally, including the submission of MT PASA inputs on a week to week basis and ST PASA inputs when they were required to be made.

353    Furthermore, the AER relied on question 5 in the Section 28 Notice served by the AER and ENGIE’s response thereto. The question and answer were as follows:

State which persons with IPAH were responsible for, and/or had authority for, submitting to AEMO ST PASA inputs and MT PASA inputs for PPCCGT during the period 11 November 2016 to 8 February 2017, in respect of the 8 February 2017 trading day, the positions of those persons and the names and position of their immediate superiors.

Answer

Please refer to the organisational chart labelled “Figure 5” (ENG.501.001.0182) provided in response to this question.

The Energy Traders were: Caroline Converset; Andrew Morrisey; Andrew John; Aaron Finn; Ben Wilson; Andrew Godfrey; and Jack Anderson.

The listed Energy Traders were supervised by Steven Frimston, Trading Operations Manager during this period. Steven Frimston was supervised by Darren Foulds, Head of TPM during this period.

354    The Court has evidence from Mr Foulds who was the person who instructed Mr Frimston to alter the PASA submissions after the mothballing of half the generation capacity of the Pelican Point PS. The Court does not have evidence from the persons who thereafter made the MT PASA and ST PASA submissions.

355    Thirdly, the AER submitted that if PPPL’s commercial intention as to the extent it planned to offer the physical plant capability of Pelican Point PS for dispatch into the market is relevant to its PASA availability under the rubric of “current intentions” in cl 3.7.3(e), as relevant to ST PASA (and one of its submissions was that it is not), the AER accepts that, at all relevant times, PPPL did not subjectively intend to make more than the capacity of one gas turbine available in the market. The AER made that clear in its opening. Counsel for the AER said that it did not contest that PPPL did not intend to make GT12 available and said that the AER was not running a fraud case. The AER was not suggesting, for example, that PPPL in fact intended to make both turbines available, but did not disclose it. The AER accepts that PPPL did not intend to make GT12 available on the relevant date. One of the AER’s submissions, it will be recalled, was that PPPL’s intention is relevant, and only relevant, to the available capacity of the Pelican Point PS which PPPL was required to submit under cl 3.7.3(e)(1) of the NER.

356    Fourthly and relatedly, the AER submitted that beyond the acceptance of what they called “that basic fact”, none of Mr Foulds’ evidence was probative as to PPPL’s “current intentions” as reflected in its ST PASA availability. He did not submit, or instruct his subordinates to submit, PASA inputs during the relevant period and he made clear that making PASA submissions was not part of his responsibilities. In the circumstances, the relevant intention to be imputed to PPPL, insofar as its intention is relevant to PASA availability, was that of the traders who made the PASA availability submissions in issue, or who instructed that they be made at a particular level. The AER submits that that accords squarely with the observations of Lord Hoffman in Meridan Global Funds Management Asia Ltd v Securities Commission (1995) 2 AC 500 at 511 as follows:

Once it is appreciated that the question is one of construction rather than metaphysics, the answer in this case seems to their Lordships to be as straightforward as it did to Heron J. The policy of section 20 of the Securities Amendment Act 1988 is to compel, in fast-moving markets, the immediate disclosure of the identity of persons who become substantial security holders in public issuers. Notice must be given as soon as that person knows that he has become a substantial security holder. In the case of a corporate security holder, what rule should be implied as to the person whose knowledge for this purpose is to count as the knowledge of the company? Surely the person who, with the authority of the company, acquired the relevant interest. Otherwise the policy of the Act would be defeated. Companies would be able to allow employees to acquire interests on their behalf which made them substantial security holders but would not have to report them until the board or someone else in senior management got to know about it. This would put a premium on the board paying as little attention as possible to what its investment managers were doing.

357    The AER submitted that the Court has no evidence to what extent the opinions or “rationalisations” deposed to by Mr Foulds were in fact conveyed to the responsible traders, nor whether those traders agreed with those opinions or formed their own intentions having regard to other information. It followed, in those circumstances, that Mr Foulds’ evidence was of no probative value to PPPL’s actual intentions that informed the making of its PASA availability submissions. It is not clear to me where this submission goes because, in my opinion, it has been clearly established (and accepted by the AER) that PPPL’s intention at the relevant times was to operate one gas turbine. As to the related point of the reasons PPPL did not make a “higher” PASA submission, I consider that despite the fact that neither Mr Frimston nor Mr Godfrey (or indeed any of the other energy traders) were called, on the basis of Mr Foulds’ evidence and the evidence referred to below (at [592]–[595]), I find that that was because of the absence of firm gas supply and gas transport arrangements to support the running of a second turbine.

Mr Baksi

358    Mr Baksi was the General Manager – South Australian Assets of ENGIE ANZ until 7 August 2020. He holds a Bachelor of Engineering (Mechanical Engineering) with First Class Honours from the Indian Institute of Engineering, Science and Technology. He has worked in various roles at GDF Suez (now trading as ENGIE), formerly International Power, for 21 years.

359    In his role as General Manager – South Australian Assets from August 2012 to August 2020, Mr Baksi was responsible for the management of operations of all ENGIE’s assets in South Australia, including the Pelican Point PS. He said that in relation to the Pelican Point PS, he oversaw the operations side of the business, including maintenance and long term asset management. He managed a team of operation and maintenance managers, a renewables and compliance manager, control room operators, engineers and maintenance workers at the Pelican Point PS.

360    Mr Baksi said that the operations team worked closely with the trading team which he described as largely “market-facing” and as dealing with external stakeholders, including AEMO/ElectraNet and counterparties to source gas and bid capacity into the market. By contrast, the operations team is largely “plant-facing” and is responsible for the continued operation of the plant and for responding, to the extent possible, to requests from the trading team to make generation capacity available. The operations team advises the trading team of what generation capacity can be made available and any operational (technical) risks associated with that generation. The trading team, having received the advice of the operations team, makes the final decision about whether or not generation capacity will be made available.

361    Mr Baksi described the two gas turbines at the Pelican Point PS and the steam turbine and how the heat from the gas turbine(s) is used as power for the steam turbine. It is not necessary for me to set out the details, except to note the importance of maintaining the proper water chemistry in the heat recovery steam generators. The key point is that there are various rules of operational practice as to how often a gas turbine should be run if it is in wet storage and when it is operated, how long it should be operated for depends on when it was last operated.

362    Mr Baksi described a C-inspection of a gas turbine as a major inspection and overhaul which is a key aspect of maintaining the safe availability and reliability of gas turbines. It is a periodic service undertaken on the CCGT which requires it to be fully stripped down, overhauled and rebuilt. As part of that process, a number of key components of the gas turbine are usually replaced and refurbished. In addition, peripheral parts of the gas turbine will be checked and replaced, and other maintenance work will be undertaken.

363    Mr Baksi described the concept of Equivalent Operating Hours (EOH) as a measure of hours that a gas turbine has operated, which are calculated by adding actual operating hours with the number of start-ups multiplied by 20. The reason start-ups are multiplied by 20 is because they increase the wear on the gas turbines. In terms of the C-inspection, the reference to EOH is the period which the gas turbines may be operated in between two consecutive C-inspection overhauls. It is not a reference to the total number of operating hours that a gas turbine has accumulated since it was commissioned and first fired. Mr Baksi said that PPPL had operated GT11 and GT12 with ST18 since 2001.

364    C-inspections often involve a significant capital commitment and the relevant gas turbine and heat recovery steam generator being out of action for anywhere between 35 days and a couple of months.

365    The manufacturer’s recommendation for C-inspections was that they should be carried out after every 24,000 EOH. PPPL had established from experience and it was Mr Baksi’s view that intervals of 29,000 EOH (and possibly up to 30,000 EOH) were possible.

366    By approximately early 2014, GT11 was not due for a C-inspection until about 2017, subject to its actual running regime. It had had a previous C-inspection in 2011 and had undergone a complete blade replacement with “MXL” turbine blades fitted. These blades represented a significant improvement over previous versions, with a manufacturer recommended C-inspection of 36,000 hours. On the other hand, GT12 which was fitted with original 13E2 blades and had exceeded 25,000 EOH since its last C-inspection and had developed cracking in its gas turbine blades, including a crack on the trailing edge of blade #18 on row 1 and severe “letterbox” cracking on almost all blades on row 1.

367    Mr Baksi said that a crack on the trailing edge of a blade is located at the thinnest and rear section of the blade. In the case of this particular crack, it was located near the base of blade #18 on row 1 of the five gas turbines blades of GT12. Mr Baksi said that of all the rows of blades, row 1 is exposed to the highest-temperature flue gas. The row 1 blades are most expensive with a replacement cost of approximately $3 million AUD.

368    The crack in blade #18 was first detected during a minor inspection of GT12 in about late 2013 which included a borescopic inspection. Such an inspection involves the use of an optical tool which allows the engineer to visually inspect the blade in-situ inside the turbine casing without opening it. A letterbox crack is a crack located at the top of the blade and is caused by a design deficiency associated with the older design of the blades. There is a low risk of letterbox cracks resulting in part of the blade becoming liberated. Nevertheless, as with any substantial piece of metal becoming liberated in the gas turbine, any such failure would be catastrophic.

369    Of most concern to Mr Baksi was the crack on blade #18. He said that the PPPL engineering team consulted Alstom and GDF Suez’s corporate gas turbine specialists about the crack. Mr Baksi produced email correspondence in late 2013 between Mr Phil von Einem, who reported to Mr Baksi, and Mr Simon Corlett of Alstom. Mr Baksi said that his view at the time was as follows:

(1)    there were low risks associated with continuing to operate GT12 as long as the crack on blade #18 did not progress and reach a stage causing metal to be liberated;

(2)    the risk of the blade crack progressing could be minimised to some extent by undertaking regular borescopic inspections and this was recommended to be undertaken after every five start-ups of GT12; and

(3)    despite the risks being minimised by those inspections, there was still a medium to high level risk of blade failure in between those borescopic inspections and such a failure within the CCGT would be catastrophic.

370    By the time GT12 was mothballed in April 2015, it had accumulated 27,217 EOH since its last C-inspection. Mr Baksi described his concern about the cracked blade and its potential to break off and cause extensive damage “which included total or near total destruction of the GTs”. Repair costs could run into “the many tens of millions of dollars”.

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.

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.

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.

376    Mr Baksi gave evidence that if someone had asked him a month or two prior to January 2017 whether GT12 could have run for 2,000 hours, he would have said that he did not know because it would be subject to the runs and consecutive inspections as well as all the preservation methodology “that we have discussed so many times”.

377    In the context of objections to Mr Baksi’s evidence, and in particular paras 16 and 17 of his affidavit (the outcome of the objection is irrelevant for present purposes), the AER in the schedule of objections said that it did not dispute that PPPL did not “subjectively intend” to use GT12 concurrently with GT11 on 8 February 2017. I refer to my discussion of PPPL’s intention in the context of Mr Foulds’ evidence. The AER goes on to say that the condition of GT12 and the alleged risk of it failing are otherwise irrelevant to PPPL’s pleaded case. In particular, PPPL did not allege in its Concise Response that the physical condition of GT12 was such that it was not able to be made available on 8 February 2017. This was confirmed by a letter dated 14 August 2020 from PPPL’s solicitors which stated, “PPPL has never stated that the physical condition of GT12 prevented it from being operated or made available on 8 February 2017”.

378    Mr Baksi left ENGIE on 7 August 2020 after a reorganisation and his position became redundant. He left after Mr Frimston had left ENGIE. Mr Frimston went to work for AEMO first and then he moved on to work for AGL. Mr Baksi also said that starting a second gas turbine required him to arrange for additional manpower because PPPL was on skeleton manpower during those days.

379    Mr Baksi accepted that PPPL ran GT12 on 9 February 2017 for approximately four hours, that PPPL was not required to comply with a direction from AEMO if, among other circumstances, it would materially risk damaging equipment and that his primary concern was running the two turbines together such that there would not be a “back-up” in the event of failure.

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”. Mr Baksi said that as far as the number of EOHs before a C-inspection was concerned, 20,000 to 30,000 was the recommended practice at every “GDF SUEZ site”. PPPL did not accept the recommendation of the manufacturer that a C-inspection be performed at or around 24,000 EOHs.

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.

383    Mr Baksi agreed that PPPL had run both turbines on each of the days between 28 March and 31 March 2017 with a maximum output of at least 450 MW on each day.

384    Mr Baksi said that the reason GT12 was run for a number of hours more than GT11 in November and December 2016 was because PPPL sought to conserve GT11 once it became clear that GT12 would be undergoing a C-inspection and the latter became clear during discussions with Origin Energy about a tolling agreement.

Mr Weatherly

385    Mr Weatherly is an energy consultant. He conducts his own energy consulting business which he established in July 2018. He provides management consulting services to businesses in Australia. He is primarily engaged in strategic portfolio reviews as well as assisting in business development projects, including reviewing businesses’ gas portfolios and customer bases and advising on strategic options arising from that review, assisting businesses with commercial negotiations, reviewing and advising on pipeline contracts, and providing wholesale gas and electricity procurement advice.

386    Mr Weatherly obtained a Bachelor of Commerce in Accounting from the University of South Australia in 2008 and he obtained a Bachelor of Business (Commercial Law) in 2015.

387    Mr Weatherly has worked in the energy sector in Australia since 2005. It is not necessary to set out the details of his employment history other than to say that he worked for International Power (Australia) from May 2007 to June 2018 and that during that time, he worked as an energy trader, trading originator/senior trading originator, trading manager and origination manager in Australia. In the last position which he commenced in March 2015, Mr Weatherly was responsible for developing and executing strategies to utilise the assets of the Australian business, as well as leading a team of between three to six persons (depending on the period) to develop wholesale market structured transactions (particularly framework agreements which provided a basis for day-to-day transactions, gas supply, transport and storage contracts (other than spot) and bespoke electricity arrangements). The duties he performed as part of his role as Origination Manager included managing key relationships with external stakeholders and negotiating and executing both higher-level agreements, which would provide a framework for short term trades, and more detailed bespoke contracts between PPPL and other Market Participants for gas supply and transport, as well as storage, gas derivative trading and bespoke electricity arrangements, including with external stakeholders. The examples of external stakeholders which Mr Weatherly gave were South East Australian Gas Pty Ltd (SEAGas), Epic Energy South Australia Pty Ltd (Epic) (the owner of the MAPS), BHP Petroleum (Victoria) Pty Ltd (BHP), Origin Energy Retail Limited (Origin Energy) and Santos Limited (Santos).

388    Mr Weatherly described the market in which PPPL’s Pelican Point PS was operated as a challenging market in about 2013–2014 and he said that to remain a going concern, PPPL had to take a much more proactive role in managing its gas arrangements with a view to substantially reducing its fixed gas costs. PPPL entered into agreements with third parties as well as with other entities within the ENGIE group of companies.

389    At the time that Mr Weatherly commenced working for the ENGIE group in 2007, PPPL was the central gas trading company in the ENGIE portfolio in the Victorian and South Australian region. The portfolio included two companies which traded as “Simply Energy”, being IPower Pty Limited and IPower 2 Pty Limited. These companies were a significant mass-market energy retailer with a large volume of retail customers in Victoria and South Australia. The group of companies also included Synergen Power Pty Ltd (Synergen Power) which owned and operated (relevantly for present purposes) two gas-fired peaking power stations, one at Dry Creek and the other at Mintaro in South Australia. Mr Weatherly described wholesale electricity and/or gas prices in the period from at least 2014 to 2017 as highly volatile. He said it was not uncommon for the wholesale cost of electricity to vary from $1,000 to $14,000 per megawatt hour in a 5-minute interval. His duties as Origination Manager included entering into a number of arm’s length agreements which sought to limit the exposure of the entities within the group to the highly volatile prices.

390    Mr Weatherly said that in early to mid-2014, he was involved in the decision-making process to “mothball” half the generating capacity of PPPL. At that time, he was employed as the trading originator/senior trading originator. It was his view at the time that the on-selling of PPPL’s gas transport rights, and thereby the costs associated with them, was a critical step in PPPL being able to remain commercially viable in a challenging market environment.