Australian Energy Regulator v Pelican Point Power Ltd
[2023] FCA 1110
•20 September 2023
FEDERAL COURT OF AUSTRALIA
Australian Energy Regulator v Pelican Point Power Ltd [2023] FCA 1110
File number: SAD 187 of 2019 Judgment of: BESANKO J Date of judgment: 20 September 2023 Catchwords: CONSUMER LAW — application for declarations of contraventions of National Electricity Rules (NER) pursuant to s 44AAG(1) of the Competition and Consumer Act 2010 (Cth) — where on 8 February 2017, a day Adelaide recorded a maximum temperature of 42.4 degrees Celsius, the Australian Energy Market Operator (AEMO) had to issue a direction to initiate load shedding to return the power system to a secure operating state in South Australia — where load shedding was not required in similar conditions on 9 February 2017 as AEMO was able to direct Pelican Point Power Limited (PPPL) to synchronise and dispatch GT12 — whether (PPPL) contravened cl 3.7.3(e)(2) of the NER by failing to submit its short term Projected Assessment of System Adequacy (PASA) availability for each trading interval during the 8 February 2017 trading day so as to reflect the true physical plant capability of the Pelican Point Power Station that could be made available on 24 hours’ notice — whether PPPL contravened cl 3.7.2(d)(1) of the NER by failing to submit medium term PASA (MT PASA) availability so as to reflect the true physical plant capability of the Pelican Point Power Station that could be made available on 24 hours’ notice after the gas turbine GT12 was brought from dry to wet storage on 11 November 2016 — whether 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 MT PASA availability
CONSUMER LAW — where the AER seeks the imposition of civil penalties on PPPL — where Court made an order that liability be heard separately, and in advance of, the determination of what relief should be granted
CONSUMER LAW — where the highest availability submitted by PPPL in its short term PASA (ST PASA) for the 8 February 2017 trading day was 235 MW — where PPPL’s MT PASA input for 8 February 2017 was 224 MW — consideration of two hypothetical operating scenarios a reasonable generator would have had in mind, 320 MW scenario which involves GT11 and GT12 operating concurrently for four hours and the 8 February counterfactual which involves GT11 operating as it did on 8 February 2017 and GT12 operating on 8 February 2017 as it in fact operated on 9 February 2017 — consideration of principles of statutory interpretation — consideration of proper construction of the defined term “PASA availability” in cll 3.7.2(d)(1) and 3.7.3(e)(2) of the NER — where issue as to the nature and extent of the Scheduled Generator’s obligations in submitting estimates or forecasts of MT and ST PASA — consideration of the meaning of “current intentions” and “best estimates” — consideration of how much non-firm gas PPPL could reasonably expect to have been able to obtain on 8 February 2017 on 24 hours’ notice — whether PPPL ought to have reasonably expected that it could have secured the additional gas transport required to operate GT11 on 8 February 2017 and, for four hours, GT12 — whether the physical condition of GT12 had a bearing on availability of turbines for the purpose of making PASA submissions — consideration of expert evidence — where bulk of the historical data of the AER’s expert related to January and February 2017 and not November and December 2016 — held that the AER failed to establish that the MT PASA availability of 224 MW was not a reasonable forecast at that time — held that PPPL’s ST PASA inputs submitted after 3 February 2017 at 12.14 pm contravened cl 3.7.3(e)(2)
Legislation: Acts Interpretation Act 1901 (Cth) s 15AA
Competition and Consumer Act 2010 (Cth) ss 4, 44AAG
Evidence Act 1995 (Cth) s 140
National Electricity Law ss 2, 2AA, 3, 7, 9, 15, 28, 116
National Electricity Rules (Version 88) cll 3.1.1, 3.4.3, 3.7.1, 3.7.2. 3.7.3, 3.8.1, 3.8.3, 3.8.4, 3.8.20, 3.8.22, 3.9.7, 3.13.2, 3.13.3, 3.13.4, 3.13.6A, 3.13.7, 3.15.7, 4.2.6, 4.3.1, 4.8.4, 4.8.7, 4.8.9, 4.8.15, 4.9,2, 4.9.9, 4.9.9A, 4.9.9B
National Electricity (South Australia) Act 1996 (SA) ss 6, 8
National Electricity (South Australia) Regulations, reg 6
Cases cited: Australian Competition and Consumer Commission v Yazaki Corporation [2018] FCAFC 73; (2018) 262 FCR 243
Australian Energy Regulator v Stanwell Corporation Ltd [2011] FCA 991; (2011) 197 FCR 429
Briginshaw v Briginshaw [1938] HCA 34; (1938) 60 CLR 336
Canadian Pacific Tobacco Co Ltd v Stapleton [1952] HCA 32; (1952) 86 CLR 1
Certain Lloyd’s Underwriters v Cross [2012] HCA 56; (2012) 248 CLR 378
CIC Insurance Ltd v Bankstown Football Club Ltd [1997] HCA 2; (1997) 187 CLR 384
Commissioner of Stamps (SA) v Telegraph Investment Co Pty Ltd [1995] HCA 44; (1995) 184 CLR 453
Commonwealth v Sterling Nicholas Duty Free Pty Ltd (1972) 126 CLR 297
Construction, Forestry, Maritime, Mining and Energy Union v Australian Building and Construction Commissioner (Bay Street Appeal) [2020] FCAFC 192; (2020) 282 FCR 1
Gill v Donald Humberstone & Co Ltd [1963] 1 WLR 929
Grajewski v Director of Public Prosecutions (NSW) [2017] NSWCCA 251; (2017) 270 A Crim R 33
Healthcare at Home Ltd v Common Services Agency [2014] UKSC 49
HFM043 v Republic of Nauru [2018] HCA 37; (2018) 359 ALR 176
Melbourne City Council v Telstra Corporation Limited [2020] FCAFC 200; (2020) 281 FCR 379
Mills v Meeking [1990] HCA 6; (1990) 169 CLR 214
Minister for Immigration and Border Protection v SZVFW [2018] HCA 30; (2018) 264 CLR 541
Minister for Immigration and Citizenship v Li [2013] HCA 18; (2013) 249 CLR 332
Morley v Australian Securities and Investments Commission [2010] NSWCA 331; (2010) 247 FLR 140
Neat Holdings Pty Ltd v Karajan Holdings Pty Ltd [1992] HCA 66; (1992) 110 ALR 449; (1992) 67 ALJR 170
R v A2 [2019] HCA 35; (2019) 269 CLR 507
Taylor v Owners – Strata Plan No 11564 [2014] HCA 9; (2014) 253 CLR 531
Trade Practices Commission v TNT Management Pty Ltd (1985) 6 FCR 1
Wentworth Securities Ltd v Jones [1980] AC 74
Division: General Division Registry: South Australia National Practice Area: Commercial and Corporations Sub-area: Economic Regulator, Competition and Access Number of paragraphs: 681 Dates of hearing: 19-23 April 2021, 13-17, 20, 28 & 29 September 2021 Date of last submissions: 1 October 2021 Counsel for the Applicant: Mr A McClelland KC with Mr T Clarke and Mr M Peckham Solicitor for the Applicant: Australian Government Solicitor Counsel for the Respondent: Mr M Hoffmann KC with Mr B Doyle KC and Mr L Wicks Solicitor for the Respondent: King & Wood Mallesons ORDERS
SAD 187 of 2019 BETWEEN: AUSTRALIAN ENERGY REGULATOR
Applicant
AND: PELICAN POINT POWER LTD (ARBN 086 411 814)
Respondent
ORDER MADE BY:
BESANKO J
DATE OF ORDER:
20 SEPTEMBER 2023
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
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.
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.
Secondly, the AER seeks a declaration that in relation to PPPL’s medium term PASA submissions for the day 8 February 2017, PPPL contravened cl 3.7.2(d)(1) of the NER in relation to each of its 10 medium term PASA submissions made after 11 November 2016, by failing to submit medium term PASA availability so as to reflect the physical plant capability of the Pelican Point PS that could be made available on 24 hours’ notice after the gas turbine known as GT12 was brought from dry to wet storage on 11 November 2016.
Thirdly, the AER seeks further, or in the alternative to the second declaration, a declaration that PPPL contravened cl 3.13.2(h) of the NER by failing to notify AEMO promptly on or after 11 November 2016 of the increased medium term PASA availability of the Pelican Point PS after GT12 was brought from dry to wet storage on 11 November 2016. On the AER’s case, that contravention continued for a period of in the order of 86 days.
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.
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.
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.
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.
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
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.
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.
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.)
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.
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”.
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.
In its Concise Response, PPPL admits the description of the gas and steam turbines and the nameplate capacity of the Pelican Point PS.
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.
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.
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).
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).
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.
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.
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)).
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.
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)).
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.
A Scheduled Generator must notify AEMO of any changes to submitted information as changes occur (cl 3.13.2(h) and the timetable).
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.
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.
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”.
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.
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.
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.
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.
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.
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.
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.
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.
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”.
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.
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.
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.
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.
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.
At 18.01, PPPL advised AEMO that GT12 could be made available, if necessary, within one hour.
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.
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.
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.
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.
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.
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.
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.
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.
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
The following facts are taken from the Statement of Agreed Facts signed by both parties.
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 country 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.
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’”.
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.
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.
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).
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”.
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.
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.
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.
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:
Date of Submission PASA availability (MW) weekly energy constraints 7/11/2016 224 999999 16/11/2016 224 999999 22/11/2016 224 999999 3/12/2016 224 999999 13/12/2016 224 999999 19/12/2016 224 999999 26/12/2016 224 999999 2/01/2017 224 999999 11/01/2017 224 999999 23/01/2017 224 999999 27/01/2017 224 999999
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.
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
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.
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.
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.
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.
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
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.
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.
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.
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.
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
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?
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
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.
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].
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.
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.
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.
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.
Clause 41 of Schedule 2 provides that the Schedule applies to the Rules notwithstanding that the provision refers to this Law.
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.
The AER seeks to rely on extrinsic material in support of its interpretation of the Rules.
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.
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.
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.
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.
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.
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.
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.
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.
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.)
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.
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.
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.
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:
ŸClarifying 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.
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.
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.
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.
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”.
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.
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.
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”.
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.
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.
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.
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.
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]).
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.)
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.
I consider that for a period prior to 8 February 2017, PPPL ought to have reasonably expected that it could have secured the additional gas transport required to operate GT11 on 8 February 2017 and, for hour hours, GT12, namely, 3.23TJ. As I will explain later in these reasons, that period commenced upon the issuing of Revision 1 of the Scheduled Quantities Report for 8 February 2017. PPPL was clearly able to secure substantial interruptible capacity on the PCA pipeline in the period leading up to 8 February 2017. PPPL’s heavy reliance on interruptible capacity in the course of its ordinary business operations reflects its confidence in its availability. Relatively speaking, the amount of additional gas transport required is not large.
In my opinion, the substantial quantities of interruptible capacity obtained by PPPL and its reliance on it in the ordinary course of its business and its obvious confidence in obtaining it meant that there was a sound and reasonable basis for it to conclude that those circumstances would continue and that the relatively small amount of additional capacity could be secured without difficulty. The possibility of late changes under the nomination and renomination provisions under the PCA Contract did not prevent a reasonable expectation arising of the additional gas transport being secured.
The AER has made out its case concerning gas and gas transport irrespective of the circumstance that PPPL was able to obtain sufficient gas and gas transport to run GT11 and GT12 concurrently for four hours on 9 February 2017. Nevertheless, I make the following observations on the suggestion that the events on 9 February 2017 and PPPL’s answers to questions 19 and 23 of the Section 28 Notice are irrelevant to the issues in this case because they occurred, or were framed, by reference to AEMO giving a direction or indicating that it would give a direction. Mr Weatherly’s evidence is important in this respect. I can readily accept that an AEMO direction or an indication by it that one was to be given, would add a sense of urgency and likely additional effort to sourcing additional gas and gas transport. I can readily accept that a well-established commercial counterparty may be prepared to take the fact of an AEMO direction or an indication that one was to be given into account in the negotiations for the supply of gas or gas transport. The difficulty in excluding the events of 9 February 2017 and the answers to questions 19 and 23 from being at least factors to be considered, is that there is no evidence of the latter, that is, of a commercial transaction being affected by an AEMO direction or an indication that one would be given.
I do not consider that there is any basis for concluding that the problem with the Torrens A1 generating unit (AGL) explains the unused capacity in the PCA pipeline. Not only is there an absence of clear evidence on this point, but in addition, the pattern of PPPL’s substantial use of interruptible capacity and the evidence of the unused capacity on the PCA pipeline predates 6 February 2017 which was when the Torrens Island unit was withdrawn from service. Furthermore, the withdrawal from service of the unit at Torrens Island was the subject of a question in the Section 28 Notice (question 37) and PPPL’s answer does not suggest that the event had any bearing on PPPL’s access to unutilised capacity on the PCA pipeline.
As to the criticisms of Mr Snow’s reliance on daily figures for the capacity of the PCA pipeline rather than hourly figures which were not established on the evidence, I accept that matters such as pressure and temperature are likely to affect capacity over the course of a 24 hour period, although the precise way in which this occurs was not explained in the evidence. Nevertheless, the evidence of substantial unused capacity in the PCA pipeline is very strong and I do not consider that the absence of hourly figures is significant. Nor does the anecdotal evidence of Mr Weatherly about being told on occasions that the pipeline was at or near capacity persuade me otherwise.
It is true that Mr Snow said, among other things, in answer to a question about 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, that the question was too speculative to answer categorically. He also said non-firm gas supply by its very definition was speculative to start with. However, those comments must be read in the context of the whole of his evidence, not only in the joint experts’ report, but also in his reports. When that is done, it is clear that he was expressing the view that PPPL ought reasonably to have expected that it would have sufficient gas and gas transport to operate GT11 and GT12 on 8 February 2017 in accordance with the 8 February counterfactual.
In my opinion, subject to the next matter to be addressed, PPPL ought reasonably to have expected to have sufficient gas transport to operate in accordance with the 8 February counterfactual from (for reasons I will explain) the issuing of Revision 1 of the Scheduled Quantities Report for 8 February 2017. The history of PPPL obtaining substantial quantities of interruptible transport is sufficient to sustain that conclusion. The ability to interrupt Santos to the extent of 30TJ/d subject to restrictions would add confidence to that expectation, not necessarily in terms of particular days and figures, but in terms of knowing there were substantial reserves of gas transport if needed. Santos was not interrupted on 8 February 2017, but it was interrupted on 9 February 2017.
The relevance of the hourly (MHQ) and 12 hourly (M12HQ) constraints in the PCA Contract
The PCA Contract contains constraints on the quantity of gas which can be taken out of the pipeline at a nominated delivery point each hour and each 12 hour period calculated on a rolling basis. If one turbine is being run, a certain quantity of gas is required as fuel for that turbine at any particular point in time and a greater quantity of fuel is required to run two turbines. PPPL contends that two turbines could not be run concurrently without exceeding these constraints or, at least, the M12HQ. In those circumstances, a PASA submission based on two turbines running concurrently would not be a reasonable estimate or a best estimate. Put another way, and in a way which reflects the fact that it is for the AER to make out its case, a PASA submission which took account of these constraints would not fail to meet the standard of reasonableness or of being a best estimate.
The MHQ and M12HQ constraints are set out in Annexure 10 (Co-ordination of Services) of the PCA Contract. The MHQ is addressed in cl 15 and the M12HQ is addressed in cl 17. The quantity in each case is determined by the application of a formula.
In the case of the MHQ, the quantity comprises, relevantly for this case, 5% of the Firm Service MDQ plus 5% of the Scheduled Interruptible Capacity plus an Allowable Overrun Entitlement for that hour of 1TJ.
In the case of the M12HQ, the quantity is calculated on a 12 hour rolling basis and comprises 4.7% of Firm Service M12HQ plus 4.7% of Interruptible Service M12HQ.
I turn now to the circumstances in which the MHQ and M12HQ constraints were an issue in the case. Although the need to secure sufficient gas transport was referred to in the conversations between PPPL’s energy traders and AEMO representatives on 8 and 9 February 2017 and is referred to in PPPL’s response to the Section 28 Notice, no mention is made of the MHQ and M12HQ constraints in the PCA Contract being a problem or a relevant issue. The constraints were not expressly raised by PPPL as being an issue in its Concise Response or in the Joint List of Issues and Evidence.
The constraints were first raised as an issue by PPPL in Mr O’Farrell’s first expert’s report. He addressed the matter at some length in sections 8 and 9 of that report. He concluded that on his assumptions the M12HQ constraint would be breached if the two turbines were run concurrently “(1.84 TJ/hour or rights vs 2.656TJ/hour required for GT 11 and 12)” and said his analysis made it clear that the Firm M12HQ rights were insufficient to transport any additional gas to support a minimum run of GT12 of four hours. Mr O’Farrell’s operating assumptions were quite different from the 8 February counterfactual. His modelling was based on GT11 and GT12 operating for four hours at 320 MW and then GT11 operating by itself for the other 20 hours at 240 MW, whereas the 8 February counterfactual had GT11 operating as in fact it did on 8 February 2017, namely, at around 220 MW between 8.00 am and 10.00 pm before reducing to around 150 MW from midnight to 6.00 am.
Two aspects of Mr O’Farrell’s approach should be noted. Their relevance will be noted later in these reasons. First, in calculating the quantity of the constraints, Mr O’Farrell made no allowance for Scheduled Interruptible Capacity or Interruptible Service. Secondly, in deducting amounts to arrive at PPPL’s entitlement, Mr O’Farrell made no deduction in relation to the Santos interruptible rights to 30TJ/d.
In the first round of PPPL’s evidence of which Mr O’Farrell’s first report was a part, neither Mr Foulds in his affidavit nor Mr Weatherly in his (first) affidavit addressed the MHQ or M12HQ constraints.
The matter was referred to in the joint experts’ report. Mr Snow referred to Mr O’Farrell’s modelling and said that it shows that PPPL could not meet PASA as it would have overrun its PCA Firm Capacity rights for 12 hours due to the M12HQ on the PCA pipeline and, therefore, in Mr Snow’s opinion, the model output numbers used by Mr O’Farrell indicated the need to explore further GT11’s PASA capacity. The joint experts’ report then records the following:
Both Mr Snow and Mr O’Farrell agree that there is missing information on why PPPL was bidding 224 to 235 MW into the PASA if the findings in Mr O’Farrell’s modelling and his 12 hour constraint and other gas supply sourcing arguments are correct. For example, what did they do with Santos sub-haulage rights on the PCA? How did PPPL then manage 9 February 2017? If the assumptions are not correct, then there is no issue with the perceived constraint (or other simple and reliable solutions).
It will be recalled that in PPPL’s second round of evidence, Mr Weatherly in his second affidavit addressed how it was that PPPL was able run GT12 for four hours on 9 February 2017 with GT11. He said that in addressing that issue on 8 February 2017, one of the matters he had to consider was to find a way in running two turbines of achieving MHQ and M12HQ allowances under the PCA Contract high enough to transport enough gas through the pipeline during peak generating periods.
Mr Weatherly said PPPL nominated for a significant volume of interruptible transport on the PCA pipeline on 9 February 2017 and the amount it nominated for was more TJs of non-firm gas secured for that period. It nominated the receipt and delivery of more gas than it was proposing to receipt and deliver from the pipeline. This had the effect of increasing PPPL’s allocation of MHQ and M12HQ throughout the day because the allowance for hourly figures was based on a formula for daily nominations. PPPL over-nominated for this reason. In other words, it nominated the receipt and delivery of more gas than it was proposing to receipt onto the pipeline and deliver from the pipeline in order to increase its allocation of MHQ and M12HQ throughout the day.
Mr Weatherly said that the approach of over-nomination involved risks. He said that there was a real risk, particularly on a day of high demand, that PPPL’s transport rights would be curtailed. If PPPPL was taking more gas from the pipeline during a peak period than it supplied to the pipeline, the pipeline pressure would drop and, in the ordinary case, SEAGas would curtail PPPL’s gas transport rights or request PPPL to reduce its nomination to address the problem. This would leave PPPL being unable to rely on such uninterruptible transport.
I turn now to some further evidence given by Mr Snow and Mr O’Farrell. Mr Snow did not analyse the 12-hourly constraints in his first report. Mr Snow agreed in cross-examination that in analysing PPPL’s rights to gas transport on the PCA pipeline, hourly and 12-hourly constraints were also very material (i.e., in addition to gross amounts). He agreed with the proposition that one needs to look at the issue “through the prism of what can come out the other end, go in one end, out the other end, limited by hourlies overlayed with 12-hourly constraints”.
As I have previously said, there were a number of Scheduled Quantities Reports for 8 February 2017 prepared by SEAGas and tendered in evidence. The AER prepared a summary of these reports and annexed it to its closing written submissions as Appendix C (the AER’s Appendix C). It is Annexure 2 to these reasons. It is not suggested by PPPL that it is not accurate so far as it goes.
Mr O’Farrell was tested in cross-examination on his evidence about the effect of the MDQ and M12HQ constraints. He was taken to Revision 1 of the Scheduled Quantities Report issued on 3 February 2017 at 3.14 pm. He agreed that the Delivery MDQ of 4.750 was a combination of 2.958 (5% of 59.163) plus 0.792 (5% of 15.837) plus 1, a deduction for the 20TJ/d Firm Haulage Capacity for Santos (which was the only deduction he made in his modelling) results in a figure of 3.88TJ/hr. This figure is more than sufficient to meet the required MHQ for GT11 and GT12 to run concurrently of 2.66TJ/hr.
A similar analysis was performed in relation to the M12HQ where a total of 3.525TJ is reached and after a deduction for the Firm Haulage Capacity of Santos, a figure of 2.605. This figure is sufficient to meet the required flow on Mr O’Farrell’s scenario of eight hours at 240 MW and four hours at 320 MW of 2.22TJ/hr.
The same analysis performed in relation to Revisions 3 and 5 results in a figure which would mean that there would be no breach of the M12HQ constraint. Once Interruptible Service is taken into account, there is no problem with M12HQ.
These figures certainly support a conclusion that the MHQ and M12HQ constraints do not present a barrier to the operation of two turbines concurrently.
PPPL submitted that the hourly constraints are even more significant in the context of a contract under which other parties may renominate their firm entitlements at short notice. That was because in order to run two gas turbines, PPPL needed the extra capacity at the particular time of day when the two gas turbines were running, that is, the period of peak demand. PPPL submitted that insofar as the capacity was interruptible, it was a lower priority than a firm rights holder’s capacity and could be interrupted.
PPPL points to the fact that although the PCA pipeline is an hourly pipeline, as Mr Weatherly put it, Mr Snow did not address the hourly constraints on the PCA pipeline and said that he considered that they were “reasonably irrelevant”. Mr Snow did not conduct an analysis which considered the hourly utilisation on the pipeline and PPPL submitted that his opinion that the hourly constraints were not relevant should accordingly be given no weight.
The AER submitted that Mr O’Farrell’s analysis is wrong, but in any event, it was important that his level of detailed contractual analysis was kept in its proper perspective. The AER submitted that the error which Mr O’Farrell made in his reports was to assume that interruptible capacity could never be scheduled and, therefore, he assumed that MHQ and M12HQ should only ever be calculated by reference to PPPL’s firm service. The AER submitted that the invoices to which Mr O’Farrell was referred clearly demonstrated that PPPL was using substantial quantities of interruptible capacity on a daily basis in January and February 2017 and there was always going to be sufficient transport to enable MHQ and M12HQ restriction to be reached.
The AER submitted that, in the circumstances, Mr O’Farrell’s evidence about the impossibility of running two turbines having regard to the MHQ or M12HQ restrictions was obviously wrong and finds no support in the evidence of the witnesses called by PPPL. The AER also submitted that having regard to the Scheduled Delivery Reports, even if the quantity restrictions were real restrictions, PPPL would have known that there was no impediment to it running two turbines from at least 3 February 2017. The AER submitted that having regard to the substantial quantities of interruptible supply that would have been utilised by PPPL in the preceding two weeks, it would have known that there was no practical impediment by reference to those restrictions for a two week period before the six day short term PASA availability submission window.
PPPL submitted that there was no clear evidence as to how often precisely it had adopted the practice of over-nomination. That would seem to be correct. It is true, as PPPL submitted, that the Pelican Point PS was rarely dispatched according to its full PASA availability and that there was no analysis performed by Mr Snow of its generation profile and any “over-nomination” on any days on which it was so dispatched prior to 8 February 2017.
None of Mr Farrell’s analysis about MHQ and M12HQ was referred to by the PPPL witnesses, including Mr Weatherly. In addition, Mr Weatherly’s evidence about PPPL’s practice of over-nominating transport on the PCA pipeline “renders much of Mr O’Farrell’s analysis redundant”. The AER submitted that the practice of over-nomination explains why none of PPPL’s lay witnesses referred to the MHQ or M12HQ constraints as being relevant to the question of whether PPPL could run two turbines and nor was the topic mentioned by PPPL’s gas traders to AEMO in the transcripts of conversations on 8 and 9 February 2017 which are in evidence. Nor were these constraints mentioned in PPPL’s response to the Section 28 Notice. The practice of over-nomination was not an extraordinary practice that only occurred on 9 February 2017. Mr Weatherly accepted that it was PPPL’s practice to over-nominate transport over the summer of 2016/2017.
PPPL submitted that over-nomination was in breach of the PCA Contract. It referred to cl 5.11 which was a warranty by it in performing its obligations under the agreement it would, at all times, act reasonably and prudently. It referred to the significant liability that it may incur for breach of the PCA Contract.
As PPPL submitted, cll 19 and 20 in Annexure 10 gave SEAGas the power to interrupt or curtail receipts and deliveries in the event of PPPL breaching its daily and hourly limits if the breach would prevent SEAGas meeting its obligations to other Shippers or would place a material threat to the safety or operational integrity of the Pipeline System.
PPPL submitted that the practice of over-nomination was unsustainable in material amounts and could not be relied upon when projecting generation capacity. It relies on Mr O’Farrell’s evidence that the practice was unsustainable because it would affect the rights of other Shippers and the traders employed by those Shippers would pick it up. Mr O’Farrell gave the following evidence:
If they over-nominate, that means that they’re actually going to be taking my gas that I’m trying to deliver, and my traders are actually instructed to actually monitor each hour. … you would be exposing your company to an extinction event, which is what I would describe as unlimited liability, which I would be shocked if somebody did.
PPPL submits that it would be, to use its word, “perverse” for a regulator to be contending that PPPL should make a submission as to what it can do on the assumption that it will over-nominate and exceed its contractual rights.
Mr Snow dealt with PPPL’s practice of over-nominating scheduled flows to overcome M12HQ limitations in his second report and the relevant comparisons between receipts and deliveries of gas are shown in Figure 1 of that report. It is clear from Mr Snow’s report that over-nomination was a regular practice of PPPL between, for example, 1 and 11 February 2017. The facts shown in Figure 1 were not challenged in cross-examination. Mr Weatherly raised one matter which might be an impediment to PPPL’s practice of over-nomination and that was the possibility that PPPL’s supplies of gas might be curtailed if pressure on the pipeline dropped as a consequence of the over-nomination. The fact is that this was a small risk given the additional flow required for a second turbine to be operated and Mr Weatherly could not recall any occasion in 2016/2017 when SEAGas had refused a nomination by PPPL or interrupted scheduled interruptible capacity. Mr O’Farrell’s opinion that over-nomination was not permitted by the SEAGas contract must be read in this light. That proposition was not put to Mr Snow and was not advanced by Mr Weatherly. Mr Weatherly did not suggest that SEAGas opposed the practice of over-nominating and I agree with the AER that the inference should be drawn that this was an accepted business practice that SEAGas was prepared to accept in circumstances where there was always substantial unused capacity on the PCA pipeline. There is a dispute about Mr Weatherly’s evidence on this point. The AER submitted that Mr Weatherly said that the practice of over-nomination carried a risk, particularly on a high demand day, that PPPL’s transport rights would be swiftly curtailed. However, he did not say that it was unsustainable and that SEAGas would put a stop to it when it was detected.
That leaves for consideration PPPL’s own version of Appendix C which it handed up in its closing submissions (PPPL’s Appendix C). It differs from the AER’s Appendix C in a number of ways. It is Annexure 3 to these reasons.
PPPL’s Appendix C includes Revision 2 of the weekly schedule issued on 6 February 2017 at 3.14 pm. It includes figures purporting to show MDQ, MHQ and M12HQ remaining if one subtracts from the quantities shown in the Scheduled Quantities Report, the 20TJ/d Santos Firm Haulage Capacity and the 30TJ/d Santos Interruptible Firm Entitlements and the 1TJ/hr Hourly Allowance Overrun Entitlement from Hourly Entitlements in relation to Delivery MHQ.
As I have said, Mr O’Farrell’s calculations did not include the allowance on Scheduled Interruptible Capacity in the case of MHQ or Interruptible Service M12HQ in the case of that restriction. Further, Mr O’Farrell’s analysis deducts an allowance in relation to the 20TJ/d Santos Firm Haulage Capacity, but unlike PPPL’s Appendix C, does not deduct an allowance for the 30TJ/d Santos Interruptible Firm Entitlements or the Hourly Allowable Overrun Entitlement.
The AER submitted that insofar as PPPL sought to go beyond the evidence of its own expert and rely on its version of Appendix C, that does not assist PPPL for two reasons. First, there should be no deduction for the 30TJ/d Santos Interruptible Firm Entitlements. Secondly, the interruptible quantities shown in the Scheduled Quantities Report is not a cap on interruptible transport and PPPL could nominate, and had a practice of over-nominating, to avoid MHQ and M12HQ constraints becoming a problem. I agree that both of those reasons provide the answer to PPPL’s submissions.
Mr Weatherly said that PPPL had not interrupted Santos Interruptible Firm Haulage on 5, 6, 7 and 8 February 2017, but did do so on 9 February 2017. Part of the reason Mr Weatherly was not concerned about PPPL’s low firm haulage rights in the summer of 2016/2017 was that PPPL could always interrupt the Santos 30TJ/d. In the same way, that could be done where MHQ or M12HQ were looming as a problem.
Another way of avoiding any problem with MHQ or M12HQ constraints was for PPPL to nominate for more transport and it had a practice of over-nominating in order to avoid those restrictions affecting its existing method of operating the Pelican Point PS which involved the running of only one turbine at any one time. As the AER put it, there was no cap on the practice of nomination.
In conclusion, I do not consider the MHQ and M12HQ constraints to be obstacles to running GT11 and GT12 concurrently. On Mr O’Farrell’s approach, there was no risk of infringing the M12HQ constraint once the Interruptible Service was taken into account. Insofar as the existing business operations of PPPL and the scenario of two turbines operating concurrently depended on the practice of over-nomination, that was an accepted business practice of PPPL. Finally, the matters PPPL sought to raise by its version of Appendix C are answered by the AER’s two submissions referred to above.
MAPS
Gas could be transported to the Pelican Point PS on the MAPS or the PCA pipeline. PPPL had rights under the MAPS Contract to 25TJ/d of bio-directional gas transportation on the MAPS from and to receipt points, including Pelican Point PS, Dry Creek, Mintaro and Adelaide Metro.
The relevant contractual constraints are contained in cll 3 and 4 in the Second Schedule of the MAPS Contract. Those constraints include maximum Firm Service MHQ, maximum Synergen Peaking Service and maximum in any 12 hour period of Firm Service MHQ.
Gas was transported from the PCA pipeline onto the MAPS pursuant to the SEAGas-MAPS Interconnect Capacity Firming Agreement.
PPPL did not have any contracts for the supply of gas from producers receipting gas onto the MAPS and the only way for PPPL to get gas on the MAPS was via the PCA pipeline by PPPL drawing down on its transport rights and gas supplies from sources that could otherwise have been used to power the Pelican Point PS.
I have previously referred to the obligations PPPL claimed it had under internal agreements with Synergen Power and Simply Energy respectively.
The Synergen Power peaking power stations at Dry Creek and Mintaro consumed a total of 3.7TJ/hr (Snow) or 2.9–3.8TJ/hr (O’Farrell).
PPPL and its related companies could not run all three power stations together based on the transport rights on the MAPS. That was the view of both Mr Snow and Mr O’Farrell.
Mr Snow’s theory was that PPPL could simply take 3.23TJ for the Pelican Point PS otherwise directed for Synergen Power via MAPS (the gas actually used at the Mintaro PS on 8 February 2017 was 8.32TJ and at the Dry Creek PS was 9.871TJ) is incorrect because PPPL was contractually bound to deliver gas transportation rights to Synergen Power of 3.7TJ/hr and one could not do that and deliver 2.4TJ/hr to the Pelican Point PS delivery point in order for PPPL to operate its two gas turbines simultaneously for at least four hours. Mr Snow accepted that the contractual arrangements between PPPL and Synergen Power and Simply Energy were commercially appropriate and nothing in the NER required PPPL to ignore the contracts it had entered into.
However, the AER’s submission in closing was that PPPL could divert 3.23TJ to the Pelican Point PS and Synergen Power could obtain that amount by way of linepack in the MAPS. That would appear to be a viable source of the additional gas having regard to the significant amount of linepack available to PPPL on the MAPS. Linepack can vary sharply and I would be disposed to treat this as an additional reason for the conclusions reached earlier in relation to the PCA Contract, rather than a true alternative source.
The Physical Condition of GT12
The evidence of Mr Baksi is set out above (at [358]–[384]). As I have said, I accept that he was honest in giving his evidence, although I had difficulty accepting his evidence in para 38 of his affidavit. Mr Foulds also gave evidence about the physical condition of GT12 and PPPL’s approach to its use.
The AER said the focus is the maximum generating capacity that PPPL could make available, not what was reasonable for it to make available. This proposition is subject to the qualification that it would not apply if the use of any particular item of equipment is such that it would pose a hazard to public safety if it was used. The AER submitted that it is plain from the evidence of Mr Baksi that the relevant decision-makers at PPPL did not consider that GT12 could not be made available because to do so would be to pose a safety risk. The AER submitted that the reason two turbines were not used concurrently was not because of the condition of GT12, but rather because if the operating turbine suffered a fault, there would be a backup turbine. Mr Baksi agreed with the proposition that the risk was mitigated by bringing GT12 back from dry storage so that it was available to be returned to service in a matter of hours should a fault occur with GT11. The presence of the backup capability was commercially important regardless of whether GT11 or GT12 was being run as the primary turbine. If both turbines were running together, then this backup capability was not present. In the course of his cross-examination, Mr Baksi agreed that it was a very difficult decision on his part to agree to the operation of GT12 when GT11 was also operating. That was because PPPL would be running both turbines and he was nervous that there would not be any backup if something happened to the machine. He agreed that that was the key risk which he had in his mind.
The presence of a crack in the blade was a matter that the manufacturer (Alstom) had reviewed and it had reported the turbine blade was in an acceptable condition. PPPL was managing that crack by regular visible inspections. Furthermore, the existence of the crack did not prevent PPPL from running GT12 over the summer of 2016/2017.
The evidence is that GT12 was run in conjunction with GT11 on a number of occasions during the summer of 2013/2014 and during the summer of 2014/2015. The evidence is that GT12 was run as the primary gas turbine from mid-November 2016 to mid-January 2017. The evidence was that GT12 was run on 7 February 2017, on 9 February 2017 and later, together with GT11, it was run “hard” over a series of four consecutive days at the end of March 2017. Mr Baksi agreed that the risks were low provided the crack did not progress and whether the crack had progressed could be monitored by undertaking borescope inspections. These inspections were being done after every five starts. He referred to the risks associated with the next start after a five start inspection and that if anything is going to happen, it will happen then. He said that nobody could say whether something is going to happen. The AER referred to PPPL’s reliance on Mr Baksi’s evidence that if someone had asked him one or two months prior to January 2017 whether GT12 could run for 2,000 hours he would have said that he did not know because it would be subjected to the runs and consecutive inspections as well as the preservation methodology which had been discussed, and pointed in response to the evidence of Mr Baksi to the effect that from 11 November 2016 through to the end of December 2016, GT12 was operated as the primary unit more commonly and GT11 was used less. Mr Baksi agreed with the proposition that in making the decision to operate GT12 more than GT11 in November and December 2016, the motivation was because there was some commercial advantage to be gained by ENGIE in trying to reduce the use of GT11 so that the time before GT11’s next C‑inspection could be extended.
Mr Baksi said that as at 9 February 2017, GT12 had 500 to 600 EOH remaining. This was the arbitrary 30,000 equivalent operating hour deadline PPPL had set for itself for having a C‑inspection. In the circumstances, the suggestion that it was mere speculation as to how many hours GT12 had left should be rejected. Mr Baksi certainly would have known in the weeks before 8 February 2017 that as at 9 February 2017, GT12 would have some hundreds of hours left.
The AER submitted that the cracked blade in the turbine had no bearing on whether the physical plant capability of GT12 could be made available. The real reason for not operating the two turbines together may have been sensible from a commercial perspective, but it did not mean that PPPL was not able to make two turbines available to operate simultaneously. Nothing was said by PPPL to the effect that it did not want to operate two turbines simultaneously because of a safety hazard or because it would lose the backup capacity that Mr Baksi referred to.
The C-inspection of GT12 was undertaken in April 2017. GT12 and GT11 were run together on 28 to 31 March 2017 inclusive with a maximum output of at least 450 MW on each day.
As I understand it, the way in which PPPL submits that the physical condition of GT12 is relevant is that it is said that the reasonable person poised to make PASA submissions would take the physical condition of GT12 into account as a “further contingency”. As I understand it, this is an assertion that there were a number of matters relevant to the issue of availability of two turbines to run on 8 February 2017 and the physical condition of GT12 was one of them and it pointed against availability. I reject this submission. It is not supported by the evidence and is, in fact, contradicted by the following circumstances.
First, GT12 was the primary operating turbine in November, December 2016 and the first half of January 2017. The decision in mid-January 2017 to make GT11 the primary operating turbine is to be seen in the context of PPPL’s intention to run only one turbine at a time and the fact that GT11 had had a more recent C-inspection during which superior blades were fitted and GT12 was approaching a required C-inspection. Secondly, Mr Baksi’s nervousness about running two turbines at the same time was based on the risk of not having backup capacity. Thirdly, any difficulty involved in making long-range forecasts concerning GT12 is answered by the fact that there is an ability to change or revise forecasts where there is a change in circumstances, indeed an obligation to do so. Fourthly, GT12 was run for between 14–16 hours on 7 February 2017 and for four hours on 9 February 2017 with no suggestion on the latter date that AEMO’s direction meant that GT12 could not be run because the case fell within cl 4.8.9(c) of the NER. It was run “hard” in late March 2017. Finally, PPPL in its response to the Section 28 Notice did not suggest the physical condition of GT12 was an obstacle to running GT12 on 8 February 2017. The matters referred to were the availability of gas and gas transport.
CONCLUSIONS
For the reasons I have given, I do not consider that PPPL was required to assess and determine its PASA submissions by reference to the basic 320 MW scenario. PPPL’s liability for contraventions is to be determined by reference to the 8 February counterfactual.
The MT PASA covers the 24 month period commencing from the Sunday after the day of publication with a daily resolution (cl 3.7.2(a)). The Scheduled Generator’s obligation is to submit ST PASA inputs, including PASA availability, in accordance with the timetable (cl 3.7.2(d)). The timetable is defined as the timetable published by AEMO under cl 3.4.3 for the operation of the spot market and the provision of market information. As far as MT PASA inputs, including PASA availability are concerned, the relief sought by the AER relates to 10 MT PASA submissions made after 11 November 2016. The 10 submissions are identified in the Statement of Agreed Facts and range in dates from 16 November 2016 to 27 January 2017.
The ST PASA must be published at least daily by AEMO in accordance with the timetable and it covers the period of six trading days from the end of the trading day covered by the most recently published pre-dispatch schedule with a trading interval resolution (cl 3.7.3(a) and (b)). The relief sought by the AER relates to 27 ST PASA submissions made in or from 30 January 2017 for each trading interval during the 8 February 2017 trading day. The dates of PPPL’s submissions of its ST PASA inputs for the Pelican Point PS for the 8 February 2017 trading day are identified in the Statement of Agreed Facts as 15 January at 9.52; 30 January at 9.10, 2 February at 6.44 and 9.11; 6 February at 11.00; 7 February at 9.56, 11.22, 11.25, 16.56, 17.00; and 8 February at 6.58, 10.12, 11.14, 12.43, 13.53, 15.22, 15.45, 16.42, 17.17, 17.33, 18.03, 18.23, 18.40, 18.57, 19.08, 19.26, 19.47 and 20.51.
There were and still are a number of disputes between the parties about the number of contraventions by PPPL should the AER otherwise establish its case. Some have been resolved. For example, the AER no longer presses a case that PPPL committed a contravention of cl 3.7.3(e)(2) by its PASA submissions made on 15 January 2017 and does not contend that with respect to ST PASA submissions made on 8 February 2017, there are contraventions in relation to trading intervals that had already passed. Other disputes appear to remain and are identified in a helpful document attached to PPPL’s closing written submissions.
There would appear to be a dispute about the period “covered” by the ST PASA (cl 3.7.3(b) uses the word, “covers”). Mr Sanders said in his evidence that he would expect that for 8 February 2017, to “enter short-term PASA about seven days beforehand”. PPPL contends that the period or “ST PASA window” commenced either at 4 am on 4 February 2017 or 4 am on 3 February 2017 and that, on either view, the submissions made on 15 January 2017, 30 January 2017 and at 6.44 on 2 February 2017 could not be contraventions of cl 3.7.3(e)(2).
I do not need to resolve this dispute because, for the reasons which follow, I consider that there were no contraventions by PPPL prior to 3 February 2017 at 12.14 pm. It is only in relation to ST PASA submissions after that date and time that there can be contraventions. As I would read the Statement of Agreed Facts, the next ST PASA submission after 3 February 2017 at 12.14 pm was made on 6 February 2017 at 11.00. The significance of the date and time of 3 February 2017 at 12.14 pm is that that is when Revision 1 of the Scheduled Quantities Report was issued by SEAGas.
The last of the relevant MT PASA submissions by PPPL was made on 27 January 2017. The AER has failed to establish that a PASA availability of 224 MW was not a reasonable forecast at that time. The AER’s case is heavily reliant on the evidence of Mr Snow and the documents. A notable feature of Mr Snow’s evidence-in-chief was his reliance on events that took place in January and February 2017. That is not to say that all of his graphs and figures related to that period and some did reach back to 11 November 2016. However, the bulk of his historical data related to the January and February 2017 period. The other notable feature of Mr Snow’s evidence is that an aspect of his reasoning was to consider what could have been achieved on a particular day and then to consider what might have been reasonably expected prior to that day. Whilst I do not agree with PPPL’s criticism of Mr Snow’s approach, it does not mean that there is not an issue as to how far back it is appropriate to go in terms of inferring similar circumstances based on the bulk of the historical evidence. It is, in essence, a question of proof and, with respect to Mr Snow, it is not enough in my opinion, to establish contraventions of civil penalty provisions to say that the position was likely to be the same in the past because he had not seen any significant contractual changes that took place in that period. The AER submitted that if the Court was concerned about the lack of data for November and December 2016, the Court could, in effect, be satisfied of the position by mid-January 2017. I do not accept that submission.
In my opinion, the central issue in this case on the evidence is the availability of gas transport. By early February 2017, it ought to have been clear to PPPL that it could reasonably expect to obtain sufficient gas transport to operate GT11 and GT12 on 8 February 2017 in accordance with the 8 February counterfactual.
It is difficult to fix the precise point in time at which PPPL ought to have had the reasonable expectation that gas and gas transport would be available such that PPPL’s ST PASA availability rose to 320 MW and any doubt in a case involving civil penalty provisions should be resolved in favour of PPPL. I am satisfied that by the time Revision 1 of the Scheduled Quantities Report was issued, PPPL ought to have had a reasonable expectation of obtaining sufficient interruptible gas transport (and gas) to operate in accordance with the 8 February counterfactual and that, subject to determining the precise number of contraventions, PPPL contravened cl 3.7.3(e)(2) after that date. PPPL did not contravene cl 3.7.2(d)(1) and it did not contravene cl 3.7.3(e)(2) prior to 3 February 2017 at 12.14 pm.
I will hear the parties as to the appropriate orders in light of these conclusions. I will also hear the parties as to the effect of these conclusions on the AER’s case that PPPL contravened cl 3.13.2(h).
I certify that the preceding six hundred and eighty-one (681) numbered paragraphs are a true copy of the Reasons for Judgment of the Honourable Justice Besanko. Associate:
Dated: 20 September 2023
Annexure 1
Annexure 2
Annexure 3
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