Australian Energy Regulator v Stanwell Corporation Limited

[2011] FCA 991

FEDERAL COURT OF AUSTRALIA

Australian Energy Regulator v Stanwell Corporation Limited
[2011] FCA 991

Citation:

Australian Energy Regulator v Stanwell Corporation Limited [2011] FCA 991

Parties:

AUSTRALIAN ENERGY REGULATOR v STANWELL CORPORATION LIMITED (ACN 078 848 674)

File number:

QUD 186 of 2009

Judge:

DOWSETT J

Date of judgment:

30 August 2011

Catchwords:

ENERGY AND RESOURCES – application pursuant to the National Electricity Rules – the applicant alleged that the respondent had breached cl 3.8.22A of the National Electricity Rules (the “good faith requirement”) in relation to eight rebids made on 22 and 23 February 2008 – whether the respondent’s traders made the relevant rebids “in good faith” – construction to be given to the expression “material conditions and circumstances” in cl 3.8.22A(b) of the National Electricity Rules – whether the respondent’s traders made the relevant rebids with a genuine intention to honour them if the material conditions and circumstances upon which the rebids were based remained unchanged until the relevant dispatch interval  

Legislation:

Competition and Consumer Act 2010 (Cth)
National Electricity Law cl 8 of Schedule 2

National Electricity Rules cll 3.8.1, 3.8.16, 3.8.22, 3.8.22A, 3.9.2, 3.11.1, 3.13.3

Trade Practices Act 1974 (Cth) s 44AE

Cases cited:

Alcan (NT) Alumina Pty Ltd v Commissioner of Territory Revenue (2009) 239 CLR 27 cited
CIC Insurance Ltd v Bankstown Football Club Ltd (1997) 187 CLR 384 cited

Oxford English Dictionary (2nd ed, Clarendon Press, 1989)
Shorter Oxford English Dictionary (4th ed, Clarendon Press, 1993)

Dates of hearing:

15-18 June 2010, 21-25 June 2010, 29 June-2 July 2010 and 5 July 2010

Place:

Brisbane

Division:

GENERAL DIVISION

Category:

Catchwords

Number of paragraphs:

392

Counsel for the Applicant:

Mr J Santamaria QC and Mr P Gray

Solicitor for the Applicant:

DLA Phillips Fox

Counsel for the Respondent:

Mr S Doyle SC and Mr P Franco

Solicitor for the Respondent:

Minter Ellison

IN THE FEDERAL COURT OF AUSTRALIA
QUEENSLAND DISTRICT REGISTRY
GENERAL DIVISION	QUD 186 of 2009

BETWEEN:	AUSTRALIAN ENERGY REGULATOR Applicant
AND:	STANWELL CORPORATION LIMITED (ACN 078 848 674) Respondent

JUDGE:	DOWSETT J
DATE OF ORDER:	30 AUGUST 2011
WHERE MADE:	BRISBANE

THE COURT ORDERS THAT:

1.the application be dismissed; and

2.in the absence of any application, within 7 days, for any other order as to costs, the applicant pay the respondent’s costs of the proceedings, including reserved costs.

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

IN THE FEDERAL COURT OF AUSTRALIA
QUEENSLAND DISTRICT REGISTRY
GENERAL DIVISION	QUD 186 of 2009

BETWEEN:	AUSTRALIAN ENERGY REGULATOR Applicant
AND:	STANWELL CORPORATION LIMITED (ACN 078 848 674) Respondent

JUDGE:	DOWSETT J
DATE:	30 AUGUST 2011
PLACE:	BRISBANE

REASONS FOR JUDGMENT

NATIONAL ELECTRICITY MARKET........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ...	[1]
ELECTRICITY GENERATION AND SUPPLY........ ........ ........ ........ ........ ........ ........ ........ ........ .	[3]
DEMAND TRENDS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ....	[7]
MEETING DEMAND FLUCTUATIONS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[13]
THE APPLICANT........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ....	[17]
THE OPERATOR........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[18]
THE GENERATORS, INCLUDING THE RESPONDENT........ ........ ........ ........ ........ ........ ...	[19]
OPERATION OF THE NEM........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ....	[20]
PRODUCTION COSTS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........	[24]
Boiler-fired steam generation........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ..	[26]
Gas turbine generation........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[27]
Combined cycle generation........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[28]
Hydro-generation........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[29]
Relative use of fuel types........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ..	[30]
BIDDING........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........	[32]
REMUNERATION........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ..	[38]
INFORMATION........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........	[47]
UNDERLYING PRINCIPLES........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[49]
INACCURACIES IN THE BIDDING PROCESS........ ........ ........ ........ ........ ........ ........ ........ .......	[50]
DR ROSE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........	[53]
Instability........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ...	[53]
Generating technologies and costs........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[61]
Demand side responses........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[75]
Inaccuracies........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[76]
MR THORPE AND DR ROSE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[79]
OTHER WITNESSES FOR THE APPLICANT........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ..	[80]
22 AND 23 FEBRUARY 2008........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ....	[81]
THE RESPONDENT’S REBIDS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[90]
THE STATEMENT OF CLAIM........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[92]
REASONS FOR REBIDS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ....	[97]
CONTENT OF THE REBIDS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ..	[100]
Rebid 19 – impugned by reference to Rebid 20........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 24 – impugned by reference to Rebid 25........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 28 – impugned by reference to Rebid 29........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 67 – impugned by reference to Rebid 68........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 69 – impugned by reference to Rebid 70........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 81 – impugned by reference to Rebid 82........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 83 – impugned by reference to Rebid 84........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[105]
Rebid 86 – impugned by reference to Rebids 87 and 88........ ........ ........ ........ ........ ........ ........ ........ .......	[105]
MR GOBI KRISHNA GNANANANTHAN........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[105]
General matters........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[106]
Rebid 19........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[143]
Rebid 24........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[156]
Rebid 28........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[169]
MR MICHAEL JOHN POPE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ...	[188]
MR ROBERT DONALD WALLACE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[192]
General matters........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[193]
Rebid 67........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[214]
Rebid 69........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[235]
Rebid 81........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[259]
Rebid 83........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[270]
Rebid 86........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[283]
WALTER ROBERT SCHUTTE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .....	[298]
OTHER WITNESSES FOR THE RESPONDENT........ ........ ........ ........ ........ ........ ........ ........ .....	[301]
ASSESSMENT OF MR GNANANANTHAN AND MR WALLACE’S EVIDENCE.	[302]
ADMISSIBILITY OF EVIDENCE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........	[309]
THE PROPER CONSTRUCTION OF CL 3.8.22A........ ........ ........ ........ ........ ........ ........ ........ ....	[332]
THE APPLICANT’S CASE........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ...	[348]
FINDINGS CONCERNING REBIDS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ..	[358]
Rebid 19........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[358]
Rebid 24........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[362]
Rebid 28........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[367]
Rebid 67........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[369]
Rebid 69........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[375]
Rebid 81........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[377]
Rebid 83........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[383]
Rebid 86........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ......	[387]
OTHER FINDINGS OF FACT........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........	[391]
ORDERS........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ ........ .	[392]

NATIONAL ELECTRICITY MARKET

1. The National Electricity Market (the “NEM”) is a market for the sale and acquisition of electricity.  The NEM is established pursuant to the National Electricity Law (the “Law”), originally enacted by the Parliament of South Australia and subsequently adopted by Commonwealth, New South Wales, Victorian, Queensland, Tasmanian and Australian Capital Territory legislation.  The Law provides that:

   The objective of this 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. 

2. The National Electricity Rules (the “Rules”) govern the operation of the NEM.  They have the force of law.  There are five regions in the NEM, of which the State of Queensland is one.  Although the demand for electricity within Queensland is generally met from local sources, electricity can be obtained from, and supplied to New South Wales.  The NEM operates electronically.  This case primarily concerns the Queensland region of the NEM in which there were, at the relevant time, effectively, nine suppliers of electricity.  Although there were numerous purchasers of electricity in the market, mainly retail suppliers of electricity, decisions to purchase were, for present purposes, effectively made by the National Electronic Market Management Company Limited.  That corporation is generally referred to in the evidence as “NEMMCO”, although the acronym “AEMO” is also used as its name is now Australian Energy Market Operator Limited.  In these reasons I shall refer to it as the “Operator”.  It was responsible for operation of the NEM.

   ELECTRICITY GENERATION AND SUPPLY

3. The structure and operation of the NEM reflect certain characteristics of electricity and the mechanisms by which it is generated and supplied to end users.  These matters are dealt with in detail in the affidavit of Gregory Harold Thorpe filed by the applicant on 26 February 2010.  Mr Thorpe is an electrical engineer with considerable experience in the electricity industry, including industry regulation and marketing.  Dr Ian Athol Rose was called by the respondent.  He is an engineer, also eminently qualified to give evidence in respect of both technical and market matters.  In his evidence Dr Rose avoided unnecessary repetition of the very detailed and helpful description of the market and of technical matters given by Mr Thorpe.  He chose rather to comment upon aspects of Mr Thorpe’s report and to provide other, in most cases more detailed information concerning such matters.  Much of this part of my reasons comes from Mr Thorpe’s evidence.  I shall consider Dr Rose’s evidence separately.

4. In these reasons, I shall use the term “generating unit” to identify one set of equipment which is capable of generating electricity.  I shall use the word “generator” to describe a legal entity which operates a generating unit.  Generators usually operate power stations which house more than one generating unit.  Electricity produced by generating units is, in the case of larger generators, transported to consumers through shared bulk transmission networks and local distribution networks.  Some smaller or local generators supply electricity directly to local distribution networks. 

5. Electricity is generated by converting other forms of energy into electrical energy.  This may involve the conversion of energy stored in fuel such as coal or gas.  Running water, the wind and the sun are other sources of energy used in generating electricity.  Consumers convert electrical energy into other forms of energy such as light, heat and motion.  The rate at which electrical energy is produced, transported or used at any point in time is described as “electrical power” and is measured in Watts (“W”).  Applications which require substantial amounts of energy in short periods are said to have high power demand.  The amount of energy produced or consumed in a given time is found by multiplying the power (that is the rate at which energy was delivered) by the length of time for which it was delivered and is measured in Watt-hours (“Wh”).  Multiples of one thousand, one million and one thousand million units of power and energy are termed “kilowatts” and “kilowatt hours”, “megawatts” and “megawatt hours” and “gigawatts” and “gigawatt hours” respectively.  The abbreviations “kW” and “kWh”, “MW” and “MWh” and “GW” and “GWh” are in common use.  In this case it is not necessary to distinguish between Watts and Watt-hours.

6. In an electrical power system the aggregate power and energy requirements of individual consumers create the system demand for power and energy.  Demand is sometimes described as “load”.  That term may also be used to nominate the level at which generators are operating.  This ambiguity is best avoided by referring to energy requirements of individual consumers and the aggregate of such requirements as “demand”.

   DEMAND TRENDS

1. Demand within any system will vary from second to second as users (including major users) switch appliances on and off.  Demand tends to vary across each day and seasonally.  Over a 24 hour period from midnight to midnight, demand typically falls to a low between 4.00 am and 6.00 am.  Overnight demand includes 24 hour industry, security, street lighting and refrigeration.  Demand rises as industrial, domestic and commercial activities commence for the day.  Depending on the time of year and the location, early morning demand may reflect lighting, cooking, heating or air conditioning and public transport needs.  During daylight hours, demand generally continues to rise to one or more peaks, and then begins to fall as commercial and industrial activity winds down.  In hot weather air conditioning demand falls as the sun goes down.  In cooler locations heating may drop as commerce and retailing close down for the day.  Around 6.00 pm demand for cooking is high.  Demand for lighting and for uses such as domestic television also increases until the daily cycle repeats. 

2. Figure 2 in Mr Thorpe’s report appears below.  It shows typical daily fluctuation in demand for summer and winter days.  Winter demand reflects lighting and heating requirements at the start and end of daylight hours, whilst summer demand reflects air conditioning requirements during the day and into the evening. 

3. In Figure 3 (below) Mr Thorpe demonstrates the maximum or peak levels of power demand occurring during the 2007-2008 year in Queensland.  Seasonal variations can be seen.  The lowest peak demand was on Boxing Day.  The Christmas and New Year period is generally the lowest demand period because of summer holidays and reduced industrial and commercial activity.  This period of low demand is generally followed, later in January and February, by elevated demand due to air conditioning use.  In general, there are higher peak demand periods in mid-winter and summer than in the rest of the year.  In Australia demand is highly sensitive to weather conditions and associated heating and air conditioning requirements, resulting in significant day-to-day variations.  In some other states there are even greater seasonal and daily variations than in Queensland.

4. In Figure 4 (below) Mr Thorpe demonstrates the half-hourly demand trend in Queensland on 22 February 2008.  It is typical of the variations experienced on a summer’s day. 

5. The diagonal lines indicate the part of the trend line (from 8.00 am to 10.00 am) which is considered in more detail in Figure 5 (below).  Mr Thorpe says that there may be significant fluctuations within the general demand trend.  Figure 5 shows demand for the 5 minute periods between 8.00 am and 10.00 am on 22 February 2008. 

6. The “saw tooth” effect in Figure 5 cannot be seen in Figure 4.  As I understand it, that effect demonstrates very rapid rises and falls in demand which the electricity generating and distribution system must meet.  Such variation in demand imposes a number of constraints on the operation of power systems.  In particular the Operator and generators need detailed knowledge of prevailing conditions and resources to manage the technical implications of fluctuations in demand.

   MEETING DEMAND FLUCTUATIONS

7. Electricity, once generated, cannot be stored in any meaningful quantities.  This characteristic has great significance in the technical and commercial operation of electrical power systems and the NEM.  Electricity must generally be produced as it is needed by users.  Hence aggregate production must track the short-term, saw-tooth shape of demand as it occurs.  If the aggregate supply from all generators is not closely balanced with the aggregate level of demand from all users, the power system can become unstable.  In extreme circumstances such instability may result in a complete shutdown of the power system with consequential interruption of supply.  Widespread shutdowns are rare.  Systems are designed and operated to avoid such occurrences to the extent that this is possible.  However even a few seconds of imbalance between aggregate generation and aggregate demand can lead to instability.  Stability of a system is indicated by fluctuations in its operating frequency measured in Hertz (Hz).  The standard frequency in Australia is 50 Hz.  If the frequency varies from 50 Hertz by more than one or two per cent, there is a risk of instability.  Mr Thorpe explains this instability as follows:

   a.The electrical frequency at which a generating unit produces electricity is determined by the speed of rotation (rpm) and the construction of each turbine-generator unit;

   b.Instability can occur because the rotating parts of power generating units are generally only able to operate safely within a relatively narrow range of speed of rotation and hence output electrical frequency;

   c.If there is too much supply, for example due to the sudden disconnection of a block of customer demand when a transmission line is taken out of service due to a fault, the rotating machines may speed up to dangerous levels and potentially fail;

   d.Conversely if there is too little aggregate supply, for example if a large generator is suddenly shutdown because of a fault, the remaining generators will slow down as they attempt to meet the full customer demand; and

   e.Self-protection devices are built into turbine-generating plant [sic] to disconnect the units from the power system to avoid the plants running at unsafe speeds.  In the case of under-supply, the failure or disconnection of a generating unit will exacerbate the under-supply and could lead to a cascading situation and eventual collapse of the power system.

8. As with any mechanical or electrical equipment, faults sometimes occur in generating units and in transmission and distribution networks.  They may have to be taken off line for repair.  There must be available reserve capacity in appropriate locations, with suitable response times, in order to keep power system frequency within safe bounds.  Some generating systems have very short response times or other characteristics which make them especially suitable for use in the reserve role.  Mr Thorpe says that some such systems are referred to as “ancillary services”.  That term is defined in cl 3.11.1 of the Rules as:

   … services that are essential to the management of power system security, facilitate orderly trading in electricity and ensure that electricity supplies are of acceptable quality.

9. In other words such services are vital aspects of the operation of the electricity supply system as a whole.  Mr Thorpe presumably uses the term to describe generating units suitable for use in ensuring that such services are available as required.  Other evidence suggests that there are special arrangements designed to guarantee the electricity supply necessary to maintain ancillary services, including arrangements concerning payments to generators for supplying such electricity.  Mr Gnanananthan, formerly a trader employed by the respondent, gave further information concerning ancillary services.  There are eight ancillary services markets.  One such market is for power used in fine-balancing supply and demand.  The markets are organized on the basis of 5 minute supply periods.  Those periods are, themselves, divided into four second intervals.  Although ancillary services are mentioned fairly frequently in the evidence, they are not of great importance in the case.

10. The generating units used to guarantee reserve and ancillary services are sometimes less cost effective than other units, and so may not always be in use when demand is low, and other sources are available.  To guard against the risk that all available reserves may not be adequate to meet the demand created by a particular incident, systems are usually designed to permit disconnection of controlled amounts of customer demand.  Similarly, to guard against a sudden drop in demand, systems are designed to permit disconnection of generating units.  These mechanisms also provide a method of monitoring and recording changes in demand on a minute-to-minute or hour-to-hour basis. 

    THE APPLICANT

11. The applicant was established pursuant to s 44AE of the Trade Practices Act 1974 (Cth), now the Competition and Consumer Act 2010 (Cth). Its functions are prescribed by the Law. They include the investigation of possible breaches of the Law, associated Regulations and the Rules and the conduct of proceedings in connection with any such breaches.

    THE OPERATOR

12. The Operator is responsible for various aspects of the electricity distribution system, including the NEM.  In that capacity it effectively makes decisions as to the acceptance of offers by generators to supply electricity to the NEM.  It is also responsible for power system security and for planning the development of the national transmission grid.

    THE GENERATORS, INCLUDING THE RESPONDENT

13. At the relevant time there were nine generators selling electricity in the Queensland region of the NEM.  The respondent was the largest single supplier, operating generating units at Stanwell, Gladstone, Kareeya, the Barron Gorge, and Mackay power stations.  For present purposes the Stanwell and Gladstone power stations are of particular importance.  At Stanwell there were four coal-fired, thermal, 350 MW generating units and at Gladstone, six coal-fired, thermal, 280 MW generating units.  As I have said, electricity could also be acquired from the New South Wales generating system, using interstate connectors.

    OPERATION OF THE NEM

14. Some electricity generators sold electricity directly to larger end users pursuant to long term contracts.  However much of the electricity produced was sold in the Spot Market which is part of the NEM.  Operation of the NEM required that demand be tracked in order to match it with economical supply in prevailing conditions.  This “dispatch process” had, as its dual objectives, reliable technical operation and economic use of resources.  In order to manage the process the Operator had to predict future demand for electricity and have knowledge of available generating capacity.  In particular, it had to know the quantities of electricity offered by the various generators at any point in time.  Mr Thorpe suggests that the Operator had to “… judge the relative economic merits of calling different generators into service as demand rises and falls on the basis of the ‘dispatch cost’ presented to [the Operator]”.  Mr Thorpe argues that the generators, in effect, would bid for shares of market demand by offering quantities of electricity at particular prices.  Whilst the Operator sought to ensure continuity of supply to users at the lowest cost, generators sought to ensure that the amounts of electricity which they generated were disposed of and to maximise their returns.  I have previously identified the need for reserve capacity, that such capacity might be provided by generating units which could be brought on line quite quickly and that those units may be more expensive to operate than other units.  In periods of high demand, the cheaper generating units would be unable to meet demand, and so more expensive units would be brought on line.  Only the prospect of higher prices would entice a generator to bring such units on line.  A generator would seek to ensure that the electricity produced by its cheaper units was sold, whilst seeking to maximise its return by activating the more expensive units when the price was sufficiently high to justify their engagement.  As will be seen, when the Operator acquired electricity at a higher price, all generators supplying electricity at the relevant time received the benefit of that price.

15. In discussing the market it is important to note one curiosity in its terminology.  The regulations distinguished between dispatch bids, which reflected customer demand, and dispatch offers made by generators.  However, in common parlance within the industry, both bids and offers were referred to generically as “bids”.  Subsequent variations to either dispatch offers or dispatch bids were described as “rebids”.  This latter usage was recognized in the definition provisions contained in Ch 10 of the Rules.

16. As I have said, trading of electricity in the NEM occurred in two broad forms, “spot” and “contract”.  This case primarily concerns spot trading.  Mr Thorpe described the NEM as occurring in a “mandatory gross spot market”, saying that:

    a.It is mandatory as, with a limited number of exceptions … all wholesale quantities of electricity must be bought and sold through the Spot Market;

    b.It is a gross arrangement as settlement of trading is for the entire amount of electricity produced by generators and consumed by retailers and large users;

    c.It is a spot market as the trading occurs at Spot Prices determined on the basis of prevailing market conditions each half hour, although the design presumes market participants are likely to enter into bilateral contracts outside of the auspices of the [Rules]; and

    d.The points of connection to the transmission networks of generators and wholesale buyers are grouped into geographic price regions and a separate Spot Price is set for each region.  …  

17. Contract trading occurred between buyers and sellers in parallel with spot trading, generally in the form of “contracts for difference”.  Such contracts were made in advance and may have covered periods of some years.  These contracts were, as Mr Thorpe puts it, “financial in nature”.  The parties were free to agree on the contract price and other terms on a bilateral basis.  However such trading was subject to legislative and regulatory oversight outside of the Rules.  A contract for difference guaranteed that the generator would dispose of at least part of its capacity at a fixed price.  Similarly, the end user had a guaranteed supply at that price.  These contracts were generally performed by the payment of money by one party to the other, representing the difference between the relevant contract price and the spot price at the time of supply.  Electricity was transferred between generators and contract customers using the various distribution networks.  In the evidence these contracts are often referred to as “hedge contracts”. 

    PRODUCTION COSTS

18. The prices at which electricity was supplied reflected differences in generating technology.  A turbine generating unit comprises a generating mechanism mounted on one end of a shaft.  The shaft is made to rotate by a force acting on the blades of the turbine mounted on the other end of the shaft.  When the turbine rotates, the generating mechanism produces electricity.  Numerous technologies and fuels are used to drive turbines.  They include:

    ·steam produced by heating water in a boiler fuelled by gas, coal or other fuels;

    ·hot exhaust gas from the combustion of fuels such as gas in gas turbines;

    ·wind passing over the blades of wind turbines;

    ·water falling from a height or flowing into a hydro-power station; and

    ·emerging technologies, in various stages of development, including hot rocks as a source of energy to create steam, wave power and air heated in solar towers.

19. These technologies have different capital and operating cost structures which affect the cost of using them in producing electricity.  Different technologies have different characteristics, affecting the rapidity with which they can be brought from standby mode to operating mode in order to respond to dispatch instructions.  Generators were permitted only to submit bids for supply by generating units which were in operating mode and able so to respond.  Relevant characteristics of different technologies are discussed below.

    Boiler-fired steam generation

20. Steam boilers take between six and twenty hours to heat in order to produce sufficient steam to drive turbines and thus produce electricity.  Hence there is a significant delay between a decision to call on an inactive steam generating unit and actual supply.  Boilers have high capital costs which add significantly to the cost of thermal steam generating units.  However they are often built in locations at which there is ample low cost fuel, so that operating costs can be lower than for other technologies.  Typical average cost of electricity from a boiler-based generating unit using coal is $40.00 per MWh, of which approximately $25.00 to $35.00 per MWh is due to capital cost.

    Gas turbine generation

21. Gas turbine technology is less capital-intensive than thermal steam generation but makes less efficient use of fuel.  As a result gas turbines generally have relatively low capital costs, but higher operating costs per unit of electricity produced.  Gas turbines are very responsive.  They can be brought from standby to dispatch in between 5 and 20 minutes.  Because of the lower capital cost and relatively short response time, a gas turbine system is well suited to functioning as a reserve plant.  It may be operated cost-effectively to meet short duration peaks in power demand. 

    Combined cycle generation

22. Combined cycle generation technology is a combination of boiler and gas turbine technologies.  The energy in hot exhaust gas from the gas turbine is used to heat water in a boiler in order to make steam to drive another turbine.  Electricity is produced by generating units driven by both turbines, resulting in a greater electrical output for the same fuel input, and therefore lower cost per unit of electricity.  Many new, gas-fired generating units use combined technology and are, as a result, cost-effective over a relatively wide range of operating roles.  Some designs allow each part of the plant to be used separately.  The plant is less efficient when so operated. 

    Hydro-generation

23. Hydro-generating units are generally more flexible than gas turbine units.  Output can be changed by increasing or decreasing the flow of water through the turbine, using control valves.   Operating costs are low, absent any external charge for the use of water.  However hydro-facilities are generally capital-intensive.  This is especially so for facilities associated with large water storage.  Smaller facilities can be constructed at lower cost if located in the path of a rapidly flowing river.  Larger facilities typically have high capital cost but low operating cost, again absent any external charge for the use of water.  They have very short response times, in some cases, seconds, but in others, up to ten minutes.  As a result such generating units can provide reserve services over varying timeframes.  The amount of water available to drive such units may, from time to time, be limited, for example where the availability of water is affected by seasonal irrigation or annual snowmelt.  In Queensland, there is a hydro-generator at the Wivenhoe power station.  It is a “pumped storage facility”.  Water is pumped into a high-level reservoir at times when the cost of electricity from other generators is low.  The water is released through the turbine when higher-cost generation is needed.  There are similar units elsewhere in Australia. 

    Relative use of fuel types

24. In 2008 generation in the NEM was distributed amongst fuel type as follows:

    ·black coal – 49%;

    ·brown coal – 17%;

    ·hydro – 17%;

    ·gas – 15%;

    ·wind – 1%; and

    ·other – 1%.

25. In Queensland black coal was by far the most significant fuel source used in the supply of electricity.  There was also significant use of gas. 

    BIDDING

26. The Rules permitted generators to offer electricity at any point within a range from a high point of $10,000.00 per MW to a low point of minus $1,000.00 per MW meaning, in the latter case, that the generator would actually pay for electricity to be taken from it.  This curiosity reflects the lack of capacity for storing electricity and the length of time taken to bring relatively cheap generating units on line.  In general, generators prefer to keep units operating rather than to close them down, and then to re-activate them when needed.  Thus, for presumably short periods of time, a generator might have chosen to pay the Operator to take electricity, ensuring that its load was consumed in advance of that offered by generators who had bid at higher prices, and avoiding the need to close down generating units.  A generator was permitted to bid by offering dispatch volume in up to ten price bands, each having a specified price at which the generator was willing to supply an identified volume.  In principle these bids were then ranked in merit order with the lowest price at the bottom of the list and the highest, at the top.  In theory one would have expected the Operator to accept bids from the bottom upwards, until it had satisfied the aggregate demand of all customers for the relevant period.  In fact the merit order was not so strictly applied for reasons associated with the structure of the power distribution networks and the geographical locations of various generators.  The operation of the price bands can be demonstrated by this example taken from the applicant’s submissions:

    Thus, if a [generator] is offering 10MW in price band 1, 10MW in price band 2 and 10MW in price band 3, it is in effect offering 30MW if the dispatch price reaches price band 3, 20MW if it only reaches price band 2 and 10MW if it reaches only price band 1.

1. The bidding process was conducted on a day-by-day basis.  Each 24 hour cycle commenced at 4.00 am, the expected low point of daily demand.  It was divided into 48 thirty minute Trading Intervals.  Each Trading Interval was divided into six 5 minute Dispatch Intervals.  Each Trading Interval was identified by its last minute.  Dispatch Intervals were similarly identified.  Thus “Trading Interval 13:00” was the Trading Interval between 12:30 and 13:00, using the 24 hour clock.  “Dispatch Interval 13:00” was the Dispatch Interval between 12:55 and 13:00.  Generators made offers in respect of each Trading Interval in a Trading Day.  The bids were offers to supply fixed amounts of electricity for each Trading Interval.  At the relevant time the Operator employed computing software known as the National Electricity Market Dispatch Engine (“NEMDE”) in calculating the way in which electricity was acquired and dispatched.  The programme was run every five minutes and issued dispatch instructions to the various generating units in respect of which it had accepted bids.  In effect the NEMDE programme was run at the beginning of each Dispatch Interval based on information received prior to its commencement, in order to calculate the Dispatch Price for that Dispatch Interval. The Dispatch Price was, in effect, that of the highest bid accepted for that Dispatch Interval.  The evidence suggests that the Dispatch Price was published within one to two minutes of the commencement of the Dispatch Interval to which it related.

2. Each generator would submit its bids for each 24 hour period by 12.30 pm on the previous day.  Generators could thereafter vary the amount of generation made available in each band but could not vary the price applicable to each band.  Such “rebids” were permitted throughout the day.  There was no formal cut-off time after which rebids would not be permitted.  There was a working arrangement pursuant to which rebids were accepted as late as practicable.  In practice rebids were allowed until one or two minutes before each NEMDE program run.  The Spot Price for a particular Trading Interval was the average of the six Dispatch Prices for that Trading Interval.  The Spot Price was the basis for financial settlements between generators and consumers in the NEM.  All electricity acquired in the relevant Trading Interval was purchased at the Spot Price.  The evidence suggests that the Spot Price for a Trading Interval was published shortly after the publication of the Dispatch Price for the last Dispatch Interval in that Trading Interval.

3. In order to perform its own functions and to assist generators in the bidding process, the Operator assembled and published substantial amounts of information relevant to NEM operations, including Dispatch and Spot Prices.  Clauses 3.13.1 to 3.13.13 of the Rules identified other market information which it was obliged to distribute, including predictions concerning demand, available supply and price, based largely upon supply and demand bids already received.  Information concerning the previous trading day was also made available.  In addition to this very large amount of information, a generator also had information concerning its own generating capacity and current conditions, particularly weather conditions, which might affect demand.  Forecasts were upgraded during the day.  Actual and forecast dispatch generation levels for generating units in each region were available on an aggregate basis.  Details of rebids were not published to other generators during the trading day in which they occurred.  However the respondent’s evidence suggests that its operators had some knowledge of the pricing patterns of competitors.  Information concerning rebids which had been accepted on a trading day were published on the following day.

4. Rebidding was regulated by cl 3.8.22 of the Rules as follows:

   (a)Prices for each price band that are specified in dispatch bids, dispatch offers and market ancillary service offers are firm and no changes to the price for any price band are to be accepted under any circumstances.

   (b)Subject to clauses 3.8.22(c) and 3.8.22A, a Scheduled Generator or Market Participant may vary its available capacity, daily energy constraints, dispatch inflexibilities and ramp rates of generating units, scheduled network services and scheduled loads, and the response breakpoints, enablement limits and response limits of market ancillary services.

   (c)A Scheduled Generator or Market Participant must provide:

   (1)all rebids to [the Operator] electronically unless otherwise approved by [the Operator];

   (2)to [the Operator], at the same time as the rebid is made:

   (i)a brief, verifiable and specific reason for the rebid; and

   (ii)the time at which the event(s) or other occurrence(s) adduced by the Scheduled Generator or Market Participant as the reason for the rebid occurred;

   (3)to the [applicant], upon written request, in accordance with guidelines published by the [applicant] from time to time under this clause 3.8.22 in accordance with the Rules consultation procedures such additional information to substantiate and verify the reason for a rebid as the [applicant] may require from time to time.  The [applicant] must provide information provided to it in accordance with this clause 3.8.22(c)(3) to any Scheduled Generator or Market Participant that requests such information, except to the extent that the information can be reasonably claimed to be confidential information.  The guidelines developed by the [applicant] under this clause 3.8.22(c)(3) must include:

   (i)the amount of detail to be included in the information provided to [the Operator] under clause 3.8.22(c)(2); and

   (ii)procedures for handling claims by Scheduled Generators or Market Participants in accordance with clause 3.8.22(c)(3) or 3.8.19(b)(2) that information provided to the [the applicant] by such Scheduled Generators or Market Participants under those clauses is confidential information.

   The [applicant] must publish the guidelines developed under this clause 3.8.22 and may amend such guidelines from time to time.

   (d)[The Operator]  must:

   (1)subject to the Scheduled Generator or Market Participant complying with clause 3.8.22(c)(1) and (c)(2)(i) and (ii), accept the rebid; and

   (2)publish, in accordance with clause 3.13.4(p), the time the rebid was made and the reason provided by the Scheduled Generator or Market Participant under clause 3.8.22(c)(2)(i).

5. Clause 3.8.22A is critical to this case.  It provided that:

   (a)Scheduled Generators and Market Participants must make dispatch offers, dispatch bids and rebids in good faith.

   (b)In clause 3.8.22A(a) a dispatch offer, dispatch bid or rebid is taken to be made in good faith if, at the time of making such an offer, bid or rebid, a Scheduled Generator or Market Participant has a genuine intention to honour that offer, bid or rebid, if the material  conditions and circumstances upon which the offer, bid or rebid were based remain unchanged until the relevant dispatch interval.

   (c)A Scheduled Generator or Market Participant may be taken to have contravened clause 3.8.22A(a) notwithstanding that, after all the evidence has been considered, the intention of the Scheduled Generator or Market Participant is ascertainable only by inference from the conduct of the Scheduled Generator or Market Participant, or of any other person, or from relevant circumstances.

   REMUNERATION

6. The basis for remuneration of generators for electricity supplied was the Spot Price which was calculated for each Trading Interval, based upon the Dispatch Price for each Dispatch Interval comprising that Trading Interval.  Pursuant to cl 3.9.2(d) of the Rules, the Dispatch Price “represented the marginal value of supply at that location and time, this being determined as the price of meeting an incremental change in load at that location and time in accordance with clause 3.8.1(b)”. 

7. In para 109 of his report, Mr Thorpe gives a general indication of the way in which the process worked.  He said:

   Figure 12 presents the conceptual steps in scheduling process over a 30 minute period showing how the bands for a number of generating units are assembled and called in price order and the Dispatch Price for each 5 minute period determined by the price of the band at the margin, that is, the dispatch cost/price of the last band called.  [The Operator] uses the most recent bid or rebid as appropriate relevant to the time.

   a.The generator bands within bids and relevant rebids of different generators offering to produce electricity at any particular time (or in the case of scheduled loads to reduce consumption) can be visualised as being stacked in ascending order of dispatch price/cost.

   b.Note that, although the example labels the bands as being from different generators, two or more of the bands may be from the same generating unit.

   c.[The Operator] then calls or schedules for the lowest price/cost options to meet the prevailing demand.  In the example shown:

   i.In order to meet the demand at 4:05 (point A) [the Operator] will schedule generators one, two and three to the full availability offered. The Dispatch Price is based on the price of generator three at $35/MWh.

   ii.At 4:10 (point B), in order to meet the increased demand at this time bands from generators one, two and three are fully scheduled and availability from generator four is partially scheduled and the Dispatch Price is based on the dispatch price/cost of generator four at $37/MWh.

   iii.Similarly at 4:15 (point C), more of generator four is scheduled and the Dispatch Price remains at $37/MWh.

   iv.By 4:20 (point D) a small amount of generator five is required and the Dispatch Price rises to $38/MWh.

   v.By 4:25 (point E) more of generator five is required and the Dispatch Price continues to be set from it at $38/MWh.

   vi.In the final 5-minute period of the half hour demand has fallen from its peak and none of generator five is needed and only part of generator four is required meaning the Dispatch Price is set from generator 4 at $37/MWh.

   vii.The Spot Price for the half hour overall is the arithmetic average of the Dispatch Price in each of the 5-minute periods at $37/MWh.

8. Concerning the design of the NEM, Mr Thorpe says, at paras 122-124 of his report:

   122.Amounts paid to generators, and by wholesale buyers, in the NEM are based on the Spot Price for the region in which they are located after adjustment for the effect of losses incurred in the transmission system.

   123.This form of market design is known as an energy-only market.

   124.The energy-only mechanism in the NEM is based on the well established economic principle of marginal pricing and is designed to enable market participants to establish the value of electricity over time through competitive pricing of their product to market.  As a result Spot Prices can fall when there is a surplus and rise as demand approaches the available supply.

9. Paragraph 122 reflects the fact that in the course of transmitting electricity over the supply networks, there is some loss of energy.  The Spot Price was adjusted to reflect the varying losses incurred, depending upon the location of each generating unit. 

10. In a footnote to para 124 Mr Thorpe adds:

    An objective of the design is that each generator will receive sufficient revenue to recover its capital costs and operating [costs] and a commercial level of profit but only if the overall portfolio of generating types and sizes is economically optimum.  If it is not optimum one or more generation types may recover more or less than the “correct” amount.  The over or under recovery is intended to create incentives for participants to either increase investment in a particular technology type that is currently recovering more than its costs, or to retire or reduce capability on those recovering less than the “correct” amount, in order that the overall portfolio of generation plant self corrects to the optimum over time.

11. I have already referred to the practice of hedging adopted by generators and large consumers, often by “contracts of difference”.  Mr Thorpe demonstrates the operation of such arrangements at paras 139-143 as follows:

    139.In the following paragraphs I outline the operation of a number of the financial risk management instruments available in the NEM including hedge contracts introduced earlier at paragraph 63.

    140.Depending on the volume of hedge contract each party enters into, typical contract forms provide stability of the net price paid by wholesale customers and received by generators for the contracted volume, irrespective of the Spot Price.

    141.Figure 14 illustrates the effect of a hedge contract where the parties have agreed to a price of $40/MWh (i.e. in Figure 8 the value for $C is $40/MWh).  Generators continue to receive the prevailing Spot Price (adjusted by the relevant loss factor for each participant) from [the Operator] for all of the energy they deliver to the network and the customer continues to pay [the Operator] at that price for all of their consumption.  Under the terms of the hedge contract the parties also make or receive additional payments between themselves that results in the generator receiving and the customer paying net $40/MWh for the contracted quantity and the Spot Price for amounts in excess of the contract volume.

    142.Note that generators face significant financial risk at high prices depending on the level of generation actually dispatched.  This is because when the Spot Price is above the contract strike price and as [the Operator] only pays for the amount of electricity a generator actually delivers, but a typical contract obligates generators to make contract payments to counterparties for the difference between the Spot Price and the Contract Price for the contracted volume regardless of the amount the relevant generator(s) dispatches.

    143.Accordingly there is a strong incentive for generators to ensure they achieve dispatch sufficient to cover contracted volumes, at a minimum. Generators also have an opportunity-cost incentive to generate above their contracted volumes whenever the spot price is above their actual [short run marginal cost], particularly if price is high.  However, there will generally be a price-volume trade-off as price commonly falls if more generation is offered to market.

12. A generator’s need to cover its contract position is of some importance in this case.  At a later stage, I shall discuss the matter in more detail.  For the moment, I observe that for a generator, there was a tension between maximizing price and dispatching a particular volume of electricity.  The process for resolving that tension is referred to in the evidence as a “price/volume trade off”.

13. Mr Thorpe discusses the relationship between price and investment, commencing with the proposition that in a market such as the NEM, very high prices might be efficient and necessary in order to provide a commercial return to generation investors.  At paras 152-163 he observes:

    152.Because customer demand is highly dependent on the weather and because electricity cannot be stored, some generation plants may only be called on to deliver energy for a very limited number of hours per year in periods of peak demand or following breakdown of other generators.  These are termed peaking or peak load generators.

    153.Although customer demand rises and falls across the day there is always some demand from customers and a need for a matching level of generation 24 hours per day.  Generators that can cost effectively run 24 hours per day, termed base load generators, will generally offer bids and rebids that position them at the bottom of the dispatch merit order.  In the NEM base load generators are predominantly coal fired thermal units.

    154.In an energy-only market peaking generators can only cover their annual fixed costs and operating costs if they receive very high revenue from the spot market for the short time they are dispatched, or alternatively can arrange to receive at least some revenue from other sources, such as from the sale of hedging contracts to wholesale customers.

    155.Typical hedging contracts provide a stable revenue stream for the generators as customers will make steady payments who in turn will be protected from the effects of volatile Spot Prices (for the contracted volume).

    156.In principle the price a wholesale customer will pay a generator for a contract will be related to the likely expense the customer would be exposed to at Spot Price alone.  Similarly a generator would seek a contract arrangement that at least covered its fixed and variable costs and reflected the amount it might receive from the spot market alone.  Accordingly the potential exposure to Spot Price is a key factor in contract pricing.

    157.Spot Price in the NEM can rise up to the maximum allowed level of $10,000/MWh.  The following example illustrates why this relatively high amount aligns with the potential costs of low utilisation peaking generators:

    a.Consider a hypothetical generating unit with typical cost parameters that requires revenue of $150,000/MW per annum of installed capacity to repay capital costs over its operating life, plus operating costs such as for fuel consumed when it is dispatched;

    b.If this unit were operated in a base load role for 90% of the possible 8760 hours in a year (assuming it was undergoing maintenance for 10% of the time) each MW would produce 8760 [y multiplied by] 0.9 MWhs of electrical energy and require to be paid at an average wholesale price of 150,000 [divided by] 8760/0.9 = $19.0/MWh plus operating costs, in order to recover costs;

    c.On the other hand, if this same generator operated as a peak load generator and ran only for 15 hours per year it would require a wholesale price of 150,000/15 = $10,000/MWh plus operating costs for every hour it ran; and

    d.In practice the same technology would be unlikely to be cost effective for both peaking and baseload roles and thus the two types would require somewhat different prices – but not markedly so.  The example is intended to illustrate the very significant effect that the duty cycle or number of hours of operation has on the revenue and price requirements for generators and to provide context for the occasionally very high Spot Prices.

    158.Except for the peak hours of the year, generally there is more than enough capacity to meet demand in each region, although breakdowns of generators and periods of planned outages for maintenance can result in the demand approaching the level of capacity available for service at any time.

    159.As a result Spot Price is moderate most of the time, for example Figure 13 presented earlier shows the Queensland region Spot Price was less than $100/MWh for 96.8% of 2007 – 08, but occasionally the Spot Price spikes to high levels and as noted earlier up to over $8,000/MWh in February 2008.

    160.The prices in bids and rebids and the level of demand are key determinants of the Spot Price.  However, the probability of any particular price band being called in the dispatch process is strongly impacted by the volume of relatively lower priced bands that are immediately available for dispatch by [the Operator].

    161.Availability of lower priced bands is determined by the physical availability of different technology generators and the prices and volumes assigned to the bands of bids and rebids by participants to the extent permitted by the [Rules].

    162.Ancillary service prices can vary over a similar range to energy.  Historically ancillary service prices have been very low for most of the time but very occasionally spike to very high levels reflecting the opportunity cost that a generator forgoes from energy production when it provides an ancillary service at times when energy prices are very high.

    163.In general generators will make decisions about the level at which they set “dispatch cost/prices” in bids and indirectly for rebids (through the volume in different price bands) depending on their actual costs, levels of hedge contract that they have negotiated with customers or other generators, market conditions and power system conditions.  Generally they will also use the price bands to position different levels of output of generating units at different points of the merit order: for example where a generator operating a coal unit wishes to ensure that its unit is called to dispatch the minimum level that it can safely operate the unit at it will often set the price for its first bands relatively low.  Similarly an operator of a gas turbine plant may wish to avoid short runs with marginal returns that might occur if it sets its price too low and thus sets a relatively high price so that it is only called if it is clearly profitable.

1. One might infer from the above explanation that generating units were either base load units or peak load units, and that the higher spot prices, which were occasionally available, were really designed to compensate the generators operating the latter category for only limited periods of time.  However Dr Rose argues that generators operating base load units also needed the benefit of higher spot prices in order to operate on a viable financial basis.  I do not understand the applicant to dispute that view.

   INFORMATION

2. At paras 167-183 Mr Thorpe addresses the role of information in the NEM.  Again it is convenient that I set out the relevant paragraphs in full.

   167.While the calculations for actual dispatch and price and the issue of instructions to generators are of necessity undertaken in the final minutes and seconds before the time electricity is consumed, preparation for dispatch and its associated trading commences a number of years before.

   168.In the NEM many of the preparatory decisions are taken by market participants.  However, [the Operator] has an oversight role and publishes aggregated information about future conditions to inform participants’ decisions.  Relevant decisions and information includes:

   a.Forecasts of demand for between the next 5 minutes and up to a number of years in advance;

   b.Decisions about amount, location and type of generating capacity taken far enough in advance to allow new generation to be constructed;

   c.Decisions about the timing of major shutdowns for maintenance;

   d.Decisions about fuel supply;

   e.Forecasts of likely wholesale price based on analysis of expected supply and demand;

   f.Agreements between market participants about financial contracts;

   g.Decisions about prices to be bid for dispatch; and

   h.Decisions about rebids.

   169.Efficient and effective decisions rely on the decision makers having timely, accurate and relevant information and forecasts.  The [Rules] includes provisions designed to provide information to inform a number of the decisions taken by participants.  Information published in accordance with cl 3.13 of the [Rules] is particularly relevant to decisions about rebidding.

   170.Relevant provisions include a requirement for [the Operator] to prepare and publish a schedule with a resolution of 30 minutes for approximately one day ahead (30 minute predispatch schedule) showing:

   a.Expected demands and prices in the different price regions;

   b.Demand estimates (formed by [the Operator]);

   c.Network capacity and ancillary service requirements current at the time of the preparation of the schedule; and

   d.Details of the expected generation from each generator in the 30 minute predispatch schedule which are made available to the relevant generators, but not to other generators.

   171.Information about the prices and volumes bid and rebid by each generator are not included in the 30 minute predispatch schedule but details of the final bids and rebids used for dispatch are published in full the following day (in accordance with [the Rules] cl 3.13).

   172.[The Operator] updates the 30 minute predispatch schedule each 30 minutes and may also issue updates more frequently if circumstances change materially between routine updates.

   173.After consultation with market participants, each 5 minutes [the Operator] also publishes a forecast for each 5 minutes of the next hour (5 minute predispatch schedule).  Other than being calculated each 5 minutes and providing a 5 minute resolution, the 5 minute predispatch schedules contain information of the same form as 30 minute predispatch schedules.

   174.Calculations in relation to 30 minute predispatch schedules, 5 minute predispatch schedules and for dispatch instructions (for the next 5 minute period) use the most recent bid or rebid available at the time of each calculation.  Accordingly, rebids made less than 30 minutes before the time of dispatch may not appear in the last 30 minute predispatch, but will be taken into account in calculation of each 5 minute predispatch and dispatch instruction.

   175.Rebids by generators are often the source of change in information provided in updates of 30 minute predispatch schedules and 5 minute predispatch schedules.

   176.The NEM design places decisions with generators about how any limited amounts of fuel should be rationed and when a generator should begin preparations to present availability for future dispatch periods.  Similar considerations apply for scheduled loads.

   177.Consequently, the NEM also places decisions with generators about when it is efficient to not present capacity for dispatch, for example in order to undertake short term maintenance work, or because the value of a particular generator as evidenced by the forecast market price does not warrant it operating at that time.

   178.The volumes and prices in bids and rebids are the primary means generators have to communicate their decisions to [the Operator].  The market forecasts that [the Operator] subsequently publish are a key mechanism by which [the Operator] disseminates relevant market consequences of those decisions – effectively inviting rebid(s) if appropriate.

   179.I say inviting a rebid because I am aware from my experience that because of the potential for market and power system conditions to change rapidly it is normal and efficient practice for decisions to be reviewed and amended in the lead up to dispatch.

   180.I am also aware from my experience that it is very difficult to design a set of conditions to limit the basis for rebids without excluding amendments that increase efficiency and therefore reduce the cost of production of electricity.

   181.Similarly, decisions taken by [the Operator] as it prepares for dispatch and assesses the level of reserve and ancillary services and the likely loading on networks also require information.

   182.[The Operator] has obligations under the [Rules] and [the Law] to ensure safe operation of the power system and has a power to intervene in the operation of the market in the event sufficient generating capacity is not presented to it through the bidding processes.  To fulfil this obligation [the Operator] therefore must continually assess the outlook for security of the power system and determine if security standards are likely to be met or whether it should consider intervention.  Intervention is a relatively rare occurrence.

   183.Together, the provisions for bids and rebids, 30 minute predispatch schedules, 5 minute predispatch schedules and assessments of the security of operation, spot pricing and financial contracting are designed to elicit decisions by participants based on commercial incentives that deliver cost effective, reliable and secure operation of the wholesale market and allow [the Operator] to assess if it needs to intervene.

3. Although the Operator may have had both short and long term responsibilities and required information to perform those duties, paras 175 et seq demonstrate that rebids were primarily to reflect commercial considerations, and that it was difficult to design limitations which would accommodate that fact.

   UNDERLYING PRINCIPLES

4. At paras 184-194 Mr Thorpe describes “underlying principles” which reflect his views as to the way in which the market was designed in order to achieve efficiency in the supply of electricity as follows: 

   184.Earlier sections have presented descriptions of the relatively detailed measures for bidding and rebidding and operation of the dispatch process and how they interact and accommodate the complex technical characteristics of electricity.  This section aims to very briefly set these arrangements in the context of a market designed to deliver reliable and cost effective electricity in order to address the final questions put to me concerning inaccuracy in bids and rebids (dispatch offers).

   185.In very general terms an efficient market will see buyers and sellers identify a fair value for the commodity being traded.

   186.Information about future prices and market conditions is crucial in this regard.  In the electricity sector this is complex as conditions vary continuously because electricity is not storable and demand varies markedly over a day.  As a result different generators must be brought in and out of service across the daily cycle of operation as part of the dispatch process.

   187.As different generating technologies have different operating costs (see Section 4) and need to recover different fixed costs, the cost to supply varies significantly.

   188.In the longer term, economies of scale can be significant as well, meaning that investment and retirement is “lumpy” and the cost effective size of new generating units will be somewhat larger than is needed immediately – creating a short term surplus.  As a result the supply/demand balance often will move from just sufficient to a surplus which will be eroded over time as demand grows or old generators are retired from service until the investment cycle repeats.

   189.In the NEM buyers and sellers are expected to find an agreed set of prices and volumes in a mix of short term spot and longer term contract trading.  However, there are strong linkages between the two forms of trading.  If either is distorted the other is likely to be distorted also and distortion will generally mean lower efficiency and  higher cost, which is eventually borne by consumers.

   190.The bidding and rebidding provisions are a key element of the overall functioning of the NEM and are designed to assist the participants find an agreed set of spot and contact positions and in particular to respond to changing circumstances.

   191.The different characteristics of different generating technologies noted earlier affect the practical capability for amendment via rebids for the different technologies – for example a technology with a long start up time cannot change a decision not to offer capacity at just a few hours notice.

   192.As a result:

   a.Only those generation plants already in a condition to increase production, such as a boiler fired steam turbine plant that had been started previously or generation plants with rapid start up time can respond to changing conditions close to the time of dispatch; and

   b.It is generally the case that closer to the time of dispatch fewer generators can physically increase their total capacity available to the market (that is the sum of all price bands), but all that are available are able to adjust the volume within each price band (up to the capacity that is available).

   193.Similarly, any arrangements for demand side response may require a number of hours notice to arrange.

   194.Information is a key part of most markets establishing a fair and reasonable price and is the basis for the requirements for [the Operator] to publish forecasts and historical information discussed earlier (see paragraph 167).

   INACCURACIES IN THE BIDDING PROCESS

5. At section 7.4 of his report Mr Thorpe offers his views as to the effects of inaccuracy in the bidding process as follows: 

   7.4Forecast inaccuracy and dispatch inaccuracy

   195.I now turn to the consequences of inaccurate bids and rebids.

   196.Bids and rebids may be seen to be inaccurate in two ways, which for the purposes of this report I will term Forecast Inaccuracy and Dispatch Inaccuracy.  Both forms can have physical and commercial impacts on the market as a whole and on individual participants.

   7.4.1Forecast inaccuracy

   197.Forecast Inaccuracy occurs when subsequent to a bid or rebid being made, a participant submits a rebid (or further rebid) before the time of dispatch.  To the extent that information in the first bid or rebid(s) is altered by the final rebid, the information in the first bid or rebid will have been inaccurate.

   198.This may seem a harsh term to apply to a situation where new information comes to light and the information in both the first and any subsequent bids and rebids was accurate at the time it was presented.

   199.However, the earlier information will have been the basis for a number of forecast and decisions, in particular:

   a.[The Operator] will have counted now inaccurate capacity foreshadowed in the earlier bid or rebid in their planning for power system operation, including provision of reserve needed to maintain system security;

   b.[The Operator] may have made decisions to allow or disallow planned network outages or to issue, or not issue, low reserve notices in accordance with cl 4.8 of the [Rules]; and

   c.[The Operator] will have prepared and issued 30 minute predispatch schedules and 5 minute predispatch schedules including information for:

   1.power system operation;

   2.dispatch of all schedulable generation and demand side blocks;

   3.predictions of network flows;

   4.forecasts of Spot Price; and

   5.forecasts of Dispatch Price.

   200.Each of these items may therefore be inaccurate although the degree of error will be dependent on the circumstances and may range from very large to immaterial.

   201.Participants may have acted on the forecasts of dispatch volumes and prices in forming any rebids they have made.

   202.End users who are not market participants in their own right may arrange to buy from a retailer that is a participant under an arrangement that passes through all or part of the relevant Spot Price.

   203.End users may wish to do this where they manage controllable demand (or small non market in-house generators that can be used to reduce the users net demand) and I would expect they will then actively monitor market conditions and make decisions about their operations – although I would expect these to be limited to situations where only extreme prices had been forecast on the basis of the first bid and rebid.

   204.The final rebid may also be inaccurate at the time of dispatch giving rise to Dispatch Inaccuracy.

   7.4.2Dispatch inaccuracy

   205.Dispatch Inaccuracy occurs when bids or rebids contain inaccurate information about the physical capability to respond to a dispatch instruction.

   206.As noted earlier, [the Operator] uses the information contained in the bid or last rebid it receives before undertaking a dispatch calculation and issues associated dispatch instructions on the assumption all scheduled generators and scheduled loads can comply with the instructions.  However, if a scheduled generator or scheduled load receiving a dispatch instruction finds that they cannot comply with their instructions because their particular plant is not able to operate to the level envisaged when they formed the bid or rebid due to an unexpected technical problem with their plant, by default that bid or rebid therefore will be shown to be inaccurate.

   207.The consequences of a dispatch based on bids or rebids that lead to Dispatch Inaccuracy may include:

   a.Ancillary Services will automatically compensate for the scheduled unit that does not respond as expected – for example if a generator had been instructed to increase in accordance with an inaccurate bid Ancillary Services will detect that this has not occurred and increase in its place;

   b.[The Operator] may have over or under provided for different forms of operating reserves leading to increased costs or risks to operating security, or both;

   c.[The Operator] may have made different decisions about allowing network outages to proceed leading to increased costs to network operators (and thus eventually to customers who pay those costs); and

   d.Other participants may have made different decisions about their rebids had they been aware of the consequences of the inaccuracy in a bid and therefore suffer an opportunity loss.

   208.It is important to note that both Forecast and Dispatch Inaccuracies also can occur in the normal course of operation of a power system and market operation.  Unexpected technical problems that limit responses from generators in particular do occur.

   209.Further, efficient operation of the NEM is premised on participants responding to forecasts of future market outcomes for both dispatch volumes and prices.  For example, initial bids would normally be developed on the basis of expectations of market outcomes on the basis of experience and contracting prices.

   210.However, if a price forecast in a 30 minute predispatch schedule and 5 minute predispatch schedule shows a higher or lower price than was expected, all participants would normally review their operation to consider if, subject to cl 3.8.22 and 3.8.22A, they should rebid.  For example:

   a.To offer increased capacity in response to a high price due to shutdown of another participant or because they perceive the market value has changed;

   b.To offer less capacity in response to a lower than expected price due to early return to service of a low cost generator or changes in volumes offered in low priced bands of another generator; or

   c.To offer different amounts of capacity at the prices of the bands established at the time of the initial bid.

6. I note that Mr Thorpe’s category of “forecast inaccuracies” includes any bid or rebid which was superseded by a rebid or further rebid.  However the Rules permitted rebids and further rebids.  The evidence suggests that rebids were accepted up until very shortly before the commencement of a relevant Dispatch Interval.  Thus it would seem to be at least arguable that the Rules recognized the value of late bids or rebids, whatever the effect on the integrity of decisions made on the basis of any earlier bid or rebid.  Further, as Mr Thorpe demonstrates at paras 175-183, rebids were intended to reflect commercial considerations.  They occurred in a very complex structure, designed to collect, supply and analyse an enormous amount of information in a very short time.  It is, perhaps, implicit in Mr Thorpe’s evidence that even a small “inaccuracy” may have had surprising consequences, or that the combined consequences of numerous “inaccuracies” may have been surprising.  One must, however, question his use of the term “inaccuracy”.  Forecasts are, after all, by definition, subject to change, particularly where they are based upon such a wide range of information which, itself, is subject to change.  Use of the word “inaccuracy” to describe an earlier bid or rebid simply because a later bid varies it is not only “harsh”, to use Mr Thorpe’s description, but also, itself, inaccurate.  Both earlier and later bids and rebids might reflect bona fide assessments of conditions at the relevant times.  Mr Thorpe seems to say that changed conditions, as reflected in rebids or further rebids, might have led to the need to change earlier decisions.  That situation seems to be contemplated by the market design.

7. Clearly, the vast amount of information available and supplied by the Operator was intended for use by generators in bidding and rebidding.  As Mr Thorpe says, market participants acted on the basis of available information.  During the trial I expressed the tentative view that the conduct which is impugned in this case may well be seen as an attempt to acquire further information about market conditions.  If that characterization is correct, then it would be curious if the Rules were to be construed so as to prohibit such conduct, at least in the absence of any clear intention so to do.

   DR ROSE

   Instability

8. I turn to Dr Rose’s evidence.  First, Dr Rose dealt with the question of system instability, pointing out that the system was designed to remain stable, at least over a short period, even without intervention by the Operator.  All generating units connected to the NEM were equipped with automatic governor mechanisms which provided a response to any sudden load increase or decrease.  As most load changes would amount to only small percentages of total demand, and as such changes and resulting changes in frequency would be spread amongst all generating units, the individual effect would be small and co-ordinated amongst the units.  There was also provision for automatic responses from the control centre or manual intervention by dispatchers.  These responses would be slower.  In general they were not dependent upon communication systems which might be subject to failure, resulting in a system-wide blackout. 

1. In any event, for reasons which I have given, the unchanged Dispatch Price was either, itself, a change in material conditions and circumstances, or evidence of such change.  It disclosed to the trader the fact that, even with the effect of Rebid 19, there was still sufficient dispatch volume in lower bands to make it unnecessary that the Operator call on higher bands.  This may have been the result of inadequacy of the witness’s response to the lower Dispatch Price in Dispatch Interval 13:00, effectively rebids by other generators or a reduction in demand.  The change in distribution of dispatch volume and the absence of any effect on the Dispatch Price were changes in material conditions and circumstances or evidence of such matters.  For that reason, too, the applicant has failed to prove lack of good faith.

   Rebid 24

2. Rebid 24 also occurred following a Trading Interval during which Dispatch Prices had been high or very high.  However, in Dispatch Interval 14:35 the Dispatch Price fell to $54.86.  Following Rebid 24 it rose to $94.95 for Dispatch Interval 14:40.  I should refer to one specific submission made by the applicant in its written submissions.  At para 242 it submits that Mr Gnanananthan gave evidence that he did not consider that there was anything significant about a rise from $54 to $95.  The reference is to ts 537 ll 41-43.  The witness’s evidence was that he did not recall anything about $95 “to make that a significant rise”.  However the evidence was given in connection with another rebid and a different price which, the witness said, was significant for reasons which he gave.  It is not true to say that the witness treated the difference between $54 and $95 as of no consequence for the purposes of Rebid 24.

3. At 14:36:39, the trader made Rebid 25, and the Dispatch Price went to $9,899.95 in Dispatch Interval 14:45.  Each rebid involved the movement of 50 MW from Band 4 to Band 10.  The trader’s log indicates that Rebid 24 was motivated by the drop in price.  It also suggests that Rebid 25 was similarly motivated, demand not having “changed much”.  This may suggest that the substantial fall in price was attributable to a relatively minor reduction in demand or an increase in available dispatch in lower bands.   Thus a small change from a lower to a higher band might have reversed the trend.  It did so.  Two points of general application should be made here.  First, if there can be such a substantial fall without any substantial change in demand, it seems unsurprising that generators should seek to reverse the trend.  Secondly, the reference to demand tends to suggest that the trader took account of data other than price data.

4. In light of what was said in the log, and after considering Mr Gnanananthan’s evidence, I infer that the drop in price was the significant factor leading to Rebid 24, and that Rebid 25 was prompted by the fact that the price rose only to $94.95 following Rebid 24, coupled with the absence of any significant change in demand which might have accounted for the low prices in Dispatch Intervals 14:35 and 14:40.  Counsel for the applicant points out that, in respect of this rebid, the following passage appears in cross-examination at ts 597 ll 31-35:

   And your attitude was, when you made Rebid 24, “I want to get the price up with this rebid and if I fail to do so I will rebid again until I do get the price up?”  ---  Yes, you can say that.  Yes.

   When you say the second yes, that means yes, that is what your attitude was?  ---  Yes.

5. I accept that Mr Gnanananthan understood that he could, again, rebid in the event that a particular rebid did not produce an anticipated result.  However I doubt that the witness was meaning to concede that he actually had that intention at the time of Rebid 24.  He was rather acknowledging his general understanding.  In any event, it is not clear that he was speaking in the context of the applicant’s case, which is that the trader must have the intention of honouring the rebid throughout the Trading Interval to which it relates, absent a change in conditions or circumstances.  Further, the witness’s answer may not necessarily have related to rebidding in the same Trading Interval.  

6. I am not satisfied that when he made Rebid 24, the witness had the intention to rebid in respect of the remaining Dispatch Intervals in Trading Interval 15:00, in the event that the Dispatch Price did not rise sufficiently following that Rebid.  I see no reason for concluding that he doubted his own judgment as to the sufficiency of Rebid 24 to achieve the desired result.  I accept that he understood that he could rebid in those circumstances, but that does not lead me to conclude that he lacked an intention that Rebid 24 be honoured, absent any change in material conditions and circumstances.  Further, for reasons which I have given, the rebid and its consequences, as reflected in the slightly increased Dispatch Price, comprised changes in such conditions and circumstances, or evidence of such changes, particularly having regard to the earlier high prices.

   Rebid 28

7. Rebid 28 followed six Dispatch Intervals in which the Dispatch Price was in the vicinity of $5,000, with one exception.  In Dispatch Interval 16:30 it was $1,000.95.  In Dispatch Interval 16:45, the Dispatch Price dropped to $54.89.  By Rebid 28, at 16:42:40, Mr Gnanananthan moved 50 MW from Band 4 to Band 10 for Dispatch Intervals 16:50, 16:55 and 17:00.  By Rebid 29, at 16:53:20, he moved a further 75 MW from Band 4 to Band 10 for Dispatch Interval 17:00.  He also moved 175 MW from Band 4 to Band 10 for the following Trading Interval.  In his log the trader said that he made Rebid 28 because the price had dropped from $5,000.00 to $50.00.  He made Rebid 29 in the face of a drop in demand and continued volatility.  Volatility was suggested by the change in the 5 minute pre-dispatch price for Dispatch Interval 17:00.  In Dispatch Interval 16:50 the forecast figure was $49.95.  In Dispatch Interval 16:55 the forecast figure was $9,491.85.  

8. Once again, based upon the trader’s log, I conclude that Rebid 28 was made in order to provoke an increase in price.  In fact, the Dispatch Price fell to $49.95 in Dispatch Interval 16:50.  The applicant then made Rebid 29.  The Dispatch Price rose to $54.89 in Dispatch Interval 16:55, and to $9,494.95 in Dispatch Interval 17:00.  I see no basis for inferring that at the time at which the trader made Rebid 28, he had it in mind that he would again rebid for Trading Interval 17:00 in the event that the rebid did not raise the price.  It is much more likely that Rebid 29 involved the exploitation of an unexpected opportunity.  There was clearly a change in material conditions and circumstances.  The failure to identify the changed forecast as a reason for Rebid 29 at an earlier stage does not concern me.  It is clear that the task set for the respondent by the applicant was very substantial.  It is understandable that some features may have been overlooked.  The log entry is clear evidence as to the witness’s state of mind at the time of Rebid 29.  In that entry, the witness was trying to reconcile the drop in price following Rebid 28, and the low price in the current Dispatch Interval, with his decision to make Rebid 29.  In any event, even if the sole reason for Rebid 29 was the low Dispatch Price, for reasons which I have given, the failure to produce a substantial increase in price was either a change in material conditions and circumstances or evidence of such change.

   Rebid 67

9. As with Mr Gnanananthan, the applicant submits that it is unlikely that Mr Wallace noticed certain aspects of the data which he identified as probably relevant to his decisions to rebid or, if he did so, that he relied upon such data.  This is not an attractive argument.  In general, I treat his log entries as reliable and accept that he probably relied on the data in formulating those entries and making his rebids.  It is, no doubt, difficult to be sure of the extent of such reliance, but it is for the applicant to prove its case.  Mr Wallace was paid to assess the data and rebid accordingly. I see no justification for assuming that he did not do so.  As to questions concerning the capacity of certain data to influence his decisions, the applicant seems to suggest that I should treat as insignificant, matters which the witness identified as significant.  Whilst I do not necessarily accept everything that he said, he is in a much better position to assess the significance of changes in data than am I, or counsel for that matter.

10. The trader’s log discloses that the reason for Rebid 67 was “Portfolio optimization, extend [an earlier bid] until 12:30, increase in sensitivity, change in market conditions”.  I see no reason to doubt that this was an accurate, if terse statement of Mr Wallace’s reasons.  By that rebid he moved 80 MW from a low band to a high band for Dispatch Intervals 11:10, 11:15, 11:20, 11:25 and 11:30 and Trading Interval 12:00, and 240 MW from low to high bands for Trading Interval 12:30. 

11. In his evidence-in-chief he identified data which suggested increases in sensitivity and changes in market conditions, particularly changes in the Dispatch Price and pre-dispatch prices.  In cross-examination it was suggested that it would have been difficult for him to compare such figures once they had disappeared from the screen.  His explanation was that he relied upon notes and his memory.  It is not surprising that a person performing functions of this kind should make notes.  There is also nothing very surprising about the suggestion that they may have been destroyed, or not kept after the end of the trading day.  Reasons had been entered in the log and given to the Operator.  Whilst Mr Wallace’s evidence had the taste of reconstruction, to the extent that it supports the reasons given in his trader’s log, I accept it. The log demonstrates that he acted upon a perception of increased sensitivity, price volatility and changes in forecasts.  No doubt he was seeking to optimize his portfolio in the sense of obtaining the highest price for the largest possible dispatch volume.  That was, after all, his job.

12. His reasons for Rebid 68, as recorded in the log, were “Portfolio Optimization till 12:30”.  By Rebid 68 he moved a further 40 MW from low price bands to high price bands for Dispatch Intervals 11:15, 11:20, 11:25 and 11:30 and Trading Intervals 12:00 and 12:30, or at least that was the nett effect of the rebid.  At the time of Rebid 67 the Dispatch Price was $101.00.  In the following Dispatch Interval it was $101.02, indicating that a different generator was setting the price.  In Dispatch Interval 11:10, the price remained at $101.02.  Rebid 68 was made at 11:08:32, after the last-mentioned Dispatch Price had become available. 

13. The substantial movement of capacity in Rebid 67 for Trading Interval 12:30 suggests a fairly firm expectation that the price would rise rather than fall, and that the increase was likely to be sustained for some time.  It does not have the minimalist quality which marked Mr Gnanananthan’s trading.  No doubt Mr Wallace had the benefit of Mr Gnanananthan’s experiences on 22 February.  Events on that day may have encouraged a robust approach on 23 February.  At the time of Rebid 67, the Dispatch Price was rising, as were the 5 minute pre-dispatch prices.  The sensitivity figures were also rising and, in Dispatch Interval 11:10, actual demand was above forecast. 

14. I infer that Rebid 67 was made in the expectation of higher prices and with the intention of ensuring that they materialized.  It is also likely that in the rebids for Trading Intervals 11:30 and 12:00 Mr Wallace was, to some extent, testing the waters for the more substantial transfer of dispatch volume in Dispatch Interval 12:30.  I infer that Rebid 68 was motivated, at least in part, by the fact that the Dispatch Price had not moved following Rebid 67.  I accept that some of the other matters to which Mr Wallace referred in evidence probably influenced his decision, but I would be hard pressed to identify which.  The unchanged Dispatch Price may have suggested to him that he had under-estimated the volume needed to produce the desired result.  However I see no reason to infer that he had it in mind, when he made Rebid 67, that he would rebid if that result were not achieved.  I suspect that he was probably more concerned to avoid causing a collapse in price, but that is mere speculation on my part.  I am not satisfied that when the witness made Reid 67, he lacked an intention that the rebid be honoured, absent any change in material conditions and circumstances.  For reasons which I have given, I also do not accept that an intention to rebid, should the Dispatch Price not rise to a satisfactory level, deprives a rebid of the quality of good faith.

    Rebid 69

15. By Rebid 69, at 11:26:52, Mr Wallace moved 20 MW from Band 10 to Band 3 for Trading Intervals 12:00 and 12:30.  By Rebid 70, at 11:43:42, he moved 40 MW from Band 3 to Band 10 for the Dispatch Intervals 11:50, 11:55 and 12:00.  The reason entered in the trader’s log was “Port Optimization till 12:30”.  In evidence the witness said that his purpose was to increase the respondent’s dispatch volume, given that the price had dropped from $4,991.85 in the 11:20 Dispatch Interval to $72.03 in the 11:25 Dispatch Interval, and he was below his dispatch target.  The price increased thereafter, reaching $4,991.85 in the 11:40 Dispatch Interval.  Rebid 70 was made in the following Dispatch Interval.  In Dispatch Intervals 11:25, 11:30 and 11:35 the 5 minute pre-dispatch price for Dispatch Interval 11:40 was only $120.78.  The log entry asserts that this was “Port optimization till 12:00, material change in market conditions”.  Rebid 70 was motivated by a rise in Dispatch Price in Dispatch Intervals 11:35, 11:40 and 11:45.  From Dispatch Interval 11:25 until Dispatch Interval 11:45, the 5 minute pre-dispatch price for Dispatch Interval 11:45 was almost $5,000.  There was also an increase in forecast demand.  The witness’s dispatch volume had increased so that he was no longer concerned about low dispatch volume.

16. There seems to be no rational explanation for Rebid 69 other than that offered by the witness, namely that he was seeking to increase dispatch volume, although perhaps not by much.  A substantially higher price was forecast for Dispatch Interval 11:45.  Rebid 70 was almost certainly prompted by the high Dispatch Price in Dispatch Intervals 11:40 and 11:45, as well as the other matters to which the witness referred.  I am not persuaded that at the time of Rebid 69, Mr Wallace lacked an intention that it be honoured, absent any change in material conditions and circumstances.  In any event, for the reasons which I have given, I consider that an intention to rebid, should the Dispatch Price not rise to a satisfactory level, is not a basis for a finding of bad faith.

    Rebid 81

17. When Rebid 81 was made at 14:39:50, it followed a run of very high Dispatch Prices in Dispatch Intervals 14:10 to 14:40.  Rebid 82 was made at 14:46:24, almost seven minutes after Rebid 81.  By Rebid 81, the trader moved 380 MW from lower to higher bands for Trading Interval 15:30.  By Rebid 82, he moved a further 40 MW from lower to higher bands for the same Trading Interval.  In his trader’s log Mr Wallace recorded that he was extending two previous rebids (78 and 79) until 15:30.  He also recorded a reduction in the generation of two Stanwell units, and that there had been a change in market conditions in that the price was higher than predicted for the period until 15:30.  In fact the prices were higher only until 15:00.  The note may have meant that prices were high until the beginning of Trading Interval 15:30.  The log entry concerning Rebid 82 states that it was an extension of the previous rebid until 15:30, reflecting a material change in market conditions.

18. The witness said that the relevant data was the current high Dispatch Price and the 5 minute pre-dispatch prices for Dispatch Intervals 14:40 to 15:00, with a substantial collapse forecast after Trading Interval 15:00.  The current Dispatch Price was one of the respondent’s prices, but the higher price forecast for Trading Intervals 14:45, 14:55 and 15:00 was a competitor’s. In light of the forecast drop in price, he chose to move generation from lower to higher bands in order to avoid or minimize the effect of the forecast drop.

19. The applicant points to earlier Rebids 78 and 79 in which Mr Wallace moved 420 MW from lower to higher bands.  The spreadsheet in the Supplementary Court Book suggests that he moved 430 MW by Rebids 78 and 79.  The difference may be explained by the note in the trader’s log concerning a reduction in generation at Stanwell.  It does not matter.  By Rebid 78, he moved only 380MW.  There seems to be two contradictory themes concerning this rebid in the applicant’s written submissions at paras 310-312.  The applicant first submits that the witness had deliberately tried to minimize the volume transferred, presumably to maintain dispatch volume.  The applicant then submits that when Mr Wallace realized that he had only moved 380MW, he made Rebid 82 to make up the difference. 

20. At the time of Rebid 81, the Dispatch Price was $7,450.  In Dispatch Interval 14:45 it fell to $6,000.01.  In Dispatch Interval 14:50, it rose to $9,491.85.  As Rebid 82 was made at 14:46:24, Mr Wallace may or may not have seen that figure.  He also identified drops in the 5 minute pre-dispatch price for Trading Interval 15:30.  The applicant effectively rejects the suggestion that such drops were relevant, suggesting that they involved only drops from $72.03 to $72.01.  The witness said that such a drop might be significant, presumably because it would suggest a change in the generator determining the price.  However the witness had also identified greater variations in the data.  In Dispatch Interval 14:45, there were substantial drops in the forecasts for subsequent Dispatch Intervals as compared to the forecasts made in Dispatch Interval 14:40.  The Dispatch Price had also dropped.  The 30 minute pre-dispatch price for Trading Interval 15:00 was very low.  There had also been a drop in demand and forecast demand.  In its written submissions, the applicant submitted that fluctuations in demand which fell “within the saw tooth pattern of demand” were not of any significance and were “merely part of a flat demand trend”, whatever that means.  I am not surprised that a trader would seek to deal with a fall in demand rather than wait to see if conditions improved without his intervention.

21. The applicant effectively submits that I should reject any attempt by the witness to identify reasons for his decision from the data, on the basis that he is merely reconstructing his reasoning.  Whilst I accept that Mr Wallace’s evidence involves substantial reconstruction, I have explained my reasons for not rejecting it out of hand.  He was, after all, simply explaining how the data offers support for his log entries, or at least, that is how I treat his evidence.  Further, the applicant seems to imply that the trader would not have considered matters which were clearly relevant to the decisions which he had to make.  I accept that he would have considered movements in Spot Price and Dispatch Price and that he would have had regard to changes in pre-dispatch prices.  Questions of demand and forecast demand would also have been relevant.

22. It is probable that in making Rebid 81, he sought to achieve a high price whilst minimizing the risk of reduced dispatch volume.  I accept that the Dispatch Price for Dispatch Interval 14:45 suggested that his strategy had failed and, having regard to that failure and other factors, he made Rebid 82.  I am not satisfied that in making Rebid 81 he intended to rebid for the same Dispatch Intervals in the event that Rebid 81 failed to increase the Dispatch Price to a satisfactory level.  I infer that when he made Rebid 81, he intended that it be honoured, absent a change in material conditions and circumstances.  For reasons which I have already given I consider that the effect of Rebid 81 on the Dispatch Price, or the lack of such effect, was, in any event, evidence of a change in material conditions and circumstances.

    Rebid 83

1. Pursuant to Rebid 83, at 15:14:55, Mr Wallace moved 420 MW from lower to higher bands for Trading Interval 16:00.  The reason for Rebid 83 given in the log is “extend previous 2 bid [sic] to 16:00 material change in market conditions”.  The Dispatch Price for that Dispatch Interval was $6,000.01.  It had been between $6,000.00 and $9,500.00 since at least the 14:45 Dispatch Interval.  The 5 minute pre-dispatch prices for Dispatch Intervals 15:20, 15:25 and 15:30 were, at the time of Rebid 83, at the same level as the Dispatch Price for Dispatch Interval 15:15.  However the data forecast a substantial fall off in price after the end of the 15:30 Trading Interval.  Mr Wallace considered that if he moved capacity into higher bands, he could expect better prices in the 16:00 Trading Interval.  By Rebid 84, at 15:34:17, almost 20 minutes after Rebid 83, he moved 25 MW from Band 10 to Band 4 for Dispatch Intervals 15:45 to 16:00.  He said that he did so in order to increase dispatch.  In his log he said that he was extending the previous bid to 16:30 to test sensitivity and plant response time. 

2. The witness said that in making Rebid 83 he was hoping for an increase in forecast prices for the 16:00 Trading Interval.  He meant to replicate, in Trading Interval 16:00, the overall effect of Rebids 81 and 82 in Trading Interval 15:30.  Following Rebid 83 the price remained steady until Dispatch Interval 15:35 when, by Rebid 84, he moved 25 MW from Band 10 to Band 4.  He said that in so doing he was trying to increase dispatch.  I assume that he was trying to do so without any significant reduction in price.  Some aspect of Rebid 84 may also have been designed to test the response times at the Gladstone power station.  The respondent points out that by Rebid 85, he effectively reversed Rebid 84 following a collapse in price.

3. The applicant’s submissions concerning Rebid 83 are not easy to understand.  In general, the case has been conducted on the basis that a second bid affecting the same Dispatch Intervals offers a basis for inferring that the first bid was not made in good faith having been made without the intention that it be honoured in the absence of any change in material conditions and circumstances.  Rebid 83 dealt with Trading Interval 16:00.  Rebid 84 dealt with that Trading Interval only to the extent that it moved 25 MW from a higher to a lower band.  It seems likely that at least 5 MW of that dispatch volume were moved to test sensitivity and/or plant response time.  Bid 84 is not, itself, impugned.  The balance of Rebid 84 concerns Trading Interval 16:30.  That part of the rebid says nothing about Rebid 83.

4. The most likely explanation of Rebid 84, as it affected Trading Interval 16:00, is that it was an attempt to gain dispatch volume in a time of stable high prices, together with the testing purpose to which the witness referred in his log entry.  There is no reason to believe that Mr Wallace intended to deal with those matters at the time at which he made Rebid 83.  I am not satisfied that in making Rebid 83 Mr Wallace lacked the intention that the rebid be honoured in the event that there was no change in material conditions and circumstances.  Again I note that I consider a change in Dispatch Price, or the absence of a change in the face of other changed conditions, is a change in material conditions and circumstances.

   Rebid 86

5. By Rebid 86 at 16:24:33, Mr Wallace moved 330 MW from lower bands to Band 10 for the 17:00 Trading Interval.  By Rebid 87, at 16:31:44, he moved 40 MW from a low band to Band 10 for Dispatch Intervals 16:40-17:00.  By Rebid 88, at 16:41:53, he moved 50 MW from Band 4 to Band 10 for Dispatch Intervals 16:50, 16:55 and 17:00 and 420 MW from lower bands to Band 10 for Trading Interval 17:30.

6. The trader’s log entry suggests that each rebid was for portfolio optimization.  Mr Wallace observed in evidence that the Dispatch Price for Dispatch Interval 16:25 was $72.01, and the 5 minute pre-dispatch prices for Trading Interval 17:00 were generally below $34.00.  In Dispatch Interval 16:30, the Dispatch Price remained at just above $72.00, but the forecasts for Trading Interval 17:00 remained at roughly half of that sum.  In Dispatch Interval 16:35, the Dispatch Price fell to $55.64 but the forecast for Trading Interval 17:00 rose to about $72.  However, in Dispatch Interval 16:40 the Dispatch Price returned to about $72.  The forecast figures for the balance of Trading Interval 17:00 and for Trading Interval 17:30 were declining.  There had also been a fall in both actual and forecast capacity.  Rebid 88 related to both Trading Intervals 17:00 and 17:30 whilst Rebids 86 and 87 related only to Trading Interval 17:00.

7. Clearly, Mr Wallace, at the time of these rebids, considered that there was a benefit to be derived from the movement of dispatch volume into higher bands.  The applicant effectively asserts that he was motivated solely by a desire to force up the price, and that he intended, when he made Rebid 86, to rebid again if the Dispatch Price did not rise.  To the extent that the witness points to factors which may have led to his decision, the applicant asserts that it is unlikely that he considered “minor” changes to be of any significance.  One difficulty with that approach is that we are not presently concerned with objective reasonableness but actual state of mind.  The applicant may submit that a particular view of the facts is unlikely, but the question is whether the witness honestly held that view, not whether it was objectively correct, or even reasonable.  Further, Mr Wallace was, and is, much more familiar with the trading process than am I.  In some circumstances I might reject a particular assertion as to the significance of data as unlikely to be correct, but in general, in the absence of contradictory evidence, I accept his views as to significance.

8. In this case, Rebids 86 and 87 were more than seven minutes apart.  Rebids 87 and 88 were more than ten minutes apart.  To the extent that Rebid 88 affected Trading Interval 17:30 it says little or nothing about Mr Wallace’s thought processes in making Rebid 86.  I accept that Rebids 87 and 88 were made in response to the failure of Rebid 86 to produce higher prices.  Other factors were probably also relevant although, again, I would be hard pressed to identify them.  However Rebid 86 involved movement of a substantial dispatch volume.  I see no reason to infer that Mr Wallace lacked confidence in his decision concerning Rebid 86.  The applicant’s case is, in effect, that he reserved the right to engage in subsequent fine tuning.  The evidence offers no basis for that view.  I see no reason to conclude that at the time of Rebid 86, Mr Wallace lacked the intention that the rebid be honoured, absent a change in material conditions and circumstances.  In any event I consider that the subsequent Dispatch Prices indicated that, notwithstanding Mr Wallace’s bids, the level of demand was not sufficient to produce the desired price rise.  That rebid and the market’s response to it, as evidenced in the Dispatch Prices, comprised a changed in material conditions and circumstances.

   OTHER FINDINGS OF FACT

9. The applicant requested 178 separate findings of fact.  It is obviously impracticable that I address each request separately.  Requests 1 to 14 appear to be largely uncontroversial, save possibly for requests 12 and 13.  The balance of the requests relate to the impugned rebids.  I have made such findings as I consider to be appropriate given the unsatisfactory nature of the evidence.  If either party requires further findings, it may apply accordingly.

   ORDERS

10. The application must be dismissed.  In the absence of an application within seven days by either party for other orders as to costs, I shall order that the applicant pay the respondent’s costs of the proceedings, including reserved costs.

I certify that the preceding three hundred and ninety-two (392) numbered paragraphs are a true copy of the Reasons for Judgment herein of the Honourable Justice Dowsett.

Associate:

Dated:       30 August 2011